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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Canadian Natural Resources Ltd | NYSE:CNQ | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
-0.31 | -0.41% | 76.10 | 76.83 | 75.775 | 76.50 | 401,378 | 16:20:19 |
Exhibit Number
|
Description
|
|
|
99.1
|
Press Release dated March 3, 2016 |
Canadian Natural Resources Limited
Announces 2015 Fourth Quarter and Year
End Results
|
Canadian Natural Resources Limited
(Registrant)
|
|||
Date: March 9, 2016
|
By:
|
/s/ Paul M. Mendes | |
Paul M. Mendes | |||
Corporate Secretary | |||
Three Months Ended
|
Year Ended
|
||||||||||||||||||||
($ Millions, except per common share amounts)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Net earnings (loss)
|
$
|
131
|
$
|
(111
|
)
|
$
|
1,198
|
$
|
(637
|
)
|
$
|
3,929
|
|||||||||
Per common share |
– basic
|
$
|
0.12
|
$
|
(0.10
|
)
|
$
|
1.10
|
$
|
(0.58
|
)
|
$
|
3.60
|
||||||||
– diluted
|
$
|
0.12
|
$
|
(0.10
|
)
|
$
|
1.09
|
$
|
(0.58
|
)
|
$
|
3.58
|
|||||||||
Adjusted net earnings from operations (1)
|
$
|
(49
|
)
|
$
|
113
|
$
|
756
|
$
|
263
|
$
|
3,811
|
||||||||||
Per common share |
– basic
|
$
|
(0.04
|
)
|
$
|
0.10
|
$
|
0.69
|
$
|
0.24
|
$
|
3.49
|
|||||||||
– diluted
|
$
|
(0.04
|
)
|
$
|
0.10
|
$
|
0.69
|
$
|
0.24
|
$
|
3.47
|
||||||||||
Cash flow from operations (2)
|
$
|
1,379
|
$
|
1,533
|
$
|
2,368
|
$
|
5,785
|
$
|
9,587
|
|||||||||||
Per common share |
– basic
|
$
|
1.26
|
$
|
1.40
|
$
|
2.17
|
$
|
5.29
|
$
|
8.78
|
||||||||||
– diluted
|
$
|
1.26
|
$
|
1.40
|
$
|
2.16
|
$
|
5.28
|
$
|
8.74
|
|||||||||||
Capital expenditures, net of dispositions
|
$
|
(96
|
)
|
$
|
1,240
|
$
|
2,220
|
$
|
3,853
|
$
|
11,744
|
||||||||||
Daily production, before royalties
|
|||||||||||||||||||||
Natural gas (MMcf/d)
|
1,703
|
1,653
|
1,733
|
1,726
|
1,555
|
||||||||||||||||
Crude oil and NGLs (bbl/d)
|
572,000
|
573,135
|
572,040
|
564,188
|
531,194
|
||||||||||||||||
Equivalent production (BOE/d) (3)
|
855,800
|
848,701
|
860,920
|
851,901
|
790,410
|
(1) | Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation of this measure is discussed in the Management’s Discussion and Analysis (“MD&A”). |
(2) | Cash flow from operations is a non-GAAP measure that the Company considers key as it demonstrates the Company’s ability to fund capital reinvestment and debt repayment. The derivation of this measure is discussed in the MD&A. |
(3) | A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. |
§ | Canadian Natural demonstrated strong operational performance throughout 2015 despite significantly reducing its 2015 drilling programs for both crude oil and natural gas, as a result of sharply lower commodity pricing during the year. The Company’s 2015 drilling programs consisted of 306 net wells, an 80% decrease from its 2014 drilling programs of 1,554 net wells. Through a focused drilling program, strategic acquisitions and productivity enhancements, the Company was able to achieve record annual production volumes in 2015 of 851,901 BOE/d, representing an increase of 8% from 2014 levels. |
— | Record annual crude oil and NGL production volumes in 2015 averaged 564,188 bbl/d, representing an increase of 6% from 2014 levels, and within the Company’s 2015 annual guidance range of 555,000 bbl/d to 591,000 bbl/d. |
– | Horizon Oil Sands (“Horizon”), Canadian Natural’s world class oil sands mining and upgrading operations, achieved record annual production of 122,911 bbl/d of synthetic crude oil (“SCO”) in 2015, representing an 11% increase from 2014 levels. Through its safe, steady and reliable operations and a strong focus on continuous improvement, the Company’s annual operating costs averaged C$28.61/bbl (US$22.37/bbl equivalent) in 2015, a 23% reduction from 2014 levels. |
2
|
Canadian Natural Resources Limited
|
– | Thermal in situ oil sands (“thermal in situ”) annual production volumes reached record levels of 129,835 bbl/d, representing a 20% increase from 2014 volumes. During the year, the Kirby South steam assisted gravity drainage (“SAGD”) volumes advanced toward facility capacity as annual production volumes averaged 29,467 bbl/d with November 2015 volumes exceeding 41,000 bbl/d. The Company continues to enhance its focus on effective and efficient operations at its thermal in situ projects achieving annual operating costs of $10.43/bbl, a 17% reduction from 2014 levels. |
– | Pelican Lake annual production improved by 1% to 50,818 bbl/d from 2014 levels and achieved strong annual operating costs of $7.24/bbl, a 15% reduction from 2014. This leading edge polymer flood continues to perform with increasing production volumes and decreasing operating costs despite no drilling activity in the project since Q3/14. Canadian Natural leverages innovation and technology to create value through strong netbacks and robust economic returns. |
– | North America light crude oil and NGL annual production averaged a record level of 91,283 bbl/d in 2015, an increase of 2% from 2014 volumes. The increase in volumes result from strategic acquisitions offset by expected production declines. In 2015, 4 net wells were drilled compared to 101 net wells drilled in 2014. 2015 operating costs were reduced by 14% over 2014 levels. |
– | International Exploration & Production (“E&P”) annual production volumes increased to 41,295 bbl/d, representing a 39% increase from 2014 levels. North Sea improved volumes by 28% to 22,216 bbl/d while Offshore Africa’s infill drilling programs at Espoir and Baobab increased production by 54% to 19,079 bbl/d. 2015 International operating costs decreased by 19% from 2014 levels. |
— | The Company achieved record annual natural gas volumes of 1,726 MMcf/d, an increase of 11% from 2014 levels primarily as a result of opportunistic acquisitions and a focused liquids-rich natural gas drilling program. 2015 operating costs were reduced by 9% from 2014 levels. |
§ | During 2015, Canadian Natural continued to advance its Horizon expansion project, the major component of its transition to a longer life, low decline asset base. At December 31, 2015, physical progress of Horizon Phase 2B and 3 were 79% and 74% complete, respectively. Total Horizon expansion project capital costs continue to trend below budget estimate. |
§ | The start-up of Horizon Phase 2B is targeted in 7 months and will add 45,000 bbl/d of production capacity. Project capital in 2016 is targeted to be approximately $2 billion, the majority of which will be spent over the first nine months of 2016. In 2017, Horizon project capital costs are targeted to decline to approximately $1 billion for Phase 3 completion, which will add incremental production volumes of 80,000 bbl/d. At expansion completion, targeted for Q4/17, Canadian Natural targets total Horizon production volumes to average 250,000 bbl/d of SCO with operating costs trending below C$25.00/bbl (less than US$18.00/bbl equivalent). |
§ | The Company initially announced its original 2015 capital budget in November 2014 at $8.6 billion. As a result of steeply declining commodity prices, the Company responded quickly and revised the budget in January 2015 to $6.2 billion. Due to the significant capital flexibility within the Company’s program, three subsequent instances of cost cutting measures were implemented during the rest of 2015, ultimately reducing the gross capital program by approximately $3.4 billion to approximately $5.2 billion. As a result of an effective acquisitions and dispositions program in 2015, the largest transaction being the royalty land disposition to PrairieSky, the Company’s 2015 net expenditure program ended up totaling approximately $3.9 billion. |
§ | Despite the significant reduction in the Company’s 2015 original capital budget by $3.4 billion, 2015 total corporate production volumes increased to 851,901 BOE/d, representing an increase of 8% over 2014 levels. |
Canadian Natural Resources Limited
|
3
|
§ | In 2015, Canadian Natural continued to focus on effective and efficient operations reducing operating and capital costs throughout its business. As a result, the Company achieved over $1.1 billion in operating cost savings year-over-year based on 2014 unit rates versus 2015 unit rates, which is demonstrated by the product comparison in the table below. |
Operating Costs (Canadian $)
|
2015
|
2014
|
Year-over-Year
Percent
Reduction
|
|||||||||
North America Light Crude Oil and NGLs ($/bbl)
|
$
|
14.88
|
$
|
17.24
|
14%
|
|
||||||
Pelican Lake Heavy Crude Oil ($/bbl)
|
$
|
7.24
|
$
|
8.52
|
15%
|
|
||||||
Primary Heavy Crude Oil ($/bbl)
|
$
|
15.01
|
$
|
17.61
|
15%
|
|
||||||
Thermal Oil Sands In Situ ($/bbl)
|
$
|
10.43
|
$
|
12.61
|
17%
|
|
||||||
Horizon Oil Sands Mining and Upgrading ($/bbl) (1)
|
$
|
28.61
|
$
|
37.18
|
23%
|
|
||||||
North Sea Light Crude Oil ($/bbl)
|
$
|
63.67
|
$
|
74.04
|
14%
|
|
||||||
Offshore Africa Light Crude Oil ($/bbl)
|
$
|
33.32
|
$
|
43.97
|
24%
|
|
||||||
North America Natural Gas ($/Mcf)
|
$
|
1.27
|
$
|
1.42
|
11%
|
|
||||||
Total Overall ($/BOE)
|
$
|
15.18
|
$
|
18.29
|
17%
|
|
(1)
|
Horizon operating costs adjusted to reflect the impact of maintenance turnarounds.
|
§ | From 2014 to 2015, Canadian Natural attained drilling, completions, and facility cost reductions of a capital nature from 20% to 25% throughout its North America E&P operations. These reductions contributed to the Company’s ability to decrease its 2015 capital expenditure program by approximately $3.4 billion since November 2014. For 2016, the Company targets to achieve additional drilling and completions cost reductions from 5% to 10% and from 10% to 20% in facility cost reductions. |
§ | In December 2015, Canadian Natural completed the sale of a substantial portion of its royalty assets to PrairieSky for an aggregate price of $1.66 billion, consisting of $673 million in cash and the issuance of approximately 44.4 million PrairieSky common shares valued at $22.16 per common share. |
— | From its royalty assets, the Company divested a portion of its production volumes and added to its royalty portfolio through certain opportunistic acquisitions executed through 2015. The Company’s estimate of current production volumes attributed to its royalty portfolio is approximately 2,100 BOE/d, of which 1,100 BOE/d are Canadian Natural royalty volumes. |
— | Canadian Natural has agreed with PrairieSky to distribute, by no later than December 31, 2016, by way of a dividend, return of capital or otherwise (subject to regulatory approval and securities and tax regulations) sufficient PrairieSky Common Shares so that Canadian Natural, after such distribution, owns, directly or indirectly, less than 10% of the issued and outstanding shares of PrairieSky (the "Share Distribution"). Canadian Natural’s current intention is to distribute to its shareholders the majority of the Share Consideration on or after its next Annual and Special Meeting of Shareholders in May 2016, providing Canadian Natural shareholders with the opportunity to participate directly and indirectly in the combined royalty business of PrairieSky. Prior to the Share Distribution, Canadian Natural has agreed not to sell or otherwise dispose, or agree to sell or otherwise dispose, of the PrairieSky Common Shares comprising the Share Consideration, subject to certain exceptions. |
§ | Canadian Natural realized cash flow from operations in 2015 of approximately $5.8 billion. The decrease in 2015 from 2014 primarily reflects lower benchmark pricing partially offset by reduced operating costs and increased natural gas and crude oil sales volumes. |
§ | For 2015, the Company had a net loss of $637 million compared to net earnings of $3.9 billion in 2014. Adjusted net earnings from operations were $263 million in 2015 compared to $3.8 billion in 2014. Changes in adjusted net earnings primarily reflect the changes in cash flow from operations. |
4
|
Canadian Natural Resources Limited
|
§ | Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit facilities. As at December 31, 2015, the Company had in place bank credit facilities of $7,481 million, of which $3,495 million was available. |
— | During the first two quarters of 2015, the Company entered into a new $1,500 million non-revolving term credit facility maturing April 2018 and extended its two existing revolving syndicated term credit facilities to mature in June 2019 and June 2020. The result of the extension of the two revolving $2,425 million facilities netted an additional $350 million of liquidity. The Company’s credit facilities provide that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 65%. |
— | Subsequent to December 31, 2015, the Company prepaid $250 million of the borrowings from the $1,000 million non-revolving term credit facility and extended the facility to February 2019 from January 2017. In addition the Company entered into a new $125 million non-revolving term credit facility maturing February 2019, which was fully drawn. Borrowings under this facility may be made by way of pricing referenced to Canadian dollar bankers’ acceptances or Canadian prime loans. |
§ | Canadian Natural maintained a strong balance sheet with debt to book capitalization of 38% at December 31, 2015. |
§ | Subsequent to December 31, 2015, Standard & Poor’s Rating Services maintained the Company’s investment grade unsecured long-term and short-term credit ratings and DBRS Limited maintained the Company’s investment grade unsecured long-term credit rating. Additionally, Moody’s Investors Service, Inc. adjusted the Company’s credit ratings within the investment grade debt rating scale. |
§ | Canadian Natural declared a quarterly cash dividend on its common shares of C$0.23 per share payable on April 1, 2016. On an annualized basis, the dividend of C$0.92 per share remains unchanged from the previous annual dividend rate and reflects the Board of Director’s confidence in the Company’s cash flow. |
§ | Canadian Natural’s crude oil, SCO, bitumen, natural gas and NGL reserves were evaluated and reviewed by Independent Qualified Reserves Evaluators. The following highlights are based on the Company’s reserves using forecast prices and costs as at December 31, 2015 (all reserve values are Company Gross unless stated otherwise). |
— | Proved crude oil, SCO, bitumen and NGL reserves increased 4% to 4.70 billion barrels. Proved natural gas reserves increased 2% to 6.11 Tcf. Total proved reserves increased 4% to 5.71 billion BOE. |
— | Proved developed producing reserve additions and revisions, including acquisitions and dispositions, were 468 million barrels of crude oil, SCO, bitumen and NGL and 527 billion cubic feet of natural gas. The total proved developed producing reserves replacement ratio was 179%. |
— | Proved reserve additions and revisions, including acquisitions and dispositions, were 390 million barrels of crude oil, SCO, bitumen and NGL and 735 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio was 165%. The total proved BOE reserve life index is 21.5 years. |
— | Proved plus probable crude oil, SCO, bitumen and NGL reserves increased 1% to 7.62 billion barrels. Proved plus probable natural gas reserves increased 5% to 8.51 Tcf. Total proved plus probable reserves increased 2% to 9.04 billion BOE. |
— | Proved plus probable reserve additions and revisions, including acquisitions and dispositions, were 294 million barrels of crude oil, bitumen, SCO and NGL and 1.0 trillion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 148%. The total proved plus probable BOE reserve life index is 34.0 years. |
— | Corporate finding, development and acquisition (FD&A) costs, excluding changes in future development capital (FDC) and excluding proceeds from the royalty asset disposition, were strong at $9.96/BOE on a proved basis and $11.08/BOE on a proved plus probable basis. |
— | Corporate FD&A costs including changes in future development capital cannot be calculated since the decrease in FDC exceeds 2015 capital expenditures. However, North America FD&A costs including FDC, excluding Horizon, were $1.69/BOE on a proved basis and $0.27/BOE on a proved plus probable basis. |
— | The corporate net present values, at a 10% discount rate, of the future net revenue, before income taxes, was $65.2 billion on a proved basis which is a 5% decrease from the year end 2014 evaluation. On a proved plus probable basis, the net present value was $89.0 billion, a 5% decrease from year end 2014. |
Canadian Natural Resources Limited
|
5
|
§ | Canadian Natural continued to demonstrate solid operational performance during the fourth quarter of 2015. Total crude oil and NGL production was 572,000 bbl/d for Q4/15, which was comparable to Q4/14 and Q3/15 levels. Highlights of the Company’s quarterly operational performance include: |
— | Horizon quarterly production volumes averaged 129,050 bbl/d of SCO, 1% higher than Q4/14 levels and 2% lower than Q3/15 levels. Excellent operating costs of $28.56/bbl (US$21.39/bbl equivalent) were achieved at Horizon in Q4/15, a 17% decrease from Q4/14 levels. |
— | Thermal in situ quarterly production volumes were 135,135 bbl/d and Kirby South production increased to 33,746 bbl/d with November 2015 volumes at Kirby South exceeding 41,000 bbl/d. Q4/15 thermal in situ volumes increased by 14% and 1% from Q4/14 and Q3/15 levels respectively. |
— | International E&P Q4/15 production volumes improved to 47,942 bbl/d, an increase of 41% and 10% from Q4/14 and Q3/15 volumes respectively. North Sea volumes were 5% and 3% higher than Q4/14 and Q3/15 levels respectively, while Offshore Africa production improved 106% and 18% from Q4/14 and Q3/15 levels respectively. |
§ | Total natural gas production was 1,703 MMcf/d in Q4/15, a decrease of 2% from Q4/14 levels and an increase of 3% from Q3/15 levels. The decrease in production levels from the same quarter in the previous year reflect third party transmission pipeline restrictions in Northwest Alberta, as well as shut-ins of production volumes due to low natural gas pricing, which was largely driven by pipeline restrictions and partially offset by an increase in International quarterly natural gas production volumes. |
§ | During the fourth quarter, the Company continued to realize operating cost reductions. Operating costs achieved in Q4/15 were lower than 2015 average annual operating costs illustrating the Company’s ability to maintain its focus on enhancing the effectiveness and efficiency of its operating cost structures. |
Operating Costs (Canadian $)
|
2015
|
Q4/15
|
||||||
North America Light Crude Oil and NGLs ($/bbl)
|
$
|
14.88
|
$
|
13.55
|
||||
Pelican Lake Heavy Crude Oil ($/bbl)
|
$
|
7.24
|
$
|
6.75
|
||||
Primary Heavy Crude Oil ($/bbl)
|
$
|
15.01
|
$
|
13.90
|
||||
Thermal Oil Sands In Situ ($/bbl)
|
$
|
10.43
|
$
|
9.59
|
||||
Horizon Oil Sands Mining and Upgrading ($/bbl) (1)
|
$
|
28.61
|
$
|
28.56
|
||||
North Sea Light Crude Oil ($/bbl)
|
$
|
63.67
|
$
|
56.97
|
||||
Offshore Africa Light Crude Oil ($/bbl)
|
$
|
33.32
|
$
|
26.08
|
||||
North America Natural Gas ($/Mcf)
|
$
|
1.27
|
$
|
1.17
|
(1)
|
Horizon operating costs adjusted to reflect the impact of maintenance turnarounds.
