For the fiscal year ended December 31, 2009
|
Commission File Number: 333-12138
|
CANADIAN NATURAL RESOURCES LIMITED
(Exact name of Registrant as specified in its charter)
|
ALBERTA, CANADA
(Province or other jurisdiction of incorporation or organization)
|
1311
(Primary Standard Industrial Classification Code Numbers)
|
Not Applicable
(I.R.S. Employer Identification Number (if applicable))
|
2500, 855-2nd Street S.W., Calgary, Alberta, Canada, T2P 4J8
Telephone: (403) 517-7345
(Address and telephone number of Registrant’s principal executive offices)
|
CT Corporation System, 111-Eighth Avenue, New York, New York 10011
(212) 894-8940
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)
|
Title of Each Class:
|
Name of each exchange on which registered:
|
Common Shares, no par value
|
New York Stock Exchange
|
[ X ] Annual information form
|
[ X ] Audited annual financial statements
|
Yes [X]
|
No [ ]
|
Yes __
|
No __
|
|
A.
|
Annual Information Form
|
|
B.
|
Audited Annual Financial Statements
|
|
C.
|
Management’s Discussion and Analysis
|
DEFINITIONS AND ABBREVIATIONS
|
4
|
||
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
|
6
|
||
RISK FACTORS
|
8
|
||
ENVIRONMENTAL MATTERS
|
12
|
||
REGULATORY MATTERS
|
13
|
||
THE COMPANY
|
15
|
||
GENERAL DEVELOPMENT OF THE BUSINESS
|
17
|
||
DESCRIPTION OF THE BUSINESS
|
18
|
||
A.
|
PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES
|
19
|
|
Daily Production
|
19
|
||
Developed and Undeveloped Acreage
|
20
|
||
Drilling Activity
|
21
|
||
Productive Crude Oil and Natural Gas Wells
|
24
|
||
Northeast British Columbia
|
24
|
||
Northwest Alberta
|
25
|
||
Northern Plains
|
26
|
||
Southern Plains and Southeast Saskatchewan
|
28
|
||
Oil Sands Mining and Upgrading
|
29
|
||
United Kingdom North Sea
|
33
|
||
Offshore West Africa
|
34
|
||
Côte d’Ivoire
|
34
|
||
Gabon
|
35
|
||
B.
|
CRUDE OIL, NGLs AND NATURAL GAS RESERVES
|
36
|
|
C.
|
RECONCILIATION OF CHANGES IN NET RESERVES
|
42
|
|
D.
|
CRUDE OIL, NGLs AND NATURAL GAS PRODUCTION
|
46
|
|
E.
|
NET CAPITAL EXPENDITURES
|
51
|
|
F.
|
DEVELOPED AND UNDEVELOPED ACREAGE
|
52
|
|
SELECTED FINANCIAL INFORMATION
|
53
|
||
CAPITAL STRUCTURE
|
54
|
||
MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES
|
55
|
||
DIVIDEND HISTORY
|
56
|
||
TRANSFER AGENTS AND REGISTRAR
|
56
|
||
DIRECTORS AND OFFICERS
|
57
|
||
Canadian Natural Resources Limited
|
2
|
CONFLICTS OF INTEREST
|
61
|
||
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
|
61
|
||
AUDIT COMMITTEE INFORMATION
|
62
|
||
LEGAL PROCEEDINGS
|
63
|
||
MATERIAL CONTRACTS
|
63
|
||
INTERESTS OF EXPERTS
|
63
|
||
ADDITIONAL INFORMATION
|
63
|
||
SCHEDULE “A” REPORT ON RESERVES DATA
|
64
|
||
SCHEDULE “B” REPORT OF MANAGEMENT AND DIRECTORS
|
66
|
||
SCHEDULE “C” CHARTER OF THE AUDIT COMMITTEE
|
68
|
3
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
4
|
5
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
6
|
7
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
8
|
9
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
10
|
11
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
12
|
Estimated ARO, undiscounted ($millions)
|
2009
|
2008
|
||||||
North America
|
$ | 3,346 | $ | 3,072 | ||||
Oil Sands Mining and Upgrading (1)
|
1,485 | 93 | ||||||
North Sea
|
1,522 | 1,216 | ||||||
Offshore West Africa
|
253 | 93 | ||||||
6,606 | 4,474 | |||||||
North Sea PRT recovery
|
(568 | ) | (529 | ) | ||||
$ | 6,038 | $ | 3,945 |
(1)
|
Prior period amounts have been reclassified to conform to the presentation adopted in 2009.
|
13
|
Canadian Natural Resources Limited
|
●
|
A royalty credit of $200 per meter on new conventional crude oil and natural gas wells drilled between April 1, 2009 and March 31, 2010 to a maximum of 10% of conventional Crown royalties paid in Alberta.
|
●
|
Reduced royalty rates that set the maximum royalty at 5% for the first 12 months of production, up to a maximum of 50,000 boe or 500 mmcfe for new conventional crude oil and natural gas wells that commence production between April 1, 2009 and March 31, 2010.
|
●
|
Permanently imbedding in the royalty system the reduced royalty rate of a maximum of 5% on new natural gas and conventional oil wells with the same time and volume limits.
|
●
|
Reducing the maximum royalty rate for conventional crude oil from 50% to 40% and reducing the maximum royalty rate for conventional and unconventional gas from 50% to 36%.
|
●
|
A one-year, 2% royalty rate for all natural gas wells drilled between September 1, 2009 and June 30, 2010. Qualifying wells must commence production before December 31, 2010.
|
●
|
A permanent increase of 15% in the existing royalty holiday credits for the Deep Royalty Program.
|
●
|
A permanent qualification of horizontal wells drilled to a vertical depth between 1,900 and 2,300 meters into the Deep Royalty Program.
|
●
|
An additional $50 million allocation for the Infrastructure Royalty Credit Programs to stimulate investment in oil and gas roads and pipelines.
|
Canadian Natural Resources Limited
|
14
|
15
|
Canadian Natural Resources Limited
|
Jurisdiction of Incorporation
|
% Ownership
|
|
Subsidiary
|
||
CanNat Energy Inc.
|
Delaware
|
100
|
CNR (ECHO) Resources Inc.
|
Alberta
|
100
|
CNR International (U.K.) Investments Limited
|
England
|
100
|
CNR International (U.K.) Limited
|
England
|
100
|
CNR International Côte d’Ivoire SARL
|
Côte d’Ivoire
|
100
|
CNR International (Olowi) Limited
|
Bahamas
|
100
|
Horizon Construction Management Ltd.
|
Alberta
|
100
|
Partnership
|
||
Canadian Natural Resources Partnership
|
Alberta
|
100
|
Canadian Natural Resources Northern Alberta Partnership
|
Alberta
|
100
|
Canadian Natural Resources 2005 Partnership
|
Alberta
|
100
|
Canadian Natural Resources Limited
|
16
|
17
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
18
|
A.
|
PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES
|
2009 Average Daily
Production Rates
|
2008 Average Daily
Production Rates
|
|||
Region
|
Crude oil & NGLs
(mbbl)
|
Natural gas
(mmcf)
|
Crude oil & NGLs
(mbbl)
|
Natural gas
(mmcf)
|
North America
|
||||
Northeast British Columbia
|
5.5
|
329
|
5.9
|
377
|
Northwest Alberta
|
14.8
|
455
|
16.4
|
531
|
Northern Plains
|
194.6
|
341
|
200.7
|
382
|
Southern Plains
|
11.4
|
158
|
12.2
|
177
|
Southeast Saskatchewan
|
7.9
|
3
|
8.4
|
3
|
Oil sands Mining & Upgrading
|
50.3
|
-
|
-
|
-
|
Non-core regions
|
0.3
|
1
|
0.2
|
2
|
North America Total
|
284.8
|
1,287
|
243.8
|
1,472
|
International
|
||||
North Sea UK Sector
|
37.8
|
10
|
45.3
|
10
|
Offshore West Africa
|
||||
Côte d’Ivoire
|
30.3
|
18
|
26.6
|
13
|
Gabon
|
2.6
|
-
|
-
|
-
|
International Total
|
70.7
|
28
|
71.9
|
23
|
Company Total
|
355.5
|
1,315
|
315.7
|
1,495
|
19
|
Canadian Natural Resources Limited
|
Developed Acreage
|
Undeveloped Acreage
|
Total Acreage
|
Average Working
Interest |
||||
Region (thousands of acres)
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
%
|
North America
|
|||||||
Northeast British
Columbia
|
1,493
|
1,132
|
2,838
|
2,068
|
4,331
|
3,200
|
74
|
Northwest Alberta
|
1,229
|
883
|
1,531
|
1,154
|
2,760
|
2,037
|
74
|
Northern Plains
|
4,111
|
3,351
|
6,696
|
5,885
|
10,807
|
9,236
|
85
|
Southern Plains
|
1,530
|
1,216
|
950
|
804
|
2,480
|
2,020
|
81
|
Southeast Saskatchewan
|
93
|
76
|
154
|
139
|
247
|
215
|
87
|
Thermal In-Situ Oil Sands
|
29
|
29
|
588
|
486
|
617
|
515
|
83
|
Oil Sands Mining &
Upgrading
|
1
|
1
|
115
|
115
|
116
|
116
|
100
|
Non-core regions
|
42
|
14
|
1,341
|
201
|
1,383
|
215
|
16
|
North America Total
|
8,528
|
6,702
|
14,213
|
10,852
|
22,741
|
17,554
|
77
|
International
|
|||||||
North Sea UK Sector
|
68
|
57
|
184
|
150
|
252
|
207
|
82
|
Offshore West Africa
|
|||||||
Côte d’Ivoire
|
10
|
6
|
92
|
54
|
102
|
60
|
59
|
Gabon
|
2
|
2
|
150
|
138
|
152
|
140
|
92
|
Non-core regions
|
|||||||
South Africa
|
-
|
-
|
4,002
|
4,002
|
4,002
|
4,002
|
100
|
International Total
|
80
|
65
|
4,428
|
4,344
|
4,508
|
4,409
|
98
|
Company Total
|
8,608
|
6,767
|
18,641
|
15,196
|
27,249
|
21,963
|
81
|
Canadian Natural Resources Limited
|
20
|
2009 | |||||||||||
Exploratory
|
Development
|
||||||||||
Crude Oil
|
Natural Gas
|
Dry
|
Service/
Stratigraphic
|
Total
|
Crude Oil
|
Natural Gas
|
Dry
|
Service/
Stratigraphic
|
Total
|
||
North America
|
|||||||||||
Northeast
British Columbia
|
Gross
|
-
|
1.0
|
3.0
|
-
|
4.0
|
-
|
20.0
|
1.0
|
-
|
21.0
|
Net
|
-
|
0.5
|
2.4
|
-
|
2.9
|
-
|
17.6
|
1.0
|
-
|
18.6
|
|
Northwest Alberta
|
Gross
|
4.0
|
24.0
|
-
|
-
|
28.0
|
4.0
|
24.0
|
1.0
|
-
|
29.0
|
Net
|
3.5
|
22.3
|
-
|
-
|
25.8
|
3.3
|
23.4
|
1.0
|
-
|
27.7
|
|
Northern Plains
|
Gross
|
39.0
|
8.0
|
6.0
|
7.0
|
60.0
|
601.0
|
37.0
|
35.0
|
203.0
|
876.0
|
Net
|
38.5
|
7.1
|
6.0
|
7.0
|
58.6
|
565.9
|
27.9
|
33.5
|
203.0
|
830.3
|
|
Southern Plains
|
Gross
|
3.0
|
2.0
|
1.0
|
-
|
6.0
|
5.0
|
25.0
|
1.0
|
1.0
|
32.0
|
Net
|
2.1
|
2.0
|
1.0
|
-
|
5.1
|
3.6
|
8.3
|
1.0
|
1.0
|
13.9
|
|
Southeast
Saskatchewan
|
Gross
|
3.0
|
-
|
-
|
-
|
3.0
|
20.0
|
-
|
-
|
2.0
|
22.0
|
Net
|
2.1
|
-
|
-
|
-
|
2.1
|
18.4
|
-
|
-
|
2.0
|
20.4
|
|
Oil Sands Mining
and Upgrading
|
Gross
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
115.0
|
115.0
|
Net
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
115.0
|
115.0
|
|
Non-core Regions
|
Gross
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Net
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
|
North America
Total
|
Gross
|
49.0
|
35.0
|
10.0
|
7.0
|
101.0
|
630.0
|
106.0
|
38.0
|
321.0
|
1,095.0
|
Net
|
46.2
|
31.9
|
9.4
|
7.0
|
94.5
|
591.2
|
77.2
|
36.5
|
321.0
|
1,025.9
|
|
North Sea
UK Sector
|
Gross
|
-
|
-
|
1.0
|
-
|
1.0
|
1.0
|
-
|
-
|
-
|
1.0
|
Net
|
-
|
-
|
0.3
|
-
|
0.3
|
0.9
|
-
|
-
|
-
|
0.9
|
|
Offshore
West Africa
|
Gross
|
-
|
-
|
-
|
-
|
-
|
6.0
|
-
|
-
|
1.0
|
7.0
|
Net
|
-
|
-
|
-
|
-
|
-
|
5.2
|
-
|
-
|
0.9
|
6.1
|
|
Company Total
|
Gross
|
49.0
|
35.0
|
11.0
|
7.0
|
102.0
|
637.0
|
106.0
|
38.0
|
322.0
|
1,103.0
|
Net
|
46.2
|
31.9
|
9.7
|
7.0
|
94.8
|
597.3
|
77.2
|
36.5
|
321.9
|
1,032.9
|
|
21
|
Canadian Natural Resources Limited
|
2008 | |||||||||||
Exploratory
|
Development
|
||||||||||
Crude
Oil |
Natural Gas
|
Dry
|
Service/
Stratigraphic
|
Total
|
Crude
Oil
|
Natural Gas
|
Dry
|
Service/
Stratigraphic
|
Total
|
||
North America
|
|||||||||||
Northeast British
Columbia
|
Gross
|
-
|
2.0
|
2.0
|
-
|
4.0
|
-
|
26.0
|
4.0
|
-
|
30.0
|
Net
|
-
|
1.5
|
1.5
|
-
|
3.0
|
-
|
22.5
|
1.9
|
-
|
24.4
|
|
Northwest Alberta
|
Gross
|
1.0
|
14.0
|
1.0
|
-
|
16.0
|
14.0
|
62.0
|
3.0
|
3.0
|
82.0
|
Net
|
0.6
|
12.6
|
0.9
|
-
|
14.1
|
8.9
|
54.0
|
2.6
|
2.2
|
67.7
|
|
Northern Plains
|
Gross
|
27.0
|
14.0
|
5.0
|
-
|
46.0
|
583.0
|
131.0
|
22.0
|
33.0
|
769.0
|
Net
|
26.3
|
11.4
|
5.0
|
-
|
42.7
|
557.3
|
88.4
|
21.5
|
32.4
|
699.6
|
|
Southern Plains
|
Gross
|
4.0
|
6.0
|
1.0
|
-
|
11.0
|
29.0
|
153.0
|
1.0
|
-
|
183.0
|
Net
|
4.0
|
6.0
|
1.0
|
-
|
11.0
|
26.9
|
72.8
|
1.0
|
-
|
100.7
|
|
Southeast
Saskatchewan
|
Gross
|
6.0
|
-
|
2.0
|
-
|
8.0
|
57.0
|
-
|
-
|
2.0
|
59.0
|
Net
|
4.6
|
-
|
2.0
|
-
|
6.6
|
48.9
|
-
|
-
|
1.7
|
50.6
|
|
Oil Sands Mining and Upgrading
|
Gross
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
92.0
|
92.0
|
Net
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
92.0
|
92.0
|
|
Non-core Regions
|
Gross
|
-
|
-
|
-
|
-
|
-
|
-
|
3.0
|
2.0
|
-
|
5.0
|
Net
|
-
|
-
|
-
|
-
|
-
|
-
|
0.1
|
0.4
|
-
|
0.5
|
|
North America
Total |
Gross
|
38.0
|
36.0
|
11.0
|
-
|
85.0
|
683.0
|
375.0
|
32.0
|
130.0
|
1,220.0
|
Net
|
35.5
|
31.5
|
10.4
|
-
|
77.4
|
642.0
|
237.8
|
27.4
|
128.3
|
1,035.5
|
|
North Sea
UK Sector
|
Gross
|
1.0
|
-
|
-
|
-
|
1.0
|
2.0
|
-
|
1.0
|
1.0
|
4.0
|
Net
|
0.8
|
-
|
-
|
-
|
0.8
|
1.6
|
-
|
0.8
|
0.9
|
3.3
|
|
Offshore
West Africa
|
Gross
|
-
|
-
|
-
|
-
|
-
|
4.0
|
-
|
-
|
2.0
|
6.0
|
Net
|
-
|
-
|
-
|
-
|
-
|
2.3
|
-
|
-
|
1.8
|
4.1
|
|
Company Total
|
Gross
|
39.0
|
36.0
|
11.0
|
-
|
86.0
|
689.0
|
375.0
|
33.0
|
133.0
|
1,230.0
|
Net
|
36.3
|
31.5
|
10.4
|
-
|
78.2
|
645.9
|
237.8
|
28.2
|
131.0
|
1,042.9
|
|
Canadian Natural Resources Limited
|
22
|
2007 | |||||||||||
Exploratory
|
Development
|
||||||||||
Crude Oil
|
Natural Gas
|
Dry
|
Service/
Stratigraphic
|
Total
|
Crude Oil
|
Natural Gas
|
Dry
|
Service/
Stratigraphic
|
Total
|
||
North America
|
|||||||||||
Northeast British
Columbia
|
Gross
|
-
|
7.0
|
7.0
|
-
|
14.0
|
3.0
|
45.0
|
12.0
|
-
|
60.0
|
Net
|
-
|
7.0
|
6.0
|
-
|
13.0
|
2.9
|
35.1
|
10.1
|
-
|
48.1
|
|
Northwest Alberta
|
Gross
|
1.0
|
23.0
|
5.0
|
-
|
29.0
|
21.0
|
102.0
|
14.0
|
2.0
|
139.0
|
Net
|
1.0
|
16.4
|
3.8
|
-
|
21.2
|
12.1
|
82.1
|
8.9
|
1.5
|
104.6
|
|
Northern Plains
|
Gross
|
26.0
|
31.0
|
20.0
|
97.0
|
174.0
|
545.0
|
82.0
|
44.0
|
49.0
|
720.0
|
Net
|
23.8
|
24.7
|
19.4
|
97.0
|
164.9
|
500.6
|
70.9
|
42.4
|
48.8
|
662.7
|
|
Southern Plains
|
Gross
|
1.0
|
14.0
|
1.0
|
-
|
16.0
|
19.0
|
174.0
|
2.0
|
1.0
|
196.0
|
Net
|
1.0
|
13.4
|
1.0
|
-
|
15.4
|
18.1
|
134.1
|
0.6
|
1.0
|
153.8
|
|
Southeast
Saskatchewan
|
Gross
|
1.0
|
-
|
-
|
-
|
1.0
|
27.0
|
-
|
2.0
|
4.0
|
33.0
|
Net
|
1.0
|
-
|
-
|
-
|
1.0
|
23.0
|
-
|
0.4
|
4.0
|
27.4
|
|
Oil Sands Mining
and Upgrading
|
Gross
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
98.0
|
98.0
|
Net
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
98.0
|
98.0
|
|
Non-core Regions
|
Gross
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Net
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
|
North America
Total |
Gross
|
29.0
|
75.0
|
33.0
|
97.0
|
234.0
|
615.0
|
403.0
|
74.0
|
154.0
|
1,246.0
|
Net
|
26.8
|
61.5
|
30.2
|
97.0
|
215.5
|
556.7
|
322.2
|
62.4
|
153.3
|
1,094.6
|
|
North Sea
UK Sector
|
Gross
|
-
|
-
|
-
|
-
|
-
|
4.0
|
-
|
-
|
4.0
|
8.0
|
Net
|
-
|
-
|
-
|
-
|
-
|
3.7
|
-
|
-
|
3.5
|
7.2
|
|
Offshore
West Africa
|
Gross
|
-
|
-
|
-
|
-
|
-
|
7.0
|
-
|
-
|
1.0
|
8.0
|
Net
|
-
|
-
|
-
|
-
|
-
|
4.1
|
-
|
-
|
0.6
|
4.7
|
|
Company Total
|
Gross
|
29.0
|
75.0
|
33.0
|
97.0
|
234.0
|
626.0
|
403.0
|
74.0
|
159.0
|
1,262.0
|
Net
|
26.8
|
61.5
|
30.2
|
97.0
|
215.5
|
564.5
|
322.2
|
62.4
|
157.4
|
1,106.5
|
|
23
|
Canadian Natural Resources Limited
|
Natural gas wells
|
Crude oil wells
|
Total wells
|
|||||||
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
||||
Canada
|
|||||||||
Northeast British Columbia
|
1,545
|
1,281.2
|
218
|
187.4
|
1,763
|
1,468.6
|
|||
Northwest Alberta
|
2,138
|
1,677.5
|
555
|
342.4
|
2,693
|
2,019.9
|
|||
Northern Plains
|
3,788
|
3,077.9
|
6,009
|
5,529.6
|
9,797
|
8,607.5
|
|||
Southern Plains
|
7,366
|
6,094.4
|
1,227
|
1,121.5
|
8,593
|
7,215.9
|
|||
Southeast Saskatchewan
|
-
|
-
|
1,198
|
876.6
|
1,198
|
876.6
|
|||
Non-core regions
|
77
|
20.9
|
121
|
24.8
|
198
|
45.7
|
|||
Total Canada
|
14,914
|
12,151.9
|
9,328
|
8,082.3
|
24,242
|
20,234.2
|
|||
United States
|
3
|
0.3
|
2
|
0.3
|
5
|
0.6
|
|||
North Sea UK Sector
|
2
|
0.1
|
108
|
91.1
|
110
|
91.2
|
|||
Offshore West Africa
|
|||||||||
Gabon
|
-
|
-
|
5
|
4.6
|
5
|
4.6
|
|||
Côte d’Ivoire
|
-
|
-
|
23
|
13.4
|
23
|
13.4
|
|||
Total
|
14,919
|
12,152.3
|
9,466
|
8,191.7
|
24,385
|
20,344.0
|
Canadian Natural Resources Limited
|
24
|
25
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
26
|
27
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
28
|
29
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
30
|
Short lease name
|
Official lease number
|
Lease expiry date(1)
|
Area in hectares
|
Lease 18
|
727912T18
|
Continued Producing(2)
|
19,988
|
Lease 6
|
7597050T06
|
May 6, 2012
|
2,584
|
Lease 7
|
7597050T07
|
May 6, 2012
|
1,144
|
Lease 10
|
7400120010
|
December 14, 2015
|
3,840
|
Lease 11
|
7400120011
|
December 14, 2015
|
518
|
Lease 12
|
7400120012
|
December 14, 2015
|
9,216
|
Lease 13
|
7400120013
|
December 14, 2015
|
69
|
Lease 15
|
7400120015
|
December 14, 2015
|
1,536
|
Lease 25
|
7401050025
|
May 17, 2016
|
1,536
|
Lease 19
|
7402050019
|
May 30, 2017
|
5,120
|
Lease 20
|
7402050020
|
May 30, 2017
|
768
|
(1)
|
The Company can apply for an extension of the leases past the expiry date.
|
(2)
|
Pursuant to section 14 of the Oil Sands Tenure Regulation.
|
31
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
32
|
33
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
34
|
35
|
Canadian Natural Resources Limited
|
B.
|
CRUDE OIL, NGLs, AND NATURAL GAS RESERVES
|
Canadian Natural Resources Limited
|
36
|
Reserves Category
|
Crude Oil &
NGLs
(mmbbl)
|
Bitumen
(mmbbl)
|
Synthetic
Crude Oil
(mmbbl)
|
Total
Liquids
(mmbbl)
|
Natural
Gas (bcf)
|
Total
Reserves
(mmboe)
|
PROVED
|
||||||
Developed:
|
||||||
North America
|
204
|
268
|
1,589
|
2,061
|
2,333
|
2,450
|
International
|
||||||
United Kingdom – North Sea
|
94
|
-
|
-
|
94
|
45
|
101
|
Offshore West Africa
|
106
|
-
|
-
|
106
|
81
|
120
|
Total Developed:
|
404
|
268
|
1,589
|
2,261
|
2,459
|
2,671
|
Undeveloped:
|
||||||
North America
|
115
|
427
|
61
|
603
|
694
|
719
|
International
|
||||||
United Kingdom – North Sea
|
146
|
-
|
-
|
146
|
22
|
149
|
Offshore West Africa
|
17
|
-
|
-
|
17
|
4
|
18
|
Total Undeveloped:
|
278
|
427
|
61
|
766
|
720
|
886
|
TOTAL PROVED:
|
682
|
695
|
1,650
|
3,027
|
3,179
|
3,557
|
37
|
Canadian Natural Resources Limited
|
Reserves Category
|
Crude Oil & NGLs (mmbbl)
|
Bitumen
(mmbbl) |
Synthetic Crude Oil
(mmbbl)
|
Total
Liquids
(mmbbl)
|
Natural
Gas (bcf) |
Total Reserves (mmboe)
|
PROBABLE
|
||||||
Developed:
|
||||||
North America
|
72
|
23
|
79
|
174
|
709
|
292
|
International
|
||||||
United Kingdom – North Sea
|
35
|
-
|
-
|
35
|
8
|
36
|
Offshore West Africa
|
5
|
-
|
-
|
5
|
26
|
9
|
Total Developed:
|
112
|
23
|
79
|
214
|
743
|
337
|
Undeveloped:
|
||||||
North America
|
56
|
495
|
783
|
1,334
|
256
|
1,377
|
International
|
||||||
United Kingdom – North Sea
|
112
|
-
|
-
|
112
|
19
|
116
|
Offshore West Africa
|
51
|
-
|
-
|
51
|
13
|
53
|
Total Undeveloped:
|
219
|
495
|
783
|
1,497
|
288
|
1,546
|
TOTAL PROBABLE:
|
331
|
518
|
862
|
1,711
|
1,031
|
1,883
|
Canadian Natural Resources Limited
|
38
|
Price Case
|
Proved Reserves
|
|||||
Crude Oil & NGLs (mmbbl)
|
Bitumen
(mmbbl) |
Synthetic Crude Oil (mmbbl)
|
Total Liquids
(mmbbl) |
Natural
Gas (bcf) |
Total Reserves (mmboe)
|
|
December 31, 2009 Forecast Pricing
|
684
|
652
|
1,564
|
2,900
|
3,491
|
3,482
|
Price Case
|
Probable Reserves
|
|||||
Crude Oil & NGLs (mmbbl)
|
Bitumen
(mmbbl) |
Synthetic Crude Oil (mmbbl)
|
Total Liquids
(mmbbl) |
Natural
Gas (bcf) |
Total Reserves (mmboe)
|
|
December 31, 2009 Forecast Pricing
|
295
|
482
|
820
|
1,597
|
1,174
|
1,793
|
1.
|
“Net” reserves mean the Company’s gross reserves less all royalties payable to others plus royalties receivable from others.
|
2.
|
Bitumen as defined by the SEC, under the Final Rule, “is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.” Under this definition, all the Company’s primary and thermal heavy crude oil reserves have been reclassified as bitumen. Prior to December 31, 2009, these reserves would have been classified within the Company’s conventional crude oil and NGLs totals.
|
3.
|
Prior to December 31, 2009, the Company’s Horizon SCO reserves were reported separately in accordance to the SEC’s Industry Guide 7. With SEC’s Final Rule in effect January 1, 2010, for fiscal years ending on or after December 31, 2009, this SCO is now included in the Company’s crude oil and natural gas reserve totals.
|
4.
|
“Proved” oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Under the Final Rule it is required that these reserves be evaluated using 12-month average prices and current costs and be disclosed net of royalties. The Company has also provided these reserves using forecast prices and costs in a sensitivity table as permitted by the SEC under the Final Rule.
|
5.
|
“Developed” oil and gas reserves are reserves of any category that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of required equipment is relatively minor to the cost of drilling a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
|
6.
