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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Canadian Natural Resources Ltd | NYSE:CNQ | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
-0.24 | -0.32% | 74.62 | 75.82 | 74.19 | 75.74 | 2,752,639 | 01:00:00 |
Exhibit Number
|
Description
|
|
|
99.1
|
Unaudited Interim Consolidated Financial Statements for the period
ended March 31, 2015 and Management’s Discussion and Analysis
relating to the period ended March 31, 2015.
|
CANADIAN NATURAL RESOURCES LIMITED
(Registrant)
|
|||
Date: May 13, 2015
|
By:
|
/s/ B. E. McGRATH | |
B. E. McGRATH | |||
Corporate Secretary | |||
Three Months Ended
|
|||||||||||||
($ Millions, except per common share amounts) |
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Net earnings (loss)
|
$
|
(252
|
)
|
$
|
1,198
|
$
|
622
|
||||||
Per common share
|
– basic |
$
|
(0.23
|
)
|
$
|
1.10
|
$
|
0.57
|
|||||
|
– diluted |
$
|
(0.23
|
)
|
$
|
1.09
|
$
|
0.57
|
|||||
Adjusted net earnings from operations (1)
|
$
|
21
|
$
|
756
|
$
|
921
|
|||||||
Per common share
|
– basic |
$
|
0.02
|
$
|
0.69
|
$
|
0.85
|
||||||
|
– diluted |
$
|
0.02
|
$
|
0.69
|
$
|
0.85
|
||||||
Cash flow from operations (2)
|
$
|
1,370
|
$
|
2,368
|
$
|
2,146
|
|||||||
Per common share
|
– basic |
$
|
1.25
|
$
|
2.17
|
$
|
1.97
|
||||||
|
– diluted |
$
|
1.25
|
$
|
2.16
|
$
|
1.97
|
||||||
Capital expenditures, net of dispositions
|
$
|
1,412
|
$
|
2,220
|
$
|
1,893
|
|||||||
Daily production, before royalties
|
|||||||||||||
Natural gas (MMcf/d)
|
1,771
|
1,733
|
1,175
|
||||||||||
Crude oil and NGLs (bbl/d)
|
602,809
|
572,040
|
488,788
|
||||||||||
Equivalent production (BOE/d) (3)
|
898,053
|
860,920
|
684,647
|
(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. |
§ | Strong operational performance continues for all business segments of the Company. Canadian Natural’s Exploration and Production (“E&P”) assets continue to generate free cash flow and support the transition to a longer life and lower decline asset base. Q1/15 operational highlights include: |
— | Record overall quarterly corporate production of 898,053 BOE/d driven by records in both quarterly crude oil and NGL, and natural gas production volumes. |
— | Corporate quarterly crude oil and NGL production reached record levels averaging 602,809 bbl/d for Q1/15, an increase of 23% and 5% from Q1/14 and Q4/14 levels respectively. |
– | The Company’s E&P crude oil and NGL segment showed strong overall production volumes driven by: |
a. | Record North America light crude oil and NGL quarterly production volumes of 97,561 bbl/d. |
b. | Record thermal in situ oil sands (“thermal”) quarterly production performance of 146,086 bbl/d. |
c. | Strong primary heavy crude oil production volumes of 137,687 bbl/d. |
d. | Strong Pelican Lake quarterly production volumes of 51,085 bbl/d. |
e. | International quarterly production volumes of 36,224 bbl/d. |
– | Record quarterly production volumes of 134,166 bbl/d were achieved at Horizon Oil Sands (“Horizon”). |
— | Natural gas production achieved record quarterly volumes averaging 1,771 MMcf/d in Q1/15, an increase of 51% and 2% from Q1/14 and Q4/14 levels respectively. |
2
|
Canadian Natural Resources Limited
|
§ | Canadian Natural’s 2015 capital expenditure guidance has been updated to reflect capital cost savings across all business segments. The Company’s targeted 2015 capital expenditure guidance has been reduced further by approximately $300 million, as compared to capital guidance released in March 2015, to approximately $5.7 billion. Annual production guidance remains unchanged and is targeted to deliver 11% annual production growth in 2015 over 2014 levels. |
§ | Canadian Natural targets to achieve approximately $390 million of additional operating costs savings in 2015 in comparison to the 2015 original budgeted operating cost targets announced in November 2014. In comparison to 2014, these savings plus the initiatives underway through effective and efficient operations, innovation initiatives, reduced energy costs and higher production volumes result in 2015 operating costs being approximately $925 million less than what they would have been at 2014 unit cost rates. |
— | Overall corporate crude oil and NGL operating costs of $19.03/bbl in Q1/15 decreased by $5.33/bbl and $3.01/bbl from Q1/14 and Q4/14 levels, respectively. |
a. | In Q1/15, North America E&P (including thermal) crude oil and NGL quarterly operating costs were $13.75/bbl, which decreased by 16% and 4% from Q1/14 and Q4/14 levels respectively. Annual operating cost guidance is targeted to range from $12.50/bbl to $14.50/bbl. |
b. | Horizon quarterly operating costs showed significant improvement at $29.73/bbl in Q1/15, with decreases of 28% from $41.11/bbl in Q1/14 and 13% from $34.34/bbl in Q4/14. The annual operating cost guidance has been reduced and is targeted to range from $31.00/bbl to $34.00/bbl in 2015. Strong operating costs reflect safe, steady, reliable production and improved operating efficiencies. |
— | In Q1/15, North America natural gas operating costs were $1.38/Mcf, a 10% decrease from Q1/14 levels of $1.54/Mcf, reflecting a continued focus on cost optimization after acquiring higher cost production volumes in 2014. In 2015, the Company will continue its strong, effective and efficient operations with a focus on cost optimization. As a result, annual operating cost guidance has been reduced and is targeted to range from $1.25/Mcf to $1.35/Mcf. |
§ | Canadian Natural generated cash flow from operations of approximately $1.4 billion in Q1/15 compared to approximately $2.1 billion in Q1/14 and $2.4 billion in Q4/14. The decrease in Q1/15 from Q1/14 and Q4/14 primarily reflects lower crude oil, NGL and natural gas realized pricing in North America, lower synthetic crude oil (“SCO”) realized pricing, partially offset by higher North America crude oil and NGL and SCO sales volumes and the impact of a weaker Canadian dollar as compared to the US dollar. |
§ | The Company incurred a net loss in Q1/15 of $252 million, compared to net earnings of $622 million in Q1/14 and $1,198 million in Q4/14. Adjusted net earnings from operations for Q1/15 were $21 million, compared to adjusted net earnings of $921 million in Q1/14 and $756 million in Q4/14. Changes in net earnings and adjusted net earnings largely reflect the changes in cash flow. |
§ | Canadian Natural is continuing its review of its royalty lands and royalty revenue portfolio and the best options to maximize shareholder value. Options for a final strategy as it relates to its fee title and royalty lands are as follows: |
— | Divestiture of the portfolio assets, |
— | Spin-off of the portfolio assets (IPO), or |
— | Retention of the portfolio assets in their current state. |
– | The development of leased acreage is ongoing and lease requests on undeveloped acreage continue to be evaluated. Q4/14 production volumes on the royalty lands increased 3% and 14% from Q3/14 and Q2/14 levels respectively. Drilling activity has been strong on the Company’s royalty lands with 144 wells drilled in Q4/14 and 75 wells drilled in Q1/15. |
§ | Canadian Natural declared a quarterly cash dividend on common shares of C$0.23 per share payable on July 1, 2015. |
Canadian Natural Resources Limited
|
3
|
Three Months Ended Mar 31
|
||||||||||||||||
2015
|
2014
|
|||||||||||||||
(number of wells)
|
Gross
|
Net
|
Gross
|
Net
|
||||||||||||
Crude oil
|
48
|
42
|
300
|
271
|
||||||||||||
Natural gas
|
13
|
9
|
32
|
25
|
||||||||||||
Dry
|
2
|
2
|
4
|
3
|
||||||||||||
Subtotal
|
63
|
53
|
336
|
299
|
||||||||||||
Stratigraphic test / service wells
|
121
|
86
|
330
|
330
|
||||||||||||
Total
|
184
|
139
|
666
|
629
|
||||||||||||
Success rate (excluding stratigraphic test / service wells)
|
96%
|
|
99%
|
|
§ | As a direct result of the downturn in crude oil and natural gas pricing commencing in the second half of 2014, the Company reduced its 2015 drilling programs. Drilling activity in Q1/15 consisted of 139 net wells compared to 629 net wells in Q1/14. |
Three Months Ended
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Crude oil and NGLs production (bbl/d)
|
