For the fiscal year ended December 31, 2015
|
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))
|
2100, 855-2nd Street S.W., Calgary, Alberta, Canada, T2P 4J8
Telephone: (403) 517-7345
(Address and telephone number of Registrant’s principal executive offices) |
CT Corporation System, 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:
Common Shares, no par value
|
Name of each exchange on which registered:
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 |
3
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5
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7
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8
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9
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10
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11
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13
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13
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17
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47
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47
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47
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49
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50
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56
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56
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57
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57
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57
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57
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58
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59
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61
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63
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2 | Canadian Natural Resources Limited |
API
|
Specific gravity measured in degrees on the American Petroleum Institute scale
|
ARO
|
Asset retirement obligations
|
bbl
|
barrel
|
bbl/d
|
barrels per day
|
Bcf
|
billion cubic feet
|
BOE
|
barrels of oil equivalent
|
BOE/d
|
barrels of oil equivalent per day
|
“Canadian Natural Resources Limited”,
“Canadian Natural”, “Company”,
“Corporation”
|
Canadian Natural Resources Limited and includes, where applicable, reference to subsidiaries of and partnership interests held by Canadian Natural Resources Limited and its subsidiaries
|
CBM
|
Coal Bed Methane
|
CO2
|
Carbon dioxide
|
CO2e
|
Carbon dioxide equivalents
|
Crude oil, natural gas and NGLs
|
The Company’s light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, synthetic crude oil, bitumen (thermal oil), natural gas and natural gas liquids
|
CSS
|
Cyclic Steam Simulation
|
development well
|
Well drilled inside the established limits of an oil or gas reservoir or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive
|
dry well
|
Well that proves to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion
|
EOR
|
Enhanced Oil Recovery
|
exploratory well
|
Well that is not a development well, a service well, or a stratigraphic test well
|
extension well
|
Well that is drilled to test if a known reservoir extends beyond what had previously been believed to be the outer reservoir perimeter
|
fee title interest
|
Absolute ownership of legal title to mineral lands, subject to conditional interests that may have been granted from the title, such as petroleum and natural gas leases
|
FPSO
|
Floating Production, Storage and Offloading vessel
|
GHG
|
Greenhouse gas
|
gross acres
|
Total number of acres in which the Company has a working interest or fee title interest
|
gross wells
|
Total number of wells in which the Company has a working interest
|
Horizon
|
Horizon Oil Sands
|
IFRS
|
International Financial Reporting Standards
|
Mbbl
|
thousand barrels
|
Mcf
|
thousand cubic feet
|
Mcf/d
|
thousand cubic feet per day
|
MD&A
|
Management’s Discussion and Analysis
|
MMbbl
|
million barrels
|
MMBOE
|
million barrels of oil equivalent
|
MMBtu
|
million British thermal units
|
MMcf
|
million cubic feet
|
MMcf/d
|
million cubic feet per day
|
Canadian Natural Resources Limited | 3 |
MM$
|
million Canadian dollars
|
NGLs
|
Natural gas liquids
|
net acres
|
Gross acres multiplied by the percentage working interest or fee title interest therein owned
|
net asset value
|
Calculated as net present value, discounted at 10%, of the future net revenue (before income tax and excluding the ARO for development existing as at December 31, 2015) of the Company’s total proved plus probable crude oil, natural gas and NGLs reserves prepared using forecast prices and costs, plus the estimated market value of core unproved property, less net debt. Net debt is long term debt plus/minus the working capital deficit/surplus. Future development costs and abandonment and reclamation costs attributable to future development activity have been applied against the future net revenue
|
net wells
|
Gross wells multiplied by the percentage working interest therein owned by the Company
|
NYSE
|
New York Stock Exchange
|
productive well
|
Exploratory, development or extension well that is not dry
|
proved property
|
Property or part of a property to which reserves have been specifically attributed
|
PRT
|
Petroleum Revenue Tax
|
SAGD
|
Steam-Assisted Gravity Drainage
|
SCO
|
Synthetic crude oil
|
SEC
|
United States Securities and Exchange Commission
|
service well
|
Well drilled or completed for the purpose of supporting production in an existing field and drilled for the specific purposes of gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for combustion
|
stratigraphic test well
|
Drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition and ordinarily drilled without the intention of being completed for hydrocarbon production
|
TSX
|
Toronto Stock Exchange
|
UK
|
United Kingdom
|
unproved property
|
Property or part of a property to which no reserves have been specifically attributed
|
US
|
United States
|
working interest
|
Interest held by the Company in a crude oil or natural gas property, which interest normally bears its proportionate share of the costs of exploration, development, and operation as well as any royalties or other production burdens
|
WTI
|
West Texas Intermediate reference location at Cushing, Oklahoma
|
4 | Canadian Natural Resources Limited |
Canadian Natural Resources Limited | 5 |
6 | Canadian Natural Resources Limited |
October 1, 2000 - Ranger Oil Limited (“Ranger”)
|
January 1, 2003 - Rio Alto Exploration Ltd. (“RAX”)
|
January 1, 2004 - CanNat Resources Inc.
|
January 1, 2007 - ACC-CNR Resources Corporation
|
January 1, 2008 - Ranger Oil (International) Ltd.; 764968 Alberta Inc.; CNR International (Norway) Limited; Renata Resources Inc.
|
January 1, 2012 - Aspect Energy Ltd.; Creo Energy Ltd.; 1585024 Alberta Ltd.
|
January 1, 2014 - Barrick Energy Inc.
|
January 1, 2015 - EOG Resources Canada Inc.
|
Jurisdiction of Incorporation
|
% Ownership
|
||||
Subsidiary
|
|||||
Canadian Natural Upgrading Limited
|
Alberta
|
100
|
|||
CanNat Energy Inc.
|
Delaware
|
100
|
|||
CNR (ECHO) Resources Inc.
|
Alberta
|
100
|
|||
CNR International (U.K.) Investments Limited
|
England
|
100
|
|||
CNR International (U.K.) Limited
|
England
|
100
|
|||
CNR International (Côte d’Ivoire) SARL
|
Côte d’Ivoire
|
100
|
|||
CNR International (Olowi) Limited
|
Bahamas
|
100
|
|||
CNR International (South Africa) Limited
|
Alberta
|
100
|
|||
Horizon Construction Management Ltd.
|
Alberta
|
100
|
|||
Partnership
|
|||||
Canadian Natural Resources
|
Alberta
|
100
|
|||
Canadian Natural Resources Northern Alberta Partnership
|
Alberta
|
100
|
|||
Canadian Natural Resources 2005 Partnership
|
Alberta
|
100
|
Canadian Natural Resources Limited | 7 |
8 | Canadian Natural Resources Limited |
Canadian Natural Resources Limited | 9 |
North America, Exploration and Production
|
4,513
|
|||
North America, Oil Sands Mining and Upgrading
|
2,651
|
|||
North Sea
|
372
|
|||
Offshore Africa
|
32
|
|||
Total Company
|
7,568
|
10 | Canadian Natural Resources Limited |
Canadian Natural Resources Limited | 11 |
12 | Canadian Natural Resources Limited |
Canadian Natural Resources Limited | 13 |
14 | Canadian Natural Resources Limited |
Canadian Natural Resources Limited | 15 |
16 | Canadian Natural Resources Limited |
Canadian Natural Resources Limited | 17 |
Light and
Medium
Crude Oil
(MMbbl)
|
Primary
Heavy
Crude Oil
(MMbbl)
|
Pelican Lake
Heavy
Crude Oil (MMbbl)
|
Bitumen
(Thermal Oil)
(MMbbl)
|
Synthetic
Crude Oil
(MMbbl)
|
Natural Gas
(Bcf)
|
Natural Gas
Liquids
(MMbbl)
|
Barrels of Oil
Equivalent
(MMBOE)
|
|||||||||||||||||||||||||
North America
|
||||||||||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||||||||||
Developed Producing
|
102
|
112
|
222
|
351
|
2,283
|
3,848
|
99
|
3,810
|
||||||||||||||||||||||||
Developed Non-Producing
|
8
|
20
|
4
|
-
|
-
|
270
|
6
|
83
|
||||||||||||||||||||||||
Undeveloped
|
28
|
81
|
42
|
874
|
125
|
1,920
|
90
|
1,560
|
||||||||||||||||||||||||
Total Proved
|
138
|
213
|
268
|
1,225
|
2,408
|
6,038
|
195
|
5,453
|
||||||||||||||||||||||||
Probable
|
54
|
81
|
120
|
1,182
|
1,225
|
2,300
|
88
|
3,134
|
||||||||||||||||||||||||
Total Proved plus Probable
|
192
|
294
|
388
|
2,407
|
3,633
|
8,338
|
283
|
8,587
|
||||||||||||||||||||||||
North Sea
|
||||||||||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||||||||||
Developed Producing
|
3
|
26
|
7
|
|||||||||||||||||||||||||||||
Developed Non-Producing
|
21
|
9
|
23
|
|||||||||||||||||||||||||||||
Undeveloped
|
134
|
4
|
135
|
|||||||||||||||||||||||||||||
Total Proved
|
158
|
39
|
165
|
|||||||||||||||||||||||||||||
Probable
|
126
|
57
|
135
|
|||||||||||||||||||||||||||||
Total Proved plus Probable
|
284
|
96
|
300
|
|||||||||||||||||||||||||||||
Offshore Africa
|
||||||||||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||||||||||
Developed Producing
|
50
|
22
|
54
|
|||||||||||||||||||||||||||||
Developed Non-Producing
|
1
|
-
|
1
|
|||||||||||||||||||||||||||||
Undeveloped
|
39
|
7
|
40
|
|||||||||||||||||||||||||||||
Total Proved
|
90
|
29
|
95
|
|||||||||||||||||||||||||||||
Probable
|
52
|
45
|
59
|
|||||||||||||||||||||||||||||
Total Proved plus Probable
|
142
|
74
|
154
|
|||||||||||||||||||||||||||||
Total Company
|
||||||||||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||||||||||
Developed Producing
|
155
|
112
|
222
|
351
|
2,283
|
3,896
|
99
|
3,871
|
||||||||||||||||||||||||
Developed Non-Producing
|
30
|
20
|
4
|
-
|
-
|
279
|
6
|
107
|
||||||||||||||||||||||||
Undeveloped
|
201
|
81
|
42
|
874
|
125
|
1,931
|
90
|
1,735
|
||||||||||||||||||||||||
Total Proved
|
386
|
213
|
268
|
1,225
|
2,408
|
6,106
|
195
|
5,713
|
||||||||||||||||||||||||
Probable
|
232
|
81
|
120
|
1,182
|
1,225
|
2,402
|
88
|
3,328
|
||||||||||||||||||||||||
Total Proved plus Probable
|
618
|
294
|
388
|
2,407
|
3,633
|
8,508
|
283
|
9,041
|
18 | Canadian Natural Resources Limited |
Light and
Medium
Crude Oil
(MMbbl)
|
Primary
Heavy
Crude Oil
(MMbbl)
|
Pelican Lake
Heavy
Crude Oil (MMbbl)
|
Bitumen
(Thermal Oil)
(MMbbl)
|
Synthetic
Crude Oil
(MMbbl)
|
Natural Gas
(Bcf)
|
Natural Gas
Liquids
(MMbbl)
|
Barrels of Oil
Equivalent
(MMBOE)
|
|||||||||||||||||||||||||
North America
|
||||||||||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||||||||||
Developed Producing
|
90
|
96
|
168
|
276
|
1,926
|
3,495
|
73
|
3,211
|
||||||||||||||||||||||||
Developed Non-Producing
|
7
|
16
|
3
|
-
|
-
|
239
|
5
|
71
|
||||||||||||||||||||||||
Undeveloped
|
25
|
69
|
33
|
700
|
87
|
1,649
|
71
|
1,260
|
||||||||||||||||||||||||
Total Proved
|
122
|
181
|
204
|
976
|
2,013
|
5,383
|
149
|
4,542
|
||||||||||||||||||||||||
Probable
|
45
|
66
|
82
|
908
|
993
|
1,978
|
67
|
2,491
|
||||||||||||||||||||||||
Total Proved plus Probable
|
167
|
247
|
286
|
1,884
|
3,006
|
7,361
|
216
|
7,033
|
||||||||||||||||||||||||
North Sea
|
||||||||||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||||||||||
Developed Producing
|
3
|
26
|
7
|
|||||||||||||||||||||||||||||
Developed Non-Producing
|
21
|
9
|
22
|
|||||||||||||||||||||||||||||
Undeveloped
|
134
|
4
|
135
|
|||||||||||||||||||||||||||||
Total Proved
|
158
|
39
|
164
|
|||||||||||||||||||||||||||||
Probable
|
126
|
57
|
136
|
|||||||||||||||||||||||||||||
Total Proved plus Probable
|
284
|
96
|
300
|
|||||||||||||||||||||||||||||
Offshore Africa
|
||||||||||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||||||||||
Developed Producing
|
43
|
15
|
46
|
|||||||||||||||||||||||||||||
Developed Non-Producing
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Undeveloped
|
31
|
6
|
32
|
|||||||||||||||||||||||||||||
Total Proved
|
74
|
21
|
78
|
|||||||||||||||||||||||||||||
Probable
|
39
|
29
|
43
|
|||||||||||||||||||||||||||||
Total Proved plus Probable
|
113
|
50
|
121
|
|||||||||||||||||||||||||||||
Total Company
|
||||||||||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||||||||||
Developed Producing
|
136
|
96
|
168
|
276
|
1,926
|
3,536
|
73
|
3,264
|
||||||||||||||||||||||||
Developed Non-Producing
|
28
|
16
|
3
|
-
|
-
|
248
|
5
|
93
|
||||||||||||||||||||||||
Undeveloped
|
190
|
69
|
33
|
700
|
87
|
1,659
|
71
|
1,427
|
||||||||||||||||||||||||
Total Proved
|
354
|
181
|
204
|
976
|
2,013
|
5,443
|
149
|
4,784
|
||||||||||||||||||||||||
Probable
|
210
|
66
|
82
|
908
|
993
|
2,064
|
67
|
2,670
|
||||||||||||||||||||||||
Total Proved plus Probable
|
564
|
247
|
286
|
1,884
|
3,006
|
7,507
|
216
|
7,454
|
Canadian Natural Resources Limited | 19 |
1. | “Company gross reserves” are Canadian Natural’s working interest share of reserves before deduction of royalties and without including any royalty interests of the Company. |
2. | “Company net reserves” are the company gross reserves less all royalties payable to others plus royalties receivable from others. |
3. | References to “light and medium crude oil” means “light crude oil and medium crude oil combined”. |
4. | “Reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as at a given date, based on analysis of drilling, geological, geophysical, and engineering data, with the use of established technology and under specified economic conditions which are generally accepted as being reasonable. |
— | “Proved reserves” are those reserves which can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
— | “Probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
— | “Developed reserves” are reserves that are expected to be recovered from (i) existing wells and installed facilities or, if the facilities have not been installed, that would involve a low expenditure (compared to the cost of drilling a well) to put the reserves on production, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. The developed category may be subdivided into producing and non-producing. |
— | “Undeveloped reserves” are reserves that are expected to be recovered from known accumulations with new wells on undrilled acreage, or from existing wells where significant expenditures are required for the completion of these wells or for the installation of processing and gathering facilities prior to the production of these reserves. Reserves on undrilled acreage are limited to those drilling units directly offsetting development spacing areas that are reasonably certain of production when drilled unless reliable technology exists that establishes reasonable certainty of economic producibilty at greater distances. |
5. | The reserve evaluation involved data supplied by the Company with respect to geological and engineering data, adjustments for product quality, heating value and transportation, interests owned, royalties payable, production costs, capital costs and contractual commitments. This data was found by the IQRE to be reasonable. |
6. | Amendments to NI 51-101 effective July 1, 2015 included changes to the definition of natural gas. Natural gas reserves disclosure is consistent with the prior year. |
7. | BOE values as presented may not calculate due to rounding. |
20 | Canadian Natural Resources Limited |
MM$
|
Discount @ 0%
|
Discount @ 5%
|
Discount @ 10%
|
Discount @ 15%
|
Discount @ 20%
|
Unit Value
Discounted at
10%/year
$/BOE (1) |
||||||||||||||||||
North America
|
||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||
Developed Producing
|
140,590
|
58,766
|
36,051
|
26,450
|
21,124
|
11.23
|
||||||||||||||||||
Developed Non-Producing
|
1,592
|
1,214
|
953
|
773
|
644
|
13.42
|
||||||||||||||||||
Undeveloped
|
39,900
|
38,964
|
24,741
|
15,630
|
10,245
|
19.64
|
||||||||||||||||||
Total Proved
|
182,082
|
98,944
|
61,745
|
42,853
|
32,013
|
13.59
|
||||||||||||||||||
Probable
|
152,865
|
45,391
|
19,341
|
10,843
|
7,195
|
7.76
|
||||||||||||||||||
Total Proved plus Probable
|
334,947
|
144,335
|
81,086
|
53,696
|
39,208
|
11.53
|
||||||||||||||||||
North Sea
|
||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||
Developed Producing
|
(985
|
)
|
(289
|
)
|
(79
|
)
|
(7
|
)
|
23
|
(11.29
|
)
|
|||||||||||||
Developed Non-Producing
|
(164
|
)
|
(143
|
)
|
(128
|
)
|
(118
|
)
|
(109
|
)
|
(5.82
|
)
|
||||||||||||
Undeveloped
|
3,884
|
2,648
|
1,790
|
1,218
|
833
|
13.26
|
||||||||||||||||||
Total Proved
|
2,735
|
2,216
|
1,583
|
1,093
|
747
|
9.65
|
||||||||||||||||||
Probable
|
8,995
|
5,085
|
3,114
|
2,049
|
1,432
|
22.90
|
||||||||||||||||||
Total Proved plus Probable
|
11,730
|
7,301
|
4,697
|
3,142
|
2,179
|
15.66
|
||||||||||||||||||
Offshore Africa
|
||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||
Developed Producing
|
1,399
|
1,224
|
1,049
|
906
|
794
|
22.80
|
||||||||||||||||||
Developed Non-Producing
|
24
|
18
|
14
|
12
|
9
|
-
|
||||||||||||||||||
Undeveloped
|
1,912
|
1,224
|
852
|
632
|
492
|
26.63
|
||||||||||||||||||
Total Proved
|
3,335
|
2,466
|
1,915
|
1,550
|
1,295
|
24.55
|
||||||||||||||||||
Probable
|
3,361
|
2,019
|
1,329
|
938
|
699
|
30.91
|
||||||||||||||||||
Total Proved plus Probable
|
6,696
|
4,485
|
3,244
|
2,488
|
1,994
|
26.81
|
||||||||||||||||||
Total Company
|
||||||||||||||||||||||||
Proved
|
||||||||||||||||||||||||
Developed Producing
|
141,004
|
59,701
|
37,021
|
27,349
|
21,941
|
11.34
|
||||||||||||||||||
Developed Non-Producing
|
1,452
|
1,089
|
839
|
667
|
544
|
9.02
|
||||||||||||||||||
Undeveloped
|
45,696
|
42,836
|
27,383
|
17,480
|
11,570
|
19.19
|
||||||||||||||||||
Total Proved
|
188,152
|
103,626
|
65,243
|
45,496
|
34,055
|
13.64
|
||||||||||||||||||
Probable
|
165,221
|
52,495
|
23,784
|
13,830
|
9,326
|
8.91
|
||||||||||||||||||
Total Proved plus Probable
|
353,373
|
156,121
|
89,027
|
59,326
|
43,381
|
11.94
|
(1)
|
Unit values are based on company net reserves.
|
Canadian Natural Resources Limited | 21 |
MM$
|
Discount @ 0%
|
Discount @ 5%
|
Discount @ 10%
|
Discount @ 15%
|
Discount @ 20%
|
|||||||||||||||
North America
|
||||||||||||||||||||
Proved
|
||||||||||||||||||||
Developed Producing
|
105,376
|
46,041
|
29,102
|
21,764
|
17,617
|
|||||||||||||||
Developed Non-Producing
|
1,150
|
879
|
688
|
556
|
461
|
|||||||||||||||
Undeveloped
|
28,456
|
27,753
|
17,256
|
10,554
|
6,614
|
|||||||||||||||
Total Proved
|
134,982
|
74,673
|
47,046
|
32,874
|
24,692
|
|||||||||||||||
Probable
|
112,574
|
33,130
|
13,992
|
7,782
|
5,129
|
|||||||||||||||
Total Proved plus Probable
|
247,556
|
107,803
|
61,038
|
40,656
|
29,821
|
|||||||||||||||
North Sea
|
||||||||||||||||||||
Proved
|
||||||||||||||||||||
Developed Producing
|
(987
|
)
|
(296
|
)
|
(90
|
)
|
(20
|
)
|
8
|
|||||||||||
Developed Non-Producing
|
(195
|
)
|
(170
|
)
|
(152
|
)
|
(139
|
)
|
(128
|
)
|
||||||||||
Undeveloped
|
2,883
|
1,691
|
1,055
|
676
|
433
|
|||||||||||||||
Total Proved
|
1,701
|
1,225
|
813
|
517
|
313
|
|||||||||||||||
Probable
|
4,256
|
2,426
|
1,528
|
1,045
|
763
|
|||||||||||||||
Total Proved plus Probable
|
5,957
|
3,651
|
2,341
|
1,562
|
1,076
|
|||||||||||||||
Offshore Africa
|
||||||||||||||||||||
Proved
|
||||||||||||||||||||
Developed Producing
|
1,019
|
925
|
805
|
701
|
618
|
|||||||||||||||
Developed Non-Producing
|
19
|
14
|
11
|
9
|
7
|
|||||||||||||||
Undeveloped
|
1,445
|
933
|
655
|
491
|
385
|
|||||||||||||||
Total Proved
|
2,483
|
1,872
|
1,471
|
1,201
|
1,010
|
|||||||||||||||
Probable
|
2,513
|
1,522
|
1,010
|
717
|
538
|
|||||||||||||||
Total Proved plus Probable
|
4,996
|
3,394
|
2,481
|
1,918
|
1,548
|
|||||||||||||||
Total Company
|
||||||||||||||||||||
Proved
|
||||||||||||||||||||
Developed Producing
|
105,408
|
46,670
|
29,817
|
22,445
|
18,243
|
|||||||||||||||
Developed Non-Producing
|
974
|
723
|
547
|
426
|
340
|
|||||||||||||||
Undeveloped
|
32,784
|
30,377
|
18,966
|
11,721
|
7,432
|
|||||||||||||||
Total Proved
|
139,166
|
77,770
|
49,330
|
34,592
|
26,015
|
|||||||||||||||
Probable
|
119,343
|
37,078
|
16,530
|
9,544
|
6,430
|
|||||||||||||||
Total Proved plus Probable
|
258,509
|
114,848
|
65,860
|
44,136
|
32,445
|
(1)
|
After-tax net present values consider the Company’s existing tax pool balances and current tax regulations and do not represent an estimate of the value at the consolidated entity level, which may be significantly different. For information at the consolidated entity level, refer to the Company’s Consolidated Financial Statements and the Management’s Discussion and Analysis for the year ended December 31, 2015.
|
22 | Canadian Natural Resources Limited |
North America
|
North Sea
|
Offshore Africa
|
Total
|
|||||||||||||||||||||||||||||
MM$
|
Proved
|
Proved plus Probable
|
Proved
|
Proved plus Probable
|
Proved
|
Proved plus Probable
|
Proved
|
Proved plus Probable
|
||||||||||||||||||||||||
Revenue
|
451,421
|
785,008
|
18,185
|
33,814
|
6,891
|
10,960
|
476,497
|
829,782
|
||||||||||||||||||||||||
Royalties
|
79,276
|
147,943
|
37
|
57
|
236
|
402
|
79,549
|
148,402
|
||||||||||||||||||||||||
Production Costs
|
136,945
|
229,930
|
9,315
|
14,039
|
2,322
|
2,566
|
148,582
|
246,535
|
||||||||||||||||||||||||
Development Costs
|
43,911
|
61,640
|
4,050
|
5,324
|
758
|
1,027
|
48,719
|
67,991
|
||||||||||||||||||||||||
Abandonment and Reclamation
Costs – Future Development(1)
|
573
|
892
|
16
|
193
|
19
|
48
|
608
|
1,133
|
||||||||||||||||||||||||
Abandonment and Reclamation
Costs – Existing Development(1)
|
8,634
|
9,656
|
2,032
|
2,471
|
221
|
221
|
10,887
|
12,348
|
||||||||||||||||||||||||
Future Net Revenue
Before Income Taxes
|
182,082
|
334,947
|
2,735
|
11,730
|
3,335
|
6,696
|
188,152
|
353,373
|
||||||||||||||||||||||||
Income Taxes
|
47,100
|
87,391
|
1,034
|
5,773
|
852
|
1,700
|
48,986
|
94,864
|
||||||||||||||||||||||||
Future Net Revenue
After Income Taxes (2) |
134,982
|
247,556
|
1,701
|
5,957
|
2,483
|
4,996
|
139,166
|
258,509
|
(1)
|
Due to amendments to NI 51-101 effective July 1, 2015, abandonment and reclamation costs included in the calculation of the future net revenue for 2015 consist of both forecast estimates of abandonment and reclamation costs attributable to future development activity, as well as certain costs already included in the Company’s ARO for development existing as at December 31, 2015. The Company’s estimated ARO at December 31, 2015 was $1,415 million, discounted at 10% (unescalated and undiscounted ARO at December 31, 2015 was $12,137 million). Approximately $8,188 million of this unescalated and undiscounted amount was also included in the future net revenue and is escalated at 1.5% per year. Specifically, for North America (excluding SCO assets), future net revenue includes the costs associated with abandonment and reclamation of wells (wells, well sites, wellsite equipment and pipelines) with assigned reserves. For SCO assets, future net revenue includes the costs associated with the abandonment and reclamation of the mine site and all mining and upgrading facilities. For North Sea and Offshore Africa, future net revenue includes the costs associated with the abandonment and reclamation of offshore wells and facilities with assigned reserves.