|
“Undeveloped” reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where relatively major expenditures are required for the completion of these wells or for the installation of processing and gathering facilities prior to the production of these reserves. Reserves on undrilled acreage are limited to those drilling units directly offsetting development spacing areas that are reasonably certain of production when drilled unless reliable technology exists that establishes reasonable certainty of economic producibilty at greater distances.
|
7.
|
”Probable” reserves estimates are provided as optional disclosure under the Final Rule. Probable reserves are those additional reserves that are less certain to be recovered than proved, however, together with proved are as likely as not to be recovered. Under the Final Rule it is required that these be evaluated using 12-month average prices and current costs and be disclosed net of royalties. The reserve estimates could be materially different from the quantities ultimately realized. The Company has also provided these reserves using forecast prices and costs in a sensitivity table as permitted by the SEC under the Final Rule.
|
39
|
Canadian Natural Resources Limited
|
8.
|
The 12-month average price and current cost case assumes that the 2009 average prices adjusted for quality and transportation, as well as the 2009 costs, are held constant over life. The 12-month average prices are determined by calculating the arithmetic unweighted average of the first-day-of-month price for each month of the 12-month period prior to December 31, 2009. These price assumptions assume the continuance of current laws, regulations and operating costs in effect on the date of the Evaluation Report. Product prices have been held constant at the 2009 values shown below. In addition, operating and capital costs have not been increased on an inflationary basis. The following table outlines the prices calculated and used (based on a foreign exchange rate of US$0.87/C$1.00):
|
Natural gas 12-month average price
|
Crude oil & NGLs 12-month average price
|
|||||||||||||||||||||||||||||||||||
(Year)
|
Company average
price
(C$/mcf)
|
Henry Hub Louisiana (US$/mmbtu)
|
AECO
(C$/mmbtu)
|
Huntingdon/ Sumas (C$/mmbtu)
|
Company average
price
(C$/bbl)
|
WTI @
Cushing(1) (US$/bbl)
|
WCS(2)
(C$/bbl)
|
Edmonton
Par(3)
(C$/bbl)
|
North Sea Brent
(US$/bbl)
|
|||||||||||||||||||||||||||
2009
|
4.02 | 3.87 | 3.87 | 3.92 | 59.39 | 61.18 | 58.49 | 66.07 | 59.91 |
(1)
|
“WTI @ Cushing” refers to the price of West Texas Intermediate crude oil at Cushing, Oklahoma.
|
(2)
|
“WCS” refers to the price of Western Canada Select at Hardisty, Alberta.
|
(3)
|
“Edmonton Par” refers to the price of light gravity (40° API), low sulphur content crude oil at Edmonton, Alberta.
|
9.
|
The forecast price and cost case assumes the continuance of current laws and regulations, and any increases in wellhead selling prices also take inflation into account. Sales prices are based on reference prices as detailed below and adjusted for quality and transportation. Capital and operating costs are escalated at 2% per year. Future crude oil, NGLs and natural gas price forecasts were based on Sproule’s December 31, 2009 crude oil, NGLs and natural gas pricing model.
|
|
The Company’s weighted average crude oil and NGLs price and the weighted average natural gas price in the 2009 evaluation for 2010 were $75.92 per barrel and $5.48 per mcf respectively. The crude oil, NGLs and natural gas forecast prices used in the Evaluation Reports are as follows:
|
Natural gas
|
Crude oil & NGLs
|
|||||||||||||||||||||||||||||||||||
(Year)
|
Company average
price
(C$/mcf)
|
Henry Hub Louisiana (US$/mmbtu)
|
AECO
(C$/mmbtu)
|
Huntingdon/ Sumas (C$/mmbtu)
|
Company average
price
(C$/bbl)
|
WTI @
Cushing (US$/bbl)
|
WCS
(C$/bbl)
|
Edmonton Par
(C$/bbl)
|
North
Sea
Brent (US$/bbl)
|
|||||||||||||||||||||||||||
2010
|
5.48 | 5.70 | 5.36 | 5.61 | 75.92 | 79.17 | 74.14 | 84.25 | 77.92 | |||||||||||||||||||||||||||
2011
|
6.36 | 6.48 | 6.21 | 6.46 | 80.82 | 84.46 | 78.29 | 89.99 | 83.19 | |||||||||||||||||||||||||||
2012
|
6.60 | 6.70 | 6.44 | 6.69 | 82.83 | 86.89 | 76.86 | 92.61 | 85.59 | |||||||||||||||||||||||||||
2013
|
7.43 | 7.43 | 7.23 | 7.48 | 85.32 | 90.20 | 78.87 | 96.19 | 88.88 | |||||||||||||||||||||||||||
2014
|
8.20 | 8.12 | 7.98 | 8.23 | 87.11 | 92.01 | 79.49 | 98.13 | 90.65 | |||||||||||||||||||||||||||
2015
|
8.39 | 8.28 | 8.16 | 8.41 | 89.18 | 93.85 | 81.09 | 100.11 | 92.47 | |||||||||||||||||||||||||||
2016
|
8.53 | 8.45 | 8.34 | 8.59 | 90.73 | 95.72 | 82.73 | 102.13 | 94.32 | |||||||||||||||||||||||||||
2017
|
8.70 | 8.62 | 8.52 | 8.77 | 93.64 | 97.64 | 84.40 | 104.19 | 96.20 | |||||||||||||||||||||||||||
2018
|
8.87 | 8.79 | 8.71 | 8.96 | 95.97 | 99.59 | 86.10 | 106.30 | 98.13 | |||||||||||||||||||||||||||
2019
|
9.06 | 8.96 | 8.90 | 9.15 | 99.53 | 101.58 | 87.84 | 108.44 | 100.09 | |||||||||||||||||||||||||||
2020
|
9.26 | 9.14 | 9.10 | 9.35 | 101.42 | 103.61 | 89.61 | 110.63 | 102.09 |
Canadian Natural Resources Limited
|
40
|
10.
|
The estimated total development capital costs, net to the Company, necessary to develop the reported reserves:
|
Proved | Probable | |||||||||||||||
(C$millions)
|
12-Month
Average case
|
Forecast Price Case
|
12-Month
Average case
|
Forecast Price Case
|
||||||||||||
2010
|
2,003 | 2,033 | 298 | 292 | ||||||||||||
2011
|
2,250 | 2,382 | 1,578 | 1,615 | ||||||||||||
2012
|
1,868 | 2,028 | 2,616 | 2,735 | ||||||||||||
2013
|
1,711 | 1,907 | 3,552 | 3,832 | ||||||||||||
2014
|
1,173 | 1,331 | 3,155 | 3,419 | ||||||||||||
2015
|
941 | 1,115 | 1,557 | 1,727 | ||||||||||||
2016
|
1,023 | 1,200 | 1,369 | 1,551 | ||||||||||||
2017
|
736 | 894 | 285 | 3,331 | ||||||||||||
2018
|
564 | 704 | 309 | 346 | ||||||||||||
2019
|
575 | 701 | 283 | 341 | ||||||||||||
2020
|
533 | 655 | 273 | 376 | ||||||||||||
Thereafter
|
2,207 | 30,694 | 20,500 | 23,422 |
11.
|
The Evaluation Reports involved data supplied by the Company with respect to quality, heating value and transportation adjustments, interests owned, royalties payable, operating costs and contractual commitments. This data was found by GLJ and Sproule to be reasonable.
|
|
A report on reserves data by the independent qualified reserves evaluators are provided in Schedule “A” to this Annual Information Form. A report by the Company’s management and directors on crude oil and natural gas disclosure is provided in Schedule “B” to this Annual Information Form. The Company does not file estimates of its total crude oil and natural gas reserves with any U. S. agency or federal authority other than the SEC.
|
41
|
Canadian Natural Resources Limited
|
C.
|
RECONCILIATION OF CHANGES IN NET RESERVES
|
North America | International | Total | |||||
Net Proved Reserves (mmbbl)
|
Synthetic
Crude Oil(1) |
Bitumen
|
Crude Oil
& NGLs |
Total
|
North
Sea
|
Offshore
West Africa
|
|
Reserves, December 31, 2007(1)
|
920
|
310
|
128
|
1,358
|
|||
Extensions and discoveries
|
51
|
-
|
-
|
51
|
|||
Improved recovery
|
17
|
6
|
4
|
27
|
|||
Purchases of reserves in place
|
-
|
-
|
-
|
-
|
|||
Sales of reserves in place
|
-
|
-
|
-
|
-
|
|||
Production
|
(76)
|
(17)
|
(8)
|
(101)
|
|||
Economic revisions due to prices
|
28
|
(81)
|
8
|
(45)
|
|||
Revisions of prior estimates
|
8
|
38
|
10
|
56
|
|||
Reserves, December 31, 2008(1)
|
–
|
690
|
258
|
948
|
256
|
142
|
1,346
|
Extensions and discoveries
|
–
|
24
|
6
|
30
|
–
|
–
|
30
|
Improved recovery
|
–
|
8
|
75
|
83
|
–
|
–
|
83
|
SEC Reliable Technology (2)
|
–
|
7
|
–
|
7
|
–
|
–
|
7
|
SEC Rule Transition (3)
|
1,650
|
–
|
–
|
1,650
|
–
|
–
|
1,650
|
Purchases of reserves in place
|
–
|
–
|
1
|
1
|
–
|
–
|
1
|
Sales of reserves in place
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
Production
|
–
|
(49)
|
(24)
|
(73)
|
(14)
|
(11)
|
(98)
|
Economic revisions due to prices
|
–
|
(64)
|
(8)
|
(72)
|
57
|
(4)
|
(19)
|
Revisions of prior estimates
|
–
|
79
|
11
|
90
|
(59)
|
(4)
|
27
|
Reserves, December 31, 2009
|
1,650
|
695
|
319
|
2,664
|
240
|
123
|
3,027
|
Canadian Natural Resources Limited
|
42
|
North America
|
International
|
Total
|
|||||
Net Probable Reserves
(mmbbl)(4)
|
Synthetic
Crude Oil (1)
|
Bitumen
|
Crude Oil
& NGLs |
Total
|
North
Sea
|
Offshore
West Africa
|
|
Reserves, December 31, 2007(1)
|
625
|
95
|
58
|
778
|
|||
Extensions and discoveries
|
25
|
-
|
-
|
25
|
|||
Improved recovery
|
15
|
(2)
|
(4)
|
9
|
|||
Purchases of reserves in place
|
6
|
-
|
-
|
6
|
|||
Sales of reserves in place
|
-
|
-
|
-
|
-
|
|||
Production
|
-
|
-
|
-
|
-
|
|||
Economic revisions due to prices
|
31
|
36
|
-
|
67
|
|||
Revisions of prior estimates
|
(51)
|
14
|
(5)
|
(42)
|
|||
Reserves, December 31, 2008(1)
|
-
|
548
|
103
|
651
|
143
|
49
|
843
|
Extensions and discoveries
|
-
|
11
|
5
|
16
|
-
|
-
|
16
|
Improved recovery
|
-
|
4
|
37
|
41
|
-
|
-
|
41
|
SEC Reliable Technology (2)
|
-
|
3
|
-
|
3
|
-
|
-
|
3
|
SEC Rule Transition (3)
|
862
|
-
|
-
|
862
|
-
|
-
|
862
|
Purchases of reserves in place
|
-
|
-
|
1
|
1
|
-
|
-
|
1
|
Sales of reserves in place
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Production
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Economic revisions due to prices
|
-
|
(71)
|
5
|
(66)
|
(44)
|
(2)
|
(112)
|
Revisions of prior estimates
|
-
|
23
|
(23)
|
-
|
48
|
9
|
57
|
Reserves, December 31, 2009
|
862
|
518
|
128
|
1,508
|
147
|
56
|
1,711
|
43
|
Canadian Natural Resources Limited
|
Natural Gas Reserves Reconciliation, Net of Royalties
|
||||
Net Proved Reserves (bcf)
|
North
America
|
North
Sea
|
Offshore
West Africa
|
Total
|
Reserves, December 31, 2007(1)
|
3,521
|
81
|
64
|
3,666
|
Extensions and discoveries
|
140
|
-
|
-
|
140
|
Improved recovery
|
52
|
(1)
|
6
|
57
|
Property purchases
|
77
|
-
|
-
|
77
|
Property disposals
|
(1)
|
-
|
-
|
(1)
|
Production
|
(449)
|
(4)
|
(4)
|
(457)
|
Economic revisions due to prices
|
(19)
|
(56)
|
6
|
(69)
|
Revisions of prior estimates
|
202
|
47
|
22
|
271
|
Reserves, December 31, 2008(1)
|
3,523
|
67
|
94
|
3,684
|
Extensions and discoveries
|
92
|
-
|
-
|
92
|
Improved recovery
|
11
|
-
|
-
|
11
|
SEC Reliable Technology (2)
|
-
|
-
|
-
|
-
|
Property purchases
|
15
|
-
|
-
|
15
|
Property disposals
|
(6)
|
-
|
-
|
(6)
|
Production
|
(443)
|
(4)
|
(6)
|
(453)
|
Economic revisions due to prices
|
(335)
|
12
|
(4)
|
(327)
|
Revisions of prior estimates
|
170
|
(8)
|
1
|
163
|
Reserves, December 31, 2009
|
3,027
|
67
|
85
|
3,179
|
Canadian Natural Resources Limited
|
44
|
Net Probable Reserves (bcf)(4)
|
North
America
|
North
Sea
|
Offshore
West Africa
|
Total
|
Reserves, December 31, 2007(1)
|
1,081
|
32
|
24
|
1,137
|
Extensions and discoveries
|
42
|
-
|
-
|
42
|
Improved recovery
|
14
|
(2)
|
(6)
|
6
|
Property purchases
|
16
|
-
|
-
|
16
|
Property disposals
|
(5)
|
-
|
-
|
(5)
|
Production
|
-
|
-
|
-
|
-
|
Economic revisions due to prices
|
(8)
|
(7)
|
2
|
(13)
|
Revisions of prior estimates
|
(44)
|
4
|
17
|
(23)
|
Reserves, December 31, 2008(1)
|
1,096
|
27
|
37
|
1,160
|
Extensions and discoveries
|
19
|
-
|
-
|
19
|
Improved recovery
|
2
|
-
|
-
|
2
|
SEC Reliable Technology (2)
|
-
|
-
|
-
|
-
|
Property purchases
|
4
|
-
|
-
|
4
|
Property disposals
|
(1)
|
-
|
-
|
(1)
|
Production
|
-
|
-
|
-
|
-
|
Economic revisions due to prices
|
(94)
|
(5)
|
(1)
|
(100)
|
Revisions of prior estimates
|
(61)
|
5
|
3
|
(53)
|
Reserves, December 31, 2009
|
965
|
27
|
39
|
1,031
|
1.
|
Reserves evaluated prior to December 31, 2009 were evaluated based on year end prices and costs. Previous year totals do not include SCO reserves.
|
2.
|
SEC Reliable Technology accounts for reserves volumes added due to the reserves rule changes to allow booking of undeveloped reserves beyond one spacing unit with supporting geoscience and engineering data. Canadian Natural uses the combination of seismic, well logs, core analysis, production history and analogies to support the booking of undeveloped reserves.
|
3.
|
SEC Rule Transition accounts for the inclusion of Horizon SCO reserves volume additions as a result of oil sands mining being included as a crude oil and natural gas activity effective December 31, 2009. For continuity purposes, with respect to the transition from Industry Guide 7 into the SEC’s Final Rule, the following table has been provided to illustrate the changes in the Company’s Horizon SCO reserves for the 2009 year.
|
Horizon SCO Reserves
|
Net Proved (mmbbl)
|
Probable (mmbbl)
|
Reserves, December 31, 2008
|
1,946
|
998
|
Production
|
(18)
|
-
|
Economic revisions due to prices
|
(307)
|
(127)
|
Revisions of prior estimates
|
29
|
(9)
|
Reserves, December 31, 2009
|
1,650
|
862
|
4.
|
Prior to December 31, 2009, probable reserve estimates were evaluated in accordance with the standards of COGEH.
|
45
|
Canadian Natural Resources Limited
|
D.
|
CRUDE OIL, NGLs, AND NATURAL GAS PRODUCTION
|
Year Ended December 31
|
|||
Daily Production, before royalties
|
2009
|
2008
|
2007
|
Crude oil and NGLs production, (bbl/d)
|
|||
North America - Conventional
|
234,523
|
243,826
|
246,779
|
North America – Oil sands Mining and Upgrading
|
50,250
|
-
|
-
|
North Sea
|
37,761
|
45,274
|
55,933
|
Offshore West Africa
|
32,929
|
26,567
|
28,520
|
355,463
|
315,667
|
331,232
|
|
Natural gas production (mmcf/d)
|
|||
North America
|
1,287
|
1,472
|
1,643
|
North Sea
|
10
|
10
|
13
|
Offshore West Africa
|
18
|
13
|
12
|
1,315
|
1,495
|
1,668
|
|
Total Production boe/d
|
574,730
|
564,845
|
609,206
|
Year Ended December 31
|
|||
Daily Production, net of royalties
|
2009
|
2008
|
2007
|
Crude oil and NGLs production, (bbl/d)
|
|||
North America - Conventional
|
201,873
|
207,933
|
210,769
|
North America – Oil sands Mining and Upgrading
|
48,833
|
-
|
-
|
North Sea
|
37,683
|
45,182
|
55,825
|
Offshore West Africa
|
29,922
|
22,641
|
26,012
|
318,311
|
275,756
|
292,606
|
|
Natural gas production (mmcf/d)
|
|||
North America
|
1,214
|
1,225
|
1,378
|
North Sea
|
10
|
10
|
13
|
Offshore West Africa
|
17
|
11
|
11
|
1,241
|
1,246
|
1,402
|
|
Total Production boe/d
|
525,103
|
483,541
|
526,193
|
Canadian Natural Resources Limited
|
46
|
2009 | 2008 | |||||||||||||||||||||||||||||||||||||||
Q1 | Q2 | Q3 | Q4 |
Year Ended
|
Q1 | Q2 | Q3 | Q4 |
Year Ended
|
|||||||||||||||||||||||||||||||
Average daily production volumes, before royalties
|
||||||||||||||||||||||||||||||||||||||||
Conventional Crude oil and
NGLs (bbl/d) |
326,633 | 306,073 | 292,363 | 296,257 | 305,213 | 327,217 | 319,077 | 306,970 | 309,570 | 315,667 | ||||||||||||||||||||||||||||||
SCO (bbl/d)
|
3,384 | 59,599 | 66,907 | 70,194 | 50,250 | - | - | - | - | - | ||||||||||||||||||||||||||||||
Natural gas (mmcf/d)
|
1,369 | 1,352 | 1,293 | 1,250 | 1,315 | 1,538 | 1,526 | 1,490 | 1,427 | 1,495 | ||||||||||||||||||||||||||||||
Product netbacks (1)
|
||||||||||||||||||||||||||||||||||||||||
Conventional Crude oil and NGLs ($/bbl)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | 41.25 | $ | 59.56 | $ | 62.90 | $ | 68.00 | $ | 57.68 | $ | 78.99 | $ | 103.70 | $ | 102.30 | $ | 45.81 | $ | 82.41 | ||||||||||||||||||||
Royalties
|
3.98 | 7.27 | 7.89 | 7.96 | 6.73 | 8.70 | 14.82 | 14.17 | 4.49 | 10.48 | ||||||||||||||||||||||||||||||
Production expenses
|
15.02 | 16.59 | 16.71 | 15.45 | 15.92 | 14.81 | 16.39 | 17.61 | 16.33 | 16.26 | ||||||||||||||||||||||||||||||
Netback
|
$ | 22.25 | $ | 35.70 | $ | 38.30 | $ | 44.59 | $ | 35.03 | $ | 55.48 | $ | 72.52 | $ | 70.52 | $ | 24.99 | $ | 55.67 | ||||||||||||||||||||
SCO ($/bbl)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | - | $ | 65.40 | $ | 69.11 | $ | 76.33 | $ | 70.83 | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||||||||||||
Royalties
|
- | 0.76 | 2.19 | 3.06 | 2.15 | - | - | - | - | - | ||||||||||||||||||||||||||||||
Production expenses
|
42.65 | 36.85 | 41.21 | 39.89 | - | - | - | - | - | |||||||||||||||||||||||||||||||
Netback
|
$ | - | $ | 21.99 | $ | 30.07 | $ | 32.06 | $ | 28.79 | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||||||||||||
Natural gas ($/mcf)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | 5.46 | $ | 4.11 | $ | 3.80 | $ | 4.75 | $ | 4.53 | $ | 7.77 | $ | 9.89 | $ | 8.82 | $ | 7.03 | $ | 8.39 | ||||||||||||||||||||
Royalties(3)
|
0.72 | 0.06 | 0.13 | 0.35 | 0.32 | 1.35 | 1.86 | 1.55 | 1.08 | 1.46 | ||||||||||||||||||||||||||||||
Production expenses
|
1.18 | 1.05 | 1.05 | 1.03 | 1.08 | 1.03 | 0.94 | 1.05 | 1.06 | 1.02 | ||||||||||||||||||||||||||||||
Netback
|
$ | 3.56 | $ | 3.00 | $ | 2.62 | $ | 3.37 | $ | 3.13 | $ | 5.39 | $ | 7.09 | $ | 6.22 | $ | 4.89 | $ | 5.91 | ||||||||||||||||||||
Conventional Crude oil and NGLs netbacks by type(1)
|
||||||||||||||||||||||||||||||||||||||||
Light/Medium/Pelican Lake/NGLs ($/bbl)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | 47.93 | $ | 60.87 | $ | 65.58 | $ | 70.82 | $ | 61.37 | $ | 89.68 | $ | 114.69 | $ | 107.33 | $ | 53.16 | $ | 90.88 | ||||||||||||||||||||
Royalties
|
4.94 | 6.70 | 9.27 | 7.96 | 7.20 | 11.43 | 14.59 | 15.84 | 5.71 | 11.83 | ||||||||||||||||||||||||||||||
Production expenses
|
15.02 | 16.87 | 17.48 | 16.79 | 16.53 | 15.09 | 16.13 | 17.18 | 17.92 | 16.56 | ||||||||||||||||||||||||||||||
Netback
|
$ | 27.97 | $ | 37.30 | $ | 38.83 | $ | 46.07 | $ | 37.64 | $ | 63.15 | $ | 83.97 | $ | 74.30 | $ | 29.53 | $ | 62.49 | ||||||||||||||||||||
Primary and Thermal Heavy crude oil ($/bbl)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | 34.80 | $ | 58.14 | $ | 60.08 | $ | 64.73 | $ | 53.76 | $ | 67.46 | $ | 92.55 | $ | 97.20 | $ | 38.21 | $ | 73.62 | ||||||||||||||||||||
Royalties
|
3.06 | 7.89 | 6.43 | 7.97 | 6.23 | 5.74 | 15.05 | 12.47 | 3.22 | 9.08 | ||||||||||||||||||||||||||||||
Production expenses
|
15.02 | 16.29 | 15.91 | 13.89 | 15.27 | 14.50 | 16.65 | 18.05 | 14.68 | 15.95 | ||||||||||||||||||||||||||||||
Netback
|
$ | 16.72 | $ | 33.96 | $ | 37.74 | $ | 42.87 | $ | 32.26 | $ | 47.22 | $ | 60.85 | $ | 66.68 | $ | 20.31 | $ | 48.59 |
(1)
|
Amounts expressed on a per unit basis are based on sales volumes.
|
(2)
|
Net of transportation and blending costs and excluding risk management activities.
|
(3)
|
Natural gas royalties for 2009 reflect the impact of natural gas physical sales contracts.
|
47
|
Canadian Natural Resources Limited
|
NETBACKS
|
||||||||||||||||||||
INFORMATION BY QUARTER
|
||||||||||||||||||||
2007
|
||||||||||||||||||||
Q1 | Q2 | Q3 | Q4 |
Year
Ended
|
||||||||||||||||
Average daily production volumes, before royalties
|
||||||||||||||||||||
Conventional Crude oil and NGLs (bbl/d)
|
327,001 | 327,494 | 333,062 | 337,240 | 331,232 | |||||||||||||||
Natural gas (mmcf/d)
|
1,717 | 1,722 | 1,647 | 1,589 | 1,668 | |||||||||||||||
Product netbacks(1)
|
||||||||||||||||||||
Conventional Crude oil and NGLs ($/bbl)
|
||||||||||||||||||||
Sales price (2)
|
$ | 51.71 | $ | 53.74 | $ | 58.10 | $ | 58.03 | $ | 55.45 | ||||||||||
Royalties
|
4.92 | 5.46 | 6.65 | 6.66 | 5.94 | |||||||||||||||
Production expenses
|
13.81 | 15.01 | 13.13 | 11.53 | 13.34 | |||||||||||||||
Netback
|
$ | 32.98 | $ | 33.27 | $ | 38.32 | $ | 39.84 | $ | 36.17 | ||||||||||
Natural gas ($/mcf)
|
||||||||||||||||||||
Sales price (2)
|
$ | 7.74 | $ | 7.44 | $ | 5.87 | $ | 6.28 | $ | 6.85 | ||||||||||
Royalties
|
1.48 | 1.10 | 0.89 | 0.94 | 1.11 | |||||||||||||||
Production expenses
|
0.97 | 0.89 | 0.88 | 0.91 | 0.91 | |||||||||||||||
Netback
|
$ | 5.29 | $ | 5.45 | $ | 4.10 | $ | 4.43 | $ | 4.83 | ||||||||||
Conventional Crude oil and NGLs netbacks by type(1)
|
||||||||||||||||||||
Light/Medium/Pelican Lake/NGLs ($/bbl)
|
||||||||||||||||||||
Sales price (2)
|
$ | 60.19 | $ | 64.10 | $ | 67.34 | $ | 72.62 | $ | 65.99 | ||||||||||
Royalties
|
4.89 | 5.87 | 7.24 | 8.34 | 6.57 | |||||||||||||||
Production expenses
|
13.85 | 14.91 | 14.40 | 12.64 | 13.95 | |||||||||||||||
Netback
|
$ | 41.45 | $ | 43.32 | $ | 45.70 | $ | 51.64 | $ | 45.47 | ||||||||||
Primary and Thermal Heavy crude oil ($/bbl)
|
||||||||||||||||||||
Sales price (2)
|
$ | 41.24 | $ | 41.85 | $ | 48.10 | $ | 43.06 | $ | 43.66 | ||||||||||
Royalties
|
4.96 | 4.98 | 6.00 | 4.95 | 5.23 | |||||||||||||||
Production expenses
|
13.76 | 15.12 | 11.75 | 10.38 | 12.66 | |||||||||||||||
Netback
|
$ | 22.52 | $ | 21.75 | $ | 30.35 | $ | 27.73 | $ | 25.77 |
(1)
|
Amounts expressed on a per unit basis are based on sales volumes.
|
(2)
|
Net of transportation and blending costs and excluding risk management activities.
