CANADIAN NATURAL RESOURCES LIMITED
(Registrant)
|
|||
Date: November 10, 2015
|
By:
|
/s/ B. E. McGrath | |
B. E. McGRATH | |||
Corporate Secretary | |||
Three Months Ended
|
Nine Months Ended
|
||||||||||||||||||||
($ Millions, except per common share amounts)
|
Sep 30
2015 |
June 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Net earnings (loss)
|
$
|
(111
|
)
|
$
|
(405
|
)
|
$
|
1,039
|
$
|
(768
|
)
|
$
|
2,731
|
||||||||
Per common share
|
– basic |
$
|
(0.10
|
)
|
$
|
(0.37
|
)
|
$
|
0.95
|
$
|
(0.70
|
)
|
$
|
2.50
|
|||||||
|
– diluted |
$
|
(0.10
|
)
|
$
|
(0.37
|
)
|
$
|
0.94
|
$
|
(0.70
|
)
|
$
|
2.49
|
|||||||
Adjusted net earnings from operations (1)
|
$
|
113
|
$
|
178
|
$
|
984
|
$
|
312
|
$
|
3,055
|
|||||||||||
Per common share
|
– basic |
$
|
0.10
|
$
|
0.16
|
$
|
0.90
|
$
|
0.28
|
$
|
2.80
|
||||||||||
|
– diluted |
$
|
0.10
|
$
|
0.16
|
$
|
0.89
|
$
|
0.28
|
$
|
2.78
|
||||||||||
Cash flow from operations (2)
|
$
|
1,533
|
$
|
1,503
|
$
|
2,440
|
$
|
4,406
|
$
|
7,219
|
|||||||||||
Per common share
|
– basic |
$
|
1.40
|
$
|
1.38
|
$
|
2.23
|
$
|
4.03
|
$
|
6.61
|
||||||||||
|
– diluted |
$
|
1.40
|
$
|
1.37
|
$
|
2.21
|
$
|
4.02
|
$
|
6.57
|
||||||||||
Capital expenditures, net of dispositions
|
$
|
1,240
|
$
|
1,297
|
$
|
2,175
|
$
|
3,949
|
$
|
9,524
|
|||||||||||
Daily production, before royalties
|
|||||||||||||||||||||
Natural gas (MMcf/d)
|
1,653
|
1,779
|
1,674
|
1,734
|
1,497
|
||||||||||||||||
Crude oil and NGLs (bbl/d)
|
573,135
|
509,047
|
518,007
|
561,554
|
517,428
|
||||||||||||||||
Equivalent production (BOE/d) (3)
|
848,701
|
805,547
|
796,931
|
850,587
|
766,871
|
(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 maintained its focus on safe, effective and efficient operations in the third quarter of 2015 demonstrated by solid production volumes. 2015 third quarter production volumes averaged 848,701 BOE/d, an increase of 6% and 5% from Q3/14 and Q2/15 volumes respectively. Q3/15 operational highlights include:
|
— | Horizon Oil Sands (“Horizon”) production volumes averaged 131,779 bbl/d of synthetic crude oil (“SCO”), an increase of 61% and 36% from Q3/14 and Q2/15 levels respectively. Safe and reliable operations remain inherent throughout Horizon as the plant utilization rate in Q3/15 of 96% was at the high end of our target range of 92% to 96%. Quarterly operating expenses at a new benchmark low of $27.04/bbl resulted from strong production volumes. 2015 annual operating cost guidance has been lowered and is now targeted to range from $29.00/bbl to $32.00/bbl. |
— | Offshore Africa crude oil production averaged 21,077 bbl/d, an increase of 54% over Q3/14 and 23% over Q2/15 levels, resulting from the successful execution of the ongoing Espoir and Baobab infill drilling programs. |
‒ |
To date, the Espoir infill drilling program has added approximately 5,300 bbl/d net to the Company. Espoir is targeted to add overall net production volumes of 5,900 bbl/d through a 10 gross well (5.9 net well) program which includes 4 water injection wells and is currently tracking below sanctioned costs and on track for production. For the first nine months of 2015, 5 gross wells were drilled and completed for production (no water injection wells drilled to date).
|
2
|
Canadian Natural Resources Limited
|
‒ | At Baobab, 3 gross wells were drilled and completed during the first nine months of 2015. Net incremental production volumes currently average approximately 6,300 bbl/d. Production from the fourth gross well is targeted to come on stream in the fourth quarter of 2015. Baobab is targeted to add overall net production volumes of 11,000 bbl/d through a 6 gross well (3.4 net well) program, where progress is currently tracking below sanctioned costs and on track for production. |
— | At Pelican Lake, excellent operating efficiencies continue to be a focus as industry leading operating costs of $6.64/bbl were achieved, a decrease of 15% from Q3/14 and 5% from Q2/15 levels. Despite no drilling activity during the year, production volumes continue to be strong at 50,852 bbl/d and this leading edge polymer flood continues to meet expectations. |
— | Kirby South, the Company’s largest Steam Assisted Gravity Drainage (“SAGD”) operation, continues to ramp up to 40,000 bbl/d. Q3/15 production volumes were 34,069 bbl/d, an increase of 88% from Q3/14 and 30% over Q2/15 volumes. |
§ | The expansion activities at Horizon continue to progress on track with overall physical completion of 74%. Horizon project capital costs continue to trend below budget estimates. Over the next twenty months, the Company is targeted to complete the Phase 2/3 expansion, adding an incremental 125,000 bbl/d of SCO to the Company’s large, balanced and diversified asset base. Horizon will provide significant and sustainable production for decades to come. |
§ | Canadian Natural continues to execute capital discipline by proactively managing its drilling programs. As a result of the decrease in commodity pricing and other external events, the Company’s drilling activity for the first nine months of 2015 consisted of 134 net wells, excluding strat/service wells, compared to 768 net wells for the first nine months of 2014, a reduction of 83%. |
§ | Canadian Natural remains committed to its effective and efficient operations, with an enhanced focus on cost optimization. During the third quarter, the Company achieved strong operating cost reductions in the following areas: |
Q3/15
|
Q3/14
|
Year over Year
Percent
Reduction
|
||||||||||
North America Light Crude Oil and NGLs ($/bbl)
|
$
|
14.37
|
$
|
17.67
|
19%
|
|
||||||
Pelican Lake Heavy Crude Oil ($/bbl)
|
$
|
6.64
|
$
|
7.82
|
15%
|
|
||||||
Primary Heavy Crude Oil ($/bbl)
|
$
|
13.81
|
$
|
17.52
|
21%
|
|
||||||
Horizon Oil Sands Mining and Upgrading ($/bbl) (1)
|
$
|
27.04
|
$
|
37.13
|
27%
|
|
||||||
North Sea Light Crude Oil ($/bbl)
|
$
|
72.69
|
$
|
76.48
|
5%
|
|
||||||
North America Natural Gas ($/Mcf)
|
$
|
1.25
|
$
|
1.36
|
8%
|
|
(1) | Horizon Q3/14 operating costs adjusted to reflect the impact of the maintenance turnaround completed in Q3/14. |
§ | Due to the timing of liftings from the various fields in Offshore Africa that have different cost structures, and a weaker Canadian dollar, a quarterly cost comparison year over year is not indicative of performance. However, on an annual basis, due to the ongoing infill drilling program in Côte d’Ivoire and a continued focus on effective and efficient operations, Offshore Africa crude oil operating costs are targeted to reduce by 37% on a produced barrel basis, 2015 year over 2014 year. |
§ | Given the cyclical nature of Primrose operations and the continued ramp up of production volumes at Kirby South, quarterly cost comparison year over year is not indicative of performance. However, on an annual basis, with a continued focus on effective and efficient operations, thermal operating costs are targeted to reduce by 16% on a produced barrel basis, 2015 year over 2014 year. |
§ | In addition to the operating cost efficiencies achieved during the quarter, Canadian Natural has lowered its targeted 2015 capital spending program by an additional $65 million from $5,500 million to $5,435 million. This reduction is a result of the Company’s ability to optimize its execution strategy, enhance productivity, right scope projects, leverage technology, and achieve lower energy and material costs. |
§ | Year to date, Canadian Natural has been able to attain drilling and completions cost reductions from 20% to 35% and facility cost decreases from 20% to 30% throughout its North America Exploration & Production (“E&P”) operations. These reductions have contributed to the Company’s ability to decrease its targeted 2015 capital expenditure program by a total of approximately $3.2 billion since November 2014. |
Canadian Natural Resources Limited
|
3
|
§ | Canadian Natural generated cash flow from operations of approximately $1.5 billion in Q3/15 compared to approximately $2.4 billion in Q3/14 and $1.5 billion in Q2/15. The decrease in Q3/15 from Q3/14 primarily reflects lower benchmark pricing partially offset by reduced operating costs and increased crude oil production volumes. |
§ | The Company incurred a net loss in Q3/15 of $111 million, compared to net earnings of $1,039 million in Q3/14 and a net loss of $405 million in Q2/15. Adjusted net earnings from operations for Q3/15 were $113 million, compared to adjusted net earnings of $984 million in Q3/14 and $178 million in Q2/15. Changes in adjusted net earnings largely reflect the changes in cash flow from operations. |
§ | Canadian Natural declared a quarterly cash dividend on common shares of C$0.23 per share payable on December 31, 2015. |
§ | At this time, due to the current volatile issues facing the energy industry on both a national and global basis, Canadian Natural has not finalized its 2016 Budget plan. However, below we provide preliminary guidance for 2016. |
— | Continued focus on lowering cost structures, |
— | Completion of Horizon Phase 2B and progression of Phase 3 toward completion in Q4/17, |
— | Maintenance of the Company’s strong balance sheet, |
— | Maintenance of the Company’s dividend program, and |
— | Preservation of the optionality of the Company’s reserves and land base. |
§ | Operational Targets |
§ | Target Capital Program |
§ | Lowering Cost Structures |
§ | Horizon Operations and Expansion Highlights |
§ | Maintenance of Strong Balance Sheet |
§ | Canadian Natural’s Dividend Program |
§ | Preservation of the optionality of the Company’s reserves and undeveloped lands |
4
|
Canadian Natural Resources Limited
|
Nine Months Ended Sep 30
|
||||||||||||||||
2015
|
2014
|
|||||||||||||||
(number of wells)
|
Gross
|
Net
|
Gross
|
Net
|
||||||||||||
Crude oil
|
124
|
113
|
774
|
698
|
||||||||||||
Natural gas
|
22
|
15
|
81
|
59
|
||||||||||||
Dry
|
6
|
6
|
13
|
11
|
||||||||||||
Subtotal
|
152
|
134
|
868
|
768
|
||||||||||||
Stratigraphic test / service wells
|
130
|
93
|
365
|
363
|
||||||||||||
Total
|
282
|
227
|
1,233
|
1,131
|
||||||||||||
Success rate (excluding stratigraphic test / service wells)
|
96%
|
|
99%
|
|
§ | As a direct result of the decrease in crude oil and natural gas pricing and other external events, the Company has proactively reduced its 2015 drilling programs. Drilling activity, excluding strat/service wells, in Q3/15 consisted of 74 net wells compared to 300 net wells in Q3/14. |
Crude oil and NGLs – excluding Thermal In Situ Oil Sands
|
||||||||||||||||||||
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
June 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Crude oil and NGLs production (bbl/d)
|
264,709
|
270,021
|
288,858
|
273,609
|
280,319
|
|||||||||||||||
Net wells targeting crude oil
|
67
|
4
|
275
|
111
|
689
|
|||||||||||||||
Net successful wells drilled
|
63
|
4
|
270
|
105
|
679
|
|||||||||||||||
Success rate
|
94%
|
|
100%
|
|
98%
|
|
95%
|
|
99%
|
|
§ | Quarterly production volumes of North America crude oil and NGLs were 264,709 bbl/d in Q3/15, a decrease of 8% and 2% from Q3/14 and Q2/15 levels respectively. The year over year production decline reflects the 84% reduction in drilling activity from 689 net wells in the first nine months of 2014 to 111 net wells in the first nine months of 2015. |
§ | North America light crude oil and NGL quarterly production averaged 88,195 bbl/d in Q3/15, a decrease of 6% from Q3/14 volumes and comparable to Q2/15 levels. Year over year decline primarily resulted from expected production declines as no wells were drilled in Q3/15 compared to 22 net wells drilled in Q3/14. |
§ | Despite the reduction in production volumes, North America light crude oil and NGL quarterly operating costs decreased to $14.37/bbl in Q3/15, 19% lower than Q3/14 levels of $17.67/bbl and 6% lower than Q2/15 levels of $15.29/bbl. |
§ | Pelican Lake operations averaged 50,852 bbl/d of quarterly heavy crude oil production, a 2% decrease from Q3/14 and Q2/15 levels. Canadian Natural continues to achieve success in developing, implementing and optimizing the leading edge polymer flood technology at Pelican Lake. |
Canadian Natural Resources Limited
|
5
|
§ | Industry leading quarterly operating costs were achieved at Pelican Lake during Q3/15. Operating costs decreased to $6.64/bbl, 15% lower than Q3/14 and 5% lower than Q2/15. |
§ | In Q3/15, primary heavy crude oil production averaged 125,662 bbl/d, a decrease of 12% and 2% from Q3/14 and Q2/15 levels respectively. This production decline from Q3/14 to Q3/15 reflects expected declines, the Company’s proactive decision to reduce its primary heavy crude oil drilling program by 73% year over year, and the Company’s prudent decision to shut-in approximately 5,700 bbl/d of current primary heavy crude oil production volumes as a result of unfavorable economic conditions. In Q3/15, 67 net wells were drilled compared to 245 net wells in Q3/14. |
§ | Canadian Natural continues to demonstrate its strong focus on operating efficiencies achieving quarterly cost reductions in its primary heavy crude oil asset base. Primary heavy crude oil quarterly operating costs decreased in Q3/15 to $13.81/bbl compared to $17.52/bbl in Q3/14 and $14.92/bbl in Q2/15, cost reductions of 21% and 7% respectively. |
Thermal In Situ Oil Sands
|
||||||||||||||||||||
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
June 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Bitumen production (bbl/d)
|
133,183
|
105,019
|
115,256
|
128,048
|
104,037
|
|||||||||||||||
Net wells targeting bitumen
|
–
|
–
|
1
|
3
|
15
|
|||||||||||||||
Net successful wells drilled
|
–
|
–
|
1
|
3
|
15
|
|||||||||||||||
Success rate
|
–
|
–
|
100%
|
|
100%
|
|
100%
|
|
§ | In Q3/15, thermal in situ production volumes averaged 133,183 bbl/d, an increase of 16% and 27% from Q3/14 and Q2/15 production volume levels respectively. The increase in Q3/15 from Q2/15 production volumes primarily reflects increased production volumes from Primrose operations and the ramp up of Kirby South operations. |