|
(2) | Future net revenue is prior to provision for interest, general and administrative expenses and the impact of any risk management activities. |
Canadian Natural Resources Limited | 23 |
Future Net Revenue By Product Type (1) (2)
|
|||||||||
Reserves
Category
|
Production Group
|
Future Net Revenue
Before Income Taxes (discounted at 10%/year) (MM$) |
Unit Value
($/BOE) |
||||||
Proved
Reserves
|
Light and Medium Crude Oil
(including solution gas and other by-products) |
6,924
|
16.43
|
||||||
Primary Heavy Crude Oil
(including solution gas) |
3,109
|
16.99
|
|||||||
Pelican Lake Heavy Crude Oil
(including solution gas) |
3,650
|
17.84
|
|||||||
Bitumen (Thermal Oil)
|
13,806
|
14.14
|
|||||||
Synthetic Crude Oil
|
33,009
|
16.40
|
|||||||
Natural Gas
(including by-products but excluding solution gas and by-products from oil wells) |
5,416
|
5.49
|
|||||||
Abandonment and Reclamation Costs – Existing
Development
|
(671
|
)
|
- | ||||||
Total
|
65,243
|
13.64 | |||||||
Proved Plus
Probable Reserves
|
Light and Medium Crude Oil
(including solution gas and other by-products) |
12,445
|
18.51
|
||||||
Primary Heavy Crude Oil (including solution gas) |
4,619
|
18.47
|
|||||||
Pelican Lake Heavy Crude Oil
(including solution gas) |
4,923
|
17.15
|
|||||||
Bitumen (Thermal Oil)
|
19,875 | 10.55 | |||||||
Synthetic Crude Oil
|
40,230 | 13.38 | |||||||
Natural Gas
(including by-products but excluding solution gas and by-products from oil wells) |
7,725
|
5.70
|
|||||||
Abandonment and Reclamation Costs – Existing
Development
|
(790 |
)
|
- | ||||||
Total
|
89,027 | 11.94 |
(1) | Unit values are based on company net reserves. |
(2) | The net present values of the future net revenue for each product type includes the forecast estimates of abandonment and reclamation costs attributable to future development activity. The net present value of the future net revenue for the “Abandonment and Reclamation Costs – Existing Development” contains certain costs already included in the Company’s ARO for development existing as at December 31, 2015, which are not applied at the product type level. |
24 | Canadian Natural Resources Limited |
2016
|
2017
|
2018
|
2019
|
2020
|
Average
annual
increase
thereafter
|
|||||||||||||||||||
Crude Oil and NGLs
|
||||||||||||||||||||||||
WTI(1) (US$/bbl)
|
$
|
45.00
|
$
|
60.00
|
$
|
70.00
|
$
|
80.00
|
$
|
81.20
|
1.50
|
%
|
||||||||||||
WCS(2) (C$/bbl)
|
$
|
45.26
|
$
|
57.96
|
$
|
65.88
|
$
|
75.11
|
$
|
77.03
|
1.50
|
%
|
||||||||||||
Canadian Light Sweet(3) (C$/bbl)
|
$
|
55.20
|
$
|
69.00
|
$
|
78.43
|
$
|
89.41
|
$
|
91.71
|
1.50
|
%
|
||||||||||||
Cromer LSB(4) (C$/bbl)
|
$
|
54.20
|
$
|
68.00
|
$
|
77.43
|
$
|
88.41
|
$
|
90.71
|
1.50
|
%
|
||||||||||||
Edmonton C5+(5) (C$/bbl)
|
$
|
59.10
|
$
|
73.88
|
$
|
83.98
|
$
|
95.73
|
$
|
98.19
|
1.50
|
%
|
||||||||||||
North Sea Brent(6) (US$/bbl)
|
$
|
45.00
|
$
|
60.00
|
$
|
70.00
|
$
|
80.00
|
$
|
81.20
|
1.50
|
%
|
||||||||||||
Natural Gas
|
||||||||||||||||||||||||
AECO(7) (C$/MMBtu)
|
$
|
2.25
|
$
|
2.95
|
$
|
3.42
|
$
|
3.91
|
$
|
4.20
|
1.50
|
%
|
||||||||||||
BC Westcoast Station 2(8) (C$/MMBtu)
|
$
|
1.45
|
$
|
2.55
|
$
|
3.02
|
$
|
3.51
|
$
|
3.80
|
1.50
|
%
|
||||||||||||
Henry Hub(9) (US$/MMBtu)
|
$
|
2.25
|
$
|
3.00
|
$
|
3.50
|
$
|
4.00
|
$
|
4.25
|
1.50
|
%
|
(1) | "WTI” refers to the price of West Texas Intermediate crude oil at Cushing, Oklahoma. |
(2) | “WCS” refers to Western Canadian Select, a blend of heavy crude oils and bitumen with sweet synthetic and condensate diluents at Hardisty, Alberta; reference price used in the preparation of primary heavy crude oil, Pelican Lake heavy crude oil and bitumen (thermal oil) reserves. |
(3) | “Canadian Light Sweet” refers to the price of light gravity (40˚ API), low sulphur content Mixed Sweet Blend (MSW) crude oil at Edmonton, Alberta; reference price used in the preparation of light and medium crude oil and SCO reserves. |
(4) | "Cromer LSB” refers to the price of light sour blend (35˚ API) physical crude oil at Cromer, Manitoba; reference price used in the preparation of light and medium crude oil in SE Saskatchewan and SW Manitoba reserves. |
(5) | “Edmonton C5+” refers to pentanes plus at Edmonton, Alberta; reference price used in the preparation of NGLs reserves; also used in determining the diluent costs associated with primary heavy crude oil and bitumen (thermal oil) reserves. |
(6) | “North Sea Brent” refers to the benchmark price for European, African and Middle Eastern crude oil; reference price used in the preparation of North Sea and Offshore Africa light crude oil reserves. |
(7) | “AECO” refers to the Alberta natural gas trading price at the AECO-C hub in southeast Alberta; reference price used in the preparation of North America (excluding British Columbia) natural gas reserves. |
(8) | “BC Westcoast Station 2” refers to the natural gas delivery point on the Spectra Energy system at Chetwynd, British Columbia; reference price used in the preparation of British Columbia natural gas reserves. |
(9) | “Henry Hub” refers to a distribution hub on the natural gas pipeline system in Erath, Louisiana and is the pricing point for natural gas futures on the New York Mercantile Exchange. |
Canadian Natural Resources Limited | 25 |
PROVED
|
||||||||||||||||||||||||||||||||
North America
|
Light and
Medium
Crude Oil
(MMbbl)
|
Primary
Heavy
Crude Oil
(MMbbl)
|
Pelican Lake
Heavy
Crude Oil (MMbbl)
|
Bitumen
(Thermal Oil)
(MMbbl)
|
Synthetic
Crude Oil
(MMbbl)
|
Natural Gas
(Bcf)
|
Natural Gas
Liquids
(MMbbl)
|
Barrels of Oil
Equivalent
(MMBOE)
|
||||||||||||||||||||||||
December 31, 2014
|
145
|
229
|
274
|
1,217
|
2,158
|
5,869
|
188
|
5,189
|
||||||||||||||||||||||||
Discoveries
|
1
|
-
|
-
|
-
|
-
|
14
|
2
|
5
|
||||||||||||||||||||||||
Extensions
|
1
|
4
|
-
|
23
|
220
|
252
|
10
|
300
|
||||||||||||||||||||||||
Infill Drilling
|
4
|
10
|
-
|
-
|
-
|
298
|
7
|
71
|
||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
2
|
26
|
-
|
-
|
-
|
28
|
||||||||||||||||||||||||
Acquisitions
|
5
|
4
|
-
|
7
|
-
|
414
|
8
|
93
|
||||||||||||||||||||||||
Dispositions
|
(3
|
)
|
-
|
-
|
-
|
-
|
(7
|
)
|
-
|
(4
|
)
|
|||||||||||||||||||||
Economic Factors
|
(6
|
)
|
(3
|
)
|
-
|
-
|
7
|
(385
|
)
|
(6
|
)
|
(72
|
)
|
|||||||||||||||||||
Technical Revisions
|
10
|
16
|
10
|
(1
|
)
|
68
|
190
|
1
|
135
|
|||||||||||||||||||||||
Production
|
(19
|
)
|
(47
|
)
|
(18
|
)
|
(47
|
)
|
(45
|
)
|
(607
|
)
|
(15
|
)
|
(292
|
)
|
||||||||||||||||
December 31, 2015
|
138
|
213
|
268
|
1,225
|
2,408
|
6,038
|
195
|
5,453
|
||||||||||||||||||||||||
North Sea
|
||||||||||||||||||||||||||||||||
December 31, 2014
|
204
|
83
|
218
|
|||||||||||||||||||||||||||||
Discoveries
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Extensions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Infill Drilling
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Acquisitions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Dispositions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Economic Factors
|
(2
|
)
|
(7
|
)
|
(3
|
)
|
||||||||||||||||||||||||||
Technical Revisions
|
(36
|
)
|
(24
|
)
|
(40
|
)
|
||||||||||||||||||||||||||
Production
|
(8
|
)
|
(13
|
)
|
(10
|
)
|
||||||||||||||||||||||||||
December 31, 2015
|
158
|
39
|
165
|
|||||||||||||||||||||||||||||
Offshore Africa
|
||||||||||||||||||||||||||||||||
December 31, 2014
|
96
|
49
|
104
|
|||||||||||||||||||||||||||||
Discoveries
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Extensions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Infill Drilling
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Acquisitions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Dispositions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Economic Factors
|
1
|
-
|
1
|
|||||||||||||||||||||||||||||
Technical Revisions
|
-
|
(10
|
)
|
(1
|
)
|
|||||||||||||||||||||||||||
Production
|
(7
|
)
|
(10
|
)
|
(9
|
)
|
||||||||||||||||||||||||||
December 31, 2015
|
90
|
29
|
95
|
|||||||||||||||||||||||||||||
Total Company
|
||||||||||||||||||||||||||||||||
December 31, 2014
|
445
|
229
|
274
|
1,217
|
2,158
|
6,001
|
188
|
5,511
|
||||||||||||||||||||||||
Discoveries
|
1
|
-
|
-
|
-
|
-
|
14
|
2
|
5
|
||||||||||||||||||||||||
Extensions
|
1
|
4
|
-
|
23
|
220
|
252
|
10
|
300
|
||||||||||||||||||||||||
Infill Drilling
|
4
|
10
|
-
|
-
|
-
|
298
|
7
|
71
|
||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
2
|
26
|
-
|
-
|
-
|
28
|
||||||||||||||||||||||||
Acquisitions
|
5
|
4
|
-
|
7
|
-
|
414
|
8
|
93
|
||||||||||||||||||||||||
Dispositions
|
(3
|
)
|
-
|
-
|
-
|
-
|
(7
|
)
|
-
|
(4
|
)
|
|||||||||||||||||||||
Economic Factors
|
(7
|
)
|
(3
|
)
|
-
|
-
|
7
|
(392
|
)
|
(6
|
)
|
(74
|
)
|
|||||||||||||||||||
Technical Revisions
|
(26
|
)
|
16
|
10
|
(1
|
)
|
68
|
156
|
1
|
94
|
||||||||||||||||||||||
Production
|
(34
|
)
|
(47
|
)
|
(18
|
)
|
(47
|
)
|
(45
|
)
|
(630
|
)
|
(15
|
)
|
(311
|
)
|
||||||||||||||||
December 31, 2015
|
386
|
213
|
268
|
1,225
|
2,408
|
6,106
|
195
|
5,713
|
26 | Canadian Natural Resources Limited |
PROBABLE
|
||||||||||||||||||||||||||||||||
North America
|
Light and
Medium
Crude Oil
(MMbbl)
|
Primary
Heavy
Crude Oil (MMbbl)
|
Pelican Lake
Heavy
Crude Oil
(MMbbl)
|
Bitumen
(Thermal Oil)
(MMbbl)
|
Synthetic
Crude Oil
(MMbbl)
|
Natural Gas
(Bcf)
|
Natural Gas
Liquids
(MMbbl)
|
Barrels of Oil
Equivalent
(MMBOE)
|
||||||||||||||||||||||||
December 31, 2014
|
58
|
88
|
121
|
1,095
|
1,435
|
2,057
|
70
|
3,210
|
||||||||||||||||||||||||
Discoveries
|
-
|
-
|
-
|
-
|
-
|
3
|
-
|
1
|
||||||||||||||||||||||||
Extensions
|
1
|
2
|
-
|
88
|
(175
|
)
|
106
|
5
|
(61
|
)
|
||||||||||||||||||||||
Infill Drilling
|
4
|
3
|
-
|
-
|
-
|
444
|
22
|
103
|
||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
1
|
14
|
-
|
1
|
-
|
15
|
||||||||||||||||||||||||
Acquisitions
|
1
|
1
|
-
|
2
|
-
|
101
|
2
|
23
|
||||||||||||||||||||||||
Dispositions
|
(2
|
)
|
-
|
-
|
-
|
-
|
(2
|
)
|
-
|
(3
|
)
|
|||||||||||||||||||||
Economic Factors
|
-
|
-
|
-
|
-
|
-
|
(117
|
)
|
(2
|
)
|
(22
|
)
|
|||||||||||||||||||||
Technical Revisions
|
(8
|
)
|
(13
|
)
|
(2
|
)
|
(17
|
)
|
(35
|
)
|
(293
|
)
|
(9
|
)
|
(132
|
)
|
||||||||||||||||
Production
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||||||||
December 31, 2015
|
54
|
81
|
120
|
1,182
|
1,225
|
2,300
|
88
|
3,134
|
||||||||||||||||||||||||
North Sea
|
||||||||||||||||||||||||||||||||
December 31, 2014
|
104
|
31
|
109
|
|||||||||||||||||||||||||||||
Discoveries
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Extensions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Infill Drilling
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Acquisitions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Dispositions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Economic Factors
|
-
|
7
|
1
|
|||||||||||||||||||||||||||||
Technical Revisions
|
22
|
19
|
25
|
|||||||||||||||||||||||||||||
Production
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
December 31, 2015
|
126
|
57
|
135
|
|||||||||||||||||||||||||||||
Offshore Africa
|
||||||||||||||||||||||||||||||||
December 31, 2014
|
53
|
49
|
61
|
|||||||||||||||||||||||||||||
Discoveries
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Extensions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Infill Drilling
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Acquisitions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Dispositions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Economic Factors
|
(1
|
)
|
1
|
(1
|
)
|
|||||||||||||||||||||||||||
Technical Revisions
|
-
|
(5
|
)
|
(1
|
)
|
|||||||||||||||||||||||||||
Production
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
December 31, 2015
|
52
|
45
|
59
|
|||||||||||||||||||||||||||||
Total Company
|
||||||||||||||||||||||||||||||||
December 31, 2014
|
215
|
88
|
121
|
1,095
|
1,435
|
2,137
|
70
|
3,380
|
||||||||||||||||||||||||
Discoveries
|
-
|
-
|
-
|
-
|
-
|
3
|
-
|
1
|
||||||||||||||||||||||||
Extensions
|
1
|
2
|
-
|
88
|
(175
|
)
|
106
|
5
|
(61
|
)
|
||||||||||||||||||||||
Infill Drilling
|
4
|
3
|
-
|
-
|
-
|
444
|
22
|
103
|
||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
1
|
14
|
-
|
1
|
-
|
15
|
||||||||||||||||||||||||
Acquisitions
|
1
|
1
|
-
|
2
|
-
|
101
|
2
|
23
|
||||||||||||||||||||||||
Dispositions
|
(2
|
)
|
-
|
-
|
-
|
-
|
(2
|
)
|
-
|
(3
|
)
|
|||||||||||||||||||||
Economic Factors
|
(1
|
)
|
-
|
-
|
-
|
-
|
(109
|
)
|
(2
|
)
|
(22
|
)
|
||||||||||||||||||||
Technical Revisions
|
14
|
(13
|
)
|
(2
|
)
|
(17
|
)
|
(35
|
)
|
(279
|
)
|
(9
|
)
|
(108
|
)
|
|||||||||||||||||
Production
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||||||||
December 31, 2015
|
232
|
81
|
120
|
1,182
|
1,225
|
2,402
|
88
|
3,328
|
Canadian Natural Resources Limited | 27 |
PROVED PLUS PROBABLE
|
||||||||||||||||||||||||||||||||
North America
|
Light and
Medium
Crude Oil
(MMbbl)
|
Primary
Heavy
Crude Oil (MMbbl)
|
Pelican Lake
Heavy
Crude Oil
(MMbbl)
|
Bitumen
(Thermal Oil)
(MMbbl)
|
Synthetic
Crude Oil
(MMbbl)
|
Natural Gas
(Bcf)
|
Natural Gas
Liquids
(MMbbl)
|
Barrels of Oil
Equivalent
(MMBOE)
|
||||||||||||||||||||||||
December 31, 2014
|
203
|
317
|
395
|
2,312
|
3,593
|
7,926
|
258
|
8,399
|
||||||||||||||||||||||||
Discoveries
|
1
|
-
|
-
|
-
|
-
|
17
|
2
|
6
|
||||||||||||||||||||||||
Extensions
|
2
|
6
|
-
|
111
|
45
|
358
|
15
|
239
|
||||||||||||||||||||||||
Infill Drilling
|
8
|
13
|
-
|
-
|
-
|
742
|
29
|
174
|
||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
3
|
40
|
-
|
1
|
-
|
43
|
||||||||||||||||||||||||
Acquisitions
|
6
|
5
|
-
|
9
|
-
|
515
|
10
|
116
|
||||||||||||||||||||||||
Dispositions
|
(5
|
)
|
-
|
-
|
-
|
-
|
(9
|
)
|
-
|
(7
|
)
|
|||||||||||||||||||||
Economic Factors
|
(6
|
)
|
(3
|
)
|
-
|
-
|
7
|
(502
|
)
|
(8
|
)
|
(94
|
)
|
|||||||||||||||||||
Technical Revisions
|
2
|
3
|
8
|
(18
|
)
|
33
|
(103
|
)
|
(8
|
)
|
3
|
|||||||||||||||||||||
Production
|
(19
|
)
|
(47
|
)
|
(18
|
)
|
(47
|
)
|
(45
|
)
|
(607
|
)
|
(15
|
)
|
(292
|
)
|
||||||||||||||||
December 31, 2015
|
192
|
294
|
388
|
2,407
|
3,633
|
8,338
|
283
|
8,587
|
||||||||||||||||||||||||
North Sea
|
||||||||||||||||||||||||||||||||
December 31, 2014
|
308
|
114
|
327
|
|||||||||||||||||||||||||||||
Discoveries
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Extensions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Infill Drilling
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Acquisitions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Dispositions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Economic Factors
|
(2
|
)
|
-
|
(2
|
)
|
|||||||||||||||||||||||||||
Technical Revisions
|
(14
|
)
|
(5
|
)
|
(15
|
)
|
||||||||||||||||||||||||||
Production
|
(8
|
)
|
(13
|
)
|
(10
|
)
|
||||||||||||||||||||||||||
December 31, 2015
|
284
|
96
|
300
|
|||||||||||||||||||||||||||||
Offshore Africa
|
||||||||||||||||||||||||||||||||
December 31, 2014
|
149
|
98
|
165
|
|||||||||||||||||||||||||||||
Discoveries
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Extensions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Infill Drilling
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Acquisitions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Dispositions
|
-
|
-
|
-
|
|||||||||||||||||||||||||||||
Economic Factors
|
-
|
1
|
-
|
|||||||||||||||||||||||||||||
Technical Revisions
|
-
|
(15
|
)
|
(2
|
)
|
|||||||||||||||||||||||||||
Production
|
(7
|
)
|
(10
|
)
|
(9
|
)
|
||||||||||||||||||||||||||
December 31, 2015
|
142
|
74
|
154
|
|||||||||||||||||||||||||||||
Total Company
|
||||||||||||||||||||||||||||||||
December 31, 2014
|
660
|
317
|
395
|
2,312
|
3,593
|
8,138
|
258
|
8,891
|
||||||||||||||||||||||||
Discoveries
|
1
|
-
|
-
|
-
|
-
|
17
|
2
|
6
|
||||||||||||||||||||||||
Extensions
|
2
|
6
|
-
|
111
|
45
|
358
|
15
|
239
|
||||||||||||||||||||||||
Infill Drilling
|
8
|
13
|
-
|
-
|
-
|
742
|
29
|
174
|
||||||||||||||||||||||||
Improved Recovery
|
-
|
-
|
3
|
40
|
-
|
1
|
-
|
43
|
||||||||||||||||||||||||
Acquisitions
|
6
|
5
|
-
|
9
|
-
|
515
|
10
|
116
|
||||||||||||||||||||||||
Dispositions
|
(5
|
)
|
-
|
-
|
-
|
-
|
(9
|
)
|
-
|
(7
|
)
|
|||||||||||||||||||||
Economic Factors
|
(8
|
)
|
(3
|
)
|
-
|
-
|
7
|
(501
|
)
|
(8
|
)
|
(96
|
)
|
|||||||||||||||||||
Technical Revisions
|
(12
|
)
|
3
|
8
|
(18
|
)
|
33
|
(123
|
)
|
(8
|
)
|
(14
|
)
|
|||||||||||||||||||
Production
|
(34
|
)
|
(47
|
)
|
(18
|
)
|
(47
|
)
|
(45
|
)
|
(630
|
)
|
(15
|
)
|
(311
|
)
|
||||||||||||||||
December 31, 2015
|
618
|
294
|
388
|
2,407
|
3,633
|
8,508
|
283
|
9,041
|
(1) | Discoveries are additions to reserves in reservoirs where no reserves were previously booked. |
(2) | Extensions are additions to reserves resulting from step-out drilling or recompletions. |
(3) | Infill Drilling are additions to reserves resulting from drilling or recompletions within the known boundaries of a reservoir. |
(4) | Improved Recovery are additions to reserves resulting from the implementation of improved recovery schemes. |
(5) | Negative volumes, if any, for probable reserves result from the transfer of probable reserves to proved reserves. If reserves previously assigned to a discovery, an extension, an infill drilling, or an improved recovery reserves change category are initially classified as probable, they may be classified as a proved addition, in the same reserves change category, in the year when the reserves are reclassified as proved. |
(6)
|
Economic Factors are changes primarily due to price forecasts.
|
(7)
|
Technical Revisions include changes in previous estimates resulting from new technical data or revised interpretations.
|
28 | Canadian Natural Resources Limited |
Proved Undeveloped Reserves
|
||||||||||||||||||||||||||||||||
Year
|
Light and Medium
Crude Oil (MMbbl)
|
Primary
Heavy
Crude Oil (MMbbl) |
Pelican Lake
Heavy Crude Oil (MMbbl) |
Bitumen (Thermal Oil)
(MMbbl) |
Synthetic
Crude Oil (MMbbl)
|
Natural
Gas (Bcf) |
Natural Gas Liquids
(MMbbl)
|
Barrels of Oil Equivalent (MMBOE)
|
||||||||||||||||||||||||
2013
First Attributed
|
3
|
20
|
2
|
-
|
-
|
180
|
13
|
68
|
||||||||||||||||||||||||
Total
|
251
|
98
|
41
|
746
|
363
|
1,170
|
43
|
1,737
|
||||||||||||||||||||||||
2014
First Attributed
|
7
|
13
|
-
|
91
|
-
|
653
|
36
|
256
|
||||||||||||||||||||||||
Total
|
264
|
82
|
39
|
846
|
189
|
1,741
|
87
|
1,797
|
||||||||||||||||||||||||
2015
First Attributed
|
3
|
4
|
-
|
29
|
125
|
487
|
15
|
257
|
||||||||||||||||||||||||
Total
|
201
|
81
|
42
|
874
|
125
|
1,931
|
90
|
1,735
|
Probable Undeveloped Reserves
|
||||||||||||||||||||||||||||||||
Year
|
Light and Medium
Crude Oil (MMbbl)
|
Primary
Heavy
Crude Oil (MMbbl) |
Pelican Lake
Heavy Crude Oil (MMbbl) |
Bitumen (Thermal Oil)
(MMbbl) |
Synthetic
Crude Oil (MMbbl)
|
Natural
Gas (Bcf) |
Natural Gas Liquids
(MMbbl)
|
Barrels of Oil Equivalent (MMBOE)
|
||||||||||||||||||||||||
2013
First Attributed
|
3
|
16
|
-
|
16
|
-
|
267
|
20
|
100
|
||||||||||||||||||||||||
Total
|
145
|
50
|
22
|
1,001
|
978
|
744
|
42
|
2,362
|
||||||||||||||||||||||||
2014
First Attributed
|
7
|
7
|
-
|
44
|
358
|
343
|
18
|
491
|
||||||||||||||||||||||||
Total
|
155
|
44
|
23
|
1,083
|
1,326
|
864
|
40
|
2,815
|
||||||||||||||||||||||||
2015
First Attributed
|
4
|
3
|
-
|
90
|
4
|
507
|
26
|
212
|
||||||||||||||||||||||||
Total
|
164
|
46
|
26
|
968
|
1,043
|
1,176
|
57
|
2,500
|
Canadian Natural Resources Limited | 29 |
Future Development Costs (Undiscounted)
|
||||||||||||||||||||||||||||||||
North America
|
North Sea
|
Offshore Africa
|
Total
|
|||||||||||||||||||||||||||||
Year
|
Proved
(MM$)
|
Proved
plus
Probable
(MM$)
|
Proved
(MM$)
|
Proved
plus
Probable
(MM$)
|
Proved
(MM$)
|
Proved
plus
Probable
(MM$)
|
Proved
(MM$)
|
Proved
plus
Probable
(MM$)
|
||||||||||||||||||||||||
2016
|
2,962
|
3,048
|
139
|
139
|
184
|
341
|
3,285
|
3,528
|
||||||||||||||||||||||||
2017
|
2,962
|
3,167
|
487
|
498
|
43
|
43
|
3,492
|
3,708
|
||||||||||||||||||||||||
2018
|
3,353
|
3,701
|
525
|
593
|
11
|
11
|
3,889
|
4,305
|
||||||||||||||||||||||||
2019
|
2,746
|
3,237
|
374
|
440
|
195
|
242
|
3,315
|
3,919
|
||||||||||||||||||||||||
2020
|
2,351
|
2,554
|
261
|
400
|
42
|
42
|
2,654
|
2,996
|
||||||||||||||||||||||||
Thereafter
|
29,537
|
45,933
|
2,264
|
3,254
|
283
|
348
|
32,084
|
49,535
|
||||||||||||||||||||||||
Total
|
43,911
|
61,640
|
4,050
|
5,324
|
758
|
1,027
|
48,719
|
67,991
|
30 | Canadian Natural Resources Limited |
2015 Average Daily
Production Rates
|
2014 Average Daily
Production Rates
|
|||||||||||||||
Region
|
Crude Oil & NGLs
(Mbbl) |
Natural Gas
(MMcf) |
Crude Oil & NGLs
(Mbbl) |
Natural Gas
(MMcf) |
||||||||||||
North America
|
||||||||||||||||
Northeast British Columbia
|
17
|
521
|
17
|
494
|
||||||||||||
Northwest Alberta
|
42
|
679
|
39
|
624
|
||||||||||||
Northern Plains
|
321
|
222
|
315
|
217
|
||||||||||||
Southern Plains
|
14
|
238
|
13
|
190
|
||||||||||||
Southeast Saskatchewan
|
6
|
3
|
7
|
2
|
||||||||||||
Oil Sands Mining & Upgrading
|
123
|
-
|
111
|
-
|
||||||||||||
North America Total
|
523
|
1,663
|
502
|
1,527
|
||||||||||||
International
|
||||||||||||||||
North Sea UK Sector
|
22
|
36
|
17
|
7
|
||||||||||||
Offshore Africa
|
19
|
27
|
12
|
21
|
||||||||||||
International Total
|
41
|
63
|
29
|
28
|
||||||||||||
Company Total
|
564
|
1,726
|
531
|
1,555
|
Canadian Natural Resources Limited | 31 |
32 | Canadian Natural Resources Limited |
Canadian Natural Resources Limited | 33 |
34 | Canadian Natural Resources Limited |
Canadian Natural Resources Limited | 35 |
36 | Canadian Natural Resources Limited |
Canadian Natural Resources Limited | 37 |
38 | Canadian Natural Resources Limited |
Natural Gas Wells
|
Crude Oil Wells
|
Total Wells
|
||||||||||||||||||||||
Producing
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
||||||||||||||||||
Canada
|
||||||||||||||||||||||||
Alberta
|
27,968.0
|
21,595.6
|
11,167.0
|
9,700.2
|
39,135.0
|
31,295.8
|
||||||||||||||||||
British Columbia
|
2,763.0
|
2,200.1
|
313.0
|
269.1
|
3,076.0
|
2,469.2
|
||||||||||||||||||
Saskatchewan
|
10,684.0
|
9,675.8
|
3,792.0
|
2,381.6
|
14,476.0
|
12,057.4
|
||||||||||||||||||
Manitoba
|
-
|
-
|
210.0
|
203.6
|
210.0
|
203.6
|
||||||||||||||||||
Total Canada
|
41,415.0
|
33,471.5
|
15,482.0
|
12,554.5
|
56,897.0
|
46,026.0
|
||||||||||||||||||
United States
|
-
|
-
|
2.0
|
0.3
|
2.0
|
0.3
|
||||||||||||||||||
North Sea UK Sector
|
2.0
|
1.5
|
72.0
|
62.8
|
74.0
|
64.3
|
||||||||||||||||||
Offshore Africa
|
||||||||||||||||||||||||
Côte d’Ivoire
|
-
|
-
|
25.0
|
14.6
|
25.0
|
14.6
|
||||||||||||||||||
Gabon
|
-
|
-
|
13.0
|
12.0
|
13.0
|
12.0
|
||||||||||||||||||
Total
|
41,417.0
|
33,473.0
|
15,594.0
|
12,644.2
|
57,011.0
|
46,117.2
|
Natural Gas Wells
|
Crude Oil Wells
|
Total Wells
|
||||||||||||||||||||||
Non Producing
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
||||||||||||||||||
Canada
|
||||||||||||||||||||||||
Alberta
|
7,551.0
|
5,990.1
|
7,182.0
|
6,111.2
|
14,733.0
|
12,101.3
|
||||||||||||||||||
British Columbia
|
1,878.0
|
1,530.9
|
453.0
|
371.7
|
2,331.0
|
1,902.6
|
||||||||||||||||||
Saskatchewan
|
1,760.0
|
1,583.7
|
2,896.0
|
2,211.8
|
4,656.0
|
3,795.5
|
||||||||||||||||||
Manitoba
|
2.0
|
2.0
|
27.0
|
24.4
|
29.0
|
26.4
|
||||||||||||||||||
Northwest Territories
|
36.0
|
20.8
|
-
|
-
|
36.0
|
20.8
|
||||||||||||||||||
Total Canada
|
11,227.0
|
9,127.5
|
10,558.0
|
8,719.1
|
21,785.0
|
17,846.6
|
||||||||||||||||||
United States
|
1.0
|
0.1
|
2.0
|
0.3
|
3.0
|
0.4
|
||||||||||||||||||
North Sea UK Sector
|
2.0
|
1.5
|
25.0
|
23.3
|
27.0
|
24.8
|
||||||||||||||||||
Offshore Africa
|
||||||||||||||||||||||||
Côte d’Ivoire
|
-
|
-
|
10.0
|
5.8
|
10.0
|
5.8
|
||||||||||||||||||
Gabon
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
Total
|
11,230.0
|
9,129.1
|
10,595.0
|
8,748.5
|
21,825.0
|
17,877.6
|
Canadian Natural Resources Limited | 39 |
Proved Properties
|
Unproved Properties
|
Total Acreage
|
Average
Working
Interest
|
|||||||||||||||||||||||||
Region (thousands of acres)
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
%
|
|||||||||||||||||||||
North America
|
||||||||||||||||||||||||||||
Northeast British Columbia
|
1,068
|
881
|
5,043
|
4,240
|
6,111
|
5,121
|
84%
|
|
||||||||||||||||||||
Northwest Alberta
|
1,726
|
1,235
|
3,940
|
3,076
|
5,666
|
4,311
|
76%
|
|
||||||||||||||||||||
Northern Plains
|
2,051
|
1,712
|
8,230
|
7,262
|
10,281
|
8,974
|
87%
|
|
||||||||||||||||||||
Southern Plains
|
2,562
|
2,148
|
3,003
|
2,554
|
5,565
|
4,702
|
85%
|
|
||||||||||||||||||||
Southeast Saskatchewan
|
130
|
117
|
126
|
117
|
256
|
234
|
91%
|
|
||||||||||||||||||||
Thermal In Situ Oil Sands
|
93
|
91
|
930
|
825
|
1,023
|
916
|
90%
|
|
||||||||||||||||||||
Oil Sands Mining & Upgrading
|
24
|
24
|
57
|
57
|
81
|
81
|
100%
|
|
||||||||||||||||||||
Non-core Regions
|
8
|
3
|
1,192
|
432
|
1,200
|
435
|
36%
|
|
||||||||||||||||||||
Fee Title
|
90
|
83
|
842
|
830
|
932
|
913
|
98%
|
|
||||||||||||||||||||
North America Total
|
7,752
|
6,294
|
23,363
|
19,393
|
31,115
|
25,687
|
83%
|
|
||||||||||||||||||||
International
|
||||||||||||||||||||||||||||
North Sea UK Sector
|
63
|
55
|
101
|
93
|
164
|
148
|
90%
|
|
||||||||||||||||||||
Offshore Africa
|
||||||||||||||||||||||||||||
Côte d’Ivoire
|
10
|
6
|
360
|
214
|
370
|
220
|
59%
|
|
||||||||||||||||||||
Gabon
|
-
|
-
|
152
|
140
|
152
|
140
|
92%
|
|
||||||||||||||||||||
South Africa
|
-
|
-
|
4,002
|
2,001
|
4,002
|
2,001
|
50%
|
|
||||||||||||||||||||
International Total
|
73
|
61
|
4,615
|
2,448
|
4,688
|
2,509
|
54%
|
|
||||||||||||||||||||
Company Total
|
7,825
|
6,355
|
27,978
|
21,841
|
35,803
|
28,196
|
79%
|
|
40 | Canadian Natural Resources Limited |
MM$
|
North America
|
North Sea
|
Offshore Africa
|
Total
|
||||||||||||
Property Acquisitions
|
||||||||||||||||
Proved
|
(556
|
)
|
-
|
-
|
(556
|
)
|
||||||||||
Unproved
|
(446
|
)
|
-
|
-
|
(446
|
)
|
||||||||||
Exploration
|
87
|
-
|
35
|
122
|
||||||||||||
Development
|
2,845
|
13
|
524
|
3,382
|
||||||||||||
1,930
|
13
|
559
|
2,502
|
|||||||||||||
Add: Net non-cash and other costs (1)
|
681
|
217
|
49
|
947
|
||||||||||||
Costs Incurred
|
2,611
|
230
|
608
|
3,449
|