|
Canadian Natural Resources Limited
|
48
|
2009 | 2008 | |||||||||||||||||||||||||||||||||||||||
Q1 | Q2 | Q3 | Q4 |
Year Ended
|
Q1 | Q2 | Q3 | Q4 | Year Ended | |||||||||||||||||||||||||||||||
SEGMENTED
|
||||||||||||||||||||||||||||||||||||||||
North America product netbacks(1)
|
||||||||||||||||||||||||||||||||||||||||
Light/Medium/Pelican Lake/NGLs ($/bbl)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | 42.39 | $ | 57.67 | $ | 60.06 | $ | 65.80 | $ | 56.38 | $ | 82.25 | $ | 107.38 | $ | 102.17 | $ | 44.21 | $ | 84.00 | ||||||||||||||||||||
Royalties
|
7.37 | 10.49 | 12.75 | 13.21 | 10.93 | 16.40 | 21.68 | 21.29 | 8.80 | 17.20 | ||||||||||||||||||||||||||||||
Production expenses
|
13.80 | 13.54 | 14.00 | 12.67 | 13.51 | 12.80 | 13.32 | 13.17 | 13.68 | 13.24 | ||||||||||||||||||||||||||||||
Netback
|
$ | 21.22 | $ | 33.64 | $ | 33.31 | $ | 39.92 | $ | 31.94 | $ | 53.05 | $ | 72.38 | $ | 67.70 | $ | 21.73 | $ | 53.72 | ||||||||||||||||||||
Primary and Thermal Heavy crude oil ($/bbl)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | 34.80 | $ | 58.14 | $ | 60.08 | $ | 64.73 | $ | 53.76 | $ | 67.46 | $ | 92.55 | $ | 97.20 | $ | 38.21 | $ | 73.62 | ||||||||||||||||||||
Royalties
|
3.06 | 7.89 | 6.43 | 7.97 | 6.23 | 5.74 | 15.05 | 12.47 | 3.22 | 9.08 | ||||||||||||||||||||||||||||||
Production expenses
|
15.02 | 16.29 | 15.91 | 13.89 | 15.27 | 14.50 | 16.65 | 18.05 | 14.68 | 15.95 | ||||||||||||||||||||||||||||||
Netback
|
$ | 16.72 | $ | 33.96 | $ | 37.74 | $ | 42.87 | $ | 32.26 | $ | 47.22 | $ | 60.85 | $ | 66.68 | $ | 20.31 | $ | 48.59 | ||||||||||||||||||||
SCO ($/bbl)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | - | $ | 65.40 | $ | 69.11 | $ | 76.33 | $ | 70.83 | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||||||||||||
Royalties
|
- | 0.76 | 2.19 | 3.06 | 2.15 | - | - | - | - | - | ||||||||||||||||||||||||||||||
Production expenses
|
- | 42.65 | 36.85 | 41.21 | 39.89 | - | - | - | - | - | ||||||||||||||||||||||||||||||
Netback
|
$ | - | $ | 21.99 | $ | 30.07 | $ | 32.06 | $ | 28.79 | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||||||||||||
Natural gas ($/mcf)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | 5.46 | $ | 4.06 | $ | 3.76 | $ | 4.75 | $ | 4.51 | $ | 7.74 | $ | 9.89 | $ | 8.76 | $ | 6.94 | $ | 8.41 | ||||||||||||||||||||
Royalties(3)
|
0.73 | 0.05 | 0.12 | 0.35 | 0.32 | 1.36 | 1.88 | 1.55 | 1.09 | 1.47 | ||||||||||||||||||||||||||||||
Production expenses
|
1.17 | 1.04 | 1.04 | 1.01 | 1.07 | 1.01 | 0.98 | 1.03 | 1.04 | 1.00 | ||||||||||||||||||||||||||||||
Netback
|
$ | 3.56 | $ | 2.97 | $ | 2.60 | $ | 3.39 | $ | 3.12 | $ | 5.37 | $ | 7.08 | $ | 6.18 | $ | 4.81 | $ | 5.88 | ||||||||||||||||||||
North Sea product netbacks(1)
|
||||||||||||||||||||||||||||||||||||||||
Light crude oil ($/bbl)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | 54.67 | $ | 65.52 | $ | 75.91 | $ | 78.89 | $ | 68.84 | $ | 99.01 | $ | 129.57 | $ | 109.82 | $ | 63.07 | $ | 100.31 | ||||||||||||||||||||
Royalties
|
0.13 | 0.11 | 0.16 | 0.15 | 0.14 | 0.91 | 0.27 | 0.24 | 0.12 | 0.21 | ||||||||||||||||||||||||||||||
Production expenses
|
22.39 | 27.36 | 31.30 | 27.03 | 26.98 | 22.35 | 25.61 | 29.21 | 28.77 | 26.29 | ||||||||||||||||||||||||||||||
Netback
|
$ | 32.15 | $ | 38.05 | $ | 44.45 | $ | 51.71 | $ | 41.72 | $ | 76.47 | $ | 103.69 | $ | 80.37 | $ | 34.18 | $ | 73.81 | ||||||||||||||||||||
Natural Gas ($/mcf)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | 4.28 | $ | 3.84 | $ | 5.70 | $ | 4.94 | $ | 4.66 | $ | 3.30 | $ | 4.27 | $ | 3.65 | $ | 5.19 | $ | 4.09 | ||||||||||||||||||||
Royalties
|
- | - | - | - | - | |||||||||||||||||||||||||||||||||||
Production expenses
|
1.86 | 1.62 | 1.57 | 3.23 | 2.16 | 2.33 | 2.68 | 3.09 | 1.96 | 2.51 | ||||||||||||||||||||||||||||||
Netback
|
$ | 2.42 | $ | 2.22 | $ | 4.13 | $ | 1.71 | $ | 2.50 | $ | 0.97 | $ | 1.59 | $ | 0.56 | $ | 3.23 | $ | 1.58 | ||||||||||||||||||||
Offshore West Africa product netbacks(1)
|
||||||||||||||||||||||||||||||||||||||||
Light crude oil ($/bbl)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | 54.27 | $ | 63.00 | $ | 70.05 | $ | 72.88 | $ | 65.27 | $ | 96.31 | $ | 114.56 | $ | 125.71 | $ | 65.80 | $ | 97.96 | ||||||||||||||||||||
Royalties
|
3.73 | 5.82 | 8.94 | 5.24 | 5.79 | 17.43 | 14.49 | 26.90 | 4.71 | 14.81 | ||||||||||||||||||||||||||||||
Production expenses
|
11.39 | 10.45 | 13.35 | 15.26 | 12.83 | 8.03 | 9.79 | 7.74 | 14.47 | 10.29 | ||||||||||||||||||||||||||||||
Netback
|
$ | 39.15 | $ | 46.73 | $ | 47.76 | $ | 52.38 | $ | 46.65 | $ | 70.85 | $ | 90.28 | $ | 91.07 | $ | 46.62 | $ | 72.86 | ||||||||||||||||||||
Natural Gas ($/mcf)
|
||||||||||||||||||||||||||||||||||||||||
Sales price (2)
|
$ | 6.68 | $ | 7.34 | $ | 5.72 | $ | 5.04 | $ | 6.11 | $ | 7.89 | $ | 8.97 | $ | 11.18 | $ | 12.54 | $ | 10.03 | ||||||||||||||||||||
Royalties
|
0.46 | 0.63 | 0.74 | 0.27 | 0.53 | 1.43 | 1.13 | 2.24 | 1.26 | 1.52 | ||||||||||||||||||||||||||||||
Production expenses
|
1.70 | 1.36 | 1.37 | 0.70 | 1.23 | 1.25 | 1.27 | 1.58 | 2.51 | 1.61 | ||||||||||||||||||||||||||||||
Netback
|
$ | 4.52 | $ | 5.35 | $ | 3.61 | $ | 4.07 | $ | 4.35 | $ | 5.21 | $ | 6.57 | $ | 7.36 | $ | 8.77 | $ | 6.90 |
(1)
|
Amounts expressed on a per unit basis are based on sales volumes.
|
(2)
|
Net of transportation and blending costs and excluding risk management activities.
|
(3)
|
Natural gas royalties for 2009 reflect the impact of natural gas physical sales contracts.
|
49
|
Canadian Natural Resources Limited
|
2007
|
||||||||||||||||||||||
Q1 | Q2 | Q3 | Q4 |
Year
Ended
|
||||||||||||||||||
SEGMENTED
|
||||||||||||||||||||||
North America product netbacks(1)
|
||||||||||||||||||||||
Light/Medium/Pelican Lake/NGLs ($/bbl)
|
||||||||||||||||||||||
Sales price (2)
|
$ | 54.13 | $ | 56.06 | $ | 60.26 | $ | 63.94 | $ | 58.66 | ||||||||||||
Royalties
|
8.84 | 9.22 | 11.55 | 12.56 | 10.57 | |||||||||||||||||
Production expense
|
11.74 | 12.11 | 11.58 | 10.82 | 11.56 | |||||||||||||||||
Netback
|
$ | 33.55 | $ | 34.73 | $ | 37.13 | $ | 40.56 | $ | 36.53 | ||||||||||||
Primary and Thermal Heavy crude oil ($/bbl)
|
||||||||||||||||||||||
Sales price (2)
|
$ | 41.24 | $ | 41.85 | $ | 48.10 | $ | 43.06 | $ | 43.66 | ||||||||||||
Royalties
|
4.96 | 4.98 | 6.00 | 4.95 | 5.23 | |||||||||||||||||
Production expense
|
13.76 | 15.12 | 11.75 | 10.38 | 12.66 | |||||||||||||||||
Netback
|
$ | 22.52 | $ | 21.75 | $ | 30.35 | $ | 27.73 | $ | 25.77 | ||||||||||||
Natural gas ($/mcf)
|
||||||||||||||||||||||
Sales price (2)
|
$ | 7.79 | $ | 7.47 | $ | 5.88 | $ | 6.31 | $ | 6.87 | ||||||||||||
Royalties
|
1.50 | 1.11 | 0.90 | 0.95 | 1.12 | |||||||||||||||||
Production expense
|
0.95 | 0.87 | 0.87 | 0.90 | 0.90 | |||||||||||||||||
Netback
|
$ | 5.34 | $ | 5.49 | $ | 4.11 | $ | 4.46 | $ | 4.85 | ||||||||||||
North Sea product netbacks(1)
|
||||||||||||||||||||||
Light crude oil ($/bbl)
|
||||||||||||||||||||||
Sales price (2)
|
$ | 68.83 | $ | 73.18 | $ | 77.55 | $ | 83.44 | $ | 74.99 | ||||||||||||
Royalties
|
0.13 | 0.13 | 0.14 | 0.19 | 0.14 | |||||||||||||||||
Production expense
|
18.57 | 22.11 | 23.61 | 18.95 | 20.78 | |||||||||||||||||
Netback
|
$ | 50.13 | $ | 50.94 | $ | 53.80 | $ | 64.30 | $ | 54.07 | ||||||||||||
Natural gas ($/mcf)
|
||||||||||||||||||||||
Sales price (2)
|
$ | 4.49 | $ | 3.92 | $ | 5.26 | $ | 3.62 | $ | 4.26 | ||||||||||||
Royalties
|
- | - | - | - | - | |||||||||||||||||
Production expense
|
2.58 | 2.26 | 2.29 | 1.50 | 2.17 | |||||||||||||||||
Netback
|
$ | 1.91 | $ | 1.66 | $ | 2.97 | $ | 2.12 | $ | 2.09 | ||||||||||||
Offshore West Africa product netbacks(1)
|
||||||||||||||||||||||
Light crude oil ($/bbl)
|
||||||||||||||||||||||
Sales price (2)
|
$ | 58.60 | $ | 72.84 | $ | 70.52 | $ | 81.89 | $ | 71.68 | ||||||||||||
Royalties
|
3.70 | 7.12 | 6.81 | 7.59 | 6.40 | |||||||||||||||||
Production expense
|
8.93 | 7.98 | 7.00 | 9.32 | 8.32 | |||||||||||||||||
Netback
|
$ | 45.97 | $ | 57.74 | $ | 56.71 | $ | 64.98 | $ | 56.96 | ||||||||||||
Natural gas ($/mcf)
|
||||||||||||||||||||||
Sales price (2)
|
$ | 5.97 | $ | 6.22 | $ | 5.31 | $ | 5.49 | $ | 5.68 | ||||||||||||
Royalties
|
0.38 | 0.59 | 0.51 | 0.52 | 0.51 | |||||||||||||||||
Production expense
|
1.48 | 1.10 | 1.39 | 1.89 | 1.48 | |||||||||||||||||
Netback
|
$ | 4.11 | $ | 4.53 | $ | 3.41 | $ | 3.08 | $ | 3.69 |
(1)
|
Amounts expressed on a per unit basis are based on sales volumes.
|
(2)
|
Net of transportation and blending costs and excluding risk management activities.
|
Canadian Natural Resources Limited
|
50
|
E.
|
NET CAPITAL EXPENDITURES
|
NET CAPITAL EXPENDITURES BY YEAR (1)
|
||||||||
Year Ended December 31
|
||||||||
($ millions)
|
2009
|
2008
|
||||||
Net property acquisitions (dispositions)
|
$ | 6 | $ | 336 | ||||
Land acquisition and retention
|
77 | 86 | ||||||
Seismic evaluations
|
73 | 107 | ||||||
Well drilling, completion and equipping
|
1,244 | 1,664 | ||||||
Production and related facilities
|
977 | 1,282 | ||||||
Total net reserve replacement expenditures
|
2,377 | 3,475 | ||||||
Oil Sands Mining and Upgrading
|
||||||||
Horizon Phase 1 construction costs
|
69 | 2,732 | ||||||
Horizon Phase 1 commissioning and other costs
|
202 | 364 | ||||||
Horizon Phase 2/3 costs
|
104 | 336 | ||||||
Capitalized interest, stock-based compensation and other
|
98 | 480 | ||||||
Sustaining Capital
|
80 | - | ||||||
Total Oil Sands Mining and Upgrading (2)
|
553 | 3,912 | ||||||
Midstream
|
6 | 9 | ||||||
Abandonments (3)
|
48 | 38 | ||||||
Head office
|
13 | 17 | ||||||
Total net capital expenditures
|
$ | 2,997 | $ | 7,451 |
2009 Three Months Ended | ||||||||||||||||
($ millions)
|
Mar 31
|
Jun 30
|
Sep 30
|
Dec 31
|
||||||||||||
Net property acquisitions (dispositions)
|
$ | 27 | (2 | ) | (30 | ) | 11 | |||||||||
Land acquisition and retention
|
13 | 18 | 18 | 28 | ||||||||||||
Seismic evaluation
|
28 | 11 | 21 | 13 | ||||||||||||
Well drilling, completion and equipping
|
498 | 194 | 261 | 291 | ||||||||||||
Production and related facilities
|
290 | 230 | 235 | 222 | ||||||||||||
Total net reserve replacement expenditures
|
856 | 451 | 505 | 565 | ||||||||||||
Oil Sands Mining and Upgrading
|
||||||||||||||||
Horizon Phase 1 construction costs
|
128 | (59 | ) | - | - | |||||||||||
Horizon Phase 1 commissioning and other costs
|
156 | 46 | - | - | ||||||||||||
Horizon Phase 2/3 costs
|
19 | 22 | 21 | 42 | ||||||||||||
Capitalized interest, stock-based compensation and other
|
79 | (4 | ) | 11 | 12 | |||||||||||
Sustaining Capital
|
- | 4 | 23 | 53 | ||||||||||||
Total Oil Sands Mining and Upgrading (2)
|
382 | 9 | 55 | 107 | ||||||||||||
Midstream
|
5 | - | - | 1 | ||||||||||||
Abandonments (3)
|
9 | 10 | 12 | 17 | ||||||||||||
Head office
|
4 | 3 | 2 | 4 | ||||||||||||
Total net capital expenditures
|
$ | 1,256 | 473 | 574 | 694 |
51
|
Canadian Natural Resources Limited
|
2008 Three Months Ended | ||||||||||||||||
($ millions)
|
Mar 31
|
Jun 30
|
Sep 30
|
Dec 31
|
||||||||||||
Net property acquisitions (dispositions)
|
$ | (8 | ) | $ | 263 | $ | 47 | $ | 34 | |||||||
Land acquisition and retention
|
12 | 24 | 32 | 18 | ||||||||||||
Seismic evaluation
|
27 | 18 | 40 | 22 | ||||||||||||
Well drilling, completion and equipping
|
452 | 286 | 421 | 505 | ||||||||||||
Production and related facilities
|
319 | 270 | 311 | 382 | ||||||||||||
Total net reserve replacement expenditures
|
802 | 861 | 851 | 961 | ||||||||||||
Oil Sands Mining and Upgrading
|
||||||||||||||||
Horizon Phase 1 construction costs
|
665 | 875 | 635 | 557 | ||||||||||||
Horizon Phase 1 commissioning and other costs
|
91 | 48 | 111 | 115 | ||||||||||||
Horizon Phase 2/3 costs
|
77 | 82 | 83 | 94 | ||||||||||||
Capitalized interest, stock-based compensation and other
|
109 | 247 | 46 | 78 | ||||||||||||
Sustaining Capital
|
- | - | - | - | ||||||||||||
Total Oil Sands Mining and Upgrading (2)
|
941 | 1,252 | 875 | 844 | ||||||||||||
Midstream
|
1 | 3 | 2 | 3 | ||||||||||||
Abandonments (3)
|
6 | 7 | 10 | 15 | ||||||||||||
Head office
|
3 | 4 | 6 | 4 | ||||||||||||
Total net capital expenditures
|
$ | 1,753 | $ | 2,127 | $ | 1,744 | $ | 1,827 |
(1)
|
Net capital expenditures exclude adjustments related to differences between carrying value and tax value, and other fair value adjustments.
|
(2)
|
Net capital expenditures for the Oil Sands Mining and Upgrading assets also include the impact of intersegment eliminations.
|
(3)
|
Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table.
|
F.
|
DEVELOPED AND UNDEVELOPED ACREAGE
|
(thousands)
|
Developed Acreage
|
Undeveloped Acreage
|
Total Acreage
|
|||
Gross Acres
|
Net Acres
|
Gross Acres
|
Net Acres
|
Gross Acres
|
Net Acres
|
|
North America
|
||||||
Alberta
|
6,255
|
5,003
|
9,238
|
7,901
|
15,493
|
12,904
|
British Columbia
|
1,485
|
1,125
|
2,814
|
2,046
|
4,299
|
3,171
|
Saskatchewan
|
739
|
554
|
803
|
687
|
1,542
|
1,241
|
Manitoba
|
7
|
6
|
17
|
17
|
24
|
23
|
North Sea
|
||||||
United Kingdom
|
68
|
57
|
184
|
150
|
252
|
207
|
Offshore West Africa
|
||||||
Côte d’Ivoire
|
10
|
6
|
92
|
54
|
102
|
60
|
Gabon
|
2
|
2
|
150
|
138
|
152
|
140
|
Total
|
8,566
|
6,753
|
13,298
|
10,993
|
21,864
|
17,746
|
Canadian Natural Resources Limited
|
52
|
Year Ended Dec 31 | ||||||
($ millions, except per common share information)
|
2009 | 2008 | ||||
Revenues, before royalties
|
$ | 11,078 | $ | 16,173 | ||
Net earnings
|
$ | 1,580 | $ | 4,985 | ||
Per common share - basic and diluted
|
$ | 2.92 | $ | 9.22 | ||
Adjusted net earnings from operations (1)
|
$ | 2,689 | $ | 3,492 | ||
Per common share - basic and diluted
|
$ | 4.96 | $ | 6.46 | ||
Cash flow from operations (1)
|
$ | 6,090 | $ | 6,969 | ||
Per common share - basic and diluted
|
$ | 11.24 | $ | 12.89 | ||
Total assets
|
$ | 41,024 | $ | 42,650 | ||
Total long-term liabilities
|
$ | 19,193 | $ | 20,856 |
(1)
|
These non-GAAP measures are reconciled to net earnings as determined in accordance with Canadian GAAP in the “Financial Highlights” section of the Company’s MD&A which is incorporated by reference into this document.
|
2009 Three Months Ended
|
||||||||||||||||
($ millions, except per common share information)
|
Mar 31
|
Jun 30
|
Sep 30
|
Dec 31
|
||||||||||||
Revenues, before royalties
|
$ | 2,186 | 2,750 | 2,823 | 3,319 | |||||||||||
Net earnings (loss)
|
$ | 305 | 162 | 658 | 455 | |||||||||||
Per common share - basic and diluted
|
$ | 0.56 | 0.30 | 1.21 | 0.85 |
2008 Three Months Ended
|
||||||||||||||||
($ millions, except per common share information)
|
Mar 31
|
Jun 30
|
Sep 30
|
Dec 31
|
||||||||||||
Revenues, before royalties
|
$ | 3,967 | $ | 5,112 | $ | 4,583 | $ | 2,511 | ||||||||
Net earnings
|
$ | 727 | $ | (347 | ) | $ | 2,835 | $ | 1,770 | |||||||
Per common share - basic and diluted
|
$ | 1.35 | $ | (0.65 | ) | $ | 5.25 | $ | 3.27 |
53
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
54
|
2009 Monthly Historical Trading on TSX
|
||||||||||||||||
Month
|
High
|
Low
|
Close
|
Volume Traded
|
||||||||||||
January
|
$ | 57.20 | 41.06 | 43.89 | 51,057,171 | |||||||||||
February
|
$ | 48.44 | 36.50 | 40.90 | 50,126,029 | |||||||||||
March
|
$ | 53.50 | 35.85 | 48.91 | 72,570,396 | |||||||||||
April
|
$ | 61.15 | 47.70 | 55.01 | 46,587,159 | |||||||||||
May
|
$ | 65.69 | 55.27 | 64.71 | 45,089,003 | |||||||||||
June
|
$ | 68.69 | 54.08 | 61.19 | 43,417,767 | |||||||||||
July
|
$ | 66.19 | 52.71 | 64.76 | 37,118,226 | |||||||||||
August
|
$ | 68.54 | 61.55 | 62.71 | 29,996,464 | |||||||||||
September
|
$ | 76.91 | 60.65 | 72.30 | 44,597,734 | |||||||||||
October
|
$ | 79.00 | 67.38 | 70.22 | 33,029,358 | |||||||||||
November
|
$ | 73.15 | 66.51 | 70.47 | 35,763,690 | |||||||||||
December
|
$ | 76.46 | 65.97 | 76.00 | 30,807,147 |
55
|
Canadian Natural Resources Limited
|
2009 |
2008
|
2007
|
|||||||||
Cash dividends declared per common share
|
$ | 0.42 | $ | 0.40 | $ | 0.34 |
Canadian Natural Resources Limited
|
56
|
Name
|
Position Presently Held
|
Principal Occupation During Past 5 Years
|
Catherine M. Best, FCA, ICD.D
Calgary, Alberta
Canada
|
Director (2)(4)(5)
(age 56)
|
Corporate Director. Until May 2009, Interim Chief Financial Officer of Alberta Health Services which was formed in 2008 when the Alberta government consolidated all of the health regions of the province under one board. Executive Vice-President, Risk Management and Chief Financial Officer of the Calgary Health Region (fully integrated publicly funded health care system) from 2002 to 2008; has served continuously as a director of the Company since November 2003. Currently serving on the board of directors of Enbridge Income Fund and Superior Plus Income Fund. She is also a member of the Board of the Alberta Children’s Hospital Foundation and serves as a volunteer member of the Audit Committee of the Calgary Exhibition and Stampede.
|
N. Murray Edwards
Calgary/Banff, Alberta
Canada
|
Vice-Chairman and
Director (3)
(age 50)
|
President, Edco Financial Holdings Ltd. (private management and consulting company). Has served continuously as a director of the Company since September 1988. Currently is Chairman and serving on the board of directors of Ensign Energy Services Inc. and Magellan Aerospace Corporation.
|
Honourable Gary A. Filmon,
P.C., O.C., O.M.
Winnipeg, Manitoba
Canada
|
Director (1)(2)
(age 67)
|
Consultant, The Exchange Group (business consulting firm). Has served continuously as a director of the Company since February 2006. Currently serving on the board of directors of MTS Allstream Inc., Arctic Glacier Income Trust, Exchange Income Corporation, Wellington West Capital Inc. and FWS Construction Inc. and serves as Chair of Canada’s Security and Intelligence Review Committee.
|
Ambassador Gordon D. Giffin
Atlanta, Georgia
USA
|
Director (1)(2)(3)
(age 60)
|
Senior Partner, McKenna Long & Aldridge LLP (law firm) since May 2001. Has served continuously as a director of the Company since May 2002. Currently serving on the board of directors of Canadian National Railway Company, Canadian Imperial Bank of Commerce, Just Energy Corp., and Transalta Corporation.
|
John G. Langille
Calgary, Alberta
Canada
|
Vice-Chairman and Director
(age 64)
|
Officer of the Company. Has served continuously as a director of the Company since June 1982.
|
Steve W. Laut
Calgary, Alberta
Canada
|
President and Director
(age 52)
|
Officer of the Company. Has served continuously as a director of the Company since August 2006.
|
Keith A.J. MacPhail
Calgary, Alberta
Canada
|
Director (3)(5)
(age 53)
|
Chairman and Chief Executive Officer, Bonavista Energy Trust (oil and gas energy trust) since November 1997 and Chairman, NuVista Energy Ltd. (an oil and gas exploration, development and production company) since July 2003. Has served continuously as a director of the Company since October 1993. Currently serving on the board of directors of Bonavista Energy Trust and NuVista Energy Ltd.
|
57
|
Canadian Natural Resources Limited
|
Allan P. Markin, O.C.
Calgary, Alberta
Canada
|
Chairman and Director (5)
(age 64)
|
Chairman of the Company. Has served continuously as a director of the Company since January 1989.
|
Honourable Frank J. McKenna,
P.C., O.C., O.N.B., Q.C. Cap Pelé, New Brunswick
Canada
|
Director (1)(4)
(age 62)
|
Deputy Chair, TD Bank Financial Group (financial services). Counsel to Atlantic Canada law firm McInnes Cooper from 1998 to 2005, and most recently Canadian Ambassador to the United States from 2005 to 2006. He has served continuously as a director of the Company since August 2006. Currently serving on the board of directors of Brookfield Asset Management Inc.
|
James S. Palmer, C.M.,
A.O.E., Q.C.
Calgary, Alberta
Canada
|
Director (3)(4)(5)
(age 81)
|
Chairman and a Partner of Burnet, Duckworth & Palmer LLP (law firm). Has served continuously as a director of the Company since May 1997. Currently serving on the board of directors of Magellan Aerospace Corporation and is Director Emeritus of Frontier Oil Corporation.
|
Dr. Eldon R. Smith, O.C., M.D.