§ | At Kirby South, quarterly production volumes continued to increase in Q3/15 to 34,069 bbl/d as operations continue to ramp up to the targeted 40,000 bbl/d of design capacity. The reservoir continues to perform as expected with very good thermal efficiencies. The steam to oil ratio (“SOR”) in Q3/15 was 2.5. For October 2015, Kirby South’s production volumes exited at an approximate rate of 36,000 bbl/d following a short shut down for maintenance on the oil treating vessels. |
§ | The Company continues to progress the low pressure steamflood operations at Primrose East Area 1 and the low pressure cyclic steam stimulation (“CSS”) operations at Primrose East Area 2. Operations at Primrose East are meeting expectations with current production volumes ranging from 15,000 bbl/d to 20,000 bbl/d. |
Natural Gas
|
||||||||||||||||||||
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
June 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Natural gas production (MMcf/d)
|
1,592
|
1,716
|
1,644
|
1,673
|
1,468
|
|||||||||||||||
Net wells targeting natural gas
|
4
|
2
|
22
|
15
|
60
|
|||||||||||||||
Net successful wells drilled
|
4
|
2
|
21
|
15
|
59
|
|||||||||||||||
Success rate
|
100%
|
|
100%
|
|
95%
|
|
100%
|
|
98%
|
|
§ | North America natural gas quarterly production volumes averaged 1,592 MMcf/d for Q3/15, a decrease of 3% and 7% from Q3/14 and Q2/15 levels respectively. The decrease from Q2/15 levels reflects unplanned and planned pipeline take away capacity constraints 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 quarterly operating costs of $0.20/Mcfe in Q3/15. |
6
|
Canadian Natural Resources Limited
|
§ | Canadian Natural’s North America natural gas production volumes during Q3/15 were negatively impacted by transportation restrictions on the NOVA pipeline system by 89 MMcf/d. An additional 16 MMcf/d of natural gas production volumes were also negatively impacted as a result of an unexpected seven day outage of the Alliance pipeline system. |
§ | Further restrictions on the NOVA pipeline system are expected in Q4/15 which will lower North America natural gas production volumes by approximately 70 MMcf/d. Canadian Natural’s Q4/15 total natural gas production guidance reflects these impacts and is targeted to range from 1,735 MMcf/d to 1,775 MMcf/d. |
§ | North America natural gas quarterly operating costs were $1.25/Mcf in Q3/15, an 8% decrease from Q3/14 levels of $1.36/Mcf, and a 2% decrease from Q2/15 levels of $1.28/Mcf, reflecting a continued focus on cost optimization. |
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
June 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Crude oil production (bbl/d)
|
||||||||||||||||||||
North Sea
|
22,387
|
20,330
|
18,197
|
21,915
|
15,848
|
|||||||||||||||
Offshore Africa
|
21,077
|
17,070
|
13,684
|
17,140
|
12,557
|
|||||||||||||||
Natural gas production (MMcf/d)
|
||||||||||||||||||||
North Sea
|
35
|
38
|
7
|
36
|
7
|
|||||||||||||||
Offshore Africa
|
26
|
25
|
23
|
25
|
22
|
|||||||||||||||
Net wells targeting crude oil
|
2.6
|
1.4
|
1.8
|
4.6
|
3.5
|
|||||||||||||||
Net successful wells drilled
|
2.6
|
1.4
|
1.8
|
4.6
|
3.5
|
|||||||||||||||
Success rate
|
100%
|
|
100%
|
|
100%
|
|
100%
|
|
100%
|
|
§ | International crude oil production averaged 43,464 bbl/d during Q3/15, an increase of 36% from Q3/14 levels and a 16% increase from Q2/15 levels. The increase in Q3/15 production volumes over Q3/14 levels was primarily due to completion and tie-in of new wells at the Baobab and Espoir fields during the second and third quarters of 2015 and the reinstatement of production from both the Banff FPSO and the Tiffany platform outages during 2014. The increase in Q3/15 production volumes from Q2/15 was primarily due to bringing new wells onstream at the Baobab and Espoir fields during Q3/15 and production volume increases from the Ninian field after planned turnaround activity performed in Q2/15. |
§ | The infill drilling programs at the Espoir and Baobab fields in Côte d’Ivoire continue to be successfully executed with results meeting expectations. |
— | To date, the Espoir infill drilling program has added approximately 5,300 bbl/d net to the Company. Espoir is targeted to add overall net production volumes of 5,900 bbl/d through a 10 gross well (5.9 net well) program which includes 4 water injection wells and is currently tracking below sanctioned costs and on track for production. For the first nine months of 2015, 5 gross wells were drilled and completed for production (no water injection wells drilled to date). |
— | At Baobab, 3 gross wells were drilled and completed for production during the first nine months of 2015. Net incremental production volumes currently average approximately 6,300 bbl/d. Production from the fourth gross well is targeted to come on stream in the fourth quarter of 2015. Baobab is targeted to add overall net production volumes of 11,000 bbl/d through a 6 gross well (3.4 net well) program, where progress is currently tracking below sanctioned costs and on track for production. |
Canadian Natural Resources Limited
|
7
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
June 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Synthetic crude oil production (bbl/d) (1)
|
131,779
|
96,607
|
82,012
|
120,842
|
104,667
|
(1) | The Company has commenced production of diesel for internal use at Horizon. Third quarter 2015 SCO production before royalties excludes 2,058 bbl/d of SCO consumed internally as diesel (second quarter 2015 – 2,410 bbl/d; third quarter 2014 – 875 bbl/d; nine months ended September 30, 2015 – 2,049 bbl/d; nine months ended September 30, 2014 – 295 bbl/d). |
§ | Horizon quarterly production volumes were strong in Q3/15 averaging 131,779 bbl/d of SCO, an increase of 61% and 36% from Q3/14 and Q2/15 levels respectively. Increased production volumes in Q3/15, as compared to Q3/14 and Q2/15, reflect normal operating conditions as planned maintenance activities impacted previous quarters. Q4/15 production guidance is targeted to range from 123,000 bbl/d to 129,000 bbl/d, with a targeted utilization rate of 92% at the midpoint. 2015 annual production guidance remains unchanged at 121,000 bbl/d to 131,000 bbl/d. |
§ | The Company achieved record quarterly operating costs at Horizon of $27.04/bbl as a result of safe, steady and reliable operations in Q3/15. 2015 annual operating cost guidance has been lowered and is now targeted to range from $29.00/bbl to $32.00/bbl. |
§ | 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 schedule. Canadian Natural has committed to approximately 82% of the Engineering, Procurement and Construction contracts with over 78% of the construction contracts awarded to date, 85% being lump sum, ensuring greater cost certainty and efficiency. |
§ | Overall Horizon Phase 2/3 expansion is 74% physically complete as at Q3/15: |
— | Directive 74 includes technological investment and research into tailings management. This project remains on track and is 57% physically complete. |
— | Phase 2B is 72% 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. Full commissioning of the Phase 2B equipment will be completed as planned in early Q4/16, adding 45,000 bbl/d of production capacity. |
— | Phase 3 is currently on budget and on schedule. This Phase is 67% physically complete, and includes the addition of extraction trains. 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. |
— | Horizon project capital in 2016 is targeted to be approximately $2.1 billion, the majority of which will be spent over the first nine months of 2016. In 2017, Horizon project capital is targeted to decline to $1.0 billion to $1.3 billion for Phase 3 completion. Once Horizon expansion activities are completed in Q4/17, total Horizon production volumes are targeted to average 250,000 bbl/d of SCO with operating costs targeted below $25.00/bbl. |
§ | The development of leased acreage is ongoing and lease requests on undeveloped acreage continue to be evaluated. Total drilling activity for the nine months of 2015 consisted of 251 wells with 235 drilled by third parties and 16 drilled by Canadian Natural. |
§ | The Company continues to focus on lease compliance, well commitments, offset drilling obligations and compensatory royalties payable. |
§ | Royalty production volumes highlighted below are not reported in Canadian Natural’s quarterly production volumes. Third party royalty revenues are included in reported Product Sales in the Company’s consolidated statement of earnings. |
8
|
Canadian Natural Resources Limited
|
Q2/15
|
Q1/15
|
|||||||
Natural gas (MMcf/d)
|
21.8
|
22.4
|
||||||
Crude oil (bbl/d)
|
4,004
|
4,263
|
||||||
NGLs (bbl/d)
|
527
|
538
|
||||||
Total (BOE/d)
|
8,157
|
8,537
|
Royalty volumes for Q2/15 attributable to
|
||||||||||||
Third
Party
|
Canadian
Natural (2)
|
Total
|
||||||||||
Natural gas (MMcf/d)
|
18.7
|
3.1
|
21.8
|
|||||||||
Crude oil (bbl/d)
|
3,379
|
625
|
4,004
|
|||||||||
NGLs (bbl/d)
|
481
|
46
|
527
|
|||||||||
Total (BOE/d)
|
6,979
|
1,178
|
8,157
|
Royalty revenue for Q2/15 attributable to
|
||||||||||||
($ millions)
|
Third
Party
|
Canadian
Natural (2)
|
Total
|
|||||||||
Natural gas
|
$
|
4
|
$
|
1
|
$
|
5
|
||||||
Crude oil
|
$
|
18
|
$
|
3
|
$
|
21
|
||||||
NGLs
|
$
|
2
|
$
|
–
|
$
|
2
|
||||||
Other revenue (3)
|
$
|
1
|
$
|
–
|
$
|
1
|
||||||
Total
|
$
|
25
|
$
|
4
|
$
|
29
|
Royalty revenue for Q2/15 attributable to
|
||||||||||||
($ millions)
|
Third
Party
|
Canadian
Natural (2)
|
Total
|
|||||||||
Fee title
|
$
|
15
|
$
|
3
|
$
|
18
|
||||||
Gross overriding royalty (4)
|
$
|
9
|
$
|
1
|
$
|
10
|
||||||
Other revenue (3)
|
$
|
1
|
$
|
–
|
$
|
1
|
||||||
Total
|
$
|
25
|
$
|
4
|
$
|
29
|
Q2/15
|
||||
Natural gas ($/Mcf)
|
$
|
2.41
|
||
Crude oil ($/bbl)
|
$
|
58.43
|
||
NGLs ($/bbl)
|
$
|
32.78
|
||
Total ($/BOE)
|
$
|
38.96
|
Canadian Natural Resources Limited
|
9
|
Leased to
|
||||||||||||
(gross acres, millions)
|
Third Party
and Unleased
|
Canadian
Natural (2)
|
Total
|
|||||||||
Fee title (5)
|
3.07
|
0.26
|
3.33
|
|||||||||
Gross overriding royalty (4)
|
1.82
|
1.67
|
3.49
|
|||||||||
Total
|
4.89
|
1.93
|
6.82
|
(1) | Based on the Company’s current estimate of revenue and volumes attributable to the noted period. |
(2) | Indicates Canadian Natural is both the Lessor and Lessee, thereby incurring intercompany royalties; in addition there are certain Canadian Natural fee title lands where the Company has production where no royalty burden has been recognized in this table. |
(3) | Includes sulphur revenue, bonus payments, lease rentals and compliance revenue. |
(4) | Includes Net Profit Interests and other royalties. |
(5) | Includes fee title and freehold lands. |
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
June 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Crude oil and NGLs pricing
|
||||||||||||||||||||
WTI benchmark price (US$/bbl) (1)
|
$
|
46.44
|
$
|
57.96
|
$
|
97.21
|
$
|
50.98
|
$
|
99.60
|
||||||||||
WCS blend differential from WTI (%) (2)
|
28%
|
|
20%
|
|
21%
|
|
26%
|
|
21%
|
|
||||||||||
SCO price (US$/bbl)
|
$
|
45.78
|
$
|
60.61
|
$
|
94.31
|
$
|
50.55
|
$
|
98.20
|
||||||||||
Condensate benchmark pricing (US$/bbl)
|
$
|
44.20
|
$
|
57.98
|
$
|
93.49
|
$
|
49.25
|
$
|
100.36
|
||||||||||
Average realized pricing before risk
management (C$/bbl) (3)
|
$
|
41.55
|
$
|
53.09
|
$
|
79.99
|
$
|
43.58
|
$
|
82.35
|
||||||||||
Natural gas pricing
|
||||||||||||||||||||
AECO benchmark price (C$/GJ)
|
$
|
2.65
|
$
|
2.53
|
$
|
4.00
|
$
|
2.66
|
$
|
4.32
|
||||||||||
Average realized pricing before risk
management (C$/Mcf) |
$
|
3.22
|
$
|
3.06
|
$
|
4.54
|
$
|
3.22
|
$
|
5.03
|
(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$/bbl)
|
Dated Brent Differential
from WTI (US$/bbl)
|
Condensate Differential
from WTI
(US$/bbl) |
||||||||||||||||||
2015
|
||||||||||||||||||||||||
July
|
$
|
50.93
|
14.6%
|
|
$
|
(7.44
|
)
|
$
|
2.62
|
$
|
5.61
|
$
|
(4.35
|
)
|
||||||||||
August
|
$
|
42.89
|
31.3%
|
|
$
|
(13.41
|
)
|
$
|
(0.64
|
)
|
$
|
4.04
|
$
|
(1.36
|
)
|
|||||||||
September
|
$
|
45.47
|
41.7%
|
|
$
|
(18.97
|
)
|
$
|
(4.05
|
)
|
$
|
2.15
|
$
|
(0.96
|
)
|
|||||||||
October
|
$
|
46.29
|
29.2%
|
|
$
|
(13.51
|
)
|
$
|
0.11
|
$
|
2.27
|
$
|
(0.54
|
)
|
||||||||||
November*
|
$
|
46.37
|
32.6%
|
|
$
|
(15.14
|
)
|
$
|
0.43
|
$
|
1.50
|
$
|
(1.12
|
)
|
||||||||||
December*
|
$
|
47.30
|
32.1%
|
|
$
|
(15.17
|
)
|
$
|
1.30
|
$
|
1.41
|
$
|
(0.75
|
)
|
§ | Volatility in supply and demand factors and geopolitical events continued to affect WTI and Brent pricing. The Organization of the Petroleum Exporting Countries’ (“OPEC”) decision to maintain crude oil production quotas resulted in a year over year decline in benchmark pricing. |
10
|
Canadian Natural Resources Limited
|
§ | The WCS differential to WTI averaged US$13.21/bbl or 28% in Q3/15 compared to US$20.19/bbl or 21% in Q3/14. The WCS differential widened during Q3/15 compared to Q2/15 due to planned and unplanned refinery shutdowns in the US Midwest and seasonal demand. November 2015 and December 2015 indications of the WCS heavy differential are trending higher to US$15.14/bbl or 33% and US$15.17/bbl or 32%, respectively. This widening is mainly due to the seasonality of heavy crude oil demand in the winter months. Seasonal demand fluctuations, changes in transportation logistics and refinery utilization and shutdowns will continue to be reflected in WCS pricing. |
§ | Canadian Natural contributed approximately 165,000 bbl/d of its heavy crude oil stream to the WCS blend in Q3/15. The Company remains the largest contributor to the WCS blend, accounting for 45% of the total blend. |
§ | SCO pricing averaged US$45.78/bbl during Q3/15 compared to US$94.31/bbl in Q3/14 and US$60.61/bbl in Q2/15, as a result of changes in WTI benchmark pricing. |
§ |
AECO natural gas pricing in Q3/15 averaged $2.65/GJ, a decrease of 34% from Q3/14 and an increase of 5% from Q2/15 pricing. In Q3/15, US natural gas production was relatively constant to Q2/15 with natural gas inventories growing slightly above normal industry levels. Natural gas prices were lower in Q3/15 compared to Q3/14 primarily due to lower than average storage levels as a result of the cold winter temperatures in 2014.