(1) | Non-cash and other costs are comprised primarily of changes in ARO as well as proceeds on disposition of properties in excess of original cost. |
Canadian Natural Resources Limited | 41 |
2015 Exploratory Wells
|
|||||||||||||||||||||||||
Crude Oil
|
Natural Gas
|
Dry
|
Service
|
Stratigraphic
|
Total
|
||||||||||||||||||||
North America
|
|||||||||||||||||||||||||
Northeast British Columbia
|
Gross
|
- | 1.0 | - | - | - | 1.0 | ||||||||||||||||||
Net
|
- | 1.0 | - | - | - | 1.0 | |||||||||||||||||||
Northwest Alberta
|
Gross
|
- | 5.0 | - | - | - | 5.0 | ||||||||||||||||||
Net
|
- | 5.0 | - | - | - | 5.0 | |||||||||||||||||||
Northern Plains
|
Gross
|
3.0 | - | - | - | - | 3.0 | ||||||||||||||||||
Net
|
3.0 | - | - | - | - | 3.0 | |||||||||||||||||||
Southern Plains
|
Gross
|
- | - | - | - | - | - | ||||||||||||||||||
Net
|
- | - | - | - | - | - | |||||||||||||||||||
Southeast Saskatchewan
|
Gross
|
- | - | - | - | - | - | ||||||||||||||||||
Net
|
- | - | - | - | - | - | |||||||||||||||||||
Oil Sands Mining and Upgrading
|
Gross
|
- | - | - | - | - | - | ||||||||||||||||||
Net
|
- | - | - | - | - | - | |||||||||||||||||||
Non-core Regions
|
Gross
|
- | - | - | - | - | - | ||||||||||||||||||
Net
|
- | - | - | - | - | - | |||||||||||||||||||
North America Total
|
Gross
|
3.0 | 6.0 | - | - | - | 9.0 | ||||||||||||||||||
Net
|
3.0 | 6.0 | - | - | - | 9.0 | |||||||||||||||||||
North Sea UK Sector
|
Gross
|
- | - | - | - | - | - | ||||||||||||||||||
Net
|
- | - | - | - | - | - | |||||||||||||||||||
Offshore Africa
|
Gross
|
- | - | - | - | 1.0 | 1.0 | ||||||||||||||||||
Net
|
- | - | - | - | 0.4 | 0.4 | |||||||||||||||||||
Company Total
|
Gross
|
3.0 | 6.0 | - | - | 1.0 | 10.0 | ||||||||||||||||||
Net
|
3.0 | 6.0 | - | - | 0.4 | 9.4 |
42 | Canadian Natural Resources Limited |
2015 Development Wells
|
|||||||||||||||||||||||||
Crude Oil
|
Natural Gas
|
Dry
|
Service
|
Stratigraphic
|
Total
|
||||||||||||||||||||
North America
|
|||||||||||||||||||||||||
Northeast British Columbia
|
Gross
|
-
|
2.0
|
-
|
-
|
-
|
2.0
|
||||||||||||||||||
Net
|
-
|
2.0
|
-
|
-
|
-
|
2.0
|
|||||||||||||||||||
Northwest Alberta
|
Gross
|
4.0
|
18.0
|
-
|
-
|
-
|
22.0
|
||||||||||||||||||
Net
|
3.1
|
9.3
|
-
|
-
|
-
|
12.4
|
|||||||||||||||||||
Northern Plains
|
Gross
|
108.0
|
6.0
|
6.0
|
26.0
|
52.0
|
198.0
|
||||||||||||||||||
Net
|
102.8
|
1.9
|
5.8
|
25.5
|
17.0
|
153.0
|
|||||||||||||||||||
Southern Plains
|
Gross
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
Net
|
-
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||||||||
Southeast Saskatchewan
|
Gross
|
8.0
|
-
|
-
|
3.0
|
-
|
11.0
|
||||||||||||||||||
Net
|
0.3
|
-
|
-
|
-
|
-
|
0.3
|
|||||||||||||||||||
Oil Sands Mining and Upgrading
|
Gross
|
-
|
-
|
-
|
31.0
|
91.0
|
122.0
|
||||||||||||||||||
|
Net
|
-
|
-
|
-
|
31.0
|
91.0
|
122.0
|
||||||||||||||||||
Non-core Regions
|
Gross
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
Net
|
-
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||||||||
North America Total
|
Gross
|
120.0
|
26.0
|
6.0
|
60.0
|
143.0
|
355.0
|
||||||||||||||||||
Net
|
106.2
|
13.2
|
5.8
|
56.5
|
108.0
|
289.7
|
|||||||||||||||||||
North Sea UK Sector
|
Gross
|
-
|
-
|
-
|
1.0
|
-
|
1.0
|
||||||||||||||||||
Net
|
-
|
-
|
-
|
0.9
|
-
|
0.9
|
|||||||||||||||||||
Offshore Africa
|
Gross
|
10.0
|
-
|
-
|
-
|
1.0
|
11.0
|
||||||||||||||||||
Net
|
5.8
|
-
|
-
|
-
|
0.5
|
6.3
|
|||||||||||||||||||
Company Total
|
Gross
|
130.0
|
26.0
|
6.0
|
61.0
|
144.0
|
367.0
|
||||||||||||||||||
Net
|
112.0
|
13.2
|
5.8
|
57.4
|
108.5
|
296.9
|
Canadian Natural Resources Limited | 43 |
Light and Medium
Crude Oil
(bbl/d) |
Primary
Heavy
Crude Oil
(bbl/d) |
Pelican Lake Heavy
Crude Oil (bbl/d) |
Bitumen (Thermal Oil)
(bbl/d) |
Synthetic
Crude Oil
(bbl/d)
|
Natural Gas
(MMcf/d) |
Natural Gas
Liquids (bbl/d) |
Barrels of Oil Equivalent
(BOE/d) |
|||||||||||||||||||||||||
PROVED
|
||||||||||||||||||||||||||||||||
North America
|
41,822
|
101,546
|
49,500
|
121,126
|
116,900
|
1,432
|
39,368
|
708,928
|
||||||||||||||||||||||||
North Sea
|
20,587
|
-
|
-
|
-
|
-
|
46
|
-
|
28,254
|
||||||||||||||||||||||||
Offshore Africa
|
25,828
|
-
|
-
|
-
|
-
|
27
|
-
|
30,328
|
||||||||||||||||||||||||
Total Proved
|
88,237
|
101,546
|
49,500
|
121,126
|
116,900
|
1,505
|
39,368
|
767,510
|
||||||||||||||||||||||||
PROBABLE
|
||||||||||||||||||||||||||||||||
North America
|
2,442
|
8,870
|
1,747
|
18
|
9,850
|
73
|
1,821
|
36,915
|
||||||||||||||||||||||||
North Sea
|
2,060
|
-
|
-
|
-
|
-
|
3
|
-
|
2,560
|
||||||||||||||||||||||||
Offshore Africa
|
4,328
|
-
|
-
|
-
|
-
|
3
|
-
|
4,828
|
||||||||||||||||||||||||
Total Probable
|
8,830
|
8,870
|
1,747
|
18
|
9,850
|
79
|
1,821
|
44,303
|
2015
|
||||||||||||||||||||
Q1
|
Q2
|
Q3
|
Q4
|
Year Ended
|
||||||||||||||||
North America Production and Netbacks by Product Type (1)
|
||||||||||||||||||||
Light and Medium Crude Oil
|
||||||||||||||||||||
Average daily production
(before royalties) (bbl/d) |
55,382
|
51,454
|
49,599
|
48,773
|
51,279
|
|||||||||||||||
Netbacks ($/bbl)
|
||||||||||||||||||||
Sales price (2)
|
$
|
50.55
|
$
|
69.64
|
$
|
55.33
|
$
|
50.12
|
$
|
56.39
|
||||||||||
Transportation
|
3.56
|
3.72
|
3.42
|
3.44
|
3.54
|
|||||||||||||||
Royalties
|
6.30
|
7.29
|
6.56
|
6.90
|
6.75
|
|||||||||||||||
Production expenses
|
22.06
|
20.72
|
19.52
|
19.14
|
20.41
|
|||||||||||||||
Netback
|
$
|
18.63
|
$
|
37.91
|
$
|
25.83
|
$
|
20.64
|
$
|
25.69
|
||||||||||
Primary Heavy Crude Oil
|
||||||||||||||||||||
Average daily production
(before royalties) (bbl/d) |
137,687
|
128,781
|
125,662
|
120,269
|
128,046
|
|||||||||||||||
Netbacks ($/bbl)
|
||||||||||||||||||||
Sales price (2)
|
$
|
37.64
|
$
|
53.85
|
$
|
39.97
|
$
|
31.14
|
$
|
40.71
|
||||||||||
Transportation
|
2.99
|
3.03
|
2.98
|
3.01
|
3.00
|
|||||||||||||||
Royalties
|
3.32
|
6.05
|
3.22
|
2.86
|
3.86
|
|||||||||||||||
Production expenses
|
17.21
|
14.92
|
13.81
|
13.90
|
15.01
|
|||||||||||||||
Netback
|
$
|
14.12
|
$
|
29.85
|
$
|
19.96
|
$
|
11.37
|
$
|
18.84
|
||||||||||
Pelican Lake Heavy Crude Oil
|
||||||||||||||||||||
Average daily production
(before royalties) (bbl/d) |
51,085
|
52,015
|
50,852
|
49,340
|
50,818
|
|||||||||||||||
Netbacks ($/bbl)
|
||||||||||||||||||||
Sales price (2)
|
$
|
36.21
|
$
|
54.87
|
$
|
39.54
|
$
|
33.25
|
$
|
41.09
|
||||||||||
Transportation
|
3.49
|
4.07
|
3.61
|
4.36
|
3.88
|
|||||||||||||||
Royalties
|
6.47
|
10.24
|
5.45
|
5.27
|
6.88
|
|||||||||||||||
Production expenses
|
8.62
|
6.98
|
6.64
|
6.75
|
7.24
|
|||||||||||||||
Netback
|
$
|
17.63
|
$
|
33.58
|
$
|
23.84
|
$
|
16.87
|
$
|
23.09
|
||||||||||
Bitumen (Thermal Oil)
|
||||||||||||||||||||
Average daily production
(before royalties) (bbl/d) |
146,086
|
105,018
|
133,183
|
135,135
|
129,835
|
|||||||||||||||
Netbacks ($/bbl)
|
||||||||||||||||||||
Sales price (2)
|
$
|
30.25
|
$
|
44.63
|
$
|
37.46
|
$
|
27.92
|
$
|
34.37
|
||||||||||
Transportation
|
1.60
|
2.57
|
2.46
|
2.40
|
2.23
|
|||||||||||||||
Royalties
|
3.64
|
6.25
|
4.41
|
2.92
|
4.17
|
|||||||||||||||
Production expenses
|
10.64
|
12.18
|
9.74
|
9.59
|
10.43
|
|||||||||||||||
Netback
|
$
|
14.37
|
$
|
23.63
|
$
|
20.85
|
$
|
13.01
|
$
|
17.54
|
||||||||||
SCO
|
||||||||||||||||||||
Average daily production
(before royalties) (bbl/d) (3) |
96,607
|
134,166
|
131,779
|
129,050
|
122,911
|
|||||||||||||||
Netbacks ($/bbl)
|
||||||||||||||||||||
Sales price (2)
|
$
|
56.75
|
$
|
73.05
|
$
|
60.66
|
$
|
57.49
|
$
|
61.39
|
||||||||||
Transportation
|
1.83
|
1.98
|
1.82
|
1.66
|
1.81
|
|||||||||||||||
Royalties (4)
|
1.01
|
0.99
|
1.32
|
0.99
|
1.08
|
|||||||||||||||
Production expenses (5)
|
29.73
|
29.25
|
27.04
|
28.56
|
28.61
|
|||||||||||||||
Netback
|
$
|
24.18
|
$
|
40.83
|
$
|
30.48
|
$
|
26.28
|
$
|
29.89
|
||||||||||
Natural Gas
|
||||||||||||||||||||
Average daily production
(before royalties) (MMcf/d) |
1,713
|
1,716
|
1,592
|
1,635
|
1,663
|
|||||||||||||||
Netbacks ($/Mcf)
|
||||||||||||||||||||
Sales price (2)
|
$
|
3.14
|
$
|
2.80
|
$
|
2.99
|
$
|
2.73
|
$
|
2.91
|
||||||||||
Transportation
|
0.31
|
0.30
|
0.31
|
0.30
|
0.30
|
|||||||||||||||
Royalties
|
0.12
|
0.05
|
0.11
|
0.10
|
0.09
|
|||||||||||||||
Production expenses
|
1.38
|
1.28
|
1.25
|
1.17
|
1.27
|
|||||||||||||||
Netback
|
$
|
1.33
|
$
|
1.17
|
$
|
1.32
|
$
|
1.16
|
$
|
1.25
|
Canadian Natural Resources Limited | 45 |
2015
|
||||||||||||||||||||
Q1
|
Q2
|
Q3
|
Q4
|
Year Ended
|
||||||||||||||||
Natural Gas Liquids
|
||||||||||||||||||||
Average daily production
(before royalties) (bbl/d) |
42,179
|
37,772
|
38,596
|
41,491
|
40,004
|
|||||||||||||||
Netbacks ($/bbl)
|
||||||||||||||||||||
Sales price (2)
|
$
|
23.34
|
$
|
27.51
|
$
|
22.31
|
$
|
20.37
|
$
|
23.30
|
||||||||||
Transportation
|
2.02
|
1.88
|
1.33
|
1.06
|
1.57
|
|||||||||||||||
Royalties
|
1.70
|
1.49
|
3.44
|
3.16
|
2.46
|
|||||||||||||||
Production expenses
|
8.58
|
7.89
|
7.76
|
6.98
|
7.80
|
|||||||||||||||
Netback
|
$
|
11.04
|
$
|
16.25
|
$
|
9.78
|
$
|
9.17
|
$
|
11.47
|
||||||||||
North Sea Production and Netbacks by Product Type (1)
|
||||||||||||||||||||
Light and Medium Crude Oil
|
||||||||||||||||||||
Average daily production
(before royalties) (bbl/d) |
23,036
|
20,330
|
22,387
|
23,110
|
22,216
|
|||||||||||||||
Netbacks ($/bbl)
|
||||||||||||||||||||
Sales price (2)
|
$
|
64.59
|
73.57
|
$
|
62.28
|
$
|
57.50
|
$
|
65.13
|
|||||||||||
Transportation
|
1.23
|
0.83
|
0.83
|
1.77
|
1.14
|
|||||||||||||||
Royalties
|
0.16
|
0.11
|
0.17
|
0.14
|
0.14
|
|||||||||||||||
Production expenses
|
65.23
|
60.61
|
72.69
|
56.97
|
63.67
|
|||||||||||||||
Netback
|
$
|
(2.03
|
)
|
$
|
12.02
|
$
|
(11.41
|
)
|
$
|
(1.38
|
)
|
$
|
0.18
|
|||||||
Natural Gas
|
||||||||||||||||||||
Average daily production
(before royalties) (MMcf/d) |
34
|
38
|
35
|
36
|
36
|
|||||||||||||||
Netbacks ($/Mcf)
|
||||||||||||||||||||
Sales price (2)
|
$
|
10.18
|
$
|
9.54
|
$
|
9.44
|
$
|
9.53
|
$
|
9.66
|
||||||||||
Transportation
|
3.49
|
3.91
|
3.95
|
4.46
|
3.96
|
|||||||||||||||
Royalties
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||||
Production Expenses
|
3.89
|
6.47
|
3.85
|
3.27
|
4.41
|
|||||||||||||||
Netback
|
$
|
2.80
|
$
|
(0.84
|
)
|
$
|
1.64
|
$
|
1.80
|
$
|
1.29
|
|||||||||
Offshore Africa Production and Netbacks by Product Type (1)
|
||||||||||||||||||||
Light and Medium Crude Oil
|
||||||||||||||||||||
Average daily production
(before royalties) (bbl/d) |
13,188
|
17,070
|
21,077
|
24,832
|
19,079
|
|||||||||||||||
Netbacks ($/bbl)
|
||||||||||||||||||||
Sales price (2)
|
$
|
71.75
|
$
|
74.84
|
$
|
65.31
|
$
|
53.37
|
$
|
63.13
|
||||||||||
Transportation
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||||
Royalties
|
3.27
|
3.19
|
2.89
|
2.61
|
2.87
|
|||||||||||||||
Production expenses
|
15.46
|
43.88
|
40.53
|
26.08
|
33.32
|
|||||||||||||||
Netback
|
$
|
53.02
|
$
|
27.77
|
$
|
21.89
|
$
|
24.68
|
$
|
26.94
|
||||||||||
Natural Gas
|
||||||||||||||||||||
Average daily production
(before royalties) (MMcf/d) |
24
|
25
|
26
|
32
|
27
|
|||||||||||||||
Netbacks ($/Mcf)
|
||||||||||||||||||||
Sales price (2)
|
$
|
11.70
|
$
|
10.49
|
$
|
9.01
|
$
|
7.63
|
$
|
9.53
|
||||||||||
Transportation
|
0.16
|
0.16
|
0.17
|
0.18
|
0.17
|
|||||||||||||||
Royalties
|
0.54
|
0.48
|
0.41
|
0.44
|
0.46
|
|||||||||||||||
Production expenses
|
2.80
|
1.42
|
1.43
|
1.55
|
1.76
|
|||||||||||||||
Netback
|
$
|
8.20
|
$
|
8.43
|
$
|
7.00
|
$
|
5.46
|
$
|
7.14
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
(3) | 2015 SCO production before royalties excludes 2,122 bbl/d of SCO consumed internally as diesel. |
(4) | Calculated based on actual bitumen royalties expensed during the year; divided by the corresponding SCO sales volumes. |
(5) | Adjusted cash production costs on a per unit basis are based on sales volumes excluding turnaround periods. |
46 | Canadian Natural Resources Limited |
Year Ended December 31
|
|||||||||
(MM$, except per common share information)
|
2015
|
2014
|
|||||||
Product sales
|
$
|
13,167
|
$
|
21,301
|
|||||
Net earnings (loss)
|
$
|
(637
|
)
|
$
|
3,929
|
||||
Per common share
|
– basic |
$
|
(0.58
|
)
|
$
|
3.60
|
|||
|
– diluted
|
$
|
(0.58
|
)
|
$
|
3.58
|
|||
Adjusted net earnings from operations (1)
|
$
|
263
|
$
|
3,811
|
|||||
Per common share
|
– basic |
$
|
0.24
|
$
|
3.49
|
||||
|
– diluted
|
$
|
0.24
|
$
|
3.47
|
||||
Cash flow from operations (1)
|
$
|
5,785
|
$
|
9,587
|
|||||
Per common share
|
– basic |
$
|
5.29
|
$
|
8.78
|
||||
|
– diluted
|
$
|
5.28
|
$
|
8.74
|
||||
Dividends declared per common share
|
$
|
0.92
|
$
|
0.90
|
|||||
Total assets
|
$
|
59,275
|
$
|
60,200
|
|||||
Total long-term liabilities
|
$
|
27,299
|
$
|
26,167
|
|||||
Capital expenditures, net of dispositions
|
$
|
3,853
|
$
|
11,744
|
(1) | These non-GAAP measures are reconciled to net earnings as determined in accordance with IFRS in the “Net Earnings (Loss) and Cash Flow from Operations” section of the Company’s MD&A which is incorporated by reference into this document. |
2015(1)
|
2014
|
2013
|
||||||||||
Cash dividends declared per common share
|
$
|
0.92
|
$
|
0.90
|
$
|
0.575
|
(1) | On December 31, 2015, the Company paid the dividend it would historically have paid on January 1st of the following year. As a result, the actual dividends paid in 2015 were $1.145 per common share. |
Canadian Natural Resources Limited | 47 |
Senior Unsecured
Debt Securities |
Commercial
Paper |
Outlook/Trend(1)
|
|
Moody’s Investors Service, Inc. (“Moody’s”) (2)
|
Baa3
|
P-3
|
Negative
|
Standard & Poor’s Rating Services (“S&P”)
|
BBB+
|
A-2
|
Stable
|
DBRS Limited (“DBRS”) (2)
|
BBB (high)
|
-
|
Negative
|
(1) | Moody’s and S&P assign a rating outlook to Canadian Natural and not to individual long-term debt instruments. |
(2) | The above rating and outlook of Moody’s reflect changes made in February 2016 and the outlook of DBRS reflects a change made in January 2016. |
48 | Canadian Natural Resources Limited |
2015 Monthly Historical Trading on TSX
|
||||||||||||||||
Month
|
High
|
Low
|
Close
|
Volume Traded
|
||||||||||||
January
|
$
|
37.24
|
$
|
31.20
|
$
|
36.84
|
76,468,663
|
|||||||||
February
|
$
|
40.80
|
$
|
36.36
|
$
|
36.36
|
50,169,720
|
|||||||||
March
|
$
|
39.51
|
$
|
35.37
|
$
|
38.82
|
61,417,637
|
|||||||||
April
|
$
|
42.46
|
$
|
38.70
|
$
|
40.09
|
44,459,484
|
|||||||||
May
|
$
|
40.38
|
$
|
37.30
|
$
|
38.38
|
42,261,245
|
|||||||||
June
|
$
|
38.78
|
$
|
33.61
|
$
|
33.90
|
49,860,822
|
|||||||||
July
|
$
|
34.01
|
$
|
29.95
|
$
|
31.92
|
53,981,483
|
|||||||||
August
|
$
|
33.57
|
$
|
25.01
|
$
|
29.65
|
68,168,213
|
|||||||||
September
|
$
|
29.38
|
$
|
25.47
|
$
|
25.99
|
71,185,316
|
|||||||||
October
|
$
|
32.69
|
$
|
25.32
|
$
|
30.32
|
89,804,865
|
|||||||||
November
|
$
|
34.51
|
$
|
29.91
|
$
|
32.34
|
60,772,620
|
|||||||||
December
|
$
|
32.57
|
$
|
27.71
|
$
|
30.22
|
59,483,109
|
Canadian Natural Resources Limited | 49 |
Name
|
Position Presently Held
|
Principal Occupation During Past 5 Years
|
Catherine M. Best, FCA, ICD.D
Calgary, Alberta
Canada
|
Director (1)(2)
(age 62)
|
Corporate director. She has served continuously as a director of the Company since November 2003 and is currently serving on the board of directors of Superior Plus Corporation, Aston Hill Financial Inc., Badger Daylighting Ltd. and AltaGas Ltd. She is also a member of the Board of the Alberta Children’s Hospital Foundation, The Calgary Foundation, The Wawanesa Mutual Insurance Company and serves as a volunteer member of the Audit Committee of the Calgary Stampede.
|
N. Murray Edwards, O.C.
London, United Kingdom
|
Executive Chairman and
Director (5) (age 56)
|
Corporate director and investor. He has served continuously as a director of the Company since September 1988. Prior to December 2015, he was President of Edco Financial Holdings Ltd. (private management and consulting company). Currently, he is Chairman and serving on the board of directors of Ensign Energy Services Inc. and Magellan Aerospace Corporation.
|
Timothy W. Faithfull
London, United Kingdom
|
Director (1)(3)
(age 71)
|
Corporate director. He has served continuously as a director of the Company since November 2010. He is Chairman of the Starehe Endowment Fund in the UK and sits as a Council Member of the Canada – UK Colloquia. He is currently serving on the board of directors of TransAlta Corporation, ICE Futures Europe, and LIFFE Administration and Management.
|
Honourable Gary A. Filmon,
P.C., O.C., O.M.
Winnipeg, Manitoba
Canada
|
Director (1)(4)
(age 73)
|
Corporate director. He has served continuously as a director of the Company since February 2006 and is currently serving on the board of directors of Arctic Glacier Income Trust, and Exchange Income Corporation.
|
Christopher L. Fong
Calgary, Alberta
Canada
|
Director (3)(5)
(age 66)
|
Corporate director. He has served continuously as a director of the Company since November 2010. He was appointed Advisor to the Alberta’s Department of Energy’s Competitive Review process in 2009. He is currently serving on the board of directors of Anderson Energy Inc., Computer Modelling Group Ltd. and sits on the Petroleum Advisory Committee of the Alberta Securities Commission.
|
Ambassador Gordon D. Giffin
Atlanta, Georgia
U.S.A
|
Director (1)(4)
(age 66)
|
Partner, Dentons US LLP (law firm); prior thereto Senior Partner, McKenna Long & Aldridge LLP (law firm) from May 2001 until its merger with Dentons in 2015. He 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, Element Financial Corporation, and TransAlta Corporation.
|
50 | Canadian Natural Resources Limited |
Name
|
Position Presently Held
|
Principal Occupation During Past 5 Years
|
Wilfred A. Gobert
Calgary, Alberta
Canada
|
Director (2)(4)(5)
(age 68)
|
Independent businessman. He has served continuously as a director since November 2010. He is currently serving on the board of directors of Gluskin Sheff & Associates and Trilogy Energy Corp.
|
Steve W. Laut
Calgary, Alberta
Canada
|
President and Director (3)
(age 58)
|
Officer of the Company. He has served continuously as a director of the Company since August 2006.
|
Honourable Frank J. McKenna,
P.C., O.C., O.N.B., Q.C.
Cap Pelé, New Brunswick
Canada
|
Director (2)(4)
(age 68)
|
Deputy Chair, TD Bank Group. 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.
|
David A. Tuer
Calgary, Alberta
Canada
|
Director (1)(5)
(age 66)
|
Chairman, Optiom Inc. (private insurance company); prior thereto, from 2010 to 2015, the Vice-Chairman and Chief Executive Officer of Teine Energy Ltd. (private oil and gas exploration company) and served as Vice-Chairman and Chief Executive Officer of Marble Point Energy Ltd. the predecessor to Teine Energy Ltd. from 2008 to 2010. Prior thereto he was Chairman, Calgary Health Region from 2001 to 2008. He has served continuously as a director of the Company since May 2002.
|
Annette M. Verschuren, O.C.
Toronto, Ontario
Canada
|
Director(2)(3)
(age 59)
|
Ms. A. M. Verschuren is the Chair and Chief Executive Officer of NRStor Inc., an energy storage project developer of energy storage technologies. She has served as a director of the Corporation since November 2014. She was President of The Home Depot Canada from 1996 to 2011 where she oversaw the company's successful growth in Canada leading to its entry into China. She currently serves as Chancellor of Cape Breton University and as a director of Liberty Mutual Insurance Group and a board member of numerous non-profit organizations. Currently serving on the board of directors of Air Canada and Saputo Inc.
|
Troy J.P. Anderson
Calgary, Alberta
Canada
|
Vice-President,
West Conventional Operations
(age 37)
|
Officer of the Company since January 2015; prior thereto UK1 Production Manager from March 2009 to July 2011, Production Manager from July 2011 to October 2013 and most recently Northern Operations Manager from October 2013 to January 2015.
|
Jeffrey J. Bergeson
Calgary, Alberta
Canada
|
Vice-President,
Exploitation West (age 59)
|
Officer of the Company.
|
Canadian Natural Resources Limited | 51 |
Name
|
Position Presently Held
|
Principal Occupation During Past 5 Years
|
Corey B. Bieber
Calgary, Alberta
Canada
|
Chief Financial Officer and Senior
Vice-President,
Finance (age 52)
|
Officer of the Company.
|
Bryan C. Bradley
Calgary, Alberta
Canada
|
Vice-President,
Marketing (age 50)
|
Officer of the Company since November 2011; prior thereto Manager Crude Oil Marketing from November 2006 to November 2011.
|
Trevor J. Cassidy
Calgary, Alberta
Canada
|
Vice-President, Production
Central
(age 42)
|
Officer of the Company since August 2014; prior thereto Production Manager from April 2005 to August 2014.
|
Mark Chalmers
Calgary, Alberta
Canada
|
Vice-President, Exploration
Central
(age 56)
|
Officer of the Company since January 2015; prior thereto Exploration Manager, British Columbia North from December 2006 to September 2010 and most recently Exploration Manager, Northern Plains from September 2010 to January 2015.
|
William R. Clapperton
Calgary, Alberta
Canada
|
Vice-President,
Regulatory, Stakeholder and Environmental Affairs
(age 53)
|
Officer of the Company.
|
James F. Corson
Calgary, Alberta
Canada
|
Vice-President,
Human Resources (age 65)
|
Officer of the Company.
|
Réal M. Cusson
Calgary, Alberta
Canada
|
Senior Vice-President,
Marketing (age 65)
|
Officer of the Company.
|
Réal J. H. Doucet
Calgary, Alberta
Canada
|
Senior Vice-President,
Horizon Projects (age 63)
|
Officer of the Company.
|
Darren M. Fichter
Calgary, Alberta
Canada
|
Senior Vice-President,
Exploitation (age 45)
|
Officer of the Company since January 2012; prior thereto Manager, Heavy Oil South April 2004 to June 2009 and most recently Vice-President, Exploitation of CNR International (U.K.) Limited, a wholly owned subsidiary of the Company, from June 2009 to January 2012.
|
Allan E. Frankiw
Calgary, Alberta
Canada
|
Vice-President,
Production, East (age 59)
|
Officer of the Company.
|
Jay E. Froc
Calgary, Alberta
Canada
|
Vice-President, Horizon
Infrastructure, Logistics
and Project Controls
(age 50)
|
Officer of the Company since June 2013. Most recently held various positions with Suncor Energy Inc. since 2006.
|
52 | Canadian Natural Resources Limited |
Name
|
Position Presently Held
|
Principal Occupation During Past 5 Years
|
Christopher I. Grayston
Calgary, Alberta
Canada
|
Vice-President,
Finance and E&P Accounting
(age 56)
|
Officer of the Company since May 2015; prior thereto Assistant Controller, Operations Accounting from November 2010 to March 2014 and most recently Controller, Operations Accounting from March 2014 to May 2015.
|
Dean W. Halewich
Calgary, Alberta
Canada
|
Vice-President,
Facilities and Pipelines (age 48)
|
Officer of the Company since September 2011; prior thereto Manager, Facilities Engineering from February 2002 to May 2011 and most recently Manager, Thermal Projects from May 2011 to September 2011.
|
Jon Halford
Calgary, Alberta
Canada
|
Vice-President,
Commercial Operations
(age 42)
|
Officer of the Company since January 2015; prior thereto Manager, Materials and Contracts from June 2010 to November 2010 and most recently Director, Supply Management – Major Projects.
|
Murray G. Harris
Calgary, Alberta
Canada
|
Vice-President,
Financial Controller and Horizon Accounting
(age 52)
|
Officer of the Company since March 2012; prior thereto Financial Controller from June 2005 to March 2012.
|
David B. Holt
Calgary, Alberta
Canada
|
Vice-President,
Production, West (age 50)
|
Officer of the Company since September 2011; prior thereto Production Manager, Heavy Oil North from January 2003 to September 2011.
|
John A. Howard
Calgary, Alberta
Canada
|
Vice-President,
Thermal Production Primrose
(age 57)
|
Officer of the Company since September 2011; prior thereto Project Manager, Bitumen Upgrading from May 2006 to May 2007; Manager, Deep Basin Production from May 2007 to October 2009 and most recently Manager, SAGD Production from October 2009 to September 2011.
|
Gerard Iannattone
Calgary, Alberta
Canada
|
Vice-President,
Thermal Exploitation Athabasca
(age 56)
|
Officer of the Company since March 2014; prior thereto Exploitation Manager, N. E. British Columbia from November 2006 to March 2014.
|
Terry J. Jocksch
Calgary, Alberta
Canada
|
Senior Vice-President,
Thermal (age 48)
|
Officer of the Company.
|
Philip A. Keele
Calgary, Alberta
Canada
|
Vice-President,
Mining (age 56)
|
Officer of the Company.
|
Kevin B. Kowbel
Calgary, Alberta
Canada
|
Vice-President,
Drilling and Completions (age 45)
|
Officer of the Company since January 2012; prior thereto Drilling Manager from April 2006 to January 2012.
|
Canadian Natural Resources Limited | 53 |
Name
|
Position Presently Held
|
Principal Occupation During Past 5 Years
|
Trevor D. Krause
Calgary, Alberta
Canada
|
Vice-President,
Exploration, East
(age 44)
|
Officer of the Company since January 2015; prior thereto Exploration Manager, N. E. Alberta from April 2007 to July 2011 and most recently Exploration Manager, Heavy Oil South from July 2011 to January 2015.
|
Dan H. Krentz
Calgary, Alberta
Canada
|
Vice-President,
Exploration, West
(age 57)
|
Officer of the Company since March 2014; prior thereto Exploration Manager, Foothills from November 2006 to April 2011 and most recently Exploration Manager, Deep Basin from April 2011 to March 2014.
|
Ronald K. Laing
Calgary, Alberta
Canada
|
Senior Vice-President,
Corporate Development and Land
(age 46)
|
Officer of the Company.
|
Raul Lanfranchi
Calgary, Alberta
Canada
|
Vice-President, Horizon
Downstream Projects
(age 58)
|
Officer of the Company since February 2016; prior thereto Project Manager, Horizon from July 2006 to March 2013, Project Director, Horizon Downstream from April 2013 to January 2016.
|
Pamela A. McIntyre
Calgary, Alberta
Canada
|
Vice-President,
Safety and Asset Integrity (age 53)
|
Officer of the Company since May 2011; prior thereto Project Integration Manager from July 2007 to January 2011 and most recently Manager, Special Projects Assets from January 2011 to May 2011.
|
Tim S. McKay
Calgary, Alberta
Canada
|
Chief Operating Officer
(age 54)
|
Officer of the Company.