286,333
|
291,002
|
266,110
|
|||||||||
Net wells targeting crude oil
|
40
|
332
|
263
|
|||||||||
Net successful wells drilled
|
38
|
324
|
260
|
|||||||||
Success rate
|
95
|
%
|
98
|
%
|
99
|
%
|
§ | North America crude oil and NGLs achieved quarterly production of 286,333 bbl/d in Q1/15, an increase of 8% from Q1/14 levels and a slight decrease of 2% from Q4/14 levels. |
§ | North America light crude oil and NGLs achieved record quarterly production averaging 97,561 bbl/d in Q1/15. Production increased 29% and 2% from Q1/14 levels and Q4/14 levels respectively, largely as a result of the successful integration of light crude oil and NGL production volumes acquired in 2014, complemented by a successful drilling program. |
§ | As expected, Pelican Lake operations achieved solid quarterly heavy crude oil production volumes of 51,085 bbl/d, a 6% increase from Q1/14 levels and comparable to Q4/14 levels. Canadian Natural continues to achieve success in developing, implementing and optimizing the leading edge polymer flood technology at Pelican Lake. |
4
|
Canadian Natural Resources Limited
|
§ | In Q1/15, primary heavy crude oil production averaged 137,687 bbl/d, a decrease of 3% and 5% from Q1/14 and Q4/14 levels respectively. The decrease in production volumes reflects a reduced drilling program, as a result of a prudent reduction in capital allocation due to unfavorable commodity pricing and economic conditions. The Company’s high working interest, large undeveloped land base of over 8,000 potential well locations and extensive operated infrastructure enable Canadian Natural to exercise a nimble, flexible capital allocation program. Canadian Natural drilled 36 net primary heavy crude oil wells in Q1/15 compared to 224 and 305 net primary heavy crude oil wells drilled in Q1/14 and Q4/14 respectively. |
Three Months Ended
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Bitumen production (bbl/d)
|
146,086
|
118,974
|
82,077
|
|||||||||
Net wells targeting bitumen
|
3
|
–
|
11
|
|||||||||
Net successful wells drilled
|
3
|
–
|
11
|
|||||||||
Success rate
|
100%
|
|
–
|
100%
|
|
§ | In Q1/15, record thermal in situ quarterly production volumes were achieved averaging 146,086 bbl/d, an increase of 78% and 23% from Q1/14 and Q4/14 production volumes respectively. The increase in Q1/15 from Q1/14 reflects record production volumes at Primrose and increased Kirby South production volumes. |
§ | Primrose production volumes reached record quarterly average levels of 122,386 bbl/d in Q1/15, resulting from the Company’s execution excellence in optimizing operations and reflecting the cyclic nature of the operations. As expected, Q2/15 total thermal production volumes are targeted to range from 106,000 bbl/d to 115,000 bbl/d. |
§ | Subsequent to Q1/15, Canadian Natural submitted its Primrose Flow-to-Surface (“FTS”) Final Report. The report reflects the Company’s initial findings as reported in its Primrose FTS Causation Report submitted in early 2014. |
§ | The Company commenced a low pressure steamflood at Primrose East Area 1 in September 2014. Production ramp up is meeting expectations with current volumes of approximately 11,000 bbl/d. Additionally, low pressure cyclic steam stimulation (“CSS”) operations at Primrose East Area 2 received regulatory approval and steaming was subsequently implemented in February 2015 with production ramping up as expected. |
§ | At Kirby South, Q1/15 production volumes increased to 23,700 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. For wells on Steam Assisted Gravity Drainage (“SAGD”), steam to oil ratio (“SOR”) in Q1/15 was 2.4. For April 2015, Kirby South’s production continues to ramp up to volumes averaging approximately 27,500 bbl/d. |
Three Months Ended
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Natural gas production (MMcf/d)
|
1,713
|
1,705
|
1,147
|
|||||||||
Net wells targeting natural gas
|
9
|
16
|
25
|
|||||||||
Net successful wells drilled
|
9
|
16
|
25
|
|||||||||
Success rate
|
100%
|
|
100%
|
|
100%
|
|
§ | North America natural gas production reached record quarterly levels averaging 1,713 MMcf/d for Q1/15, an increase of 49% from Q1/14 and comparable to Q4/14 levels. The increase from Q1/14 levels resulted from additional production volumes acquired in 2014, complemented by a focused liquids-rich natural gas drilling program. |
Canadian Natural Resources Limited
|
5
|
§ | North America natural gas quarterly operating costs were $1.38/Mcf in Q1/15, a 10% decrease from Q1/14 levels of $1.54/Mcf, reflecting a continued focus on cost optimization after acquiring higher cost production volumes in 2014. In 2015, the Company will continue its strong, effective and efficient operations with a focus on cost optimization. As a result, annual operating cost guidance has been reduced and is targeted to range from $1.25/Mcf to $1.35/Mcf. |
Three Months Ended
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Crude oil production (bbl/d)
|
||||||||||||
North Sea
|
23,036
|
21,927
|
16,715
|
|||||||||
Offshore Africa
|
13,188
|
12,047
|
10,791
|
|||||||||
Natural gas production (MMcf/d)
|
||||||||||||
North Sea
|
34
|
10
|
7
|
|||||||||
Offshore Africa
|
24
|
18
|
21
|
|||||||||
Net wells targeting crude oil
|
0.6
|
1.0
|
–
|
|||||||||
Net successful wells drilled
|
0.6
|
1.0
|
–
|
|||||||||
Success rate
|
100%
|
|
100%
|
|
–
|
§ | International crude oil production averaged 36,224 bbl/d during Q1/15, an increase of 32% from Q1/14 levels and a 7% increase from Q4/14 levels. The increase in production over Q1/14 levels was primarily due to the reinstatement of the Banff/Kyle Floating Production Storage and Offtake Vessel (“FPSO”) in July 2014 and increased production from Baobab after experiencing downtime in Q1/14. Q1/15 production volumes also reflect the return to production on the Tiffany platform which experienced unplanned downtime during Q4/14, and higher production at Espoir. |
§ | In offshore Côte d’Ivoire, Canadian Natural has contracted a drilling rig to undertake a 10 well (5.9 net) infill development drilling program targeted to add 5,900 BOE/d of net production at the Espoir Field. In Q1/15, the first oil well was brought on stream and is currently producing at a net rate of approximately 3,000 bbl/d. In April 2015, the Company commenced production from its second well at a net production rate of approximately 2,100 bbl/d. Production from both wells is above expectations and the program is progressing below budget and on schedule. |
§ | The Company has also contracted a drilling rig to undertake a 6 well (3.5 net) infill development drilling program targeted to add 11,000 BOE/d of net production at the Baobab Field, offshore Côte d’Ivoire. Drilling has commenced and first oil is targeted in June 2015. |
§ | In Q2/14, an exploratory well was drilled on Block CI-514, in which the Company has a 36% working interest. The well demonstrated the presence of a working petroleum system. In April 2015, a second exploration well was drilled to evaluate the up-dip potential of the initial well. The well has been plugged and abandoned, and the results will be evaluated and integrated into our understanding of the block. |
Three Months Ended
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Synthetic crude oil production (bbl/d) (1)
|
134,166
|
128,090
|
113,095
|
(1) | The Company has commenced production of diesel for internal use at Horizon. First quarter 2015 SCO production before royalties excludes 1,676 bbl/d of SCO consumed internally as diesel (fourth quarter 2014 – 1,288 bbl/d; first quarter 2014 – nil). |
6
|
Canadian Natural Resources Limited
|
§ | Horizon achieved record quarterly production of 134,166 bbl/d of SCO, an increase of 19% from Q1/14 levels and an increase of 5% from Q4/14 levels. As previously discussed in Canadian Natural’s Q4/14 and Year End Results, new equipment performance and the execution of an optimized mining strategy have increased the stability of the extraction and upgrading processes, resulting in increased nameplate capacity to 137,000 bbl/d. Horizon productive capacity reflects target utilization rates ranging from 92% to 96% of the plant nameplate capacity. During Q1/15, utilization rates were exceptional reaching 98%. April 2015 average production volumes at Horizon were approximately 123,000 bbl/d, slightly below the target utilization rate range. Annual production guidance range remains between 121,000 bbl/d and 131,000 bbl/d. |