|
§ | Capital expenditures, compared to budget, decreased by another $193 million in Q4/15 reflecting the Company’s ability to attain further drilling and completions cost reductions and further facility cost decreases throughout its North America E&P operations. |
§ | Canadian Natural generated cash flow from operations of approximately $1.4 billion in Q4/15 compared to approximately $2.4 billion in Q4/14 and $1.5 billion in Q3/15. The decrease in Q4/15 from Q4/14 primarily reflects lower benchmark pricing volumes partially offset by reduced operating costs. |
§ | Net earnings from operations for Q4/15 were $131 million, compared to net earnings of $1,198 million in Q4/14 and a net loss of $111 million in Q3/15. In Q4/15, adjusted net loss from operations was $49 million, compared to adjusted net earnings of $756 million in Q4/14 and $113 million in Q3/15. Changes in adjusted net earnings primarily reflect the changes in cash flow. |
6
|
Canadian Natural Resources Limited
|
§ | Canadian Natural develops its capital budgets to be flexible and nimble allowing the Company to proactively adapt to changing market conditions. Commensurate to this, the Company continues to progress its transition to a longer life, low decline asset base and maintain the strength of its balance sheet. For 2016, Canadian Natural targets its capital program to range from $3.5 billion to $3.9 billion, with overall 2016 production volumes targeted to be 2% less than 2015 annual production volumes, at the midpoint of guidance. The majority of the Company’s expenditure program, approximately $2 billion, is allocated to advancing the completion of Phases 2B and 3 of the Horizon expansion project. |
§ | Overall production in 2016 is targeted to be between 809,000 BOE/d and 868,000 BOE/d, with a product mix of approximately 64% crude oil and NGLs and 36% natural gas. |
§ | Overall crude oil and NGLs production for 2016 is targeted to range from 514,000 bbl/d to 563,000 bbl/d. |
§ | Canadian Natural’s total natural gas production for 2016 is targeted to range from 1,770 MMcf/d to 1,830 MMcf/d. |
§ | For 2016, the Company is committed to further enhancing its effective and efficient operations and is targeting to deliver further operating cost reductions in North America natural gas of approximately 6% and in its crude oil and NGL operating areas of approximately 8%, based on unit rates compared to 2015 levels. |
§ | As reflected by the Company’s 2016 capital budget, Canadian Natural is committed to advancing the completion of the Horizon expansion project, the major component of its transition to longer life, low decline asset base. The start-up of Horizon Phase 2B is targeted in 7 months and will add 45,000 bbl/d of production capacity. Project capital in 2016 is targeted to be approximately $2 billion, the majority of which will be spent over the first nine months of 2016. In 2017, Horizon project capital costs are targeted to decline in 2017 to approximately $1 billion for Phase 3 completion, which will add incremental production volumes of 80,000 bbl/d. At expansion completion, targeted for Q4/17, Canadian Natural targets total Horizon production volumes to average 250,000 bbl/d of SCO with operating costs trending below C$25.00/bbl (less than US$18.00/bbl equivalent). |
§ | Due to Canadian Natural’s large, high quality, and diversified asset base, the Company is able to achieve a strong overall 2016 corporate base production decline rate of approximately 15%, which assumes no development activity. |
§ | Details of Canadian Natural’s Q1/16 production guidance and 2016 annual production and capital guidance can be found on the Company’s website at http://www.cnrl.com/investor-information/corporate-guidance-and-hedging.html |
Canadian Natural Resources Limited
|
7
|
Year Ended Dec 31
|
||||||||||||||||
2015
|
2014
|
|||||||||||||||
(number of wells)
|
Gross
|
Net
|
Gross
|
Net
|
||||||||||||
Crude oil
|
133
|
115
|
1,112
|
1,023
|
||||||||||||
Natural gas
|
32
|
19
|
100
|
75
|
||||||||||||
Dry
|
6
|
6
|
21
|
19
|
||||||||||||
Subtotal
|
171
|
140
|
1,233
|
1,117
|
||||||||||||
Stratigraphic test / service wells
|
206
|
166
|
444
|
437
|
||||||||||||
Total
|
377
|
306
|
1,677
|
1,554
|
||||||||||||
Success rate (excluding stratigraphic test / service wells)
|
96%
|
|
98%
|
|
§ | As a direct result of the decrease in crude oil and natural gas pricing and other external events, the Company proactively reduced its 2015 drilling programs. Drilling activity, excluding strat/service wells, in Q4/15 consisted of 6 net wells compared to 349 net wells in Q4/14. The Company’s 2015 annual drilling program, excluding strat/service wells, consisted of 140 net wells, an 87% decrease from its 2014 drilling program of 1,117 net wells. |
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Crude oil and NGLs production (bbl/d)
|
259,873
|
264,709
|
291,002
|
270,147
|
283,012
|
|||||||||||||||
Net wells targeting crude oil
|
1
|
67
|
332
|
112
|
1,021
|
|||||||||||||||
Net successful wells drilled
|
1
|
63
|
324
|
106
|
1,003
|
|||||||||||||||
Success rate
|
100%
|
|
94%
|
|
98%
|
|
95%
|
|
98%
|
|
§ | Annual production volumes of North America crude oil and NGLs averaged 270,147 bbl/d in 2015, a decrease of 5% from 2014 levels. The year over year production decline reflects an 89% reduction in drilling activity from 1,021 net wells in 2014 to 112 net wells in 2015. |
§ | Record North America light crude oil and NGL annual production averaged 91,283 bbl/d in 2015, an increase of 2% from 2014 volumes. The increase in volumes result from strategic acquisitions offset by expected production declines. In 2015, 4 net wells were drilled compared to 101 net wells drilled in 2014. Operating costs were reduced by 14% from 2014 levels. |
§ | Pelican Lake operations averaged 50,818 bbl/d of annual heavy crude oil production, a 1% increase from 2014 levels. Canadian Natural continues to achieve success in developing, implementing and optimizing the leading edge polymer flood technology at Pelican Lake. |
§ | Primary heavy crude oil annual production averaged 128,046 bbl/d, a decrease of 11%, as expected, from 2014 levels. This production decline reflects the Company’s proactive decision to reduce its primary heavy crude oil drilling program by 88% year over year, and the Company’s prudent decision to shut-in approximately 4,300 bbl/d of primary heavy crude oil production volumes during 2015 as a result of unfavorable economic conditions. In 2015, 108 net wells were drilled compared to 896 net wells in 2014. |
8
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Bitumen production (bbl/d)
|
135,135
|
133,183
|
118,974
|
129,835
|
107,802
|
|||||||||||||||
Net wells targeting bitumen
|
–
|
–
|
–
|
3
|
15
|
|||||||||||||||
Net successful wells drilled
|
–
|
–
|
–
|
3
|
15
|
|||||||||||||||
Success rate
|
–
|
–
|
–
|
100%
|
|
100%
|
|
§ | In 2015, thermal in situ annual production achieved record volumes of 129,835 bbl/d, an increase of 20% from 2014 production volume levels. The increase in 2015 production reflects an 8% increase in production volumes from Primrose operations and an increase in Kirby South SAGD production volumes of 94%. |
§ | At Kirby South, production volumes averaged 29,467 bbl/d in 2015 as operations continued its ramp-up to the targeted 40,000 bbl/d of design capacity. In November 2015, production exceeded 41,000 bbl/d which contributed to quarterly volumes of 33,746 bbl/d. The reservoir continues to perform as expected with very good thermal efficiencies. |
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Natural gas production (MMcf/d)
|
1,635
|
1,592
|
1,705
|
1,663
|
1,527
|
|||||||||||||||
Net wells targeting natural gas
|
4
|
4
|
16
|
19
|
76
|
|||||||||||||||
Net successful wells drilled
|
4
|
4
|
16
|
19
|
75
|
|||||||||||||||
Success rate
|
100%
|
|
100%
|
|
100%
|
|
100%
|
|
99%
|
|
§ | North America natural gas annual production volumes averaged 1,663 MMcf/d for 2015, an increase of 9% from 2014 levels. The increase from 2014 to 2015 levels reflects strategic acquisitions partially offset by third party transportation restrictions in Alberta. |
§ | Operations at Septimus, Canadian Natural’s liquids-rich Montney natural gas play in British Columbia, continue to perform above expectations, with industry leading annual operating costs of $0.20/Mcfe in 2015. |
§ | Canadian Natural’s North America natural gas production volumes continued to be negatively impacted by transportation restrictions on the NOVA pipeline system in Q4/15 by 48 MMcf/d. In addition, the Company shut-in 50 MMcf/d of natural gas volumes related to low natural gas prices, driven largely by third party transmission pipeline restrictions in Northwest Alberta. |
§ | Volumes will continue to be negatively affected in 2016 as a result of TransCanada’s third party maintenance program on the NOVA pipeline system. Minor restrictions on the NOVA pipeline system are expected in Q1/16 and are reflected in Canadian Natural’s Q1/16 total natural gas production guidance. |
§ | North America natural gas annual operating costs were $1.27/Mcf in 2015, an 11% decrease from 2014 levels of $1.42/Mcf, reflecting a continued focus on cost optimization. |
Canadian Natural Resources Limited
|
9
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Crude oil production (bbl/d)
|
||||||||||||||||||||
North Sea
|
23,110
|
22,387
|
21,927
|
22,216
|
17,380
|
|||||||||||||||
Offshore Africa
|
24,832
|
21,077
|
12,047
|
19,079
|
12,429
|
|||||||||||||||
Natural gas production (MMcf/d)
|
||||||||||||||||||||
North Sea
|
36
|
35
|
10
|
36
|
7
|
|||||||||||||||
Offshore Africa
|
32
|
26
|
18
|
27
|
21
|
|||||||||||||||
Net wells targeting crude oil
|
1.2
|
2.6
|
1.0
|
5.8
|
4.5
|
|||||||||||||||
Net successful wells drilled
|
1.2
|
2.6
|
1.0
|
5.8
|
4.5
|
|||||||||||||||
Success rate
|
100%
|
|
100%
|
|
100%
|
|
100%
|
|
100%
|
|
§ | International crude oil production averaged 41,295 bbl/d during 2015, an increase of 39% from 2014 levels. The increase in 2015 production volumes over 2014 levels was primarily due to completion and tie-in of new wells at the Baobab and Espoir fields during the second half of 2015 and the reinstatement of production from both the Banff FPSO and the Tiffany platforms. |
§ | During 2015, at the Espoir field, Côte d’Ivoire, the Company drilled 5 gross producing wells and 1 injector well, adding net production volumes of approximately 6,900 bbl/d to date. In 2016, upon completion of the sixth gross producing well, no additional wells will be drilled in the program. The infill drilling program is currently tracking to below its original sanction costs, and above original sanction production. |
§ | During 2015, at the Baobab field, Côte d’Ivoire, the Company drilled 5 gross wells, adding net production volumes of approximately 13,400 bbl/d to date. In late December, the Baobab field was temporarily shut-in due to a riser failure, delaying first oil on the fifth gross well. After inspection of the riser system, production was reinstated in late January 2016. The drilling program is currently tracking to below its original sanction costs, and above original sanction production. |
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Synthetic crude oil production (bbl/d) (1)
|
129,050
|
131,779
|
128,090
|
122,911
|
110,571
|
(1) | The Company produces diesel for internal use at Horizon. Fourth quarter 2015 SCO production before royalties excludes 2,337 bbl/d of SCO consumed internally as diesel (third quarter 2015 – 2,058 bbl/d; fourth quarter 2014 – 1,288 bbl/d; year ended December 31, 2015 – 2,122 bbl/d; year ended December 31, 2014 – 545 bbl/d). |