|
Casey D. McWhan
Calgary, Alberta
Canada
|
Vice-President, Horizon
Bitumen Production (age 53)
|
Officer of the Company since November 2011; prior thereto President, Modec du Brasil from January 2006 to September 2008; Senior Vice-President, Prosafe Production from September 2008 to January 2010 and most recently Continuous Process Improvement Lead with the Company from April 2010 to November 2011.
|
Kevin Melnyk
Calgary, Alberta
Canada
|
Vice-President, Horizon
Upgrading and Utilities
(age 49)
|
Officer of the Company since November 2015; prior thereto Agrium Plant Manager, Fort Saskatchewan Nitrogen Operations 2009 to 2012, Redwater Nitrogen Operations 2012-2015 and most recently Director, Utilities and Upgrading from January 2015 to October 2015.
|
Paul M. Mendes
Calgary, Alberta
Canada
|
Vice-President,
Legal, General Counsel and Corporate Secretary
(age 50)
|
Officer of the Company.
|
S. John Parr
Calgary, Alberta
Canada
|
Vice-President,
Thermal Projects (age 55)
|
Officer of the Company.
|
54 | Canadian Natural Resources Limited |
Name
|
Position Presently Held
|
Principal Occupation During Past 5 Years
|
David A. Payne
Calgary, Alberta
Canada
|
Vice-President,
Exploitation, Central (age 54)
|
Officer of the Company.
|
William R. Peterson
Calgary, Alberta
Canada
|
Senior Vice-President,
Production and Development Operations
(age 49)
|
Officer of the Company.
|
Andrew Richardson
Calgary, Alberta
Canada
|
Vice-President,
Thermal Production
Athabasca
(age 48)
|
Officer of the Company since March 2014; prior thereto Manager Production Engineering, Long Lake with Nexen Inc. from August 2006 to January 2012, Manager CSS Production with the Company from January 2012 to November 12, 2012 and most recently Manager, Wolf Lake and Production Development from December 2012 to March 2014.
|
Joy P. Romero
Calgary, Alberta
Canada
|
Vice-President,
Technology Development (age 59)
|
Officer of the Company.
|
Sheldon L. Schroeder
Fort McMurray, Alberta
Canada
|
Vice-President,
Horizon Upstream Projects (age 48)
|
Officer of the Company.
|
Kara Slemko
Calgary, Alberta
Canada
|
Vice-President,
Supply Management
(age 46)
|
Officer of the Company since January 2015; prior thereto Director Operations with Canadian National Railway from February 2003 to February 2011, Management Consultant with Ernst & Young LLP from March 2011 to September 2012 and most recently Director, Supply Management, Operations with the Corporation from September 2012 to January 2015.
|
Kendall W. Stagg
Calgary, Alberta
Canada
|
Senior Vice-President,
Exploration (age 54)
|
Officer of the Company.
|
Scott G. Stauth
Calgary, Alberta
Canada
|
Senior Vice-President,
North American Operations (age 50)
|
Officer of the Company.
|
Lyle G. Stevens
Calgary, Alberta
Canada
|
Executive Vice-President,
Canadian Conventional (age 61)
|
Officer of the Company.
|
Stephen C. Suche
Calgary, Alberta
Canada
|
Vice-President,
Information and Corporate Services (age 56)
|
Officer of the Company.
|
Canadian Natural Resources Limited | 55 |
Name
|
Position Presently Held
|
Principal Occupation During Past 5 Years
|
Domenic Torriero
Calgary, Alberta
Canada
|
Vice-President,
Thermal Exploration (age 51)
|
Officer of the Company.
|
Gregory A. Ulrich
Calgary, Alberta
Canada
|
Vice-President, Thermal
And East Conventional
Field Operations
(age 53)
|
Officer of the Company since March 2014; prior thereto Field Operations Manager from November 2006 to March 2014.
|
Betty Yee
Calgary, Alberta
Canada
|
Vice-President,
Land
(age 51)
|
Officer of the Company since June 2013. Most recently was Manager of Acquisition and Divestments of the Company since 2003.
|
Daryl G. Youck
Calgary, Alberta
Canada
|
Vice-President,
Thermal Exploitation Primrose
(age 47)
|
Officer of the Company.
|
Robin S. Zabek
Calgary, Alberta
Canada
|
Vice-President,
Exploitation East
(age 44)
|
Officer of the Company since March 2014; prior thereto Manager Exploitation from September 2006 to March 2014.
|
(1) | Member of the Audit Committee. |
(2) | Member of the Compensation Committee. |
(3) | Member of the Health, Safety, Asset Integrity and Environmental Committee. |
(4) | Member of the Nominating, Governance and Risk Committee. |
(5) | Member of the Reserves Committee. |
56 | Canadian Natural Resources Limited |
Canadian Natural Resources Limited | 57 |
Auditor service (000’s)
|
2015
|
2014
|
||||||
Audit fees
|
$
|
3,012
|
$
|
3,047
|
||||
Audit related fees
|
250
|
259
|
||||||
Tax fees
|
495
|
523
|
||||||
All other fees
|
84
|
87
|
||||||
$
|
3,841
|
$
|
3,916
|
58 | Canadian Natural Resources Limited |
1. | We have evaluated and reviewed the Company’s reserves data as at December 31, 2015. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2015, estimated using forecast prices and costs. |
2. | The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation and review. |
3. | We carried out our evaluation and review in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the “COGE Handbook”) maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter). |
4. | Those standards require that we plan and perform an evaluation and review to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation and review also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook. |
5. | The following table shows the net present value of 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 Company evaluated and reviewed for the year ended December 31, 2015, and identifies the respective portions thereof that we have evaluated and reviewed and reported on to the Company’s management and board of directors: |
Net Present Value of Future Net Revenue
(Before Income Taxes, 10% Discount Rate)
($ millions)
|
||||||||||||||||||||
Independent
Qualified Reserves
Evaluator or
Auditor
|
Effective Date of Evaluation/Review
Report
|
Location of
Reserves
(Country or Foreign
Geographic Area)
|
Audited
|
Evaluated
|
Reviewed
|
Total
|
||||||||||||||
Sproule Associates Limited
|
December 31, 2015
|
Canada and USA
|
-
|
40,021
|
1,225
|
41,246
|
||||||||||||||
Sproule International Limited
|
December 31, 2015
|
United Kingdom
and Offshore Africa |
-
|
7,941
|
-
|
7,941
|
||||||||||||||
GLJ Petroleum Consultants Ltd.
|
December 31, 2015
|
Canada
|
-
|
39,840
|
-
|
39,840
|
||||||||||||||
Total
|
-
|
87,802
|
1,225
|
89,027
|
6. | In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate. |
7. | We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports. |
Canadian Natural Resources Limited | 59 |
8. | Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. |
Sproule Associates Limited
Calgary, Alberta, Canada,
March 2, 2016
Original Signed By
SIGNED “HARRY J. HELWERDA”
|
Sproule International Limited
Calgary, Alberta, Canada,
March 2, 2016
Original Signed By
SIGNED “HARRY J. HELWERDA”
|
||
Harry J. Helwerda, P.Eng., FEC, FGC (Hon)
President and Director
|
Harry J. Helwerda, P.Eng., FEC, FGC (Hon)
President and Director
|
||
Original Signed By
SIGNED “NORA T. STEWART”
|
Original Signed By
SIGNED “SCOTT W. PENNELL”
|
||
Nora T. Stewart, P.Eng.
Vice President, Reserves Certification
and Director
|
Scott W. Pennell, P.Eng.
Vice President, Engineering
and Director
|
||
Original Signed By
SIGNED “STEVEN J. GOLKO”
|
|||
Steven J. Golko, P.Eng.
Vice President, Field Development & Capital
Strategies and Partner
|
|||
Original Signed By
SIGNED “CAMERON P. SIX”
|
|||
Cameron P. Six, P.Eng.
Vice President, Engineering, Chief
|
|||
Engineer and Director | |||
GLJ Petroleum Consultants Ltd.
Calgary, Alberta, Canada,
March 2, 2016
Original Signed By
SIGNED “TIM R. FREEBORN”
|
|||
Tim R. Freeborn, P.Eng.
Vice President
Mineable Oil Sands and Shales
|
60 | Canadian Natural Resources Limited |
(a) | reviewed the Company’s procedures for providing information to the independent qualified reserves evaluators; |
(b) | met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and |
(c) | reviewed the reserves data with management and the independent qualified reserves evaluators. |
(a) | the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information; |
(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. |
Canadian Natural Resources Limited | 61 |
Original Signed By
|
|
||
Steve W. Laut
President
|
|||
Original Signed By
SIGNED “COREY B. BIEBER”
|
|||
Corey B. Bieber
Chief Financial Officer and Senior Vice President, Finance
|
|||
Original Signed By
SIGNED “DAVID A TUER”
|
|||
David A. Tuer
Independent Director and Chair of the Reserves Committee
|
|||
|
|||
Original Signed By
SIGNED “CHRISTOPHER L. FONG”
|
|||
Christopher L. Fong
Independent Director and Member of the Reserves Committee
|
|||
Dated this 2nd day of March, 2016
|
62 | Canadian Natural Resources Limited |
I
|
Audit Committee Purpose
|
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 and review 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. |
II
|
Audit Committee Composition, Procedures and Organization
|
1. | The Audit Committee shall consist of at least three (3) directors as determined by the Board, each of whom shall be independent, non-executive directors, free from any relationship that would interfere with the exercise of his or her independent judgment. Audit Committee members shall meet the independence and experience requirements of the regulatory bodies to which the Corporation is subject 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. |
Canadian Natural Resources Limited | 63 |
4. | The Secretary or the Assistant Secretary of the Corporation shall be secretary of the Audit Committee unless the Audit Committee appoints a secretary of the Audit Committee. |
5. | The quorum for meetings shall be one half (or where one half of the members of the Audit Committee is not a whole number, the whole number which is closest to and less than one half) of the members of the Audit Committee subject to a minimum of two members of the Audit Committee present in person or by telephone or other telecommunications device that permits all persons participating in the meeting to speak and to hear each other. |
6. | Meetings of the Audit Committee shall be conducted as follows: |
(a) | the Audit Committee shall meet at least four (4) times annually at such times and at such locations as may be requested by the Chair of the Audit Committee; |
(b) | the Audit Committee shall meet privately in executive sessions at each meeting with management, the manager of internal auditing, the independent auditors, and as a committee to discuss any matters that the Audit Committee or each of these groups believe should be discussed. |
7. | The independent auditors and internal auditors shall have a direct line of communication to the Audit Committee through its chair and may bypass management if deemed necessary. Any employee may bring before the Audit Committee directly and may bypass management if deemed necessary any matter involving questionable, illegal or improper financial practices or transactions. |
III
|
Audit Committee Duties and Responsibilities
|
1. | The overall duties and responsibilities of the Audit Committee shall be as follows: |
a. | to assist the Board in the discharge of its responsibilities relating to the Corporation’s accounting principles, reporting practices and internal controls and its approval of the Corporation’s annual and quarterly consolidated financial statements; |
b. | to establish and maintain a direct line of communication with the Corporation’s internal auditors and independent auditors and assess their performance; |
c. | to ensure that the management of the Corporation has 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, Governance and Risk 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 |
64 | Canadian Natural Resources Limited |
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; |
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. |
Canadian Natural Resources Limited | 65 |
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; |
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. |
66 | Canadian Natural Resources Limited |
— | the Company’s consolidated financial statements as at and for the year ended December 31, 2015; and |
— | the effectiveness of the Company’s internal control over financial reporting as at December 31, 2015. |
(signed) “Steve W. Laut” | (signed) “Corey B. Bieber” | (signed) “Murray G. Harris” | |||
Steve W. Laut
President
|
Corey B. Bieber, CA
Chief Financial Officer and
Senior Vice-President, Finance
|
Murray G. Harris, CA
Vice-President, Financial Controller
and Horizon Accounting |
(signed) “Steve W. Laut”
|
(signed) “Corey B. Bieber”
|
||
Steve W. Laut
|
Corey B. Bieber, CA
|
||
President
|
Chief Financial Officer and
Senior Vice-President, Finance
|
/s/ PricewaterhouseCoopers LLP | |
|
|
Chartered Professional Accountants
|
|
|
|
As at December 31
(millions of Canadian dollars) |
Note
|
2015 |
2014
|
|||||||||
ASSETS
|
||||||||||||
Current assets
|
||||||||||||
Cash and cash equivalents
|
$
|
69
|
$
|
25
|
||||||||
Accounts receivable
|
1,277
|
1,889
|
||||||||||
Current income taxes
|
677
|
228
|
||||||||||
Inventory
|
4
|
525
|
665
|
|||||||||
Prepaids and other
|
162
|
172
|
||||||||||
Investment in PrairieSky Royalty Ltd.
|
7
|
974
|
–
|
|||||||||
Current portion of other long-term assets
|
8
|
375
|
510
|
|||||||||
4,059
|
3,489
|
|||||||||||
Exploration and evaluation assets
|
5
|
2,586
|
3,557
|
|||||||||
Property, plant and equipment
|
6
|
51,475
|
52,480
|
|||||||||
Other long-term assets
|
8
|
1,155
|
674
|
|||||||||
$
|
59,275
|
$
|
60,200
|
|||||||||
LIABILITIES
|
||||||||||||
Current liabilities
|
||||||||||||
Accounts payable
|
$
|
571
|
$
|
564
|
||||||||
Accrued liabilities
|
2,089
|
3,279
|
||||||||||
Current portion of long-term debt
|
9
|
1,729
|
980
|
|||||||||
Current portion of other long-term liabilities
|
10
|
206
|
319
|
|||||||||
4,595
|
5,142
|
|||||||||||
Long-term debt
|
9
|
15,065
|
13,022
|
|||||||||
Other long-term liabilities
|
10
|
2,890
|
4,175
|
|||||||||
Deferred income taxes
|
11
|
9,344
|
8,970
|
|||||||||
31,894
|
31,309
|
|||||||||||
SHAREHOLDERS’ EQUITY
|
||||||||||||
Share capital
|
12
|
4,541
|
4,432
|
|||||||||
Retained earnings
|
22,765
|
24,408
|
||||||||||
Accumulated other comprehensive income
|
13
|
75
|
51
|
|||||||||
27,381
|
28,891
|
|||||||||||
$
|
59,275
|
$
|
60,200
|
/s/ Catherine M. Best | /s/ N. Murray Edwards | ||
Catherine M. Best
|
N. Murray Edwards
|
||
Chair of the Audit Committee and Director
|
Executive Chairman of the Board of Directors and Director
|
For the years ended December 31
(millions of Canadian dollars, except per
common share amounts)
|
Note
|
2015
|
2014
|
2013
|
||||||||||||
Product sales
|
$
|
13,167
|
$
|
21,301
|
$
|
17,945
|
||||||||||
Less: royalties
|
(804
|
)
|
(2,438
|
)
|
(1,800
|
)
|
||||||||||
Revenue
|
12,363
|
18,863
|
16,145
|
|||||||||||||
Expenses
|
||||||||||||||||
Production
|
4,726
|
5,265
|
4,559
|
|||||||||||||
Transportation and blending
|
2,379
|
3,232
|
2,938
|
|||||||||||||
Depletion, depreciation and amortization
|
5, 6
|
5,483
|
4,880
|
4,844
|
||||||||||||
Administration
|
390
|
367
|
335
|
|||||||||||||
Share-based compensation
|
10
|
(46
|
)
|
66
|
135
|
|||||||||||
Asset retirement obligation accretion
|
10
|
173
|
193
|
171
|
||||||||||||
Interest and other financing expense
|
16
|
322
|
323
|
279
|
||||||||||||
Risk management activities
|
17
|
(469
|
)
|
(800
|
)
|
(77
|
)
|
|||||||||
Foreign exchange loss
|
761
|
303
|
210
|
|||||||||||||
Gains on disposition of properties and corporate
acquisitions
|
5, 6
|
(739
|
)
|
(137
|
)
|
(289
|
)
|
|||||||||
Loss from investments
|
7, 8
|
50
|
8
|
4
|
||||||||||||
13,030
|
13,700
|
13,109
|
||||||||||||||
Earnings (loss) before taxes
|
(667
|
)
|
5,163
|
3,036
|
||||||||||||
Current income tax (recovery) expense
|
11
|
(261
|
)
|
427
|
735
|
|||||||||||
Deferred income tax expense
|
11
|
231
|
807
|
31
|
||||||||||||
Net earnings (loss)
|
$
|
(637
|
)
|
$
|
3,929
|
$
|
2,270
|
|||||||||
Net earnings (loss) per common share
|
||||||||||||||||
Basic
|
15
|
$
|
(0.58
|
)
|
$
|
3.60
|
$
|
2.08
|
||||||||
Diluted
|
15
|
$
|
(0.58
|
)
|
$
|
3.58
|
$
|
2.08
|
For the years ended December 31
(millions of Canadian dollars)
|
2015
|
2014
|
2013
|
|||||||||
Net earnings (loss)
|
$
|
(637
|
)
|
$
|
3,929
|
$
|
2,270
|
|||||
Items that may be reclassified subsequently to net earnings
|
||||||||||||
Net change in derivative financial instruments designated as cash flow hedges
|
||||||||||||
Unrealized income (loss) , net of taxes of
$2 million (2014 – $nil, 2013 – $nil)
|
(23
|
)
|
5
|
(4
|
)
|
|||||||
Reclassification to net earnings (loss), net of taxes of
$2 million (2014 – $1 million, 2013 – $nil)
|
(13
|
)
|
8
|
(1
|
)
|
|||||||
(36
|
)
|
13
|
(5
|
)
|
||||||||
Foreign currency translation adjustment
|
||||||||||||
Translation of net investment
|
60
|
(4
|
)
|
(11
|
)
|
|||||||
Other comprehensive income (loss), net of taxes
|
24
|
9
|
(16
|
)
|
||||||||
Comprehensive income (loss)
|
$
|
(613
|
)
|
$
|
3,938
|
$
|
2,254
|
For the years ended December 31
(millions of Canadian dollars)
|
Note
|
2015
|
2014 |
2013 |
||||||||||||
Share capital
|
12
|
|||||||||||||||
Balance – beginning of year
|
$
|
4,432
|
$
|
3,854
|
$
|
3,709
|
||||||||||
Issued upon exercise of stock options
|
91
|
488
|
130
|
|||||||||||||
Previously recognized liability on stock options
exercised for common shares
|
18
|
129
|
50
|
|||||||||||||
Purchase of common shares under Normal Course
Issuer Bid
|
–
|
(39
|
)
|
(35
|
)
|
|||||||||||
Balance – end of year
|
4,541
|
4,432
|
3,854
|
|||||||||||||
Retained earnings
|
||||||||||||||||
Balance – beginning of year
|
24,408
|
21,876
|
20,516
|
|||||||||||||
Net earnings (loss)
|
(637
|
)
|
3,929
|
2,270
|
||||||||||||
Purchase of common shares under Normal Course
Issuer Bid
|
12
|
–
|
(414
|
)
|
(285
|
)
|
||||||||||
Dividends on common shares
|
12
|
(1,006
|
)
|
(983
|
)
|
(625
|
)
|
|||||||||
Balance – end of year
|
22,765
|
24,408
|
21,876
|
|||||||||||||
Accumulated other comprehensive income
|
13
|
|||||||||||||||
Balance – beginning of year
|
51
|
42
|
58
|
|||||||||||||
Other comprehensive income (loss), net of taxes
|
24
|
9
|
(16
|
)
|
||||||||||||
Balance – end of year
|
75
|
51
|
42
|
|||||||||||||
Shareholders’ equity
|
$
|
27,381
|
$
|
28,891
|
$
|
25,772
|
For the years ended December 31
(millions of Canadian dollars)
|
Note
|
2015
|
2014 |
2013 |
||||||||||||
Operating activities
|
||||||||||||||||
Net earnings (loss)
|
$
|
(637
|
)
|
$
|
3,929
|
$
|
2,270
|
|||||||||
Non-cash items
|
||||||||||||||||
Depletion, depreciation and amortization
|
5,483
|
4,880
|
4,844
|
|||||||||||||
Share-based compensation
|
(46
|
)
|
66
|
135
|
||||||||||||
Asset retirement obligation accretion
|
173
|
193
|
171
|
|||||||||||||
Unrealized risk management loss (gain)
|
374
|
(451
|
)
|
39
|
||||||||||||
Unrealized foreign exchange loss
|
858
|
256
|
226
|
|||||||||||||
Realized foreign exchange loss (gain)
on repayment of US dollar debt securities
|
–
|
36
|
(12
|
)
|
||||||||||||
Loss from investments
|
7, 8
|
55
|
8
|
4
|
||||||||||||
Deferred income tax expense
|
231
|
807
|
31
|
|||||||||||||
Gains on disposition of properties and corporate acquisitions
|
(739
|
)
|
(137
|
)
|
(289
|
)
|
||||||||||
Current income tax on disposition of properties
|
33
|
–
|
58
|
|||||||||||||
Other
|
(22
|
)
|
(38
|
)
|
(19
|
)
|
||||||||||
Abandonment expenditures
|
(370
|
)
|
(346
|
)
|
(207
|
)
|
||||||||||
Net change in non-cash working capital
|
19
|
239
|
(744
|
)
|
(33
|
)
|
||||||||||
5,632
|
8,459
|
7,218
|
||||||||||||||
Financing activities
|
||||||||||||||||
Issue of bank credit facilities and commercial paper, net
|
970
|
1,195
|
803
|
|||||||||||||
Issue of medium-term notes, net
|
9
|
107
|
992
|
98
|
||||||||||||
Issue (repayment) of US dollar debt securities, net
|
9
|
–
|
1,482
|
(398
|
)
|
|||||||||||
Issue of common shares on exercise of stock options
|
91
|
488
|
130
|
|||||||||||||
Purchase of common shares under Normal Course Issuer Bid
|
–
|
(453
|
)
|
(320
|
)
|
|||||||||||
Dividends on common shares
|
(1,251
|
)
|
(955
|
)
|
(523
|
)
|
||||||||||
Net change in non-cash working capital
|
19
|
(40
|
)
|
(22
|
)
|
(23
|
)
|
|||||||||
(123
|
)
|
2,727
|
(233
|
)
|
||||||||||||
Investing activities
|
||||||||||||||||
Net proceeds (expenditures) on exploration and evaluation assets (1)
|
19
|
236
|
(1,190
|
)
|
144
|
|||||||||||
Net expenditures on property, plant and equipment (1)
|
19
|
(4,704
|
)
|
(10,208
|
)
|
(7,211
|
)
|
|||||||||
Current income tax on disposition of properties
|
(33
|
)
|
–
|
(58
|
)
|
|||||||||||
Investment in other long-term assets
|
(112
|
)
|
(113
|
)
|
–
|
|||||||||||
Net change in non-cash working capital
|
19
|
(852
|
)
|
334
|
119
|
|||||||||||
(5,465
|
)
|
(11,177
|
)
|
(7,006
|
)
|
|||||||||||
Increase (decrease) in cash and cash equivalents
|
44
|
9
|
(21
|
)
|
||||||||||||
Cash and cash equivalents – beginning of year
|
25
|
16
|
37
|
|||||||||||||
Cash and cash equivalents – end of year
|
$
|
69
|
$
|
25
|
$
|
16
|
||||||||||
Interest paid, net
|
$
|
541
|
$
|
521
|
$
|
460
|
||||||||||
Income taxes paid
|
$
|
42
|
$
|
792
|
$
|
357
|
(1) | Net proceeds on exploration and evaluation assets and net expenditures on property, plant and equipment in 2015 exclude non-cash share consideration of $985 million received from PrairieSky Royalty Ltd. (“PrairieSky”) on the disposition of royalty income assets. |
2015
|
2014
|
|||||||
Product inventory
|
$
|
186
|
$
|
332
|
||||
Materials and supplies
|
339
|
333
|
||||||
$
|
525
|
$
|
665
|
Exploration and Production
|
Oil Sands
Mining and Upgrading
|
Total
|
||||||||||||||||||
North America
|
North Sea
|
Offshore Africa
|
||||||||||||||||||
Cost
|
||||||||||||||||||||
At December 31, 2013
|
$
|
2,570
|
$
|
–
|
$
|
39
|
$
|
–
|
$
|
2,609
|
||||||||||
Additions
|
1,103
|
–
|
87
|
–
|
1,190
|
|||||||||||||||
Transfers to property, plant and
equipment
|
(247
|
)
|
–
|
–
|
–
|
(247
|
)
|
|||||||||||||
Foreign exchange adjustments
|
–
|
–
|
5
|
–
|
5
|
|||||||||||||||
At December 31, 2014
|
3,426
|
–
|
131
|
–
|
3,557
|
|||||||||||||||
Additions
|
132
|
–
|
35
|
–
|
167
|
|||||||||||||||
Transfers to property, plant and
equipment
|
(567
|
)
|
–
|
–
|
–
|
(567
|
)
|
|||||||||||||
Disposals/derecognitions (1)
|
(491
|
)
|
(96
|
)
|
(587
|
)
|
||||||||||||||
Foreign exchange adjustments
|
–
|
–
|
16
|
–
|
16
|
|||||||||||||||
At December 31, 2015
|
$
|
2,500
|
$
|
–
|
$
|
86
|
$
|
–
|
$
|
2,586
|
(1) | Refer to note 6 regarding the disposition of exploration and evaluation assets in the North America segment. |
Exploration and Production
|
Oil Sands
Mining and Upgrading
|
Midstream
|
Head
Office
|
Total
|
||||||||||||||||||||||||
North America
|
North Sea
|
Offshore
Africa
|
||||||||||||||||||||||||||
Cost
|
||||||||||||||||||||||||||||
At December 31, 2013
|
$
|
53,810
|
$
|
5,200
|
$
|
3,356
|
$
|
19,366
|
$
|
508
|
$
|
308
|
$
|
82,548
|
||||||||||||||
Additions
|
6,858
|
486
|
193
|
2,728
|
62
|
45
|
10,372
|
|||||||||||||||||||||
Transfers from E&E assets
|
247
|
–
|
–
|
–
|
–
|
–
|
247
|
|||||||||||||||||||||
Disposals/derecognitions
|
(309
|
)
|
–
|
–
|
(146
|
)
|
–
|
(1
|
)
|
(456
|
)