§ | Strong quarterly operating costs at Horizon averaged $29.73/bbl in Q1/15, representing a decrease of 28% from $41.11/bbl in Q1/14 and a decrease of 13% from $34.34/bbl in Q4/14. Decreases in operating costs reflect safe, steady and reliable operations, the impact of cost reduction initiatives across the site, the production and internal use of mine diesel, lower energy costs, and higher production volumes on a relatively fixed cost structure. As a result of these factors, Horizon’s 2015 operating cost guidance range has been reduced to $31.00/bbl to $34.00/bbl. As production volumes increase with the expansion to 250,000 bbl/d, which is targeted for completion at the end of 2017, production costs are targeted to reduce further, ranging between $25.00/bbl and $27.00/bbl. |
§ | The 2015 maintenance turnaround targeted for this fall has been accelerated to June 2015. Along with performing critical maintenance activities of the plant, the Horizon team will also take advantage of the opportunity to enhance reliability, optimize vessel performance and potentially increase capacity of the Diluent Recovery Unit (“DRU”). |
§ | Canadian Natural continues to deliver on its strategy to transition to a longer life, low decline asset base while providing significant and growing free cash flow. Canadian Natural’s staged expansion of Horizon to 250,000 bbl/d of SCO production capacity continues to progress ahead of schedule. Compared to the Company’s original 2015 budget released in November 2014, $300 million is targeted to be reduced in 2015 on Horizon Phase 2/3 Expansion activities, with no impact to the current targeted schedule. Canadian Natural has committed to approximately 77% of the Engineering, Procurement and Construction contracts with over 72% of the construction contracts awarded to date, 85% being lump sum, ensuring greater cost certainty and efficiency. |
§ | Overall Horizon Phase 2/3 expansion is 60% physically complete as at Q1/15: |
— | Reliability – Tranche 2 is 100% physically complete. Completion occurred in 2014 resulting in increased performance and overall production reliability. This contributed approximately 5% increase in production levels from Phase 1 production levels. |
—
|
Directive 74 includes technological investment and research into tailings management. This project remains on track and is 53% physically complete. |
—
|
Phase 2A is a coker expansion that was originally scheduled to be completed in mid-2015; however, due to strong construction performance and the early completion of the coker installation, the Company accelerated the tie-in to August 2014. The expanded Coker Unit is now fully operational and the project was completed on time and below budget. Horizon SCO production levels increased by approximately 12,000 bbl/d with the completion of the coker tie-in. Through the completion of Phase 2A, additional coker capacity and equipment were added, increasing the plant nameplate capacity to 133,000 bbl/d. New equipment performance combined with an optimized mining strategy have increased the stability of the extraction and upgrading processes, resulting in a further increase to plant nameplate capacity to 137,000 bbl/d. |
—
|
Phase 2B is 54% 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 May 2016 turnaround. Production volumes after the turnaround are targeted to increase by 4,000 bbl/d in Q3/16 and 10,000 bbl/d in Q4/16, above the original planned production ramp up. Full commissioning of the Phase 2B equipment will be completed as planned in late 2016, adding 45,000 bbl/d of production capacity. |
—
|
Phase 3 is on track and on schedule. This Phase is 51% physically complete, and includes the addition of extraction trains. This phase is targeted to increase production capacity by 80,000 bbl/d in late 2017 and will result in additional reliability, redundancy and significant operating cost savings for the Horizon project. |
Canadian Natural Resources Limited
|
7
|
§ | The development of leased acreage is ongoing and lease requests on undeveloped acreage continue to be evaluated. Q4/14 production volumes on the royalty lands increased 3% and 14% from Q3/14 and Q2/14 levels respectively. Drilling activity has been strong on the Company’s royalty lands with 144 wells drilled in Q4/14, of which 127 wells were drilled by third parties and 17 wells were drilled by Canadian Natural. In Q1/15, drilling activity consisted of 75 wells drilled, 72 wells were drilled by third parties and 3 wells were 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. |
Q4/14
|
Q3/14
|
|||||||
Natural gas (MMcf/d)
|
24.0
|
23.6
|
||||||
Crude oil (bbl/d)
|
4,203
|
4,047
|
||||||
NGLs (bbl/d)
|
534
|
472
|
||||||
Total (BOE/d)
|
8,732
|
8,448
|
Royalty volumes for Q4/14 attributable to
|
||||||||||||
Third
Party
|
Canadian
Natural (2)
|
Total
|
||||||||||
Natural gas (MMcf/d)
|
20.6
|
3.4
|
24.0
|
|||||||||
Crude oil (bbl/d)
|
3,513
|
690
|
4,203
|
|||||||||
NGLs (bbl/d)
|
491
|
43
|
534
|
|||||||||
Total (BOE/d)
|
7,442
|
1,290
|
8,732
|
8
|
Canadian Natural Resources Limited
|
Royalty revenue for Q4/14 attributable to
|
||||||||||||
($ millions)
|
Third
Party
|
Canadian
Natural (2)
|
Total
|
|||||||||
Natural gas
|
$
|
7
|
$
|
1
|
$
|
8
|
||||||
Crude oil
|
$
|
22
|
$
|
4
|
$
|
26
|
||||||
NGLs
|
$
|
2
|
$
|
-
|
$
|
2
|
||||||
Other revenue (3)
|
$
|
4
|
$
|
-
|
$
|
4
|
||||||
Total
|
$
|
35
|
$
|
5
|
$
|
40
|
Royalty revenue for Q4/14 attributable to
|
||||||||||||
($ millions)
|
Third
Party
|
Canadian
Natural (2)
|
Total
|
|||||||||
Fee title
|
$
|
19
|
$
|
4
|
$
|
23
|
||||||
Gross overriding royalty (4)
|
$
|
12
|
$
|
1
|
$
|
13
|
||||||
Other revenue (3)
|
$
|
4
|
$
|
-
|
$
|
4
|
||||||
Total
|
$
|
35
|
$
|
5
|
$
|
40
|
Q4/14
|
||||
Natural gas ($/Mcf)
|
$
|
3.60
|
||
Crude oil ($/bbl)
|
$
|
67.84
|
||
NGLs ($/bbl)
|
$
|
41.15
|
||
Total ($/BOE)
|
$
|
50.35
|
Leased to
|
||||||||||||
(gross acres, millions)
|
Third Party
and Unleased
|
Canadian
Natural (2)
|
Total
|
|||||||||
Fee title (5)
|
3.14
|
0.21
|
3.35
|
|||||||||
Gross overriding royalty (4)
|
1.90
|
1.64
|
3.54
|
|||||||||
Total
|
5.04
|
1.85
|
6.89
|
(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. |
Canadian Natural Resources Limited
|
9
|
Three Months Ended
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Crude oil and NGLs pricing
|
||||||||||||
WTI benchmark price (US$/bbl) (1)
|
$
|
48.57
|
$
|
73.12
|
$
|
98.61
|
||||||
WCS blend differential from WTI (%) (2)
|
30%
|
|
20%
|
|
24%
|
|
||||||
SCO price (US$/bbl)
|
$
|
45.26
|
$
|
71.01
|
$
|
96.45
|
||||||
Condensate benchmark pricing (US$/bbl)
|
$
|
45.59
|
$
|
70.54
|
$
|
102.53
|
||||||
Average realized pricing before risk management (C$/bbl) (3)
|
$
|
37.03
|
$
|
62.80
|
$
|
79.68
|
||||||
Natural gas pricing
|
||||||||||||
AECO benchmark price (C$/GJ)
|
$
|
2.80
|
$
|
3.80
|
$
|
4.52
|
||||||
Average realized pricing before risk
management (C$/Mcf)
|
$
|
3.38
|
$
|
4.32
|
$
|
5.69
|
(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
|
||||||||||||||||||||||||
January
|
$
|
47.33
|
36%
|
|
$
|
(16.90
|
)
|
$
|
(3.16
|
)
|
$
|
0.74
|
$
|
(4.89
|
)
|
|||||||||
February
|
$
|
50.72
|
28%
|
|
$
|
(14.20
|
)
|
$
|
(3.43
|
)
|
$
|
7.21
|
$
|
(4.24
|
)
|
|||||||||
March
|
$
|
47.85
|
27%
|
|
$
|
(13.09
|
)
|
$
|
(3.33
|
)
|
$
|
7.94
|
$
|
0.09
|
||||||||||
April
|
$
|
54.63
|
26%
|
|
$
|
(14.37
|
)
|
$
|
0.86
|
$
|
5.13
|
$
|
0.68
|
|||||||||||
May*
|
$
|
60.65
|
20%
|
|
$
|
(11.87
|
)
|
$
|
3.43
|
$
|
5.95
|
$
|
1.54
|
|||||||||||
June*
|
$
|
61.67
|
14%
|
|
$
|
(8.73
|
)
|
$
|
3.68
|
$
|
5.77
|
$
|
(1.37
|
)
|
§ | 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 in November 2014 to not reduce crude oil production to offset the excess world supply put downward pressure on benchmark pricing. Additionally, the growth of North American shale oil production continues to contribute to this downturn in benchmark pricing. |