§ | Horizon’s strong performance during 2015 resulted in record production volumes of 122,911 bbl/d of SCO, an increase of 11% from 2014 levels. The increase in production volumes reflect safe, steady and reliable operations performed throughout the year offset by the 15 day planned maintenance turnaround completed in Q2/15. |
§ | The Company achieved record annual operating costs at Horizon of $28.61/bbl (US$22.37/bbl equivalent) as a result of safe, steady and reliable operations and a focus on continuous improvement throughout 2015. In Q4/15, Horizon operating costs were $28.56/bbl (US$21.39/bbl equivalent), a 17% reduction from Q4/14 levels. |
§ | Canadian Natural continues to execute on its strategy to transition to a longer life, low decline asset base while delivering significant and sustainable production. Canadian Natural’s staged expansion of Horizon to 250,000 bbl/d of SCO production capacity continues to progress ahead of original schedule and below budget sanction. Canadian Natural has committed to approximately 85% of the Engineering, Procurement and Construction contracts with over 83% of the construction contracts awarded to date. |
10
|
Canadian Natural Resources Limited
|
§ | As at December 31, 2015, physical progress of the Horizon project is updated below. |
— | Directive 74 includes technological investment and research into tailings management. This project remains on track and is 59% physically complete. |
— | Phase 2B is 79% physically complete. This Phase expands the capacity of major components such as gas/oil hydrotreatment, froth treatment and the hydrogen plant. Due to continued strong construction performance on the Horizon expansion, certain components of this project will be tied-in during the mid-2016 turnaround. The start-up of Horizon Phase 2B is targeted in 7 months and will add 45,000 bbl/d of production capacity. |
— | Phase 3 is currently on budget and on schedule. This Phase is 74% physically complete, and includes the addition of extraction trains and combined hydrotreater. Phase 3 is targeted to increase production capacity by 80,000 bbl/d in Q4/17 and will result in additional reliability, redundancy and significant operating cost savings for the Horizon project. |
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Crude oil and NGLs pricing
|
||||||||||||||||||||
WTI benchmark price (US$/bbl) (1)
|
$
|
42.17
|
$
|
46.44
|
$
|
73.12
|
$
|
48.76
|
$
|
92.92
|
||||||||||
WCS blend differential from WTI (%) (2)
|
34%
|
|
28%
|
|
20%
|
|
28%
|
|
21%
|
|
||||||||||
SCO price (US$/bbl)
|
$
|
42.77
|
$
|
45.78
|
$
|
71.01
|
$
|
48.59
|
$
|
91.35
|
||||||||||
Condensate benchmark pricing (US$/bbl)
|
$
|
41.67
|
$
|
44.20
|
$
|
70.54
|
$
|
47.34
|
$
|
92.84
|
||||||||||
Average realized pricing before risk
management (C$/bbl) (3)
|
$
|
33.90
|
$
|
41.55
|
$
|
62.80
|
$
|
41.13
|
$
|
77.04
|
||||||||||
Natural gas pricing
|
||||||||||||||||||||
AECO benchmark price (C$/GJ)
|
$
|
2.51
|
$
|
2.65
|
$
|
3.80
|
$
|
2.62
|
$
|
4.19
|
||||||||||
Average realized pricing before risk
management (C$/Mcf) |
$
|
2.96
|
$
|
3.22
|
$
|
4.32
|
$
|
3.16
|
$
|
4.83
|
(1) | West Texas Intermediate (“WTI”). |
(2) | Western Canadian Select (“WCS”). |
(3) | Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities. |
Benchmark Pricing
|
WTI Pricing (US$/bbl) |
WCS Blend Differential
from WTI (%)
|
WCS Blend Differential
from WTI
(US$/bbl) |
SCO
Differential
from WTI
(US$/bbl)
|
Condensate Differential
from WTI
(US$/bbl) |
1 CAD=X USD
average
exchange rate
|
||||||||||||||||||
2015
|
||||||||||||||||||||||||
October
|
$
|
46.29
|
29.2%
|
|
$
|
(13.51
|
)
|
$
|
0.11
|
$
|
(0.54
|
)
|
$
|
0.7649
|
||||||||||
November
|
$
|
42.92
|
35.3%
|
|
$
|
(15.14
|
)
|
$
|
0.43
|
$
|
(1.12
|
)
|
$
|
0.7530
|
||||||||||
December
|
$
|
37.33
|
39.7%
|
|
$
|
(14.82
|
)
|
$
|
1.25
|
$
|
0.13
|
$
|
0.7297
|
|||||||||||
2016
|
||||||||||||||||||||||||
January
|
$
|
31.78
|
43.7%
|
|
$
|
(13.90
|
)
|
$
|
(0.03
|
)
|
$
|
2.85
|
$
|
0.7031
|
||||||||||
February*
|
$
|
30.62
|
46.7%
|
|
$
|
(14.32
|
)
|
$
|
(0.46
|
)
|
$
|
1.25
|
$
|
0.7250
|
||||||||||
March*
|
$
|
34.33
|
43.3%
|
|
$
|
(14.50
|
)
|
$
|
1.20
|
$
|
(1.27
|
)
|
$
|
0.7412
|
Canadian Natural Resources Limited
|
11
|
§ | The 2015 annual average WTI price was US$48.76/bbl as compared to US$92.92/bbl in 2014. Q4/15 WTI pricing averaged US$42.17/bbl as compared to US$73.12/bbl in Q4/14. Volatility in supply and demand factors and geopolitical events remain primary factors in the current WTI and Brent pricing environment. The Organization of the Petroleum Exporting Countries’ (“OPEC”) decision not to curtail oil production to offset the excess world supply resulted in a year over year decline in benchmark pricing. |
§ | The WCS differential to WTI averaged US$13.51/bbl or 28% in 2015 compared to US$19.41/bbl or 21% in 2014. In Q4/15, the WCS differential to WTI averaged US$14.48/bbl or 34% as compared to Q4/14 of US$14.26/bbl or 20%. February 2016 and March 2016 indications of the WCS blend differential of US$14.32/bbl or 47% and US$14.50/bbl or 43% respectively, are normal given the trending WTI price curve. Seasonal demand fluctuations, changes in transportation logistics and refinery utilization and shutdowns will continue to be reflected in WCS pricing. |
§ | Canadian Natural contributed approximately 183,000 bbl/d of its heavy crude oil stream to the WCS blend in 2015. The Company remains the largest contributor to the WCS blend, accounting for 49% of the total blend. |
§ | SCO pricing averaged US$48.59/bbl during 2015 compared to US$91.35/bbl in 2014, a 47% decrease. Q4/15 SCO pricing averaged US$42.77/bbl in Q4/15 as compared to US$71.01/bbl in Q4/14 and US$45.78/bbl in Q3/15. Fluctuations in SCO pricing during Q4/15 were a result of changes in WTI benchmark pricing and unplanned industry-wide upgrader outages. |
§ | AECO natural gas pricing in 2015 averaged $2.62/GJ, a decrease of 37% from 2014. Q4/15 AECO pricing averaged $2.51/GJ in Q4/15, decreasing by 34% and 5% from $3.80/GJ and $2.65/GJ in Q4/14 and Q3/15 respectively. In Q4/15, natural gas inventories reached new seasonal record levels as a result of warmer than normal winter temperatures in North America and higher US natural gas production relative to Q3/15 levels. 2015 natural gas pricing reflects lower demand due to warmer than normal winter temperatures in North America and higher than average storage levels relative to 2014. |
12
|
Canadian Natural Resources Limited
|
§ | The Company’s strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved production of 851,901 BOE/d for 2015, with approximately 97% of total production located in G8 countries. |
§ | Canadian Natural maintains significant financial stability and liquidity represented in part by bank credit facilities. As at December 31, 2015, the Company had in place bank credit facilities of $7,481 million, of which $3,495 million was available. |
— | During the first two quarters of 2015, the Company entered into a new $1,500 million non-revolving term credit facility maturing April 2018 and extended its two existing revolving syndicated term credit facilities to mature in June 2019 and June 2020. The result of the extension of the two revolving $2,425 million facilities netted an additional $350 million of liquidity. The Company’s credit facilities all state that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 65%. |
— | Subsequent to December 31, 2015, the Company prepaid $250 million of the borrowings from the $1,000 million non-revolving term credit facility and extended the facility to February 2019 from January 2017. In addition the Company entered into a new $125 million non-revolving term credit facility maturing February 2019, which was fully drawn. Borrowings under this facility may be made by way of pricing referenced to Canadian dollar bankers’ acceptances or Canadian prime loans. |
§ | Canadian Natural maintained a strong balance sheet with debt to book capitalization of 38% at December 31, 2015. |
§ | Subsequent to December 31, 2015, Standard & Poor’s Rating Services maintained the Company’s investment grade unsecured long-term and short-term credit ratings and DBRS Limited maintained the Company’s investment grade unsecured long-term credit rating. Additionally, Moody’s Investors Service, Inc. adjusted the Company’s credit ratings within the investment grade debt rating scale. |
§ | Canadian Natural declared a quarterly cash dividend on its common shares of C$0.23 per share payable on April 1, 2016. On an annualized basis, the dividend of C$0.92 per share remains unchanged from the previous annual dividend rate and reflects the Board of Director’s confidence in the Company’s cash flow. |
§ | The Company has a strong balance sheet and cash flow generation which enables it to weather volatility in commodity prices. Canadian Natural retains additional capital expenditure program flexibility to proactively adapt to changing market conditions. |
Canadian Natural Resources Limited
|
13
|
§ | Proved crude oil, SCO, bitumen and NGL reserves increased 4% to 4.70 billion barrels. Proved natural gas reserves increased 2% to 6.11 Tcf. Total proved reserves increased 4% to 5.71 billion BOE. |
§ | Proved plus probable crude oil, SCO, bitumen and NGL reserves increased 1% to 7.62 billion barrels. Proved plus probable natural gas reserves increased 5% to 8.51 Tcf. Total proved plus probable reserves increased 2% to 9.04 billion BOE. |
§ | Proved reserve additions and revisions, including acquisitions and dispositions, were 390 million barrels of crude oil, SCO, bitumen and NGL and 735 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio was 165%. The total proved BOE reserve life index is 21.5 years. |
§ | Proved plus probable reserve additions and revisions, including acquisitions and dispositions, were 294 million barrels of crude oil, bitumen, SCO and NGL and 1.0 trillion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 148%. The total proved plus probable BOE reserve life index is 34.0 years. |
§ | Proved undeveloped crude oil, SCO, bitumen and NGL reserves accounted for 25% of the corporate total proved reserves and proved undeveloped natural gas reserves accounted for 6% of the corporate total proved reserves. |
§ | Proved crude oil, bitumen and NGL reserves decreased 1% to 2.04 billion barrels. Proved natural gas reserves increased 3% to 6.04 Tcf. Total proved BOE increased slightly from 3.03 billion barrels to 3.05 billion barrels. |
§ | Proved plus probable crude oil, bitumen and NGL reserves increased 2% to 3.56 billion barrels. Proved plus probable natural gas reserves increased 5% to 8.34 Tcf. Total proved plus probable BOE increased 3% to 4.95 billion barrels. |
§ | Proved reserve additions and revisions, including acquisitions and dispositions, were 132 million barrels of crude oil, bitumen and NGL and 776 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio is 106%. The total proved BOE reserve life index in 14.5 years. |
§ | Proved plus probable reserve additions and revisions, including acquisitions and dispositions, were 225 million barrels of crude oil, bitumen and NGL and 1,019 billion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 160%. The total proved plus probable BOE reserve life index is 23.6 years. |
§ | Proved SCO reserves increased 12% to 2.41 billion barrels, primarily due to a revised mine plan allowing mining to a Total Volume : Bitumen In Place (“TV:BIP”) of 13 versus 12 in the original plan. |