|
§ | The Company’s strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved production of 848,701 BOE/d for Q3/15, with approximately 97% of total production located in G8 countries. |
§ | Canadian Natural has a strong balance sheet with debt to book capitalization of 38% at September 30, 2015. All of the Company’s credit facilities are subject to a financial covenant that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 65%. |
§ | Canadian Natural maintains significant financial stability and liquidity represented in part by bank credit facilities. As at September 30, 2015, the Company had in place bank credit facilities of $7,480 million, of which $3,440 million was available. |
§ | Subsequent to September 30, 2015, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to $3,000 million of medium term notes in Canada, which expires in November 2017. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance. |
§ | Subsequent to September 30, 2015, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to US$3,000 million of debt securities in the United States, which expires in November 2017. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance. |
§ | Canadian Natural’s strong investment grade ratings have been maintained. |
§ | The Company’s commodity hedging program is utilized to protect investment returns, support ongoing balance sheet strength and the cash flow for its capital expenditure programs. Details of the Company’s commodity hedging program can be found on the Company’s website at www.cnrl.com. |
§ | Canadian Natural declared a quarterly cash dividend on common shares of C$0.23 per share payable on December 31, 2015. |
§ | The Company has a strong balance sheet and cash flow generation which enables it to weather volatility in commodity prices. Canadian Natural retains additional capital expenditure program flexibility to proactively adapt to changing market conditions. |
Canadian Natural Resources Limited
|
11
|
12
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
13
|
($ millions, except per common share amounts)
|
|||||||||||||||||||||
Three Months Ended
|
Nine Months Ended
|
||||||||||||||||||||
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||||
Product sales
|
$
|
3,316
|
$
|
3,662
|
$
|
5,370
|
$
|
10,204
|
$
|
16,451
|
|||||||||||
Net earnings (loss)
|
$
|
(111
|
)
|
$
|
(405
|
)
|
$
|
1,039
|
$
|
(768
|
)
|
$
|
2,731
|
||||||||
Per common share
|
– basic |
$
|
(0.10
|
)
|
$
|
(0.37
|
)
|
$
|
0.95
|
$
|
(0.70
|
)
|
$
|
2.50
|
|||||||
|
– diluted
|
$
|
(0.10
|
)
|
$
|
(0.37
|
)
|
$
|
0.94
|
$
|
(0.70
|
)
|
$
|
2.49
|
|||||||
Adjusted net earnings from operations (1)
|
$
|
113
|
$
|
178
|
$
|
984
|
$
|
312
|
$
|
3,055
|
|||||||||||
Per common share
|
– basic |
$
|
0.10
|
$
|
0.16
|
$
|
0.90
|
$
|
0.28
|
$
|
2.80
|
||||||||||
|
– diluted
|
$
|
0.10
|
$
|
0.16
|
$
|
0.89
|
$
|
0.28
|
$
|
2.78
|
||||||||||
Cash flow from operations (2)
|
$
|
1,533
|
$
|
1,503
|
$
|
2,440
|
$
|
4,406
|
$
|
7,219
|
|||||||||||
Per common share
|
– basic |
$
|
1.40
|
$
|
1.38
|
$
|
2.23
|
$
|
4.03
|
$
|
6.61
|
||||||||||
|
– diluted
|
$
|
1.40
|
$
|
1.37
|
$
|
2.21
|
$
|
4.02
|
$
|
6.57
|
||||||||||
Capital expenditures, net of dispositions
|
$
|
1,240
|
$
|
1,297
|
$
|
2,175
|
$
|
3,949
|
$
|
9,524
|
(1) | Adjusted net earnings from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings from operations. The reconciliation “Adjusted Net Earnings from Operations” 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. |
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014
|
Sep 30
2015
|
Sep 30
2014
|
|||||||||||||||
Net earnings (loss) as reported
|
$
|
(111)
|
|
$
|
(405)
|
|
$
|
1,039
|
$
|
(768)
|
|
$
|
2,731
|
|||||||
Share-based compensation, net of tax (1)
|
(87)
|
|
(79)
|
|
(122)
|
|
(102)
|
|
210
|
|||||||||||
Unrealized risk management (gain) loss, net of tax (2)
|
(24)
|
|
162
|
(118)
|
|
147
|
(36)
|
|
||||||||||||
Unrealized foreign exchange loss (gain), net of tax (3)
|
351
|
(76)
|
|
185
|
688
|
150
|
||||||||||||||
Equity loss (gain) from investment, net of tax (4)
|
20
|
(3)
|
|
–
|
32
|
–
|
||||||||||||||
Gain on disposition of properties, net of tax (5)
|
(36)
|
|
–
|
–
|
(36)
|
|
–
|
|||||||||||||
Effect of statutory tax rate and other legislative changes on deferred income
tax liabilities (6)
|
–
|
579
|
–
|
351
|
–
|
|||||||||||||||
Adjusted net earnings from operations
|
$
|
113
|
$
|
178
|
$
|
984
|
$
|
312
|
$
|
3,055
|
(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) | The Company's investment in the 50% owned North West Redwater Partnership is accounted for using the equity method of accounting. The non-cash equity loss (gain) from investment represents the Company's pro rata share of the North West Redwater Partnership's accounting loss (gain). |
(5) | 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. |
(6) | 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 $228 million. |
14
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Net earnings (loss)
|
$
|
(111)
|
|
$
|
(405)
|
|
$
|
1,039
|
$
|
(768)
|
|
$
|
2,731
|
|||||||
Non-cash items:
|
||||||||||||||||||||
Depletion, depreciation and amortization
|
1,376
|
1,280
|
1,226
|
4,011
|
3,474
|
|||||||||||||||
Share-based compensation
|
(87)
|
|
(79)
|
|
(122
|
)
|
(102)
|
|
210
|
|||||||||||
Asset retirement obligation accretion
|
44
|
43
|
49
|
130
|
144
|
|||||||||||||||
Unrealized risk management (gain) loss
|
(29)
|
|
215
|
(150
|
)
|
200
|
(47)
|
|
||||||||||||
Unrealized foreign exchange loss (gain)
|
351
|
(76)
|
|
185
|
688
|
150
|
||||||||||||||
Equity loss (gain) from investment
|
20
|
(3)
|
|
5
|
32
|
3
|
||||||||||||||
Deferred income tax expense
|
18
|
528
|
208
|
264
|
554
|
|||||||||||||||
Gain on disposition of properties
|
(49)
|
|
–
|
–
|
(49)
|
|
–
|
|||||||||||||
Cash flow from operations
|
$
|
1,533
|
$
|
1,503
|
$
|
2,440
|
$
|
4,406
|
$
|
7,219
|
§ | 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. |
§ | 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 crude oil and NGLs and natural gas sales volumes in the North America segment; and |
§ | higher depletion, depreciation and amortization expense; |
Canadian Natural Resources Limited
|
15
|
§ | higher crude oil and natural gas and SCO sales volumes in the International and Oil Sands Mining and Upgrading segments; |
§ | higher realized risk management gains; 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; |
§ | lower crude oil and NGLs sales volumes in the North Sea segment; and |
§ | lower natural gas sales volumes in the North America segment; |
§ | higher SCO and crude oil and NGLs sales volumes in the Oil Sands Mining and Upgrading, North America and Offshore Africa segments; |
§ | higher realized risk management gains; and |
§ | the impact of a weaker Canadian dollar relative to the US dollar. |
($ millions, except per common share amounts)
|
Sep 30
2015 |
Jun 30
2015 |
Mar 31
2015 |
Dec 31
2014 |
||||||||||||
Product sales
|
$
|
3,316
|
$
|
3,662
|
$
|
3,226
|
$
|
4,850
|
||||||||
Net earnings (loss)
|
$
|
(111
|
)
|
$
|
(405
|
)
|
$
|
(252
|
)
|
$
|
1,198
|
|||||
Net earnings (loss) per common share
|
||||||||||||||||
– basic
|
$
|
(0.10
|
)
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
$
|
1.10
|
|||||
– diluted
|
$
|
(0.10
|
)
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
$
|
1.09
|
|||||
($ millions, except per common share amounts)
|
Sep 30
2014 |
Jun 30
2014 |
Mar 31
2014 |
Dec 31
2013 |
||||||||||||
Product sales
|
$
|
5,370
|
$
|
6,113
|
$
|
4,968
|
$
|
4,330
|
||||||||
Net earnings (loss)
|
$
|
1,039
|
$
|
1,070
|
$
|
622
|
$
|
413
|
||||||||
Net earnings (loss) per common share
|
||||||||||||||||
– basic
|
$
|
0.95
|
$
|
0.98
|
$
|
0.57
|
$
|
0.38
|
||||||||
– diluted
|
$
|
0.94
|
$
|
0.97
|
$
|
0.57
|
$
|
0.38
|
16
|
Canadian Natural Resources Limited
|
§ | Crude oil pricing – The impact of increased shale oil production in North America, fluctuating global supply/demand, 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, the heavy crude oil drilling program, the impact and timing of acquisitions, and the impact of turnarounds at Horizon. 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 pricing, and the impact and timing of acquisitions. |
§ | Production expense – Fluctuations primarily due to the impact of the demand 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 depletion, depreciation and amortization expense in the North Sea resulting from the planned early cessation of production at the Murchison platform, 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 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 acquisitions/disposition of properties – Fluctuations due to the recognition of gains on dispositions in the third quarter of 2015 and acquisitions in the fourth quarter of 2014. |
Canadian Natural Resources Limited
|
17
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
WTI benchmark price (US$/bbl)
|
$
|
46.44
|
$
|
57.96
|
$
|
97.21
|
$
|
50.98
|
$
|
99.60
|
||||||||||
Dated Brent benchmark price (US$/bbl)
|
$
|
50.39
|
$
|
61.95
|
$
|
101.90
|
$
|
55.37
|
$
|
106.55
|
||||||||||
WCS blend differential from WTI (US$/bbl)
|
$
|
13.21
|
$
|
11.60
|
$
|
20.19
|
$
|
13.18
|
$
|
21.15
|
||||||||||
WCS blend differential from WTI (%)
|
28%
|
|
20%
|
|
21%
|
|
26%
|
|
21%
|
|
||||||||||
SCO price (US$/bbl)
|
$
|
45.78
|
$
|
60.61
|
$
|
94.31
|
$
|
50.55
|
$
|
98.20
|
||||||||||
Condensate benchmark price (US$/bbl)
|
$
|
44.20
|
$
|
57.98
|
$
|
93.49
|
$
|
49.25
|
$
|
100.36
|
||||||||||
NYMEX benchmark price (US$/MMBtu)
|
$
|
2.77
|
$
|
2.67
|
$
|
4.07
|
$
|
2.80
|
$
|
4.51
|
||||||||||
AECO benchmark price (C$/GJ)
|
$
|
2.65
|
$
|
2.53
|
$
|
4.00
|
$
|
2.66
|
$
|
4.32
|
||||||||||
US/Canadian dollar average exchange rate
(US$)
|
$
|
0.7640
|
$
|
0.8132
|
$
|
0.9183
|
$
|
0.7936
|
$
|
0.9139
|
18
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Crude oil and NGLs (bbl/d)
|
||||||||||||||||||||
North America – Exploration and Production
|
397,892
|
375,040
|
404,114
|
401,657
|
384,356
|
|||||||||||||||
North America – Oil Sands Mining and Upgrading (1)
|
131,779
|
96,607
|
82,012
|
120,842
|
104,667
|
|||||||||||||||
North Sea
|
22,387
|
20,330
|
18,197
|
21,915
|
15,848
|
|||||||||||||||
Offshore Africa
|
21,077
|
17,070
|
13,684
|
17,140
|
12,557
|
|||||||||||||||
573,135
|
509,047
|
518,007
|
561,554
|
517,428
|
||||||||||||||||
Natural gas (MMcf/d)
|
||||||||||||||||||||
North America
|
1,592
|
1,716
|
1,644
|
1,673
|
1,468
|
|||||||||||||||
North Sea
|
35
|
38
|
7
|
36
|
7
|
|||||||||||||||
Offshore Africa
|
26
|
25
|
23
|
25
|
22
|
|||||||||||||||
1,653
|
1,779
|
1,674
|
1,734
|
1,497
|
||||||||||||||||
Total barrels of oil equivalent (BOE/d)
|
848,701
|
805,547
|
796,931
|
850,587
|
766,871
|
|||||||||||||||
Product mix
|
||||||||||||||||||||
Light and medium crude oil and NGLs
|
15%
|
|
16%
|
|
16%
|
|
15%
|
|
15%
|
|
||||||||||
Pelican Lake heavy crude oil
|
6%
|
|
6%
|
|
7%
|
|
6%
|
|
6%
|
|
||||||||||
Primary heavy crude oil
|
15%
|
|
16%
|
|
18%
|
|
16%
|
|
19%
|
|
||||||||||
Bitumen (thermal oil)
|
16%
|
|
13%
|
|
14%
|
|
15%
|
|
14%
|
|
||||||||||
Synthetic crude oil (1)
|
16%
|
|
12%
|
|
10%
|
|
14%
|
|
14%
|
|
||||||||||
Natural gas
|
32%
|
|
37%
|
|
35%
|
|
34%
|
|
32%
|
|
||||||||||
Percentage of product sales (1) (2)
(excluding Midstream revenue) |
||||||||||||||||||||
Crude oil and NGLs
|
83%
|
|
84%
|
|
85%
|
|
83%
|
|
85%
|
|
||||||||||
Natural gas
|
17%
|
|
16%
|
|
15%
|
|
17%
|
|
15%
|
|
(1) | Third quarter 2015 SCO production before royalties excludes 2,058 bbl/d of SCO consumed internally as diesel (second quarter 2015 – 2,410 bbl/d; third quarter 2014 – 875 bbl/d; nine months ended September 30, 2015 – 2,049 bbl/d; nine months ended September 30, 2014 – 295 bbl/d). |
(2) | Net of blending costs and excluding risk management activities. |
Canadian Natural Resources Limited
|
19
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Crude oil and NGLs (bbl/d)
|
||||||||||||||||||||
North America – Exploration and Production
|
350,444
|
326,445
|
329,533