Calgary, Alberta
Canada
|
Director (4)(5)
(age 70)
|
President of Eldon R. Smith & Associates Ltd., (a private health care consulting company), and Emeritus Professor of Medicine and Former Dean, Faculty of Medicine, University of Calgary. Has served continuously as a director of the Company since May 1997. Currently serving on the board of directors of Intellipharmaceutics International Inc. and Aston Hill Financial.
|
David A. Tuer
Calgary, Alberta
Canada
|
Director (1)(2)(3)
(age 60)
|
Vice-Chairman and Chief Executive Officer of Marble Point Energy Ltd. (private oil and gas exploration company); Chairman, Calgary Health Region from 2001 to 2008 and Executive Vice-Chairman BA Energy Inc. from April 2005 to February 2008 when it was acquired by its parent company Value Creations Inc. through a Plan of Arrangement and which until recently was engaged in the development, building and operations of a merchant heavy oil upgrader in Northern Alberta for the purpose of upgrading bitumen and heavy oil feedstock into high-quality crude oils. Prior thereto President, CEO and a director of Hawker Resources Inc. from January 2003 to March 2005. Has served continuously as a director of the Company since May 2002. Currently serving on the board of directors of Daylight Resources Trust, Xtreme Coil Drilling Corp., Canadian Phoenix Resources and Altalink Management LLP., a private limited partnership.
|
Jeffrey J. Bergeson
Calgary, Alberta
Canada
|
Vice-President, Exploitation West
(age 53)
|
Officer of the Company since May 2007; prior thereto Exploitation Manager of the Company.
|
Corey B. Bieber
Calgary, Alberta
Canada
|
Vice-President, Finance and
Investor Relations (age 46)
|
Officer of the Company since April 2005; prior thereto Director, Investor Relations of the Company from July 2002 to April 2005 and most recently Vice-President, Investor Relations April 2005 to February 2007.
|
Mary-Jo E. Case
Calgary, Alberta
Canada
|
Vice-President,
Land
(age 51)
|
Officer of the Company.
|
William R. Clapperton
Calgary, Alberta
Canada
|
Vice-President,
Regulatory, Stakeholder
and Environmental Affairs (age 47)
|
Officer of the Company.
|
Canadian Natural Resources Limited
|
58
|
James F. Corson
Calgary, Alberta
Canada
|
Vice-President,
Human Resources, Horizon
(age 59)
|
Officer of the Company since January 2007; prior thereto Vice-President, Human Resources of Qatar Petroleum Corp. from March 1997 to July 2005 and most recently Director Human Resources and Stakeholder Relations of the Company from July 2005 to 2007.
|
Réal M. Cusson
Calgary, Alberta
Canada
|
Senior Vice-President, Marketing
(age 59)
|
Officer of the Company.
|
Randall S. Davis
Calgary, Alberta
Canada
|
Vice-President,
Finance & Accounting
(age 43)
|
Officer of the Company.
|
Réal J. H. Doucet
Calgary, Alberta
Canada
|
Senior Vice-President,
Horizon Projects
(age 57)
|
Officer of the Company.
|
Allan E. Frankiw
Calgary, Alberta
Canada
|
Vice-President,
Production, Central
(age 53)
|
Officer of the Company since March 2007; prior thereto Manager Midstream for Anadarko Canada Corporation from November 1998 to March 2005, Manager Facilities & Construction for Anadarko Canada Corporation from April 2005 to November 2006, and most recently Production Manager, Edson of the Company from November 2006 to March 2007.
|
Tim Hamilton
Calgary, Alberta
Canada
|
Vice-President,
Developments
(age 54)
|
Officer of the Company since February 2010; prior thereto Manager Production, Southern Alberta from 2000 to 2006, Manager Production, Southern Alberta, S.E. Saskatchewan and Manitoba 2006 to 2007, Manager Production, British Columbia South 2007 to September 2009 and most recently Manager Production, British Columbia from September 2009 to February 2010.
|
Peter J. Janson
Calgary, Alberta
Canada
|
Senior Vice-President,
Horizon Operations
(age 52)
|
Officer of the Company.
|
Terry Jocksch
Calgary, Alberta
Canada
|
Senior Vice-President,
Thermal and International
(age 42)
|
Officer of the Company since June 2009; prior thereto Exploitation Manager of the Company to April 2004, Vice-President Exploitation West April 2004 to May 2007, and most recently Managing Director, International May 2007 to June 2009.
|
Philip A. Keele
Calgary, Alberta
Canada
|
Vice-President,
Mining,
Horizon Oil Sands Project
(age 50)
|
Officer of the Company.
|
Allen M. Knight
Calgary, Alberta
Canada
|
Senior Vice-President,
International & Corporate Development (age 60)
|
Officer of the Company.
|
Cameron S. Kramer
Calgary, Alberta
Canada
|
Senior Vice-President,
North America Operations
(age 42)
|
Officer of the Company.
|
Ronald K. Laing
Calgary, Alberta
Canada
|
Vice-President, Commercial Operations
(age 40)
|
Officer of the Company since March 2009; prior thereto Manager, Commercial Operations of the Company from April 2004 to March 2009.
|
59
|
Canadian Natural Resources Limited
|
Reno G. Laseur
Fort McMurray, Alberta
Canada
|
Vice-President,
Upgrading
(age 54)
|
Officer of the Company since August 2008; prior thereto Operations Manager, Upgrading of the Company November 2002 to October 2007, and most recently Operations Director, Upgrading of the Company from October 2007 to August 2008.
|
Bruce E. McGrath
Calgary, Alberta
Canada
|
Corporate Secretary
(age 60)
|
Officer of the Company.
|
Tim S. McKay
Calgary, Alberta
Canada
|
Chief Operating Officer
(age 48)
|
Officer of the Company.
|
Paul Mendes
Calgary, Alberta
Canada
|
Vice-President
Legal and General Counsel
(age 44)
|
Officer of the Company since February 2010; prior thereto Manager, Legal Services, Horizon January 2005 to January 2007 and most recently Director, Legal Services Horizon from January 2007 to February 2010.
|
Leon Miura
Calgary, Alberta
Canada
|
Vice-President,
Horizon Downstream Projects
(age 55)
|
Officer of the Company.
|
S. John Parr
Calgary, Alberta
Canada
|
Vice-President,
Production, East
(age 48)
|
Officer of the Company.
|
David A. Payne
Calgary, Alberta
Canada
|
Vice-President,
Exploitation, Central
(age 48)
|
Officer of the Company.
|
William R. Peterson
Calgary, Alberta
Canada
|
Vice-President,
Production, West
(age 43)
|
Officer of the Company.
|
Douglas A. Proll
Calgary, Alberta
Canada
|
Chief Financial Officer and Senior Vice-President, Finance
(age 59)
|
Officer of the Company.
|
Timothy G. Reed
Calgary, Alberta
Canada
|
Vice-President,
Human Resources
(age 53)
|
Officer of the Company since January 2007; prior thereto Manager, Human Resources of the Company 2000 to 2005 and most recently Director, Human Resources 2005 to January 2007.
|
Joy P. Romero
Calgary, Alberta
Canada
|
Vice President,
Bitumen Production
(age 53)
|
Officer of the Company since March 2008; prior thereto Director, Bitumen Production Process of the Company from September 2002 to March 2008.
|
Sheldon L. Schroeder
Fort McMurray, Alberta
Canada
|
Vice-President,
Horizon Upstream Projects
(age 42)
|
Officer of the Company.
|
Kendall W. Stagg
Calgary, Alberta
Canada
|
Vice-President,
Exploration, West
(age 48)
|
Officer of the Company.
|
Scott G. Stauth
Calgary, Alberta
Canada
|
Vice-President,
Field Operations
(age 52)
|
Officer of the Company since November 2006; prior thereto Manager, Eastern Field Operations of the Company from April 2003 to November 2006.
|
Lyle G. Stevens
Calgary, Alberta
Canada
|
Senior Vice-President, Exploitation
(age 55)
|
Officer of the Company.
|
Canadian Natural Resources Limited
|
60
|
Stephen C. Suche
Calgary, Alberta
Canada
|
Vice-President,
Information and
Corporate Services
(age 50)
|
Officer of the Company since July 2006; prior thereto Manager Information and Corporate Services of the Company from January 2000 to July 2006.
|
Domenic Torriero
Calgary, Alberta
Canada
|
Vice-President,
Exploration, Central
(age 45)
|
Officer of the Company since November 2006; prior thereto Exploration Manager of the Company from March 2004 to November 2006.
|
Grant M. Williams
Calgary, Alberta
Canada
|
Vice-President,
Exploration, East
(age 52)
|
Officer of the Company since March 2007; prior thereto Manager, Exploration Heavy Oil of the Company from October 2003 to April 2007.
|
Jeffrey W. Wilson
Calgary, Alberta
Canada
|
Senior Vice-President, Exploration
(age 57)
|
Officer of the Company.
|
Daryl G. Youck
Calgary, Alberta
Canada
|
Vice-President,
Exploitation, East
(age 41)
|
Officer of the Company since February 2008; prior thereto Manager, Exploitation of the Company from July 2002 to February 2008.
|
Lynn M. Zeidler
Calgary, Alberta
Canada
|
Vice-President,
Horizon Operations and Project Services
(age 53)
|
Officer of the Company.
|
(1)
|
Member of the Nominating and Corporate Governance Committee
|
(2)
|
Member of the Audit Committee
|
(3)
|
Member of the Reserves Committee
|
(4)
|
Member of the Compensation Committee
|
(5)
|
Member of the Health, Safety, and Environmental Committee
|
61
|
Canadian Natural Resources Limited
|
Auditor service
|
2009
|
2008
|
||||||
Audit fees
|
$ | 2,710,100 | $ | 2,685,800 | ||||
Audit related fees
|
154,300 | 156,300 | ||||||
Tax related fees
|
131,650 | 91,500 | ||||||
All other fees
|
9,500 | 9,500 | ||||||
$ | 3,005,550 | $ | 2,943,100 |
Canadian Natural Resources Limited
|
62
|
63
|
Canadian Natural Resources Limited
|
1.
|
We have reviewed and evaluated the Corporation’s reserves data as at December 31, 2009. The reserves data consist of the following:
|
||
(a)
|
(i)
|
both proved, and proved and probable crude oil, synthetic crude oil, NGLs and natural gas reserve quantities estimated as at December 31, 2009 using 12-month average prices and current costs;
|
|
(ii)
|
the related future net revenue; and
|
||
(iii)
|
the related standardized measure calculation for proved crude oil, synthetic crude oil, NGL and natural gas reserve quantities.
|
||
(b)
|
(i)
|
both proved, and proved and probable crude oil, synthetic crude oil, NGL and natural gas reserve quantities estimated as at December 31, 2009 using forecast prices and costs;
|
|
(ii)
|
the related future net revenue.
|
||
2.
|
The reserves data are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
|
||
We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) with the necessary modifications to reflect definitions and standards under the U.S. Financial Accounting Standards Board policies (the “FASB Standards”) and the legal requirements of the U.S. Securities and Exchange Commission (“SEC Requirements”).
|
|||
3.
|
Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions as outlined in the COGE Handbook, the FASB Standards and the SEC Requirements.
|
||
4.
|
The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us for the year ended December 31, 2009 and identifies the respective portions thereof that we have evaluated and reported on to the Corporation’s management and board of directors:
|
Canadian Natural Resources Limited
|
64
|
Net Present Value of Future Net Revenue
(Before Income Taxes, 10% Discount Rate) ($millions Cdn)
|
||||||||||||||||||
Independent Qualified Reserves Evaluator or Auditor
|
Description and Preparation Date of Evaluation Report
|
Location of Reserves
|
Audited
|
Evaluated
|
Reviewed
|
Total
|
||||||||||||
Sproule Associates Limited
|
Evaluation and review of the P&NG Reserves, February 8th, 2010
|
Canada and USA
|
$ | 0 | $ | 37,994 | $ | 3,041 | $ | 41,035 | ||||||||
Sproule Associates Limited
|
Evaluation and review of the P&NG Reserves, February 8th, 2010
|
United Kingdom and
Offshore West Africa |
$ | 0 | $ | 10,053 | $ | 3,682 | $ | 13,735 | ||||||||
GLJ Petroleum Consultants Limited
|
Evaluation of the oil sands mining reserves, March 2nd, 2010
|
Canada
|
$ | 0 | $ | 23,064 | $ | 0 | $ | 23,064 | ||||||||
Totals
|
$ | 0 | $ | 71,111 | $ | 6,723 | $ | 77,834 |
|
|
5.
|
In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook as modified by the FASB Standards and SEC requirements. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
|
6.
|
We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.
|
7.
|
Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.
|
Sproule Associates Limited, Calgary, Alberta, Canada, March 3, 2010
|
|
Original Signed By:
SIGNED “HARRY J. HELWERDA”
Harry J. Helwerda, P.Eng.,
Executive Vice-President
|
Original Signed By:
SIGNED “DOUG HO”
Doug Ho, P.Eng.
Vice-President, Unconventional
|
Original Signed By:
SIGNED: “R. KEITH MACLEOD”
R. Keith MacLeod, P.Eng.
President
|
|
GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, March 3, 2010
|
|
Original Signed By:
SIGNED: “JAMES H. WILLMON”
James H. Willmon, P.Eng.
Vice-President
|
65
|
Canadian Natural Resources Limited
|
(a)
|
(i)
|
both proved, and proved and probable crude oil, synthetic crude oil, NGLs and natural gas reserve quantities estimated as at December 31, 2009 using 12-month average prices and current costs;
|
(ii)
|
the related future net revenue; and
|
|
(iii)
|
the related standardized measure calculation for proved crude oil, synthetic crude oil, NGL and natural gas reserve quantities.
|
|
(b)
|
(i)
|
both proved, and proved and probable crude oil, synthetic crude oil, NGL and natural gas reserve quantities estimated as at December 31, 2009 using forecast prices and costs;
|
(ii)
|
the related future net revenue.
|
(a)
|
reviewed the Corporation’s procedures for providing information to the independent qualified reserves evaluator;
|
(b)
|
met with each of the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation and in the event of a proposal to change the independent qualified reserves evaluators, to inquire whether there had been disputes between the previous independent qualified reserves evaluators and management; and
|
(c)
|
reviewed the reserves data with management and the independent qualified reserves evaluators.
|
Canadian Natural Resources Limited
|
66
|
(a)
|
the content and filing with securities regulatory authorities of reserves data and other oil, gas and surface mineable oil sands information contained in the Company’s Annual Information Form to which this report is attached as Schedule “B”;
|
(b) |
the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluators on the reserves data; and
|
(c) |
the content and filing of this report.
|
67
|
Canadian Natural Resources Limited
|
|
1.
|
ensure that the Corporation’s management implemented an effective system of internal controls over financial reporting;
|
|
2.
|
monitor and oversee the integrity of the Corporation’s financial statements, financial reporting processes and systems of internal controls regarding financial, accounting and compliance with regulatory and statutory requirements as they relate to financial statements, taxation matters and disclosure of material facts;
|
|
3.
|
select and recommend for appointment by the shareholders, the Corporation’s independent auditors, pre-approve all audit and non-audit services to be provided to the Corporation by the Corporation’s independent auditors consistent with all applicable laws, and establish the fees and other compensation to be paid to the independent auditors;
|
|
4.
|
monitor the independence, qualifications and performance of the Corporation’s independent auditors and oversee the audit of the Corporation’s financial statements;
|
|
5.
|
monitor the performance of the internal audit function;
|
|
6.
|
establish procedures for the receipt, retention, response to and treatment of complaints, including confidential, anonymous submissions by the Corporation’s employees, regarding accounting, internal controls or auditing matters; and,
|
|
7.
|
provide an avenue of communication among the independent auditors, management, the internal auditing function and the Board.
|
|
1.
|
The Audit Committee shall consist of at least three (3) directors as determined by the Board, each of whom shall be independent, non-executive directors, free from any relationship that would interfere with the exercise of his or her independent judgment. Audit Committee members shall meet the independence and experience requirements of the regulatory bodies to which the Corporation is subject to. All members of the Audit Committee shall have a basic understanding of finance and accounting and be able to read and understand fundamental financial statements at the time of their appointment to the Audit Committee. At least one member of the Audit Committee shall have accounting or related financial management expertise and qualify as a “financial expert” or similar designation in accordance with the requirements of the regulatory bodies to which the Corporation may be subject to.
|
|
2.
|
The Board at its organizational meeting held in conjunction with each annual general meeting of the shareholders shall appoint the members of the Audit Committee for the ensuing year. The Board may at any time remove or replace any member of the Audit Committee and may fill any vacancy in the Audit Committee.
|
|
3.
|
The Board shall appoint a member of the Audit Committee as chair of the Audit Committee. If an Audit Committee Chair is not designated by the Board, or is not present at a meeting of the Audit Committee, the members of the Audit Committee may designate a chair by majority vote of the Audit Committee membership.
|
|
4.
|
The Secretary or the Assistant Secretary of the Corporation shall be secretary of the Audit Committee unless the Audit Committee appoints a secretary of the Audit Committee.
|
Canadian Natural Resources Limited
|
68
|
|
5.
|
The quorum for meetings shall be one half (or where one half of the members of the Audit Committee is not a whole number, the whole number which is closest to and less than one half) of the members of the Audit Committee subject to a minimum of two members of the Audit Committee present in person or by telephone or other telecommunications device that permits all persons participating in the meeting to speak and to hear each other.
|
|
6.
|
Meetings of the Audit Committee shall be conducted as follows:
|
|
(a)
|
the Audit Committee shall meet at least four (4) times annually at such times and at such locations as may be requested by the Chair of the Audit Committee;
|
|
(b)
|
the Audit Committee shall meet privately in executive sessions at each meeting with management, the manager of internal auditing, the independent auditors, and as a committee to discuss any matters that the Audit Committee or each of these groups believe should be discussed.
|
|
7.
|
The independent auditors and internal auditors shall have a direct line of communication to the Audit Committee through its chair and may bypass management if deemed necessary. Any employee may bring before the Audit Committee directly and may bypass management if deemed necessary any matter involving questionable, illegal or improper financial practices or transactions.
|
|
1.
|
The overall duties and responsibilities of the Audit Committee shall be as follows:
|
|
a.
|
to assist the Board in the discharge of its responsibilities relating to the Corporation’s accounting principles, reporting practices and internal controls and its approval of the Corporation’s annual and quarterly consolidated financial statements;
|
|
b.
|
to establish and maintain a direct line of communication with the Corporation’s internal auditors and independent auditors and assess their performance;
|
|
c.
|
to ensure that the management of the Corporation has implemented and is maintaining an effective system of internal controls over financial reporting;
|
|
d.
|
to report regularly to the Board on the fulfillment of its duties and responsibilities; and,
|
|
e.
|
to review annually the Audit Committee Charter and recommend any changes to the Nominating and Corporate Governance Committee for approval by the Board.
|
|
2.
|
The duties and responsibilities of the Audit Committee as they relate to the independent auditors shall be as follows:
|
|
a.
|
to select and recommend to the Board of Directors for appointment by the shareholders, the Corporation’s independent auditors, review the independence and monitor the performance of the independent auditors and approve any discharge of auditors when circumstances warrant;
|
|
b.
|
to approve the fees and other significant compensation to be paid to the independent auditors, scope and timing of the audit and other related services rendered by the independent auditors;
|
|
c.
|
to review and discuss with management and the independent auditors prior to the annual audit the independent auditor’s annual audit plan, including scope, staffing, locations and reliance upon management and internal audit department and oversee the audit of the Corporation’s financial statements;
|
|
d.
|
to pre-approve all proposed non-audit services to be provided by the independent auditors except those non-audit services prohibited by legislation;
|
|
e.
|
on an annual basis, obtain and review a report by the independent auditors describing (i) the independent auditor’s internal quality control procedures; (ii) any material issues raised by the most recent quality-control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities within the preceding five years respecting one or more independent audits carried out by the firm; and, (iii) any steps taken to address any such issues arising from the review, inquiry or investigation, and, receive a written statement from the independent auditors outlining all significant relationships they have with the Corporation that could impair the auditor’s independence. The Corporation’s independent auditors may not be engaged to perform prohibited activities under the Sarbanes-Oxley Act of 2002 or the rules of the Public Company Accounting Oversight Board or other regulatory bodies, which the Corporation is governed by;
|
69
|
Canadian Natural Resources Limited
|
|
f.
|
to review and discuss with the independent auditors, upon completion of their audit and prior to the filing or releasing annual financial statements:
|
|
(i)
|
contents of their report, including :
|
|
(a)
|
all critical accounting policies and practices used;
|
|
(b)
|
all alternative treatments of financial information within GAAP that have been discussed with management, ramifications of the use of such treatments and the treatment preferred by the independent auditor;
|
|
(c)
|
other material written communications between the independent auditor and management;
|
|
(ii)
|
scope and quality of the audit work performed;
|
|
(iii)
|
adequacy of the Corporation’s financial and auditing personnel;
|
|
(iv)
|
cooperation received from the Corporation’s personnel during the audit;
|
|
(v)
|
internal resources used;
|
|
(vi)
|
significant transactions outside of the normal business of the Corporation;
|
|
(vii)
|
significant proposed adjustments and recommendations for improving internal accounting controls, accounting principles or management systems;
|
|
(viii)
|
the non-audit services provided by the independent auditors; and,
|
|
(ix)
|
consider the independent auditor’s judgments about the quality and appropriateness of the Corporation’s accounting principles and critical accounting estimates as applied in its financial reporting.
|
|
g.
|
to review and approve a report to shareholders as required, to be included in the Corporation’s Information Circular and Proxy Statement, disclosing any non-audit services approved by the Audit Committee.
|
|
h.
|
to review and approve the Corporation’s hiring policies regarding partners, employees and former partners and employees of the present and former independent auditor of the Corporation.
|
|
3.
|
The duties and responsibilities of the Audit Committee as they relate to the internal auditors shall be as follows:
|
|
a.
|
to review the budget, internal audit function with respect to the organization structure, staffing, effectiveness and qualifications of the Corporation’s internal audit department;
|
|
b.
|
to review the internal audit plan; and
|
|
c.
|
to review significant internal audit findings and recommendations together with management’s response and follow-up thereto.
|
|
4.
|
The duties and responsibilities of the Audit Committee as they relate to the internal control procedures of the Corporation shall be as follows:
|
|
a.
|
to review the appropriateness and effectiveness of the Corporation’s policies and business practices which impact on the financial integrity of the Corporation, including those relating to internal auditing, insurance, accounting, information services and systems and financial controls, management reporting (including financial reporting) and risk management;
|
|
b.
|
to review any unresolved issues between management and the independent auditors that could affect the financial reporting or internal controls of the Corporation; and
|
|
c.
|
to periodically review the extent to which recommendations made by the internal audit staff or by the independent auditors have been implemented.
|
|
5.
|
Other duties and responsibilities of the Audit Committee shall be as follows:
|
|
a.
|
to review and discuss with management, the internal audit group and the independent auditors, the Corporation’s unaudited quarterly consolidated financial statements and related Management Discussion & Analysis including the impact of unusual items and changes in accounting principles and estimates, the earnings press releases before disclosure to the public and report to the Board with respect thereto;
|
|
b.
|
to review and discuss with management, the internal audit group and the independent auditors, the Corporation’s audited annual consolidated financial statements and related Management Discussion & Analysis including the impact of unusual items and changes in accounting principles and estimates, the earnings press releases before disclosure to the public and report to the Board with respect thereto;
|
Canadian Natural Resources Limited
|
70
|
|
c.
|
to ensure adequate procedures are in place for the review of the Corporation’s public disclosure of financial information extracted or derived from the Corporation’s financial statements, other than the quarterly and annual earnings press releases, and periodically assess the adequacy of those procedures;
|
|
d.
|
to review management’s report on the appropriateness of the policies and procedures used in the preparation of the Corporation’s consolidated financial statements and other required disclosure documents and consider recommendations for any material change to such policies;
|
|
e.
|
to review with management, the independent auditors and if necessary with legal counsel, any litigation, claim or other contingency, including tax assessments that could have a material affect upon the financial position or operating results of the Corporation and the manner in which such matters have been disclosed in the consolidated financial statements;
|
|
f.
|
to establish procedures for:
|
|
(i)
|
the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls, or auditing matters; and
|
|
(ii)
|
the confidential, anonymous submission by employees of the Corporation of concerns regarding questionable accounting or auditing matters.
|
|
g.
|
to co-ordinate meetings with the Reserves Committee of the Corporation, the Corporation’s senior engineering management, independent evaluating engineers and auditors as required and consider such further inquiries as are necessary to approve the consolidated financial statements;
|
|
h.
|
to develop a calendar of activities to be undertaken by the Audit Committee for each ensuing year and to submit the calendar in the appropriate format to the Board following each annual general meeting of shareholders;
|
|
i.
|
to perform any other activities consistent with this Charter, the Corporation’s By-laws and governing law, as the Audit Committee or the Board deems necessary or appropriate; and,
|
|
j.
|
to maintain minutes of meetings and to report on a regular basis to the Board on significant results of the foregoing activities.
|
71
|
Canadian Natural Resources Limited
|
·
|
the Company’s consolidated financial statements as at December 31, 2009; and
|
·
|
the effectiveness of the Company’s internal control over financial reporting as at December 31, 2009.
|
(signed) “Steve W. Laut”
|
(signed) “Douglas A. Proll”
|
(signed) “Randall S. Davis”
|
Steve W. Laut
President
|
Douglas A. Proll, CA
Chief Financial Officer &
Senior Vice-President, Finance
|
Randall S. Davis, CA
Vice-President, Finance &
Accounting
|
(signed) “Steve W. Laut”
|
(signed) “Douglas A. Proll”
|
|
Steve W. Laut
President
|
Douglas A. Proll, CA
Chief Financial Officer &
Senior Vice-President, Finance
|
As at December 31
(millions of Canadian dollars)
|
2009
|
2008
|
||||||
ASSETS
|
||||||||
Current assets
|
||||||||
Cash and cash equivalents
|
$ | 13 | $ | 27 | ||||
Accounts receivable
|
1,148 | 1,059 | ||||||
Inventory, prepaids and other
|
584 | 455 | ||||||
Future income tax (note 8)
|
146 | – | ||||||
Current portion of other long-term assets (note 3)
|
– | 1,851 | ||||||
1,891 | 3,392 | |||||||
Property, plant and equipment (note 4)
|
39,115 | 38,966 | ||||||
Other long-term assets (note 3)
|
18 | 292 | ||||||
$ | 41,024 | $ | 42,650 | |||||
LIABILITIES
|
||||||||
Current liabilities
|
||||||||
Accounts payable
|
$ | 240 | $ | 383 | ||||
Accrued liabilities
|
1,522 | 1,802 | ||||||
Future income tax (note 8)
|
– | 585 | ||||||
Current portion of long-term debt (note 5)
|
– | 420 | ||||||
Current portion of other long-term liabilities (note 6)
|
643 | 230 | ||||||
2,405 | 3,420 | |||||||
Long-term debt (note 5)
|
9,658 | 12,596 | ||||||
Other long-term liabilities (note 6)
|
1,848 | 1,124 | ||||||
Future income tax (note 8)
|
7,687 | 7,136 | ||||||
21,598 | 24,276 | |||||||
SHAREHOLDERS’ EQUITY
|
||||||||
Share capital (note 9)
|
2,834 | 2,768 | ||||||
Retained earnings
|
16,696 | 15,344 | ||||||
Accumulated other comprehensive (loss) income (note 10)
|
(104 | ) | 262 | |||||
19,426 | 18,374 | |||||||
$ | 41,024 | $ | 42,650 |
(signed) "Catherine M. Best" |
(signed) " N. Murray Edwards"
|
|
Catherine M. Best
Chair of the Audit Committee and Director
|
N. Murray Edwards
Vice-Chairman of the Board of Directors and Director
|
For the years ended December 31
(millions of Canadian dollars, except per common share amounts)
|
2009
|
2008
|
2007
|
|||||||||
Revenue
|
$ | 11,078 | $ | 16,173 | $ | 12,543 | ||||||
Less: royalties
|
(936 | ) | (2,017 | ) | (1,391 | ) | ||||||
Revenue, net of royalties
|
10,142 | 14,156 | 11,152 | |||||||||
Expenses
|
||||||||||||
Production
|
2,987 | 2,451 | 2,184 | |||||||||
Transportation and blending
|
1,218 | 1,936 | 1,570 | |||||||||
Depletion, depreciation and amortization
|
2,819 | 2,683 | 2,863 | |||||||||
Asset retirement obligation accretion (note 6)
|
90 | 71 | 70 | |||||||||
Administration
|
181 | 180 | 208 | |||||||||
Stock-based compensation expense (recovery) (note 6)
|
355 | (52 | ) | 193 | ||||||||
Interest, net
|
410 | 128 | 276 | |||||||||
Risk management activities (note 13)
|
738 | (1,230 | ) | 1,562 | ||||||||
Foreign exchange (gain) loss
|
(631 | ) | 718 | (471 | ) | |||||||
8,167 | 6,885 | 8,455 | ||||||||||
Earnings before taxes
|
1,975 | 7,271 | 2,697 | |||||||||
Taxes other than income tax (note 8)
|
106 | 178 | 165 | |||||||||
Current income tax expense (note 8)
|
388 | 501 | 380 | |||||||||
Future income tax (recovery) expense (note 8)
|
(99 | ) | 1,607 | (456 | ) | |||||||
Net earnings
|
$ | 1,580 | $ | 4,985 | $ | 2,608 | ||||||
Net earnings per common share (note 12)
|
||||||||||||
Basic and diluted
|
$ | 2.92 | $ | 9.22 | $ | 4.84 |
For the years ended December 31
(millions of Canadian dollars)
|
2009
|
2008
|
2007
|
|||||||||
Share capital (note 9)
|
||||||||||||
Balance – beginning of year
|
$ | 2,768 | $ | 2,674 | $ | 2,562 | ||||||
Issued upon exercise of stock options
|
24 | 18 | 21 | |||||||||
Previously recognized liability on stock options exercised for common shares
|
42 | 76 | 91 | |||||||||
Balance – end of year
|
2,834 | 2,768 | 2,674 | |||||||||
Retained earnings
|
||||||||||||
Balance – beginning of year, as originally reported
|
15,344 | 10,575 | 8,141 | |||||||||
Transition adjustment on adoption of financial instruments standards
|
– | – | 10 | |||||||||
Balance – beginning of year, as restated
|
15,344 | 10,575 | 8,151 | |||||||||
Net earnings
|
1,580 | 4,985 | 2,608 | |||||||||
Dividends on common shares (note 9)
|
(228 | ) | (216 | ) | (184 | ) | ||||||
Balance – end of year
|
16,696 | 15,344 | 10,575 | |||||||||
Accumulated other comprehensive (loss) income (note 10)
|
||||||||||||
Balance – beginning of year, as originally reported
|
262 | 72 | (13 | ) | ||||||||
Transition adjustment on adoption of financial instruments standards
|
– | – | 159 | |||||||||
Balance – beginning of year, as restated
|
262 | 72 | 146 | |||||||||
Other comprehensive (loss) income, net of taxes
|
(366 | ) | 190 | (74 | ) | |||||||
Balance – end of year
|
(104 | ) | 262 | 72 | ||||||||
Shareholders’ equity
|
$ | 19,426 | $ | 18,374 | $ | 13,321 |
For the years ended December 31
(millions of Canadian dollars)
|
2009
|
2008
|
2007
|
|||||||||
Net earnings
|
$ | 1,580 | $ | 4,985 | $ | 2,608 | ||||||
Net change in derivative financial instruments designated as cash flow hedges
|
||||||||||||
Unrealized (loss) income during the year, net of taxes of
$5 million (2008 – $1 million, 2007 – $6 million)
|
(33 | ) | 30 | 38 | ||||||||
Reclassification to net earnings, net of taxes of $1 million (2008 – $6 million, 2007 – $45 million)
|
(10 | ) | (12 | ) | (96 | ) | ||||||
(43 | ) | 18 | (58 | ) | ||||||||
Foreign currency translation adjustment
|
||||||||||||
Translation of net investment
|
(323 | ) | 172 | (16 | ) | |||||||
Other comprehensive (loss) income, net of taxes
|
(366 | ) | 190 | (74 | ) | |||||||
Comprehensive income
|
$ | 1,214 | $ | 5,175 | $ | 2,534 |
For the years ended December 31
(millions of Canadian dollars)
|
2009
|
2008
|
2007
|
|||||||||
Operating activities
|
||||||||||||
Net earnings
|
$ | 1,580 | $ | 4,985 | $ | 2,608 | ||||||
Non-cash items
|
||||||||||||
Depletion, depreciation and amortization
|
2,819 | 2,683 | 2,863 | |||||||||
Asset retirement obligation accretion
|
90 | 71 | 70 | |||||||||
Stock-based compensation expense (recovery)
|
355 | (52 | ) | 193 | ||||||||
Unrealized risk management loss (gain)
|
1,991 | (3,090 | ) | 1,400 | ||||||||
Unrealized foreign exchange (gain) loss
|
(661 | ) | 832 | (524 | ) | |||||||
Deferred petroleum revenue tax expense (recovery)
|
15 | (67 | ) | 44 | ||||||||
Future income tax (recovery) expense
|
(99 | ) | 1,607 | (456 | ) | |||||||
Other
|
5 | 25 | 38 | |||||||||
Abandonment expenditures
|
(48 | ) | (38 | ) | (71 | ) | ||||||
Net change in non-cash working capital (note 15)
|
(235 | ) | (189 | ) | (346 | ) | ||||||
5,812 | 6,767 | 5,819 | ||||||||||
Financing activities
|
||||||||||||
Repayment of bank credit facilities, net
|
(2,021 | ) | (623 | ) | (1,925 | ) | ||||||
Issue of medium-term notes
|
– | – | 273 | |||||||||
Repayment of senior unsecured notes
|
(34 | ) | (31 | ) | (33 | ) | ||||||
Issue of US dollar debt securities
|
– | 1,215 | 2,553 | |||||||||
Issue of common shares on exercise of stock options
|
24 | 18 | 21 | |||||||||
Dividends on common shares
|
(225 | ) | (208 | ) | (178 | ) | ||||||
Net change in non-cash working capital (note 15)
|
(12 | ) | 46 | 8 | ||||||||
(2,268 | ) | 417 | 719 | |||||||||
Investing activities
|
||||||||||||
Expenditures on property, plant and equipment
|
(2,985 | ) | (7,433 | ) | (6,464 | ) | ||||||
Net proceeds on sale of property, plant and equipment
|
36 | 20 | 110 | |||||||||
Net expenditures on property, plant and equipment
|
(2,949 | ) | (7,413 | ) | (6,354 | ) | ||||||
Net change in non-cash working capital (note 15)
|
(609 | ) | 235 | (186 | ) | |||||||
(3,558 | ) | (7,178 | ) | (6,540 | ) | |||||||
(Decrease) increase in cash and cash equivalents
|
(14 | ) | 6 | (2 | ) | |||||||
Cash and cash equivalents – beginning of year
|
27 | 21 | 23 | |||||||||
Cash and cash equivalents – end of year
|
$ | 13 | $ | 27 | $ | 21 |
●
|
Section 1582 – “Business Combinations”, 1601 – “Consolidated Financial Statements”, and 1602 – “Non-Controlling Interests” replace Section 1581 – “Business Combinations”, and 1600 – “Consolidated Financial Statements”. The new standards are the Canadian equivalent of IFRS 3 “Business Combinations” and IAS 27 “Consolidated and Separate Financial Statements”. Section 1582 is effective for business combinations for acquisition dates on or after January 1, 2011. Earlier adoption is permitted, provided all three new standards are adopted simultaneously. Section 1582 requires equity instruments issued as part of the purchase consideration to be measured at fair value at the acquisition date, rather than the date when the acquisition was agreed to and announced. In addition, most acquisition costs are expensed as incurred, instead of being included in the purchase consideration. The new standard also requires non-controlling interests to be measured at fair value instead of carrying amounts. Section 1602 provides guidance on the treatment of non-controlling interests after acquisition. Section 1601 carries forward existing guidance on the preparation of consolidated financial statements, other than non-controlling interests. There is no impact on the Company’s results of operations or financial position at this time.