|
|||||||||||||||||
Foreign exchange adjustments and other
|
–
|
496
|
309
|
–
|
–
|
–
|
805
|
|||||||||||||||||||||
At December 31, 2014
|
60,606
|
6,182
|
3,858
|
21,948
|
570
|
352
|
93,516
|
|||||||||||||||||||||
Additions
|
691
|
13
|
524
|
2,523
|
7
|
26
|
3,784
|
|||||||||||||||||||||
Transfers from E&E assets
|
567
|
–
|
–
|
–
|
–
|
–
|
567
|
|||||||||||||||||||||
Disposals/derecognitions
|
(1,324
|
)
|
–
|
–
|
(128
|
)
|
–
|
–
|
(1,452
|
)
|
||||||||||||||||||
Foreign exchange adjustments and other
|
–
|
1,219
|
791
|
–
|
–
|
–
|
2,010
|
|||||||||||||||||||||
At December 31, 2015
|
$
|
60,540
|
$
|
7,414
|
$
|
5,173
|
$
|
24,343
|
$
|
577
|
$
|
378
|
$
|
98,425
|
||||||||||||||
Accumulated depletion and depreciation
|
||||||||||||||||||||||||||||
At December 31, 2013
|
$
|
28,315
|
$
|
3,467
|
$
|
2,551
|
$
|
1,414
|
$
|
111
|
$
|
203
|
$
|
36,061
|
||||||||||||||
Expense
|
3,880
|
265
|
105
|
596
|
9
|
25
|
4,880
|
|||||||||||||||||||||
Disposals/derecognitions
|
(309
|
)
|
–
|
–
|
(146
|
)
|
–
|
(1
|
)
|
(456
|
)
|
|||||||||||||||||
Foreign exchange adjustments and other
|
–
|
317
|
234
|
–
|
–
|
–
|
551
|
|||||||||||||||||||||
At December 31, 2014
|
31,886
|
4,049
|
2,890
|
1,864
|
120
|
227
|
41,036
|
|||||||||||||||||||||
Expense
|
4,226
|
383
|
177
|
562
|
12
|
27
|
5,387
|
|||||||||||||||||||||
Disposals/derecognitions
|
(758
|
)
|
–
|
–
|
(128
|
)
|
–
|
–
|
(886
|
)
|
||||||||||||||||||
Foreign exchange adjustments and other
|
(7
|
)
|
832
|
592
|
(4
|
)
|
–
|
–
|
1,413
|
|||||||||||||||||||
At December 31, 2015
|
$
|
35,347
|
$
|
5,264
|
$
|
3,659
|
$
|
2,294
|
$
|
132
|
$
|
254
|
$
|
46,950
|
||||||||||||||
Net book value
- at December 31, 2015
|
$
|
25,193
|
$
|
2,150
|
$
|
1,514
|
$
|
22,049
|
$
|
445
|
$
|
124
|
$
|
51,475
|
||||||||||||||
- at December 31, 2014
|
$
|
28,720
|
$
|
2,133
|
$
|
968
|
$
|
20,084
|
$
|
450
|
$
|
125
|
$
|
52,480
|
Project costs not subject to depletion and depreciation
|
2015
|
2014
|
||||||
Horizon
|
$
|
6,017
|
$
|
5,492
|
||||
Kirby Thermal Oil Sands – North
|
$
|
816
|
$
|
681
|
2015
|
2014
|
2013
|
||||||||||
Fair value loss from PrairieSky
|
$
|
11
|
$
|
–
|
$
|
–
|
||||||
Dividend income from PrairieSky
|
(5
|
)
|
–
|
–
|
||||||||
$
|
6
|
$
|
–
|
$
|
–
|
2015
|
2014
|
|||||||
Investment in North West Redwater Partnership
|
$
|
254
|
$
|
298
|
||||
North West Redwater Partnership subordinated debt (1)
|
254
|
120
|
||||||
Risk Management (note 17)
|
854
|
599
|
||||||
Other
|
168
|
167
|
||||||
1,530
|
1,184
|
|||||||
Less: current portion
|
375
|
510
|
||||||
$
|
1,155
|
$
|
674
|
(1) | Includes accrued interest. |
2015
|
2014
|
|||||||||||||||
Redwater Partnership
100% interest
|
Company
50% interest
|
Redwater
Partnership
100% interest
|
Company
50% interest
|
|||||||||||||
Current assets
|
$
|
138
|
$
|
69
|
$
|
132
|
$
|
66
|
||||||||
Non-current assets
|
$
|
5,834
|
$
|
2,917
|
$
|
3,062
|
$
|
1,531
|
||||||||
Current liabilities
|
$
|
678
|
$
|
339
|
$
|
454
|
$
|
227
|
||||||||
Non-current liabilities
|
$
|
4,786
|
$
|
2,393
|
$
|
2,144
|
$
|
1,072
|
||||||||
Partners’ equity
|
$
|
508
|
$
|
254
|
$
|
596
|
$
|
298
|
||||||||
Equity loss
|
$
|
88
|
$
|
44
|
$
|
16
|
$
|
8
|
2015
|
2014
|
|||||||
Canadian dollar denominated debt, unsecured
|
||||||||
Bank credit facilities
|
$
|
2,385
|
$
|
2,404
|
||||
Medium-term notes
|
||||||||
4.95% debentures due June 1, 2015
|
–
|
400
|
||||||
3.05% debentures due June 19, 2019
|
500
|
500
|
||||||
2.60% debentures due December 3, 2019
|
500
|
500
|
||||||
2.89% debentures due August 14, 2020
|
1,000
|
500
|
||||||
3.55% debentures due June 3, 2024
|
500
|
500
|
||||||
4,885
|
4,804
|
|||||||
US dollar denominated debt, unsecured
|
||||||||
Bank credit facilities (December 31, 2015 – US$657 million;
December 31, 2014 – $nil)
|
909
|
–
|
||||||
Commercial paper (US$500 million)
|
692
|
580
|
||||||
US dollar debt securities
|
||||||||
Three-month LIBOR plus 0.375% due March 30, 2016
(US$500 million)
|
692
|
580
|
||||||
6.00% due August 15, 2016 (US$250 million)
|
346
|
290
|
||||||
5.70% due May 15, 2017 (US$1,100 million)
|
1,523
|
1,276
|
||||||
1.75% due January 15, 2018 (US$600 million)
|
830
|
696
|
||||||
5.90% due February 1, 2018 (US$400 million)
|
554
|
464
|
||||||
3.45% due November 15, 2021 (US$500 million)
|
692
|
580
|
||||||
3.80% due April 15, 2024 (US$500 million)
|
692
|
580
|
||||||
3.90% due February 1, 2025 (US$600 million)
|
830
|
696
|
||||||
7.20% due January 15, 2032 (US$400 million)
|
554
|
464
|
||||||
6.45% due June 30, 2033 (US$350 million)
|
484
|
406
|
||||||
5.85% due February 1, 2035 (US$350 million)
|
484
|
406
|
||||||
6.50% due February 15, 2037 (US$450 million)
|
622
|
523
|
||||||
6.25% due March 15, 2038 (US$1,100 million)
|
1,523
|
1,276
|
||||||
6.75% due February 1, 2039 (US$400 million)
|
554
|
464
|
||||||
11,981
|
9,281
|
|||||||
Long-term debt before transaction costs and original issue discounts, net
|
16,866
|
14,085
|
||||||
Less: original issue discounts, net (1)
|
(10
|
)
|
(21
|
)
|
||||
transaction costs (1) (2)
|
(62
|
)
|
(62
|
)
|
||||
16,794
|
14,002
|
|||||||
Less: current portion of commercial paper
|
692
|
580
|
||||||
current portion of long-term debt (1) (2)
|
1,037
|
400
|
||||||
$
|
15,065
|
$
|
13,022
|
(1) | The Company has included unamortized original issue discounts and premiums, and directly attributable transaction costs in the carrying amount of the outstanding debt. |
(2) | 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 $100 million demand credit facility; |
· | a $1,000 million non-revolving term credit facility maturing January 2017; |
· | a $1,500 million non-revolving term credit facility maturing April 2018; |
· | a $2,425 million revolving syndicated credit facility maturing June 2019; |
· | a $2,425 million revolving syndicated credit facility maturing June 2020; and, |
· | a £15 million demand credit facility related to the Company’s North Sea operations. |
Year
|
Repayment
|
|||
2016
|
$
|
1,730
|
||
2017
|
$
|
2,522
|
||
2018
|
$
|
2,899
|
||
2019
|
$
|
1,353
|
||
2020
|
$
|
1,427
|
||
Thereafter
|
$
|
6,935
|
2015
|
2014
|
|||||||
Asset retirement obligations
|
$
|
2,950
|
$
|
4,221
|
||||
Share-based compensation
|
128
|
203
|
||||||
Other
|
18
|
70
|
||||||
3,096
|
4,494
|
|||||||
Less: current portion
|
206
|
319
|
||||||
$
|
2,890
|
$
|
4,175
|
2015
|
2014
|
2013
|
||||||||||
Balance – beginning of year
|
$
|
4,221
|
$
|
4,162
|
$
|
4,266
|
||||||
Liabilities incurred
|
7
|
41
|
62
|
|||||||||
Liabilities acquired, net
|
129
|
404
|
131
|
|||||||||
Liabilities settled
|
(370
|
)
|
(346
|
)
|
(207
|
)
|
||||||
Asset retirement obligation accretion
|
173
|
193
|
171
|
|||||||||
Revision of cost, inflation rates and timing estimates
|
(313
|
)
|
(907
|
)
|
375
|
|||||||
Change in discount rate
|
(1,150
|
)
|
558
|
(723
|
)
|
|||||||
Foreign exchange adjustments
|
253
|
116
|
87
|
|||||||||
Balance – end of year
|
2,950
|
4,221
|
4,162
|
|||||||||
Less: current portion
|
101
|
121
|
–
|
|||||||||
$
|
2,849
|
$
|
4,100
|
$
|
4,162
|
2015
|
2014
|
|||||||
Exploration and Production
|
||||||||
North America
|
$
|
1,114
|
$
|
2,012
|
||||
North Sea
|
975
|
1,169
|
||||||
Offshore Africa
|
266
|
255
|
||||||
Oil Sands Mining and Upgrading
|
594
|
783
|
||||||
Midstream
|
1
|
2
|
||||||
$
|
2,950
|
$
|
4,221
|
2015
|
2014
|
2013
|
||||||||||
Balance – beginning of year
|
$
|
203
|
$
|
260
|
$
|
154
|
||||||
Share-based compensation (recovery) expense
|
(46
|
)
|
66
|
135
|
||||||||
Cash payment for stock options surrendered
|
(1
|
)
|
(8
|
)
|
(4
|
)
|
||||||
Transferred to common shares
|
(18
|
)
|
(129
|
)
|
(50
|
)
|
||||||
(Recovered from) capitalized to Oil Sands Mining and Upgrading
|
(10
|
)
|
14
|
25
|
||||||||
Balance – end of year
|
128
|
203
|
260
|
|||||||||
Less: current portion
|
105
|
158
|
216
|
|||||||||
$
|
23
|
$
|
45
|
$
|
44
|
2015
|
2014
|
2013
|
||||||||||
Fair value
|
$
|
3.06
|
$
|
5.51
|
$
|
7.08
|
||||||
Share price
|
$
|
30.22
|
$
|
35.92
|
$
|
35.94
|
||||||
Expected volatility
|
28.6%
|
|
25.1%
|
|
27.2%
|
|
||||||
Expected dividend yield
|
3.0%
|
|
2.5%
|
|
2.2%
|
|
||||||
Risk free interest rate
|
0.6%
|
|
1.2%
|
|
1.5%
|
|
||||||
Expected forfeiture rate
|
4.8%
|
|
4.7%
|
|
4.6%
|
|
||||||
Expected stock option life (1)
|
4.5 years
|
4.5 years
|
4.5 years
|
(1) | At original time of grant. |
2015
|
2014
|
2013
|
||||||||||
Current corporate income tax expense – North America
|
$
|
86
|
$
|
702
|
$
|
544
|
||||||
Current corporate income tax (recovery) expense – North Sea
|
(117
|
)
|
(68
|
)
|
23
|
|||||||
Current corporate income tax expense – Offshore Africa(1)
|
17
|
43
|
202
|
|||||||||
Current PRT(2) recovery – North Sea
|
(258
|
)
|
(273
|
)
|
(56
|
)
|
||||||
Other taxes
|
11
|
23
|
22
|
|||||||||
Current income tax (recovery) expense
|
(261
|
)
|
427
|
735
|
||||||||
Deferred corporate income tax expense
|
216
|
681
|
163
|
|||||||||
Deferred PRT(2) expense (recovery) – North Sea
|
15
|
126
|
(132
|
)
|
||||||||
Deferred income tax expense
|
231
|
807
|
31
|
|||||||||
Income tax (recovery) expense
|
$
|
(30
|
)
|
$
|
1,234
|
$
|
766
|
(1) | Includes current income taxes relating to disposition of properties in 2013. |
(2) | Petroleum Revenue Tax. |
2015
|
2014
|
2013
|
||||||||||
Canadian statutory income tax rate
|
26.0%
|
|
25.1%
|
|
25.1%
|
|
||||||
Income tax provision at statutory rate
|
$
|
(173
|
)
|
$
|
1,296
|
$
|
762
|
|||||
Effect on income taxes of:
|
||||||||||||
UK PRT and other taxes
|
(232
|
)
|
(124
|
)
|
(166
|
)
|
||||||
Impact of deductible UK PRT and other taxes on corporate
income tax
|
119
|
85
|
111
|
|||||||||
Foreign and domestic tax rate differentials
|
(157
|
)
|
(61
|
)
|
(66
|
)
|
||||||
Non-taxable portion of capital gains/losses
|
36
|
36
|
14
|
|||||||||
Stock options exercised for common shares
|
(12
|
)
|
14
|
33
|
||||||||
Income tax rate and other legislative changes
|
362
|
–
|
15
|
|||||||||
Non-taxable gain on corporate acquisitions
|
–
|
(34
|
)
|
(16
|
)
|
|||||||
Revisions arising from prior year tax filings
|
32
|
5
|
57
|
|||||||||
Other
|
(5
|
)
|
17
|
22
|
||||||||
Income tax (recovery) expense
|
$
|
(30
|
)
|
$
|
1,234
|
$
|
766
|
2015
|
2014
|
|||||||
Deferred income tax liabilities
|
||||||||
Property, plant and equipment and exploration and evaluation assets
|
$
|
10,257
|
$
|
9,985
|
||||
Timing of partnership items
|
261
|
437
|
||||||
Unrealized risk management activities
|
111
|
120
|
||||||
Unrealized foreign exchange gain on long-term debt
|
–
|
10
|
||||||
Deferred PRT
|
65
|
37
|
||||||
Investment in PrairieSky
|
60
|
–
|
||||||
10,754
|
10,589
|
|||||||
Deferred income tax assets
|
||||||||
Asset retirement obligations
|
(976
|
)
|
(1,362
|
)
|
||||
Loss carryforwards
|
(170
|
)
|
(117
|
)
|
||||
Unrealized foreign exchange loss on long-term debt
|
(212
|
)
|
–
|
|||||
PRT deduction for corporate income tax
|
(33
|
)
|
(23
|
)
|
||||
Other
|
(19
|
)
|
(117
|
)
|
||||
(1,410
|
)
|
(1,619
|
)
|
|||||
Net deferred income tax liability
|
$
|
9,344
|
$
|
8,970
|
2015
|
2014
|
2013
|
||||||||||
Property, plant and equipment and exploration and evaluation
assets
|
$
|
(7
|
)
|
$
|
647
|
$
|
250
|
|||||
Timing of partnership items
|
(176
|
)
|
(195
|
)
|
(199
|
)
|
||||||
Unrealized foreign exchange loss on long-term debt
|
(222
|
)
|
(77
|
)
|
(55
|
)
|
||||||
Unrealized risk management activities
|
(5
|
)
|
142
|
13
|
||||||||
Asset retirement obligations
|
522
|
119
|
76
|
|||||||||
Loss carryforwards
|
(53
|
)
|
109
|
25
|
||||||||
Investment in PrairieSky
|
60
|
–
|
–
|
|||||||||
Deferred PRT
|
15
|
126
|
(132
|
)
|
||||||||
PRT deduction for corporate income tax
|
(5
|
)
|
(77
|
)
|
78
|
|||||||
Other
|
102
|
13
|
(25
|
)
|
||||||||
$
|
231
|
$
|
807
|
$
|
31
|
2015
|
2014
|
2013
|
||||||||||
Balance – beginning of year
|
$
|
8,970
|
$
|
8,183
|
$
|
8,174
|
||||||
Deferred income tax expense
|
231
|
807
|
31
|
|||||||||
Deferred income tax (recovery) expense included in other
comprehensive income
|
(4
|
)
|
1
|
–
|
||||||||
Foreign exchange adjustments
|
147
|
70
|
53
|
|||||||||
Business combinations
|
–
|
(91
|
)
|
(75
|
)
|
|||||||
Balance – end of year
|
$
|
9,344
|
$
|
8,970
|
$
|
8,183
|
2015
|
2014
|
|||||||||||||||
Common shares
|
Number
of shares (thousands)
|
Amount
|
Number
of shares (thousands)
|
Amount
|
||||||||||||
Balance – beginning of year
|
1,091,837
|
$
|
4,432
|
1,087,322
|
$
|
3,854
|
||||||||||
Issued upon exercise of stock options
|
2,831
|
91
|
14,610
|
488
|
||||||||||||
Previously recognized liability on stock options exercised for
common shares
|
–
|
18
|
–
|
129
|
||||||||||||
Purchase of common shares under Normal Course Issuer Bid
|
–
|
(10,095
|
)
|
(39
|
)
|
|||||||||||
Balance – end of year
|
1,094,668
|
$
|
4,541
|
1,091,837
|
$
|
4,432
|
2015
|
2014
|
|||||||||||||||
Stock options (thousands)
|
Weighted average exercise price
|
Stock options (thousands)
|
Weighted average
exercise price
|
|||||||||||||
Outstanding – beginning of year
|
71,708
|
$
|
35.60
|
72,741
|
$
|
34.36
|
||||||||||
Granted
|
13,310
|
$
|
30.56
|
18,517
|
$
|
38.70
|
||||||||||
Surrendered for cash settlement
|
(185
|
)
|
$
|
33.30
|
(1,047
|
)
|
$
|
33.74
|
||||||||
Exercised for common shares
|
(2,831
|
)
|
$
|
32.31
|
(14,610
|
)
|
$
|
33.40
|
||||||||
Forfeited
|
(7,387
|
)
|
$
|
35.12
|
(3,893
|
)
|
$
|
36.00
|
||||||||
Outstanding – end of year
|
74,615
|
$
|
34.88
|
71,708
|
$
|
35.60
|
||||||||||
Exercisable – end of year
|
30,567
|
$
|
36.19
|
23,717
|
$
|
36.27
|
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
|
|||||||||||||||||
$
|
27.72-$29.99
|
17,849
|
3.47
|
$
|
$28.53
|
4,919
|
$
|
$28.25
|
||||||||||||||
$
|
30.00-$34.99
|
20,255
|
3.26
|
$
|
$33.18
|
6,598
|
$
|
$33.48
|
||||||||||||||
$
|
35.00-$39.99
|
22,793
|
2.54
|
$
|
$36.48
|
11,053
|
$
|
$36.82
|
||||||||||||||
$
|
40.00-$44.99
|
12,152
|
1.76
|
$
|
$42.71
|
7,434
|
$
|
$42.23
|
||||||||||||||
$
|
45.00-$45.09
|
1,566
|
3.03
|
$
|
$45.07
|
563
|
$
|
$45.05
|
||||||||||||||
74,615
|
2.84
|
$
|
$34.88
|
30,567
|
$
|
$36.19
|
2015
|
2014
|
|||||||
Derivative financial instruments designated as cash flow hedges
|
$
|
58
|
$
|
94
|
||||
Foreign currency translation adjustment
|
17
|
(43
|
)
|
|||||
$
|
75
|
$
|
51
|
2015
|
2014
|
|||||||
Long-term debt (1)
|
$
|
16,794
|
$
|
14,002
|
||||
Total shareholders’ equity
|
$
|
27,381
|
$
|
28,891
|
||||
Debt to book capitalization
|
38%
|
|
33%
|
|
(1) | Includes the current portion of long-term debt. |
2015
|
2014
|
2013
|
|||||||||||
Weighted average common shares outstanding
– basic (thousands of shares)
|
1,093,862
|
1,091,754
|
1,088,682
|
||||||||||
Effect of dilutive stock options (thousands of shares)
|
–
|
5,068
|
1,859
|
||||||||||
Weighted average common shares outstanding
– diluted (thousands of shares)
|
1,093,862
|
1,096,822
|
1,090,541
|
||||||||||
Net earnings (loss)
|
$
|
(637
|
)
|
$
|
3,929
|
$
|
2,270
|
||||||
Net earnings (loss) per common share
|
– basic |
$
|
(0.58
|
)
|
$
|
3.60
|
$
|
2.08
|
|||||
– diluted
|
$
|
(0.58
|
)
|
$
|
3.58
|
$
|
2.08
|
2015
|
2014
|
2013
|
||||||||||
Interest and other financing expense:
|
||||||||||||
Long-term debt
|
$
|
618
|
$
|
542
|
$
|
457
|
||||||
Other (1)
|
1
|
(7
|
)
|
(2
|
)
|
|||||||
619
|
535
|
455
|
||||||||||
Less: amounts capitalized on qualifying assets
|
244
|
204
|
175
|
|||||||||
Total interest and other financing expense
|
375
|
331
|
280
|
|||||||||
Total interest income
|
(53
|
)
|
(8
|
)
|
(1
|
)
|
||||||
Net interest and other financing expense
|
$
|
322
|
$
|
323
|
$
|
279
|
(1)
|
Includes the fair value impact of interest rate swaps on US dollar debt securities.
|
2015
|
||||||||||||||||||||
Asset (liability)
|
Financial
assets
at amortized
cost
|
Fair value
through
profit or loss
|
Derivatives
used for
hedging
|
Financial
liabilities at amortized
cost
|
Total
|
|||||||||||||||
Accounts receivable
|
$
|
1,277
|
$
|
–
|
$
|
–
|
$
|
–
|
$
|
1,277
|
||||||||||
Investment in PrairieSky
|
–
|
974
|
–
|
–
|
974
|
|||||||||||||||
Other long-term assets
|
254
|
36
|
818
|
–
|
1,108
|
|||||||||||||||
Accounts payable
|
–
|
–
|
–
|
(571
|
)
|
(571
|
)
|
|||||||||||||
Accrued liabilities
|
–
|
–
|
–
|
(2,089
|
)
|
(2,089
|
)
|
|||||||||||||
Long-term debt (1)
|
–
|
–
|
–
|
(16,794
|
)
|
(16,794
|
)
|
|||||||||||||
$
|
1,531
|
$
|
1,010
|
$
|
818
|
$
|
(19,454
|
)
|
$
|
(16,095
|
)
|
2014
|
||||||||||||||||||||
Asset (liability)
|
Financial
assets
at amortized
cost
|
Fair value
through
profit or loss
|
Derivatives
used for
hedging
|
Financial
liabilities at amortized
cost
|
Total
|
|||||||||||||||
Accounts receivable
|
$
|
1,889
|
$
|
–
|
$
|
–
|
$
|
–
|
$
|
1,889
|
||||||||||
Other long-term assets
|
120
|
415
|
184
|
–
|
719
|
|||||||||||||||
Accounts payable
|
–
|
–
|
–
|
(564
|
)
|
(564
|
)
|
|||||||||||||
Accrued liabilities
|
–
|
–
|
–
|
(3,279
|
)
|
(3,279
|
)
|
|||||||||||||
Other long-term liabilities
|
–
|
–
|
–
|
(40
|
)
|
(40
|
)
|
|||||||||||||
Long-term debt (1)
|
–
|
–
|
–
|
(14,002
|
)
|
(14,002
|
)
|
|||||||||||||
$
|
2,009
|
$
|
415
|
$
|
184
|
$
|
(17,885
|
)
|
$
|
(15,277
|
)
|
(1) | Includes the current portion of long-term debt. |
2015
|
||||||||||||||||
Carrying amount
|
Fair value
|
|||||||||||||||
Asset (liability) (1) (2)
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
Investment in PrairieSky (3)
|
$
|
974
|
$
|
974
|
$
|
–
|
$
|
–
|
||||||||
Other long-term assets (4)
|
$
|
1,108
|
$
|
–
|
$
|
854
|
$
|
254
|
||||||||
Fixed rate long-term debt (5) (6)
|
$
|
(12,808
|
)
|
$
|
(12,431
|
)
|
$
|
–
|
$
|
–
|
2014
|
||||||||||||||||
Carrying amount
|
Fair value
|
|||||||||||||||
Asset (liability) (1) (2)
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
Other long-term assets (4)
|
$
|
719
|
$
|
–
|
$
|
599
|
$
|
120
|
||||||||
Fixed rate long-term debt (5) (6)
|
$
|
(11,018
|
)
|
$
|
(11,855
|
)
|
$
|
–
|
$
|
–
|
(1) | Excludes financial assets and liabilities where the carrying amount 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) | There were no transfers between Level 1, 2 and 3 financial instruments. |
(3) | The fair value of the investment in PrairieSky is based on quoted market prices. |
(4) | The fair value of North West Redwater Partnership subordinated debt is based on the present value of future cash receipts. |
(5) | The fair value of fixed rate long-term debt has been determined based on quoted market prices. |
(6) | Includes the current portion of fixed rate long-term debt. |
Asset (liability)
|
2015
|
2014
|
||||||
Derivatives held for trading
|
||||||||
Crude oil price collars
|
$
|
–
|
$
|
410
|
||||
Crude oil WCS (1) differential swaps
|
–
|
(16
|
)
|
|||||
Foreign currency forward contracts
|
36
|
21
|
||||||
Cash flow hedges
|
||||||||
Foreign currency forward contracts
|
30
|
11
|
||||||
Cross currency swaps
|
788
|
173
|
||||||
$
|
854
|
$
|
599
|
|||||
Included within:
|
||||||||
Current portion of other long-term assets
|
$
|
305
|
$
|
436
|
||||
Other long-term assets
|
549
|
163
|
||||||
$
|
854
|
$
|
599
|
(1) | Western Canadian Select. |
Asset (liability)
|
2015
|
2014
|
||||||
Balance – beginning of year
|
$
|
599
|
$
|
(136
|
)
|
|||
Net change in fair value of outstanding derivative financial instruments
recognized in:
|
||||||||
Risk management activities
|
(374
|
)
|
451
|
|||||
Foreign exchange
|
669
|
270
|
||||||
Other comprehensive (loss) income
|
(40
|
)
|
14
|
|||||
Balance – end of year
|
854
|
599
|
||||||
Less: current portion
|
305
|
436
|
||||||
$
|
549
|
$
|
163
|
2015
|
2014
|
2013
|
||||||||||
Net realized risk management gain
|
$
|
(843
|
)
|
$
|
(349
|
)
|
$
|
(116
|
)
|
|||
Net unrealized risk management loss (gain)
|
374
|
(451
|
)
|
39
|
||||||||
$
|
(469
|
)
|
$
|
(800
|
)
|
$
|
(77
|
)
|
a) | Market risk |
Remaining term
|
Amount
|
Exchange rate
(US$/C$)
|
Interest rate
(US$)
|
Interest rate
(C$)
|
|||
Cross currency
|
|||||||
Swaps
|
Jan 2016
|
–
|
Mar 2016
|
US$500
|
1.109
|
Three-month
LIBOR plus
0.375%
|
Three-month
CDOR (1) plus
0.309%
|
Jan 2016
|
–
|
Aug 2016
|
US$250
|
1.116
|
6.00%
|
5.40%
|
|
Jan 2016
|
–
|
May 2017
|
US$1,100
|
1.170
|
5.70%
|
5.10%
|
|
Jan 2016
|
–
|
Nov 2021
|
US$500
|
1.022
|
3.45%
|
3.96%
|
|
Jan 2016
|
–
|
Mar 2038
|
US$550
|
1.170
|
6.25%
|
5.76%
|
(1) | Canadian Dealer Offered Rate (“CDOR”). |
(Increase) decrease to
net loss |
(Increase) decrease to other comprehensive loss
|
|||||||
Interest rate risk
|
||||||||
Increase interest rate 1%
|
$
|
(17
|
)
|
$
|
(41
|
)
|
||
Decrease interest rate 1%
|
$
|
15
|
$
|
46
|
||||
Foreign currency exchange rate risk
|
||||||||
Increase exchange rate by US$0.01
|
$
|
(70
|
)
|
$
|
–
|
|||
Decrease exchange rate by US$0.01
|
$
|
68
|
$
|
–
|
b) | Credit risk |
c) | Liquidity risk |
Less than
1 year |
1 to less than
2 years |
2 to less than
5 years |
Thereafter
|
|||||||||||||
Accounts payable
|
$
|
571
|
$
|
–
|
$
|
–
|
$
|
–
|
||||||||
Accrued liabilities
|
$
|
2,089
|
$
|
–
|
$
|
–
|
$
|
–
|
||||||||
Long-term debt (1)
|
$
|
1,730
|
$
|
2,522
|
$
|
5,679
|
$
|
6,935
|
(1) | Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums, or transaction costs. |
2016
|
2017
|
2018
|
2019
|
2020
|
Thereafter
|
|||||||||||||||||||
Product transportation and pipeline
|
$
|
423
|
$
|
341
|
$
|
303
|
$
|
261
|
$
|
246
|
$
|
1,304
|
||||||||||||
Offshore equipment operating leases and offshore drilling
|
$
|
247
|
$
|
93
|
$
|
71
|
$
|
22
|
$
|
–
|
$
|
–
|
||||||||||||
Office leases
|
$
|
42
|
$
|
42
|
$
|
42
|
$
|
43
|
$
|
42
|
$
|
193
|
||||||||||||
Other
|
$
|
141
|
$
|
38
|
$
|
48
|
$
|
1
|
$
|
–
|
$
|
–
|
2015
|
2014
|
2013
|
||||||||||
Changes in non-cash working capital
|
||||||||||||
Accounts receivable
|
$
|
615
|
$
|
(456
|
)
|
$
|
(243
|
)
|
||||
Inventory
|
142
|
(31
|
)
|
(76
|
)
|
|||||||
Prepaids and other
|
11
|
(30
|
)
|
(14
|
)
|
|||||||
Accounts payable
|
7
|
(70
|
)
|
175
|
||||||||
Accrued liabilities
|
(981
|
)
|
741
|
127
|
||||||||
Current income tax (liabilities) assets
|
(447
|
)
|
(586
|
)
|
94
|
|||||||
Net changes in non-cash working capital
|
$
|
(653
|
)
|
$
|
(432
|
)
|
$
|
63
|
||||
Relating to:
|
||||||||||||
Operating activities
|
$
|
239
|
$
|
(744
|
)
|
$
|
(33
|
)
|
||||
Financing activities
|
(40
|
)
|
(22
|
)
|
(23
|
)
|
||||||
Investing activities
|
(852
|
)
|
334
|
119
|
||||||||
$
|
(653
|
)
|
$
|
(432
|
)
|
$
|
63
|
2015
|
2014
|
2013
|
||||||||||
Expenditures on exploration and evaluation assets
|
$
|
180
|
$
|
1,190
|
$
|
119
|
||||||
Net proceeds on sale of exploration and
evaluation assets (1) |
(416
|
)
|
–
|
(263
|
)
|
|||||||
Net (proceeds) expenditures on exploration and evaluation assets
|
$
|
(236
|
)
|
$
|
1,190
|
$
|
(144
|
)
|
||||
Expenditures on property, plant and equipment
|
$
|
5,118
|
$
|
10,252
|
$
|
7,249
|
||||||
Net proceeds on sale of property, plant
and equipment (1) |
(414
|
)
|
(44
|
)
|
(38
|
)
|
||||||
Net expenditures on property, plant and equipment
|
$
|
4,704
|
$
|
10,208
|
$
|
7,211
|
(1)
|
Net proceeds on exploration and evaluation assets and net expenditures on property, plant and equipment in 2015 exclude non-cash share consideration of $985 million received from PrairieSky on the disposition of royalty income assets.