|
352,278
|
309,855
|
|||||||||||||||
North America – Oil Sands Mining and Upgrading
|
129,355
|
95,057
|
76,515
|
118,930
|
100,152
|
|||||||||||||||
North Sea
|
22,325
|
20,300
|
18,062
|
21,865
|
15,773
|
|||||||||||||||
Offshore Africa
|
20,145
|
16,342
|
12,276
|
16,386
|
11,600
|
|||||||||||||||
522,269
|
458,144
|
436,386
|
509,459
|
437,380
|
||||||||||||||||
Natural gas (MMcf/d)
|
||||||||||||||||||||
North America
|
1,527
|
1,684
|
1,525
|
1,617
|
1,341
|
|||||||||||||||
North Sea
|
35
|
38
|
7
|
36
|
7
|
|||||||||||||||
Offshore Africa
|
25
|
24
|
19
|
24
|
19
|
|||||||||||||||
1,587
|
1,746
|
1,551
|
1,677
|
1,367
|
||||||||||||||||
Total barrels of oil equivalent (BOE/d)
|
786,734
|
749,210
|
694,859
|
789,030
|
665,214
|
20
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
21
|
(bbl)
|
Sep 30
2015 |
Jun 30
2015 |
Dec 31
2014 |
|||||||||
North America – Exploration and Production
|
424,270
|
839,720
|
930,116
|
|||||||||
North America – Oil Sands Mining and Upgrading (SCO)
|
1,327,603
|
1,074,964
|
1,266,063
|
|||||||||
North Sea
|
450,023
|
131,959
|
368,808
|
|||||||||
Offshore Africa
|
1,353,011
|
1,459,094
|
461,997
|
|||||||||
3,554,907
|
3,505,737
|
3,026,984
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||||||||||
Sales price (2)
|
$
|
41.55
|
$
|
53.09
|
$
|
79.99
|
$
|
43.58
|
$
|
82.35
|
||||||||||
Transportation
|
2.56
|
2.80
|
2.32
|
2.60
|
2.51
|
|||||||||||||||
Realized sales price, net of transportation
|
38.99
|
50.29
|
77.67
|
40.98
|
79.84
|
|||||||||||||||
Royalties
|
4.09
|
5.91
|
13.66
|
4.57
|
14.46
|
|||||||||||||||
Production expense
|
15.70
|
17.01
|
15.99
|
16.25
|
18.08
|
|||||||||||||||
Netback
|
$
|
19.20
|
$
|
27.37
|
$
|
48.02
|
$
|
20.16
|
$
|
47.30
|
||||||||||
Natural gas ($/Mcf) (1)
|
||||||||||||||||||||
Sales price (2)
|
$
|
3.22
|
$
|
3.06
|
$
|
4.54
|
$
|
3.22
|
$
|
5.03
|
||||||||||
Transportation
|
0.39
|
0.38
|
0.26
|
0.38
|
0.27
|
|||||||||||||||
Realized sales price, net of transportation
|
2.83
|
2.68
|
4.28
|
2.84
|
4.76
|
|||||||||||||||
Royalties
|
0.11
|
0.05
|
0.32
|
0.09
|
0.43
|
|||||||||||||||
Production expense
|
1.31
|
1.39
|
1.45
|
1.38
|
1.52
|
|||||||||||||||
Netback
|
$
|
1.41
|
$
|
1.24
|
$
|
2.51
|
$
|
1.37
|
$
|
2.81
|
||||||||||
Barrels of oil equivalent ($/BOE) (1)
|
||||||||||||||||||||
Sales price (2)
|
$
|
33.46
|
$
|
38.85
|
$
|
59.56
|
$
|
34.22
|
$
|
62.38
|
||||||||||
Transportation
|
2.56
|
2.67
|
2.08
|
2.56
|
2.24
|
|||||||||||||||
Realized sales price, net of transportation
|
30.90
|
36.18
|
57.48
|
31.66
|
60.14
|
|||||||||||||||
Royalties
|
2.81
|
3.58
|
9.12
|
3.01
|
9.97
|
|||||||||||||||
Production expense
|
12.68
|
13.39
|
13.15
|
13.09
|
14.68
|
|||||||||||||||
Netback
|
$
|
15.41
|
$
|
19.21
|
$
|
35.21
|
$
|
15.56
|
$
|
35.49
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
22
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1) (2)
|
||||||||||||||||||||
North America
|
$
|
39.26
|
$
|
50.96
|
$
|
78.38
|
$
|
41.42
|
$
|
80.09
|
||||||||||
North Sea
|
$
|
62.28
|
$
|
73.57
|
$
|
113.08
|
$
|
67.38
|
$
|
120.76
|
||||||||||
Offshore Africa
|
$
|
65.31
|
$
|
74.84
|
$
|
104.82
|
$
|
69.23
|
$
|
111.25
|
||||||||||
Company average
|
$
|
41.55
|
$
|
53.09
|
$
|
79.99
|
$
|
43.58
|
$
|
82.35
|
||||||||||
Natural gas ($/Mcf) (1) (2)
|
||||||||||||||||||||
North America
|
$
|
2.99
|
$
|
2.80
|
$
|
4.43
|
$
|
2.98
|
$
|
4.91
|
||||||||||
North Sea
|
$
|
9.44
|
$
|
9.54
|
$
|
6.93
|
$
|
9.71
|
$
|
6.45
|
||||||||||
Offshore Africa
|
$
|
9.01
|
$
|
10.49
|
$
|
11.73
|
$
|
10.34
|
$
|
12.05
|
||||||||||
Company average
|
$
|
3.22
|
$
|
3.06
|
$
|
4.54
|
$
|
3.22
|
$
|
5.03
|
||||||||||
Company average ($/BOE) (1) (2)
|
$
|
33.46
|
$
|
38.85
|
$
|
59.56
|
$
|
34.22
|
$
|
62.38
|
(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
|
23
|
(Quarterly Average)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
|||||||||
Wellhead Price (1) (2)
|
||||||||||||
Light and medium crude oil and NGLs ($/bbl)
|
$
|
40.88
|
$
|
51.80
|
$
|
77.79
|
||||||
Pelican Lake heavy crude oil ($/bbl)
|
$
|
39.54
|
$
|
54.87
|
$
|
81.52
|
||||||
Primary heavy crude oil ($/bbl)
|
$
|
39.97
|
$
|
53.85
|
$
|
79.70
|
||||||
Bitumen (thermal oil) ($/bbl)
|
$
|
37.46
|
$
|
44.63
|
$
|
75.81
|
||||||
Natural gas ($/Mcf)
|
$
|
2.99
|
$
|
2.80
|
$
|
4.43
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
24
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||||||||||
North America
|
$
|
4.34
|
$
|
6.40
|
$
|
13.99
|
$
|
4.86
|
$
|
15.17
|
||||||||||
North Sea
|
$
|
0.17
|
$
|
0.11
|
$
|
0.84
|
$
|
0.14
|
$
|
0.43
|
||||||||||
Offshore Africa
|
$
|
2.89
|
$
|
3.19
|
$
|
10.79
|
$
|
3.04
|
$
|
7.77
|
||||||||||
Company average
|
$
|
4.09
|
$
|
5.91
|
$
|
13.66
|
$
|
4.57
|
$
|
14.46
|
||||||||||
Natural gas ($/Mcf) (1)
|
||||||||||||||||||||
North America
|
$
|
0.11
|
$
|
0.05
|
$
|
0.30
|
$
|
0.09
|
$
|
0.41
|
||||||||||
Offshore Africa
|
$
|
0.41
|
$
|
0.48
|
$
|
1.88
|
$
|
0.47
|
$
|
1.94
|
||||||||||
Company average
|
$
|
0.11
|
$
|
0.05
|
$
|
0.32
|
$
|
0.09
|
$
|
0.43
|
||||||||||
Company average ($/BOE) (1)
|
$
|
2.81
|
$
|
3.58
|
$
|
9.12
|
$
|
3.01
|
$
|
9.97
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited
|
25
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||||||||||
North America
|
$
|
11.64
|
$
|
13.14
|
$
|
14.52
|
$
|
12.85
|
$
|
15.20
|
||||||||||
North Sea
|
$
|
72.69
|
$
|
60.61
|
$
|
76.48
|
$
|
65.64
|
$
|
77.31
|
||||||||||
Offshore Africa
|
$
|
40.53
|
$
|
43.88
|
$
|
27.20
|
$
|
37.85
|
$
|
40.91
|
||||||||||
Company average
|
$
|
15.70
|
$
|
17.01
|
$
|
15.99
|
$
|
16.25
|
$
|
18.08
|
||||||||||
Natural gas ($/Mcf) (1)
|
||||||||||||||||||||
North America
|
$
|
1.25
|
$
|
1.28
|
$
|
1.36
|
$
|
1.30
|
$
|
1.45
|
||||||||||
North Sea
|
$
|
3.85
|
$
|
6.47
|
$
|
19.21
|
$
|
4.80
|
$
|
10.58
|
||||||||||
Offshore Africa
|
$
|
1.43
|
$
|
1.42
|
$
|
2.68
|
$
|
1.86
|
$
|
3.18
|
||||||||||
Company average
|
$
|
1.31
|
$
|
1.39
|
$
|
1.45
|
$
|
1.38
|
$
|
1.52
|
||||||||||
Company average ($/BOE) (1)
|
$
|
12.68
|
$
|
13.39
|
$
|
13.15
|
$
|
13.09
|
$
|
14.68
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
26
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Expense ($ millions)
|
$
|
1,208
|
$
|
1,158
|
$
|
1,087
|
$
|
3,579
|
$
|
3,065
|
||||||||||
$/BOE (1)
|
$
|
18.25
|
$
|
18.02
|
$
|
16.54
|
$
|
18.02
|
$
|
17.08
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Expense ($ millions)
|
$
|
36
|
$
|
36
|
$
|
37
|
$
|
107
|
$
|
109
|
||||||||||
$/BOE (1)
|
$
|
0.54
|
$
|
0.55
|
$
|
0.56
|
$
|
0.54
|
$
|
0.60
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited
|
27
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($/bbl)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
SCO sales price (1)
|
$
|
60.66
|
$
|
73.05
|
$
|
103.91
|
$
|
62.82
|
$
|
108.58
|
||||||||||
Bitumen value for royalty purposes (1) (2)
|
$
|
33.20
|
$
|
44.09
|
$
|
74.11
|
$
|
34.92
|
$
|
72.03
|
||||||||||
Bitumen royalties (1) (3)
|
$
|
1.32
|
$
|
0.99
|
$
|
7.17
|
$
|
1.11
|
$
|
6.29
|
||||||||||
Transportation
|
$
|
1.82
|
$
|
1.98
|
$
|
2.28
|
$
|
1.87
|
$
|
1.88
|
(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. |
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions) |
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Cash production costs
|
$
|
321
|
$
|
321
|
$
|
398
|
$
|
988
|
$
|
1,214
|
||||||||||
Less: costs incurred during turnaround
periods
|
–
|
(45
|
)
|
(98
|
)
|
(45
|
)
|
(98
|
)
|
|||||||||||
Adjusted cash production costs
|
$
|
321
|
$
|
276
|
$
|
300
|
$
|
943
|
$
|
1,116
|
||||||||||
Adjusted cash production costs, excluding
natural gas costs
|
$
|
300
|
$
|
260
|
$
|
280
|
$
|
886
|
$
|
1,027
|
||||||||||
Adjusted natural gas costs
|
21
|
16
|
20
|
57
|
89
|
|||||||||||||||
Adjusted cash production costs
|
$
|
321
|
$
|
276
|
$
|
300
|
$
|
943
|
$
|
1,116
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($/bbl) (1)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Adjusted cash production costs, excluding
natural gas costs
|
$
|
25.28
|
$
|
27.52
|
$
|
34.65
|
$
|
26.89
|
$
|
35.26
|
||||||||||
Adjusted natural gas costs
|
1.76
|
1.73
|
2.48
|
1.74
|
3.05
|
|||||||||||||||
Adjusted cash production costs
|
$
|
27.04
|
$
|
29.25
|
$
|
37.13
|
$
|
28.63
|
$
|
38.31
|
||||||||||
Sales (bbl/d)
|
129,033
|
103,388
|
87,826
|
120,617
|
106,721
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
28
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions, except per bbl amounts) |
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Depletion, depreciation and amortization
|
$
|
165
|
$
|
119
|
$
|
137
|
$
|
423
|
$
|
402
|
||||||||||
Less: depreciation incurred during
turnaround period
|
–
|
(5
|
)
|
(28
|
)
|
(5
|
)
|
(28
|
)
|
|||||||||||
Adjusted depletion, depreciation and
amortization
|
$
|
165
|
$
|
114
|
$
|
109
|
$
|
418
|
$
|
374
|
||||||||||
$/bbl (1)
|
$
|
13.95
|
$
|
12.04
|
$
|
13.43
|
$
|
12.70
|
$
|
12.83
|
(1) | Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods. |
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions, except per bbl amounts) |
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Expense
|
$
|
8
|
$
|
7
|
$
|
12
|
$
|
23
|
$
|
35
|
||||||||||
$/bbl (1)
|
$
|
0.65
|
$
|
0.82
|
$
|
1.45
|
$
|
0.70
|
$
|
1.21
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited
|
29
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions) |
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Revenue
|
$
|
33
|
$
|
35
|
$
|
30
|
$
|
103
|
$
|
91
|
||||||||||
Production expense
|
7
|
9
|
8
|
25
|
27
|
|||||||||||||||
Midstream cash flow
|
26
|
26
|
22
|
78
|
64
|
|||||||||||||||
Depreciation
|
3
|
3
|
2
|
9
|
7
|
|||||||||||||||
Equity loss (gain) from investment
|
20
|
(3
|
)
|
5
|
32
|
3
|
||||||||||||||
Segment earnings before taxes
|
$
|
3
|
$
|
26
|
$
|
15
|
$
|
37
|
$
|
54
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts) |
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Expense
|
$
|
93
|
$
|
100
|
$
|
87
|
$
|
297
|
$
|
267
|
||||||||||
$/BOE (1)
|
$
|
1.20
|
$
|
1.35
|
$
|
1.17
|
$
|
1.28
|
$
|
1.28
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
30
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
(Recovery) Expense
|
$
|
(87
|
)
|
$
|
(79
|
)
|
$
|
(122
|
)
|
$
|
(102
|
)
|
$
|
210
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts and interest rates)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Expense, gross
|
$
|
142
|
$
|
147
|
$
|
135
|
$
|
433
|
$
|
386
|
||||||||||
Less: capitalized interest
|
64
|
62
|
56
|
184
|
147
|
|||||||||||||||
Expense, net
|
$
|
78
|
$
|
85
|
$
|
79
|
$
|
249
|
$
|
239
|
||||||||||
$/BOE (1)
|
$
|
1.00
|
$
|
1.16
|
$
|
1.06
|
$
|
1.08
|
$
|
1.15
|
||||||||||
Average effective interest rate
|
3.8%
|
|
3.8%
|
|
3.9%
|
|
3.9%
|
|
4.0%
|
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited
|
31
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Crude oil and NGLs financial instruments
|
$
|
(173
|
)
|
$
|
(91
|
)
|
$
|
–
|
$
|
(381
|
)
|
$
|
–
|
|||||||
Natural gas financial instruments
|
–
|
–
|
21
|
–
|
33
|
|||||||||||||||
Foreign currency contracts
|
(90
|
)
|
22
|
(17
|
)
|
(207
|
)
|
(47
|
)
|
|||||||||||
Realized (gain) loss
|
(263
|
)
|
(69
|
)
|
4
|
(588
|
)
|
(14
|
)
|
|||||||||||
Crude oil and NGLs financial instruments
|
(12
|
)
|
205
|
(70
|
)
|
205
|
(24
|
)
|
||||||||||||
Natural gas financial instruments
|
–
|
–
|
(21
|
)
|
–
|
–
|
||||||||||||||
Foreign currency contracts
|
(17
|
)
|
10
|
(59
|
)
|
(5
|
)
|
(23
|
)
|
|||||||||||
Unrealized (gain) loss
|
(29
|
)
|
215
|
(150
|
)
|
200
|
(47
|
)
|
||||||||||||
Net (gain) loss
|
$
|
(292
|
)
|
$
|
146
|
$
|
(146
|
)
|
$
|
(388
|
)
|
$
|
(61
|
)
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Net realized (gain) loss
|
$
|
(28
|
)
|
$
|
(11
|
)
|
$
|
(1
|
)
|
$
|
(92
|
)
|
$
|
29
|
||||||
Net unrealized loss (gain) (1)
|
351
|
(76
|
)
|
185
|
688
|
150
|
||||||||||||||
Net loss (gain)
|
$
|
323
|
$
|
(87
|
)
|
$
|
184
|
$
|
596
|
$
|
179
|
(1)
|
Amounts are reported net of the hedging effect of cross currency swaps.