|
●
|
Effective January 1, 2009 Section 3064 – “Goodwill and Intangible Assets” replaced Section 3062 – “Goodwill and Other Intangible Assets” and Section 3450 – “Research and Development Costs”. In addition, EIC-27 – “Revenue and Expenditures during the Pre-Operating Period” was withdrawn. The new standard addresses when an internally generated intangible asset meets the definition of an asset. The adoption of this standard, which was adopted retroactively, did not have an impact on the Company’s results of operations or financial position.
|
●
|
On January 20, 2009 the Emerging Issues Committee (“EIC”) issued a new abstract EIC–173 “Credit Risk and the Fair Value of Financial Assets and Financial Liabilities”. This abstract concludes that an entity’s own credit risk and the credit risk of the counterparty should be taken into account when determining the fair value of financial assets and financial liabilities, including derivative financial instruments. This abstract applies to all financial assets and liabilities measured at fair value in interim and annual financial statements for periods ending on or after January 20, 2009. The adoption of this abstract did not have a material impact on the Company’s results of operations or financial position.
|
●
|
Effective July 1, 2009 Section 3855 – “Financial Instruments – Recognition and Measurement” was amended to add guidance on the assessment of embedded derivatives upon reclassification of a financial asset from the held-for-trading category. This amendment did not have any impact on the Company’s results of operations or financial position.
|
·
|
Effective October 1, 2009 Section 3862 – “Financial Instruments – Disclosures” was amended to include additional disclosure requirements for fair value measurements of financial instruments and to enhance liquidity risk disclosure requirements. The amendment requires the classification and disclosure of fair value measurements using a three-level hierarchy that reflects the significance of the inputs used in making the fair value measurements. This amendment affected disclosure only and did not impact the Company’s accounting for financial instruments (note 13).
|
2009
|
2008
|
|||||||
Risk management (note 13)
|
$ | – | $ | 2,119 | ||||
Other
|
18 | 24 | ||||||
18 | 2,143 | |||||||
Less: current portion
|
– | 1,851 | ||||||
$ | 18 | $ | 292 |
Cost
|
2009
Accumulated depletion and depreciation
|
Net
|
Cost
|
2008
Accumulated depletion and depreciation
|
Net
|
|||||||||||||||||||
Conventional crude oil and natural gas
|
||||||||||||||||||||||||
North America
|
$ | 38,259 | $ | 16,425 | $ | 21,834 | $ | 36,532 | $ | 14,381 | $ | 22,151 | ||||||||||||
North Sea
|
3,879 | 2,067 | 1,812 | 4,167 | 2,119 | 2,048 | ||||||||||||||||||
Offshore West Africa
|
2,861 | 978 | 1,883 | 2,671 | 777 | 1,894 | ||||||||||||||||||
Other
|
42 | 14 | 28 | 40 | 14 | 26 | ||||||||||||||||||
Oil Sands Mining and Upgrading
|
13,481 | 186 | 13,295 | 12,573 | – | 12,573 | ||||||||||||||||||
Midstream
|
284 | 81 | 203 | 278 | 72 | 206 | ||||||||||||||||||
Head office
|
200 | 140 | 60 | 190 | 122 | 68 | ||||||||||||||||||
$ | 59,006 | $ | 19,891 | $ | 39,115 | $ | 56,451 | $ | 17,485 | $ | 38,966 |
2009
|
2008
|
|||||||
Conventional crude oil and natural gas
|
||||||||
North America
|
$ | 2,102 | $ | 2,271 | ||||
North Sea
|
4 | 12 | ||||||
Offshore West Africa
|
666 | 595 | ||||||
Other
|
28 | 26 | ||||||
Oil Sands Mining and Upgrading
|
752 | 12,573 | ||||||
$ | 3,552 | $ | 15,477 |
2010
|
2011
|
2012
|
2013
|
2014
|
Average
annual increase
thereafter
|
|||||||||||||||||||
Crude oil and NGLs
|
||||||||||||||||||||||||
North America
|
||||||||||||||||||||||||
WTI at Cushing (US$/bbl)
|
$ | 79.17 | $ | 84.46 | $ | 86.89 | $ | 90.20 | $ | 92.01 | 2 | % | ||||||||||||
Western Canada Select (C$/bbl)
|
$ | 74.14 | $ | 78.29 | $ | 76.86 | $ | 78.87 | $ | 79.49 | 2 | % | ||||||||||||
Edmonton Par (C$/bbl)
|
$ | 84.25 | $ | 89.99 | $ | 92.61 | $ | 96.19 | $ | 98.13 | 2 | % | ||||||||||||
North Sea and Offshore West Africa
|
||||||||||||||||||||||||
North Sea Brent (US$/bbl)
|
$ | 77.92 | $ | 83.19 | $ | 85.59 | $ | 88.88 | $ | 90.65 | 2 | % | ||||||||||||
Natural gas
|
||||||||||||||||||||||||
North America
|
||||||||||||||||||||||||
Henry Hub Louisiana (US$/mmbtu)
|
$ | 5.70 | $ | 6.48 | $ | 6.70 | $ | 7.43 | $ | 8.12 | 2 | % | ||||||||||||
AECO (C$/mmbtu)
|
$ | 5.36 | $ | 6.21 | $ | 6.44 | $ | 7.23 | $ | 7.98 | 2 | % | ||||||||||||
Huntingdon/Sumas (C$/mmbtu)
|
$ | 5.61 | $ | 6.46 | $ | 6.69 | $ | 7.48 | $ | 8.23 | 2 | % |
2009
|
2008
|
|||||||
Canadian dollar denominated debt
|
||||||||
Bank credit facilities
|
||||||||
Bankers’ acceptances
|
$ | 1,897 | $ | 4,073 | ||||
Medium-term notes
|
||||||||
5.50% unsecured debentures due December 17, 2010
|
400 | 400 | ||||||
4.50% unsecured debentures due January 23, 2013
|
400 | 400 | ||||||
4.95% unsecured debentures due June 1, 2015
|
400 | 400 | ||||||
3,097 | 5,273 | |||||||
US dollar denominated debt
|
||||||||
Senior unsecured notes
|
||||||||
Adjustable rate due May 27, 2009 (2009 – US$nil, 2008 – US$31 million)
|
– | 38 | ||||||
US dollar debt securities
|
||||||||
6.70% due July 15, 2011 (2009 and 2008 – US$400 million)
|
419 | 490 | ||||||
5.45% due October 1, 2012 (2009 and 2008 – US$350 million)
|
366 | 429 | ||||||
5.15% due February 1, 2013 (2009 and 2008 – US$400 million)
|
419 | 490 | ||||||
4.90% due December 1, 2014 (2009 and 2008 – US$350 million)
|
366 | 429 | ||||||
6.00% due August 15, 2016 (2009 and 2008 – US$250 million)
|
262 | 306 | ||||||
5.70% due May 15, 2017 (2009 and 2008 – US$1,100 million)
|
1,151 | 1,346 | ||||||
5.90% due February 1, 2018 (2009 and 2008 – US$400 million)
|
419 | 490 | ||||||
7.20% due January 15, 2032 (2009 and 2008 – US$400 million)
|
419 | 490 | ||||||
6.45% due June 30, 2033 (2009 and 2008 – US$350 million)
|
366 | 429 | ||||||
5.85% due February 1, 2035 (2009 and 2008 – US$350 million)
|
366 | 429 | ||||||
6.50% due February 15, 2037 (2009 and 2008 – US$450 million)
|
471 | 551 | ||||||
6.25% due March 15, 2038 (2009 and 2008 – US$1,100 million)
|
1,151 | 1,346 | ||||||
6.75% due February 1, 2039 (2009 and 2008 – US$400 million)
|
419 | 490 | ||||||
Less – original issue discount on senior unsecured notes and US dollar debt securities (1)
|
(22 | ) | (23 | ) | ||||
6,572 | 7,730 | |||||||
Fair value impact of interest rate swaps on US dollar debt securities (2)
|
38 | 68 | ||||||
6,610 | 7,798 | |||||||
Long-term debt before transaction costs
|
9,707 | 13,071 | ||||||
Less: transaction costs (1) (3)
|
(49 | ) | (55 | ) | ||||
9,658 | 13,016 | |||||||
Less: current portion
|
– | 420 | ||||||
$ | 9,658 | $ | 12,596 |
(1) | The Company has included unamortized original issue discounts and directly attributable transaction costs in the carrying value of the outstanding debt. |
(2) |
The carrying value of US$350 million of 5.45% notes due October 2012 and US$350 million of 4.90% notes due December 2014 have been adjusted by $38 million (2008 – $68 million) to reflect the fair value impact of hedge accounting.
|
(3) | Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other professional fees. |
·
|
a $200 million demand credit facility;
|
·
|
a revolving syndicated credit facility of $2,230 million maturing June 2012;
|
·
|
a revolving syndicated credit facility of $1,500 million maturing June 2012; and
|
·
|
a £15 million demand credit facility related to the Company’s North Sea operations.
|
Year
|
Repayment
|
|||
2010
|
$ | 400 | ||
2011
|
$ | 419 | ||
2012
|
$ | 366 | ||
2013
|
$ | 819 | ||
2014
|
$ | 366 | ||
Thereafter
|
$ | 5,424 |
2009
|
2008
|
|||||||
Asset retirement obligations
|
$ | 1,610 | $ | 1,064 | ||||
Stock-based compensation
|
392 | 171 | ||||||
Risk management (note 13)
|
309 | - | ||||||
Other
|
180 | 119 | ||||||
2,491 | 1,354 | |||||||
Less: current portion
|
643 | 230 | ||||||
$ | 1,848 | $ | 1,124 |
2009
|
2008
|
2007
|
||||||||||
Balance – beginning of year
|
$ | 1,064 | $ | 1,074 | $ | 1,166 | ||||||
Liabilities incurred (1)
|
299 | 18 | 21 | |||||||||
Liabilities acquired
|
– | 3 | – | |||||||||
Liabilities disposed
|
– | – | (65 | ) | ||||||||
Liabilities settled
|
(48 | ) | (38 | ) | (71 | ) | ||||||
Asset retirement obligation accretion
|
90 | 71 | 70 | |||||||||
Revision of estimates
|
276 | (156 | ) | 35 | ||||||||
Foreign exchange
|
(71 | ) | 92 | (82 | ) | |||||||
Balance – end of year
|
$ | 1,610 | $ | 1,064 | $ | 1,074 |
(1)
|
During 2009, the Company recognized additional asset retirement obligations related to Horizon and Gabon, Offshore West Africa.
|
2009
|
2008
|
2007
|
||||||||||
Balance – beginning of year
|
$ | 171 | $ | 529 | $ | 744 | ||||||
Stock-based compensation expense (recovery)
|
355 | (52 | ) | 193 | ||||||||
Cash payment for options surrendered
|
(94 | ) | (207 | ) | (375 | ) | ||||||
Transferred to common shares
|
(42 | ) | (76 | ) | (91 | ) | ||||||
Capitalized (recovery) to Oil Sands Mining and Upgrading
|
2 | (23 | ) | 58 | ||||||||
Balance – end of year
|
392 | 171 | 529 | |||||||||
Less: current portion
|
365 | 159 | 390 | |||||||||
$ | 27 | $ | 12 | $ | 139 |
2009
|
2008
|
2007
|
||||||||||
Current PRT expense
|
$ | 70 | $ | 210 | $ | 97 | ||||||
Deferred PRT expense (recovery)
|
15 | (67 | ) | 44 | ||||||||
Provincial capital taxes and surcharges
|
21 | 35 | 24 | |||||||||
$ | 106 | $ | 178 | $ | 165 |
2009
|
2008
|
2007
|
||||||||||
Current income tax – North America
|
$ | 28 | $ | 33 | $ | 96 | ||||||
Current income tax – North Sea
|
278 | 340 | 210 | |||||||||
Current income tax – Offshore West Africa
|
82 | 128 | 74 | |||||||||
Current income tax expense
|
388 | 501 | 380 | |||||||||
Future income tax (recovery) expense
|
(99 | ) | 1,607 | (456 | ) | |||||||
Income tax expense (recovery)
|
$ | 289 | $ | 2,108 | $ | (76 | ) |
2009
|
2008
|
2007
|
||||||||||
Canadian statutory income tax rate
|
29.1 | % | 29.8 | % | 32.5 | % | ||||||
Income tax provision at statutory rate
|
$ | 576 | $ | 2,166 | $ | 877 | ||||||
Effect on income taxes of:
|
||||||||||||
Deductible UK petroleum revenue tax
|
(43 | ) | (72 | ) | (71 | ) | ||||||
Foreign and domestic tax rate differentials
|
(127 | ) | (5 | ) | (25 | ) | ||||||
North America income tax rate and other legislative changes
|
(19 | ) | (19 | ) | (864 | ) | ||||||
Côte d’Ivoire income tax rate changes
|
– | (22 | ) | – | ||||||||
Non-taxable portion of foreign exchange (gain) loss
|
(92 | ) | 127 | (96 | ) | |||||||
Stock options exercised in shares
|
27 | 6 | 63 | |||||||||
Other
|
(33 | ) | (73 | ) | 40 | |||||||
Income tax expense (recovery)
|
$ | 289 | $ | 2,108 | $ | (76 | ) |
2009
|
2008
|
|||||||
Future income tax liabilities
|
||||||||
Property, plant and equipment
|
$ | 6,992 | $ | 6,303 | ||||
Timing of partnership items
|
1,127 | 1,276 | ||||||
Unrealized foreign exchange gain on long-term debt
|
152 | 13 | ||||||
Unrealized risk management activities
|
– | 651 | ||||||
Other
|
31 | – | ||||||
Future income tax assets
|
||||||||
Asset retirement obligations
|
(499 | ) | (372 | ) | ||||
Loss carryforwards for income tax
|
(84 | ) | (62 | ) | ||||
Stock-based compensation
|
(83 | ) | (38 | ) | ||||
Unrealized risk management activities
|
(69 | ) | – | |||||
Other
|
– | (7 | ) | |||||
Deferred petroleum revenue tax
|
(26 | ) | (43 | ) | ||||
Net future income tax liability
|
7,541 | 7,721 | ||||||
Less: current portion of future income tax (asset) liability
|
(146 | ) | 585 | |||||
Future income tax liability
|
$ | 7,687 | $ | 7,136 |
2009
|
2008
|
|||||||||||||||
Common shares
|
Number of shares (thousands)
|
Amount
|
Number of shares (thousands)
|
Amount
|
||||||||||||
Balance – beginning of year
|
540,991 | $ | 2,768 | 539,729 | $ | 2,674 | ||||||||||
Issued upon exercise of stock options
|
1,336 | 24 | 1,262 | 18 | ||||||||||||
Previously recognized liability on stock options exercised for common shares
|
- | 42 | - | 76 | ||||||||||||
Balance – end of year
|
542,327 | $ | 2,834 | 540,991 | $ | 2,768 |
2009
|
2008
|
|||||||||||||||
Stock options (thousands)
|
Weighted average exercise price
|
Stock options (thousands)
|
Weighted average exercise price
|
|||||||||||||
Outstanding – beginning of year
|
30,962 | $ | 51.94 | 30,659 | $ | 47.23 | ||||||||||
Granted
|
6,736 | $ | 67.91 | 7,705 | $ | 53.38 | ||||||||||
Surrendered for cash settlement
|
(2,833 | ) | $ | 27.31 | (3,702 | ) | $ | 25.60 | ||||||||
Exercised for common shares
|
(1,336 | ) | $ | 17.99 | (1,262 | ) | $ | 14.61 | ||||||||
Forfeited
|
(1,423 | ) | $ | 59.55 | (2,438 | ) | $ | 56.56 | ||||||||
Outstanding – end of year
|
32,106 | $ | 58.54 | 30,962 | $ | 51.94 | ||||||||||
Exercisable – end of year
|
10,969 | $ | 53.90 | 8,809 | $ | 44.58 |
Stock options outstanding
|
Stock options exercisable
|
|||||||||||||||||||||
Range of exercise prices
|
Stock options outstanding (thousands)
|
Weighted average remaining term (years)
|
Weighted average exercise price
|
Stock options exercisable (thousands)
|
Weighted average exercise price
|
|||||||||||||||||
$ | 16.89 – $19.99 | 338 | 0.28 | $ | 17.36 | 331 | $ | 17.36 | ||||||||||||||
$ | 20.00 – $29.99 | 1,993 | 0.35 | $ | 25.61 | 1,342 | $ | 25.35 | ||||||||||||||
$ | 30.00 – $39.99 | 755 | 0.63 | $ | 33.28 | 528 | $ | 33.29 | ||||||||||||||
$ | 40.00 – $49.99 | 6,523 | 4.06 | $ | 46.38 | 1,252 | $ | 45.96 | ||||||||||||||
$ | 50.00 – $59.99 | 4,700 | 1.85 | $ | 58.11 | 2,609 | $ | 58.04 | ||||||||||||||
$ | 60.00 – $69.99 | 10,601 | 3.84 | $ | 65.58 | 2,503 | $ | 61.54 | ||||||||||||||
$ | 70.00 – $79.99 | 6,412 | 3.32 | $ | 70.82 | 2,363 | $ | 70.72 | ||||||||||||||
$ | 80.00 – $89.99 | - | - | $ | - | - | $ | - | ||||||||||||||
$ | 90.00 – $92.50 | 784 | 4.53 | $ | 92.50 | 41 | $ | 92.50 | ||||||||||||||
32,106 | 3.18 | $ | 58.54 | 10,969 | $ | 53.90 |
2009
|
2008
|
|||||||
Derivative financial instruments designated as cash flow hedges
|
$ | 76 | $ | 119 | ||||
Foreign currency translation adjustment
|
(180 | ) | 143 | |||||
$ | (104 | ) | $ | 262 |
2009
|
2008
|
||||||||
Long-term debt (1)
|
$ | 9,658 | $ | 13,016 | |||||
Total shareholders’ equity
|
$ | 19,426 | $ | 18,374 | |||||
Debt to book capitalization
|
33 | % | 41 | % |
(1)
|
Includes the current portion of long-term debt.
|
2009
|
2008
|
2007
|
||||||||||
Weighted average common shares outstanding – basic and diluted (thousands of shares)
|
541,925 | 540,647 | 539,336 | |||||||||
Net earnings – basic and diluted
|
$ | 1,580 | $ | 4,985 | $ | 2,608 | ||||||
Net earnings per common share – basic and diluted
|
$ | 2.92 | $ | 9.22 | $ | 4.84 |
|
2009
|
|||||||||||
Asset (liability)
|
Loans and receivables at amortized cost
|
Held for trading at
fair value
|
Other financial liabilities at amortized cost
|
|||||||||
Cash and cash equivalents
|
$ | – | $ | 13 | $ | – | ||||||
Accounts receivable
|
1,148 | – | – | |||||||||
Other long-term assets
|
– | – | – | |||||||||
Accounts payable
|
– | – | (240 | ) | ||||||||
Accrued liabilities
|
– | – | (1,522 | ) | ||||||||
Other long-term liabilities
|
– | (309 | ) | (167 | ) | |||||||
Long-term debt
|
– | – | (9,658 | ) | ||||||||
$ | 1,148 | $ | (296 | ) | $ | (11,587 | ) |
2008
|
||||||||||||
Asset (liability)
|
Loans and receivables at amortized cost
|
Held for
trading at
fair value
|
Other financial liabilities at amortized cost
|
|||||||||
Cash and cash equivalents
|
$ | – | $ | 27 | $ | – | ||||||
Accounts receivable
|
1,059 | – | – | |||||||||
Other long-term assets
|
– | 2,119 | – | |||||||||
Accounts payable
|
– | – | (383 | ) | ||||||||
Accrued liabilities
|
– | – | (1,802 | ) | ||||||||
Other long-term liabilities
|
– | – | (105 | ) | ||||||||
Long-term debt (1)
|
– | – | (13,016 | ) | ||||||||
$ | 1,059 | $ | 2,146 | $ | (15,306 | ) |
(1)
|
Includes the current portion of long-term debt.
|
2009
|
||||||||||||
Carrying value
|
Fair value
|
|||||||||||
Asset (liability) (1)
|
Level 1
|
Level 2
|
||||||||||
Other long-term assets
|
$ | – | $ | – | $ | – | ||||||
Other long-term liabilities
|
(309 | ) | – | (309 | ) | |||||||
Fixed-rate long-term debt(2) (3)
|
(7,761 | ) | (8,212 | ) | – | |||||||
$ | (8,070 | ) | $ | (8,212 | ) | $ | (309 | ) |
2008
|
||||||||||||
Carrying value
|
Fair value
|
|||||||||||
Asset (liability) (1)
|
Level 1
|
Level 2
|
||||||||||
Other long-term assets
|
$ | 2,119 | $ | – | $ | 2,119 | ||||||
Other long-term liabilities
|
– | – | – | |||||||||
Fixed-rate long-term debt(2) (3)
|
(8,943 | ) | (7,649 | ) | – | |||||||
$ | (6,824 | ) | $ | (7,649 | ) | $ | 2,119 |
(1)
|
Excludes financial assets and liabilities where book value approximates fair value due to the liquid nature of the asset or liability (cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities).
|
(2)
|
The carrying values of US$350 million of 5.45% notes due October 2012 and US$350 million of 4.90% notes due December 2014 have been adjusted by $38 million (2008 – $68 million) to reflect the fair value impact of hedge accounting.
|
(3)
|
The fair value of fixed-rate long-term debt has been determined based on quoted market prices.
|
2009
|
2008
|
|||||||
Asset (liability)
|
Risk management mark-to-market
|
Risk management mark-to-market
|
||||||
Balance – beginning of year
|
$ | 2,119 | $ | (1,474 | ) | |||
Net cost of outstanding put options
|
– | 297 | ||||||
Net change in fair value of outstanding derivative financial instruments attributable to:
|
||||||||
Risk management activities
|
(1,991 | ) | 3,090 | |||||
Interest expense
|
(25 | ) | 60 | |||||
Foreign exchange
|
(338 | ) | 449 | |||||
Other comprehensive income
|
(78 | ) | 18 | |||||
Settlement of interest rate swaps
|
4 | (20 | ) | |||||
(309 | ) | 2,420 | ||||||
Add: put premium financing obligations (1)
|
– | (301 | ) | |||||
Balance – end of year
|
(309 | ) | 2,119 | |||||
Less: current portion
|
(182 | ) | 1,851 | |||||
$ | (127 | ) | $ | 268 |
(1) The Company negotiated payment of put option premiums with various counterparties at the time of actual settlement of the respective options. These obligations were reflected in the net risk management asset (liability).
|
2009
|
2008
|
2007
|
||||||||||
Net realized risk management (gain) loss
|
$ | (1,253 | ) | $ | 1,860 | $ | 162 | |||||
Net unrealized risk management loss (gain)
|
1,991 | (3,090 | ) | 1,400 | ||||||||
$ | 738 | $ | (1,230 | ) | $ | 1,562 |
a)
|
Market risk
|
Remaining term
|
Volume
|
Weighted average price
|
Index
|
|
Crude oil
|
||||
Crude oil price collars
|
Jan 2010 – Mar 2010
|
6,000 bbl/d
|
US$60.00 – US$105.15
|
WTI
|
Jan 2010 – Jun 2010
|
100,000 bbl/d
|
US$60.00 – US$90.13
|
WTI
|
|
Jan 2010 – Sep 2010
|
50,000 bbl/d
|
US$65.00 – US$105.49
|
WTI
|
|
Jan 2010 – Dec 2010
|
50,000 bbl/d
|
US$60.00 – US$75.08
|
WTI
|
|
Jul 2010 – Dec 2010
|
50,000 bbl/d
|
US$65.00 – US$108.94
|
WTI
|
|
Remaining term
|
Volume
|
Weighted average price
|
Index
|
|
Natural gas
|
||||
Natural gas price collars(1)
|
Jan 2010 – Dec 2010
|
220,000 GJ/d
|
C$6.00 – C$8.00
|
AECO
|
(1)
|
Subsequent to December 31, 2009, the Company entered into 400,000 GJ/d of C$4.50 – C$6.30 natural gas AECO collars for the period April to September 2010.
|
Remaining term
|
Amount ($ millions)
|
Fixed rate
|
Floating rate
|
|
Interest rate
|
||||
Swaps – fixed to floating
|
Jan 2010 – Dec 2014
|
US$350
|
4.90%
|
LIBOR (1) + 0.38%
|
Swaps – floating to fixed
|
Jan 2010 – Feb 2011
|
C$300
|
1.0680%
|
3 month CDOR (2)
|
Jan 2010 – Feb 2012
|
C$200
|
1.4475%
|
3 month CDOR (2)
|
Remaining term
|
Amount
($ millions)
|
Exchange rate (US$/C$)
|
Interest rate (US$)
|
Interest rate (C$)
|
|
Cross currency
|
|||||
Swaps
|
Jan 2010 – Aug 2016
|
US$250
|
1.116
|
6.00%
|
5.40%
|
Jan 2010 – May 2017
|
US$1,100
|
1.170
|
5.70%
|
5.10%
|
|
Jan 2010 – Mar 2038
|
US$550
|
1.170
|
6.25%
|
5.76%
|
Impact on
net earnings
|
Impact on other comprehensive income
|
|||||||
Commodity price risk
|
||||||||
Increase WTI US$1.00/bbl
|
$ | (21 | ) | $ | – | |||
Decrease WTI US$1.00/bbl
|
$ | 20 | $ | – | ||||
Increase AECO C$0.10/mcf
|
$ | (4 | ) | $ | – | |||
Decrease AECO C$0.10/mcf
|
$ | 4 | $ | – | ||||
Interest rate risk
|
||||||||
Increase interest rate 1%
|
$ | (12 | ) | $ | 14 | |||
Decrease interest rate 1%
|
$ | 8 | $ | (18 | ) | |||
Foreign currency exchange rate risk
|
||||||||
Increase exchange rate by US$0.01
|
$ | (29 | ) | $ | – | |||
Decrease exchange rate by US$0.01
|
$ | 29 | $ | – |
b)
|
Credit Risk
|
Less than
1 year
|
1 to less than
2 years
|
2 to less than
5 years
|
Thereafter
|
|||||||||||||
Accounts payable
|
$ | 240 | $ | – | $ | – | $ | – | ||||||||
Accrued liabilities
|
$ | 1,522 | $ | – | $ | – | $ | – | ||||||||
Risk management
|
$ | 182 | $ | 15 | $ | 48 | $ | 64 | ||||||||
Other long-term liabilities
|
$ | 96 | $ | 18 | $ | 32 | $ | 21 | ||||||||
Long-term debt (1)
|
$ | 400 | $ | 419 | $ | 1,551 | $ | 5,424 |
(1)
|
The long-term debt represents principal repayments only and does not reflect fair value adjustments, original issue discounts or transaction costs. No debt repayments are reflected for $1,897 million of revolving bank credit facilities due to the extendable nature of the facilities.