§ | The WCS differential to WTI averaged US$14.75/bbl or 30% in Q1/15 compared to US$23.27/bbl or 24% in Q1/14. The WCS heavy differential widened during Q1/15 compared to Q1/14 due to the rapid decline in WTI benchmark pricing. May 2015 and June 2015 indications of the WCS heavy differential are trending lower to US$11.87/bbl or 20% and US$8.73/bbl or 14%, respectively. Seasonal demand fluctuations, changes in transportation logistics and refinery utilization and shutdowns will continue to be reflected in WCS pricing. |
§ | Canadian Natural contributed approximately 179,000 bbl/d of its heavy crude oil stream to the WCS blend in Q1/15. The Company remains the largest contributor to the WCS blend, accounting for 54% of the total blend. |
§ | SCO pricing averaged US$45.26/bbl during Q1/15, a decrease of 53% from Q1/14 pricing of US$96.45/bbl and a decrease of 36% from US$71.01/bbl in Q4/14, primarily due to a decrease in WTI benchmark pricing. |
§ | AECO natural gas pricing in Q1/15 averaged $2.80/GJ, a decrease of 38% and 26% from Q1/14 and Q4/14 pricing respectively. |
10
|
Canadian Natural Resources Limited
|
§ | The Company’s strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved production of approximately 898,100 BOE/d for Q1/15 with approximately 98% of production located in G8 countries. |
§ | Canadian Natural has a strong balance sheet with debt to book capitalization of 36% and debt to EBITDA of 1.7x at March 31, 2015. |
§ | Canadian Natural maintains significant financial stability and liquidity represented in part by bank credit facilities. As at March 31, 2015, the Company had in place bank credit facilities of $7,128 million, of which $3,269 million was available. |
§ | In March 2015, the United Kingdom (“UK”) government enacted a reduction in the corporate tax rate charged on profits from North Sea oil and gas production from 62% to 50%, effective January 1, 2015 and a reduction in the rate of Petroleum Revenue Tax (“PRT”) from 50% to 35%, effective January 1, 2016. This resulted in a decrease to the overall effective corporate tax rate applicable to net operating income from oil and gas activities to 50% for non-PRT paying fields, 75% for PRT paying fields effective January 1, 2015, and a further reduction to 67.5% for PRT paying fields effective January 1, 2016, after allowing for deductions for capital and abandonment expenditures. Allowable abandonment expenditures eligible for carryback to prior taxation years for PRT purposes are still recoverable at the previous tax rate of 50%. As a result of the income tax rate changes, the Company’s deferred income tax liability was decreased by $228 million. In addition, the UK government announced a new Investment Allowance replacing existing field allowances including Brown Field Allowance. |
§ | The Company’s commodity hedging program is utilized, as required, 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 July 1, 2015. |
§ | Subsequent to Q1/15, Toronto Stock Exchange accepted notice of Canadian Natural’s Normal Course Issuer Bid (“NCIB”) through facilities of Toronto Stock Exchange and the New York Stock Exchange. The notice provides that Canadian Natural may, during the 12 month period commencing April 2015 and ending April 2016, purchase for cancellation on Toronto Stock Exchange and the New York Stock Exchange up to 54,640,607 common shares. |
· | In 2015, the Company has not purchased any common shares under its NCIBs. |
§ | The Company has a strong balance sheet and cash flow generation which enables it to weather volatility in commodity prices. Additionally, Canadian Natural retains significant 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
|
Three Months Ended
|
|||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||||
Product sales
|
$
|
3,226
|
$
|
4,850
|
$
|
4,968
|
|||||||
Net earnings (loss)
|
$
|
(252
|
)
|
$
|
1,198
|
$
|
622
|
||||||
Per common share
|
– basic |
$
|
(0.23
|
)
|
$
|
1.10
|
$
|
0.57
|
|||||
– diluted
|
$
|
(0.23
|
)
|
$
|
1.09
|
$
|
0.57
|
||||||
Adjusted net earnings from operations (1)
|
$
|
21
|
$
|
756
|
$
|
921
|
|||||||
Per common share
|
– basic |
$
|
0.02
|
$
|
0.69
|
$
|
0.85
|
||||||
|
– diluted
|
$
|
0.02
|
$
|
0.69
|
$
|
0.85
|
||||||
Cash flow from operations (2)
|
$
|
1,370
|
$
|
2,368
|
$
|
2,146
|
|||||||
Per common share
|
– basic |
$
|
1.25
|
$
|
2.17
|
$
|
1.97
|
||||||
|
– diluted
|
$
|
1.25
|
$
|
2.16
|
$
|
1.97
|
||||||
Capital expenditures, net of dispositions
|
$
|
1,412
|
$
|
2,220
|
$
|
1,893
|
(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
|
||||||||||||
($ millions)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Net earnings (loss) as reported
|
$
|
(252
|
)
|
$
|
1,198
|
$
|
622
|
|||||
Share-based compensation, net of tax (1)
|
64
|
(144
|
)
|
143
|
||||||||
Unrealized risk management loss (gain), net of tax (2)
|
9
|
(303
|
)
|
38
|
||||||||
Unrealized foreign exchange loss, net of tax (3)
|
413
|
106
|
118
|
|||||||||
Realized foreign exchange loss on repayment of US dollar debt securities, net of tax (4)
|
–
|
36
|
–
|
|||||||||
Equity loss from investment, net of tax (5)
|
15
|
–
|
–
|
|||||||||
Gain on corporate acquisition, net of tax (6)
|
–
|
(137
|
)
|
–
|
||||||||
Effect of statutory tax rate and other legislative changes on deferred income tax liabilities (7)
|
(228
|
)
|
–
|
–
|
||||||||
Adjusted net earnings from operations
|
$
|
21
|
$
|
756
|
$
|
921
|
(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 and natural gas, and foreign exchange. |
(3) | Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps, and are recognized in net earnings. |
(4) | During the fourth quarter of 2014, the Company repaid US$500 million of 1.45% notes and US$350 million of 4.90% notes. |
(5) | The Company's investment in the 50% owned North West Redwater Partnership is accounted for using the equity method of accounting. The non-cash equity loss from investment represents the Company's pro rata share of the North West Redwater Partnership's accounting loss. |
(6) | During the fourth quarter of 2014, the Company recorded an after-tax gain of $137 million related to the acquisition of certain producing crude oil and natural gas properties. |
(7) | 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 deferred income tax liabilities of approximately $228 million. |
14
|
Canadian Natural Resources Limited
|
Three Months Ended
|
||||||||||||
($ millions)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Net earnings (loss)
|
$
|
(252
|
)
|
$
|
1,198
|
$
|
622
|
|||||
Non-cash items:
|
||||||||||||
Depletion, depreciation and amortization
|
1,355
|
1,406
|
1,011
|
|||||||||
Share-based compensation
|
64
|
(144
|
)
|
143
|
||||||||
Asset retirement obligation accretion
|
43
|
49
|
45
|
|||||||||
Unrealized risk management loss (gain)
|
14
|
(404
|
)
|
49
|
||||||||
Unrealized foreign exchange loss
|
413
|
106
|
118
|
|||||||||
Realized foreign exchange loss on repayment of US dollar debt securities
|
–
|
36
|
–
|
|||||||||
Equity loss from investment
|
15
|
5
|
1
|
|||||||||
Deferred income tax (recovery) expense
|
(282
|
)
|
253
|
157
|
||||||||
Gain on corporate acquisition
|
–
|
(137
|
)
|
–
|
||||||||
Cash flow from operations
|
$
|
1,370
|
$
|
2,368
|
$
|
2,146
|
§ | lower crude oil and NGLs netbacks in the North America and North Sea 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 and natural gas sales volumes across all segments; |
§ | higher SCO sales volumes in the Oil Sands Mining and Upgrading segment; |
§ | 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 North America and North Sea segments; |
§ | lower realized SCO prices; |
§ | lower natural gas netbacks in the North America segment; |
§ | lower crude oil sales volumes in the North Sea and Offshore Africa segments; and |
§ | lower realized risk management gains; |
Canadian Natural Resources Limited
|
15
|
§ | higher crude oil and NGLs and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments; |
§ | higher crude oil netbacks in the Offshore Africa segment; and |
§ | the impact of a weaker Canadian dollar relative to the US dollar. |
($ millions, except per common share
amounts)
|
Mar 31
2015 |
Dec 31
2014 |
Sep 30
2014 |