|
32
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions, except income tax rates)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
North America (1)
|
$
|
65
|
$
|
79
|
$
|
162
|
$
|
152
|
$
|
579
|
||||||||||
North Sea
|
(16
|
)
|
(19
|
)
|
14
|
(99
|
)
|
(45
|
)
|
|||||||||||
Offshore Africa
|
5
|
5
|
21
|
12
|
35
|
|||||||||||||||
PRT recovery – North Sea
|
(61
|
)
|
(72
|
)
|
(114
|
)
|
(187
|
)
|
(187
|
)
|
||||||||||
Other taxes
|
2
|
4
|
6
|
9
|
18
|
|||||||||||||||
Current income tax (recovery) expense
|
(5
|
)
|
(3
|
)
|
89
|
(113
|
)
|
400
|
||||||||||||
Deferred income tax expense
|
8
|
498
|
158
|
217
|
427
|
|||||||||||||||
Deferred PRT expense – North Sea
|
10
|
30
|
50
|
47
|
127
|
|||||||||||||||
Deferred income tax expense
|
18
|
528
|
208
|
264
|
554
|
|||||||||||||||
$
|
13
|
$
|
525
|
$
|
297
|
$
|
151
|
$
|
954
|
|||||||||||
Income tax rate and other legislative
changes (2) (3)
|
–
|
(579
|
)
|
–
|
(351
|
)
|
–
|
|||||||||||||
$
|
13
|
$
|
(54
|
)
|
$
|
297
|
$
|
(200
|
)
|
$
|
954
|
|||||||||
Effective income tax rate on adjusted net
earnings from operations (4)
|
28.0%
|
17.0%
|
24.7
|
%
|
10.3%
|
24.4%
|
|
(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 $228 million.
|
(4)
|
Excludes the impact of current and deferred PRT expense and other current income tax expense.
|
Canadian Natural Resources Limited
|
33
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
($ millions)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Exploration and Evaluation
|
||||||||||||||||||||
Net expenditures (2) (3)
|
$
|
5
|
$
|
29
|
$
|
92
|
$
|
80
|
$
|
1,093
|
||||||||||
Property, Plant and Equipment
|
||||||||||||||||||||
Net property acquisitions (2) (3)
|
(70
|
)
|
51
|
79
|
(8
|
)
|
2,821
|
|||||||||||||
Well drilling, completion and equipping
|
237
|
199
|
498
|
728
|
1,580
|
|||||||||||||||
Production and related facilities
|
191
|
249
|
504
|
754
|
1,348
|
|||||||||||||||
Capitalized interest and other (4)
|
23
|
27
|
34
|
76
|
78
|
|||||||||||||||
Net expenditures
|
381
|
526
|
1,115
|
1,550
|
5,827
|
|||||||||||||||
Total Exploration and Production
|
386
|
555
|
1,207
|
1,630
|
6,920
|
|||||||||||||||
Oil Sands Mining and Upgrading
|
||||||||||||||||||||
Horizon Phase 2/3 construction costs
|
668
|
535
|
670
|
1,609
|
1,763
|
|||||||||||||||
Sustaining capital
|
64
|
94
|
122
|
246
|
269
|
|||||||||||||||
Turnaround costs
|
3
|
6
|
15
|
13
|
21
|
|||||||||||||||
Capitalized interest and other (4)
|
42
|
43
|
38
|
156
|
195
|
|||||||||||||||
Total Oil Sands Mining and Upgrading
|
777
|
678
|
845
|
2,024
|
2,248
|
|||||||||||||||
Midstream
|
2
|
1
|
27
|
6
|
78
|
|||||||||||||||
Abandonments (4)
|
65
|
56
|
82
|
265
|
245
|
|||||||||||||||
Head office
|
10
|
7
|
14
|
24
|
33
|
|||||||||||||||
Total net capital expenditures
|
$
|
1,240
|
$
|
1,297
|
$
|
2,175
|
$
|
3,949
|
$
|
9,524
|
||||||||||
By segment
|
||||||||||||||||||||
North America (2) (3)
|
$
|
199
|
$
|
307
|
$
|
997
|
$
|
1,007
|
$
|
6,471
|
||||||||||
North Sea
|
41
|
93
|
100
|
196
|
295
|
|||||||||||||||
Offshore Africa
|
146
|
155
|
110
|
427
|
154
|
|||||||||||||||
Oil Sands Mining and Upgrading
|
777
|
678
|
845
|
2,024
|
2,248
|
|||||||||||||||
Midstream
|
2
|
1
|
27
|
6
|
78
|
|||||||||||||||
Abandonments (5)
|
65
|
56
|
82
|
265
|
245
|
|||||||||||||||
Head office
|
10
|
7
|
14
|
24
|
33
|
|||||||||||||||
Total
|
$
|
1,240
|
$
|
1,297
|
$
|
2,175
|
$
|
3,949
|
$
|
9,524
|
(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 disposition 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.
|
34
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||||||
(number of wells)
|
Sep 30
2015 |
Jun 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||||
Net successful natural gas wells
|
4
|
2
|
21
|
15
|
59
|
|||||||||||||||
Net successful crude oil wells (1)
|
66
|
5
|
273
|
113
|
698
|
|||||||||||||||
Dry wells
|
4
|
–
|
6
|
6
|
11
|
|||||||||||||||
Stratigraphic test / service wells
|
1
|
6
|
11
|
93
|
363
|
|||||||||||||||
Total
|
75
|
13
|
311
|
227
|
1,131
|
|||||||||||||||
Success rate (excluding stratigraphic test / service wells)
|
95%
|
|
100%
|
|
98%
|
|
96%
|
99%
|
|
(1)
|
Includes bitumen wells.
|
Canadian Natural Resources Limited
|
35
|
36
|
Canadian Natural Resources Limited
|
($ millions, except ratios)
|
Sep 30
2015 |
Jun 30
2015 |
Dec 31
2014 |
Sep 30
2014 |
||||||||||||
Working capital (deficit) (1)
|
$
|
309
|
$
|
261
|
$
|
(673
|
)
|
$
|
(915
|
)
|
||||||
Long-term debt (2) (3)
|
$
|
16,510
|
$
|
15,983
|
$
|
14,002
|
$
|
13,685
|
||||||||
Share capital
|
$
|
4,533
|
$
|
4,532
|
$
|
4,432
|
$
|
4,388
|
||||||||
Retained earnings
|
22,885
|
23,248
|
24,408
|
23,499
|
||||||||||||
Accumulated other comprehensive income
(loss)
|
67
|
(7
|
)
|
51
|
47
|
|||||||||||
Shareholders' equity
|
$
|
27,485
|
$
|
27,773
|
$
|
28,891
|
$
|
27,934
|
||||||||
Debt to book capitalization (3) (4)
|
38%
|
37%
|
33%
|
|
33%
|
|
||||||||||
Debt to market capitalization (3) (5)
|
37%
|
30%
|
|
26%
|
|
22%
|
|
|||||||||
After-tax return on average common
shareholders' equity (6) |
2%
|
|
6%
|
|
14%
|
|
12%
|
|
||||||||
After-tax return on average capital
employed (3) (7) |
2%
|
4%
|
10%
|
|
9%
|
|
(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 for the twelve month trailing period; as a percentage of average common shareholders' equity for the period.
|
(7)
|
Calculated as net earnings plus after-tax interest and other financing expense for the twelve month trailing period; as a percentage of average capital employed for the period.
|
§
|
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:
|
—
|
Subsequent to September 30, 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.
|
Canadian Natural Resources Limited
|
37
|
—
|
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 $1,500 million non-revolving term credit facility maturing April 2018. Both facilities were fully drawn at September 30, 2015;
|
§
|
Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages. All of the Company's credit facilities are subject to a financial covenant that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 0.65 to 1.0; and
|
§
|
Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place to minimize the impact in the event of a default.
|
38
|
Canadian Natural Resources Limited
|
($ millions)
|
Remaining
2015
|
2016
|
2017
|
2018
|
2019
|
Thereafter
|
||||||||||||||||||
Product transportation and
pipeline
|
$
|
110
|
$
|
381
|
$
|
337
|
$
|
295
|
$
|
256
|
$
|
1,542
|
||||||||||||
Offshore equipment operating
leases and offshore drilling
|
$
|
119
|
$
|
174
|
$
|
90
|
$
|
68
|
$
|
22
|
$
|
–
|
||||||||||||
Long-term debt (1) (3)
|
$
|
669
|
$
|
1,005
|
$
|
2,472
|
$
|
2,842
|
$
|
1,369
|
$
|
8,229
|
||||||||||||
Interest and other financing
expense (2)
|
$
|
122
|
$
|
633
|
$
|
551
|
$
|
467
|
$
|
427
|
$
|
4,858
|
||||||||||||
Office leases
|
$
|
10
|
$
|
41
|
$
|
42
|
$
|
43
|
$
|
43
|
$
|
239
|
||||||||||||
Other
|
$
|
54
|
$
|
131
|
$
|
65
|
$
|
36
|
$
|
–
|
$
|
–
|
(1)
|
Long-term debt represents principal repayments only and does not reflect original issue discounts and premiums or transaction costs.
|
(2)
|
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 September 30, 2015.
|
(3)
|
At September 30, 2015, the Company had US$500 million of three-month LIBOR plus 0.375% due March 2016 and US$250 million of 6.00% 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.