§ | North Sea proved reserves decreased 24% to 165 million BOE. North Sea proved plus probable reserves decreased 8% to 300 million BOE. |
§ | Offshore Africa proved reserves decreased 9% to 95 million BOE. Offshore Africa proved plus probable reserves decreased 7% to 154 million BOE. |
14
|
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
|
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
|
Canadian Natural Resources Limited
|
15
|
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
|
16
|
Canadian Natural Resources Limited
|
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
|
Canadian Natural Resources Limited
|
17
|
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
|
18
|
Canadian Natural Resources Limited
|
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
|
Canadian Natural Resources Limited
|
19
|
(1) | Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests. |
(2) | Company Net reserves are working interest share after deduction of royalties and including any royalty interests. |
(3) | BOE values may not calculate due to rounding. |
(4) | Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserve estimates were provided by Sproule Associates Limited: |
2016
|
2017
|
2018
|
2019
|
2020
|
Average
annual increase thereafter |
|||||||||||||||||||
Crude oil and NGL
|
||||||||||||||||||||||||
WTI at Cushing (US$/bbl)
|
$
|
45.00
|
$
|
60.00
|
$
|
70.00
|
$
|
80.00
|
$
|
81.20
|
1.50
|
%
|
||||||||||||
Western Canada Select (C$/bbl)
|
$
|
45.26
|
$
|
57.96
|
$
|
65.88
|
$
|
75.11
|
$
|
77.03
|
1.50
|
%
|
||||||||||||
Canadian Light Sweet (C$/bbl)
|
$
|
55.20
|
$
|
69.00
|
$
|
78.43
|
$
|
89.41
|
$
|
91.71
|
1.50
|
%
|
||||||||||||
Cromer LSB (C$/bbl)
|
$
|
54.20
|
$
|
68.00
|
$
|
77.43
|
$
|
88.41
|
$
|
90.71
|
1.50
|
%
|
||||||||||||
Edmonton Pentanes+ (C$/bbl)
|
$
|
59.10
|
$
|
73.88
|
$
|
83.98
|
$
|
95.73
|
$
|
98.19
|
1.50
|
%
|
||||||||||||
North Sea Brent (US$/bbl)
|
$
|
45.00
|
$
|
60.00
|
$
|
70.00
|
$
|
80.00
|
$
|
81.20
|
1.50
|
%
|
||||||||||||
Natural gas
|
||||||||||||||||||||||||
AECO (C$/MMBtu)
|
$
|
2.25
|
$
|
2.95
|
$
|
3.42
|
$
|
3.91
|
$
|
4.20
|
1.50
|
%
|
||||||||||||
BC Westcoast Station 2 (C$/MMBtu)
|
$
|
1.45
|
$
|
2.55
|
$
|
3.02
|
$
|
3.51
|
$
|
3.80
|
1.50
|
%
|
||||||||||||
Henry Hub Louisiana (US$/MMBtu)
|
$
|
2.25
|
$
|
3.00
|
$
|
3.50
|
$
|
4.00
|
$
|
4.25
|
1.50
|
%
|
(5) | Reserve additions and revisions are comprised of all categories of Company Gross reserve changes, exclusive of production. |
(6) | Reserve replacement ratio is the Company Gross reserve additions and revisions, for the relevant reserve category, divided by the Company Gross production in the same period. |
(7) | Reserve Life Index is based on the amount for the relevant reserve category divided by the 2016 proved developed producing production forecast prepared by the Independent Qualified Reserve Evaluators. |
(8) | Finding, Development and Acquisition (FD&A) costs are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2015 by the sum of total additions and revisions for the relevant reserve category. |
(9) | FD&A costs including change in Future Development Capital (FDC) are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2015 and net change in FDC from December 31, 2014 to December 31, 2015 by the sum of total additions and revisions for the relevant reserve category. FDC excludes all abandonment and reclamation costs. |
(10) | A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. |
20
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
21
|
22
|
Canadian Natural Resources Limited
|
($ millions, except per common share amounts)
|
|||||||||||||||||||||
Three Months Ended
|
Year Ended
|
||||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||||
Product sales
|
$
|
2,963
|
$
|
3,316
|
$
|
4,850
|
$
|
13,167
|
$
|
21,301
|
|||||||||||
Net earnings (loss)
|
$
|
131
|
$
|
(111
|
)
|
$
|
1,198
|
$
|
(637
|
)
|
$
|
3,929
|
|||||||||
Per common share |
– basic
|
$
|
0.12
|
$
|
(0.10
|
)
|
$
|
1.10
|
$
|
(0.58
|
)
|
$
|
3.60
|
||||||||
– diluted
|
$
|
0.12
|
$
|
(0.10
|
)
|
$
|
1.09
|
$
|
(0.58
|
)
|
$
|
3.58
|
|||||||||
Adjusted net earnings (loss) from operations(1)
|
$
|
(49
|
)
|
$
|
113
|
$
|
756
|
$
|
263
|
$
|
3,811
|
||||||||||
Per common share |
– basic
|
$
|
(0.04
|
)
|
$
|
0.10
|
$
|
0.69
|
$
|
0.24
|
$
|
3.49
|
|||||||||
– diluted
|
$
|
(0.04
|
)
|
$
|
0.10
|
$
|
0.69
|
$
|
0.24
|
$
|
3.47
|
||||||||||
Cash flow from operations (2)
|
$
|
1,379
|
$
|
1,533
|
$
|
2,368
|
$
|
5,785
|
$
|
9,587
|
|||||||||||
Per common share |
– basic
|
$
|
1.26
|
$
|
1.40
|
$
|
2.17
|
$
|
5.29
|
$
|
8.78
|
||||||||||
– diluted
|
$
|
1.26
|
$
|
1.40
|
$
|
2.16
|
$
|
5.28
|
$
|
8.74
|
|||||||||||
Capital expenditures, net of dispositions
|
$
|
(96
|
)
|
$
|
1,240
|
$
|
2,220
|
$
|
3,853
|
$
|
11,744
|
(1) | Adjusted net earnings (loss) from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings from operations. The reconciliation “Adjusted Net Earnings from Operations” 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 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. |
Canadian Natural Resources Limited
|
23
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Net earnings (loss) as reported
|
$
|
131
|
$
|
(111
|
)
|
$
|
1,198
|
$
|
(637
|
)
|
$
|
3,929
|
||||||||
Share-based compensation, net of tax (1)
|
56
|
(87
|
)
|
(144
|
)
|
(46
|
)
|
66
|
||||||||||||
Unrealized risk management loss (gain), net of tax (2)
|
128
|
(24
|
)
|
(303
|
)
|
275
|
(339
|
)
|
||||||||||||
Unrealized foreign exchange loss , net of tax (3)
|
170
|
351
|
106
|
858
|
256
|
|||||||||||||||
Realized foreign exchange loss on repayment of US dollar debt securities,
net of tax (4)
|
–
|
–
|
36
|
–
|
36
|
|||||||||||||||
Loss from investments, net of tax (5)(6)
|
23
|
20
|
–
|
55
|
–
|
|||||||||||||||
Gains on disposition of properties and corporate acquisitions, net of tax (7)
|
(627
|
)
|
(36
|
)
|
(137
|
)
|
(663
|
)
|
(137
|
)
|
||||||||||
Derecognition of exploration and evaluation assets, net of tax (8)
|
70
|
–
|
–
|
70
|
–
|
|||||||||||||||
Effect of statutory tax rate and other legislative changes on deferred income
tax liabilities (9)
|
–
|
–
|
–
|
351
|
–
|
|||||||||||||||
Adjusted net earnings (loss) from operations
|
$
|
(49
|
)
|
$
|
113
|
$
|
756
|
$
|
263
|
$
|
3,811
|
(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 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. |
(4) | During the fourth quarter of 2014, the Company repaid US$500 million of 1.45% notes and US$350 million of 4.90% notes. |
(5) | The Company's investment in the 50% owned North West 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 North West 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 the fourth quarter of 2015, the Company recorded a pre-tax gain of $690 million ($627 million after-tax) related to the disposition of a number of North America royalty income assets. During the third quarter of 2015, the Company recorded a pre-tax gain of $49 million ($36 million after-tax) related to the disposition of a number of North America crude oil and natural gas properties. During the fourth quarter of 2014, the Company recorded an after-tax gain of $137 million related to the acquisition of certain producing crude oil and natural gas properties. |
(8) | In connection with the Company’s notice of withdrawal from Block CI-514 in Côte d’Ivoire, Offshore Africa in the fourth quarter of 2015, the Company derecognized $96 million ($70 million after-tax) of exploration and evaluation assets through depletion, depreciation and amortization expense. |
(9) | During the second quarter of 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12% effective July 1, 2015. As a result of this income tax rate increase, the Company’s deferred income tax liability was increased by $579 million. During the first quarter of 2015, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and the Petroleum Revenue Tax (“PRT”), and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in the Company’s deferred income tax liability of $228 million. |
24
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Net earnings (loss)
|
$
|
131
|
$
|
(111
|
)
|
$
|
1,198
|
$
|
(637
|
)
|
$
|
3,929
|
||||||||
Non-cash items:
|
||||||||||||||||||||
Depletion, depreciation and amortization
|
1,472
|
1,376
|
1,406
|
5,483
|
4,880
|
|||||||||||||||
Share-based compensation
|
56
|
(87
|
)
|
(144
|
)
|
(46
|
)
|
66
|
||||||||||||
Asset retirement obligation accretion
|
43
|
44
|
49
|
173
|
193
|
|||||||||||||||
Unrealized risk management loss (gain)
|
174
|
(29
|
)
|
(404
|
)
|
374
|
(451
|
)
|
||||||||||||
Unrealized foreign exchange loss
|
170
|
351
|
106
|
858
|
256
|
|||||||||||||||
Realized foreign exchange loss on repayment of US dollar
debt securities, net of tax
|
–
|
–
|
36
|
–
|
36
|
|||||||||||||||
Loss from investments
|
23
|
20
|
5
|
55
|
8
|
|||||||||||||||
Deferred income tax (recovery) expense
|
(33
|
)
|
18
|
253
|
231
|
807
|
||||||||||||||
Gains on disposition of properties and corporate
acquisitions
|
(690
|
)
|
(49
|
)
|
(137
|
)
|
(739
|
)
|
(137
|
)
|
||||||||||
Current income tax on disposition of properties
|
33
|
–
|
–
|
33
|
–
|
|||||||||||||||
Cash flow from operations
|
$
|
1,379
|
$
|
1,533
|
$
|
2,368
|
$
|
5,785
|
$
|
9,587
|
§ | 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. |
Canadian Natural Resources Limited
|
25
|
§ | 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; |
§ | lower natural gas sales volumes in the North America segment; and |
§ | lower realized risk management gains. |
§ | higher crude oil and NGLs sales volumes in the International segments; and |
§ | the impact of a weaker Canadian dollar relative to the US dollar. |
§ | lower crude oil and NGLs netbacks in the Exploration and Production segments; |
§ | lower realized SCO prices; and |
§ | lower crude oil and NGLs sales volumes in the North America segment. |
§ | higher crude oil and NGLs sales volumes in the International segments; and |
§ | the impact of a weaker Canadian dollar relative to the US dollar. |
($ millions, except per common share
amounts)
|
Dec 31
2015 |
Sep 30
2015 |
Jun 30
2015 |
Mar 31
2015 |
||||||||||||
Product sales
|
$
|
2,963
|
$
|
3,316
|
$
|
3,662
|
$
|
3,226
|
||||||||
Net earnings (loss)
|
$
|
131
|
$
|
(111
|
)
|
$
|
(405
|
)
|
$
|
(252
|
)
|
|||||
Net earnings (loss) per common share
|
||||||||||||||||
– basic
|
$
|
0.12
|
$
|
(0.10
|
)
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
|||||
– diluted
|
$
|
0.12
|
$
|
(0.10
|
)
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
|||||
($ millions, except per common share
amounts)
|
Dec 31
2014 |
Sep 30
2014 |
Jun 30
2014 |
Mar 31
2014 |
||||||||||||
Product sales
|
$
|
4,850
|
$
|
5,370
|
$
|
6,113
|
$
|
4,968
|
||||||||
Net earnings (loss)
|
$
|
1,198
|
$
|
1,039
|
$
|
1,070
|
$
|
622
|
||||||||
Net earnings (loss) per common share
|
||||||||||||||||
– basic
|
$
|
1.10
|
$
|
0.95
|
$
|
0.98
|
$
|
0.57
|
||||||||
– diluted
|
$
|
1.09
|
$
|
0.94
|
$
|
0.97
|
$
|
0.57
|
26
|
Canadian Natural Resources Limited
|
§ | 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 the West Texas Intermediate reference location at Cushing, Oklahoma (“WTI”) in North America and the impact of the differential between WTI and Dated 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 also 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. |
Canadian Natural Resources Limited
|
27
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
WTI benchmark price (US$/bbl)
|
$
|
42.17
|
$
|
46.44
|
$
|
73.12
|
$
|
48.76
|
$
|
92.92
|
||||||||||
Dated Brent benchmark price (US$/bbl)
|
$
|
43.59
|