Jun 30
2014 |
||||||||||||
Product sales
|
$
|
3,226
|
$
|
4,850
|
$
|
5,370
|
$
|
6,113
|
||||||||
Net earnings (loss)
|
$
|
(252
|
)
|
$
|
1,198
|
$
|
1,039
|
$
|
1,070
|
|||||||
Net earnings (loss) per common share
|
||||||||||||||||
– basic
|
$
|
(0.23
|
)
|
$
|
1.10
|
$
|
0.95
|
$
|
0.98
|
|||||||
– diluted
|
$
|
(0.23
|
)
|
$
|
1.09
|
$
|
0.94
|
$
|
0.97
|
|||||||
($ millions, except per common share
amounts)
|
Mar 31
2014
|
Dec 31
2013
|
Sept 30
2013
|
Jun 30
2013
|
||||||||||||
Product sales
|
$
|
4,968
|
$
|
4,330
|
$
|
5,284
|
$
|
4,230
|
||||||||
Net earnings (loss)
|
$
|
622
|
$
|
413
|
$
|
1,168
|
$
|
476
|
||||||||
Net earnings (loss) per common share
|
||||||||||||||||
– basic
|
$
|
0.57
|
$
|
0.38
|
$
|
1.07
|
$
|
0.44
|
||||||||
– diluted
|
$
|
0.57
|
$
|
0.38
|
$
|
1.07
|
$
|
0.44
|
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 strong heavy crude oil drilling program throughout 2013 and 2014, 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 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 corporate acquisitions/disposition of properties – Fluctuations due to the recognition of gains on corporate acquisitions/dispositions in the fourth quarter of 2014 and the third quarter of 2013. |
Canadian Natural Resources Limited
|
17
|
Three Months Ended
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
WTI benchmark price (US$/bbl)
|
$
|
48.57
|
$
|
73.12
|
$
|
98.61
|
||||||
Dated Brent benchmark price (US$/bbl)
|
$
|
53.80
|
$
|
75.99
|
$
|
108.20
|
||||||
WCS blend differential from WTI (US$/bbl)
|
$
|
14.75
|
$
|
14.26
|
$
|
23.27
|
||||||
WCS blend differential from WTI (%)
|
30%
|
|
20%
|
|
24%
|
|
||||||
SCO price (US$/bbl)
|
$
|
45.26
|
$
|
71.01
|
$
|
96.45
|
||||||
Condensate benchmark price (US$/bbl)
|
$
|
45.59
|
$
|
70.54
|
$
|
102.53
|
||||||
NYMEX benchmark price (US$/MMBtu)
|
$
|
2.96
|
$
|
3.95
|
$
|
4.89
|
||||||
AECO benchmark price (C$/GJ)
|
$
|
2.80
|
$
|
3.80
|
$
|
4.52
|
||||||
US/Canadian dollar average exchange rate (US$)
|
$
|
0.8057
|
$
|
0.8806
|
$
|
0.9064
|
18
|
Canadian Natural Resources Limited
|
Three Months Ended
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Crude oil and NGLs (bbl/d)
|
||||||||||||
North America – Exploration and Production
|
432,419
|
409,976
|
348,187
|
|||||||||
North America – Oil Sands Mining and Upgrading (1)
|
134,166
|
128,090
|
113,095
|
|||||||||
North Sea
|
23,036
|
21,927
|
16,715
|
|||||||||
Offshore Africa
|
13,188
|
12,047
|
10,791
|
|||||||||
602,809
|
572,040
|
488,788
|
||||||||||
Natural gas (MMcf/d)
|
||||||||||||
North America
|
1,713
|
1,705
|
1,147
|
|||||||||
North Sea
|
34
|
10
|
7
|
|||||||||
Offshore Africa
|
24
|
18
|
21
|
|||||||||
1,771
|
1,733
|
1,175
|
||||||||||
Total barrels of oil equivalent (BOE/d)
|
898,053
|
860,920
|
684,647
|
|||||||||
Product mix
|
||||||||||||
Light and medium crude oil and NGLs
|
15%
|
|
15%
|
|
15%
|
|
||||||
Pelican Lake heavy crude oil
|
6%
|
|
6%
|
|
7%
|
|
||||||
Primary heavy crude oil
|
15%
|
|
17%
|
|
20%
|
|
||||||
Bitumen (thermal oil)
|
16%
|
|
14%
|
|
12%
|
|
||||||
Synthetic crude oil (1)
|
15%
|
|
15%
|
|
17%
|
|
||||||
Natural gas
|
33%
|
|
33%
|
|
29%
|
|
||||||
Percentage of product sales (1) (2)
(excluding Midstream revenue) |
||||||||||||
Crude oil and NGLs
|
80%
|
|
84%
|
|
86%
|
|
||||||
Natural gas
|
20%
|
|
16%
|
|
14%
|
|
(1) | First quarter 2015 SCO production before royalties excludes 1,676 bbl/d of SCO consumed internally as diesel (fourth quarter 2014 – 1,288 bbl/d; first quarter 2014 – nil). |
(2) | Net of blending costs and excluding risk management activities. |
Canadian Natural Resources Limited
|
19
|
Three Months Ended
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Crude oil and NGLs (bbl/d)
|
||||||||||||
North America – Exploration and Production
|
380,273
|
343,324
|
280,826
|
|||||||||
North America – Oil Sands Mining and Upgrading
|
132,413
|
121,292
|
106,891
|
|||||||||
North Sea
|
22,976
|
21,881
|
16,662
|
|||||||||
Offshore Africa
|
12,586
|
11,203
|
9,762
|
|||||||||
548,248
|
497,700
|
414,141
|
||||||||||
Natural gas (MMcf/d)
|
||||||||||||
North America
|
1,643
|
1,606
|
1,017
|
|||||||||
North Sea
|
34
|
10
|
7
|
|||||||||
Offshore Africa
|
23
|
16
|
18
|
|||||||||
1,700
|
1,632
|
1,042
|
||||||||||
Total barrels of oil equivalent (BOE/d)
|
831,637
|
769,775
|
587,737
|
20
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
21
|
(bbl)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
North America – Exploration and Production
|
598,825
|
930,116
|
1,069,537
|
|||||||||
North America – Oil Sands Mining and Upgrading (SCO)
|
1,692,043
|
1,266,063
|
1,693,887
|
|||||||||
North Sea
|
562,540
|
368,808
|
311,457
|
|||||||||
Offshore Africa
|
1,086,222
|
461,997
|
1,156,700
|
|||||||||
3,939,630
|
3,026,984
|
4,231,581
|
Three Months Ended
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||
Sales price (2)
|
$
|
37.03
|
$
|
62.80
|
$
|
79.68
|
||||||
Transportation
|
2.46
|
2.15
|
2.49
|
|||||||||
Realized sales price, net of transportation
|
34.57
|
60.65
|
77.19
|
|||||||||
Royalties
|
3.83
|
9.05
|
14.05
|
|||||||||
Production expense
|
16.10
|
18.69
|
19.18
|
|||||||||
Netback
|
$
|
14.64
|
$
|
32.91
|
$
|
43.96
|
||||||
Natural gas ($/Mcf) (1)
|
||||||||||||
Sales price (2)
|
$
|
3.38
|
$
|
4.32
|
$
|
5.69
|
||||||
Transportation
|
0.36
|
0.28
|
0.30
|
|||||||||
Realized sales price, net of transportation
|
3.02
|
4.04
|
5.39
|
|||||||||
Royalties
|
0.12
|
0.24
|
0.62
|
|||||||||
Production expense
|
1.44
|
1.39
|
1.61
|
|||||||||
Netback
|
$
|
1.46
|
$
|
2.41
|
$
|
3.16
|
||||||
Barrels of oil equivalent ($/BOE) (1)
|
||||||||||||
Sales price (2)
|
$
|
30.57
|
$
|
48.23
|
$
|
63.14
|
||||||
Transportation
|
2.44
|
2.05
|
2.29
|
|||||||||
Realized sales price, net of transportation
|
28.13
|
46.18
|
60.85
|
|||||||||
Royalties
|
2.65
|
6.10
|
10.42
|
|||||||||
Production expense
|
13.20
|
14.66
|
15.82
|
|||||||||
Netback
|
$
|
12.28
|
$
|
25.42
|
$
|
34.61
|
(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
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Crude oil and NGLs ($/bbl) (1) (2)
|
||||||||||||
North America
|
$
|
35.22
|
$
|
61.28
|
$
|
77.54
|
||||||
North Sea
|
$
|
64.59
|
$
|
83.32
|
$
|
121.38
|
||||||
Offshore Africa
|
$
|
71.75
|
$
|
68.90
|
$
|
–
|
||||||
Company average
|
$
|
37.03
|
$
|
62.80
|
$
|
79.68
|
||||||
Natural gas ($/Mcf) (1) (2)
|
||||||||||||
North America
|
$
|
3.14
|
$
|
4.22
|
$
|
5.56
|
||||||
North Sea
|
$
|
10.18
|
$
|
8.22
|
$
|
6.05
|
||||||
Offshore Africa
|
$
|
11.70
|
$
|
11.73
|
$
|
12.18
|
||||||
Company average
|
$
|
3.38
|
$
|
4.32
|
$
|
5.69
|
||||||
Company average ($/BOE) (1) (2)
|
$
|
30.57
|
$
|
48.23
|
$
|
63.14
|
(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)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Wellhead Price (1) (2)
|
||||||||||||
Light and medium crude oil and NGLs ($/bbl)
|
$
|
38.78
|
$
|
62.27
|
$
|
83.57
|
||||||
Pelican Lake heavy crude oil ($/bbl)
|
$
|
36.21
|
$
|
62.33
|
$
|
79.94
|
||||||
Primary heavy crude oil ($/bbl)
|
$
|
37.64
|
$
|
62.47
|
$
|
77.78
|
||||||
Bitumen (thermal oil) ($/bbl)
|
$
|
30.25
|
$
|
58.64
|
$
|
69.73
|
||||||
Natural gas ($/Mcf)
|
$
|
3.14
|
$
|
4.22
|
$
|
5.56
|
(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
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||
North America
|
$
|
4.02
|
$
|
9.76
|
$
|
14.75
|
||||||
North Sea
|
$
|
0.16
|
$
|
0.17
|
$
|
0.38
|
||||||
Offshore Africa
|
$
|
3.27
|
$
|
4.83
|
$
|
–
|
||||||
Company average
|
$
|
3.83
|
$
|
9.05
|
$
|
14.05
|
||||||
Natural gas ($/Mcf) (1)
|
||||||||||||
North America
|
$
|
0.12
|
$
|
0.23
|
$
|
0.60
|
||||||
Offshore Africa
|
$
|
0.54
|
$
|
0.99
|
$
|
2.06
|
||||||
Company average
|
$
|
0.12
|
$
|
0.24
|
$
|
0.62
|
||||||
Company average ($/BOE) (1)
|
$
|
2.65
|
$
|
6.10
|
$
|
10.42
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited
|
25
|
Three Months Ended
|
||||||||||||
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||
North America
|
$
|
13.75
|
$
|
14.38
|
$
|
16.31
|
||||||
North Sea
|
$
|
65.23
|
$
|
68.64
|
$
|
75.51
|
||||||
Offshore Africa
|
$
|
15.46
|
$
|
50.54
|
$
|
–
|
||||||
Company average
|
$
|
16.10
|
$
|
18.69