|
Canadian Natural Resources Limited
|
39
|
As at
(millions of Canadian dollars, unaudited) |
Note
|
Sep 30
2015 |
Dec 31
2014 |
||||||||
ASSETS
|
|||||||||||
Current assets
|
|||||||||||
Cash and cash equivalents
|
$
|
30
|
$
|
25
|
|||||||
Accounts receivable
|
1,314
|
1,889
|
|||||||||
Current income taxes
|
599
|
228
|
|||||||||
Inventory
|
663
|
665
|
|||||||||
Prepaids and other
|
270
|
172
|
|||||||||
Current portion of other long-term assets
|
5
|
468
|
510
|
||||||||
3,344
|
3,489
|
||||||||||
Exploration and evaluation assets
|
3
|
3,437
|
3,557
|
||||||||
Property, plant and equipment
|
4
|
52,830
|
52,480
|
||||||||
Other long-term assets
|
5
|
1,017
|
674
|
||||||||
$
|
60,628
|
$
|
60,200
|
||||||||
LIABILITIES
|
|||||||||||
Current liabilities
|
|||||||||||
Accounts payable
|
$
|
470
|
$
|
564
|
|||||||
Accrued liabilities
|
2,398
|
3,279
|
|||||||||
Current portion of long-term debt
|
6
|
1,673
|
980
|
||||||||
Current portion of other long-term liabilities
|
7
|
167
|
319
|
||||||||
4,708
|
5,142
|
||||||||||
Long-term debt
|
6
|
14,837
|
13,022
|
||||||||
Other long-term liabilities
|
7
|
4,243
|
4,175
|
||||||||
Deferred income taxes
|
9,355
|
8,970
|
|||||||||
33,143
|
31,309
|
||||||||||
SHAREHOLDERS' EQUITY
|
|||||||||||
Share capital
|
9
|
4,533
|
4,432
|
||||||||
Retained earnings
|
22,885
|
24,408
|
|||||||||
Accumulated other comprehensive income
|
10
|
67
|
51
|
||||||||
27,485
|
28,891
|
||||||||||
$
|
60,628
|
$
|
60,200
|
40
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||||||
(millions of Canadian dollars, except per
common share amounts, unaudited)
|
Note
|
Sep 30
2015
|
Sep 30
2014
|
Sep 30
2015
|
Sep 30
2014 |
||||||||||||||
Product sales
|
$
|
3,316
|
$
|
5,370
|
$
|
10,204
|
$
|
16,451
|
|||||||||||
Less: royalties
|
(202
|
)
|
(658
|
)
|
(634
|
)
|
(1,972
|
)
|
|||||||||||
Revenue
|
3,114
|
4,712
|
9,570
|
14,479
|
|||||||||||||||
Expenses
|
|||||||||||||||||||
Production
|
1,166
|
1,267
|
3,607
|
3,866
|
|||||||||||||||
Transportation and blending
|
540
|
747
|
1,804
|
2,473
|
|||||||||||||||
Depletion, depreciation and amortization
|
4
|
1,376
|
1,226
|
4,011
|
3,474
|
||||||||||||||
Administration
|
93
|
87
|
297
|
267
|
|||||||||||||||
Share-based compensation
|
7
|
(87
|
)
|
(122
|
)
|
(102
|
)
|
210
|
|||||||||||
Asset retirement obligation accretion
|
7
|
44
|
49
|
130
|
144
|
||||||||||||||
Interest and other financing expense
|
78
|
79
|
249
|
239
|
|||||||||||||||
Risk management activities
|
13
|
(292
|
)
|
(146
|
)
|
(388
|
)
|
(61
|
)
|
||||||||||
Foreign exchange loss
|
323
|
184
|
596
|
179
|
|||||||||||||||
Gain on disposition of properties
|
4
|
(49
|
)
|
–
|
(49
|
)
|
–
|
||||||||||||
Equity loss from investment
|
5
|
20
|
5
|
32
|
3
|
||||||||||||||
3,212
|
3,376
|
10,187
|
10,794
|
||||||||||||||||
Earnings (loss) before taxes
|
(98
|
)
|
1,336
|
(617
|
)
|
3,685
|
|||||||||||||
Current income tax (recovery) expense
|
8
|
(5
|
)
|
89
|
(113
|
)
|
400
|
||||||||||||
Deferred income tax expense
|
8
|
18
|
208
|
264
|
554
|
||||||||||||||
Net earnings (loss)
|
$
|
(111
|
)
|
$
|
1,039
|
$
|
(768
|
)
|
$
|
2,731
|
|||||||||
Net earnings (loss) per common share
|
|||||||||||||||||||
Basic
|
12
|
$
|
(0.10
|
)
|
$
|
0.95
|
$
|
(0.70
|
)
|
$
|
2.50
|
||||||||
Diluted
|
12
|
$
|
(0.10
|
)
|
$
|
0.94
|
$
|
(0.70
|
)
|
$
|
2.49
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
(millions of Canadian dollars, unaudited)
|
Sep 30
2015
|
Sep 30
2014
|
Sep 30
2015
|
Sep 30
2014 |
||||||||||||
Net earnings (loss)
|
$
|
(111
|
)
|
$
|
1,039
|
$
|
(768
|
)
|
$
|
2,731
|
||||||
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
$5 million (2014 – $nil) – three months ended;
$1 million (2014 – $nil) – nine months ended
|
35
|
(2
|
)
|
(8
|
)
|
(1
|
)
|
|||||||||
Reclassification to net earnings (loss), net of taxes of
$nil (2014 – $1 million) – three months ended;
$1 million (2014 – $1 million) – nine months ended
|
(5
|
)
|
3
|
(11
|
)
|
7
|
||||||||||
30
|
1
|
(19
|
)
|
6
|
||||||||||||
Foreign currency translation adjustment
|
||||||||||||||||
Translation of net investment
|
44
|
–
|
35
|
(1
|
)
|
|||||||||||
Other comprehensive income, net of taxes
|
74
|
1
|
16
|
5
|
||||||||||||
Comprehensive income (loss)
|
$
|
(37
|
)
|
$
|
1,040
|
$
|
(752
|
)
|
$
|
2,736
|
Canadian Natural Resources Limited
|
41
|
Nine Months Ended
|
|||||||||||
(millions of Canadian dollars, unaudited)
|
Note
|
Sep 30
2015 |
Sep 30
2014 |
||||||||
Share capital
|
9
|
||||||||||
Balance – beginning of period
|
$
|
4,432
|
$
|
3,854
|
|||||||
Issued upon exercise of stock options
|
84
|
448
|
|||||||||
Previously recognized liability on stock options exercised for
common shares |
17
|
120
|
|||||||||
Purchase of common shares under Normal Course Issuer Bid
|
–
|
(34
|
)
|
||||||||
Balance – end of period
|
4,533
|
4,388
|
|||||||||
Retained earnings
|
|||||||||||
Balance – beginning of period
|
24,408
|
21,876
|
|||||||||
Net earnings (loss)
|
(768
|
)
|
2,731
|
||||||||
Purchase of common shares under Normal Course Issuer Bid
|
9
|
–
|
(370
|
)
|
|||||||
Dividends on common shares
|
9
|
(755
|
)
|
(738
|
)
|
||||||
Balance – end of period
|
22,885
|
23,499
|
|||||||||
Accumulated other comprehensive income
|
10
|
||||||||||
Balance – beginning of period
|
51
|
42
|
|||||||||
Other comprehensive income, net of taxes
|
16
|
5
|
|||||||||
Balance – end of period
|
67
|
47
|
|||||||||
Shareholders' equity
|
$
|
27,485
|
$
|
27,934
|
42
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
(millions of Canadian dollars, unaudited)
|
Sep 30
2015
|
Sep 30
2014
|
Sep 30
2015
|
Sep 30
2014 |
||||||||||||
Operating activities
|
||||||||||||||||
Net earnings (loss)
|
$
|
(111
|
)
|
$
|
1,039
|
$
|
(768
|
)
|
$
|
2,731
|
||||||
Non-cash items
|
||||||||||||||||
Depletion, depreciation and amortization
|
1,376
|
1,226
|
4,011
|
3,474
|
||||||||||||
Share-based compensation
|
(87
|
)
|
(122
|
)
|
(102
|
)
|
210
|
|||||||||
Asset retirement obligation accretion
|
44
|
49
|
130
|
144
|
||||||||||||
Unrealized risk management (gain) loss
|
(29
|
)
|
(150
|
)
|
200
|
(47
|
)
|
|||||||||
Unrealized foreign exchange loss
|
351
|
185
|
688
|
150
|
||||||||||||
Equity loss from investment
|
20
|
5
|
32
|
3
|
||||||||||||
Deferred income tax expense
|
18
|
208
|
264
|
554
|
||||||||||||
Gain on disposition of properties
|
(49
|
)
|
–
|
(49
|
)
|
–
|
||||||||||
Other
|
19
|
18
|
81
|
69
|
||||||||||||
Abandonment expenditures
|
(65
|
)
|
(82
|
)
|
(265
|
)
|
(245
|
)
|
||||||||
Net change in non-cash working capital
|
121
|
(45
|
)
|
(75
|
)
|
(902
|
)
|
|||||||||
1,608
|
2,331
|
4,147
|
6,141
|
|||||||||||||
Financing activities
|
||||||||||||||||
(Repayment) issue of bank credit facilities and commercial paper, net
|
(168
|
)
|
(151
|
)
|
1,043
|
1,557
|
||||||||||
Issue of medium-term notes, net
|
–
|
–
|
107
|
992
|
||||||||||||
Issue of US dollar debt securities, net
|
–
|
–
|
–
|
1,100
|
||||||||||||
Issue of common shares on exercise of stock options
|
1
|
63
|
84
|
448
|
||||||||||||
Purchase of common shares under Normal Course Issuer Bid
|
–
|
(163
|
)
|
–
|
(404
|
)
|
||||||||||
Dividends on common shares
|
(252
|
)
|
(246
|
)
|
(748
|
)
|
(709
|
)
|
||||||||
Net change in non-cash working capital
|
–
|
(5
|
)
|
(40
|
)
|
(16
|
)
|
|||||||||
(419
|
)
|
(502
|
)
|
446
|
2,968
|
|||||||||||
Investing activities
|
||||||||||||||||
Net expenditures on exploration and evaluation assets
|
(5
|
)
|
(92
|
)
|
(80
|
)
|
(1,093
|
)
|
||||||||
Net expenditures on property, plant and equipment
|
(1,170
|
)
|
(2,001
|
)
|
(3,604
|
)
|
(8,186
|
)
|
||||||||
Investment in other long-term assets
|
–
|
–
|
(112
|
)
|
(113
|
)
|
||||||||||
Net change in non-cash working capital
|
(16
|
)
|
249
|
(792
|
)
|
283
|
||||||||||
(1,191
|
)
|
(1,844
|
)
|
(4,588
|
)
|
(9,109
|
)
|
|||||||||
(Decrease) increase in cash and cash equivalents
|
(2
|
)
|
(15
|
)
|
5
|
–
|
||||||||||
Cash and cash equivalents –
beginning of period
|
32
|
31
|
25
|
16
|
||||||||||||
Cash and cash equivalents –
end of period
|
$
|
30
|
$
|
16
|
$
|
30
|
$
|
16
|
||||||||
Interest paid
|
$
|
172
|
$
|
142
|
$
|
447
|
$
|
387
|
||||||||
Income taxes (received) paid
|
$
|
(128
|
)
|
$
|
63
|
$
|
136
|
$
|
665
|
Canadian Natural Resources Limited
|
43
|
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, net
|
63
|
–
|
28
|
–
|
91
|
|||||||||||||||
Transfers to property, plant and
equipment
|
(223
|
)
|
–
|
–
|
–
|
(223
|
)
|
|||||||||||||
Foreign exchange adjustments
|
–
|
–
|
12
|
–
|
12
|
|||||||||||||||
At September 30, 2015
|
$
|
3,266
|
$
|
–
|
$
|
171
|
$
|
–
|
$
|
3,437
|
44
|
Canadian Natural Resources Limited
|
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
|
1,115
|
193
|
399
|
2,024
|
6
|
24
|
3,761
|
|||||||||||||||||||||
Transfers from E&E assets
|
223
|
–
|
–
|
–
|
–
|
–
|
223
|
|||||||||||||||||||||
Disposals/derecognitions
|
(460
|
)
|
–
|
–
|
(86
|
)
|
–
|
–
|
(546
|
)
|
||||||||||||||||||
Foreign exchange adjustments and other
|
–
|
973
|
624
|
–
|
–
|
–
|
1,597
|
|||||||||||||||||||||
At September 30, 2015
|
$
|
61,484
|
$
|
7,348
|
$
|
4,881
|
$
|
23,886
|
$
|
576
|
$
|
376
|
$
|
98,551
|
||||||||||||||
Accumulated depletion and depreciation
|
||||||||||||||||||||||||||||
At December 31, 2014
|
$
|
31,886
|
$
|
4,049
|
$
|
2,890
|
$
|
1,864
|
$
|
120
|
$
|
227
|
$
|
41,036
|
||||||||||||||
Expense
|
3,167
|
278
|
115
|
423
|
9
|
19
|
4,011
|
|||||||||||||||||||||
Disposals/derecognitions
|
(374
|
)
|
–
|
–
|
(86
|
)
|
–
|
–
|
(460
|
)
|
||||||||||||||||||
Foreign exchange adjustments and other
|
(3
|
)
|
660
|
477
|
–
|
–
|
–
|
1,134
|
||||||||||||||||||||
At September 30, 2015
|
$
|
34,676
|
$
|
4,987
|
$
|
3,482
|
$
|
2,201
|
$
|
129
|
$
|
246
|
$
|
45,721
|
||||||||||||||
Net book value
– at September 30, 2015
|
$
|
26,808
|
$
|
2,361
|
$
|
1,399
|
$
|
21,685
|
$
|
447
|
$
|
130
|
$
|
52,830
|
||||||||||||||
– at December 31, 2014
|
$
|
28,720
|
$
|
2,133
|
$
|
968
|
$
|
20,084
|
$
|
450
|
$
|
125
|
$
|
52,480
|
Project costs not subject to depletion and depreciation
|
Sep 30
2015
|
Dec 31
2014
|
||||||
Horizon
|
$
|
7,010
|
$
|
5,492
|
||||
Kirby Thermal Oil Sands – North
|
$
|
777
|
$
|
681
|
Canadian Natural Resources Limited
|
45
|
Sep 30
2015
|
Dec 31
2014
|
|||||||
Investment in North West Redwater Partnership
|
$
|
266
|
$
|
298
|
||||
North West Redwater Partnership subordinated debt (1)
|
248
|
120
|
||||||
Risk Management (note 13)
|
900
|
599
|
||||||
Other
|
71
|
167
|
||||||
1,485
|
1,184
|
|||||||
Less: current portion
|
468
|
510
|
||||||
$
|
1,017
|
$
|
674
|
(1)
|
Includes accrued interest.
|
46
|
Canadian Natural Resources Limited
|
Sep 30
2015
|
Dec 31
2014 |
|||||||
Canadian dollar denominated debt, unsecured
|
||||||||
Bank credit facilities
|
$
|
2,845
|
$
|
2,404
|
||||
Medium-term notes
|
2,500
|
2,400
|
||||||
5,345
|
4,804
|
|||||||
US dollar denominated debt, unsecured
|
||||||||
Bank credit facilities (September 30, 2015 – US$393 million;
December 31, 2014 – $nil)
|
526
|
–
|
||||||
Commercial paper (US$500 million)
|
669
|
580
|
||||||
US dollar debt securities (US$7,500 million)
|
10,046
|
8,701
|
||||||
11,241
|
9,281
|
|||||||
Long-term debt before transaction costs and original issue discounts, net
|
16,586
|
14,085
|
||||||
Less: original issue discounts, net (1)
|
(10
|
)
|
(21
|
)
|
||||
transaction costs (1) (2)
|
(66
|
)
|
(62
|
)
|
||||
16,510
|
14,002
|
|||||||
Less: current portion of commercial paper
|
669
|
580
|
||||||
current portion of long-term debt (1) (2)
|
1,004
|
400
|
||||||
$
|
14,837
|
$
|
13,022
|
(1)
|
The Company has included unamortized original issue discounts and premiums, and directly attributable transaction costs in the carrying amount of the outstanding debt.