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
|||||||||||||||||||
Product transportation and pipeline
|
$ | 207 | $ | 162 | $ | 136 | $ | 125 | $ | 126 | $ | 1,051 | ||||||||||||
Offshore equipment operating leases
|
$ | 155 | $ | 124 | $ | 103 | $ | 102 | $ | 101 | $ | 261 | ||||||||||||
Offshore drilling
|
$ | 49 | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||||
Asset retirement obligations (1)
|
$ | 16 | $ | 20 | $ | 21 | $ | 31 | $ | 39 | $ | 6,479 | ||||||||||||
Office leases
|
$ | 25 | $ | 19 | $ | 3 | $ | 2 | $ | 2 | $ | - | ||||||||||||
Other
|
$ | 271 | $ | 67 | $ | 23 | $ | 15 | $ | 12 | $ | 34 |
|
(1) Amounts represent management’s estimate of the future undiscounted payments to settle asset retirement obligations related to resource properties, facilities, and production platforms, based on current legislation and industry operating practices. Amounts disclosed for the period 2010 – 2014 represent the minimum required expenditures to meet these obligations. Actual expenditures in any particular year may exceed these minimum amounts.
|
2009
|
2008
|
2007
|
||||||||||
Changes in non-cash working capital
|
||||||||||||
Accounts receivable and other
|
$ | (276 | ) | $ | 111 | $ | 334 | |||||
Accounts payable
|
(151 | ) | (4 | ) | (456 | ) | ||||||
Accrued liabilities
|
(429 | ) | (15 | ) | (402 | ) | ||||||
Net changes in non-cash working capital
|
$ | (856 | ) | $ | 92 | $ | (524 | ) | ||||
Relating to:
|
||||||||||||
Operating activities
|
$ | (235 | ) | $ | (189 | ) | $ | (346 | ) | |||
Financing activities
|
(12 | ) | 46 | 8 | ||||||||
Investing activities
|
(609 | ) | 235 | (186 | ) | |||||||
$ | (856 | ) | $ | 92 | $ | (524 | ) | |||||
Other cash flow information:
|
2009 | 2008 | 2007 | |||||||||
Interest paid
|
$ | 516 | $ | 574 | $ | 556 | ||||||
Taxes other than income tax paid
|
$ | 52 | $ | 300 | $ | 116 | ||||||
Current income tax paid
|
$ | 216 | $ | 258 | $ | 302 |
Conventional Crude Oil and Natural Gas
|
North America
|
North Sea
|
Offshore West Africa
|
Total
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
|||||||||||||||||||||||||||||||||||||
Segmented revenue
|
$ | 7,973 | $ | 13,496 | $ | 10,149 | $ | 961 | $ | 1,769 | $ | 1,597 | $ | 913 | $ | 944 | $ | 776 | $ | 9,847 | $ | 16,209 | $ | 12,522 | ||||||||||||||||||||||||
Less: royalties
|
(825 | ) | (1,876 | ) | (1,318 | ) | (2 | ) | (4 | ) | (3 | ) | (81 | ) | (143 | ) | (70 | ) | (908 | ) | (2,023 | ) | (1,391 | ) | ||||||||||||||||||||||||
Revenue, net of royalties
|
7,148 | 11,620 | 8,831 | 959 | 1,765 | 1,594 | 832 | 801 | 706 | 8,939 | 14,186 | 11,131 | ||||||||||||||||||||||||||||||||||||
Segmented expenses
|
||||||||||||||||||||||||||||||||||||||||||||||||
Production
|
1,748 | 1,881 | 1,642 | 376 | 457 | 432 | 179 | 102 | 94 | 2,303 | 2,440 | 2,168 | ||||||||||||||||||||||||||||||||||||
Transportation and blending
|
1,213 | 1,975 | 1,595 | 8 | 10 | 16 | 1 | 1 | 1 | 1,222 | 1,986 | 1,612 | ||||||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization
|
2,060 | 2,236 | 2,350 | 261 | 317 | 340 | 335 | 132 | 165 | 2,656 | 2,685 | 2,855 | ||||||||||||||||||||||||||||||||||||
Asset retirement obligation accretion
|
41 | 42 | 38 | 24 | 27 | 30 | 4 | 2 | 2 | 69 | 71 | 70 | ||||||||||||||||||||||||||||||||||||
Realized risk management activities
|
(880 | ) | 1,861 | 129 | (373 | ) | (1 | ) | 33 | – | – | – | (1,253 | ) | 1,860 | 162 | ||||||||||||||||||||||||||||||||
Total segmented expenses
|
4,182 | 7,995 | 5,754 | 296 | 810 | 851 | 519 | 237 | 262 | 4,997 | 9,042 | 6,867 | ||||||||||||||||||||||||||||||||||||
Segmented earnings before the following
|
$ | 2,966 | $ | 3,625 | $ | 3,077 | $ | 663 | $ | 955 | $ | 743 | $ | 313 | $ | 564 | $ | 444 | $ | 3,942 | $ | 5,144 | $ | 4,264 |
Non–segmented expenses
|
Administration
|
Stock-based compensation expense (recovery)
|
Interest, net
|
Unrealized risk management activities
|
Foreign exchange (gain) loss
|
Total non-segmented expenses
|
Earnings before taxes
|
Taxes other than income tax
|
Current income tax expense
|
Future income tax (recovery) expense
|
Net earnings
|
Oil Sands Mining and Upgrading
|
Midstream
|
Inter–segment elimination and other
|
Total
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
|||||||||||||||||||||||||||||||||||||
Segmented revenue
|
$ | 1,253 | $ | – | $ | – | $ | 72 | $ | 77 | $ | 74 | $ | (94 | ) | $ | (113 | ) | $ | (53 | ) | $ | 11,078 | $ | 16,173 | $ | 12,543 | |||||||||||||||||||||
Less: royalties
|
(36 | ) | – | – | – | – | – | 8 | 6 | – | (936 | ) | (2,017 | ) | (1,391 | ) | ||||||||||||||||||||||||||||||||
Revenue, net of royalties
|
1,217 | – | – | 72 | 77 | 74 | (86 | ) | (107 | ) | (53 | ) | 10,142 | 14,156 | 11,152 | |||||||||||||||||||||||||||||||||
Segmented expenses
|
||||||||||||||||||||||||||||||||||||||||||||||||
Production
|
683 | – | – | 19 | 25 | 22 | (18 | ) | (14 | ) | (6 | ) | 2,987 | 2,451 | 2,184 | |||||||||||||||||||||||||||||||||
Transportation and blending
|
41 | – | – | – | – | – | (45 | ) | (50 | ) | (42 | ) | 1,218 | 1,936 | 1,570 | |||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization
|
187 | – | – | 9 | 8 | 8 | (33 | ) | (10 | ) | – | 2,819 | 2,683 | 2,863 | ||||||||||||||||||||||||||||||||||
Asset retirement obligation accretion
|
21 | – | – | – | – | – | – | – | – | 90 | 71 | 70 | ||||||||||||||||||||||||||||||||||||
Realized risk management activities
|
– | – | – | – | – | – | – | – | – | (1,253 | ) | 1,860 | 162 | |||||||||||||||||||||||||||||||||||
Total segmented expenses
|
932 | – | – | 28 | 33 | 30 | (96 | ) | (74 | ) | (48 | ) | 5,861 | 9,001 | 6,849 | |||||||||||||||||||||||||||||||||
Segmented earnings before the following
|
$ | 285 | $ | – | $ | – | $ | 44 | $ | 44 | $ | 44 | $ | 10 | $ | (33 | ) | $ | (5 | ) | $ | 4,281 | $ | 5,155 | $ | 4,303 | ||||||||||||||||||||||
Non–segmented expenses
|
||||||||||||||||||||||||||||||||||||||||||||||||
Administration
|
181 | 180 | 208 | |||||||||||||||||||||||||||||||||||||||||||||
Stock-based compensation expense (recovery)
|
355 | (52 | ) | 193 | ||||||||||||||||||||||||||||||||||||||||||||
Interest, net
|
410 | 128 | 276 | |||||||||||||||||||||||||||||||||||||||||||||
Unrealized risk management activities
|
1,991 | (3,090 | ) | 1,400 | ||||||||||||||||||||||||||||||||||||||||||||
Foreign exchange (gain) loss
|
(631 | ) | 718 | (471 | ) | |||||||||||||||||||||||||||||||||||||||||||
Total non–segmented expenses
|
2,306 | (2,116 | ) | 1,606 | ||||||||||||||||||||||||||||||||||||||||||||
Earnings before taxes
|
1,975 | 7,271 | 2,697 | |||||||||||||||||||||||||||||||||||||||||||||
Taxes other than income tax
|
106 | 178 | 165 | |||||||||||||||||||||||||||||||||||||||||||||
Current income tax expense
|
388 | 501 | 380 | |||||||||||||||||||||||||||||||||||||||||||||
Future income tax (recovery) expense
|
(99 | ) | 1,607 | (456 | ) | |||||||||||||||||||||||||||||||||||||||||||
Net earnings
|
$ | 1,580 | $ | 4,985 | $ | 2,608 |
2009 | 2008 | ||||||||||||||||||||||||
Net expenditures
|
Non cash and fair value changes(1)
|
Capitalized costs
|
Net expenditures
|
Non cash and fair value changes(1)
|
Capitalized costs
|
||||||||||||||||||||
Conventional crude oil and natural gas
|
|||||||||||||||||||||||||
North America
|
$ | 1,663 | $ | 65 | $ | 1,728 | $ | 2,344 | $ | (7 | ) | $ | 2,337 | ||||||||||||
North Sea
|
168 | 146 | 314 | 319 | (127 | ) | 192 | ||||||||||||||||||
Offshore West Africa
|
544 | 111 | 655 | 811 | 6 | 817 | |||||||||||||||||||
Other
|
2 | - | 2 | 1 | - | 1 | |||||||||||||||||||
2,377 | 322 | 2,699 | 3,475 | (128 | ) | 3,347 | |||||||||||||||||||
Oil Sands Mining and Upgrading(2)
|
553 | 355 | 908 | 3,912 | 10 | 3,922 | |||||||||||||||||||
Midstream
|
6 | - | 6 | 9 | - | 9 | |||||||||||||||||||
Head office
|
13 | - | 13 | 17 | - | 17 | |||||||||||||||||||
$ | 2,949 | $ | 677 | $ | 3,626 | $ | 7,413 | $ | (118 | ) | $ | 7,295 |
(1)
|
Asset retirement obligations, future income tax adjustments related to differences between carrying value and tax value, and other fair value adjustments.
|
(2)
|
Net expenditures for Oil Sands Mining and Upgrading also include capitalized interest, stock-based compensation, and the impact of intersegment eliminations.
|
2009
|
2008
|
|||||||
Conventional crude oil and natural gas
|
||||||||
North America
|
$ | 22,994 | $ | 24,875 | ||||
North Sea
|
1,968 | 2,638 | ||||||
Offshore West Africa
|
2,033 | 2,013 | ||||||
Other
|
42 | 64 | ||||||
Oil Sands Mining and Upgrading
|
13,621 | 12,677 | ||||||
Midstream
|
306 | 315 | ||||||
Head office
|
60 | 68 | ||||||
$ | 41,024 | $ | 42,650 |
(millions of Canadian dollars, except per common share amounts)
|
Notes
|
2009
|
2008
|
2007
|
||||||||||||
Net earnings – Canadian GAAP
|
$ | 1,580 | $ | 4,985 | $ | 2,608 | ||||||||||
Adjustments
|
||||||||||||||||
Depletion, net of taxes of $7 million
(2008 – $2,503 million, 2007 – $1 million)
|
(A,B,C,D | ) | (273 | ) | (6,169 | ) | (10 | ) | ||||||||
Stock-based compensation, net of taxes of $51
million (2008 – $32 million, 2007 – $3 million)
|
(B)
|
(154 | ) | (76 | ) | (22 | ) | |||||||||
Future income taxes
|
(F)
|
- | 234 | (234 | ) | |||||||||||
Net earnings (loss) – US GAAP
|
$ | 1,153 | $ | (1,026 | ) | $ | 2,342 | |||||||||
Net earnings (loss) – US GAAP per common share
|
||||||||||||||||
Basic
|
$ | 2.13 | $ | (1.90 | ) | $ | 4.34 | |||||||||
Diluted
|
(E)
|
$ | 2.13 | $ | (1.90 | ) | $ | 4.32 |
(millions of Canadian dollars)
|
Notes
|
2009
|
2008
|
2007
|
|||||||||
Comprehensive income – Canadian GAAP
|
$ | 1,214 | $ | 5,175 | $ | 2,534 | |||||||
US GAAP earnings adjustments
|
(427 | ) | (6,011 | ) | (266 | ) | |||||||
Comprehensive income (loss) – US GAAP
|
$ | 787 | $ | (836 | ) | $ | 2,268 |
2009
|
||||||||||||||||
(millions of Canadian dollars)
|
Notes
|
Canadian GAAP
|
Increase (Decrease)
|
US GAAP
|
||||||||||||
Current assets
|
$ | 1,891 | $ | 103 | $ | 1,994 | ||||||||||
Property, plant and equipment
|
(A,B,C,D | ) | 39,115 | (8,824 | ) | 30,291 | ||||||||||
Other long-term assets
|
(G)
|
18 | 49 | 67 | ||||||||||||
$ | 41,024 | $ | (8,672 | ) | $ | 32,352 | ||||||||||
Current liabilities
|
(B)
|
$ | 2,405 | $ | 387 | $ | 2,792 | |||||||||
Long-term debt
|
(G)
|
9,658 | 49 | 9,707 | ||||||||||||
Other long-term liabilities
|
(B)
|
1,848 | 35 | 1,883 | ||||||||||||
Future income tax
|
(A,B,C,D,F)
|
7,687 | (2,474 | ) | 5,213 | |||||||||||
Share capital
|
2,834 | - | 2,834 | |||||||||||||
Retained earnings
|
16,696 | (6,669 | ) | 10,027 | ||||||||||||
Accumulated other comprehensive income
|
(104 | ) | - | (104 | ) | |||||||||||
$ | 41,024 | $ | (8,672 | ) | $ | 32,352 |
2008
|
||||||||||||||||
(millions of Canadian dollars)
|
Notes
|
Canadian GAAP
|
Increase (Decrease)
|
US GAAP
|
||||||||||||
Current assets
|
$ | 3,392 | $ | - | $ | 3,392 | ||||||||||
Property, plant and equipment
|
(A,B,C,D | ) | 38,966 | (8,551 | ) | 30,415 | ||||||||||
Other long-term assets
|
(G)
|
292 | 55 | 347 | ||||||||||||
$ | 42,650 | $ | (8,496 | ) | $ | 34,154 | ||||||||||
Current liabilities
|
(B)
|
$ | 3,420 | $ | 150 | $ | 3,570 | |||||||||
Long-term debt
|
(G)
|
12,596 | 55 | 12,651 | ||||||||||||
Other long-term liabilities
|
(B)
|
1,124 | 15 | 1,139 | ||||||||||||
Future income tax
|
(A,B,C,D,F)
|
7,136 | (2,474 | ) | 4,662 | |||||||||||
Share capital
|
2,768 | - | 2,768 | |||||||||||||
Retained earnings
|
15,344 | (6,242 | ) | 9,102 | ||||||||||||
Accumulated other comprehensive income
|
262 | - | 262 | |||||||||||||
$ | 42,650 | $ | (8,496 | ) | $ | 34,154 |
(A)
|
Under Canadian full cost accounting guidance, costs capitalized in each country cost centre are limited to an amount equal to the future net revenues from proved and probable reserves using estimated future prices and costs discounted at the risk-free rate, plus the carrying amount of unproved properties and major development projects (the “ceiling test”) as described in note 1(I). Under the full cost method of accounting as set forth by the US Securities and Exchange Commission, the ceiling test differs from Canadian GAAP in that future net revenues from proved reserves are based on prices using the average first-day-of-the-month price during the previous twelve-month period and costs as at the balance sheet date, and are discounted at 10%. Capitalized costs and future net revenues are determined on a net of tax basis. In addition, beginning in 2009, the Company’s Oil Sands Mining and Upgrading activities are included in the Company’s US GAAP full cost oil and gas cost center for Canada for ceiling test purposes. These differences in applying the ceiling test to current and prior years resulted in the recognition of ceiling test impairments under US GAAP, which reduced property, plant and equipment by $8,951 million in 2009 (2008 – $8,697 million, 2007 – $36 million).
|
(B)
|
The Company accounts for its stock-based compensation liability under Canadian GAAP using the intrinsic value method, as described in note 1(P). Under US GAAP, effective January 1, 2006, the Company would have adopted Financial Accounting Standards Board Statement (FASB) Topic 718 “Compensation – Stock Compensation” (previously FAS 123(R)), which requires companies to account for all stock-based compensation liabilities using the fair value method, where fair value is measured using an option pricing model. The Company uses the Black Scholes option pricing model to determine the fair value of its stock-based compensation liability for US GAAP purposes. The previous US GAAP standard, FAS 123, required companies to account for cash settled stock-based compensation liabilities using the intrinsic value method. For the year ended December 31, 2009, US GAAP net earnings would have decreased by $154 million (2008 – $76 million, 2007 – $22 million), net of income taxes of $51 million (2008 – $32 million, 2007 – $3 million) related to the different valuation methodologies. The 2007 income tax effect includes the effect of enacted Canadian income tax rate changes on this item. In addition, US GAAP net earnings would have decreased by $1 million (2008 - $nil, 2007 - $nil), net of income taxes of $nil (2008 - $nil, 2007 - $nil) related to the impact of the change in capitalized stock-based compensation on depletion, depreciation and amortization expenses.
|
(C)
|
Under US GAAP, the foreign currency component of a business combination is not eligible for cash flow hedging. The impact of prior year adjustments would have decreased US GAAP net earnings by $7 million for the year ended December 31, 2009 (2008 – $8 million, 2007 – $6 million), net of income taxes of $3 million (2008 – $3 million, 2007 – $7 million), to reflect the impact of higher depletion charges. The 2007 income tax effect includes the effect of enacted Canadian income tax rate changes on this item.
|
(D)
|
Under Canadian GAAP, the Company began capitalizing interest on the Horizon Project when the Board of Directors approval was received in 2005. For US GAAP, capitalization of interest on projects constructed over time is mandatory and interest would have been capitalized to the costs of construction beginning in 2004. As a result of applying US GAAP, an additional $27 million would have been capitalized to property, plant and equipment in 2004. During 2009, Horizon Phase 1 assets were completed and available for their intended use. Accordingly, capitalization of all associated Phase 1 development costs, including capitalized interest ceased and depletion, depreciation and amortization of these assets commenced. For the year ended December 31, 2009, US GAAP net earnings would have decreased by $1 million (2008 – nil, 2007 – nil), net of income taxes of $nil (2008 – $nil, 2007 – $nil).
|
(E)
|
Under Canadian GAAP, the Company is not required to include potential common shares related to stock options in the calculation of diluted earnings per share as the Company has recorded the potential settlement of the stock options as a liability. Under US GAAP Topic 260 “Earnings Per Share” (previously FAS 128 “Earnings Per Share”), the Company would have included potential common shares related to stock options in the calculation of diluted earnings per share. For the year ended December 31, 2009, nil additional shares would have been included in the calculation of diluted earnings per share for US GAAP (2008 – nil additional shares, 2007 – 3,376,000 additional shares).
|
(F)
|
Under Canadian GAAP, the effects of income tax changes are recognized when the changes are considered substantively enacted. Under US GAAP, the income tax changes would not be recognized until the changes are enacted into law. For the years ended December 31, 2008 and 2007, the differences between substantively enacted and enacted tax legislation resulted in a difference in timing of the recognition of a $234 million future income tax recovery.
|
(G)
|
Under Canadian GAAP, debt issue costs on long-term debt must be included in the carrying value of the related debt. Under US GAAP, these items must be recorded as a deferred charge. Application of US GAAP would have resulted in the balance sheet reclassification of $49 million of debt issue costs from long-term debt to deferred charges in 2009 (2008 – $55 million, 2007 – $51 million).
|
(H)
|
In December 2007, the FASB issued Topic 805 “Business Combinations” (previously FAS 141(R) “Business Combinations”), which replaced FAS 141 effective for fiscal years beginning after December 15, 2008. Topic 805 retains the purchase method of accounting and requires assets acquired and liabilities assumed in a business combination to be measured at fair value at the date of acquisition. The standard also requires acquisition-related costs and restructuring costs to be recognized separately from the business combination. This standard is to be applied prospectively to all business combinations subsequent to the effective date and does not require restatement of previously completed business combinations. The adoption of this standard did not result in a US GAAP reconciling item.
|
AECO
|
Alberta natural gas reference location
|
API
|
Specific gravity measured in degrees on the American Petroleum Institute scale
|
ARO
|
Asset retirement obligations
|
bbl
|
barrels
|
bbl/d
|
barrels per day
|
bcf
|
billion cubic feet
|
boe
|
barrels of oil equivalent
|
boe/d
|
barrels of oil equivalent per day
|
Brent
|
Dated Brent
|
C$
|
Canadian dollars
|
CICA
|
Canadian Institute of Chartered Accountants
|
CO2
|
Carbon dioxide
|
CO2e
|
Carbon dioxide equivalents
|
Canadian GAAP
|
Generally accepted accounting principles in Canada
|
FPSO
|
Floating Production, Storage and Offtake Vessel
|
GHG
|
Greenhouse gas
|
GJ
|
gigajoules
|
GJ/d
|
gigajoules per day
|
Heavy Differential
|
Heavy crude oil differential from WTI
|
Horizon
|
Horizon Oil Sands
|
LIBOR
|
London Interbank Offered Rate
|
mcf
|
thousand cubic feet
|
mmbbl
|
million barrels
|
mmbtu
|
million British thermal units
|
mmcf/d
|
million cubic feet per day
|
mmcfe
|
millions of cubic feet equivalent
|
NGLs
|
Natural gas liquids
|
NYMEX
|
New York Mercantile Exchange
|
NYSE
|
New York Stock Exchange
|
PRT
|
Petroleum Revenue Tax
|
SCO
|
Synthetic light crude oil
|
SEC
|
United States Securities and Exchange Commission
|
TSX
|
Toronto Stock Exchange
|
UK
|
United Kingdom
|
US
|
United States
|
US GAAP
|
Generally accepted accounting principles in the United States
|
US$
|
United States dollars
|
WCS
|
Western Canadian Select
|
WTI
|
West Texas Intermediate
|
|
§
|
Balance among its products, namely natural gas, light/medium crude oil and NGLs, Pelican Lake crude oil (2), primary heavy crude oil and thermal heavy crude oil and SCO;
|
|
§
|
Balance among near-, mid- and long-term projects;
|
|
§
|
Balance among acquisitions, exploitation and exploration; and
|
|
§
|
Balance between sources and terms of debt financing and maintenance of a strong balance sheet.
|
|
§
|
Blending various crude oil streams with diluents to create more attractive feedstock;
|
|
§
|
Supporting and participating in pipeline expansions and/or new additions; and
|
|
§
|
Supporting and participating in projects that will increase the downstream conversion capacity for heavy crude oil.
|
|
§
|
Achieved net earnings of $1.6 billion, adjusted net earnings from operations of $2.7 billion, and cash flow from operations of $6.1 billion;
|
|
§
|
Completed the construction of Phase 1 of Horizon and commenced operations;
|
|
§
|
Achieved annual crude oil and natural gas production guidance;
|
|
§
|
Achieved first crude oil production from Platform C in the Olowi Field in Offshore Gabon;
|
|
§
|
Reduced long-term debt by $3.4 billion to $9.7 billion in 2009 from $13.0 billion in 2008; and
|
|
§
|
Increased annual dividend payout to $0.42 from $0.40, our 10th consecutive year of dividend increases.