$
|
50.39
|
$
|
75.99
|
$
|
52.40
|
$
|
98.85
|
||||||||||
WCS blend differential from WTI (US$/bbl)
|
$
|
14.48
|
$
|
13.21
|
$
|
14.26
|
$
|
13.51
|
$
|
19.41
|
||||||||||
WCS blend differential from WTI (%)
|
34%
|
|
28%
|
|
20%
|
|
28%
|
|
21%
|
|
||||||||||
SCO price (US$/bbl)
|
$
|
42.77
|
$
|
45.78
|
$
|
71.01
|
$
|
48.59
|
$
|
91.35
|
||||||||||
Condensate benchmark price (US$/bbl)
|
$
|
41.67
|
$
|
44.20
|
$
|
70.54
|
$
|
47.34
|
$
|
92.84
|
||||||||||
NYMEX benchmark price (US$/MMBtu)
|
$
|
2.28
|
$
|
2.77
|
$
|
3.95
|
$
|
2.67
|
$
|
4.37
|
||||||||||
AECO benchmark price (C$/GJ)
|
$
|
2.51
|
$
|
2.65
|
$
|
3.80
|
$
|
2.62
|
$
|
4.19
|
||||||||||
US/Canadian dollar average exchange rate
(US$)
|
$
|
0.7489
|
$
|
0.7640
|
$
|
0.8806
|
$
|
0.7820
|
$
|
0.9054
|
28
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Crude oil and NGLs (bbl/d)
|
||||||||||||||||||||
North America – Exploration and Production
|
395,008
|
397,892
|
409,976
|
399,982
|
390,814
|
|||||||||||||||
North America – Oil Sands Mining and
Upgrading (1)
|
129,050
|
131,779
|
128,090
|
122,911
|
110,571
|
|||||||||||||||
North Sea
|
23,110
|
22,387
|
21,927
|
22,216
|
17,380
|
|||||||||||||||
Offshore Africa
|
24,832
|
21,077
|
12,047
|
19,079
|
12,429
|
|||||||||||||||
572,000
|
573,135
|
572,040
|
564,188
|
531,194
|
||||||||||||||||
Natural gas (MMcf/d)
|
||||||||||||||||||||
North America
|
1,635
|
1,592
|
1,705
|
1,663
|
1,527
|
|||||||||||||||
North Sea
|
36
|
35
|
10
|
36
|
7
|
|||||||||||||||
Offshore Africa
|
32
|
26
|
18
|
27
|
21
|
|||||||||||||||
1,703
|
1,653
|
1,733
|
1,726
|
1,555
|
||||||||||||||||
Total barrels of oil equivalent (BOE/d)
|
855,800
|
848,701
|
860,920
|
851,901
|
790,410
|
|||||||||||||||
Product mix
|
||||||||||||||||||||
Light and medium crude oil and NGLs
|
16%
|
|
15%
|
|
15%
|
|
16%
|
|
15%
|
|
||||||||||
Pelican Lake heavy crude oil
|
6%
|
|
6%
|
|
6%
|
|
6%
|
|
6%
|
|
||||||||||
Primary heavy crude oil
|
14%
|
|
15%
|
|
17%
|
|
15%
|
|
18%
|
|
||||||||||
Bitumen (thermal oil)
|
16%
|
|
16%
|
|
14%
|
|
15%
|
|
14%
|
|
||||||||||
Synthetic crude oil (1)
|
15%
|
|
16%
|
|
15%
|
|
14%
|
|
14%
|
|
||||||||||
Natural gas
|
33%
|
|
32%
|
|
33%
|
|
34%
|
|
33%
|
|
||||||||||
Percentage of product sales (1) (2)
(excluding Midstream revenue) |
||||||||||||||||||||
Crude oil and NGLs
|
82%
|
|
83%
|
|
84%
|
|
82%
|
|
85%
|
|
||||||||||
Natural gas
|
18%
|
|
17%
|
|
16%
|
|
18%
|
|
15%
|
|
(1) | Fourth quarter 2015 SCO production before royalties excludes 2,337 bbl/d of SCO consumed internally as diesel (third quarter 2015 – 2,058 bbl/d; fourth quarter 2014 – 1,288 bbl/d; year ended December 31, 2015 – 2,122 bbl/d; year ended December 31, 2014 – 545 bbl/d). |
(2) | Net of blending costs and excluding risk management activities. |
Canadian Natural Resources Limited
|
29
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Crude oil and NGLs (bbl/d)
|
||||||||||||||||||||
North America – Exploration and Production
|
345,027
|
350,444
|
343,324
|
350,451
|
318,291
|
|||||||||||||||
North America – Oil Sands Mining and
Upgrading
|
127,968
|
129,355
|
121,292
|
121,208
|
104,095
|
|||||||||||||||
North Sea
|
23,054
|
22,325
|
21,881
|
22,164
|
17,313
|
|||||||||||||||
Offshore Africa
|
23,620
|
20,145
|
11,203
|
18,209
|
11,500
|
|||||||||||||||
519,669
|
522,269
|
497,700
|
512,032
|
451,199
|
||||||||||||||||
Natural gas (MMcf/d)
|
||||||||||||||||||||
North America
|
1,568
|
1,527
|
1,606
|
1,606
|
1,407
|
|||||||||||||||
North Sea
|
36
|
35
|
10
|
36
|
7
|
|||||||||||||||
Offshore Africa
|
30
|
25
|
16
|
25
|
18
|
|||||||||||||||
1,634
|
1,587
|
1,632
|
1,667
|
1,432
|
||||||||||||||||
Total barrels of oil equivalent (BOE/d)
|
792,083
|
786,734
|
769,775
|
789,799
|
689,893
|
30
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
31
|
(bbl)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
|||||||||
North Sea
|
835,806
|
450,023
|
368,808
|
|||||||||
Offshore Africa
|
1,271,170
|
1,353,011
|
461,997
|
|||||||||
2,106,976
|
1,803,034
|
830,805
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||||||||||
Sales price (2)
|
$
|
33.90
|
$
|
41.55
|
$
|
62.80
|
$
|
41.13
|
$
|
77.04
|
||||||||||
Transportation
|
2.61
|
2.56
|
2.15
|
2.60
|
2.41
|
|||||||||||||||
Realized sales price, net of transportation
|
31.29
|
38.99
|
60.65
|
38.53
|
74.63
|
|||||||||||||||
Royalties
|
3.49
|
4.09
|
9.05
|
4.30
|
12.99
|
|||||||||||||||
Production expense
|
14.26
|
15.70
|
18.69
|
15.74
|
18.25
|
|||||||||||||||
Netback
|
$
|
13.54
|
$
|
19.20
|
$
|
32.91
|
$
|
18.49
|
$
|
43.39
|
||||||||||
Natural gas ($/Mcf) (1)
|
||||||||||||||||||||
Sales price (2)
|
$
|
2.96
|
$
|
3.22
|
$
|
4.32
|
$
|
3.16
|
$
|
4.83
|
||||||||||
Transportation
|
0.38
|
0.39
|
0.28
|
0.38
|
0.27
|
|||||||||||||||
Realized sales price, net of transportation
|
2.58
|
2.83
|
4.04
|
2.78
|
4.56
|
|||||||||||||||
Royalties
|
0.10
|
0.11
|
0.24
|
0.10
|
0.38
|
|||||||||||||||
Production expense
|
1.22
|
1.31
|
1.39
|
1.34
|
1.48
|
|||||||||||||||
Netback
|
$
|
1.26
|
$
|
1.41
|
$
|
2.41
|
$
|
1.34
|
$
|
2.70
|
||||||||||
Barrels of oil equivalent ($/BOE) (1)
|
||||||||||||||||||||
Sales price (2)
|
$
|
27.79
|
$
|
33.46
|
$
|
48.23
|
$
|
32.60
|
$
|
58.48
|
||||||||||
Transportation
|
2.59
|
2.56
|
2.05
|
2.56
|
2.18
|
|||||||||||||||
Realized sales price, net of transportation
|
25.20
|
30.90
|
46.18
|
30.04
|
56.30
|
|||||||||||||||
Royalties
|
2.38
|
2.81
|
6.10
|
2.85
|
8.90
|
|||||||||||||||
Production expense
|
11.55
|
12.68
|
14.66
|
12.70
|
14.67
|
|||||||||||||||
Netback
|
$
|
11.27
|
$
|
15.41
|
$
|
25.42
|
$
|
14.49
|
$
|
32.73
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
32
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1) (2)
|
||||||||||||||||||||
North America
|
$
|
31.51
|
$
|
39.26
|
$
|
61.28
|
$
|
38.96
|
$
|
75.09
|
||||||||||
North Sea
|
$
|
57.50
|
$
|
62.28
|
$
|
83.32
|
$
|
65.13
|
$
|
106.63
|
||||||||||
Offshore Africa
|
$
|
53.37
|
$
|
65.31
|
$
|
68.90
|
$
|
63.13
|
$
|
97.81
|
||||||||||
Company average
|
$
|
33.90
|
$
|
41.55
|
$
|
62.80
|
$
|
41.13
|
$
|
77.04
|
||||||||||
Natural gas ($/Mcf) (1) (2)
|
||||||||||||||||||||
North America
|
$
|
2.73
|
$
|
2.99
|
$
|
4.22
|
$
|
2.91
|
$
|
4.72
|
||||||||||
North Sea
|
$
|
9.53
|
$
|
9.44
|
$
|
8.22
|
$
|
9.66
|
$
|
7.07
|
||||||||||
Offshore Africa
|
$
|
7.63
|
$
|
9.01
|
$
|
11.73
|
$
|
9.53
|
$
|
11.98
|
||||||||||
Company average
|
$
|
2.96
|
$
|
3.22
|
$
|
4.32
|
$
|
3.16
|
$
|
4.83
|
||||||||||
Company average ($/BOE) (1) (2)
|
$
|
27.79
|
$
|
33.46
|
$
|
48.23
|
$
|
32.60
|
$
|
58.48
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
Canadian Natural Resources Limited
|
33
|
(Quarterly Average)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
|||||||||
Wellhead Price (1) (2)
|
||||||||||||
Light and medium crude oil and NGLs ($/bbl)
|
$
|
36.45
|
$
|
40.88
|
$
|
62.27
|
||||||
Pelican Lake heavy crude oil ($/bbl)
|
$
|
33.25
|
$
|
39.54
|
$
|
62.33
|
||||||
Primary heavy crude oil ($/bbl)
|
$
|
31.14
|
$
|
39.97
|
$
|
62.47
|
||||||
Bitumen (thermal oil) ($/bbl)
|
$
|
27.92
|
$
|
37.46
|
$
|
58.64
|
||||||
Natural gas ($/Mcf)
|
$
|
2.73
|
$
|
2.99
|
$
|
4.22
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||||||||||
North America
|
$
|
3.71
|
$
|
4.34
|
$
|
9.76
|
$
|
4.57
|
$
|
13.74
|
||||||||||
North Sea
|
$
|
0.14
|
$
|
0.17
|
$
|
0.17
|
$
|
0.14
|
$
|
0.33
|
||||||||||
Offshore Africa
|
$
|
2.61
|
$
|
2.89
|
$
|
4.83
|
$
|
2.87
|
$
|
6.83
|
||||||||||
Company average
|
$
|
3.49
|
$
|
4.09
|
$
|
9.05
|
$
|
4.30
|
$
|
12.99
|
||||||||||
Natural gas ($/Mcf) (1)
|
||||||||||||||||||||
North America
|
$
|
0.10
|
$
|
0.11
|
$
|
0.23
|
$
|
0.09
|
$
|
0.36
|
||||||||||
Offshore Africa
|
$
|
0.44
|
$
|
0.41
|
$
|
0.99
|
$
|
0.46
|
$
|
1.74
|
||||||||||
Company average
|
$
|
0.10
|
$
|
0.11
|
$
|
0.24
|
$
|
0.10
|
$
|
0.38
|
||||||||||
Company average ($/BOE) (1)
|
$
|
2.38
|
$
|
2.81
|
$
|
6.10
|
$
|
2.85
|
$
|
8.90
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
34
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||||||||||
North America
|
$
|
11.45
|
$
|
11.64
|
$
|
14.38
|
$
|
12.51
|
$
|
14.98
|
||||||||||
North Sea
|
$
|
56.97
|
$
|
72.69
|
$
|
68.64
|
$
|
63.67
|
$
|
74.04
|
||||||||||
Offshore Africa
|
$
|
26.08
|
$
|
40.53
|
$
|
50.54
|
$
|
33.32
|
$
|
43.97
|
||||||||||
Company average
|
$
|
14.26
|
$
|
15.70
|
$
|
18.69
|
$
|
15.74
|
$
|
18.25
|
||||||||||
Natural gas ($/Mcf) (1)
|
||||||||||||||||||||
North America
|
$
|
1.17
|
$
|
1.25
|
$
|
1.34
|
$
|
1.27
|
$
|
1.42
|
||||||||||
North Sea
|
$
|
3.27
|
$
|
3.85
|
$
|
6.35
|
$
|
4.41
|
$
|
9.10
|
||||||||||
Offshore Africa
|
$
|
1.55
|
$
|
1.43
|
$
|
3.35
|
$
|
1.76
|
$
|
3.22
|
||||||||||
Company average
|
$
|
1.22
|
$
|
1.31
|
$
|
1.39
|
$
|
1.34
|
$
|
1.48
|
||||||||||
Company average ($/BOE) (1)
|
$
|
11.55
|
$
|
12.68
|
$
|
14.66
|
$
|
12.70
|
$
|
14.67
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited
|
35
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Expense ($ millions)
|
$
|
1,330
|
$
|
1,208
|
$
|
1,210
|
$
|
4,909
|
$
|
4,275
|
||||||||||
$/BOE (1)
|
$
|
19.95
|
$
|
18.25
|
$
|
17.76
|
$
|
18.50
|
$
|
17.27
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
36
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Expense ($ millions)
|
$
|
35
|
$
|
36
|
$
|
37
|
$
|
142
|
$
|
146
|
||||||||||
$/BOE (1)
|
$
|
0.54
|
$
|
0.54
|
$
|
0.56
|
$
|
0.54
|
$
|
0.59
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($/bbl)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
SCO sales price (1)
|
$
|
57.49
|
$
|
60.66
|
$
|
79.23
|
$
|
61.39
|
$
|
100.27
|
||||||||||
Bitumen value for royalty purposes (1) (2)
|
$
|
24.37
|
$
|
33.20
|
$
|
56.98
|
$
|
32.14
|
$
|
67.63
|
||||||||||
Bitumen royalties (1) (3)
|
$
|
0.99
|
$
|
1.32
|
$
|
4.44
|
$
|
1.08
|
$
|
5.77
|
||||||||||
Transportation
|
$
|
1.66
|
$
|
1.82
|
$
|
1.76
|
$
|
1.81
|
$
|
1.85
|
(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 period; divided by the corresponding SCO sales volumes. |
Canadian Natural Resources Limited
|
37
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions) |
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Cash production costs
|
$
|
344
|
$
|
321
|
$
|
395
|
$
|
1,332
|
$
|
1,609
|
||||||||||
Less: costs incurred during turnaround
periods
|
–
|
–
|
–
|
(45
|
)
|
(98
|
)
|
|||||||||||||
Adjusted cash production costs
|
$
|
344
|
$
|
321
|
$
|
395
|
$
|
1,287
|
$
|
1,511
|
||||||||||
Adjusted cash production costs, excluding
natural gas costs
|
$
|
326
|
$
|
300
|
$
|
368
|
$
|
1,212
|
$
|
1,395
|
||||||||||
Adjusted natural gas costs
|
18
|
21
|
27
|
75
|
116
|
|||||||||||||||
Adjusted cash production costs
|
$
|
344
|
$
|
321
|
$
|
395
|
$
|
1,287
|
$
|
1,511
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($/bbl) (1)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Adjusted cash production costs, excluding
natural gas costs
|
$
|
27.10
|
$
|
25.28
|
$
|
31.97
|
$
|
26.95
|
$
|
34.33
|
||||||||||
Adjusted natural gas costs
|
1.46
|
1.76
|
2.37
|
1.66
|
2.85
|
|||||||||||||||
Adjusted cash production costs
|
$
|
28.56
|
$
|
27.04
|
$
|
34.34
|
$
|
28.61
|
$
|
37.18
|
||||||||||
Sales (bbl/d)
|
130,990
|
129,033
|
125,092
|
123,231
|
111,351
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions, except per bbl amounts) |
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Depletion, depreciation and amortization
|
$
|
139
|
$
|
165
|
$
|
194
|
$
|
562
|
$
|
596
|
||||||||||
Less: depreciation incurred during
turnaround period
|
–
|
–
|
–
|
(5
|
)
|
(28
|
)
|
|||||||||||||
Adjusted depletion, depreciation and
amortization
|
$
|
139
|
$
|
165