|
Exploration and Production
|
||||||||||||||||||||||||||||||||||||
North America
|
North Sea
|
Offshore Africa
|
||||||||||||||||||||||||||||||||||
2015
|
2014
|
2013
|
2015
|
2014
|
2013
|
2015
|
2014
|
2013
|
||||||||||||||||||||||||||||
Segmented product sales
|
$
|
9,222
|
$
|
15,963
|
$
|
12,659
|
$
|
638
|
$
|
701
|
$
|
805
|
$
|
482
|
$
|
503
|
$
|
824
|
||||||||||||||||||
Less: royalties
|
(732
|
)
|
(2,159
|
)
|
(1,477
|
)
|
(1
|
)
|
(2
|
)
|
(2
|
)
|
(22
|
)
|
(43
|
)
|
(137
|
)
|
||||||||||||||||||
Segmented revenue
|
8,490
|
13,804
|
11,182
|
637
|
699
|
803
|
460
|
460
|
687
|
|||||||||||||||||||||||||||
Segmented expenses
|
||||||||||||||||||||||||||||||||||||
Production
|
2,603
|
2,924
|
2,351
|
544
|
496
|
431
|
223
|
212
|
191
|
|||||||||||||||||||||||||||
Transportation
and blending
|
2,309
|
3,228
|
2,939
|
61
|
5
|
6
|
2
|
1
|
1
|
|||||||||||||||||||||||||||
Depletion, depreciation and amortization
|
4,248
|
3,901
|
3,568
|
388
|
269
|
552
|
273
|
105
|
134
|
|||||||||||||||||||||||||||
Asset retirement obligation accretion
|
93
|
98
|
92
|
39
|
38
|
35
|
10
|
10
|
10
|
|||||||||||||||||||||||||||
Realized risk management activities
|
(843
|
)
|
(349
|
)
|
(116
|
)
|
–
|
–
|
–
|
–
|
–
|
–
|
||||||||||||||||||||||||
Gains on disposition of properties and corporate acquisitions
|
(739
|
)
|
(137
|
)
|
(65
|
)
|
–
|
–
|
–
|
–
|
–
|
(224
|
)
|
|||||||||||||||||||||||
Loss from investments
|
6
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
|||||||||||||||||||||||||||
Total segmented expenses
|
7,677
|
9,665
|
8,769
|
1,032
|
808
|
1,024
|
508
|
328
|
112
|
|||||||||||||||||||||||||||
Segmented earnings (loss) before the following
|
$
|
813
|
$
|
4,139
|
$
|
2,413
|
$
|
(395
|
)
|
$
|
(109
|
)
|
$
|
(221
|
)
|
$
|
(48
|
)
|
$
|
132
|
$
|
575
|
||||||||||||||
Non–segmented expenses
|
||||||||||||||||||||||||||||||||||||
Administration
|
||||||||||||||||||||||||||||||||||||
Share-based compensation
|
||||||||||||||||||||||||||||||||||||
Interest and other financing expense
|
||||||||||||||||||||||||||||||||||||
Unrealized risk management activities
|
||||||||||||||||||||||||||||||||||||
Foreign exchange loss
|
||||||||||||||||||||||||||||||||||||
Total non–segmented
expenses
|
||||||||||||||||||||||||||||||||||||
Earnings (loss) before
taxes
|
||||||||||||||||||||||||||||||||||||
Current income tax (recovery) expense
|
||||||||||||||||||||||||||||||||||||
Deferred income tax expense
|
||||||||||||||||||||||||||||||||||||
Net earnings (loss)
|
Oil Sands Mining and Upgrading
|
Midstream
|
Inter-segment
elimination and other
|
Total
|
|||||||||||||||||||||||||||||||||||||||||||
2015
|
2014
|
2013
|
2015
|
2014
|
2013
|
2015
|
2014
|
2013
|
2015
|
2014
|
2013
|
|||||||||||||||||||||||||||||||||||
$
|
2,764
|
$
|
4,095
|
$
|
3,631
|
$
|
136
|
$
|
120
|
$
|
110
|
$
|
(75
|
)
|
$
|
(81
|
)
|
$
|
(84
|
)
|
$
|
13,167
|
$
|
21,301
|
$
|
17,945
|
||||||||||||||||||||
(49
|
)
|
(234
|
)
|
(184
|
)
|
–
|
–
|
–
|
–
|
–
|
–
|
(804
|
)
|
(2,438
|
)
|
(1,800
|
)
|
|||||||||||||||||||||||||||||
2,715
|
3,861
|
3,447
|
136
|
120
|
110
|
(75
|
)
|
(81
|
)
|
(84
|
)
|
12,363
|
18,863
|
16,145
|
||||||||||||||||||||||||||||||||
1,332
|
1,609
|
1,567
|
32
|
34
|
34
|
(8
|
)
|
(10
|
)
|
(15
|
)
|
4,726
|
5,265
|
4,559
|
||||||||||||||||||||||||||||||||
82
|
75
|
63
|
–
|
–
|
–
|
(75
|
)
|
(77
|
)
|
(71
|
)
|
2,379
|
3,232
|
2,938
|
||||||||||||||||||||||||||||||||
562
|
596
|
582
|
12
|
9
|
8
|
–
|
–
|
–
|
5,483
|
4,880
|
4,844
|
|||||||||||||||||||||||||||||||||||
31
|
47
|
34
|
–
|
–
|
–
|
–
|
–
|
–
|
173
|
193
|
171
|
|||||||||||||||||||||||||||||||||||
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(843
|
)
|
(349
|
)
|
(116
|
)
|
||||||||||||||||||||||||||||||||
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(739
|
)
|
(137
|
)
|
(289
|
)
|
||||||||||||||||||||||||||||||||
–
|
–
|
–
|
44
|
8
|
4
|
–
|
–
|
–
|
50
|
8
|
4
|
|||||||||||||||||||||||||||||||||||
2,007
|
2,327
|
2,246
|
88
|
51
|
46
|
(83
|
)
|
(87
|
)
|
(86
|
)
|
11,229
|
13,092
|
12,111
|
||||||||||||||||||||||||||||||||
$
|
708
|
$
|
1,534
|
$
|
1,201
|
$
|
48
|
$
|
69
|
$
|
64
|
$
|
8
|
$
|
6
|
$
|
2
|
1,134
|
5,771
|
4,034
|
||||||||||||||||||||||||||
390
|
367
|
335
|
||||||||||||||||||||||||||||||||||||||||||||
(46
|
)
|
66
|
135
|
|||||||||||||||||||||||||||||||||||||||||||
322
|
323
|
279
|
||||||||||||||||||||||||||||||||||||||||||||
374
|
(451
|
)
|
39
|
|||||||||||||||||||||||||||||||||||||||||||
761
|
303
|
210
|
||||||||||||||||||||||||||||||||||||||||||||
1,801
|
608
|
998 |
||||||||||||||||||||||||||||||||||||||||||||
(667
|
)
|
5,163
|
3,036
|
|||||||||||||||||||||||||||||||||||||||||||
(261
|
)
|
427
|
735
|
|||||||||||||||||||||||||||||||||||||||||||
231
|
807
|
31
|
||||||||||||||||||||||||||||||||||||||||||||
$
|
(637
|
)
|
$
|
3,929
|
$
|
2,270
|
2015
|
2014
|
|||||||||||||||||||||||
Net
expenditures (proceeds) (2)
|
Non-cash
and fair value changes (3)
|
Capitalized
costs
|
Net
expenditures
|
Non-cash
and fair value changes (3)
|
Capitalized
costs
|
|||||||||||||||||||
Exploration and
evaluation assets
|
||||||||||||||||||||||||
Exploration and Production
|
||||||||||||||||||||||||
North America (4)
|
$
|
(260
|
)
|
$
|
(666
|
)
|
$
|
(926
|
)
|
$
|
1,103
|
$
|
(247
|
)
|
$
|
856
|
||||||||
North Sea
|
–
|
–
|
–
|
–
|
–
|
–
|
||||||||||||||||||
Offshore Africa
|
35
|
(96
|
)
|
(61
|
)
|
87
|
–
|
87
|
||||||||||||||||
$
|
(225
|
)
|
$
|
(762
|
)
|
$
|
(987
|
)
|
$
|
1,190
|
$
|
(247
|
)
|
$
|
943
|
|||||||||
Property, plant and equipment
|
||||||||||||||||||||||||
Exploration and Production
|
||||||||||||||||||||||||
North America (4)
|
$
|
1,171
|
$
|
(1,237
|
)
|
$
|
(66
|
)
|
$
|
6,397
|
$
|
399
|
$
|
6,796
|
||||||||||
North Sea
|
230
|
(217
|
)
|
13
|
400
|
86
|
486
|
|||||||||||||||||
Offshore Africa
|
573
|
(49
|
)
|
524
|
194
|
(1
|
)
|
193
|
||||||||||||||||
1,974
|
(1,503
|
)
|
471
|
6,991
|
484
|
7,475
|
||||||||||||||||||
Oil Sands Mining
and Upgrading (5) |
2,730
|
(335
|
)
|
2,395
|
3,110
|
(528
|
)
|
2,582
|
||||||||||||||||
Midstream
|
8
|
(1
|
)
|
7
|
62
|
–
|
62
|
|||||||||||||||||
Head office
|
26
|
–
|
26
|
45
|
(1
|
)
|
44
|
|||||||||||||||||
$
|
4,738
|
$
|
(1,839
|
)
|
$
|
2,899
|
$
|
10,208
|
$
|
(45
|
)
|
$
|
10,163
|
(1) | This table provides a reconciliation of capitalized costs including derecognitions and does not include the impact of foreign exchange adjustments. |
(2) | Net expenditures (proceeds) in 2015 do not include non-cash share consideration of $985 million received from PrairieSky on the disposition of royalty income assets. |
(3) | Asset retirement obligations, deferred income tax adjustments related to differences between carrying amounts and tax values, transfers of exploration and evaluation assets, and other fair value adjustments. |
(4) | The above noted figures in 2015 do not include the impact of other pre-tax gains on the sale of other properties totaling $49 million recognized in 2015. |
(5) | Net expenditures for Oil Sands Mining and Upgrading also include capitalized interest and share-based compensation. |
2015
|
2014
|
|||||||
Exploration and Production
|
||||||||
North America
|
$
|
30,937
|
$
|
34,382
|
||||
North Sea
|
2,734
|
2,711
|
||||||
Offshore Africa
|
1,755
|
1,214
|
||||||
Other
|
73
|
18
|
||||||
Oil Sands Mining and Upgrading
|
22,598
|
20,702
|
||||||
Midstream
|
1,054
|
1,048
|
||||||
Head office
|
124
|
125
|
||||||
$
|
59,275
|
$
|
60,200
|
2015
|
2014
|
2013
|
||||||||||
Fees earned
|
$
|
2
|
$
|
3
|
$
|
2
|
2015
|
2014
|
2013
|
||||||||||
Salary
|
$
|
3
|
$
|
3
|
$
|
3
|
||||||
Common stock option based awards
|
7
|
8
|
11
|
|||||||||
Annual incentive plans
|
2
|
4
|
3
|
|||||||||
Long-term incentive plans
|
6
|
17
|
14
|
|||||||||
Other compensation
|
–
|
–
|
1
|
|||||||||
$
|
18
|
$
|
32
|
$
|
32
|
(1) | Senior management identified above are consistent with the disclosure on Named Executive Officers provided in the Company’s Information Circular to shareholders for the respective years. |
AECO
|
Alberta natural gas reference location
|
AIF
|
Annual Information Form
|
API
|
specific gravity measured in degrees on the American Petroleum Institute scale
|
ARO
|
asset retirement obligations
|
bbl
|
barrel
|
bbl/d
|
barrels per day
|
Bcf
|
billion cubic feet
|
Bcf/d
|
billion cubic feet per day
|
BOE
|
barrels of oil equivalent
|
BOE/d
|
barrels of oil equivalent per day
|
Bitumen
|
solid or semi-solid viscous mixture consisting mainly of pentanes and heavier hydrocarbons with viscosity
greater than 10,000 centipoise
|
Brent
|
Dated Brent
|
C$
|
Canadian dollars
|
CAGR
|
compound annual growth rate
|
CAPEX
|
capital expenditures
|
CO2
|
carbon dioxide
|
CO2e
|
carbon dioxide equivalents
|
Crude oil
|
includes light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen
(thermal oil), and synthetic crude oil
|
CSS
|
Cyclic Steam Stimulation
|
EOR
|
Enhanced Oil Recovery
|
E&P
|
Exploration and Production
|
FPSO
|
Floating Production, Storage and Offloading Vessel
|
GHG
|
greenhouse gas
|
GJ
|
gigajoules
|
GJ/d
|
gigajoules per day
|
Horizon
|
Horizon Oil Sands
|
IASB
|
International Accounting Standards Board
|
IFRS
|
International Financial Reporting Standards
|
LIBOR
|
London Interbank Offered Rate
|
Mbbl
|
thousand barrels
|
Mbbl/d
|
thousand barrels per day
|
MBOE
|
thousand barrels of oil equivalent
|
MBOE/d
|
thousand barrels of oil equivalent per day
|
Mcf
|
thousand cubic feet
|
Mcfe
|
thousands of cubic feet equivalent
|
Mcf/d
|
thousand cubic feet per day
|
MMbbl
|
million barrels
|
MMBOE
|
million barrels of oil equivalent
|
MMBtu
|
million British thermal units
|
MMcf
|
million cubic feet
|
MMcf/d
|
million cubic feet per day
|
NGLs
|
natural gas liquids
|
NYMEX
|
New York Mercantile Exchange
|
NYSE
|
New York Stock Exchange
|
PRT
|
Petroleum Revenue Tax
|
SAGD
|
Steam-Assisted Gravity Drainage
|
SCO
|
synthetic crude oil
|
SEC
|
United States Securities and Exchange Commission
|
Tcf
|
trillion cubic feet
|
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
|
WCS Heavy
|
|
Differential
|
WCS Heavy Differential from WTI
|
WTI
|
West Texas Intermediate reference location at Cushing, Oklahoma
|
— | Balance among its products, namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil(2), bitumen (thermal oil), SCO and natural gas; |
— | A large, balanced, diversified, high quality asset base; |
— | Balance among acquisitions, exploitation and exploration; and |
— | Balance between sources and terms of debt financing and a strong financial position. |
(1) | Discounted value of crude oil and natural gas reserves plus value of unproved land, less net debt. |
(2) | Pelican Lake heavy crude oil is 14–17º API oil, which receives medium quality crude netbacks due to lower production costs and lower royalty rates. |
— | 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 and bitumen (thermal oil). |
Financial Highlights
|
|||||||||||||
($ millions, except per common share amounts)
|
2015
|
2014
|
2013
|
||||||||||
Product sales
|
$
|
13,167
|
$
|
21,301
|
$
|
17,945
|
|||||||
Net earnings (loss)
|
$
|
(637
|
)
|
$
|
3,929
|
$
|
2,270
|
||||||
Per common share
|
– basic |
$
|
(0.58
|
)
|
$
|
3.60
|
$
|
2.08
|
|||||
|
– diluted |
$
|
(0.58
|
)
|
$
|
3.58
|
$
|
2.08
|
|||||
Adjusted net earnings from operations (1)
|
$
|
263
|
$
|
3,811
|
$
|
2,435
|
|||||||
Per common share
|
– basic |
$
|
0.24
|
$
|
3.49
|
$
|
2.24
|
||||||
|
– diluted |
$
|
0.24
|
$
|
3.47
|
$
|
2.23
|
||||||
Cash flow from operations (2)
|
$
|
5,785
|
$
|
9,587
|
$
|
7,477
|
|||||||
Per common share
|
– basic |
$
|
5.29
|
$
|
8.78
|
$
|
6.87
|
||||||
|
– diluted |
$
|
5.28
|
$
|
8.74
|
$
|
6.86
|
||||||
Dividends declared per common share (3)
|
$
|
0.92
|
$
|
0.90
|
$
|
0.575
|
|||||||
Total assets
|
$
|
59,275
|
$
|
60,200
|
$
|
51,754
|
|||||||
Total long-term liabilities
|
$
|
27,299
|
$
|
26,167
|
$
|
20,748
|
|||||||
Capital expenditures, net of dispositions
|
$
|
3,853
|
$
|
11,744
|
$
|
7,274
|
(1) | Adjusted net earnings from operations is a non-GAAP measure that represents net earnings (loss) 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” presents 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 (loss) 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” presents 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. |
(3) | On March 2, 2016, the Board of Directors declared a quarterly dividend of $0.23 per common share, beginning with the dividend payable on April 1, 2016. In 2015 the Board of Directors declared a quarterly dividend of $0.23 per common share, beginning with the dividend payable on April 1, 2015. In 2014, the Board of Directors approved a quarterly dividend of $0.225 per common share, beginning with the dividend payable on April 1, 2014. In 2013, the Board of Directors approved a dividend of $0.20 per common share on November 5, 2013, beginning with the dividend payable on January 1, 2014 ($0.125 per common share, approved on March 6, 2013, beginning with the dividend payable on April 1, 2013). |
Adjusted Net Earnings from Operations
|
||||||||||||
($ millions)
|
2015
|
2014
|
2013
|
|||||||||
Net earnings (loss)
|
$
|
(637
|
)
|
$
|
3,929
|
$
|
2,270
|
|||||
Share-based compensation, net of tax (1)
|
(46
|
)
|
66
|
135
|
||||||||
Unrealized risk management loss (gain), net of tax (2)
|
275
|
(339
|
)
|
32
|
||||||||
Unrealized foreign exchange loss, net of tax (3)
|
858
|
256
|
226
|
|||||||||
Realized foreign exchange loss (gain) on repayment of
US dollar debt securities, net of tax (4)
|
–
|
36
|
(12
|
)
|
||||||||
Loss from investments, net of tax (5)(6)
|
55
|
–
|
–
|
|||||||||
Gains on disposition of properties and corporate acquisitions,
net of tax (7)
|
(663
|
)
|
(137
|
)
|
(231
|
)
|
||||||
Derecognition of exploration and evaluation assets,
net of tax (8)
|
70
|
–
|
–
|
|||||||||
Effect of statutory tax rate and other legislative changes on deferred income tax liabilities (9)
|
351
|
–
|
15
|
|||||||||
Adjusted net earnings from operations
|
$
|
263
|
$
|
3,811
|
$
|
2,435
|
(1)
|
The Company’s employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded as a liability on the Company’s balance sheets and periodic changes in the fair value are recognized in net earnings (loss) or are capitalized to Oil Sands Mining and Upgrading construction costs.
|
(2)
|
Derivative financial instruments are recorded at fair value on the Company’s balance sheets, with changes in the 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, natural gas and foreign exchange.
|
(3)
|
Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps, and are recognized in net earnings (loss).
|
(4)
|
During 2014, the Company repaid US$500 million of 1.45% debt securities and US$350 million of 4.90% debt securities. During 2013, the Company repaid US$400 million of 5.15% debt securities.
|
(5)
|
The Company’s investment in the 50% owned North West Redwater Partnership (“Redwater Partnership”) is accounted for using the equity method of accounting. Included in the non-cash loss from investments is the Company’s pro-rata share of the Redwater Partnership’s accounting loss.
|
(6)
|
The Company’s investment in PrairieSky Royalty Ltd. (“PrairieSky”) has been accounted for at fair value through profit and loss and is remeasured each period with changes in fair value recognized in net earnings.
|
(7)
|
During 2015, the Company recorded a pre-tax gain of $739 million ($663 million after-tax) related to the disposition of a number of North America royalty income assets and crude oil and natural gas properties. During 2014, the Company recorded an after-tax gain of $137 million related to the acquisition of certain producing crude oil and natural gas properties. During 2013, the Company recorded an after-tax gain of $231 million related to the acquisition of Barrick Energy Inc. and the disposition of a 50% interest in an exploration right in South Africa.
|
(8)
|
In connection with the Company’s notice of withdrawal from Block CI-514 in Côte d’Ivoire, Offshore Africa in 2015, the Company derecognized $96 million ($70 million after-tax) of exploration and evaluation assets through depletion, depreciation and amortization expense.
|
(9)
|
All substantively enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the Company’s balance sheets in determining deferred income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in net earnings (loss) during the period the legislation is substantively enacted. During 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12%. As a result of this income tax rate increase, the Company's deferred income tax liability was increased by $579 million. In addition, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and the PRT, and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in the Company's deferred income tax liability of $228 million. During 2013, the British Columbia government substantively enacted legislation to increase its provincial corporate income tax rate, resulting in an increase in the Company’s deferred income tax liability of $15 million.
|
Cash Flow from Operations
|
||||||||||||
($ millions)
|
2015
|
2014
|
2013
|
|||||||||
Net earnings (loss)
|
$
|
(637
|
)
|
$
|
3,929
|
$
|
2,270
|
|||||
Non-cash items:
|
||||||||||||
Depletion, depreciation and amortization
|
5,483
|
4,880
|
4,844
|
|||||||||
Share-based compensation
|
(46
|
)
|
66
|
135
|
||||||||
Asset retirement obligation accretion
|
173
|
193
|
171
|
|||||||||
Unrealized risk management loss (gain)
|
374
|
(451
|
)
|
39
|
||||||||
Unrealized foreign exchange loss
|
858
|
256
|
226
|
|||||||||
Realized foreign exchange loss (gain) on repayment of
US dollar debt securities
|
–
|
36
|
(12
|
)
|
||||||||
Loss from investments
|
55
|
8
|
4
|
|||||||||
Deferred income tax expense
|
231
|
807
|
31
|
|||||||||
Gains on disposition of properties and corporate acquisitions
|
(739
|
)
|
(137
|
)
|
(289
|
)
|
||||||
Current income tax on disposition of properties
|
33
|
–
|
58
|
|||||||||
Cash flow from operations
|
$
|
5,785
|
$
|
9,587
|
$
|
7,477
|
— | lower crude oil and NGLs netbacks in the Exploration and Production segments; |
— | lower realized SCO prices; |
— | lower natural gas netbacks in the North America segment; and |
— | higher depletion, depreciation and amortization expense; |
— | higher crude oil and NGLs, SCO and natural gas sales volumes across all segments; |
— | higher realized risk management gains; and |
— | the impact of a weaker Canadian dollar relative to the US dollar. |
($ millions, except per common share amounts)
|
|||||||||||||||||||||
2015
|
Total
|
Dec 31
|
Sep 30
|
Jun 30
|
Mar 31
|
||||||||||||||||
Product sales
|
$
|
13,167
|
$
|
2,963
|
$
|
3,316
|
$
|
3,662
|
$
|
3,226
|
|||||||||||
Net earnings (loss)
|
$
|
(637
|
)
|
$
|
131
|
$
|
(111
|
)
|
$
|
(405
|
)
|
$
|
(252
|
)
|
|||||||
Net earnings (loss) per common share
|
|||||||||||||||||||||
|
– basic |
$
|
(0.58
|
)
|
$
|
0.12
|
$
|
(0.10
|
)
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
||||||
|
– diluted
|
$
|
(0.58
|
)
|
$
|
0.12
|
$
|
(0.10
|
)
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
||||||
2014
|
Total
|
Dec 31
|
Sep 30
|
Jun 30
|
Mar 31
|
||||||||||||||||
Product sales
|
$
|
21,301
|
$
|
4,850
|
$
|
5,370
|
$
|
6,113
|
$
|
4,968
|
|||||||||||
Net earnings (loss)
|
$
|
3,929
|
$
|
1,198
|
$
|
1,039
|
$
|
1,070
|
$
|
622
|
|||||||||||
Net earnings (loss) per common share
|
|||||||||||||||||||||
|
– basic |
$
|
3.60
|
$
|
1.10
|
$
|
0.95
|
$
|
0.98
|
$
|
0.57
|
||||||||||
|
– diluted
|
$
|
3.58
|
$
|
1.09
|
$
|
0.94
|
$
|
0.97
|
$
|
0.57
|
— | Crude oil pricing – The impact of increased shale oil production in North America, fluctuating global supply/demand including the Organization of the Petroleum Exporting Countries’ (“OPEC”) decision not to curtail crude oil production to offset the excess world supply, the impact of geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential from WTI in North America and the impact of the differential between WTI and Brent benchmark pricing in the North Sea and Offshore Africa. |
— | Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, and the impact of increased shale gas production in the US. |
— | Crude oil and NGLs sales volumes – Fluctuations in production due to the cyclic nature of the Company’s Primrose thermal projects, production from Kirby South, the results from the Pelican Lake water and polymer flood projects, fluctuations in the Company’s drilling program in North America, the impact and timing of acquisitions, the impact of turnarounds at Horizon and higher drilling in Côte d’Ivoire in Offshore Africa. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the North Sea and Offshore Africa. |
— | Natural gas sales volumes – Fluctuations in production due to the Company’s allocation of capital to higher return crude oil projects, as well as natural decline rates, shut-in natural gas production due to third party pipeline restrictions and related pricing impacts, and the impact and timing of acquisitions. |
— | Production expense – Fluctuations primarily due to the impact of the demand and cost for services, fluctuations in product mix and production, the impact of seasonal costs that are dependent on weather, cost optimizations across all segments, the impact and timing of acquisitions, and turnarounds at Horizon. |
— | Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes including the impact and timing of acquisitions, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company’s proved undeveloped reserves, fluctuations in international sales volumes subject to higher depletion rates, and the impact of turnarounds at Horizon. |
— | Share-based compensation – Fluctuations due to the determination of fair market value based on the Black-Scholes valuation model of the Company’s share-based compensation liability. |
— | Risk management – Fluctuations due to commodity volumes hedged and the recognition of 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, which 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. Fluctuations in realized and unrealized foreign exchange gains and losses are recorded with respect to US dollar denominated debt, partially offset by the impact of cross currency swap hedges. |
— | Income tax expense – Fluctuations in income tax expense include statutory tax rate and other legislative changes substantively enacted in the various periods. |
— | Gains on disposition of properties and corporate acquisitions – Fluctuations due to the recognition of gains on disposition of properties in the third and fourth quarters of 2015 and acquisitions in the fourth quarter of 2014. |
(Yearly average)
|
2015
|
2014
|
2013
|
|||||||||
WTI benchmark price (US$/bbl)
|
$
|
48.76
|
$
|
92.92
|
$
|
98.00
|
||||||
Brent benchmark price (US$/bbl)
|
$
|
52.40
|
$
|
98.85
|
$
|
108.62
|
||||||
WCS blend differential from WTI (US$/bbl)
|
$
|
13.51
|
$
|
19.41
|
$
|
25.11
|
||||||
WCS blend differential from WTI (%)
|
28%
|
|
21%
|
|
26%
|
|
||||||
SCO price (US$/bbl)
|
$
|
48.59
|
$
|
91.35
|
$
|
98.18
|
||||||
Condensate benchmark price (US$/bbl)
|
$
|
47.34
|
$
|
92.84
|
$
|
101.67
|
||||||
NYMEX benchmark price (US$/MMBtu)
|
$
|
2.67
|
$
|
4.37
|
$
|
3.67
|
||||||
AECO benchmark price (C$/GJ)
|
$
|
2.62
|
$
|
4.19
|
$
|
3.00
|
||||||
US / Canadian dollar average exchange rate (US$)
|
$
|
0.7820
|
$
|
0.9054
|
$
|
0.9710
|
||||||
US / Canadian dollar year end exchange rate (US$)
|
$
|
0.7225
|
$
|
0.8620
|
$
|
0.9402
|
Changes due to
|
Changes due to
|
|||||||||||||||||||||||||||||||||||
($ millions)
|
2013
|
Volumes
|
Prices
|
Other
|
2014
|
Volumes
|
Prices
|
Other
|
2015
|
|||||||||||||||||||||||||||
North America
|
||||||||||||||||||||||||||||||||||||
Crude oil and
NGLs |
$
|
11,246
|
$
|
1,527
|
$
|
585
|
$
|
(26
|
)
|
$
|
13,332
|
$
|
402
|
$
|
(6,378
|
)
|
$
|
96
|
$
|
7,452
|
||||||||||||||||
Natural gas
|
1,413
|
497
|
721
|
–
|
2,631
|
234
|
(1,095
|
)
|
–
|
1,770
|
||||||||||||||||||||||||||
12,659
|
2,024
|
1,306
|
(26
|
)
|
15,963
|
636
|
(7,473
|
)
|
96
|
9,222
|
||||||||||||||||||||||||||
North Sea
|
||||||||||||||||||||||||||||||||||||
Crude oil and
NGLs |
795
|
(3
|
)
|
(37
|
)
|
(73
|
)
|
682
|
137
|
(317
|
)
|
10
|
512
|
|||||||||||||||||||||||
Natural gas
|
10
|
8
|
1
|
–
|
19
|
73
|
34
|
–
|
126
|
|||||||||||||||||||||||||||
805
|
5
|
(36
|
)
|
(73
|
)
|
701
|
210
|
(283
|
)
|
10
|
638
|
|||||||||||||||||||||||||
Offshore Africa
|
||||||||||||||||||||||||||||||||||||
Crude oil and
NGLs |
733
|
(264
|
)
|
(52
|
)
|
(7
|
)
|
410
|
185
|
(214
|
)
|
8
|
389
|
|||||||||||||||||||||||
Natural gas
|
91
|
(10
|
)
|
12
|
–
|
93
|
24
|
(24
|
)
|
–
|
93
|
|||||||||||||||||||||||||
824
|
(274
|
)
|
(40
|
)
|
(7
|
)
|
503
|
209
|
(238
|
)
|
8
|
482
|
||||||||||||||||||||||||
Subtotal
|
||||||||||||||||||||||||||||||||||||
Crude oil and
NGLs |
12,774
|
1,260
|
496
|
(106
|
)
|
14,424
|
724
|
(6,909
|
)
|
114
|
8,353
|
|||||||||||||||||||||||||
Natural gas
|
1,514
|
495
|
734
|
–
|
2,743
|
331
|
(1,085
|
)
|
–
|
1,989
|
||||||||||||||||||||||||||
14,288
|
1,755
|
1,230
|
(106
|
)
|
17,167
|
1,055
|
(7,994
|
)
|
114
|
10,342
|
||||||||||||||||||||||||||
Oil Sands Mining and Upgrading
|
3,631
|
463
|
(20
|
)
|
21
|
4,095
|
435
|
(1,749
|
)
|
(17
|
)
|
2,764
|
||||||||||||||||||||||||
Midstream
|
110
|
–
|
–
|
10
|
120
|
–
|
–
|
16
|
136
|
|||||||||||||||||||||||||||
Intersegment
eliminations and other (1) |
(84
|
)
|
–
|
–
|
3
|
(81
|
)
|
–
|
–
|
6
|
(75
|
)
|
||||||||||||||||||||||||
Total
|
$
|
17,945
|
$
|
2,218
|
$
|
1,210
|
$
|
(72
|
)
|
$
|
21,301
|
$
|
1,490
|
$
|
(9,743
|
)
|
$
|
119
|
$
|
13,167
|
(1) | Eliminates internal transportation and electricity charges. |
2015
|
2014
|
2013
|
|
Crude oil and NGLs (bbl/d)
|
|||
North America – Exploration and Production
|
399,982
|
390,814
|
343,699
|
North America – Oil Sands Mining and Upgrading (1)
|
122,911
|
110,571
|
100,284
|
North Sea
|
22,216
|
17,380
|
18,334
|
Offshore Africa
|
19,079
|
12,429
|
15,923
|
564,188
|
531,194
|
478,240
|
|
Natural gas (MMcf/d)
|
|||
North America
|
1,663
|
1,527
|
1,130
|
North Sea
|
36
|
7
|
4
|
Offshore Africa
|
27
|
21
|
24
|
1,726
|
1,555
|
1,158
|
|
Total barrels of oil equivalent (BOE/d)
|
851,901
|
790,410
|
671,162
|
Product mix
|
|||
Light and medium crude oil and NGLs
|
16%
|
15%
|
15%
|
Pelican Lake heavy crude oil
|
6%
|
6%
|
7%
|
Primary heavy crude oil
|
15%
|
18%
|
20%
|
Bitumen (thermal oil)
|
15%
|
14%
|
14%
|
Synthetic crude oil (1)
|
14%
|
14%
|
15%
|
Natural gas
|
34%
|
33%
|
29%
|
Percentage of gross revenue (1) (2)
|
|||
(excluding Midstream revenue)
|
|||
Crude oil and NGLs
|
82%
|
85%
|
90%
|
Natural gas
|
18%
|
15%
|
10%
|
(1) | 2015 SCO production before royalties excludes 2,122 bbl/d of SCO consumed internally as diesel (2014 – 545 bbl/d; 2013 – nil). |
(2) | Net of blending costs and excluding risk management activities. |
2015
|
2014
|
2013
|
|
Crude oil and NGLs (bbl/d)
|
|||
North America – Exploration and Production
|
350,451
|
318,291
|
287,428
|
North America – Oil Sands Mining and Upgrading
|
121,208
|
104,095
|
95,098
|
North Sea
|
22,164
|
17,313
|
18,279
|
Offshore Africa
|
18,209
|
11,500
|
12,973
|
512,032
|
451,199
|
413,778
|
|
Natural gas (MMcf/d)
|
|||
North America
|
1,606
|
1,407
|
1,080
|
North Sea
|
36
|
7
|
4
|
Offshore Africa
|
25
|
18
|
20
|
1,667
|
1,432
|
1,104
|
|
Total barrels of oil equivalent (BOE/d)
|
789,799
|
689,893
|
597,835
|
(bbl)
|
2015
|
2014
|
2013
|
North Sea
|
835,806
|
368,808
|
385,073
|
Offshore Africa
|
1,271,170
|
461,997
|
185,476
|
2,106,976
|
830,805
|
570,549
|
2015
|
2014
|
2013
|
||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||
Sales price (2)
|
$
|
41.13
|
$
|
77.04
|
$
|
73.81
|
||||||
Transportation
|
2.60
|
2.41
|
2.22
|
|||||||||
Realized sales price, net of transportation
|
38.53
|
74.63
|
71.59
|
|||||||||
Royalties
|
4.30
|
12.99
|
11.13
|
|||||||||
Production expense
|
15.74
|
18.25
|
17.14
|
|||||||||
Netback
|
$
|
18.49
|
$
|
43.39
|
$
|
43.32
|
||||||
Natural gas ($/Mcf) (1)
|
||||||||||||
Sales price (2)
|
$
|
3.16
|
$
|
4.83
|
$
|
3.58
|
||||||
Transportation
|
0.38
|
0.27
|
0.28
|
|||||||||
Realized sales price, net of transportation
|
2.78
|
4.56
|
3.30
|
|||||||||
Royalties
|
0.10
|
0.38
|
0.18
|
|||||||||
Production expense
|
1.34
|
1.48
|
1.42
|
|||||||||
Netback
|
$
|
1.34
|
$
|
2.70
|
$
|
1.70
|
||||||
Barrels of oil equivalent ($/BOE) (1)
|
||||||||||||
Sales price (2)
|
$
|
32.60
|
$
|
58.48
|
$
|
56.46
|
||||||
Transportation
|
2.56
|
2.18
|
2.10
|
|||||||||
Realized sales price, net of transportation
|
30.04
|
56.30
|
54.36
|
|||||||||
Royalties
|
2.85
|
8.90
|
7.74
|
|||||||||
Production expense
|
12.70
|
14.67
|
14.24
|
|||||||||
Netback
|
$
|
14.49
|
$
|
32.73
|
$
|
32.38
|
(1)
|
Amounts expressed on a per unit basis are based on sales volumes.
|
(2)
|
Net of blending costs and excluding risk management activities.