|
(2)
|
Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other professional fees.
|
§
|
a $100 million demand credit facility;
|
§
|
a $1,000 million non-revolving term credit facility maturing January 2017;
|
§
|
a $1,500 million non-revolving term credit facility maturing April 2018;
|
§
|
a $2,425 million revolving syndicated credit facility maturing June 2019;
|
§
|
a $2,425 million revolving syndicated credit facility maturing June 2020; and
|
§
|
a £15 million demand credit facility related to the Company's North Sea operations.
|
Canadian Natural Resources Limited
|
47
|
Sep 30
2015 |
Dec 31
2014 |
|||||||
Asset retirement obligations
|
$
|
4,327
|
$
|
4,221
|
||||
Share-based compensation
|
61
|
203
|
||||||
Other
|
22
|
70
|
||||||
4,410
|
4,494
|
|||||||
Less: current portion
|
167
|
319
|
||||||
$
|
4,243
|
$
|
4,175
|
48
|
Canadian Natural Resources Limited
|
Sep 30
2015 |
Dec 31
2014 |
|||||||
Balance – beginning of period
|
$
|
4,221
|
$
|
4,162
|
||||
Liabilities incurred
|
6
|
41
|
||||||
Liabilities acquired, net
|
30
|
404
|
||||||
Liabilities settled
|
(265
|
)
|
(346
|
)
|
||||
Asset retirement obligation accretion
|
130
|
193
|
||||||
Revision of cost, inflation rates and timing estimates
|
–
|
(907
|
)
|
|||||
Change in discount rate
|
–
|
558
|
||||||
Foreign exchange adjustments
|
205
|
116
|
||||||
Balance – end of period
|
4,327
|
4,221
|
||||||
Less: current portion
|
127
|
121
|
||||||
$
|
4,200
|
$
|
4,100
|
Sep 30
2015 |
Dec 31
2014 |
|||||||
Balance – beginning of period
|
$
|
203
|
$
|
260
|
||||
Share-based compensation (recovery) expense
|
(102
|
)
|
66
|
|||||
Cash payment for stock options surrendered
|
(1
|
)
|
(8
|
)
|
||||
Transferred to common shares
|
(17
|
)
|
(129
|
)
|
||||
(Recovered from) capitalized to Oil Sands Mining and Upgrading
|
(22
|
)
|
14
|
|||||
Balance – end of period
|
61
|
203
|
||||||
Less: current portion
|
40
|
158
|
||||||
$
|
21
|
$
|
45
|
Canadian Natural Resources Limited
|
49
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
Sep 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||
Current corporate income tax expense – North
America
|
$
|
65
|
$
|
162
|
$
|
152
|
$
|
579
|
||||||||
Current corporate income tax (recovery) expense –
North Sea
|
(16
|
)
|
14
|
(99
|
)
|
(45
|
)
|
|||||||||
Current corporate income tax expense – Offshore
Africa
|
5
|
21
|
12
|
35
|
||||||||||||
Current PRT (1) recovery – North Sea
|
(61
|
)
|
(114
|
)
|
(187
|
)
|
(187
|
)
|
||||||||
Other taxes
|
2
|
6
|
9
|
18
|
||||||||||||
Current income tax (recovery) expense
|
(5
|
)
|
89
|
(113
|
)
|
400
|
||||||||||
Deferred corporate income tax expense
|
8
|
158
|
217
|
427
|
||||||||||||
Deferred PRT (1) expense – North Sea
|
10
|
50
|
47
|
127
|
||||||||||||
Deferred income tax expense
|
18
|
208
|
264
|
554
|
||||||||||||
Income tax expense
|
$
|
13
|
$
|
297
|
$
|
151
|
$
|
954
|
(1)
|
Petroleum Revenue Tax.
|
Nine Months Ended Sep 30, 2015
|
||||||||
Issued common shares
|
Number of shares (thousands)
|
Amount
|
||||||
Balance – beginning of period
|
1,091,837
|
$
|
4,432
|
|||||
Issued upon exercise of stock options
|
2,571
|
84
|
||||||
Previously recognized liability on stock options exercised for
common shares
|
–
|
17
|
||||||
Balance – end of period
|
1,094,408
|
$
|
4,533
|
50
|
Canadian Natural Resources Limited
|
Nine Months Ended Sep 30, 2015
|
||||||||
Stock options (thousands)
|
Weighted
average
exercise price |
|||||||
Outstanding – beginning of period
|
71,708
|
$
|
35.60
|
|||||
Granted
|
5,120
|
$
|
33.16
|
|||||
Surrendered for cash settlement
|
(172
|
)
|
$
|
33.43
|
||||
Exercised for common shares
|
(2,571
|
)
|
$
|
32.71
|
||||
Forfeited
|
(6,777
|
)
|
$
|
35.12
|
||||
Outstanding – end of period
|
67,308
|
$
|
35.58
|
|||||
Exercisable – end of period
|
20,610
|
$
|
36.59
|
Sep 30
2015 |
Sep 30
2014
|
|||||||
Derivative financial instruments designated as cash flow hedges
|
$
|
75
|
$
|
87
|
||||
Foreign currency translation adjustment
|
(8
|
)
|
(40
|
)
|
||||
$
|
67
|
$
|
47
|
Canadian Natural Resources Limited
|
51
|
Sep 30
2015 |
Dec 31
2014 |
|||||||
Long-term debt (1)
|
$
|
16,510
|
$
|
14,002
|
||||
Total shareholders' equity
|
$
|
27,485
|
$
|
28,891
|
||||
Debt to book capitalization
|
38%
|
33%
|
(1)
|
Includes the current portion of long-term debt.
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||||
Sep 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
||||||||||||||
Weighted average common shares outstanding
– basic (thousands of shares) |
1,094,398
|
1,092,149
|
1,093,638
|
1,091,864
|
|||||||||||||
Effect of dilutive stock options (thousands of shares) (1)
|
–
|
10,613
|
–
|
7,052
|
|||||||||||||
Weighted average common shares outstanding
– diluted (thousands of shares) |
1,094,398
|
1,102,762
|
1,093,638
|
1,098,916
|
|||||||||||||
Net earnings (loss)
|
$
|
(111
|
)
|
$
|
1,039
|
$
|
(768
|
)
|
$
|
2,731
|
|||||||
Net earnings (loss) per common share
|
– basic |
$
|
(0.10
|
)
|
$
|
0.95
|
$
|
(0.70
|
)
|
$
|
2.50
|
||||||
|
– diluted |
$
|
(0.10
|
)
|
$
|
0.94
|
$
|
(0.70
|
)
|
$
|
2.49
|
(1)
|
For the three months ended September 30, 2015, the dilutive effect of 2,000 options has not been included in the determination of the weighted average number of common shares outstanding as the inclusion would be anti-dilutive to the net loss per common share (nine months ended September 30, 2015 – 1,127,000).
|
52
|
Canadian Natural Resources Limited
|
Sep 30, 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
|
$
|
1,314
|
$
|
–
|
$
|
–
|
$
|
–
|
$
|
1,314
|
||||||||||
Other long-term assets
|
248
|
211
|
689
|
–
|
1,148
|
|||||||||||||||
Accounts payable
|
–
|
–
|
–
|
(470
|
)
|
(470
|
)
|
|||||||||||||
Accrued liabilities
|
–
|
–
|
–
|
(2,398
|
)
|
(2,398
|
)
|
|||||||||||||
Long-term debt (1)
|
–
|
–
|
–
|
(16,510
|
)
|
(16,510
|
)
|
|||||||||||||
$
|
1,562
|
$
|
211
|
$
|
689
|
$
|
(19,378
|
)
|
$
|
(16,916
|
)
|
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.
|
Sep 30, 2015
|
||||||||||||||||
Carrying amount
|
Fair value
|
|||||||||||||||
Asset (liability) (1) (2)
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
Other long-term assets (3)
|
$
|
1,148
|
$
|
–
|
$
|
900
|
$
|
248
|
||||||||
Fixed rate long-term debt (4) (5)
|
$
|
(12,470
|
)
|
$
|
(12,594
|
)
|
$
|
–
|
$
|
–
|
Dec 31, 2014
|
||||||||||||||||
Carrying amount
|
Fair value
|
|||||||||||||||
Asset (liability) (1) (2)
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
Other long-term assets (3)
|
$
|
719
|
$
|
–
|
$
|
599
|
$
|
120
|
||||||||
Fixed rate long-term debt (4) (5)
|
$
|
(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 North West Redwater Partnership subordinated debt is based on the present value of future cash receipts.
|
(4)
|
The fair value of fixed rate long-term debt has been determined based on quoted market prices.
|
(5)
|
Includes the current portion of fixed rate long-term debt.
|
Canadian Natural Resources Limited
|
53
|
Asset (liability)
|
Sep 30, 2015
|
Dec 31, 2014
|
||||||
Derivatives held for trading
|
||||||||
Crude oil price collars
|
$
|
189
|
$
|
410
|
||||
Crude oil WCS (1) differential swaps
|
–
|
(16
|
)
|
|||||
Foreign currency forward contracts
|
22
|
21
|
||||||
Cash flow hedges
|
||||||||
Foreign currency forward contracts
|
12
|
11
|
||||||
Cross currency swaps
|
677
|
173
|
||||||
$
|
900
|
$
|
599
|
|||||
Included within:
|
||||||||
Current portion of other long-term assets
|
$
|
427
|
$
|
436
|
||||
Other long-term assets
|
473
|
163
|
||||||
$
|
900
|
$
|
599
|
(1)
|
Western Canadian Select.
|
Asset (liability)
|
Nine Months Ended
Sep 30, 2015 |
Year Ended
Dec 31, 2014 |
||||||
Balance – beginning of period
|
$
|
599
|
$
|
(136
|
)
|
|||
Net change in fair value of outstanding derivative financial instruments
recognized in:
|
||||||||
Risk management activities
|
(200
|
)
|
451
|
|||||
Foreign exchange
|
522
|
270
|
||||||
Other comprehensive income (loss)
|
(21
|
)
|
14
|
|||||
Balance – end of period
|
900
|
599
|
||||||
Less: current portion
|
427
|
436
|
||||||
$
|
473
|
$
|
163
|
54
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
Sep 30
2015 |
Sep 30
2014 |
Sep 30
2015 |
Sep 30
2014 |
|||||||||||||
Net realized risk management (gain) loss
|
$
|
(263
|
)
|
$
|
4
|
$
|
(588
|
)
|
$
|
(14
|
)
|
|||||
Net unrealized risk management (gain) loss
|
(29
|
)
|
(150
|
)
|
200
|
(47
|
)
|
|||||||||
$
|
(292
|
)
|
$
|
(146
|
)
|
$
|
(388
|
)
|
$
|
(61
|
)
|
a)
|
Market risk
|
Remaining term
|
Volume
|
Weighted average price
|
Index
|
|||||
Crude oil
|
||||||||
Price collars
|
Oct 2015
|
–
|
Dec 2015
|
50,000 bbl/d
|
US$80.00
|
–
|
US$120.52
|
Brent
|
Canadian Natural Resources Limited
|
55
|
Remaining term
|
Amount
|
Exchange rate
(US$/C$)
|
Interest rate
(US$)
|
Interest rate
(C$)
|
|||
Cross currency
|
|||||||
Swaps
|
Oct 2015
|
–
|
Mar 2016
|
US$500
|
1.109
|
Three-month
LIBOR plus
0.375%
|
Three-month
CDOR (1) plus
0.309%
|
Oct 2015
|
–
|
Aug 2016
|
US$250
|
1.116
|
6.00%
|
5.40%
|
|
Oct 2015
|
–
|
May 2017
|
US$1,100
|
1.170
|
5.70%
|
5.10%
|
|
Oct 2015
|
–
|
Nov 2021
|
US$500
|
1.022
|
3.45%
|
3.96%
|
|
Oct 2015
|
–
|
Mar 2038
|
US$550
|
1.170
|
6.25%
|
5.76%
|
(1)
|
Canadian Dealer Offered Rate ("CDOR").