|
$
|
19.18
|
||||||
Natural gas ($/Mcf) (1)
|
||||||||||||
North America
|
$
|
1.38
|
$
|
1.34
|
$
|
1.54
|
||||||
North Sea
|
$
|
3.89
|
$
|
6.35
|
$
|
5.83
|
||||||
Offshore Africa
|
$
|
2.80
|
$
|
3.35
|
$
|
3.64
|
||||||
Company average
|
$
|
1.44
|
$
|
1.39
|
$
|
1.61
|
||||||
Company average ($/BOE) (1)
|
$
|
13.20
|
$
|
14.66
|
$
|
15.82
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
26
|
Canadian Natural Resources Limited
|
Three Months Ended
|
||||||||||||
($ millions, except per BOE amounts)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Expense
|
$
|
1,213
|
$
|
1,210
|
$
|
879
|
||||||
$/BOE (1)
|
$
|
17.78
|
$
|
17.76
|
$
|
17.55
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended
|
||||||||||||
($ millions, except per BOE amounts)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Expense
|
$
|
35
|
$
|
37
|
$
|
33
|
||||||
$/BOE (1)
|
$
|
0.52
|
$
|
0.56
|
$
|
0.67
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended
|
||||||||||||
($/bbl)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
SCO sales price (1)
|
$
|
56.75
|
$
|
79.23
|
$
|
107.82
|
||||||
Bitumen value for royalty purposes (1) (2)
|
$
|
29.70
|
$
|
56.98
|
$
|
66.27
|
||||||
Bitumen royalties (1) (3)
|
$
|
1.01
|
$
|
4.44
|
$
|
5.06
|
||||||
Transportation
|
$
|
1.83
|
$
|
1.76
|
$
|
1.96
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Calculated as the quarterly average of the bitumen valuation methodology price. |
(3) | Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes. |
Canadian Natural Resources Limited
|
27
|
Three Months Ended
|
||||||||||||
($ millions) |
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Cash production costs, excluding natural gas costs
|
$
|
326
|
$
|
368
|
$
|
375
|
||||||
Natural gas costs
|
20
|
27
|
37
|
|||||||||
Total cash production costs
|
$
|
346
|
$
|
395
|
$
|
412
|
Three Months Ended
|
||||||||||||
($/bbl) (1)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Cash production costs, excluding natural gas costs
|
$
|
28.03
|
$
|
31.97
|
$
|
37.39
|
||||||
Natural gas costs
|
1.70
|
2.37
|
3.72
|
|||||||||
Cash production costs
|
$
|
29.73
|
$
|
34.34
|
$
|
41.11
|
||||||
Sales (bbl/d)
|
129,433
|
125,092
|
111,506
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended
|
||||||||||||
($ millions, except per bbl amounts) |
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Expense
|
$
|
139
|
$
|
194
|
$
|
130
|
||||||
$/bbl (1)
|
$
|
11.96
|
$
|
16.85
|
$
|
12.95
|
(1) | Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods. |
Three Months Ended
|
||||||||||||
($ millions, except per bbl amounts) |
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Expense
|
$
|
8
|
$
|
12
|
$
|
12
|
||||||
$/bbl (1)
|
$
|
0.66
|
$
|
1.02
|
$
|
1.17
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
28
|
Canadian Natural Resources Limited
|
Three Months Ended
|
||||||||||||
($ millions) |
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Revenue
|
$
|
35
|
$
|
29
|
$
|
31
|
||||||
Production expense
|
9
|
7
|
9
|
|||||||||
Midstream cash flow
|
26
|
22
|
22
|
|||||||||
Depreciation
|
3
|
2
|
2
|
|||||||||
Equity loss from investment
|
15
|
5
|
1
|
|||||||||
Segment earnings before taxes
|
$
|
8
|
$
|
15
|
$
|
19
|
Three Months Ended
|
||||||||||||
($ millions, except per BOE amounts) |
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Expense
|
$
|
104
|
$
|
100
|
$
|
90
|
||||||
$/BOE (1)
|
$
|
1.31
|
$
|
1.26
|
$
|
1.49
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited
|
29
|
Three Months Ended
|
||||||||||||
($ millions)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Expense (Recovery)
|
$
|
64
|
$
|
(144
|
)
|
$
|
143
|
Three Months Ended
|
||||||||||||
($ millions, except per BOE amounts and interest rates)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Expense, gross
|
$
|
144
|
$
|
141
|
$
|
115
|
||||||
Less: capitalized interest
|
58
|
57
|
47
|
|||||||||
Expense, net
|
$
|
86
|
$
|
84
|
$
|
68
|
||||||
$/BOE (1)
|
$
|
1.07
|
$
|
1.05
|
$
|
1.13
|
||||||
Average effective interest rate
|
4.0%
|
|
4.0%
|
|
4.3%
|
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
30
|
Canadian Natural Resources Limited
|
Three Months Ended
|
||||||||||||
($ millions)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Crude oil and NGLs financial instruments
|
$
|
(117
|
)
|
$
|
(284
|
)
|
$
|
–
|
||||
Natural gas financial instruments
|
–
|
1
|
–
|
|||||||||
Foreign currency contracts
|
(139
|
)
|
(52
|
)
|
(75
|
)
|
||||||
Realized gain
|
(256
|
)
|
(335
|
)
|
(75
|
)
|
||||||
Crude oil and NGLs financial instruments
|
12
|
(403
|
)
|
(3
|
)
|
|||||||
Natural gas financial instruments
|
–
|
(3
|
)
|
45
|
||||||||
Foreign currency contracts
|
2
|
2
|
7
|
|||||||||
Unrealized loss (gain)
|
14
|
(404
|
)
|
49
|
||||||||
Net gain
|
$
|
(242
|
)
|
$
|
(739
|
)
|
$
|
(26
|
)
|
Three Months Ended
|
||||||||||||
($ millions)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Net realized (gain) loss
|
$
|
(53
|
)
|
$
|
18
|
$
|
(1
|
)
|
||||
Net unrealized loss (1)
|
413
|
106
|
118
|
|||||||||
Net loss
|
$
|
360
|
$
|
124
|
$
|
117
|
(1) | Amounts are reported net of the hedging effect of cross currency swaps. |
Canadian Natural Resources Limited
|
31
|
Three Months Ended
|
||||||||||||
($ millions, except income tax rates)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
North America (1)
|
$
|
8
|
$
|
123
|
$
|
192
|
||||||
North Sea
|
(64
|
)
|
(23
|
)
|
(15
|
)
|
||||||
Offshore Africa
|
2
|
8
|
4
|
|||||||||
PRT recovery – North Sea
|
(54
|
)
|
(86
|
)
|
(61
|
)
|
||||||
Other taxes
|
3
|
5
|
6
|
|||||||||
Current income tax (recovery) expense
|
(105
|
)
|
27
|
126
|
||||||||
Deferred income tax (recovery) expense
|
(289
|
)
|
254
|
91
|
||||||||
Deferred PRT expense (recovery) – North Sea
|
7
|
(1
|
)
|
66
|
||||||||
Deferred income tax (recovery) expense
|
(282
|
)
|
253
|
157
|
||||||||
(387
|
)
|
280
|
283
|
|||||||||
Income tax rate and other legislative changes (2)
|
228
|
–
|
–
|
|||||||||
$
|
(159
|
)
|
$
|
280
|
$
|
283
|
||||||
Effective income tax rate on adjusted net earnings from
operations (3)
|
105.8%
|
|
25.7%
|
|
23.5%
|
|
(1) | Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments. |
(2) | 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 deferred income tax liabilities of approximately $228 million. |
(3) | Excludes the impact of current and deferred PRT expense and other current income tax expense. |
32
|
Canadian Natural Resources Limited
|
Three Months Ended
|
||||||||||||
($ millions)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Exploration and Evaluation
|
||||||||||||
Net expenditures (2)
|
$
|
46
|
$
|
97
|
$
|
117
|
||||||
Property, Plant and Equipment
|
||||||||||||
Net property acquisitions (2)
|
11
|
72
|
(4
|
)
|
||||||||
Well drilling, completion and equipping
|
292
|
582
|
641
|
|||||||||
Production and related facilities
|
314
|
482
|
415
|
|||||||||
Capitalized interest and other (3)
|
26
|
28
|
23
|
|||||||||
Net expenditures
|
643
|
1,164
|
1,075
|
|||||||||
Total Exploration and Production
|
689
|
1,261
|
1,192
|
|||||||||
Oil Sands Mining and Upgrading
|
||||||||||||
Horizon Phase 2/3 construction costs
|
406
|
739
|
444
|
|||||||||
Sustaining capital
|
88
|
83
|
60
|
|||||||||
Turnaround costs
|
4
|
8
|
2
|
|||||||||
Capitalized interest and other (3)
|
71
|
32
|
73
|
|||||||||
Total Oil Sands Mining and Upgrading
|
569
|
862
|
579
|
|||||||||
Midstream
|
3
|
(16
|
)
|
25
|
||||||||
Abandonments (4)
|
144
|
101
|
87
|
|||||||||
Head office
|
7
|
12
|
10
|
|||||||||
Total net capital expenditures
|
$
|
1,412
|
$
|
2,220
|
$
|
1,893
|
||||||
By segment
|
||||||||||||
North America (2)
|
$
|
501
|
$
|
1,029
|
$
|
1,087
|
||||||
North Sea
|
62
|
105
|
88
|
|||||||||
Offshore Africa
|
126
|
127
|
17
|
|||||||||
Oil Sands Mining and Upgrading
|
569
|
862
|
579
|
|||||||||
Midstream
|
3
|
(16
|
)
|
25
|
||||||||
Abandonments (4)
|
144
|
101
|
87
|
|||||||||
Head office
|
7
|
12
|
10
|
|||||||||
Total
|
$
|
1,412
|
$
|
2,220
|
$
|
1,893
|
(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)
|
Capitalized interest and other includes expenditures related to land acquisition and retention, seismic, and other adjustments.