|
2015
|
2014
|
2013
|
||||||||||
Crude oil and NGLs ($/bbl) (1) (2)
|
||||||||||||
North America
|
$
|
38.96
|
$
|
75.09
|
$
|
69.90
|
||||||
North Sea
|
$
|
65.13
|
$
|
106.63
|
$
|
112.46
|
||||||
Offshore Africa
|
$
|
63.13
|
$
|
97.81
|
$
|
110.21
|
||||||
Company average
|
$
|
41.13
|
$
|
77.04
|
$
|
73.81
|
||||||
Natural gas ($/Mcf) (1) (2)
|
||||||||||||
North America
|
$
|
2.91
|
$
|
4.72
|
$
|
3.43
|
||||||
North Sea
|
$
|
9.66
|
$
|
7.07
|
$
|
5.69
|
||||||
Offshore Africa
|
$
|
9.53
|
$
|
11.98
|
$
|
10.45
|
||||||
Company average
|
$
|
3.16
|
$
|
4.83
|
$
|
3.58
|
||||||
Company average ($/BOE) (1) (2)
|
$
|
32.60
|
$
|
58.48
|
$
|
56.46
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
(Yearly average)
|
2015
|
2014
|
2013
|
|||||||||
Wellhead Price (1) (2)
|
||||||||||||
Light and medium crude oil and NGLs (C$/bbl)
|
$
|
41.88
|
$
|
76.94
|
$
|
76.44
|
||||||
Pelican Lake heavy crude oil (C$/bbl)
|
$
|
41.09
|
$
|
77.58
|
$
|
70.62
|
||||||
Primary heavy crude oil (C$/bbl)
|
$
|
40.71
|
$
|
76.29
|
$
|
69.06
|
||||||
Bitumen (thermal oil) (C$/bbl)
|
$
|
34.37
|
$
|
70.78
|
$
|
66.14
|
||||||
Natural gas (C$/Mcf)
|
$
|
2.91
|
$
|
4.72
|
$
|
3.43
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
2015
|
2014
|
2013
|
||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||
North America
|
$
|
4.57
|
$
|
13.74
|
$
|
11.30
|
||||||
North Sea
|
$
|
0.14
|
$
|
0.33
|
$
|
0.33
|
||||||
Offshore Africa
|
$
|
2.87
|
$
|
6.83
|
$
|
18.18
|
||||||
Company average
|
$
|
4.30
|
$
|
12.99
|
$
|
11.13
|
||||||
Natural gas ($/Mcf) (1)
|
||||||||||||
North America
|
$
|
0.09
|
$
|
0.36
|
$
|
0.14
|
||||||
Offshore Africa
|
$
|
0.46
|
$
|
1.74
|
$
|
1.83
|
||||||
Company average
|
$
|
0.10
|
$
|
0.38
|
$
|
0.18
|
||||||
Company average ($/BOE) (1)
|
$
|
2.85
|
$
|
8.90
|
$
|
7.74
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
2015
|
2014
|
2013
|
||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||
North America
|
$
|
12.51
|
$
|
14.98
|
$
|
14.20
|
||||||
North Sea
|
$
|
63.67
|
$
|
74.04
|
$
|
66.19
|
||||||
Offshore Africa
|
$
|
33.32
|
$
|
43.97
|
$
|
25.32
|
||||||
Company average
|
$
|
15.74
|
$
|
18.25
|
$
|
17.14
|
||||||
Natural gas ($/Mcf) (1)
|
||||||||||||
North America
|
$
|
1.27
|
$
|
1.42
|
$
|
1.39
|
||||||
North Sea
|
$
|
4.41
|
$
|
9.10
|
$
|
4.67
|
||||||
Offshore Africa
|
$
|
1.76
|
$
|
3.22
|
$
|
2.53
|
||||||
Company average
|
$
|
1.34
|
$
|
1.48
|
$
|
1.42
|
||||||
Company average ($/BOE) (1)
|
$
|
12.70
|
$
|
14.67
|
$
|
14.24
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
($ millions, except per BOE amounts)
|
2015
|
2014
|
2013
|
|||||||||
North America
|
$
|
4,248
|
$
|
3,901
|
$
|
3,568
|
||||||
North Sea
|
388
|
269
|
552
|
|||||||||
Offshore Africa
|
273
|
105
|
134
|
|||||||||
Expense
|
$
|
4,909
|
$
|
4,275
|
$
|
4,254
|
||||||
$/BOE (1)
|
$
|
18.50
|
$
|
17.27
|
$
|
20.38
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
($ millions, except per BOE amounts)
|
2015
|
2014
|
2013
|
|||||||||
North America
|
$
|
93
|
$
|
98
|
$
|
92
|
||||||
North Sea
|
39
|
38
|
35
|
|||||||||
Offshore Africa
|
10
|
10
|
10
|
|||||||||
Expense
|
$
|
142
|
$
|
146
|
$
|
137
|
||||||
$/BOE (1)
|
$
|
0.54
|
$
|
0.59
|
$
|
0.66
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
($/bbl)
|
2015
|
2014
|
2013
|
|||||||||
SCO sales price(1)
|
$
|
61.39
|
$
|
100.27
|
$
|
100.75
|
||||||
Bitumen value for royalty purposes (1) (2)
|
$
|
32.14
|
$
|
67.63
|
$
|
65.48
|
||||||
Bitumen royalties (1) (3)
|
$
|
1.08
|
$
|
5.77
|
$
|
5.11
|
||||||
Transportation
|
$
|
1.81
|
$
|
1.85
|
$
|
1.57
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Calculated as the quarterly average of the bitumen valuation methodology price. |
(3) | Calculated based on actual bitumen royalties expensed during the year; divided by the corresponding SCO sales volumes. |
($ millions)
|
2015
|
2014
|
2013
|
|||||||||
Cash production costs
|
$
|
1,332
|
$
|
1,609
|
$
|
1,567
|
||||||
Less: costs incurred during turnaround periods
|
(45
|
)
|
(98
|
)
|
(104
|
)
|
||||||
Adjusted cash production costs
|
$
|
1,287
|
$
|
1,511
|
$
|
1,463
|
||||||
Adjusted cash production costs, excluding natural gas costs
|
$
|
1,212
|
$
|
1,395
|
$
|
1,359
|
||||||
Adjusted natural gas costs
|
75
|
116
|
104
|
|||||||||
Adjusted cash production costs
|
$
|
1,287
|
$
|
1,511
|
$
|
1,463
|
($/bbl) (1)
|
2015
|
2014
|
2013
|
|||||||||
Adjusted cash production costs, excluding natural gas costs
|
$
|
26.95
|
$
|
34.33
|
$
|
37.68
|
||||||
Adjusted natural gas costs
|
1.66
|
2.85
|
2.89
|
|||||||||
Adjusted cash production costs
|
$
|
28.61
|
$
|
37.18
|
$
|
40.57
|
||||||
Sales (bbl/d)
|
123,231
|
111,351
|
98,757
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
($ millions, except per bbl amounts)
|
2015
|
2014
|
2013
|
|||||||||
Depletion, depreciation and amortization
|
$
|
562
|
$
|
596
|
$
|
582
|
||||||
Less: depreciation incurred during turnaround periods
|
(5
|
)
|
(28
|
)
|
(79
|
)
|
||||||
Adjusted depletion, depreciation and amortization
|
$
|
557
|
$
|
568
|
$
|
503
|
||||||
$/bbl (1)
|
$
|
12.37
|
$
|
13.97
|
$
|
13.95
|
(1) | Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods. |
($ millions, except per bbl amounts)
|
2015
|
2014
|
2013
|
|||||||||
Expense
|
$
|
31
|
$
|
47
|
$
|
34
|
||||||
$/bbl (1)
|
$
|
0.69
|
$
|
1.16
|
$
|
0.94
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
($ millions)
|
2015
|
2014
|
2013
|
|||||||||
Revenue
|
$
|
136
|
$
|
120
|
$
|
110
|
||||||
Production expense
|
32
|
34
|
34
|
|||||||||
Midstream cash flow
|
104
|
86
|
76
|
|||||||||
Depreciation
|
12
|
9
|
8
|
|||||||||
Equity loss from Redwater Partnership
|
44
|
8
|
4
|
|||||||||
Segment earnings before taxes
|
$
|
48
|
$
|
69
|
$
|
64
|
($ millions, except per BOE amounts)
|
2015
|
2014
|
2013
|
|||||||||
Expense
|
$
|
390
|
$
|
367
|
$
|
335
|
||||||
$/BOE (1)
|
$
|
1.26
|
$
|
1.28
|
$
|
1.37
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
($ millions)
|
2015
|
2014
|
2013
|
|||||||||
(Recovery) expense
|
$
|
(46
|
)
|
$
|
66
|
$
|
135
|
($ millions, except per BOE amounts and interest rates)
|
2015
|
2014
|
2013
|
|||||||||
Expense, gross
|
$
|
566
|
$
|
527
|
$
|
454
|
||||||
Less: capitalized interest
|
244
|
204
|
175
|
|||||||||
Expense, net
|
$
|
322
|
$
|
323
|
$
|
279
|
||||||
$/BOE (1)
|
$
|
1.04
|
$
|
1.12
|
$
|
1.14
|
||||||
Average effective interest rate
|
3.9%
|
|
3.9%
|
|
4.4%
|
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
($ millions)
|
2015
|
2014
|
2013
|
|||||||||
Crude oil and NGLs financial instruments
|
$
|
(599
|
)
|
$
|
(284
|
)
|
$
|
44
|
||||
Natural gas financial instruments
|
–
|
34
|
–
|
|||||||||
Foreign currency contracts
|
(244
|
)
|
(99
|
)
|
(160
|
)
|
||||||
Realized gain
|
$
|
(843
|
)
|
$
|
(349
|
)
|
$
|
(116
|
)
|
|||
Crude oil and NGLs financial instruments
|
$
|
394
|
$
|
(427
|
)
|
$
|
17
|
|||||
Natural gas financial instruments
|
–
|
(3
|
)
|
3
|
||||||||
Foreign currency contracts
|
(20
|
)
|
(21
|
)
|
19
|
|||||||
Unrealized loss (gain)
|
$
|
374
|
$
|
(451
|
)
|
$
|
39
|
|||||
Net gain
|
$
|
(469
|
)
|
$
|
(800
|
)
|
$
|
(77
|
)
|
($ millions)
|
2015
|
2014
|
2013
|
|||||||||
Net realized (gain) loss
|
$
|
(97
|
)
|
$
|
47
|
$
|
(16
|
)
|
||||
Net unrealized loss (1)
|
858
|
256
|
226
|
|||||||||
Net loss
|
$
|
761
|
$
|
303
|
$
|
210
|
(1) | Amounts are reported net of the hedging effect of cross currency swaps. |
($ millions, except income tax rates)
|
2015
|
2014
|
2013
|
|||||||||
North America (1)
|
$
|
86
|
$
|
702
|
$
|
544
|
||||||
North Sea
|
(117
|
)
|
(68
|
)
|
23
|
|||||||
Offshore Africa (2)
|
17
|
43
|
202
|
|||||||||
PRT recovery – North Sea
|
(258
|
)
|
(273
|
)
|
(56
|
)
|
||||||
Other taxes
|
11
|
23
|
22
|
|||||||||
Current income tax (recovery) expense
|
(261
|
)
|
427
|
735
|
||||||||
Deferred income tax expense
|
216
|
681
|
163
|
|||||||||
Deferred PRT expense (recovery) – North Sea
|
15
|
126
|
(132
|
)
|
||||||||
Deferred income tax expense
|
231
|
807
|
31
|
|||||||||
(30
|
)
|
1,234
|
766
|
|||||||||
Income tax rate and other legislative changes (3)
|
(351
|
)
|
–
|
(15
|
)
|
|||||||
$
|
(381
|
)
|
$
|
1,234
|
$
|
751
|
||||||
Effective income tax rate on adjusted net
earnings from operations (4)
|
61%
|
|
25%
|
|
26%
|
|
(1) | Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments. |
(2) | Includes current income taxes relating to disposition of properties in 2013. |
(3) | During 2015, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and PRT, and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in the Company’s deferred income tax liability of $228 million. During 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12%. As a result of this income tax rate increase, the Company’s deferred income tax liability was increased by $579 million. During 2013, the British Columbia government substantively enacted legislation to increase its provincial corporate income tax rate. As a result of the income tax rate change, the Company’s deferred income tax liability was increased by $15 million. |
(4) | Excludes the impact of current and deferred PRT expense and other current income tax expense. |
($ millions)
|
2015
|
2014
|
2013
|
|||||||||
Exploration and Evaluation
|
||||||||||||
Net (proceeds) expenditures (2) (3) (4)
|
$
|
(805
|
)
|
$
|
1,190
|
$
|
(144
|
)
|
||||
Property, Plant and Equipment
|
||||||||||||
Net property (disposals) acquisitions (2) (3) (4)
|
(451
|
)
|
2,893
|
246
|
||||||||
Well drilling, completion and equipping
|
965
|
2,162
|
2,140
|
|||||||||
Production and related facilities
|
908
|
1,830
|
1,878
|
|||||||||
Capitalized interest and other (5)
|
102
|
106
|
120
|
|||||||||
Net (proceeds) expenditures
|
1,524
|
6,991
|
4,384
|
|||||||||
Total Exploration and Production
|
719
|
8,181
|
4,240
|
|||||||||
Oil Sands Mining and Upgrading
|
||||||||||||
Horizon Phases 2/3 construction costs
|
2,187
|
2,502
|
2,057
|
|||||||||
Sustaining capital
|
301
|
352
|
278
|
|||||||||
Turnaround costs
|
18
|
29
|
100
|
|||||||||
Capitalized interest and other (5)
|
224
|
227
|
157
|
|||||||||
Total Oil Sands Mining and Upgrading
|
2,730
|
3,110
|
2,592
|
|||||||||
Midstream
|
8
|
62
|
197
|
|||||||||
Abandonments (6)
|
370
|
346
|
207
|
|||||||||
Head office
|
26
|
45
|
38
|
|||||||||
Total net capital expenditures
|
$
|
3,853
|
$
|
11,744
|
$
|
7,274
|
||||||
By segment
|
||||||||||||
North America (2) (3) (4)
|
$
|
(119
|
)
|
$
|
7,500
|
$
|
4,026
|
|||||
North Sea
|
230
|
400
|
334
|
|||||||||
Offshore Africa (3)
|
608
|
281
|
(120
|
)
|
||||||||
Oil Sands Mining and Upgrading
|
2,730
|
3,110
|
2,592
|
|||||||||
Midstream
|
8
|
62
|
197
|
|||||||||
Abandonments (6)
|
370
|
346
|
207
|
|||||||||
Head office
|
26
|
45
|
38
|
|||||||||
Total
|
$
|
3,853
|
$
|
11,744
|
$
|
7,274
|
(1) | Net capital expenditures exclude adjustments related to differences between carrying amounts and tax values, and other fair value adjustments. |
(2) | Includes Business Combinations. |
(3) | Includes proceeds from the Company’s dispositions of properties. |
(4) | The above noted figures include non-cash share consideration of $985 million received from PrairieSky on the disposition of royalty income assets in 2015 and the impact of other pre-tax gains on the sale of other properties totaling $49 million recognized in 2015. |
(5) | Capitalized interest and other includes expenditures related to land acquisition and retention, seismic, and other adjustments. |
(6) | Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table. |
Drilling Activity (number of wells)
|
2015
|
2014
|
2013
|
Net successful natural gas wells
|
19
|
75
|
44
|
Net successful crude oil wells (1)
|
115
|
1,023
|
1,117
|
Dry wells
|
6
|
19
|
30
|
Stratigraphic test / service wells
|
166
|
437
|
384
|
Total
|
306
|
1,554
|
1,575
|
Success rate (excluding stratigraphic test / service wells)
|
96%
|
98%
|
97%
|
(1)
|
Includes bitumen wells.
|
($ millions, except ratios)
|
2015
|
2014
|
2013
|
|||||||||
Working capital (deficit) (1)
|
$
|
1,193
|
$
|
(673
|
)
|
$
|
(1,574
|
)
|
||||
Long-term debt (2) (3)
|
$
|
16,794
|
$
|
14,002
|
$
|
9,661
|
||||||
Shareholders’ equity
|
||||||||||||
Share capital
|
$
|
4,541
|
$
|
4,432
|
$
|
3,854
|
||||||
Retained earnings
|
22,765
|
24,408
|
21,876
|
|||||||||
Accumulated other comprehensive income
|
75
|
51
|
42
|
|||||||||
Total
|
$
|
27,381
|
$
|
28,891
|
$
|
25,772
|
||||||
Debt to book capitalization (3) (4)
|
38
|
%
|
33
|
%
|
27
|
%
|
||||||
Debt to market capitalization (3) (5)
|
34
|
%
|
26
|
%
|
20
|
%
|
||||||
After-tax return on average common
shareholders’ equity (6)
|
(2
|
%)
|
14
|
%
|
9
|
%
|
||||||
After-tax return on average capital employed (3) (7)
|
(1
|
%)
|
10
|
%
|
7
|
%
|
(1) | Calculated as current assets less current liabilities, excluding the current portion of long-term debt. |
(2) | Includes the current portion of long-term debt (2015 – $1,729 million; 2014 – $980 million; 2013 – $1,444 million). |
(3) | Long-term debt is stated at its carrying value, net of fair value adjustments, original issue discounts and premiums and transaction costs. |
(4) | Calculated as current and long-term debt; divided by the book value of common shareholders’ equity plus current and long-term debt. |
(5) | Calculated as current and long-term debt; divided by the market value of common shareholders’ equity plus current and long-term debt. |
(6) | Calculated as net earnings (loss) for the year; as a percentage of average common shareholders’ equity for the year. |
(7) | Calculated as net earnings (loss) plus after-tax interest and other financing expense for the year; as a percentage of average capital employed for the year. |
— | Monitoring cash flow from operations, which is the primary source of funds; |
— | Actively managing the allocation of maintenance and growth capital to ensure it is expended in a prudent and appropriate manner with flexibility to adjust to market conditions. In response to the decline in commodity prices, the Company continues to exercise its capital flexibility to address commodity price volatility and its impact on operating expenditures, capital commitments and long-term debt; |
— | Reviewing the Company's borrowing capacity: |
— | During 2015, the Company filed base shelf prospectuses that allow for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada and US$3,000 million of debt securities in the United States until November 2017. If issued, these securities may be offered separately or together, in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance; |
— | During 2015, the Company issued $500 million of series 2 medium-term notes, due August 2020, through the reopening of its previously issued 2.89% notes. In addition, the $1,500 million revolving syndicated credit facility was increased to $2,425 million and the maturity date was extended to June 2019 from June 2016. The $3,000 million revolving syndicated credit facility was reduced to $2,425 million and the maturity date was extended to June 2020 from June 2017. As a result, the Company's available liquidity increased by $350 million; |
— | The Company's borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million. The Company reserves capacity under its bank credit facilities for amounts outstanding under the US commercial paper program; |
— | During 2015, the Company extended its existing $1,000 million non-revolving term credit facility to January 2017. In addition, the Company entered into a new $1,500 million non-revolving term credit facility maturing April 2018. Both facilities were fully drawn at December 31, 2015. Subsequent to December 31, 2015, the Company prepaid $250 million of the borrowings outstanding under the $1,000 million non-revolving term credit facility and extended the facility to February 2019 from January 2017. Subsequent to December 31, 2015, the Company also entered into a new $125 million non-revolving term credit facility maturing February 2019, which was fully drawn. Borrowings under this new facility may be made by way of pricing referenced to Canadian dollar bankers’ acceptances or Canadian prime loans; |
— | Subsequent to December 31, 2015, the Company retained its investment grade ratings with both Standard & Poor’s Rating Services and DBRS Limited. In addition, Moody’s Investors Service, Inc. downgraded the Company’s credit ratings within the investment grade debt rating scale. The current changes in the Company’s credit ratings are not expected to have a significant impact on the Company’s access to debt capital markets, its US commercial paper program or on its overall cost of borrowing. |
— | Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages. Beginning in 2015, all of the Company's credit facilities are now subject to a financial covenant that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 0.65 to 1.0; and |
— | Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place to minimize the impact in the event of a default. |
($ millions)
|
2016
|
2017
|
2018
|
2019
|
2020
|
Thereafter
|
||||||||||||||||||
Product transportation and pipeline
|
$
|
423
|
$
|
341
|
$
|
303
|
$
|
261
|
$
|
246
|
$
|
1,304
|
||||||||||||
Offshore equipment operating leases and offshore drilling
|
$
|
247
|
$
|
93
|
$
|
71
|
$
|
22
|
$
|
–
|
$
|
–
|
||||||||||||
Long-term debt (1) (2)
|
$
|
1,730
|
$
|
2,522
|
$
|
2,899
|
$
|
1,353
|
$
|
1,427
|
$
|
6,935
|
||||||||||||
Interest and other financing expense (3)
|
$
|
649
|
$
|
564
|
$
|
478
|
$
|
437
|
$
|
408
|
$
|
4,608
|
||||||||||||
Office leases
|
$
|
42
|
$
|
42
|
$
|
42
|
$
|
43
|
$
|
42
|
$
|
193
|
||||||||||||
Other
|
$
|
141
|
$
|
38
|
$
|
48
|
$
|
1
|
$
|
–
|
$
|
–
|
(1) | Long-term debt represents principal repayments only and does not reflect original issue discounts and premiums or transaction costs. |
(2) | At December 31, 2015, the Company had US$500 million of debt securities at three-month LIBOR plus 0.375% due March 2016 and US$250 million of 6.00% debt securities due August 2016. These debt securities have been hedged by way of cross currency swaps with principal repayment amounts fixed at $555 million and $279 million respectively. |
(3) | Interest and other financing expense amounts represent the scheduled fixed rate and variable rate cash interest payments related to long-term debt. Interest on variable rate long-term debt was estimated based upon prevailing interest rates and foreign exchange rates as at December 31, 2015. |
Proved Reserves
|
Light and
Medium
Crude Oil
|
Primary
Heavy
Crude Oil
|
Pelican Lake
Heavy
Crude
Oil
|
Bitumen
(Thermal
Oil)
|
Synthetic
Crude Oil
|
Natural Gas
|
Natural Gas
Liquids
|
Barrels
of Oil
Equivalent
|
(MMbbl)
|
(MMbbl)
|
(MMbbl)
|
(MMbbl)
|
(MMbbl)
|
(Bcf)
|
(MMbbl)
|
(MMBOE)
|
|
December 31, 2014
|
445
|
229
|
274
|
1,217
|
2,158
|
6,001
|
188
|
5,511
|
Discoveries
|
1
|
–
|
–
|
–
|
–
|
14
|
2
|
5
|
Extensions
|
1
|
4
|
–
|
23
|
220
|
252
|
10
|
300
|
Infill Drilling
|
4
|
10
|
–
|
–
|
–
|
298
|
7
|
71
|
Improved Recovery
|
–
|
–
|
2
|
26
|
–
|
–
|
–
|
28
|
Acquisitions
|
5
|
4
|
–
|
7
|
–
|
414
|
8
|
93
|
Dispositions
|
(3)
|
–
|
–
|
–
|
–
|
(7)
|
–
|
(4)
|
Economic Factors
|
(7)
|
(3)
|
–
|
–
|
7
|
(392)
|
(6)
|
(74)
|
Technical Revisions
|
(26)
|
16
|
10
|
(1)
|
68
|
156
|
1
|
94
|
Production
|
(34)
|
(47)
|
(18)
|
(47)
|
(45)
|
(630)
|
(15)
|
(311)
|
December 31, 2015
|
386
|
213
|
268
|
1,225
|
2,408
|
6,106
|
195
|
5,713
|
Proved Plus Probable Reserves
|
Light and
Medium
Crude Oil
|
Primary
Heavy
Crude Oil
|
Pelican Lake
Heavy
Crude
Oil
|
Bitumen
(Thermal
Oil)
|
Synthetic
Crude Oil
|
Natural Gas
|
Natural Gas
Liquids
|
Barrels
of Oil
Equivalent
|
(MMbbl)
|
(MMbbl)
|
(MMbbl)
|
(MMbbl)
|
(MMbbl)
|
(Bcf)
|
(MMbbl)
|
(MMBOE)
|
|
December 31, 2014
|
660
|
317
|
395
|
2,312
|
3,593
|
8,138
|
258
|
8,891
|
Discoveries
|
1
|
–
|
–
|
–
|
–
|
17
|
2
|
6
|
Extensions
|
2
|
6
|
–
|
111
|
45
|
358
|
15
|
239
|
Infill Drilling
|
8
|
13
|
–
|
–
|
–
|
742
|
29
|
174
|
Improved Recovery
|
–
|
–
|
3
|
40
|
–
|
1
|
–
|
43
|
Acquisitions
|
6
|
5
|
–
|
9
|
–
|
515
|
10
|
116
|
Dispositions
|
(5)
|
–
|
–
|
–
|
–
|
(9)
|
–
|
(7)
|
Economic Factors
|
(8)
|
(3)
|
–
|
–
|
7
|
(501)
|
(8)
|
(96)
|
Technical Revisions
|
(12)
|
3
|
8
|
(18)
|
33
|
(123)
|
(8)
|
(14)
|
Production
|
(34)
|
(47)
|
(18)
|
(47)
|
(45)
|
(630)
|
(15)
|
(311)
|
December 31, 2015
|
618
|
294
|
388
|
2,407
|
3,633
|
8,508
|
283
|
9,041
|
— | The ability to find, produce and replace reserves, whether sourced from exploration, improved recovery or acquisitions, 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; |
— | Reservoir quality and uncertainty of reserve estimates; |
— | Volatility in the 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 and in mining, extracting or upgrading the Company’s bitumen products; |
— | Timing and success of integrating the business and operations of acquired properties and/or companies; |
— | Credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts, including derivative financial instruments and physical sales contracts as part of a hedging program; |
— | 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 all sales are predominantly based on US dollar denominated benchmarks; |
— | Environmental impact risk associated with exploration and development activities, including GHG; |
— | Geopolitical risks associated with changing governments or governmental policies, social instability and other political, economic or diplomatic developments in the regions where the Company has its operations; |
— | Future legislative and regulatory developments related to environmental regulation; |
— | Potential actions of governments, regulatory authorities and other stakeholders that may result in costs or restrictions in the jurisdictions where the Company has operations; |
— | Changing royalty regimes, including final resolution of the Alberta provincial royalty review; |
— | Business interruptions because of unexpected events such as fires or explosions whether caused by human error or nature, severe storms and other calamitous acts of nature, blowouts, freeze-ups, mechanical or equipment failures of facilities and infrastructure and other similar events affecting the Company or other parties whose operations or assets directly or indirectly impact the Company and that may or may not be financially recoverable; |
— | The ability to secure adequate transportation for products which could be affected by pipeline constraints, the construction by third parties of new or expansion of existing pipeline capacity and other factors; |
— | The access to markets for the Company’s products; 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 operated facilities; |
— | Continued evaluation of new technologies to reduce environmental impacts and support for Canada’s Oil Sands Innovation Alliance (“COSIA”); |
— | CO2 reduction programs including carbon capture at hydrotreaters, the injection of CO2 into tailings and for use in EOR; |
— | A program in place related to progressive reclamation and tailings management at Horizon including low fines mining; and |
— | Participation and support for the Joint Oil Sands Monitoring Program. |
($ millions)
|
2015
|
2014
|
||||||
Exploration and Production
|
||||||||
North America
|
$
|
1,114
|
$
|
2,012
|
||||
North Sea
|
975
|
1,169
|
||||||
Offshore Africa
|
266
|
255
|
||||||
Oil Sands Mining and Upgrading
|
594
|
783
|
||||||
Midstream
|
1
|
2
|
||||||
$
|
2,950
|
$
|
4,221
|
($ millions)
|
2016
|
|||
Exploration and Production
|
||||
North America natural gas and NGLs
|
$
|
160 – 195
|
||
North America crude oil
|
305 – 435
|
|||
International crude oil
|
450 – 495
|
|||
Thermal In Situ Oil Sands
|
||||
Primrose and future
|
120 – 140
|
|||
Kirby South
|
10 – 16
|
|||
Kirby North Phase 1
|
25 – 34
|
|||
Midstream and other
|
15 – 20
|
|||
Total Exploration and Production
|
$
|
1,085 – 1,335
|
||
Oil Sands Mining and Upgrading
|
||||
Project Capital
|
||||
Directive 74
|
50 – 60
|
|||
Phase 2B
|
1,180
|
|||
Phase 3
|
410 – 460
|
|||
Owner’s Costs and Other
|
250 – 290
|
|||
Total Project Capital
|
$
|
1,890 – 1,990
|
||
Technology and Phase 4
|
5
|
|||
Sustaining capital
|
280 – 310
|
|||
Turnarounds and reclamation
|
110 – 120
|
|||
Capitalized interest and other
|
130 – 140
|
|||
Total Oil Sands Mining and Upgrading
|
$
|
2,415 – 2,565
|
||
Total
|
$
|
3,500 – 3,900
|
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
|
$
|
198
|
$
|
0.18
|
$
|
194
|
$
|
0.18
|
||||||||
Natural gas – AECO C$0.10/Mcf
|
$
|
38
|
$
|
0.03
|
$
|
37
|
$
|
0.03
|
||||||||
Volume changes
|
||||||||||||||||
Crude oil – 10,000 bbl/d
|
$
|
72
|
$
|
0.07
|
$
|
27
|
$
|
0.02
|
||||||||
Natural gas – 10 MMcf/d
|
$
|
3
|
$
|
–
|
$
|
–
|
$
|
–
|
||||||||
Foreign currency rate change
|
||||||||||||||||
$0.01 change in US$ (1)
|
||||||||||||||||
Including financial derivatives
|
$
|
78 - 81
|
$
|
0.07
|
$
|
9
|
$
|
0.01
|
||||||||
Interest rate change – 1%
|
$
|
30
|
$
|
0.03
|
$
|
30
|
$
|
0.03
|
(1) | For details of financial instruments in place, refer to note 17 to the Company’s consolidated financial statements as at December 31, 2015. |
Q1
|
Q2
|
Q3
|
Q4
|
2015
|
2014
|
2013
|
||||||||
Crude oil and NGLs (bbl/d)
|
||||||||||||||
North America –
Exploration and Production |
432,419
|
375,040
|
397,892
|
395,008
|
399,982
|
390,814
|
343,699
|
|||||||
North America –
Oil Sands Mining and Upgrading |
134,166
|
96,607
|
131,779
|
129,050
|
122,911
|
110,571
|
100,284
|
|||||||
North Sea
|
23,036
|
20,330
|
22,387
|
23,110
|
22,216
|
17,380
|
18,334
|
|||||||
Offshore
Africa |
13,188
|
17,070
|
21,077
|
24,832
|
19,079
|
12,429
|
15,923
|
|||||||
Total
|
602,809
|
509,047
|
573,135
|
572,000
|
564,188
|
531,194
|
478,240
|
|||||||
Natural gas (MMcf/d)
|
||||||||||||||
North America
|
1,713
|
1,716
|
1,592
|
1,635
|
1,663
|
1,527
|
1,130
|
|||||||
North Sea
|
34
|
38
|
35
|
36
|
36
|
7
|
4
|
|||||||
Offshore
Africa |
24
|
25
|
26
|
32
|
27
|
21
|
24
|
|||||||
Total
|
1,771
|
1,779
|
1,653
|
1,703
|
1,726
|
1,555
|
1,158
|
|||||||
Barrels of oil equivalent (BOE/d)
|
||||||||||||||
North America –
Exploration and Production |
718,050
|
660,975
|
663,260
|
667,504
|
677,270
|
645,227
|
531,961
|
|||||||
North America –
Oil Sands Mining and Upgrading |
134,166
|
96,607
|
131,779
|
129,050
|
122,911
|
110,571
|
100,284
|
|||||||
North Sea
|
28,692
|
26,737
|
28,195
|
29,135
|
28,191
|
18,629
|
19,029
|
|||||||
Offshore
Africa |
17,145
|
21,228
|
25,467
|
30,111
|
23,529
|
15,983
|
19,888
|
|||||||
Total
|
898,053
|
805,547
|
848,701
|
855,800
|
851,901
|
790,410
|
671,162
|
Q1
|
Q2
|
Q3
|
Q4
|
2015
|
2014
|
2013
|
||||||||||||||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||||||||||||||||||
Sales price (2)
|
$
|
37.03
|
$
|
53.09
|
$
|
41.55
|
$
|
33.90
|
$
|
41.13
|
$
|
77.04
|
$
|
73.81
|
||||||||||||||
Transportation
|
2.46
|
2.80
|
2.56
|
2.61
|
2.60
|
2.41
|
2.22
|
|||||||||||||||||||||
Realized sales price, net of transportation
|
34.57
|
50.29
|
38.99
|
31.29
|
38.53
|
74.63
|
71.59
|
|||||||||||||||||||||
Royalties
|
3.83
|
5.91
|
4.09
|
3.49
|
4.30
|
12.99
|
11.13
|
|||||||||||||||||||||
Production expense
|
16.10
|
17.01
|
15.70
|
14.26
|
15.74
|
18.25
|
17.14
|
|||||||||||||||||||||
Netback
|
$
|
14.64
|
$
|
27.37
|
$
|
19.20
|
$
|
13.54
|
$
|
18.49
|
$
|
43.39
|
$
|
43.32
|
||||||||||||||
Natural gas ($/Mcf) (1)
|
||||||||||||||||||||||||||||
Sales price (2)
|
$
|
3.38
|
$
|
3.06
|
$
|
3.22
|
$
|
2.96
|
$
|
3.16
|
$
|
4.83
|
$
|
3.58
|
||||||||||||||
Transportation
|
0.36
|
0.38
|
0.39
|
0.38
|
0.38
|
0.27
|
0.28
|
|||||||||||||||||||||
Realized sales price, net of transportation
|
3.02
|
2.68
|
2.83
|
2.58
|
2.78
|
4.56
|
3.30
|
|||||||||||||||||||||
Royalties
|
0.12
|
0.05
|
0.11
|
0.10
|
0.10
|
0.38
|
0.18
|
|||||||||||||||||||||
Production expense
|
1.44
|
1.39
|
1.31
|
1.22
|
1.34
|
1.48
|
1.42
|
|||||||||||||||||||||
Netback
|
$
|
1.46
|
$
|
1.24
|
$
|
1.41
|
$
|
1.26
|
$
|
1.34
|
$
|
2.70
|
$
|
1.70
|
||||||||||||||
Barrels of oil equivalent ($/BOE) (1)
|
||||||||||||||||||||||||||||
Sales price (2)
|
$
|
30.57
|
$
|
38.85
|
$
|
33.46
|
$
|
27.79
|
$
|
32.60
|
$
|
58.48
|
$
|
56.46
|
||||||||||||||
Transportation
|
2.44
|
2.67
|
2.56
|
2.59
|
2.56
|
2.18
|
2.10
|
|||||||||||||||||||||
Realized sales price, net of transportation
|
28.13
|
36.18
|
30.90
|
25.20
|
30.04
|
56.30
|
54.36
|
|||||||||||||||||||||
Royalties
|
2.65
|
3.58
|
2.81
|
2.38
|
2.85
|
8.90
|
7.74
|
|||||||||||||||||||||
Production expense
|
13.20
|
13.39
|
12.68
|
11.55
|
12.70
|
14.67
|
14.24
|
|||||||||||||||||||||
Netback
|
$
|
12.28
|
$
|
19.21
|
$
|
15.41
|
$
|
11.27
|
$
|
14.49
|
$
|
32.73
|
$
|
32.38
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
Q1
|
Q2
|
Q3
|
Q4
|
2015
|
2014
|
2013
|
||||||||||||||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||||||||||||||||||
SCO sales price
|
$
|
56.75
|
$
|
73.05
|
$
|
60.66
|
$
|
57.49
|
$
|
61.39
|
$
|
100.27
|
$
|
100.75
|
||||||||||||||
Bitumen royalties (2)
|
1.01
|
0.99
|
1.32
|
0.99
|
1.08
|
5.77
|
5.11
|
|||||||||||||||||||||
Transportation
|
1.83
|
1.98
|
1.82
|
1.66
|
1.81
|
1.85
|
1.57
|
|||||||||||||||||||||
Adjusted cash
production costs |
29.73
|
29.25
|
27.04
|
28.56
|
28.61
|
37.18
|
40.57
|
|||||||||||||||||||||
Netback
|
$
|
24.18
|
$
|
40.83
|
$
|
30.48
|
$
|
26.28
|
$
|
29.89
|
$
|
55.47
|
$
|
53.50
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes. |
Q1
|
Q2
|
Q3
|
Q4
|
2015
|
2014
|
|||||||||||||||||||
TSX – C$
|
||||||||||||||||||||||||
Trading volume (thousands)
|
188,056
|
136,582
|
193,335
|
210,061
|
728,034
|
717,580
|
||||||||||||||||||
Share Price ($/share)
|
||||||||||||||||||||||||
High
|
$
|
40.80
|
$
|
42.46
|
$
|
34.01
|
$
|
34.51
|
$
|
42.46
|
$
|
49.57
|
||||||||||||
Low
|
$
|
31.20
|
$
|
33.61
|
$
|
25.01
|
$
|
25.32
|
$
|
25.01
|
$
|
31.00
|
||||||||||||
Close
|
$
|
38.82
|
$
|
33.90
|
$
|
25.99
|
$
|
30.22
|
$
|
30.22
|
$
|
35.92
|
||||||||||||
Market capitalization as at
December 31 ($ millions)
|
$
|
33,081
|
$
|
39,219
|
||||||||||||||||||||
Shares outstanding
(thousands) |
1,094,668
|
1,091,837
|
||||||||||||||||||||||
NYSE – US$
|
||||||||||||||||||||||||
Trading volume (thousands)
|
229,008
|
150,833
|
296,623
|
274,847
|
951,311
|
812,521
|
||||||||||||||||||
Share Price ($/share)
|
||||||||||||||||||||||||
High
|
$
|
32.57
|
$
|
34.46
|
$
|
27.23
|
$
|
26.24
|
$
|
34.46
|
$
|
46.65
|
||||||||||||
Low
|
$
|
26.13
|
$
|
26.93
|
$
|
18.94
|
$
|
19.12
|
$
|
18.94
|
$
|
26.53
|
||||||||||||
Close
|
$
|
30.71
|
$
|
27.16
|
$
|
19.45
|
$
|
21.83
|
$
|
21.83
|
$
|
30.88
|
||||||||||||
Market capitalization as at
December 31 ($ millions)
|
$
|
23,897
|
$
|
33,716
|
||||||||||||||||||||
Shares outstanding
(thousands) |
1,094,668
|
1,091,837
|
($ millions)
|
2016
|
2017
|
2018
|
2019
|
2020
|
Thereafter
|
||||||||||||||||||
Product transportation and pipeline
|
$
|
423
|
$
|
341
|
$
|
303
|
$
|
261
|
$
|
246
|
$
|
1,304
|
||||||||||||
Offshore equipment operating leases and offshore drilling
|
$
|
247
|
$
|
93
|
$
|
71
|
$
|
22
|
$
|
-
|
$
|
-
|
||||||||||||
Long-term debt (1)(2)
|
$
|
1,730
|
$
|
2,522
|
$
|
2,899
|
$
|
1,353
|
$
|
1,427
|
$
|
6,935
|
||||||||||||
Interest and other financing expense (3)
|
$
|
649
|
$
|
564
|
$
|
478
|
$
|
437
|
$
|
408
|
$
|
4,608
|
||||||||||||
Office leases
|
$
|
42
|
$
|
42
|
$
|
42
|
$
|
43
|
$
|
42
|
$
|
193
|
||||||||||||
Other
|
$
|
141
|
$
|
38
|
$
|
48
|
$
|
1
|
$
|
-
|
$
|
-
|
(1) | Long-term debt represents principal repayments only and does not reflect original issue discounts or transaction costs. |
(2) | At December 31, 2015, the Company had US$500 million of debt securities at three-month LIBOR plus 0.375% due March 2016 and US$250 million of 6.00% debt securities due August 2016. These debt securities have been hedged by way of cross currency swaps with principal repayment amounts fixed at $555 million and $279 million respectively. |
(3) | Interest and other financing expense amounts represent the scheduled fixed rate and variable rate cash interest payments related to long-term debt. Interest on variable rate long-term debt was estimated based upon prevailing interest rates and foreign exchange rates as at December 31, 2015. |
CANADIAN NATURAL RESOURCES LIMITED | |||
|
By:
|
SIGNED “STEVE W. LAUT” | |
Name: Steve W. Laut | |||
Title: President | |||
Reserves Certification
Strategic Advisory
Reservoir Characterization
& Integrated Services Field Development
& Capital Strategies Sproule Academy
|
Re:
|
Consent of Independent Petroleum Consultants
|
Sincerely,
|
SPROULE ASSOCIATES LIMITED
|
Original Signed by Nora T. Stewart, P.Eng.