|
$
|
194
|
$
|
557
|
$
|
568
|
||||||||||
$/bbl (1)
|
$
|
11.48
|
$
|
13.95
|
$
|
16.85
|
$
|
12.37
|
$
|
13.97
|
(1) | Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods. |
38
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions, except per bbl amounts) |
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Expense
|
$
|
8
|
$
|
8
|
$
|
12
|
$
|
31
|
$
|
47
|
||||||||||
$/bbl (1)
|
$
|
0.64
|
$
|
0.65
|
$
|
1.02
|
$
|
0.69
|
$
|
1.16
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions) |
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Revenue
|
$
|
33
|
$
|
33
|
$
|
29
|
$
|
136
|
$
|
120
|
||||||||||
Production expense
|
7
|
7
|
7
|
32
|
34
|
|||||||||||||||
Midstream cash flow
|
26
|
26
|
22
|
104
|
86
|
|||||||||||||||
Depreciation
|
3
|
3
|
2
|
12
|
9
|
|||||||||||||||
Equity loss from Redwater Partnership
|
12
|
20
|
5
|
44
|
8
|
|||||||||||||||
Segment earnings before taxes
|
$
|
11
|
$
|
3
|
$
|
15
|
$
|
48
|
$
|
69
|
Canadian Natural Resources Limited
|
39
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts) |
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Expense
|
$
|
93
|
$
|
93
|
$
|
100
|
$
|
390
|
$
|
367
|
||||||||||
$/BOE (1)
|
$
|
1.18
|
$
|
1.20
|
$
|
1.26
|
$
|
1.26
|
$
|
1.28
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Expense (recovery)
|
$
|
56
|
$
|
(87
|
)
|
$
|
(144
|
)
|
$
|
(46
|
)
|
$
|
66
|
40
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts and
interest rates)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Expense, gross
|
$
|
133
|
$
|
142
|
$
|
141
|
$
|
566
|
$
|
527
|
||||||||||
Less: capitalized interest
|
60
|
64
|
57
|
244
|
204
|
|||||||||||||||
Expense, net
|
$
|
73
|
$
|
78
|
$
|
84
|
$
|
322
|
$
|
323
|
||||||||||
$/BOE (1)
|
$
|
0.93
|
$
|
1.00
|
$
|
1.05
|
$
|
1.04
|
$
|
1.12
|
||||||||||
Average effective interest rate
|
3.8%
|
|
3.8%
|
|
4.0%
|
|
3.9%
|
|
3.9%
|
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Crude oil and NGLs financial instruments
|
$
|
(218
|
)
|
$
|
(173
|
)
|
$
|
(284
|
)
|
$
|
(599
|
)
|
$
|
(284
|
)
|
|||||
Natural gas financial instruments
|
–
|
–
|
1
|
–
|
34
|
|||||||||||||||
Foreign currency contracts
|
(37
|
)
|
(90
|
)
|
(52
|
)
|
(244
|
)
|
(99
|
)
|
||||||||||
Realized gain
|
(255
|
)
|
(263
|
)
|
(335
|
)
|
(843
|
)
|
(349
|
)
|
||||||||||
Crude oil and NGLs financial instruments
|
189
|
(12
|
)
|
(403
|
)
|
394
|
(427
|
)
|
||||||||||||
Natural gas financial instruments
|
–
|
–
|
(3
|
)
|
–
|
(3
|
)
|
|||||||||||||
Foreign currency contracts
|
(15
|
)
|
(17
|
)
|
2
|
(20
|
)
|
(21
|
)
|
|||||||||||
Unrealized loss (gain)
|
174
|
(29
|
)
|
(404
|
)
|
374
|
(451
|
)
|
||||||||||||
Net gain
|
$
|
(81
|
)
|
$
|
(292
|
)
|
$
|
(739
|
)
|
$
|
(469
|
)
|
$
|
(800
|
)
|
Canadian Natural Resources Limited
|
41
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Net realized (gain) loss
|
$
|
(5
|
)
|
$
|
(28
|
)
|
$
|
18
|
$
|
(97
|
)
|
$
|
47
|
|||||||
Net unrealized loss (1)
|
170
|
351
|
106
|
858
|
256
|
|||||||||||||||
Net loss
|
$
|
165
|
$
|
323
|
$
|
124
|
$
|
761
|
$
|
303
|
(1) | Amounts are reported net of the hedging effect of cross currency swaps. |
42
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions, except income tax rates)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
North America (1)
|
$
|
(66
|
)
|
$
|
65
|
$
|
123
|
$
|
86
|
$
|
702
|
|||||||||
North Sea
|
(18
|
)
|
(16
|
)
|
(23
|
)
|
(117
|
)
|
(68
|
)
|
||||||||||
Offshore Africa
|
5
|
5
|
8
|
17
|
43
|
|||||||||||||||
PRT recovery – North Sea
|
(71
|
)
|
(61
|
)
|
(86
|
)
|
(258
|
)
|
(273
|
)
|
||||||||||
Other taxes
|
2
|
2
|
5
|
11
|
23
|
|||||||||||||||
Current income tax (recovery) expense
|
(148
|
)
|
(5
|
)
|
27
|
(261
|
)
|
427
|
||||||||||||
Deferred income tax expense
|
(1
|
)
|
8
|
254
|
216
|
681
|
||||||||||||||
Deferred PRT (recovery) expense – North Sea
|
(32
|
)
|
10
|
(1
|
)
|
15
|
126
|
|||||||||||||
Deferred income tax (recovery) expense
|
(33
|
)
|
18
|
253
|
231
|
807
|
||||||||||||||
$
|
(181
|
)
|
$
|
13
|
$
|
280
|
$
|
(30
|
)
|
$
|
1,234
|
|||||||||
Income tax rate and other legislative
changes (2) (3)
|
–
|
–
|
–
|
(351
|
)
|
–
|
||||||||||||||
$
|
(181
|
)
|
$
|
13
|
$
|
280
|
$
|
(381
|
)
|
$
|
1,234
|
|||||||||
Effective income tax rate on adjusted net
earnings from operations (4)
|
59%
|
|
28%
|
|
26%
|
|
61%
|
|
25%
|
|
(1) | Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments. |
(2) | During the second quarter of 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12% effective July 1, 2015. As a result of this income tax rate increase, the Company’s deferred income tax liability was increased by $579 million. |
(3) | During the first quarter of 2015, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and the Petroleum Revenue Tax (“PRT”), and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in the Company’s deferred income tax liability of $228 million. |
(4) | Excludes the impact of current and deferred PRT expense and other current income tax expense. |
Canadian Natural Resources Limited
|
43
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
($ millions)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Exploration and Evaluation
|
||||||||||||||||||||
Net (proceeds) expenditures (2) (3) (6)
|
$
|
(885
|
)
|
$
|
5
|
$
|
97
|
$
|
(805
|
)
|
$
|
1,190
|
||||||||
Property, Plant and Equipment
|
||||||||||||||||||||
Net property (disposals) acquisitions (2) (3) (6)
|
(443
|
)
|
(70
|
)
|
72
|
(451
|
)
|
2,893
|
||||||||||||
Well drilling, completion and equipping
|
237
|
237
|
582
|
965
|
2,162
|
|||||||||||||||
Production and related facilities
|
154
|
191
|
482
|
908
|
1,830
|
|||||||||||||||
Capitalized interest and other (4)
|
26
|
23
|
28
|
102
|
106
|
|||||||||||||||
Net (proceeds) expenditures
|
(26
|
)
|
381
|
1,164
|
1,524
|
6,991
|
||||||||||||||
Total Exploration and Production
|
(911
|
)
|
386
|
1,261
|
719
|
8,181
|
||||||||||||||
Oil Sands Mining and Upgrading
|
||||||||||||||||||||
Horizon Phases 2/3 construction costs
|
578
|
668
|
739
|
2,187
|
2,502
|
|||||||||||||||
Sustaining capital
|
55
|
64
|
83
|
301
|
352
|
|||||||||||||||
Turnaround costs
|
5
|
3
|
8
|
18
|
29
|
|||||||||||||||
Capitalized interest and other (4)
|
68
|
42
|
32
|
224
|
227
|
|||||||||||||||
Total Oil Sands Mining and Upgrading
|
706
|
777
|
862
|
2,730
|
3,110
|
|||||||||||||||
Midstream
|
2
|
2
|
(16
|
)
|
8
|
62
|
||||||||||||||
Abandonments (5)
|
105
|
65
|
101
|
370
|
346
|
|||||||||||||||
Head office
|
2
|
10
|
12
|
26
|
45
|
|||||||||||||||
Total net capital (proceeds) expenditures
|
$
|
(96
|
)
|
$
|
1,240
|
$
|
2,220
|
$
|
3,853
|
$
|
11,744
|
|||||||||
By segment
|
||||||||||||||||||||
North America (2) (3) (6)
|
$
|
(1,126
|
)
|
$
|
199
|
$
|
1,029
|
$
|
(119
|
)
|
$
|
7,500
|
||||||||
North Sea
|
34
|
41
|
105
|
230
|
400
|
|||||||||||||||
Offshore Africa
|
181
|
146
|
127
|
608
|
281
|
|||||||||||||||
Oil Sands Mining and Upgrading
|
706
|
777
|
862
|
2,730
|
3,110
|
|||||||||||||||
Midstream
|
2
|
2
|
(16
|
)
|
8
|
62
|
||||||||||||||
Abandonments (5)
|
105
|
65
|
101
|
370
|
346
|
|||||||||||||||
Head office
|
2
|
10
|
12
|
26
|
45
|
|||||||||||||||
Total
|
$
|
(96
|
)
|
$
|
1,240
|
$
|
2,220
|
$
|
3,853
|
$
|
11,744
|
(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)
|
Capitalized interest and other includes expenditures related to land acquisition and retention, seismic, and other adjustments.
|
(5)
|
Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table.
|
(6) | The above noted figures include non-cash share consideration of $985 million received from PrairieSky on the disposition of royalty income assets in the fourth quarter of 2015 and the impact of other pre-tax gains on the sale of other properties totaling $49 million recognized in the third quarter of 2015. |
44
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||||||
(number of wells)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||||
Net successful natural gas wells
|
4
|
4
|
16
|
19
|
75
|
|||||||||||||||
Net successful crude oil wells (1)
|
2
|
66
|
325
|
115
|
1,023
|
|||||||||||||||
Dry wells
|
–
|
4
|
8
|
6
|
19
|
|||||||||||||||
Stratigraphic test / service wells
|
73
|
1
|
74
|
166
|
437
|
|||||||||||||||
Total
|
79
|
75
|
423
|
306
|
1,554
|
|||||||||||||||
Success rate (excluding stratigraphic test /
service wells)
|
100%
|
|
95%
|
|
98%
|
|
96%
|
|
98%
|
|
(1) | Includes bitumen wells. |
Canadian Natural Resources Limited
|
45
|
($ millions, except ratios)
|
Dec 31
2015 |
Sep 30
2015 |
Dec 31
2014 |
|||||||||
Working capital (deficit) (1)
|
$
|
1,193
|
$
|
309
|
$
|
(673
|
)
|
|||||
Long-term debt (2) (3)
|
$
|
16,794
|
$
|
16,510
|
$
|
14,002
|
||||||
Share capital
|
$
|
4,541
|
$
|
4,533
|
$
|
4,432
|
||||||
Retained earnings
|
22,765
|
22,885
|
24,408
|
|||||||||
Accumulated other comprehensive income
|
75
|
67
|
51
|
|||||||||
Shareholders’ equity
|
$
|
27,381
|
$
|
27,485
|
$
|
28,891
|
||||||
Debt to book capitalization (3) (4)
|
38%
|
|
38%
|
|
33%
|
|
||||||
Debt to market capitalization (3) (5)
|
34%
|
|
37%
|
|
26%
|
|
||||||
After-tax return on average common
shareholders’ equity (6) |
(2%)
|
|
2%
|
|
14%
|
|
||||||
After-tax return on average capital
employed (3) (7) |
(1%)
|
|
2%
|
|
10%
|
|
(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. |
(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 twelve month trailing period; as a percentage of average common shareholders’ equity for the period. |
(7) | Calculated as net earnings (loss) plus after-tax interest and other financing expense for the twelve month trailing period; as a percentage of average capital employed for the period. |
46
|
Canadian Natural Resources Limited
|
§ | 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 the fourth quarter of 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 the second quarter of 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 the first quarter of 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 $125 million non-revolving term credit facility maturing February 2019, which was fully drawn. Borrowings under this new facility may be made by way of pricing referenced to Canadian dollar bankers’ acceptances or Canadian prime loans; |
— | Subsequent to December 31, 2015, the Company retained its investment grade ratings with both Standard & Poor’s Rating Services and DBRS Limited. In addition, Moody’s Investors Service, Inc. downgraded the Company’s credit ratings within the investment grade debt rating scale. The current changes in the Company’s credit ratings are not expected to have a significant impact on the Company’s access to debt capital markets, its US commercial paper program or on its overall cost of borrowing. |
§ | Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages. Beginning in 2015, all of the Company’s credit facilities are now subject to a financial covenant that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 0.65 to 1.0; and |
§ | Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place to minimize the impact in the event of a default. |
Canadian Natural Resources Limited
|
47
|
($ 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. |
48
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
49
|
As at
(millions of Canadian dollars, unaudited) |
Note
|
Dec 31
2015 |
Dec 31
2014 |
||||||||
ASSETS
|
|||||||||||
Current assets
|
|||||||||||
Cash and cash equivalents
|
$
|
69
|
$
|
25
|
|||||||
Accounts receivable
|
1,277
|
1,889
|
|||||||||
Current income taxes
|
677
|
228
|
|||||||||
Inventory
|
525
|
665
|
|||||||||
Prepaids and other
|
162
|
172
|
|||||||||
Investment in PrairieSky Royalty Ltd.