|
(4) | Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table. |
Canadian Natural Resources Limited
|
33
|
Three Months Ended
|
||||||||||||
(number of wells)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Net successful natural gas wells
|
9
|
16
|
25
|
|||||||||
Net successful crude oil wells (1)
|
42
|
325
|
271
|
|||||||||
Dry wells
|
2
|
8
|
3
|
|||||||||
Stratigraphic test / service wells
|
86
|
74
|
330
|
|||||||||
Total
|
139
|
423
|
629
|
|||||||||
Success rate (excluding stratigraphic test / service wells)
|
96%
|
|
98%
|
|
99%
|
|
(1) | Includes bitumen wells. |
34
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
35
|
($ millions, except ratios)
|
Mar 31
2015 |
Dec 31
2014 |
Mar 31
2014 |
|||||||||
Working capital deficit (1)
|
$
|
13
|
$
|
673
|
$
|
1,025
|
||||||
Long-term debt (2) (3)
|
$
|
15,689
|
$
|
14,002
|
$
|
10,354
|
||||||
Share capital
|
$
|
4,474
|
$
|
4,432
|
$
|
4,100
|
||||||
Retained earnings
|
23,905
|
24,408
|
22,193
|
|||||||||
Accumulated other comprehensive income
|
36
|
51
|
44
|
|||||||||
Shareholders’ equity
|
$
|
28,415
|
$
|
28,891
|
$
|
26,337
|
||||||
Debt to book capitalization (3) (4)
|
36%
|
|
33%
|
|
28%
|
|
||||||
Debt to market capitalization (3) (5)
|
27%
|
|
26%
|
|
18%
|
|
||||||
After-tax return on average common shareholders’ equity (6)
|
11%
|
|
14%
|
|
11%
|
|
||||||
After-tax return on average capital employed (3) (7)
|
8%
|
|
10%
|
|
8%
|
|
(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 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 declining commodity prices in late 2014 and the first quarter of 2015, 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 bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages. 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 $1,500 million non-revolving term credit facility maturing April 2018; and, |
§ | Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place to minimize the impact in the event of a default. |
36
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
37
|
($ millions)
|
Remaining
2015
|
2016
|
2017
|
2018
|
2019
|
Thereafter
|
||||||||||||||||||
Product transportation and
pipeline
|
$
|
367
|
$
|
354
|
$
|
324
|
$
|
284
|
$
|
248
|
$
|
1,527
|
||||||||||||
Offshore equipment operating
leases and offshore drilling
|
$
|
290
|
$
|
101
|
$
|
72
|
$
|
65
|
$
|
21
|
$
|
–
|
||||||||||||
Long-term debt (1)
|
$
|
1,034
|
$
|
1,064
|
$
|
3,008
|
$
|
2,767
|
$
|
1,000
|
$
|
6,898
|
||||||||||||
Interest and other financing
expense (2)
|
$
|
434
|
$
|
600
|
$
|
507
|
$
|
415
|
$
|
378
|
$
|
4,586
|
||||||||||||
Office leases
|
$
|
32
|
$
|
42
|
$
|
45
|
$
|
46
|
$
|
48
|
$
|
292
|
||||||||||||
Other
|
$
|
151
|
$
|
126
|
$
|
41
|
$
|
1
|
$
|
1
|
$
|
–
|
(1) | Long-term debt represents principal repayments only and does not reflect original issue discounts 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 March 31, 2015. |
38
|
Canadian Natural Resources Limited
|
As at
(millions of Canadian dollars, unaudited) |
Note
|
Mar 31
2015
|
Dec 31
2014
|
||||||||
ASSETS
|
|||||||||||
Current assets
|
|||||||||||
Cash and cash equivalents
|
$
|
34
|
$
|
25
|
|||||||
Accounts receivable
|
1,458
|
1,889
|
|||||||||
Current income taxes
|
562
|
228
|
|||||||||
Inventory
|
716
|
665
|
|||||||||
Prepaids and other
|
178
|
172
|
|||||||||
Current portion of other long-term assets
|
4
|
600
|
510
|
||||||||
3,548
|
3,489
|
||||||||||
Exploration and evaluation assets
|
2
|
3,531
|
3,557
|
||||||||
Property, plant and equipment
|
3
|
52,698
|
52,480
|
||||||||
Other long-term assets
|
4
|
922
|
674
|
||||||||
$
|
60,699
|
$
|
60,200
|
||||||||
LIABILITIES
|
|||||||||||
Current liabilities
|
|||||||||||
Accounts payable
|
$
|
598
|
$
|
564
|
|||||||
Accrued liabilities
|
2,651
|
3,279
|
|||||||||
Current portion of long-term debt
|
5
|
1,667
|
980
|
||||||||
Current portion of other long-term liabilities
|
6
|
312
|
319
|
||||||||
5,228
|
5,142
|
||||||||||
Long-term debt
|
5
|
14,022
|
13,022
|
||||||||
Other long-term liabilities
|
6
|
4,269
|
4,175
|
||||||||
Deferred income taxes
|
8,765
|
8,970
|
|||||||||
32,284
|
31,309
|
||||||||||
SHAREHOLDERS’ EQUITY
|
|||||||||||
Share capital
|
8
|
4,474
|
4,432
|
||||||||
Retained earnings
|
23,905
|
24,408
|
|||||||||
Accumulated other comprehensive income
|
9
|
36
|
51
|
||||||||
28,415
|
28,891
|
||||||||||
$
|
60,699
|
$
|
60,200
|
Canadian Natural Resources Limited
|
39
|
Three Months Ended
|
|||||||||||
(millions of Canadian dollars, except per common share amounts, unaudited)
|
Note
|
Mar 31
2015
|
Mar 31
2014
|
||||||||
Product sales
|
$
|
3,226
|
$
|
4,968
|
|||||||
Less: royalties
|
(192
|
)
|
(572
|
)
|
|||||||
Revenue
|
3,034
|
4,396
|
|||||||||
Expenses
|
|||||||||||
Production
|
1,253
|
1,211
|
|||||||||
Transportation and blending
|
635
|
831
|
|||||||||
Depletion, depreciation and amortization
|
3
|
1,355
|
1,011
|
||||||||
Administration
|
104
|
90
|
|||||||||
Share-based compensation
|
6
|
64
|
143
|
||||||||
Asset retirement obligation accretion
|
6
|
43
|
45
|
||||||||
Interest and other financing expense
|
86
|
68
|
|||||||||
Risk management activities
|
12
|
(242
|
)
|
(26
|
)
|
||||||
Foreign exchange loss
|
360
|
117
|
|||||||||
Equity loss from investment
|
4
|
15
|
1
|
||||||||
3,673
|
3,491
|
||||||||||
Earnings (loss) before taxes
|
(639
|
)
|
905
|
||||||||
Current income tax (recovery) expense
|
7
|
(105
|
)
|
126
|
|||||||
Deferred income tax (recovery) expense
|
7
|
(282
|
)
|
157
|
|||||||
Net earnings (loss)
|
$
|
(252
|
)
|
$
|
622
|
||||||
Net earnings (loss) per common share
|
|||||||||||
Basic
|
11
|
$
|
(0.23
|
)
|
$
|
0.57
|
|||||
Diluted
|
11
|
$
|
(0.23
|
)
|
$
|
0.57
|
Three Months Ended
|
||||||||
(millions of Canadian dollars, unaudited)
|
Mar 31
2015
|
Mar 31
2014
|
||||||
Net earnings (loss)
|
$
|
(252
|
)
|
$
|
622
|
|||
Items that may be reclassified subsequently to net earnings (loss)
|
||||||||
Net change in derivative financial instruments
designated as cash flow hedges
|
||||||||
Unrealized income (loss), net of taxes of
$1 million (2014 – $nil)
|
(9
|
)
|
1
|
|||||
Reclassification to net earnings (loss), net of taxes of
$nil (2014 – $nil)
|
(2
|
)
|
3
|