|
b)
|
Credit risk
|
c)
|
Liquidity risk
|
56
|
Canadian Natural Resources Limited
|
Less than
1 year |
1 to less than
2 years |
2 to less than
5 years |
Thereafter
|
|||||||||||||
Accounts payable
|
$
|
470
|
$
|
–
|
$
|
–
|
$
|
–
|
||||||||
Accrued liabilities
|
$
|
2,398
|
$
|
–
|
$
|
–
|
$
|
–
|
||||||||
Long-term debt (1)
|
$
|
1,674
|
$
|
2,472
|
$
|
5,712
|
$
|
6,728
|
(1)
|
Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
|
Remaining
2015
|
2016
|
2017
|
2018
|
2019
|
Thereafter | |||||||||||||||||||
Product transportation
and pipeline |
$
|
110
|
$
|
381
|
$
|
337
|
$
|
295
|
$
|
256
|
$
|
1,542
|
||||||||||||
Offshore equipment operating
leases and offshore drilling
|
$
|
119
|
$
|
174
|
$
|
90
|
$
|
68
|
$
|
22
|
$
|
–
|
||||||||||||
Office leases
|
$
|
10
|
$
|
41
|
$
|
42
|
$
|
43
|
$
|
43
|
$
|
239
|
||||||||||||
Other
|
$
|
54
|
$
|
131
|
$
|
65
|
$
|
36
|
$
|
–
|
$
|
–
|
Canadian Natural Resources Limited
|
57
|
Exploration and Production
|
|||||||||||||||||||||||||||||||||||||||||||||||||
North America
|
North Sea
|
Offshore Africa
|
Total Exploration and Production
|
||||||||||||||||||||||||||||||||||||||||||||||
(millions of Canadian dollars,
unaudited) |
Three Months Ended
Sep 30 |
Nine Months Ended
Sep 30 |
Three Months Ended
Sep 30 |
Nine Months Ended
Sep 30 |
Three Months Ended
Sep 30 |
Nine Months Ended
Sep 30 |
Three Months Ended
Sep 30 |
Nine Months Ended
Sep 30 |
|||||||||||||||||||||||||||||||||||||||||
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
||||||||||||||||||||||||||||||||||
Segmented product sales
|
2,273
|
4,257
|
7,252
|
12,377
|
152
|
72
|
505
|
496
|
156
|
196
|
334
|
392
|
2,581
|
4,525
|
8,091
|
13,265
|
|||||||||||||||||||||||||||||||||
Less: royalties
|
(179
|
)
|
(577
|
)
|
(581
|
)
|
(1,752
|
)
|
–
|
(1
|
)
|
(1
|
)
|
(2
|
)
|
(7
|
)
|
(22
|
)
|
(15
|
)
|
(35
|
)
|
(186
|
)
|
(600
|
)
|
(597
|
)
|
(1,789
|
)
|
||||||||||||||||||
Segmented revenue
|
2,094
|
3,680
|
6,671
|
10,625
|
152
|
71
|
504
|
494
|
149
|
174
|
319
|
357
|
2,395
|
3,925
|
7,494
|
11,476
|
|||||||||||||||||||||||||||||||||
Segmented expenses
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Production
|
615
|
755
|
2,011
|
2,170
|
139
|
59
|
434
|
325
|
86
|
50
|
156
|
138
|
840
|
864
|
2,601
|
2,633
|
|||||||||||||||||||||||||||||||||
Transportation and blending
|
521
|
746
|
1,755
|
2,471
|
14
|
–
|
43
|
3
|
–
|
1
|
1
|
1
|
535
|
747
|
1,799
|
2,475
|
|||||||||||||||||||||||||||||||||
Depletion, depreciation and
amortization
|
1,059
|
1,020
|
3,183
|
2,842
|
95
|
26
|
281
|
149
|
54
|
41
|
115
|
74
|
1,208
|
1,087
|
3,579
|
3,065
|
|||||||||||||||||||||||||||||||||
Asset retirement obligation accretion
|
23
|
25
|
70
|
73
|
10
|
9
|
29
|
28
|
3
|
3
|
8
|
8
|
36
|
37
|
107
|
109
|
|||||||||||||||||||||||||||||||||
Realized risk management activities
|
(263
|
)
|
4
|
(588
|
)
|
(14
|
)
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(263
|
)
|
4
|
(588
|
)
|
(14
|
)
|
|||||||||||||||||||||||||||
Gain on disposition of properties
|
(49
|
)
|
–
|
(49
|
)
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(49
|
)
|
–
|
(49
|
)
|
–
|
|||||||||||||||||||||||||||||
Equity loss from investment
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
|||||||||||||||||||||||||||||||||
Total segmented expenses
|
1,906
|
2,550
|
6,382
|
7,542
|
258
|
94
|
787
|
505
|
143
|
95
|
280
|
221
|
2,307
|
2,739
|
7,449
|
8,268
|
|||||||||||||||||||||||||||||||||
Segmented earnings (loss) before
the following
|
188
|
1,130
|
289
|
3,083
|
(106
|
)
|
(23
|
)
|
(283
|
)
|
(11
|
)
|
6
|
79
|
39
|
136
|
88
|
1,186
|
45
|
3,208
|
|||||||||||||||||||||||||||||
Non-segmented expenses
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Administration
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Share-based compensation
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Interest and other financing expense
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Unrealized risk management activities
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Foreign exchange loss
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Total non-segmented expenses
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Earnings (loss) before taxes
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Current income tax (recovery)
expense
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Deferred income tax expense
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Net earnings (loss)
|
58
|
Canadian Natural Resources Limited
|
Oil Sands Mining and Upgrading
|
Midstream
|
Inter-segment elimination and other
|
Total
|
||||||||||||||||||||||||||||||||||||||||||||||
(millions of Canadian dollars,
unaudited) |
Three Months Ended
Sep 30 |
Nine Months Ended
Sep 30 |
Three Months Ended
Sep 30 |
Nine Months Ended
Sep 30 |
Three Months Ended
Sep 30 |
Nine Months Ended
Sep 30 |
Three Months Ended
Sep 30 |
Nine Months Ended
Sep 30 |
|||||||||||||||||||||||||||||||||||||||||
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
||||||||||||||||||||||||||||||||||
Segmented product sales
|
722
|
840
|
2,071
|
3,163
|
33
|
30
|
103
|
91
|
(20
|
)
|
(25
|
)
|
(61
|
)
|
(68
|
)
|
3,316
|
5,370
|
10,204
|
16,451
|
|||||||||||||||||||||||||||||
Less: royalties
|
(16
|
)
|
(58
|
)
|
(37
|
)
|
(183
|
)
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(202
|
)
|
(658
|
)
|
(634
|
)
|
(1,972
|
)
|
|||||||||||||||||||||||||
Segmented revenue
|
706
|
782
|
2,034
|
2,980
|
33
|
30
|
103
|
91
|
(20
|
)
|
(25
|
)
|
(61
|
)
|
(68
|
)
|
3,114
|
4,712
|
9,570
|
14,479
|
|||||||||||||||||||||||||||||
Segmented expenses
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Production
|
321
|
398
|
988
|
1,214
|
7
|
8
|
25
|
27
|
(2
|
)
|
(3
|
)
|
(7
|
)
|
(8
|
)
|
1,166
|
1,267
|
3,607
|
3,866
|
|||||||||||||||||||||||||||||
Transportation and blending
|
22
|
18
|
62
|
55
|
–
|
–
|
–
|
–
|
(17
|
)
|
(18
|
)
|
(57
|
)
|
(57
|
)
|
540
|
747
|
1,804
|
2,473
|
|||||||||||||||||||||||||||||
Depletion, depreciation and
amortization
|
165
|
137
|
423
|
402
|
3
|
2
|
9
|
7
|
–
|
–
|
–
|
–
|
1,376
|
1,226
|
4,011
|
3,474
|
|||||||||||||||||||||||||||||||||
Asset retirement obligation accretion
|
8
|
12
|
23
|
35
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
44
|
49
|
130
|
144
|
|||||||||||||||||||||||||||||||||
Realized risk management activities
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(263
|
)
|
4
|
(588
|
)
|
(14
|
)
|
||||||||||||||||||||||||||||||
Gain on disposition of properties
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(49
|
)
|
–
|
(49
|
)
|
–
|
|||||||||||||||||||||||||||||||
Equity loss from investment
|
–
|
–
|
–
|
–
|
20
|
5
|
32
|
3
|
–
|
–
|
–
|
–
|
20
|
5
|
32
|
3
|
|||||||||||||||||||||||||||||||||
Total segmented expenses
|
516
|
565
|
1,496
|
1,706
|
30
|
15
|
66
|
37
|
(19
|
)
|
(21
|
)
|
(64
|
)
|
(65
|
)
|
2,834
|
3,298
|
8,947
|
9,946
|
|||||||||||||||||||||||||||||
Segmented earnings (loss) before
the following
|
190
|
217
|
538
|
1,274
|
3
|
15
|
37
|
54
|
(1
|
)
|
(4
|
)
|
3
|
(3
|
)
|
280
|
1,414
|
623
|
4,533
|
||||||||||||||||||||||||||||||
Non-segmented expenses
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Administration
|
93
|
87
|
297
|
267
|
|||||||||||||||||||||||||||||||||||||||||||||
Share-based compensation
|
(87
|
)
|
(122
|
)
|
(102
|
)
|
210
|
||||||||||||||||||||||||||||||||||||||||||
Interest and other financing expense
|
78
|
79
|
249
|
239
|
|||||||||||||||||||||||||||||||||||||||||||||
Unrealized risk management activities
|
(29
|
)
|
(150
|
)
|
200
|
(47
|
)
|
||||||||||||||||||||||||||||||||||||||||||
Foreign exchange loss
|
323
|
184
|
596
|
179
|
|||||||||||||||||||||||||||||||||||||||||||||
Total non-segmented expenses
|
378
|
78
|
1,240
|
848
|
|||||||||||||||||||||||||||||||||||||||||||||
Earnings (loss) before taxes
|
(98
|
)
|
1,336
|
(617
|
)
|
3,685
|
|||||||||||||||||||||||||||||||||||||||||||
Current income tax (recovery)
expense
|
(5
|
)
|
89
|
(113
|
)
|
400
|
|||||||||||||||||||||||||||||||||||||||||||
Deferred income tax expense
|
18
|
208
|
264
|
554
|
|||||||||||||||||||||||||||||||||||||||||||||
Net earnings (loss)
|
(111
|
)
|
1,039
|
(768
|
)
|
2,731
|
Canadian Natural Resources Limited
|
59
|
Nine Months Ended
|
||||||||||||||||||||||||
Sep 30, 2015
|
Sep 30, 2014
|
|||||||||||||||||||||||
Net
expenditures
|
Non-cash
and fair value changes(2)
|
Capitalized
costs
|
Net
expenditures
|
Non-cash
and fair value changes(2)
|
Capitalized
costs
|
|||||||||||||||||||
Exploration and
evaluation assets
|
||||||||||||||||||||||||
Exploration and
Production
|
||||||||||||||||||||||||
North America (3)
|
$
|
63
|
$
|
(223
|
)
|
$
|
(160
|
)
|
$
|
1,028
|
$
|
(160
|
)
|
$
|
868
|
|||||||||
North Sea
|
–
|
–
|
–
|
–
|
–
|
–
|
||||||||||||||||||
Offshore Africa
|
28
|
–
|
28
|
65
|
–
|
65
|
||||||||||||||||||
$
|
91
|
$
|
(223
|
)
|
$
|
(132
|
)
|
$
|
1,093
|
$
|
(160
|
)
|
$
|
933
|
||||||||||
Property, plant and
equipment
|
||||||||||||||||||||||||
Exploration and
Production
|
||||||||||||||||||||||||
North America (3)
|
$
|
989
|
$
|
(111
|
)
|
$
|
878
|
$
|
5,443
|
$
|
302
|
$
|
5,745
|
|||||||||||
North Sea
|
196
|
(3
|
)
|
193
|
295
|
–
|
295
|
|||||||||||||||||
Offshore Africa
|
399
|
–
|
399
|
89
|
–
|
89
|
||||||||||||||||||
1,584
|
(114
|
)
|
1,470
|
5,827
|
302
|
6,129
|
||||||||||||||||||
Oil Sands Mining and
Upgrading (4)
|
2,024
|
(86
|
)
|
1,938
|
2,248
|
(92
|
)
|
2,156
|
||||||||||||||||
Midstream
|
6
|
–
|
6
|
78
|
–
|
78
|
||||||||||||||||||
Head office
|
24
|
–
|
24
|
33
|
(1
|
)
|
32
|
|||||||||||||||||
$
|
3,638
|
$
|
(200
|
)
|
$
|
3,438
|
$
|
8,186
|
$
|
209
|
$
|
8,395
|
(1)
|
This table provides a reconciliation of capitalized costs including derecognitions and does not include the impact of foreign exchange adjustments.
|
(2)
|
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.
|
(3)
|
The above noted figures do not include the impact of a pre-tax gain on the sale of properties totaling $49 million.
|
(4)
|
Net expenditures for Oil Sands Mining and Upgrading also include capitalized interest and share-based compensation.
|
60
|
Canadian Natural Resources Limited
|
Total Assets
|
||||||||
Sep 30
2015
|
Dec 31
2014 |
|||||||
Exploration and Production
|
||||||||
North America
|
$
|
32,418
|
$
|
34,382
|
||||
North Sea
|
2,914
|
2,711
|
||||||
Offshore Africa
|
1,757
|
1,214
|
||||||
Other
|
70
|
18
|
||||||
Oil Sands Mining and Upgrading
|
22,249
|
20,702
|
||||||
Midstream
|
1,090
|
1,048
|
||||||
Head office
|
130
|
125
|
||||||
$
|
60,628
|
$
|
60,200
|
Canadian Natural Resources Limited
|
61
|
Interest coverage ratios for the twelve month period ended September 30, 2015:
|
|
Interest coverage (times)
|
|
Net earnings (1)
|
2.5x
|
Cash flow from operations (2)
|
12.7x
|
(1)
|
Net earnings 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.
|
62
|
Canadian Natural Resources Limited
|
Board of Directors
Catherine M. Best, FCA, ICD.D
N. Murray Edwards, O.C.
Timothy W. Faithfull
Honourable Gary A. Filmon, P.C., O.C., O.M.
Christopher L. Fong
Ambassador Gordon D. Giffin
Wilfred A. Gobert
Steve W. Laut
Honourable Frank J. McKenna, P.C., O.C., O.N.B., Q.C.
David A. Tuer
Annette M. Verschuren, O.C.
Officers
N. Murray Edwards
Executive Chairman of the Board Steve W. Laut
President Tim S. McKay
Chief Operating Officer Douglas A. Proll
Executive Vice-President Lyle G. Stevens
Executive Vice-President, Canadian Conventional Corey B. Bieber
Chief Financial Officer and Senior Vice-President, Finance Réal M. Cusson
Senior Vice-President, Marketing Réal J.H. Doucet
Senior Vice-President, Horizon Projects Darren M. Fichter
Senior Vice-President, Exploitation Terry J. Jocksch
Senior Vice-President, Thermal Ronald K. Laing
Senior Vice-President, Corporate Development and Land Paul M. Mendes
Vice-President, Legal and General Counsel Bill R. Peterson
Senior Vice-President, Production and Development Operations Ken W. Stagg
Senior Vice-President, Exploration Scott G. Stauth
Senior Vice-President, North America Operations Betty Yee
Vice-President, Land Bruce E. McGrath
Corporate Secretary |
International Operations
CNR International (U.K.) Limited
Aberdeen, Scotland
W. David R. Bell
Vice-President, Exploration, International Barry Duncan
Vice-President, Finance, International Andrew M. McBoyle
Vice-President, Exploitation, International David B. Whitehouse
Vice-President, Development Operations, International Stock Listing
Toronto Stock Exchange
Trading Symbol – CNQ New York Stock Exchange
Trading Symbol – CNQ Registrar and Transfer Agent
Computershare Trust Company of Canada
Calgary, Alberta Toronto, Ontario Computershare Investor Services LLC
New York, New York Investor Relations
Telephone: (403) 514-7777
Email: ir@cnrl.com
|
Canadian Natural Resources Limited
|
63
|
C A N A D I A N N A T U R A L R E S O U R C E S L I M I T E D
2100, 855 - 2 Street S.W., Calgary, Alberta T2P 4J8
Telephone: (403) 517-6700 Facsimile: (403) 517-7350
Website: www.cnrl.com
Printed in Canada
|