|
Financial Highlights
|
||||||||||||
($ millions, except per common share amounts)
|
2009
|
2008
|
2007
|
|||||||||
Revenue, before royalties
|
$ | 11,078 | $ | 16,173 | $ | 12,543 | ||||||
Net earnings
|
$ | 1,580 | $ | 4,985 | $ | 2,608 | ||||||
Per common share– basic and diluted
|
$ | 2.92 | $ | 9.22 | $ | 4.84 | ||||||
Adjusted net earnings from operations (1)
|
$ | 2,689 | $ | 3,492 | $ | 2,406 | ||||||
Per common share– basic and diluted
|
$ | 4.96 | $ | 6.46 | $ | 4.46 | ||||||
Cash flow from operations (2)
|
$ | 6,090 | $ | 6,969 | $ | 6,198 | ||||||
Per common share– basic and diluted
|
$ | 11.24 | $ | 12.89 | $ | 11.49 | ||||||
Dividends declared per common share
|
$ | 0.42 | $ | 0.40 | $ | 0.34 | ||||||
Total assets
|
$ | 41,024 | $ | 42,650 | $ | 36,114 | ||||||
Total long-term liabilities
|
$ | 19,193 | $ | 20,856 | $ | 19,230 | ||||||
Capital expenditures, net of dispositions
|
$ | 2,997 | $ | 7,451 | $ | 6,425 |
|
(1) Adjusted net earnings from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings from operations. The reconciliation “Adjusted Net Earnings from Operations” presented below lists the after-tax effects of certain items of a non-operational nature that are included in the Company’s financial results. Adjusted net earnings from operations may not be comparable to similar measures presented by other companies.
|
|
(2) Cash flow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments. The Company evaluates its performance based on cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Cash Flow from Operations" presented below lists the effects of certain non-cash items that are included in the Company’s financial results. Cash flow from operations may not be comparable to similar measures presented by other companies.
|
Adjusted Net Earnings from Operations
|
||||||||||||
($ millions)
|
2009
|
2008
|
2007
|
|||||||||
Net earnings as reported
|
$ | 1,580 | $ | 4,985 | $ | 2,608 | ||||||
Stock-based compensation expense (recovery), net of tax (a)
|
261 | (38 | ) | 134 | ||||||||
Unrealized risk management loss (gain), net of tax (b)
|
1,437 | (2,112 | ) | 977 | ||||||||
Unrealized foreign exchange (gain) loss, net of tax (c)
|
(570 | ) | 698 | (449 | ) | |||||||
Effect of statutory tax rate and other legislative changes on future income tax liabilities (d)
|
(19 | ) | (41 | ) | (864 | ) | ||||||
Adjusted net earnings from operations
|
$ | 2,689 | $ | 3,492 | $ | 2,406 |
|
(a) The Company’s employee stock option plan provides for a cash payment option. Accordingly, the intrinsic value of outstanding vested options is recorded as a liability on the Company’s balance sheet and periodic changes in the intrinsic value are recognized in net earnings or are capitalized to Oil Sands Mining and Upgrading construction costs.
|
|
(b) Derivative financial instruments are recorded at fair value on the balance sheet, with changes in fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil and natural gas.
|
|
(c) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, offset by the impact of cross currency swap hedges, and are recognized in net earnings.
|
|
(d) All substantively enacted or enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the Company’s consolidated balance sheet in determining future income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in net earnings during the period the legislation is substantively enacted or enacted. Income tax rate changes during 2009 resulted in a reduction of future income tax liabilities of approximately $19 million in North America. Income tax rate changes during 2008 resulted in a reduction of future income tax liabilities of approximately $19 million in North America and $22 million in Côte d’Ivoire, Offshore West Africa. Income tax rate and other legislative changes during 2007 resulted in a reduction of future income tax liabilities of approximately $864 million in North America.
|
Cash Flow from Operations
|
||||||||||||
($ millions)
|
2009
|
2008
|
2007
|
|||||||||
Net earnings
|
$ | 1,580 | $ | 4,985 | $ | 2,608 | ||||||
Non-cash items:
|
||||||||||||
Depletion, depreciation and amortization
|
2,819 | 2,683 | 2,863 | |||||||||
Asset retirement obligation accretion
|
90 | 71 | 70 | |||||||||
Stock-based compensation expense (recovery)
|
355 | (52 | ) | 193 | ||||||||
Unrealized risk management loss (gain)
|
1,991 | (3,090 | ) | 1,400 | ||||||||
Unrealized foreign exchange (gain) loss
|
(661 | ) | 832 | (524 | ) | |||||||
Deferred petroleum revenue tax expense (recovery)
|
15 | (67 | ) | 44 | ||||||||
Future income tax (recovery) expense
|
(99 | ) | 1,607 | (456 | ) | |||||||
Cash flow from operations
|
$ | 6,090 | $ | 6,969 | $ | 6,198 |
($ millions, except per common share amounts)
|
||||||||||||||||||||
2009
|
Total
|
Dec 31
|
Sep 30
|
Jun 30
|
Mar 31
|
|||||||||||||||
Revenue, before royalties
|
$ | 11,078 | $ | 3,319 | $ | 2,823 | $ | 2,750 | $ | 2,186 | ||||||||||
Net earnings
|
$ | 1,580 | $ | 455 | $ | 658 | $ | 162 | $ | 305 | ||||||||||
Net earnings per common share
|
||||||||||||||||||||
– basic and diluted
|
$ | 2.92 | $ | 0.85 | $ | 1.21 | $ | 0.30 | $ | 0.56 | ||||||||||
2008
|
Total
|
Dec 31
|
Sep 30
|
Jun 30
|
Mar 31
|
|||||||||||||||
Revenue, before royalties
|
$ | 16,173 | $ | 2,511 | $ | 4,583 | $ | 5,112 | $ | 3,967 | ||||||||||
Net earnings (loss)
|
$ | 4,985 | $ | 1,770 | $ | 2,835 | $ | (347 | ) | $ | 727 | |||||||||
Net earnings (loss) per common share
|
||||||||||||||||||||
– basic and diluted
|
$ | 9.22 | $ | 3.27 | $ | 5.25 | $ | (0.65 | ) | $ | 1.35 |
§
|
Crude oil pricing – The impact of fluctuating demand, geopolitical uncertainties on worldwide benchmark pricing, and the fluctuations in the Heavy Crude Oil Differential from WTI (“Heavy Differential”) in North America.
|
§
|
Natural gas pricing – The impact of seasonal fluctuations in both the demand for natural gas and inventory storage levels, and the impact of increased shale gas production in the US, as well as fluctuations in imports of liquefied natural gas into the US.
|
§
|
Crude oil and NGLs sales volumes – Fluctuations in production from the Company’s Primrose thermal projects, the results from the Pelican Lake water and polymer flood projects, and the commencement of operations at Horizon. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the North Sea and Offshore West Africa and the impact of the shut in, and subsequent restoration of some of the production in the Baobab Field.
|
§
|
Natural gas sales volumes – Production declines due to the Company’s strategic decision to reduce natural gas drilling activity in North America and the allocation of capital to higher return crude oil projects, as well as natural decline rates.
|
§
|
Production expense – Fluctuations primarily due to the impact of the demand for services, industry-wide inflationary cost pressures experienced in prior quarters, fluctuations in product mix, the impact of seasonal costs that are dependent on weather, and the commencement of operations at Horizon and the Olowi Field in Offshore Gabon.
|
§
|
Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company’s proved undeveloped reserves, the commencement of operations at Horizon and the Olowi Field in Offshore Gabon, and the impact of a ceiling test impairment at the Olowi Field at December 31, 2009.
|
§
|
Stock-based compensation – Fluctuations due to the mark-to-market movements of the Company’s stock-based compensation liability. Stock-based compensation expense (recovery) reflected fluctuations in the Company’s share price.
|
§
|
Risk management – Fluctuations due to the recognition of realized and unrealized gains and losses from the mark-to-market and subsequent settlement of the Company’s risk management activities.
|
§
|
Foreign exchange rates – Fluctuations in the Canadian dollar relative to the US dollar impacted the realized price the Company received for its crude oil and natural gas sales, as sales prices are based predominately on US dollar denominated benchmarks. Similarly, unrealized foreign exchange gains and losses were recorded with respect to US dollar denominated debt and the re-measurement of North Sea future income tax liabilities denominated in UK pounds sterling to US dollars, partially offset by the impact of cross currency swap hedges.
|
§
|
Income tax expense (recovery) – Fluctuations in income tax expense (recovery) include statutory tax rate and other legislative changes substantively enacted or enacted in the various periods.
|
(Yearly average)
|
2009
|
2008
|
2007
|
|||||||||
WTI benchmark price (US$/bbl)
|
$ | 61.93 | $ | 99.65 | $ | 72.40 | ||||||
Dated Brent benchmark price (US$/bbl)
|
$ | 61.61 | $ | 96.99 | $ | 72.59 | ||||||
WCS blend differential from WTI (US$/bbl) (1)
|
$ | 9.64 | $ | 20.03 | $ | 23.25 | ||||||
WCS blend differential from WTI (%) (1)
|
16 | % | 20 | % | 32 | % | ||||||
SCO price (US$/bbl)
|
$ | 61.51 | $ | 102.48 | $ | 70.11 | ||||||
Condensate benchmark price (US$/bbl)
|
$ | 60.60 | $ | 100.10 | $ | 72.88 | ||||||
NYMEX benchmark price (US$/mmbtu)
|
$ | 4.03 | $ | 8.95 | $ | 6.92 | ||||||
AECO benchmark price (C$/GJ)
|
$ | 3.91 | $ | 7.71 | $ | 6.26 | ||||||
US / Canadian dollar average exchange rate
|
$ | 0.8760 | $ | 0.9381 | $ | 0.9304 | ||||||
US / Canadian dollar year end exchange rate
|
$ | 0.9555 | $ | 0.8166 | $ | 1.0120 |
Changes
|
Changes
|
|||||||||||||||||||||||||||||||||||
due to
|
due to
|
|||||||||||||||||||||||||||||||||||
($ millions)
|
2007
|
Volumes
|
Prices
|
Other
|
2008
|
Volumes
|
Prices
|
Other
|
2009
|
|||||||||||||||||||||||||||
North America
|
||||||||||||||||||||||||||||||||||||
Crude oil and NGLs
|
$ | 5,847 | $ | (49 | ) | $ | 3,013 | $ | – | $ | 8,811 | $ | (424 | ) | $ | (2,649 | ) | $ | – | $ | 5,738 | |||||||||||||||
Natural Gas
|
4,302 | (531 | ) | 914 | – | 4,685 | (598 | ) | (1,852 | ) | – | 2,235 | ||||||||||||||||||||||||
10,149 | (580 | ) | 3,927 | – | 13,496 | (1,022 | ) | (4,501 | ) | – | 7,973 | |||||||||||||||||||||||||
North Sea
|
||||||||||||||||||||||||||||||||||||
Crude oil and NGLs
|
1,575 | (334 | ) | 512 | – | 1,753 | (344 | ) | (465 | ) | – | 944 | ||||||||||||||||||||||||
Natural gas
|
22 | (5 | ) | (1 | ) | – | 16 | – | 1 | – | 17 | |||||||||||||||||||||||||
1,597 | (339 | ) | 511 | – | 1,769 | (344 | ) | (464 | ) | – | 961 | |||||||||||||||||||||||||
Offshore West Africa
|
||||||||||||||||||||||||||||||||||||
Crude oil and NGLs
|
751 | (136 | ) | 280 | – | 895 | 413 | (436 | ) | – | 872 | |||||||||||||||||||||||||
Natural gas
|
25 | 5 | 19 | – | 49 | 18 | (26 | ) | – | 41 | ||||||||||||||||||||||||||
776 | (131 | ) | 299 | – | 944 | 431 | (462 | ) | – | 913 | ||||||||||||||||||||||||||
Subtotal
|
||||||||||||||||||||||||||||||||||||
Crude oil and NGLs
|
8,173 | (519 | ) | 3,805 | – | 11,459 | (355 | ) | (3,550 | ) | – | 7,554 | ||||||||||||||||||||||||
Natural gas
|
4,349 | (531 | ) | 932 | – | 4,750 | (580 | ) | (1,877 | ) | – | 2,293 | ||||||||||||||||||||||||
12,522 | (1,050 | ) | 4,737 | – | 16,209 | (935 | ) | (5,427 | ) | – | 9,847 | |||||||||||||||||||||||||
Oil Sands Mining and Upgrading
|
– | – | – | – | – | 1,253 | – | – | 1,253 | |||||||||||||||||||||||||||
Midstream
|
74 | – | – | 3 | 77 | – | – | (5 | ) | 72 | ||||||||||||||||||||||||||
Intersegment eliminations and other (1)
|
(53 | ) | – | – | (60 | ) | (113 | ) | – | – | 19 | (94 | ) | |||||||||||||||||||||||
Total
|
$ | 12,543 | $ | (1,050 | ) | $ | 4,737 | $ | (57 | ) | $ | 16,173 | $ | 318 | $ | (5,427 | ) | $ | 14 | $ | 11,078 |
2009
|
2008
|
2007
|
|
Crude oil and NGLs (bbl/d)
|
|||
North America – Conventional
|
234,523
|
243,826
|
246,779
|
North America – Oil Sands Mining and Upgrading
|
50,250
|
–
|
–
|
North Sea
|
37,761
|
45,274
|
55,933
|
Offshore West Africa
|
32,929
|
26,567
|
28,520
|
355,463
|
315,667
|
331,232
|
|
Natural gas (mmcf/d)
|
|||
North America
|
1,287
|
1,472
|
1,643
|
North Sea
|
10
|
10
|
13
|
Offshore West Africa
|
18
|
13
|
12
|
1,315
|
1,495
|
1,668
|
|
Total barrels of oil equivalent (boe/d)
|
574,730
|
564,845
|
609,206
|
Product mix
|
|||
Light/medium crude oil and NGLs
|
21%
|
22%
|
23%
|
Pelican Lake crude oil
|
6%
|
6%
|
6%
|
Primary heavy crude oil
|
15%
|
16%
|
15%
|
Thermal heavy crude oil
|
11%
|
12%
|
11%
|
Synthetic crude oil
|
9%
|
–
|
–
|
Natural gas
|
38%
|
44%
|
45%
|
Percentage of gross revenue (1)
|
|||
(excluding midstream revenue)
|
|||
Crude oil and NGLs
|
75%
|
68%
|
62%
|
Natural gas
|
25%
|
32%
|
38%
|
(1)
|
Net of transportation and blending costs and excluding risk management activities.
|
2009
|
2008
|
2007
|
|
Crude oil and NGLs (bbl/d)
|
|||
North America – Conventional
|
201,873
|
207,933
|
210,769
|
North America – Oil Sands Mining and Upgrading
|
48,833
|
–
|
–
|
North Sea
|
37,683
|
45,182
|
55,825
|
Offshore West Africa
|
29,922
|
22,641
|
26,012
|
318,311
|
275,756
|
292,606
|
|
Natural gas (mmcf/d)
|
|||
North America
|
1,214
|
1,225
|
1,378
|
North Sea
|
10
|
10
|
13
|
Offshore West Africa
|
17
|
11
|
11
|
1,241
|
1,246
|
1,402
|
|
Total barrels of oil equivalent (boe/d)
|
525,103
|
483,541
|
526,193
|
(bbl)
|
2009
|
2008
|
2007
|
North America – Conventional
|
1,131,372
|
761,351
|
1,097,526
|
North America – Oil Sands Mining and Upgrading (SCO)
|
1,224,481
|
–
|
–
|
North Sea
|
713,112
|
558,904
|
1,032,723
|
Offshore West Africa(1)
|
51,103
|
1,113,156
|
342,987
|
3,120,068
|
2,433,411
|
2,473,236
|
(1)
|
Prior period inventory volumes include one-time adjustments to sales volumes for MD&A reporting purposes only.
|
2009
|
2008
|
2007
|
||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||
Sales price (2)
|
$ | 57.68 | $ | 82.41 | $ | 55.45 | ||||||
Royalties
|
6.73 | 10.48 | 5.94 | |||||||||
Production expense
|
15.92 | 16.26 | 13.34 | |||||||||
Netback
|
$ | 35.03 | $ | 55.67 | $ | 36.17 | ||||||
Natural gas ($/mcf) (1)
|
||||||||||||
Sales price (2)
|
$ | 4.53 | $ | 8.39 | $ | 6.85 | ||||||
Royalties (3)
|
0.32 | 1.46 | 1.11 | |||||||||
Production expense
|
1.08 | 1.02 | 0.91 | |||||||||
Netback
|
$ | 3.13 | $ | 5.91 | $ | 4.83 | ||||||
Barrels of oil equivalent ($/boe) (1)
|
||||||||||||
Sales price (2)
|
$ | 44.87 | $ | 68.62 | $ | 49.05 | ||||||
Royalties
|
4.72 | 9.78 | 6.26 | |||||||||
Production expense
|
11.98 | 11.79 | 9.75 | |||||||||
Netback
|
$ | 28.17 | $ | 47.05 | $ | 33.04 |
(1)
|
Amounts expressed on a per unit basis are based on sales volumes.
|
(2)
|
Net of transportation and blending costs and excluding risk management activities.
|
(3)
|
Natural gas royalties for 2009 reflect the impact of natural gas physical sales contracts.
|
ANALYSIS OF PRODUCT PRICES – CONVENTIONAL
|
2009
|
2008
|
2007
|
||||||||||
Crude oil and NGLs ($/bbl) (1) (2)
|
||||||||||||
North America
|
$ | 54.70 | $ | 77.42 | $ | 49.16 | ||||||
North Sea
|
$ | 68.84 | $ | 100.31 | $ | 74.99 | ||||||
Offshore West Africa
|
$ | 65.27 | $ | 97.96 | $ | 71.68 | ||||||
Company average
|
$ | 57.68 | $ | 82.41 | $ | 55.45 | ||||||
Natural gas ($/mcf) (1) (2)
|
||||||||||||
North America
|
$ | 4.51 | $ | 8.41 | $ | 6.87 | ||||||
North Sea
|
$ | 4.66 | $ | 4.09 | $ | 4.26 | ||||||
Offshore West Africa
|
$ | 6.11 | $ | 10.03 | $ | 5.68 | ||||||
Company average
|
$ | 4.53 | $ | 8.39 | $ | 6.85 | ||||||
Company average ($/boe) (1) (2)
|
$ | 44.87 | $ | 68.62 | $ | 49.05 |
(Yearly average)
|
2009
|
2008
|
2007
|
|||||||||
Wellhead Price (1) (2)
|
||||||||||||
Light/medium crude oil and NGLs (C$/bbl)
|
$ | 57.02 | $ | 89.04 | $ | 66.24 | ||||||
Pelican Lake crude oil (C$/bbl)
|
$ | 55.52 | $ | 76.91 | $ | 46.29 | ||||||
Primary heavy crude oil (C$/bbl)
|
$ | 55.66 | $ | 74.91 | $ | 43.77 | ||||||
Thermal heavy crude oil (C$/bbl)
|
$ | 51.18 | $ | 71.89 | $ | 43.49 | ||||||
Natural gas (C$/mcf)
|
$ | 4.51 | $ | 8.41 | $ | 6.87 |
North Sea
|
2009
|
2008
|
2007
|
||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||
North America
|
$ | 7.93 | $ | 11.99 | $ | 7.19 | ||||||
North Sea
|
$ | 0.14 | $ | 0.21 | $ | 0.14 | ||||||
Offshore West Africa
|
$ | 5.79 | $ | 14.81 | $ | 6.40 | ||||||
Company average
|
$ | 6.73 | $ | 10.48 | $ | 5.94 | ||||||
Natural gas ($/mcf) (1)
|
||||||||||||
North America (2)
|
$ | 0.32 | $ | 1.47 | $ | 1.12 | ||||||
Offshore West Africa
|
$ | 0.53 | $ | 1.52 | $ | 0.51 | ||||||
Company average
|
$ | 0.32 | $ | 1.46 | $ | 1.11 | ||||||
Company average ($/boe) (1)
|
$ | 4.72 | $ | 9.78 | $ | 6.26 | ||||||
Percentage of revenue (3)
|
||||||||||||
Crude oil and NGLs
|
12 | % | 13 | % | 11 | % | ||||||
Natural gas (2)
|
7 | % | 17 | % | 16 | % | ||||||
Boe
|
11 | % | 14 | % | 13 | % |
·
|
A royalty credit of $200 per meter on new conventional crude oil and natural gas wells drilled between April 1, 2009 and March 31, 2010, to a maximum of 10% of conventional Crown royalties paid in Alberta.
|
·
|
Reduced royalty rates that set the maximum royalty at 5% for the first 12 months of production, up to a maximum of 50,000 boe or 500 mmcfe, for new conventional crude oil and natural gas wells that commence production between April 1, 2009 and March 31, 2010.
|
·
|
A one-year, 2% royalty rate for all natural gas wells drilled between September 1, 2009 and June 30, 2010. Qualifying wells must commence production before December 31, 2010.
|
·
|
A permanent increase of 15% in the existing royalty holiday credits for the Deep Royalty Program.
|
·
|
Permanent qualification of horizontal wells drilled to a vertical depth between 1,900 and 2,300 meters into the Deep Royalty Program.
|
·
|
An additional $50 million allocation for the Infrastructure Royalty Credit Program to stimulate investment in oil and gas roads and pipelines.
|
2009
|
2008
|
2007
|
||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||
North America
|
$ | 14.63 | $ | 14.96 | $ | 12.26 | ||||||
North Sea
|
$ | 26.98 | $ | 26.29 | $ | 20.78 | ||||||
Offshore West Africa
|
$ | 12.83 | $ | 10.29 | $ | 8.32 | ||||||
Company average
|
$ | 15.92 | $ | 16.26 | $ | 13.34 | ||||||
Natural gas ($/mcf) (1)
|
||||||||||||
North America
|
$ | 1.07 | $ | 1.00 | $ | 0.90 | ||||||
North Sea
|
$ | 2.16 | $ | 2.51 | $ | 2.17 | ||||||
Offshore West Africa
|
$ | 1.23 | $ | 1.61 | $ | 1.48 | ||||||
Company average
|
$ | 1.08 | $ | 1.02 | $ | 0.91 | ||||||
Company average ($/boe) (1)
|
$ | 11.98 | $ | 11.79 | $ | 9.75 |
($ millions, except per boe amounts) (1)
|
2009
|
2008
|
2007
|
|||||||||
North America
|
$ | 2,060 | $ | 2,236 | $ | 2,350 | ||||||
North Sea
|
261 | 317 | 340 | |||||||||
Offshore West Africa
|
335 | 132 | 165 | |||||||||
Expense
|
$ | 2,656 | $ | 2,685 | $ | 2,855 | ||||||
$/boe
|
$ | 13.82 | $ | 12.97 | $ | 12.84 |
($ millions, except per boe amounts) (1)
|
2009
|
2008
|
2007
|
|||||||||
North America
|
$ | 41 | $ | 42 | $ | 38 | ||||||
North Sea
|
24 | 27 | 30 | |||||||||
Offshore West Africa
|
4 | 2 | 2 | |||||||||
Expense
|
$ | 69 | $ | 71 | $ | 70 | ||||||
$/boe
|
$ | 0.36 | $ | 0.34 | $ | 0.32 |
($/bbl) (1)
|
2009
|
2008
|
2007
|
|||||||||
SCO sales price (2)
|
$ | 70.83 | $ | – | $ | – | ||||||
Bitumen value for royalty purposes
|
$ | 56.57 | $ | – | $ | – | ||||||
Bitumen royalties (3)
|
$ | 2.15 | $ | – | $ | – |
($ millions)
|
2009
|
2008
|
2007
|
|||||||||
Cash costs, excluding natural gas costs
|
$ | 599 | $ | – | $ | – | ||||||
Natural gas costs
|
84 | – | – | |||||||||
Total cash production costs
|
$ | 683 | $ | – | $ | – |
($/bbl) (1)
|
2009
|
2008
|
2007
|
|||||||||
Cash costs, excluding natural gas costs
|
$ | 34.97 | $ | – | $ | – | ||||||
Natural gas costs
|
4.92 | – | – | |||||||||
Total cash production costs
|
$ | 39.89 | $ | – | $ | – | ||||||
Sales (bbl/d)
|
46,896 | – | – |
($ millions)
|
2009
|
2008
|
2007
|
|||||||||
Depreciation, depletion and amortization
|
$ | 187 | $ | – | $ | – | ||||||
Asset retirement obligation accretion
|
21 | – | – | |||||||||
Total
|
$ | 208 | $ | – | $ | – |
($/bbl) (1)
|
2009
|
2008
|
2007
|
|||||||||
Depreciation, depletion and amortization
|
$ | 10.95 | $ | – | $ | – | ||||||
Asset retirement obligation accretion
|
1.22 | – | – | |||||||||
Total
|
$ | 12.17 | $ | – | $ | – |
($ millions)
|
2009
|
2008
|
2007
|
|||||||||
Revenue
|
$ | 72 | $ | 77 | $ | 74 | ||||||
Production expense
|
19 | 25 | 22 | |||||||||
Midstream cash flow
|
53 | 52 | 52 | |||||||||
Depreciation
|
9 | 8 | 8 | |||||||||
Segment earnings before taxes
|
$ | 44 | $ | 44 | $ | 44 |
($ millions, except per boe amounts) (1)
|
2009
|
2008
|
2007
|
|||||||||
Expense
|
$ | 181 | $ | 180 | $ | 208 | ||||||
$/boe
|
$ | 0.87 | $ | 0.87 | $ | 0.93 |
($ millions)
|
2009
|
2008
|
2007
|
|||||||||
Expense (recovery)
|
$ | 355 | $ | (52 | ) | $ | 193 |
($ millions, except per boe amounts and interest rates) (1)
|
2009
|
2008
|
2007
|
|||||||||
Expense, gross
|
$ | 516 | $ | 609 | $ | 632 | ||||||
Less: capitalized interest, Oil Sands Mining and Upgrading
|
106 | 481 | 356 | |||||||||
Expense, net
|
$ | 410 | $ | 128 | $ | 276 | ||||||
$/boe
|
$ | 1.96 | $ | 0.62 | $ | 1.24 | ||||||
Average effective interest rate
|
4.3 | % | 5.1 | % | 5.5 | % |
($ millions)
|
2009
|
2008
|
2007
|
|||||||||
Crude oil and NGLs financial instruments
|
$ | (1,330 | ) | $ | 2,020 | $ | 505 | |||||
Natural gas financial instruments
|
(33 | ) | (21 | ) | (343 | ) | ||||||
Foreign currency contracts
|
110 | (139 | ) | - | ||||||||
Realized (gain) loss
|
$ | (1,253 | ) | $ | 1,860 | $ | 162 | |||||
Crude oil and NGLs financial instruments
|
$ | 2,039 | $ | (3,104 | ) | $ | 1,244 | |||||
Natural gas financial instruments
|
(58 | ) | 16 | 156 | ||||||||
Foreign currency contracts
|
10 | (2 | ) | - | ||||||||
Unrealized loss (gain)
|
$ | 1,991 | $ | (3,090 | ) | $ | 1,400 | |||||
Net loss (gain)
|
$ | 738 | $ | (1,230 | ) | $ | 1,562 |
($ millions)
|
2009
|
2008
|
2007
|
|||||||||
Net realized loss (gain)
|
$ | 30 | $ | (114 | ) | $ | 53 | |||||
Net unrealized (gain) loss (1)
|
(661 | ) | 832 | (524 | ) | |||||||
Net (gain) loss
|
$ | (631 | ) | $ | 718 | $ | (471 | ) |
($ millions, except income tax rates)
|
2009
|
2008
|
2007
|
|||||||||
Current
|
$ | 91 | $ | 245 | $ | 121 | ||||||
Deferred
|
15 | (67 | ) | 44 | ||||||||
Taxes other than income tax
|
$ | 106 | $ | 178 | $ | 165 | ||||||
North America (1)
|
$ | 28 | $ | 33 | $ | 96 | ||||||
North Sea
|
278 | 340 | 210 | |||||||||
Offshore West Africa
|
82 | 128 | 74 | |||||||||
Current income tax
|
388 | 501 | 380 | |||||||||
Future income tax
|
(99 | ) | 1,607 | (456 | ) | |||||||
289 | 2,108 | (76 | ) | |||||||||
Income tax rate and other legislative changes (2) (3) (4)
|
19 | 41 | 864 | |||||||||
$ | 308 | $ | 2,149 | $ | 788 | |||||||
Effective income tax rate before income tax rate and other legislative changes
|
24.3 | % | 27.8 | % | 32.2 | % |
($ millions)
|
2009
|
2008
|
2007
|
|||||||||
Expenditures on property, plant and equipment
|
||||||||||||
Net property acquisitions (dispositions)
|
$ | 6 | $ | 336 | $ | (39 | ) | |||||
Land acquisition and retention
|
77 | 86 | 95 | |||||||||
Seismic evaluations
|
73 | 107 | 124 | |||||||||
Well drilling, completion and equipping
|
1,244 | 1,664 | 1,642 | |||||||||
Production and related facilities
|
977 | 1,282 | 1,205 | |||||||||
Total net reserve replacement expenditures
|
2,377 | 3,475 | 3,027 | |||||||||
Oil Sands Mining and Upgrading:
|
||||||||||||
Horizon Phase 1 construction costs
|
69 | 2,732 | 2,740 | |||||||||
Horizon Phase 1 commissioning costs and other
|
202 | 364 | – | |||||||||
Horizon Phases 2/3 construction costs
|
104 | 336 | 124 | |||||||||
Capitalized interest, stock-based compensation and other
|
98 | 480 | 437 | |||||||||
Sustaining capital
|
80 | – | – | |||||||||
Total Oil Sands Mining and Upgrading (2)
|
553 | 3,912 | 3,301 | |||||||||
Midstream
|
6 | 9 | 6 | |||||||||
Abandonments (3)
|
48 | 38 | 71 | |||||||||
Head office
|
13 | 17 | 20 | |||||||||
Total net capital expenditures
|
$ | 2,997 | $ | 7,451 | $ | 6,425 | ||||||
By segment
|
||||||||||||
North America
|
$ | 1,663 | $ | 2,344 | $ | 2,428 | ||||||
North Sea
|
168 | 319 | 439 | |||||||||
Offshore West Africa
|
544 | 811 | 159 | |||||||||
Other
|
2 | 1 | 1 | |||||||||
Oil Sands Mining and Upgrading
|
553 | 3,912 | 3,301 | |||||||||
Midstream
|
6 | 9 | 6 | |||||||||
Abandonments (3)
|
48 | 38 | 71 | |||||||||
Head office
|
13 | 17 | 20 | |||||||||
Total
|
$ | 2,997 | $ | 7,451 | $ | 6,425 |
2009
|
2008
|
2007
|
|
Net successful natural gas wells
|
109
|
269
|
383
|
Net successful crude oil wells
|
644
|
682
|
592
|
Dry wells
|
46
|
39
|
93
|
Stratigraphic test / service wells
|
329
|
131
|
254
|
Total
|
1,128
|
1,121
|
1,322
|
Success rate (excluding stratigraphic test / service wells)
|
94%
|
96%
|
91%
|
·
|
Premature equipment failures in the Ore Preparation Plant, Primary Upgrading, the Naphtha Recovery Unit and the Sulphur Plant;
|
·
|
Ore processing challenges arising in September resulting from a higher percentage of clays in the second mine bench and the lack of available blending materials from other mine benches associated with early mine operations; and
|
·
|
Equipment failure in the hydrogen plant requiring a shutdown for an extended period to time, and issues with one of the coker furnaces.