|
5
|
974
|
–
|
||||||||
Current portion of other long-term assets
|
6
|
375
|
510
|
||||||||
4,059
|
3,489
|
||||||||||
Exploration and evaluation assets
|
3
|
2,586
|
3,557
|
||||||||
Property, plant and equipment
|
4
|
51,475
|
52,480
|
||||||||
Other long-term assets
|
6
|
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
|
7
|
1,729
|
980
|
||||||||
Current portion of other long-term liabilities
|
8
|
206
|
319
|
||||||||
4,595
|
5,142
|
||||||||||
Long-term debt
|
7
|
15,065
|
13,022
|
||||||||
Other long-term liabilities
|
8
|
2,890
|
4,175
|
||||||||
Deferred income taxes
|
9,344
|
8,970
|
|||||||||
31,894
|
31,309
|
||||||||||
SHAREHOLDERS’ EQUITY
|
|||||||||||
Share capital
|
10
|
4,541
|
4,432
|
||||||||
Retained earnings
|
22,765
|
24,408
|
|||||||||
Accumulated other comprehensive income
|
11
|
75
|
51
|
||||||||
27,381
|
28,891
|
||||||||||
$
|
59,275
|
$
|
60,200
|
50
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
||||||||||||||||||
(millions of Canadian dollars, except per
common share amounts, unaudited)
|
Note
|
Dec 31
2015
|
Dec 31
2014
|
Dec 31
2015
|
Dec 31
2014 |
||||||||||||||
Product sales
|
$
|
2,963
|
$
|
4,850
|
$
|
13,167
|
$
|
21,301
|
|||||||||||
Less: royalties
|
(170
|
)
|
(466
|
)
|
(804
|
)
|
(2,438
|
)
|
|||||||||||
Revenue
|
2,793
|
4,384
|
12,363
|
18,863
|
|||||||||||||||
Expenses
|
|||||||||||||||||||
Production
|
1,119
|
1,399
|
4,726
|
5,265
|
|||||||||||||||
Transportation and blending
|
575
|
759
|
2,379
|
3,232
|
|||||||||||||||
Depletion, depreciation and amortization
|
3, 4
|
1,472
|
1,406
|
5,483
|
4,880
|
||||||||||||||
Administration
|
93
|
100
|
390
|
367
|
|||||||||||||||
Share-based compensation
|
8
|
56
|
(144
|
)
|
(46
|
)
|
66
|
||||||||||||
Asset retirement obligation accretion
|
8
|
43
|
49
|
173
|
193
|
||||||||||||||
Interest and other financing expense
|
73
|
84
|
322
|
323
|
|||||||||||||||
Risk management activities
|
14
|
(81
|
)
|
(739
|
)
|
(469
|
)
|
(800
|
)
|
||||||||||
Foreign exchange loss
|
165
|
124
|
761
|
303
|
|||||||||||||||
Gains on disposition of properties and
corporate acquisitions
|
4
|
(690
|
)
|
(137
|
)
|
(739
|
)
|
(137
|
)
|
||||||||||
Loss from investments
|
5, 6
|
18
|
5
|
50
|
8
|
||||||||||||||
2,843
|
2,906
|
13,030
|
13,700
|
||||||||||||||||
Earnings (loss) before taxes
|
(50
|
)
|
1,478
|
(667
|
)
|
5,163
|
|||||||||||||
Current income tax (recovery) expense
|
9
|
(148
|
)
|
27
|
(261
|
)
|
427
|
||||||||||||
Deferred income tax (recovery) expense
|
9
|
(33
|
)
|
253
|
231
|
807
|
|||||||||||||
Net earnings (loss)
|
$
|
131
|
$
|
1,198
|
$
|
(637
|
)
|
$
|
3,929
|
||||||||||
Net earnings (loss) per common share
|
|||||||||||||||||||
Basic
|
13
|
$
|
0.12
|
$
|
1.10
|
$
|
(0.58
|
)
|
$
|
3.60
|
|||||||||
Diluted
|
13
|
$
|
0.12
|
$
|
1.09
|
$
|
(0.58
|
)
|
$
|
3.58
|
Three Months Ended
|
Year Ended
|
|||||||||||||||
(millions of Canadian dollars, unaudited)
|
Dec 31
2015
|
Dec 31
2014
|
Dec 31
2015
|
Dec 31
2014 |
||||||||||||
Net earnings (loss)
|
$
|
131
|
$
|
1,198
|
$
|
(637
|
)
|
$
|
3,929
|
|||||||
Items that may be reclassified subsequently
to net earnings |
||||||||||||||||
Net change in derivative financial instruments
designated as cash flow hedges
|
||||||||||||||||
Unrealized income (loss) during the period, net of taxes of
$1 million (2014 – $nil) – three months ended;
$2 million (2014 – $nil) – year ended
|
(15
|
)
|
6
|
(23
|
)
|
5
|
||||||||||
Reclassification to net earnings (loss), net of taxes of
$1 million (2014 – $nil) – three months ended;
$2 million (2014 – $1 million) – year ended
|
(2
|
)
|
1
|
(13
|
)
|
8
|
||||||||||
(17
|
)
|
7
|
(36
|
)
|
13
|
|||||||||||
Foreign currency translation adjustment
|
||||||||||||||||
Translation of net investment
|
25
|
(3
|
)
|
60
|
(4
|
)
|
||||||||||
Other comprehensive income, net of taxes
|
8
|
4
|
24
|
9
|
||||||||||||
Comprehensive income (loss)
|
$
|
139
|
$
|
1,202
|
$
|
(613
|
)
|
$
|
3,938
|
Canadian Natural Resources Limited
|
51
|
Year Ended
|
|||||||||||
(millions of Canadian dollars, unaudited)
|
Note
|
Dec 31
2015 |
Dec 31
2014 |
||||||||
Share capital
|
10
|
||||||||||
Balance – beginning of year
|
$
|
4,432
|
$
|
3,854
|
|||||||
Issued upon exercise of stock options
|
91
|
488
|
|||||||||
Previously recognized liability on stock options exercised for
common shares |
18
|
129
|
|||||||||
Purchase of common shares under Normal Course Issuer Bid
|
–
|
(39
|
)
|
||||||||
Balance – end of year
|
4,541
|
4,432
|
|||||||||
Retained earnings
|
|||||||||||
Balance – beginning of year
|
24,408
|
21,876
|
|||||||||
Net earnings (loss)
|
(637
|
)
|
3,929
|
||||||||
Purchase of common shares under Normal Course Issuer Bid
|
10
|
–
|
(414
|
)
|
|||||||
Dividends on common shares
|
10
|
(1,006
|
)
|
(983
|
)
|
||||||
Balance – end of year
|
22,765
|
24,408
|
|||||||||
Accumulated other comprehensive income
|
11
|
||||||||||
Balance – beginning of year
|
51
|
42
|
|||||||||
Other comprehensive income, net of taxes
|
24
|
9
|
|||||||||
Balance – end of year
|
75
|
51
|
|||||||||
Shareholders’ equity
|
$
|
27,381
|
$
|
28,891
|
52
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||
(millions of Canadian dollars, unaudited)
|
Dec 31
2015
|
Dec 31
2014
|
Dec 31
2015
|
Dec 31
2014 |
||||||||||||
Operating activities
|
||||||||||||||||
Net earnings (loss)
|
$
|
131
|
$
|
1,198
|
$
|
(637
|
)
|
$
|
3,929
|
|||||||
Non-cash items
|
||||||||||||||||
Depletion, depreciation and amortization
|
1,472
|
1,406
|
5,483
|
4,880
|
||||||||||||
Share-based compensation
|
56
|
(144
|
)
|
(46
|
)
|
66
|
||||||||||
Asset retirement obligation accretion
|
43
|
49
|
173
|
193
|
||||||||||||
Unrealized risk management loss (gain)
|
174
|
(404
|
)
|
374
|
(451
|
)
|
||||||||||
Unrealized foreign exchange loss
|
170
|
106
|
858
|
256
|
||||||||||||
Realized foreign exchange loss on
repayment of US dollar debt securities
|
–
|
36
|
–
|
36
|
||||||||||||
Loss from investments
|
23
|
5
|
55
|
8 | ||||||||||||
Deferred income tax (recovery) expense
|
(33
|
)
|
253
|
231
|
807
|
|||||||||||
Gains on disposition of properties and
corporate acquisitions
|
(690
|
)
|
(137
|
)
|
(739
|
)
|
(137
|
)
|
||||||||
Current income tax on disposition of properties
|
33
|
–
|
33
|
–
|
||||||||||||
Other
|
(103
|
)
|
(107
|
)
|
(22
|
)
|
(38
|
)
|
||||||||
Abandonment expenditures
|
(105
|
)
|
(101
|
)
|
(370
|
)
|
(346
|
)
|
||||||||
Net change in non-cash working capital
|
314
|
158
|
239
|
(744
|
)
|
|||||||||||
1,485
|
2,318
|
5,632
|
8,459
|
|||||||||||||
Financing activities
|
||||||||||||||||
(Repayment) issue of bank credit facilities and
commercial paper, net
|
(73
|
)
|
(362
|
)
|
970
|
1,195
|
||||||||||
Issue of medium-term notes, net
|
–
|
–
|
107
|
992
|
||||||||||||
Issue of US dollar debt securities, net
|
–
|
382
|
–
|
1,482
|
||||||||||||
Issue of common shares on exercise of stock
options
|
7
|
40
|
91
|
488
|
||||||||||||
Purchase of common shares under Normal Course Issuer Bid
|
–
|
(49
|
)
|
–
|
(453
|
)
|
||||||||||
Dividends on common shares
|
(503
|
)
|
(246
|
)
|
(1,251
|
)
|
(955
|
)
|
||||||||
Net change in non-cash working capital
|
–
|
(6
|
)
|
(40
|
)
|
(22
|
)
|
|||||||||
(569
|
)
|
(241
|
)
|
(123
|
)
|
2,727
|
||||||||||
Investing activities
|
||||||||||||||||
Net proceeds (expenditures) on exploration and
evaluation assets (1)
|
316
|
(97
|
)
|
236
|
(1,190
|
)
|
||||||||||
Net expenditures on property, plant and
equipment (1)
|
(1,100
|
)
|
(2,022
|
)
|
(4,704
|
)
|
(10,208
|
)
|
||||||||
Current income tax on disposition of properties
|
(33
|
)
|
–
|
(33
|
)
|
–
|
||||||||||
Investment in other long-term assets
|
–
|
–
|
(112
|
)
|
(113
|
)
|
||||||||||
Net change in non-cash working capital
|
(60
|
)
|
51
|
(852
|
)
|
334
|
||||||||||
(877
|
)
|
(2,068
|
)
|
(5,465
|
)
|
(11,177
|
)
|
|||||||||
Increase in cash and cash equivalents
|
39
|
9
|
44
|
9
|
||||||||||||
Cash and cash equivalents –
beginning of period
|
30
|
16
|
25
|
16
|
||||||||||||
Cash and cash equivalents –
end of period
|
$
|
69
|
$
|
25
|
$
|
69
|
$
|
25
|
||||||||
Interest paid, net
|
$
|
94
|
$
|
134
|
$
|
541
|
$
|
521
|
||||||||
Income taxes (received) paid
|
$
|
(94
|
)
|
$
|
127
|
$
|
42
|
$
|
792
|
(1) | Net proceeds on exploration and evaluation assets and net expenditures on property, plant and equipment in the fourth quarter of 2015 exclude non-cash share consideration of $985 million received from PrairieSky Royalty Ltd. (“PrairieSky”) on the disposition of royalty income assets. |
Canadian Natural Resources Limited
|
53
|
54
|
Canadian Natural Resources Limited
|
Exploration and Production
|
Oil Sands
Mining and Upgrading
|
Total
|
||||||||||||||||||
North America
|
North Sea
|
Offshore Africa
|
||||||||||||||||||
Cost
|
||||||||||||||||||||
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 4 regarding the disposition of exploration and evaluation assets in the North America segment. |
Canadian Natural Resources Limited
|
55
|
Exploration and Production
|
Oil Sands Mining and Upgrading
|
Midstream
|
Head Office
|
Total
|
||||||||||||||||||||||||
North America
|
North Sea
|
Offshore
Africa |
||||||||||||||||||||||||||
Cost
|
||||||||||||||||||||||||||||
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, 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
|
Dec 31
2015 |
Dec 31
2014
|
||||||
Horizon
|
$
|
6,017
|
$
|
5,492
|
||||
Kirby Thermal Oil Sands – North
|
$
|
816
|
$
|
681
|
56
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||
Dec 31
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||
Fair value loss from PrairieSky
|
$
|
11
|
$
|
–
|
$
|
11
|
$
|
–
|
||||||||
Dividend income from PrairieSky
|
(5
|
)
|
–
|
(5
|
)
|
–
|
||||||||||
$
|
6
|
$
|
–
|
$
|
6
|
$
|
–
|
Dec 31
2015 |
Dec 31
2014 |
|||||||
Investment in North West Redwater Partnership
|
$
|
254
|
$
|
298
|
||||
North West Redwater Partnership subordinated debt (1)
|
254
|
120
|
||||||
Risk Management (note 14)
|
854
|
599
|
||||||
Other
|
168
|
167
|
||||||
1,530
|
1,184
|
|||||||
Less: current portion
|
375
|
510
|
||||||
$
|
1,155
|
$
|
674
|
(1) | Includes accrued interest. |
Canadian Natural Resources Limited
|
57
|
Dec 31
2015
|
Dec 31
2014 |
|||||||
Canadian dollar denominated debt, unsecured
|
||||||||
Bank credit facilities
|
$
|
2,385
|
$
|
2,404
|
||||
Medium-term notes
|
2,500
|
2,400
|
||||||
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 (US$7,500 million)
|
10,380
|
8,701
|
||||||
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. |
58
|
Canadian Natural Resources Limited
|
§ | 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. |
Canadian Natural Resources Limited
|
59
|
Dec 31
2015 |
Dec 31
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
|
Dec 31
2015 |
Dec 31
2014 |
|||||||
Balance – beginning of year
|
$
|
4,221
|
$
|
4,162
|
||||
Liabilities incurred
|
7
|
41
|
||||||
Liabilities acquired, net
|
129
|
404
|
||||||
Liabilities settled
|
(370
|
)
|
(346
|
)
|
||||
Asset retirement obligation accretion
|
173
|
193
|
||||||
Revision of cost, inflation rates and timing estimates
|
(313
|
)
|
(907
|
)
|
||||
Change in discount rate
|
(1,150
|
)
|
558
|
|||||
Foreign exchange adjustments
|
253
|
116
|
||||||
Balance – end of year
|
2,950
|
4,221
|
||||||
Less: current portion
|
101
|
121
|
||||||
$
|
2,849
|
$
|
4,100
|
Dec 31
2015 |
Dec 31
2014 |
|||||||
Balance – beginning of year
|
$
|
203
|
$
|
260
|
||||
Share-based compensation (recovery) expense
|
(46
|
)
|
66
|
|||||
Cash payment for stock options surrendered
|
(1
|
)
|
(8
|
)
|
||||
Transferred to common shares
|
(18
|
)
|
(129
|
)
|
||||
(Recovered from) capitalized to Oil Sands Mining and Upgrading
|
(10
|
)
|
14
|
|||||
Balance – end of year
|
128
|
203
|
||||||
Less: current portion
|
105
|
158
|
||||||
$
|
23
|
$
|
45
|
60
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Year Ended
|
|||||||||||||||
Dec 31
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||
Current corporate income tax (recovery) expense –
North America
|
$
|
(66
|
)
|
$
|
123
|
$
|
86
|
$
|
702
|
|||||||
Current corporate income tax recovery – North Sea
|
(18
|
)
|
(23
|
)
|
(117
|
)
|
(68
|
)