|
Nora T. Stewart, P.Eng.
|
Vice President, Reserves Certification and Director
|
Reserves Certification
Strategic Advisory
Reservoir Characterization
& Integrated Services Field Development
& Capital Strategies Sproule Academy
|
Re:
|
Consent of Independent Petroleum Consultants
|
Sincerely,
|
SPROULE INTERNATIONAL LIMITED
|
Original Signed by Scott W. Pennell, P.Eng.
|
Scott W. Pennell, P.Eng.
|
Vice President, Engineering and Director
|
Re:
|
Consent of Independent Petroleum Consultants
|
Yours truly,
|
|
GLJ PETROLEUM CONSULTANTS LTD.
|
|
“Originally Signed By”
|
|
Tim R. Freeborn, P. Eng.
|
|
Vice President
|
1.
|
I have reviewed this annual report on Form 40-F of Canadian Natural Resources Limited;
|
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the issuer and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and |
5. | The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting. |
Dated this 24th day of March, 2016. | ||
SIGNED “STEVE W. LAUT” | ||
Steve W. Laut
|
||
President (Principal Executive Officer),
Canadian Natural Resources Limited
|
1.
|
I have reviewed this annual report on Form 40-F of Canadian Natural Resources Limited;
|
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the issuer and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusion about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and |
5. | The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting. |
Dated this 24th day of March, 2016. | ||
SIGNED “COREY B. BIEBER” | ||
Corey B. Bieber
|
||
Chief Financial Officer and Senior Vice-President, Finance (Principal Financial Officer),
Canadian Natural Resources Limited
|
1. | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
SIGNED “STEVE W. LAUT” | ||
Steve W. Laut
|
||
President (Principal Executive Officer),
Canadian Natural Resources Limited
|
1. | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
SIGNED “COREY B. BIEBER” | ||
Corey B. Bieber
|
||
Chief Financial Officer and Senior Vice-President, Finance (Principal Financial Officer),
Canadian Natural Resources Limited
|
Crude Oil and NGLs | Natural Gas | |||||||||||||||||||||||||||||||||
WTI Cushing
Oklahoma
|
WCS
|
Canadian
Light Sweet
|
Cromer
LSB
|
North Sea
Brent
|
Edmonton
C5+
|
|
Henry Hub
Louisiana |
AECO
|
BC Westcoast
Station 2 |
|||||||||||||||||||||||||
(US$/bbl)
|
(C$/bbl))
|
(C$/bbl)
|
(C$/bbl)
|
(US$/bbl)
|
(C$/bbl)
|
(US$/MMBtu)
|
(C$/MMBtu)
|
(C$/MMBtu)
|
||||||||||||||||||||||||||
50.28
|
46.83
|
58.81
|
57.06
|
55.57
|
62.57
|
2.63
|
2.68
|
1.75
|
— | For the years ended December 31, 2015, 2014, 2013, and 2012, the reports by GLJ Petroleum Consultants Ltd. covered 100% of the Company’s SCO reserves. With the inclusion of non-traditional resources within the definition of “oil and gas producing activities” in the SEC’s modernization of oil and gas reporting rules, effective January 1, 2010 these reserves volumes are included within the Company’s crude oil and natural gas reserves totals. |
— | For the years ended December 31, 2015, 2014, 2013, and 2012, the reports by Sproule Associates Limited and Sproule International Limited covered 100% of the Company’s crude oil, bitumen, natural gas and NGLs reserves. |
North America
|
||||||||||||||||||||||||||||
Crude Oil and NGLs (MMbbl)
|
Synthetic
Crude Oil
|
Bitumen(1)
|
Crude
Oil &
NGLs
|
North
America
Total
|
North
Sea |
Offshore
Africa
|
Total
|
|||||||||||||||||||||
Net Proved Reserves
|
||||||||||||||||||||||||||||
Reserves, December 31, 2012
|
1,974
|
999
|
370
|
3,343
|
235
|
85
|
3,663
|
|||||||||||||||||||||
Extensions and discoveries
|
–
|
76
|
13
|
89
|
–
|
–
|
89
|
|||||||||||||||||||||
Improved recovery
|
–
|
9
|
7
|
16
|
–
|
–
|
16
|
|||||||||||||||||||||
Purchases of reserves in place
|
–
|
–
|
8
|
8
|
6
|
–
|
14
|
|||||||||||||||||||||
Sales of reserves in place
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
|||||||||||||||||||||
Production
|
(35
|
)
|
(71
|
)
|
(33
|
)
|
(139
|
)
|
(7
|
)
|
(5
|
)
|
(151
|
)
|
||||||||||||||
Economic revisions due to prices
|
(10
|
)
|
(1
|
)
|
4
|
(7
|
)
|
–
|
(2
|
)
|
(9
|
)
|
||||||||||||||||
Revisions of prior estimates
|
(4
|
)
|
56
|
11
|
63
|
(2
|
)
|
2
|
63
|
|||||||||||||||||||
Reserves, December 31, 2013
|
1,925
|
1,068
|
380
|
3,373
|
232
|
80
|
3,685
|
|||||||||||||||||||||
Extensions and discoveries
|
–
|
112
|
11
|
123
|
–
|
–
|
123
|
|||||||||||||||||||||
Improved recovery
|
–
|
10
|
29
|
39
|
–
|
–
|
39
|
|||||||||||||||||||||
Purchases of reserves in place
|
–
|
–
|
54
|
54
|
–
|
–
|
54
|
|||||||||||||||||||||
Sales of reserves in place
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
|||||||||||||||||||||
Production
|
(38
|
)
|
(76
|
)
|
(40
|
)
|
(154
|
)
|
(6
|
)
|
(4
|
)
|
(164
|
)
|
||||||||||||||
Economic revisions due to prices
|
(89
|
)
|
11
|
–
|
(78
|
)
|
(9
|
)
|
1
|
(86
|
)
|
|||||||||||||||||
Revisions of prior estimates
|
(18
|
)
|
23
|
47
|
52
|
(6
|
)
|
–
|
46
|
|||||||||||||||||||
Reserves, December 31, 2014
|
1,780
|
1,148
|
481
|
3,409
|
211
|
77
|
3,697
|
|||||||||||||||||||||
Extensions and discoveries
|
208
|
25
|
10
|
243
|
–
|
–
|
243
|
|||||||||||||||||||||
Improved recovery
|
–
|
17
|
9
|
26
|
–
|
–
|
26
|
|||||||||||||||||||||
Purchases of reserves in place
|
–
|
9
|
11
|
20
|
–
|
–
|
20
|
|||||||||||||||||||||
Sales of reserves in place
|
–
|
–
|
(7
|
)
|
(7
|
)
|
–
|
–
|
(7
|
)
|
||||||||||||||||||
Production
|
(44
|
)
|
(84
|
)
|
(44
|
)
|
(172
|
)
|
(8
|
)
|
(6
|
)
|
(186
|
)
|
||||||||||||||
Economic revisions due to prices
|
339
|
153
|
5
|
497
|
(51
|
)
|
2
|
448
|
||||||||||||||||||||
Revisions of prior estimates
|
–
|
(5
|
)
|
6
|
1
|
(33
|
)
|
–
|
(32
|
)
|
||||||||||||||||||
Reserves, December 31, 2015
|
2,283
|
1,263
|
471
|
4,017
|
119
|
73
|
4,209
|
|||||||||||||||||||||
Net proved developed reserves
|
||||||||||||||||||||||||||||
December 31, 2012
|
1,612
|
348
|
295
|
2,255
|
66
|
55
|
2,376
|
|||||||||||||||||||||
December 31, 2013
|
1,621
|
431
|
298
|
2,350
|
59
|
30
|
2,439
|
|||||||||||||||||||||
December 31, 2014
|
1,631
|
401
|
358
|
2,390
|
39
|
21
|
2,450
|
|||||||||||||||||||||
December 31, 2015
|
2,194
|
411
|
341
|
2,946
|
3
|
41
|
2,990
|
(1) | Bitumen as defined by the SEC, “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 classified as bitumen. |
Natural Gas (Bcf)
|
North
America |
North
Sea |
Offshore
Africa |
Total |
||||||||||||
Net Proved Reserves
|
||||||||||||||||
Reserves, December 31, 2012
|
2,647
|
83
|
48
|
2,778
|
||||||||||||
Extensions and discoveries
|
126
|
–
|
–
|
126
|
||||||||||||
Improved recovery
|
62
|
–
|
–
|
62
|
||||||||||||
Purchases of reserves in place
|
99
|
14
|
–
|
113
|
||||||||||||
Sales of reserves in place
|
(1
|
)
|
–
|
–
|
(1
|
)
|
||||||||||
Production
|
(394
|
)
|
(1
|
)
|
(8
|
)
|
(403
|
)
|
||||||||
Economic revisions due to prices
|
489
|
–
|
(2
|
)
|
487
|
|||||||||||
Revisions of prior estimates
|
206
|
(4
|
)
|
(1
|
)
|
201
|
||||||||||
Reserves, December 31, 2013
|
3,234
|
92
|
37
|
3,363
|
||||||||||||
Extensions and discoveries
|
119
|
–
|
–
|
119
|
||||||||||||
Improved recovery
|
443
|
–
|
–
|
443
|
||||||||||||
Purchases of reserves in place
|
1,229
|
–
|
–
|
1,229
|
||||||||||||
Sales of reserves in place
|
–
|
–
|
–
|
–
|
||||||||||||
Production
|
(514
|
)
|
(2
|
)
|
(6
|
)
|
(522
|
)
|
||||||||
Economic revisions due to prices
|
576
|
(6
|
)
|
1
|
571
|
|||||||||||
Revisions of prior estimates
|
(70
|
)
|
–
|
2
|
(68
|
)
|
||||||||||
Reserves, December 31, 2014
|
5,017
|
84
|
34
|
5,135
|
||||||||||||
Extensions and discoveries
|
237
|
–
|
–
|
237
|
||||||||||||
Improved recovery
|
242
|
–
|
–
|
242
|
||||||||||||
Purchases of reserves in place
|
344
|
–
|
–
|
344
|
||||||||||||
Sales of reserves in place
|
(35
|
)
|
–
|
–
|
(35
|
)
|
||||||||||
Production
|
(587
|
)
|
(13
|
)
|
(9
|
)
|
(609
|
)
|
||||||||
Economic revisions due to prices
|
(935
|
)
|
(8
|
)
|
3
|
(940
|
)
|
|||||||||
Revisions of prior estimates
|
240
|
(25
|
)
|
(7
|
)
|
208
|
||||||||||
Reserves, December 31, 2015
|
4,523
|
38
|
21
|
4,582
|
||||||||||||
Net proved developed reserves
|
||||||||||||||||
December 31, 2012
|
2,060
|
58
|
39
|
2,157
|
||||||||||||
December 31, 2013
|
2,342
|
72
|
27
|
2,441
|
||||||||||||
December 31, 2014
|
3,585
|
64
|
22
|
3,671
|
||||||||||||
December 31, 2015
|
2,883
|
26
|
15
|
2,924
|
2015
|
||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Proved properties
|
$
|
84,883
|
$
|
7,414
|
$
|
5,173
|
$
|
97,470
|
||||||||
Unproved properties
|
2,500
|
–
|
86
|
2,586
|
||||||||||||
87,383
|
7,414
|
5,259
|
100,056
|
|||||||||||||
Less: accumulated depletion and depreciation
|
(37,641
|
)
|
(5,264
|
)
|
(3,659
|
)
|
(46,564
|
)
|
||||||||
Net capitalized costs
|
$
|
49,742
|
$
|
2,150
|
$
|
1,600
|
$
|
53,492
|
2014 | ||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Proved properties
|
$
|
82,554
|
$
|
6,182
|
$
|
3,858
|
$
|
92,594
|
||||||||
Unproved properties
|
3,426
|
–
|
131
|
3,557
|
||||||||||||
85,980
|
6,182
|
3,989
|
96,151
|
|||||||||||||
Less: accumulated depletion and depreciation
|
(33,750
|
)
|
(4,049
|
)
|
(2,890
|
)
|
(40,689
|
)
|
||||||||
Net capitalized costs
|
$
|
52,230
|
$
|
2,133
|
$
|
1,099
|
$
|
55,462
|
2013 | ||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Proved properties
|
$
|
73,176
|
$
|
5,200
|
$
|
3,356
|
$
|
81,732
|
||||||||
Unproved properties
|
2,570
|
–
|
39
|
2,609
|
||||||||||||
75,746
|
5,200
|
3,395
|
84,341
|
|||||||||||||
Less: accumulated depletion and depreciation
|
(29,729
|
)
|
(3,467
|
)
|
(2,551
|
)
|
(35,747
|
)
|
||||||||
Net capitalized costs
|
$
|
46,017
|
$
|
1,733
|
$
|
844
|
$
|
48,594
|
2015
|
||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Property acquisitions
|
||||||||||||||||
Proved
|
$
|
(556
|
)
|
$
|
–
|
$
|
–
|
$
|
(556
|
)
|
||||||
Unproved
|
(446
|
)
|
–
|
–
|
(446
|
)
|
||||||||||
Exploration
|
87
|
–
|
35
|
122
|
||||||||||||
Development
|
2,845
|
13
|
524
|
3,382
|
||||||||||||
Costs incurred
|
$
|
1,930
|
$
|
13
|
$
|
559
|
$
|
2,502
|
2014 | ||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Property acquisitions
|
||||||||||||||||
Proved
|
$
|
3,323
|
$
|
1
|
$
|
–
|
$
|
3,324
|
||||||||
Unproved
|
873
|
–
|
–
|
873
|
||||||||||||
Exploration
|
230
|
–
|
87
|
317
|
||||||||||||
Development
|
6,263
|
485
|
193
|
6,941
|
||||||||||||
Costs incurred
|
$
|
10,689
|
$
|
486
|
$
|
280
|
$
|
11,455
|
2013 | ||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Property acquisitions
|
||||||||||||||||
Proved
|
$
|
250
|
$
|
2
|
$
|
–
|
$
|
252
|
||||||||
Unproved
|
92
|
–
|
4
|
96
|
||||||||||||
Exploration
|
(2
|
)
|
–
|
25
|
23
|
|||||||||||
Development
|
6,152
|
297
|
97
|
6,546
|
||||||||||||
Costs incurred
|
$
|
6,492
|
$
|
299
|
$
|
126
|
$
|
6,917
|
2015
|
||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Crude oil and natural gas revenue, net of
royalties and blending costs |
$
|
10,362
|
$
|
623
|
$
|
460
|
$
|
11,445
|
||||||||
Production
|
(3,935
|
)
|
(544
|
)
|
(223
|
)
|
(4,702
|
)
|
||||||||
Transportation
|
(674
|
)
|
(61
|
)
|
(2
|
)
|
(737
|
)
|
||||||||
Depletion, depreciation and amortization (1)
|
(4,810
|
)
|
(388
|
)
|
(273
|
)
|
(5,471
|
)
|
||||||||
Asset retirement obligation accretion
|
(124
|
)
|
(39
|
)
|
(10
|
)
|
(173
|
)
|
||||||||
Petroleum revenue tax
|
–
|
243
|
–
|
243
|
||||||||||||
Income tax
|
(214
|
)
|
83
|
20
|
(111
|
)
|
||||||||||
Results of operations
|
$
|
605
|
$
|
(83
|
)
|
$
|
(28
|
)
|
$
|
494
|
(1)
|
Includes the impact of the derecognition of $96 million of exploration and evaluation assets related to the Company’s withdrawal from Block CI-514 in Côte d’Ivoire, Offshore Africa.
|
2014 | ||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Crude oil and natural gas revenue, net of
royalties and blending costs |
$
|
15,385
|
$
|
696
|
$
|
460
|
$
|
16,541
|
||||||||
Production
|
(4,533
|
)
|
(496
|
)
|
(212
|
)
|
(5,241
|
)
|
||||||||
Transportation
|
(593
|
)
|
(5
|
)
|
(1
|
)
|
(599
|
)
|
||||||||
Depletion, depreciation and amortization
|
(4,497
|
)
|
(269
|
)
|
(105
|
)
|
(4,871
|
)
|
||||||||
Asset retirement obligation accretion
|
(145
|
)
|
(38
|
)
|
(10
|
)
|
(193
|
)
|
||||||||
Petroleum revenue tax
|
–
|
147
|
–
|
147
|
||||||||||||
Income tax
|
(1,411
|
)
|
(22
|
)
|
(29
|
)
|
(1,462
|
)
|
||||||||
Results of operations
|
$
|
4,206
|
$
|
13
|
$
|
103
|
$
|
4,322
|
2013 | ||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Crude oil and natural gas revenue, net of
royalties and blending costs |
$
|
12,274
|
$
|
726
|
$
|
687
|
$
|
13,687
|
||||||||
Production
|
(3,918
|
)
|
(436
|
)
|
(191
|
)
|
(4,545
|
)
|
||||||||
Transportation
|
(483
|
)
|
(6
|
)
|
(1
|
)
|
(490
|
)
|
||||||||
Depletion, depreciation and amortization
|
(4,150
|
)
|
(552
|
)
|
(134
|
)
|
(4,836
|
)
|
||||||||
Asset retirement obligation accretion
|
(126
|
)
|
(35
|
)
|
(10
|
)
|
(171
|
)
|
||||||||
Petroleum revenue tax
|
–
|
188
|
–
|
188
|
||||||||||||
Income tax
|
(903
|
)
|
71
|
(88
|
)
|
(920
|
)
|
|||||||||
Results of operations
|
$
|
2,694
|
$
|
(44
|
)
|
$
|
263
|
$
|
2,913
|
— | Future production will include production not only from proved properties, but may also include production from probable and possible reserves; |
—
|
Future production of crude oil and natural gas from proved properties will differ from reserves estimated;
|
—
|
Future production rates will vary from those estimated;
|
—
|
Future prices and costs rather than 12-month average prices and costs as at the balance sheet date will apply;
|
— | Economic factors such as interest rates, income tax rates, regulatory and fiscal environments and operating conditions will change; |
—
|
Future estimated income taxes do not take into account the effects of future exploration and evaluation expenditures; and
|
—
|
Future development and asset retirement obligations will differ from those estimated.
|
2015
|
||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Future cash inflows
|
$
|
225,032
|
$
|
10,258
|
$
|
4,936
|
$
|
240,226
|
||||||||
Future production costs
|
(100,924
|
)
|
(5,973
|
)
|
(2,026
|
)
|
(108,923
|
)
|
||||||||
Future development costs and asset retirement
obligations |
(47,323
|
)
|
(5,228
|
)
|
(1,297
|
)
|
(53,848
|
)
|
||||||||
Future income taxes
|
(16,173
|
)
|
791
|
(430
|
)
|
(15,812
|
)
|
|||||||||
Future net cash flows
|
60,612
|
(152
|
)
|
1,183
|
61,643
|
|||||||||||
10% annual discount for timing of future
cash flows |
(34,050
|
)
|
213
|
(270
|
)
|
(34,107
|
)
|
|||||||||
Standardized measure of future net cash flows
|
$
|
26,562
|
$
|
61
|
$
|
913
|
$
|
27,536
|
2014 | ||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Future cash inflows
|
$
|
322,100
|
$
|
24,786
|
$
|
8,853
|
$
|
355,739
|
||||||||
Future production costs
|
(123,055
|
)
|
(9,708
|
)
|
(2,171
|
)
|
(134,934
|
)
|
||||||||
Future development costs and asset retirement
obligations |
(56,651
|
)
|
(8,515
|
)
|
(1,863
|
)
|
(67,029
|
)
|
||||||||
Future income taxes
|
(24,578
|
)
|
(4,816
|
)
|
(1,178
|
)
|
(30,572
|
)
|
||||||||
Future net cash flows
|
117,816
|
1,747
|
3,641
|
123,204
|
||||||||||||
10% annual discount for timing of future
cash flows |
(67,899
|
)
|
(813
|
)
|
(1,672
|
)
|
(70,384
|
)
|
||||||||
Standardized measure of future net cash flows
|
$
|
49,917
|
$
|
934
|
$
|
1,969
|
$
|
52,820
|
2013
|
||||||||||||||||
(millions of Canadian dollars)
|
North
America |
North
Sea |
Offshore
Africa |
Total
|
||||||||||||
Future cash inflows
|
$
|
290,892
|
$
|
26,378
|
$
|
9,146
|
$
|
326,416
|
||||||||
Future production costs
|
(116,984
|
)
|
(9,921
|
)
|
(2,560
|
)
|
(129,465
|
)
|
||||||||
Future development costs and asset retirement
obligations |
(51,749
|
)
|
(7,602
|
)
|
(1,840
|
)
|
(61,191
|
)
|
||||||||
Future income taxes
|
(20,384
|
)
|
(6,586
|
)
|
(1,154
|
)
|
(28,124
|
)
|
||||||||
Future net cash flows
|
101,775
|
2,269
|
3,592
|
107,636
|
||||||||||||
10% annual discount for timing of future
cash flows |
(65,063
|
)
|
(976
|
)
|
(1,755
|
)
|
(67,794
|
)
|
||||||||
Standardized measure of future net cash flows
|
$
|
36,712
|
$
|
1,293
|
$
|
1,837
|
$
|
39,842
|
(millions of Canadian dollars)
|
2015
|
2014
|
2013
|
|||||||||
Sales of crude oil and natural gas produced, net of
production costs |
$
|
(5,107
|
)
|
$
|
(10,321
|
)
|
$
|
(8,525
|
)
|
|||
Net changes in sales prices and production costs
|
(43,489
|
)
|
8,575
|
6,992
|
||||||||
Extensions, discoveries and improved recovery
|
3,201
|
4,428
|
2,304
|
|||||||||
Changes in estimated future development costs
|
5,204
|
(2,821
|
)
|
(1,536
|
)
|
|||||||
Purchases of proved reserves in place
|
624
|
4,425
|
638
|
|||||||||
Sales of proved reserves in place
|
(165
|
)
|
–
|
(1
|
)
|
|||||||
Revisions of previous reserve estimates
|
5,298
|
(1,306
|
)
|
622
|
||||||||
Accretion of discount
|
6,645
|
5,154
|
4,388
|
|||||||||
Changes in production timing and other
|
(3,452
|
)
|
5,895
|
2,341
|
||||||||
Net change in income taxes
|
5,957
|
(1,051
|
)
|
(1,115
|
)
|
|||||||
Net change
|
(25,284
|
)
|
12,978
|
6,108
|
||||||||
Balance – beginning of year
|
52,820
|
39,842
|
33,734
|
|||||||||
Balance – end of year
|
$
|
27,536
|
$
|
52,820
|
$
|
39,842
|
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