|
($ millions, except ratios)
|
2009
|
2008
|
2007
|
|||||||||
Working capital (deficit) (1)
|
$ | (514 | ) | $ | 392 | $ | (1,382 | ) | ||||
Long-term debt (2) (3)
|
$ | 9,658 | $ | 13,016 | $ | 10,940 | ||||||
Shareholders’ equity
|
||||||||||||
Share capital
|
$ | 2,834 | $ | 2,768 | $ | 2,674 | ||||||
Retained earnings
|
16,696 | 15,344 | 10,575 | |||||||||
Accumulated other comprehensive (loss) income
|
(104 | ) | 262 | 72 | ||||||||
Total
|
$ | 19,426 | $ | 18,374 | $ | 13,321 | ||||||
Debt to book capitalization (3) (4)
|
33 | % | 41 | % | 45 | % | ||||||
Debt to market capitalization (3) (5)
|
19 | % | 33 | % | 22 | % | ||||||
After tax return on average common shareholders’
equity (6)
|
8 | % | 33 | % | 22 | % | ||||||
After tax return on average capital employed (3) (7)
|
6 | % | 19 | % | 12 | % |
($ millions)
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
||||||||||||||||||
Product transportation and pipeline
|
$ | 207 | $ | 162 | $ | 136 | $ | 125 | $ | 126 | $ | 1,051 | ||||||||||||
Offshore equipment operating lease
|
$ | 155 | $ | 124 | $ | 103 | $ | 102 | $ | 101 | $ | 261 | ||||||||||||
Offshore drilling
|
$ | 49 | $ | – | $ | – | $ | – | $ | – | $ | – | ||||||||||||
Asset retirement obligations (1)
|
$ | 16 | $ | 20 | $ | 21 | $ | 31 | $ | 39 | $ | 6,479 | ||||||||||||
Long-term debt (2)
|
$ | 400 | $ | 419 | $ | 366 | $ | 819 | $ | 366 | $ | 5,424 | ||||||||||||
Interest expense (3)
|
$ | 473 | $ | 451 | $ | 415 | $ | 370 | $ | 350 | $ | 4,779 | ||||||||||||
Office leases
|
$ | 25 | $ | 19 | $ | 3 | $ | 2 | $ | 2 | $ | – | ||||||||||||
Other
|
$ | 271 | $ | 67 | $ | 23 | $ | 15 | $ | 12 | $ | 34 |
Crude oil and NGLs (mmbbl)
|
Synthetic
Crude Oil (1) |
Bitumen (2)
|
Other Oil
& NGLs
|
North
America Total |
North
Sea
|
Offshore
West
Africa
|
Total
|
Net proved reserves
|
|||||||
Reserves, December 31, 2008
|
–
|
690
|
258
|
948
|
256
|
142
|
1,346
|
Extensions and discoveries
|
–
|
24
|
6
|
30
|
–
|
–
|
30
|
Improved recovery
|
–
|
8
|
75
|
83
|
–
|
–
|
83
|
SEC Reliable Technology (3)
|
–
|
7
|
–
|
7
|
–
|
–
|
7
|
SEC Rule Transition (4)
|
1,650
|
–
|
–
|
1,650
|
–
|
–
|
1,650
|
Purchases of reserves in place
|
–
|
–
|
1
|
1
|
–
|
–
|
1
|
Sales of reserves in place
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
Production
|
–
|
(49)
|
(24)
|
(73)
|
(14)
|
(11)
|
(98)
|
Economic revisions due to prices
|
–
|
(64)
|
(8)
|
(72)
|
57
|
(4)
|
(19)
|
Revisions of prior estimates
|
–
|
79
|
11
|
90
|
(59)
|
(4)
|
27
|
Reserves, December 31, 2009
|
1,650
|
695
|
319
|
2,664
|
240
|
123
|
3,027
|
|
(1) Prior to December 31, 2009, the Company’s Horizon SCO reserves were reported separately in accordance with SEC’s Industry Guide 7. With SEC’s Final Rule in effect January 1, 2010, this synthetic crude oil is now included in the Company’s crude oil and natural gas reserve totals.
|
|
(2) Bitumen as defined by the SEC, under the Final Rule, “is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.” Under this definition, all the Company’s thermal and primary heavy crude oil reserves have been included. Prior to December 31, 2009, these numbers would have been included within the Company’s conventional crude oil and NGL totals.
|
|
(3) SEC reliable technology accounts for reserve volumes added due to the reserve rule changes.
|
|
(4) For continuity purposes, with respect to the transition from Industry Guide 7 into SEC’s Final Rule, the following SCO table has been provided to illustrate the changes in the Company’s Horizon SCO reserves for the 2009 year.
|
Horizon SCO reserves (mmbbl)
|
Net Proved (mmbl)
|
|
Reserves, December 31, 2008
|
1,946
|
|
Production
|
(18)
|
|
Economic revisions due to prices
|
(307)
|
|
Revisions of prior estimates
|
29
|
|
Reserves, December 31, 2009
|
1,650
|
Natural gas (bcf)
|
North
America
|
North
Sea
|
Offshore
West
Africa
|
Total
|
Net proved reserves
|
||||
Reserves, December 31, 2008
|
3,523
|
67
|
94
|
3,684
|
Extensions and discoveries
|
92
|
–
|
–
|
92
|
Improved recovery
|
11
|
–
|
–
|
11
|
SEC Reliable Technology
|
–
|
–
|
–
|
–
|
Purchases of reserves in place
|
15
|
–
|
–
|
15
|
Sales of reserves in place
|
(6)
|
–
|
–
|
(6)
|
Production
|
(443)
|
(4)
|
(6)
|
(453)
|
Economic revisions due to prices
|
(335)
|
12
|
(4)
|
(327)
|
Revisions of prior estimates
|
170
|
(8)
|
1
|
163
|
Reserves, December 31, 2009
|
3,027
|
67
|
85
|
3,179
|
·
|
Economic risk of finding, producing and replacing reserves at a reasonable cost, including the risk of reserve revisions due to economic and technical factors. Reserve revisions can have a positive or negative impact on asset valuations, ARO and depletion rates;
|
·
|
Prevailing prices of crude oil and NGLs, and natural gas;
|
·
|
Regulatory risk related to approval for exploration and development activities, which can add to costs or cause delays in projects;
|
·
|
Labour risk associated with securing the manpower necessary to complete capital projects in a timely and cost effective manner;
|
·
|
Operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas;
|
·
|
Success of exploration and development activities;
|
·
|
Timing and success of integrating the business and operations of acquired companies;
|
·
|
Credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts;
|
·
|
Interest rate risk associated with the Company’s ability to secure financing on commercially acceptable terms;
|
·
|
Foreign exchange risk due to fluctuating exchange rates on the Company’s US dollar denominated debt and as the majority of sales are based in US dollars;
|
·
|
Environmental impact risk associated with exploration and development activities, including GHG;
|
·
|
Risk of catastrophic loss due to fire, explosion or acts of nature;
|
·
|
Geopolitical risks associated with changing governmental policies, social instability and other political, economic or diplomatic developments in the Company’s operations;
|
·
|
Future legislative and regulatory developments related to environmental regulation;
|
·
|
Reservoir quality;
|
·
|
The ability to replace reserves of oil and gas, whether sourced from exploration, improved recovery or acquisition;
|
·
|
Potential actions of governments, regulatory authorities and other stakeholders that may impose operating costs or restrictions in the jurisdations where the Company has operations;
|
·
|
Changing royalty regimes;
|
·
|
Business interruptions because of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting the Company or other parties whose operations or assets directly or indirectly affect the Company and that may or may not be financially recoverable; and
|
·
|
Other circumstances affecting revenue and expenses.
|
·
|
An internal environmental compliance audit and inspection program of the Company’s operating facilities;
|
·
|
A suspended well inspection program to support future development or eventual abandonment;
|
·
|
Appropriate reclamation and decommissioning standards for wells and facilities ready for abandonment;
|
·
|
An effective surface reclamation program;
|
·
|
A due diligence program related to groundwater monitoring;
|
·
|
An active program related to preventing and reclaiming spill sites;
|
·
|
A solution gas conservation program;
|
·
|
A program to replace the majority of fresh water for steaming with brackish water;
|
·
|
Water programs to improve efficiency of use, recycle rates and water storage;
|
·
|
Environmental planning for all projects to assess impacts and to implement avoidance and mitigation programs;
|
·
|
Reporting for environmental liabilities;
|
·
|
A program to optimize efficiencies at the Company’s operating facilities;
|
·
|
Continued evaluation of new technologies to reduce environmental impacts;
|
·
|
Development and implementation of a tailings management plan; and
|
·
|
CO2 reduction programs including the injection of CO2 into tailings and for use in enhanced oil recovery.
|
Estimated ARO, undiscounted ($ millions)
|
2009
|
2008
|
||||||
North America, Conventional
|
$ | 3,346 | $ | 3,072 | ||||
North America, Oil Sands Mining and Upgrading (1)
|
1,485 | 93 | ||||||
North Sea
|
1,522 | 1,216 | ||||||
Offshore West Africa
|
253 | 93 | ||||||
6,606 | 4,474 | |||||||
North Sea PRT recovery
|
(568 | ) | (529 | ) | ||||
$ | 6,038 | $ | 3,945 |
·
|
Effective January 1, 2009 Section 3064 – “Goodwill and Intangible Assets” replaced Section 3062 – “Goodwill and Other Intangible Assets” and Section 3450 – “Research and Development Costs”. In addition, EIC-27 – “Revenue and Expenditures during the Pre-Operating Period” was withdrawn. The new standard addresses when an internally generated intangible asset meets the definition of an asset. The adoption of this standard, which was adopted retroactively, did not have an impact on the Company’s results of operations or financial position.
|
·
|
On January 20, 2009 the Emerging Issues Committee (“EIC”) issued a new abstract EIC–173 “Credit Risk and the Fair Value of Financial Assets and Financial Liabilities”. This abstract concludes that an entity’s own credit risk and the credit risk of the counterparty should be taken into account when determining the fair value of financial assets and financial liabilities, including derivative financial instruments. This abstract applies to all financial assets and liabilities measured at fair value in interim and annual financial statements for periods ending on or after January 20, 2009. The adoption of this abstract did not have a material impact on the Company’s results of operations or financial position.
|
·
|
Effective July 1, 2009 Section 3855 – “Financial Instruments – Recognition and Measurement” was amended to add guidance on the assessment of embedded derivatives upon reclassification of a financial asset from the held-for-trading category. This amendment did not have any impact on the Company’s results of operations or financial position.
|
·
|
Effective October 1, 2009 Section 3862 – “Financial Instruments – Disclosures” was amended to include additional disclosure requirements for fair value measurements of financial instruments and to enhance liquidity risk disclosure requirements. The amendment requires the classification and disclosure of fair value measurements using a three-level hierarchy that reflects the significance of the inputs used in making the fair value measurements. This amendment affected disclosure only and did not impact the Company’s accounting for financial instruments.
|
•
|
Phase 1 Diagnostic – identification of potential accounting and reporting differences between Canadian GAAP and IFRS.
|
•
|
Phase 2 Planning – establishment of project governance, processes, resources, budget and timeline.
|
•
|
Phase 3 Policy Delivery and Documentation – establishment of accounting policies under IFRS.
|
•
|
Phase 4 Policy Implementation – establishment of processes for accounting and reporting, IT change requirements, and education.
|
•
|
Phase 5 Sustainment – ongoing compliance with IFRS after implementation.
|
·
|
Pre-exploration costs must be expensed. Under full cost accounting, these costs are currently included in the country cost centre.
|
·
|
Exploration and evaluation costs will be initially capitalized as exploration and evaluation assets. Once technical feasibility and commercial viability of reserves is established for an area, the costs will be transferred to PP&E. If technically feasible and commercially viable reserves are not established for a new area, the costs must be expensed. Under full cost accounting, exploration and evaluation costs are currently disclosed as PP&E but withheld from depletion. Costs are transferred to the depletable assets when proved reserves are assigned or when it is determined that the costs are impaired.
|
·
|
PP&E for producing properties will be depreciated at an asset level. Under full cost accounting, PP&E is depleted on a country cost centre basis.
|
·
|
Interest directly attributable to the acquisition or construction of a qualifying asset must be capitalized to the cost of the asset. Under Canadian GAAP, capitalization of interest is discretionary.
|
·
|
Impairment of PP&E will be tested at a cash generating unit level (the lowest level at which cash inflows can be identified). Under full cost accounting, impairment is tested at the country cost centre level.
|
|
·
|
The Company intends to elect to reset the foreign currency translation adjustment to zero by transferring the Canadian GAAP balance to retained earnings on January 1, 2010, rather than retrospectively restating the balance.
|
|
·
|
The Company intends to adopt the IFRS 1 election to not restate business combinations entered into prior to January 1, 2010.
|
($ millions)
|
2010 Forecast
|
|||
Conventional crude oil and natural gas
|
||||
North America natural gas
|
$ | 674 | ||
North America crude oil and NGLs
|
1,900 | |||
North Sea
|
199 | |||
Offshore West Africa
|
264 | |||
Property acquisitions, dispositions and midstream
|
100 | |||
$ | 3,137 | |||
Oil Sands Mining and Upgrading
|
||||
Horizon Phase 2/3 – Tranche 2
|
$ | 479 | ||
Horizon Phase 2/3 – Engineering
|
95 | |||
Sustaining capital
|
164 | |||
Capitalized interest and other costs
|
47 | |||
$ | 785 | |||
Total
|
$ | 3,922 |
(Number of wells)
|
2010 Forecast
|
Targeting natural gas
|
93
|
Targeting crude oil
|
966
|
Stratigraphic test / service wells – conventional
|
227
|
Stratigraphic test wells – mining
|
166
|
Total
|
1,452
|
(Number of wells)
|
2010 Forecast
|
Coal bed methane and shallow natural gas
|
8
|
Conventional natural gas
|
36
|
Cardium natural gas
|
1
|
Deep natural gas
|
47
|
Foothills natural gas
|
1
|
Total
|
93
|
(Number of wells)
|
2010 Forecast
|
Conventional primary heavy crude oil
|
610
|
Thermal heavy crude oil
|
28
|
Light crude oil
|
117
|
Pelican Lake crude oil
|
201
|
Total
|
956
|
Cash flow from operations
($ millions)
|
Cash flow from operations (per common share, basic)
|
Net earnings
($ millions)
|
Net earnings (per common share, basic)
|
|||||||||||||
Price changes
|
||||||||||||||||
Crude oil – WTI US$1.00/bbl (1)
|
||||||||||||||||
Excluding financial derivatives
|
$ | 109 | $ | 0.20 | $ | 90 | $ | 0.17 | ||||||||
Including financial derivatives
|
$ | 91 | $ | 0.17 | $ | 76 | $ | 0.14 | ||||||||
Natural gas – AECO C$0.10/mcf (1)
|
||||||||||||||||
Excluding financial derivatives
|
$ | 33 | $ | 0.06 | $ | 24 | $ | 0.04 | ||||||||
Including financial derivatives
|
$ | 18 | $ | 0.03 | $ | 14 | $ | 0.03 | ||||||||
Volume changes
|
||||||||||||||||
Crude oil – 10,000 bbl/d
|
$ | 161 | $ | 0.30 | $ | 105 | $ | 0.19 | ||||||||
Natural gas – 10 mmcf/d
|
$ | 12 | $ | 0.02 | $ | 4 | $ | 0.01 | ||||||||
Foreign currency rate change
|
||||||||||||||||
$0.01 change in US$ (1)
|
||||||||||||||||
Including financial derivatives
|
$ | 95 – 97 | $ | 0.17 – 0.18 | $ | 31 – 32 | $ | 0.06 | ||||||||
Interest rate change – 1%
|
$ | 13 | $ | 0.02 | $ | 13 | $ | 0.02 |
(1)
|
For details of financial instruments in place, refer to note 13 to the Company’s audited annual consolidated financial statements as at December 31, 2009.
|
Q1
|
Q2
|
Q3
|
Q4
|
2009
|
2008
|
2007
|
||||||||
Crude oil and NGLs (bbl/d)
|
||||||||||||||
North America – Conventional
|
253,833
|
232,139
|
223,307
|
229,206
|
234,523
|
243,826
|
246,779
|
|||||||
North America – Oil Sands Mining and Upgrading
|
3,384
|
59,599
|
66,907
|
70,194
|
50,250
|
–
|
–
|
|||||||
North Sea
|
42,369
|
40,362
|
34,034
|
34,408
|
37,761
|
45,274
|
55,933
|
|||||||
Offshore West Africa
|
30,431
|
33,572
|
35,021
|
32,643
|
32,929
|
26,567
|
28,520
|
|||||||
Total
|
330,017
|
365,672
|
359,269
|
366,451
|
355,463
|
315,667
|
331,232
|
|||||||
Natural gas (mmcf/d)
|
||||||||||||||
North America
|
1,347
|
1,322
|
1,264
|
1,218
|
1,287
|
1,472
|
1,643
|
|||||||
North Sea
|
10
|
10
|
8
|
12
|
10
|
10
|
13
|
|||||||
Offshore West Africa
|
12
|
20
|
21
|
20
|
18
|
13
|
12
|
|||||||
Total
|
1,369
|
1,352
|
1,293
|
1,250
|
1,315
|
1,495
|
1,668
|
|||||||
Barrels of oil equivalent (boe/d)
|
||||||||||||||
North America – Conventional
|
478,301
|
452,494
|
433,928
|
432,167
|
449,054
|
489,081
|
520,564
|
|||||||
North America – Oil Sands Mining and Upgrading
|
3,384
|
59,599
|
66,907
|
70,194
|
50,250
|
–
|
–
|
|||||||
North Sea
|
44,039
|
42,045
|
35,380
|
36,440
|
39,444
|
46,956
|
58,099
|
|||||||
Offshore West Africa
|
32,418
|
36,846
|
38,540
|
36,056
|
35,982
|
28,808
|
30,543
|
|||||||
Total
|
558,142
|
590,984
|
574,755
|
574,857
|
574,730
|
564,845
|
609,206
|
Q1 | Q2 | Q3 | Q4 | 2009 | 2008 | 2007 | ||||||||||||||||||||||
Crude oil and NGLs ($/bbl)
|
||||||||||||||||||||||||||||
Sales price (2)
|
$ | 41.25 | $ | 59.56 | $ | 62.90 | $ | 68.00 | $ | 57.68 | $ | 82.41 | $ | 55.45 | ||||||||||||||
Royalties
|
3.98 | 7.27 | 7.89 | 7.96 | 6.73 | 10.48 | 5.94 | |||||||||||||||||||||
Production expense
|
15.02 | 16.59 | 16.71 | 15.45 | 15.92 | 16.26 | 13.34 | |||||||||||||||||||||
Netback
|
$ | 22.25 | $ | 35.70 | $ | 38.30 | $ | 44.59 | $ | 35.03 | $ | 55.67 | $ | 36.17 | ||||||||||||||
Natural gas ($/mcf)
|
||||||||||||||||||||||||||||
Sales price (2)
|
$ | 5.46 | $ | 4.11 | $ | 3.80 | $ | 4.75 | $ | 4.53 | $ | 8.39 | $ | 6.85 | ||||||||||||||
Royalties (3)
|
0.72 | 0.06 | 0.13 | 0.35 | 0.32 | 1.46 | 1.11 | |||||||||||||||||||||
Production expense
|
1.18 | 1.05 | 1.05 | 1.03 | 1.08 | 1.02 | 0.91 | |||||||||||||||||||||
Netback
|
$ | 3.56 | $ | 3.00 | $ | 2.62 | $ | 3.37 | $ | 3.13 | $ | 5.91 | $ | 4.83 | ||||||||||||||
Barrels of oil equivalent ($/boe)
|
||||||||||||||||||||||||||||
Sales price (2)
|
$ | 37.87 | $ | 44.52 | $ | 45.52 | $ | 51.95 | $ | 44.87 | $ | 68.62 | $ | 49.05 | ||||||||||||||
Royalties
|
4.14 | 4.34 | 4.85 | 5.60 | 4.72 | 9.78 | 6.26 | |||||||||||||||||||||
Production expense
|
11.77 | 12.21 | 12.26 | 11.72 | 11.98 | 11.79 | 9.75 | |||||||||||||||||||||
Netback
|
$ | 21.96 | $ | 27.97 | $ | 28.41 | $ | 34.63 | $ | 28.17 | $ | 47.05 | $ | 33.04 |
Q1 | Q2 | Q3 | Q4 | 2009 | 2008 | |||||||||||||||||||
TSX – C$
|
||||||||||||||||||||||||
Trading volume (thousands)
|
520,160 | 679,738 | ||||||||||||||||||||||
Share Price ($/share)
|
||||||||||||||||||||||||
High
|
$ | 57.20 | $ | 68.69 | $ | 76.91 | $ | 79.00 | $ | 79.00 | $ | 111.30 | ||||||||||||
Low
|
$ | 35.85 | $ | 47.70 | $ | 52.71 | $ | 65.97 | $ | 35.85 | $ | 34.19 | ||||||||||||
Close
|
$ | 48.91 | $ | 61.19 | $ | 72.30 | $ | 76.00 | $ | 76.00 | $ | 48.75 | ||||||||||||
Market capitalization as at December 31 ($ millions)
|
$ | 41,217 | $ | 26,373 | ||||||||||||||||||||
Shares outstanding (thousands)
|
542,327 | 540,991 | ||||||||||||||||||||||
NYSE – US$
|
||||||||||||||||||||||||
Trading volume (thousands)
|
757,307 | 967,228 | ||||||||||||||||||||||
Share Price ($/share)
|
||||||||||||||||||||||||
High
|
$ | 48.54 | $ | 63.46 | $ | 71.93 | $ | 76.51 | $ | 76.51 | $ | 109.32 | ||||||||||||
Low
|
$ | 27.69 | $ | 37.73 | $ | 45.03 | $ | 62.05 | $ | 27.69 | $ | 26.43 | ||||||||||||
Close
|
$ | 38.56 | $ | 52.49 | $ | 67.19 | $ | 71.95 | $ | 71.95 | $ | 39.98 | ||||||||||||
Market capitalization as at December 31 ($ millions)
|
$ | 39,020 | $ | 21,629 | ||||||||||||||||||||
Shares outstanding (thousands)
|
542,327 | 540,991 |
($ millions)
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
||||||
Product transportation and pipeline
|
$
|
207
|
$
|
162
|
$
|
136
|
$
|
125
|
$
|
126
|
$
|
1,051
|
Offshore equipment operating lease
|
$
|
155
|
$
|
124
|
$
|
103
|
$
|
102
|
$
|
101
|
$
|
261
|
Offshore drilling
|
$
|
49
|
$
|
–
|
$
|
–
|
$
|
–
|
$
|
–
|
$
|
–
|
Asset retirement obligations (1)
|
$
|
16
|
$
|
20
|
$
|
21
|
$
|
31
|
$
|
39
|
$
|
6,479
|
Long-term debt (2)
|
$
|
400
|
$
|
419
|
$
|
366
|
$
|
819
|
$
|
366
|
$
|
5,424
|
Interest expense (3)
|
$
|
473
|
$
|
451
|
$
|
415
|
$
|
370
|
$
|
350
|
$
|
4,779
|
Office leases
|
$
|
25
|
$
|
19
|
$
|
3
|
$
|
2
|
$
|
2
|
$
|
–
|
Other
|
$
|
271
|
$
|
67
|
$
|
23
|
$
|
15
|
$
|
12
|
$
|
34
|
(1)
|
Amounts represent management’s estimate of the future undiscounted payments to settle ARO related to resource properties, facilities, and production platforms, based on current legislation and industry operating practices. Amounts disclosed for the period 2010 – 2014 represent the minimum required expenditures to meet these obligations. Actual expenditures in any particular year may exceed these minimum amounts.
|
(2)
|
The long-term debt represents principal repayments only and does not reflect fair value adjustments, original issue discounts or transaction costs. No debt repayments are reflected for $1,897 million of revolving bank credit facilities due to the extendable nature of the facilities.
|
(3)
|
Interest expense amounts represent the scheduled fixed rate and variable rate cash payments related to long-term debt. Interest on variable rate long-term debt was estimated based upon prevailing interest rates as of December 31, 2009.
|
By:
|
/s/ Steve W. Laut
|
|
Name: | Steve W. Laut | |
Title: | President (Principal Executive Officer) |
Exhibit No.
|
Description
|
1.
|
Supplementary Oil & Gas Information for the fiscal year ended December 31, 2009.
|
2.
|
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934.
|
3.
|
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934.
|
4.
|
Certification of Chief Executive Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
|
5.
|
Certification of Chief Financial Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
|
6.
|
Consent of PricewaterhouseCoopers LLP, independent chartered accountants.
|
7.
|
Consent of Sproule Associates Limited, independent petroleum engineering consultants.
|
8.
|
Consent of GLJ Petroleum Consultants Ltd., independent petroleum engineering consultants.
|