|
||||||||
Current corporate income tax expense – Offshore
Africa
|
5
|
8
|
17
|
43
|
||||||||||||
Current PRT (1) recovery – North Sea
|
(71
|
)
|
(86
|
)
|
(258
|
)
|
(273
|
)
|
||||||||
Other taxes
|
2
|
5
|
11
|
23
|
||||||||||||
Current income tax (recovery) expense
|
(148
|
)
|
27
|
(261
|
)
|
427
|
||||||||||
Deferred corporate income tax (recovery) expense
|
(1
|
)
|
254
|
216
|
681
|
|||||||||||
Deferred PRT (1) (recovery) expense – North Sea
|
(32
|
)
|
(1
|
)
|
15
|
126
|
||||||||||
Deferred income tax (recovery) expense
|
(33
|
)
|
253
|
231
|
807
|
|||||||||||
Income tax (recovery) expense
|
$
|
(181
|
)
|
$
|
280
|
$
|
(30
|
)
|
$
|
1,234
|
(1) | Petroleum Revenue Tax. |
Year Ended Dec 31, 2015
|
||||||||
Issued common shares
|
Number of shares (thousands)
|
Amount
|
||||||
Balance – beginning of year
|
1,091,837
|
$
|
4,432
|
|||||
Issued upon exercise of stock options
|
2,831
|
91
|
||||||
Previously recognized liability on stock options exercised for
common shares
|
–
|
18
|
||||||
Balance – end of year
|
1,094,668
|
$
|
4,541
|
Canadian Natural Resources Limited
|
61
|
Year Ended Dec 31, 2015
|
||||||||
Stock options (thousands)
|
Weighted
average exercise price |
|||||||
Outstanding – beginning of year
|
71,708
|
$
|
35.60
|
|||||
Granted
|
13,310
|
$
|
30.56
|
|||||
Surrendered for cash settlement
|
(185
|
)
|
$
|
33.30
|
||||
Exercised for common shares
|
(2,831
|
)
|
$
|
32.31
|
||||
Forfeited
|
(7,387
|
)
|
$
|
35.12
|
||||
Outstanding – end of year
|
74,615
|
$
|
34.88
|
|||||
Exercisable – end of year
|
30,567
|
$
|
36.19
|
Dec 31
2015 |
Dec 31
2014
|
|||||||
Derivative financial instruments designated as cash flow hedges
|
$
|
58
|
$
|
94
|
||||
Foreign currency translation adjustment
|
17
|
(43
|
)
|
|||||
$
|
75
|
$
|
51
|
62
|
Canadian Natural Resources Limited
|
Dec 31
2015 |
Dec 31
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. |
Three Months Ended
|
Year Ended
|
||||||||||||||||
Dec 31
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
||||||||||||||
Weighted average common shares outstanding
– basic (thousands of shares) |
1,094,528
|
1,091,427
|
1,093,862
|
1,091,754
|
|||||||||||||
Effect of dilutive stock options (thousands of shares)
|
299
|
3,054
|
–
|
5,068
|
|||||||||||||
Weighted average common shares outstanding
– diluted (thousands of shares) |
1,094,827
|
1,094,481
|
1,093,862
|
1,096,822
|
|||||||||||||
Net earnings (loss)
|
$
|
131
|
$
|
1,198
|
$
|
(637
|
)
|
$
|
3,929
|
||||||||
Net earnings (loss) per common share |
– basic
|
$
|
0.12
|
$
|
1.10
|
$
|
(0.58
|
)
|
$
|
3.60
|
|||||||
– diluted
|
$
|
0.12
|
$
|
1.09
|
$
|
(0.58
|
)
|
$
|
3.58
|
Canadian Natural Resources Limited
|
63
|
Dec 31, 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
|
)
|
Dec 31, 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. |
Dec 31, 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
|
)
|
$
|
–
|
$
|
–
|
Dec 31, 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. |
64
|
Canadian Natural Resources Limited
|
Asset (liability)
|
Dec 31, 2015
|
Dec 31, 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)
|
Dec 31, 2015
|
Dec 31, 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
|
Canadian Natural Resources Limited
|
65
|
Three Months Ended
|
Year Ended
|
|||||||||||||||
Dec 31
2015 |
Dec 31
2014 |
Dec 31
2015 |
Dec 31
2014 |
|||||||||||||
Net realized risk management gain
|
$
|
(255
|
)
|
$
|
(335
|
)
|
$
|
(843
|
)
|
$
|
(349
|
)
|
||||
Net unrealized risk management loss (gain)
|
174
|
(404
|
)
|
374
|
(451
|
)
|
||||||||||
$
|
(81
|
)
|
$
|
(739
|
)
|
$
|
(469
|
)
|
$
|
(800
|
)
|
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”). |
66
|
Canadian Natural Resources Limited
|
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
|
$
|
–
|
$
|
–
|
Canadian Natural Resources Limited
|
67
|
Exploration and Production
|
||||||||||||||||||||||||||||||||||||||||||||||||
North America
|
North Sea
|
Offshore Africa
|
Total Exploration and Production
|
|||||||||||||||||||||||||||||||||||||||||||||
(millions of Canadian dollars,
unaudited) |
Three Months Ended
Dec 31 |
Year Ended
Dec 31 |
Three Months Ended
Dec 31 |
Year Ended
Dec 31 |
Three Months Ended
Dec 31 |
Year Ended
Dec 31 |
Three Months Ended
Dec 31 |
Year Ended
Dec 31 |
||||||||||||||||||||||||||||||||||||||||
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
|||||||||||||||||||||||||||||||||
Segmented product sales
|
1,970
|
3,586
|
9,222
|
15,963
|
133
|
205
|
638
|
701
|
148
|
111
|
482
|
503
|
2,251
|
3,902
|
10,342
|
17,167
|
||||||||||||||||||||||||||||||||
Less: royalties
|
(151
|
)
|
(407
|
)
|
(732
|
)
|
(2,159
|
)
|
–
|
–
|
(1
|
)
|
(2
|
)
|
(7
|
)
|
(8
|
)
|
(22
|
)
|
(43
|
)
|
(158
|
)
|
(415
|
)
|
(755
|
)
|
(2,204
|
)
|
||||||||||||||||||
Segmented revenue
|
1,819
|
3,179
|
8,490
|
13,804
|
133
|
205
|
637
|
699
|
141
|
103
|
460
|
460
|
2,093
|
3,487
|
9,587
|
14,963
|
||||||||||||||||||||||||||||||||
Segmented expenses
|
||||||||||||||||||||||||||||||||||||||||||||||||
Production
|
592
|
754
|
2,603
|
2,924
|
110
|
171
|
544
|
496
|
67
|
74
|
223
|
212
|
769
|
999
|
3,370
|
3,632
|
||||||||||||||||||||||||||||||||
Transportation and blending
|
554
|
757
|
2,309
|
3,228
|
18
|
2
|
61
|
5
|
1
|
–
|
2
|
1
|
573
|
759
|
2,372
|
3,234
|
||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization
|
1,065
|
1,059
|
4,248
|
3,901
|
107
|
120
|
388
|
269
|
158
|
31
|
273
|
105
|
1,330
|
1,210
|
4,909
|
4,275
|
||||||||||||||||||||||||||||||||
Asset retirement obligation accretion
|
23
|
25
|
93
|
98
|
10
|
10
|
39
|
38
|
2
|
2
|
10
|
10
|
35
|
37
|
142
|
146
|
||||||||||||||||||||||||||||||||
Realized risk management activities
|
(255
|
)
|
(335
|
)
|
(843
|
)
|
(349
|
)
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(255
|
)
|
(335
|
)
|
(843
|
)
|
(349
|
)
|
||||||||||||||||||||||||
Gains on disposition of properties and
corporate acquisitions
|
(690
|
)
|
(137
|
)
|
(739
|
)
|
(137
|
)
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(690
|
)
|
(137
|
)
|
(739
|
)
|
(137
|
)
|
||||||||||||||||||||||||
Loss from investments
|
6
|
–
|
6
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
6
|
–
|
6
|
–
|
||||||||||||||||||||||||||||||||
Total segmented expenses
|
1,295
|
2,123
|
7,677
|
9,665
|
245
|
303
|
1,032
|
808
|
228
|
107
|
508
|
328
|
1,768
|
2,533
|
9,217
|
10,801
|
||||||||||||||||||||||||||||||||
Segmented earnings (loss) before
the following
|
524
|
1,056
|
813
|
4,139
|
(112
|
)
|
(98
|
)
|
(395
|
)
|
(109
|
)
|
(87
|
)
|
(4
|
)
|
(48
|
)
|
132
|
325
|
954
|
370
|
4,162
|
|||||||||||||||||||||||||
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 (recovery)
expense
|
||||||||||||||||||||||||||||||||||||||||||||||||
Net earnings (loss)
|
68
|
Canadian Natural Resources Limited
|
Oil Sands Mining and Upgrading
|
Midstream
|
Inter-segment elimination and other
|
Total
|
|||||||||||||||||||||||||||||||||||||||||||||
(millions of Canadian dollars,
unaudited) |
Three Months Ended
Dec 31 |
Year Ended
Dec 31 |
Three Months Ended
Dec 31 |
Year Ended
Dec 31 |
Three Months Ended
Dec 31 |
Year Ended
Dec 31 |
Three Months Ended
Dec 31 |
Year Ended
Dec 31 |
||||||||||||||||||||||||||||||||||||||||
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
|||||||||||||||||||||||||||||||||
Segmented product sales
|
693
|
932
|
2,764
|
4,095
|
33
|
29
|
136
|
120
|
(14
|
)
|
(13
|
)
|
(75
|
)
|
(81
|
)
|
2,963
|
4,850
|
13,167
|
21,301
|
||||||||||||||||||||||||||||
Less: royalties
|
(12
|
)
|
(51
|
)
|
(49
|
)
|
(234
|
)
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(170
|
)
|
(466
|
)
|
(804
|
)
|
(2,438
|
)
|
||||||||||||||||||||||||
Segmented revenue
|
681
|
881
|
2,715
|
3,861
|
33
|
29
|
136
|
120
|
(14
|
)
|
(13
|
)
|
(75
|
)
|
(81
|
)
|
2,793
|
4,384
|
12,363
|
18,863
|
||||||||||||||||||||||||||||
Segmented expenses
|
||||||||||||||||||||||||||||||||||||||||||||||||
Production
|
344
|
395
|
1,332
|
1,609
|
7
|
7
|
32
|
34
|
(1
|
)
|
(2
|
)
|
(8
|
)
|
(10
|
)
|
1,119
|
1,399
|
4,726
|
5,265
|
||||||||||||||||||||||||||||
Transportation and blending
|
20
|
20
|
82
|
75
|
–
|
–
|
–
|
–
|
(18
|
)
|
(20
|
)
|
(75
|
)
|
(77
|
)
|
575
|
759
|
2,379
|
3,232
|
||||||||||||||||||||||||||||
Depletion, depreciation and amortization
|
139
|
194
|
562
|
596
|
3
|
2
|
12
|
9
|
–
|
–
|
–
|
–
|
1,472
|
1,406
|
5,483
|
4,880
|
||||||||||||||||||||||||||||||||
Asset retirement obligation accretion
|
8
|
12
|
31
|
47
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
43
|
49
|
173
|
193
|
||||||||||||||||||||||||||||||||
Realized risk management activities
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(255
|
)
|
(335
|
)
|
(843
|
)
|
(349
|
)
|
||||||||||||||||||||||||||||
Gains on disposition of properties and
corporate acquisitions
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(690
|
)
|
(137
|
)
|
(739
|
)
|
(137
|
)
|
||||||||||||||||||||||||||||
Loss from investments
|
–
|
–
|
–
|
–
|
12
|
5
|
44
|
8
|
–
|
–
|
–
|
–
|
18
|
5
|
50
|
8
|
||||||||||||||||||||||||||||||||
Total segmented expenses
|
511
|
621
|
2,007
|
2,327
|
22
|
14
|
88
|
51
|
(19
|
)
|
(22
|
)
|
(83
|
)
|
(87
|
)
|
2,282
|
3,146
|
11,229
|
13,092
|
||||||||||||||||||||||||||||
Segmented earnings (loss) before
the following
|
170
|
260
|
708
|
1,534
|
11
|
15
|
48
|
69
|
5
|
9
|
8
|
6
|
511
|
1,238
|
1,134
|
5,771
|
||||||||||||||||||||||||||||||||
Non-segmented expenses
|
||||||||||||||||||||||||||||||||||||||||||||||||
Administration
|
93
|
100
|
390
|
367
|
||||||||||||||||||||||||||||||||||||||||||||
Share-based compensation
|
56
|
(144
|
)
|
(46
|
)
|
66
|
||||||||||||||||||||||||||||||||||||||||||
Interest and other financing expense
|
73
|
84
|
322
|
323
|
||||||||||||||||||||||||||||||||||||||||||||
Unrealized risk management activities
|
174
|
(404
|
)
|
374
|
(451
|
)
|
||||||||||||||||||||||||||||||||||||||||||
Foreign exchange loss
|
165
|
124
|
761
|
303
|
||||||||||||||||||||||||||||||||||||||||||||
Total non-segmented expenses
|
561
|
(240
|
)
|
1,801
|
608
|
|||||||||||||||||||||||||||||||||||||||||||
Earnings (loss) before taxes
|
(50
|
)
|
1,478
|
(667
|
)
|
5,163
|
||||||||||||||||||||||||||||||||||||||||||
Current income tax (recovery)
expense
|
(148
|
)
|
27
|
(261
|
)
|
427
|
||||||||||||||||||||||||||||||||||||||||||
Deferred income tax (recovery)
expense
|
(33
|
)
|
253
|
231
|
807
|
|||||||||||||||||||||||||||||||||||||||||||
Net earnings (loss)
|
131
|
1,198
|
(637
|
)
|
3,929
|
Canadian Natural Resources Limited
|
69
|
Year Ended
|
||||||||||||||||||||||||
Dec 31, 2015
|
Dec 31, 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 in the fourth quarter of 2015. |
(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 the third quarter of 2015. |
(5) | Net expenditures for Oil Sands Mining and Upgrading also include capitalized interest and share-based compensation. |
70
|
Canadian Natural Resources Limited
|
Dec 31
2015 |
Dec 31
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
|
Canadian Natural Resources Limited
|
71
|
Interest coverage ratios for the twelve month period ended December 31, 2015:
|
||||
Interest coverage (times)
|
||||
Net earnings (loss) (1)
|
(0.2
|
)x
|
||
Cash flow from operations (2)
|
10.8
|
x
|
(1) | Net earnings (loss) plus income taxes and interest expense excluding current and deferred PRT expense and other taxes; divided by the sum of interest expense and capitalized interest. |
(2) | Cash flow from operations plus current income taxes and interest expense excluding current PRT expense and other taxes; divided by the sum of interest expense and capitalized interest. |
72
|
Canadian Natural Resources Limited
|
Telephone:
Facsimile:
Email:
Website:
|
(403) 514-7777
(403) 514-7888
ir@cnrl.com
www.cnrl.com
|
STEVE W. LAUT
President
COREY B. BIEBER
Chief Financial Officer and
Senior Vice-President, Finance
MARK A. STAINTHORPE
Director, Treasury and
Investor Relations
|
Trading Symbol - CNQ
Toronto Stock Exchange
New York Stock Exchange
|
Canadian Natural Resources Limited
|
73
|
1 Year Canadian Natural Resources Chart |
1 Month Canadian Natural Resources Chart |
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