|||||
(11
|
)
|
4
|
||||||
Foreign currency translation adjustment
|
||||||||
Translation of net investment
|
(4
|
)
|
(2
|
)
|
||||
Other comprehensive income (loss), net of taxes
|
(15
|
)
|
2
|
|||||
Comprehensive income (loss)
|
$
|
(267
|
)
|
$
|
624
|
40
|
Canadian Natural Resources Limited
|
Three Months Ended
|
|||||||||||
(millions of Canadian dollars, unaudited)
|
Note
|
Mar 31
2015
|
Mar 31
2014
|
||||||||
Share capital
|
8
|
||||||||||
Balance – beginning of period
|
$
|
4,432
|
$
|
3,854
|
|||||||
Issued upon exercise of stock options
|
35
|
195
|
|||||||||
Previously recognized liability on stock options exercised for
common shares |
7
|
57
|
|||||||||
Purchase of common shares under Normal Course Issuer Bid
|
–
|
(6
|
)
|
||||||||
Balance – end of period
|
4,474
|
4,100
|
|||||||||
Retained earnings
|
|||||||||||
Balance – beginning of period
|
24,408
|
21,876
|
|||||||||
Net earnings (loss)
|
(252
|
)
|
622
|
||||||||
Purchase of common shares under Normal Course Issuer Bid
|
8
|
–
|
(59
|
)
|
|||||||
Dividends on common shares
|
8
|
(251
|
)
|
(246
|
)
|
||||||
Balance – end of period
|
23,905
|
22,193
|
|||||||||
Accumulated other comprehensive income
|
9
|
||||||||||
Balance – beginning of period
|
51
|
42
|
|||||||||
Other comprehensive income (loss), net of taxes
|
(15
|
)
|
2
|
||||||||
Balance – end of period
|
36
|
44
|
|||||||||
Shareholders’ equity
|
$
|
28,415
|
$
|
26,337
|
Canadian Natural Resources Limited
|
41
|
Three Months Ended | ||||||||
(millions of Canadian dollars, unaudited)
|
Mar 31
2015
|
Mar 31
2014
|
||||||
Operating activities
|
||||||||
Net earnings (loss)
|
$
|
(252
|
)
|
$
|
622
|
|||
Non-cash items
|
||||||||
Depletion, depreciation and amortization
|
1,355
|
1,011
|
||||||
Share-based compensation
|
64
|
143
|
||||||
Asset retirement obligation accretion
|
43
|
45
|
||||||
Unrealized risk management loss
|
14
|
49
|
||||||
Unrealized foreign exchange loss
|
413
|
118
|
||||||
Equity loss from investment
|
15
|
1
|
||||||
Deferred income tax (recovery) expense
|
(282
|
)
|
157
|
|||||
Other
|
42
|
31
|
||||||
Abandonment expenditures
|
(144
|
)
|
(87
|
)
|
||||
Net change in non-cash working capital
|
(14
|
)
|
(737
|
)
|
||||
1,254
|
1,353
|
|||||||
Financing activities
|
||||||||
Issue (repayment) of bank credit facilities and commercial paper, net
|
877
|
(661
|
)
|
|||||
Issue of US dollar debt securities, net
|
–
|
1,100
|
||||||
Issue of common shares on exercise of stock options
|
35
|
195
|
||||||
Purchase of common shares under Normal Course Issuer Bid
|
–
|
(65
|
)
|
|||||
Dividends on common shares
|
(245
|
)
|
(217
|
)
|
||||
Net change in non-cash working capital
|
(13
|
)
|
(5
|
)
|
||||
654
|
347
|
|||||||
Investing activities
|
||||||||
Net expenditures on exploration and evaluation assets
|
(46
|
)
|
(117
|
)
|
||||
Net expenditures on property, plant and equipment
|
(1,222
|
)
|
(1,689
|
)
|
||||
Investment in other long-term assets
|
(112
|
)
|
–
|
|||||
Net change in non-cash working capital
|
(519
|
)
|
109
|
|||||
(1,899
|
)
|
(1,697
|
)
|
|||||
Increase in cash and cash equivalents
|
9
|
3
|
||||||
Cash and cash equivalents – beginning of period
|
25
|
16
|
||||||
Cash and cash equivalents – end of period
|
$
|
34
|
$
|
19
|
||||
Interest paid
|
$
|
156
|
$
|
135
|
||||
Income taxes paid
|
$
|
209
|
$
|
455
|
42
|
Canadian Natural Resources Limited
|
Exploration and Production
|
Oil Sands
Mining and Upgrading
|
Total
|
||||||||||||||||||
North America
|
North Sea
|
Offshore Africa
|
||||||||||||||||||
Cost
|
||||||||||||||||||||
At December 31, 2014
|
$
|
3,426
|
$
|
–
|
$
|
131
|
$
|
–
|
$
|
3,557
|
||||||||||
Additions
|
44
|
–
|
2
|
–
|
46
|
|||||||||||||||
Transfers to property, plant and equipment
|
(78
|
)
|
–
|
–
|
–
|
(78
|
)
|
|||||||||||||
Foreign exchange adjustments
|
–
|
–
|
6
|
–
|
6
|
|||||||||||||||
At March 31, 2015
|
$
|
3,392
|
$
|
–
|
$
|
139
|
$
|
–
|
$
|
3,531
|
Canadian Natural Resources Limited
|
43
|
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
|
462
|
62
|
124
|
569
|
3
|
7
|
1,227
|
|||||||||||||||||||||
Transfers from E&E assets
|
78
|
–
|
–
|
–
|
–
|
–
|
78
|
|||||||||||||||||||||
Disposals/derecognitions
|
(88
|
)
|
–
|
–
|
(4
|
)
|
–
|
–
|
(92
|
)
|
||||||||||||||||||
Foreign exchange adjustments
and other
|
–
|
581
|
364
|
–
|
–
|
–
|
945
|
|||||||||||||||||||||
At March 31, 2015
|
$
|
61,058
|
$
|
6,825
|
$
|
4,346
|
$
|
22,513
|
$
|
573
|
$
|
359
|
$
|
95,674
|
||||||||||||||
Accumulated depletion and depreciation
|
||||||||||||||||||||||||||||
At December 31, 2014
|
$
|
31,886
|
$
|
4,049
|
$
|
2,890
|
$
|
1,864
|
$
|
120
|
$
|
227
|
$
|
41,036
|
||||||||||||||
Expense
|
1,098
|
86
|
22
|
139
|
3
|
7
|
1,355
|
|
||||||||||||||||||||
Disposals/derecognitions
|
(88
|
)
|
–
|
–
|
(4
|
)
|
–
|
–
|
(92
|
)
|
||||||||||||||||||
Foreign exchange adjustments
and other
|
(2
|
)
|
394
|
283
|
2
|
–
|
–
|
677
|
||||||||||||||||||||
At March 31, 2015
|
$
|
32,894
|
$
|
4,529
|
$
|
3,195
|
$
|
2,001
|
$
|
123
|
$
|
234
|
$
|
42,976
|
||||||||||||||
Net book value
– at March 31, 2015
|
$
|
28,164
|
$
|
2,296
|
$
|
1,151
|
$
|
20,512
|
$
|
450
|
$
|
125
|
$
|
52,698
|
||||||||||||||
– at December 31, 2014
|
$
|
28,720
|
$
|
2,133
|
$
|
968
|
$
|
20,084
|
$
|
450
|
$
|
125
|
$
|
52,480
|
Project costs not subject to depletion and depreciation
|
Mar 31 2015
|
Dec 31 2014
|
||||||
Horizon
|
$
|
5,909
|
$
|
5,492
|
||||
Kirby Thermal Oil Sands – North
|
$
|
748
|
$
|
681
|
44
|
Canadian Natural Resources Limited
|
Mar 31
2015
|
Dec 31
2014
|
|||||||
Investment in North West Redwater Partnership
|
$
|
283
|
$
|
298
|
||||
North West Redwater Partnership subordinated debt (1)
|
238
|
120
|
||||||
Risk Management (note 12)
|
881
|
599
|
||||||
Other
|
120
|
167
|
||||||
1,522
|
1,184
|
|||||||
Less: current portion
|
600
|
510
|
||||||
$
|
922
|
$
|
674
|
(1) | Includes accrued interest. |
Canadian Natural Resources Limited
|
45
|
Mar 31
2015
|
Dec 31
2014 |
|||||||
Canadian dollar denominated debt, unsecured
|
||||||||
Bank credit facilities
|
$
|
2,648
|
$
|
2,404
|
||||
Medium-term notes
|
2,400
|
2,400
|
||||||
5,048
|
4,804
|
|||||||
US dollar denominated debt, unsecured
|
||||||||
Bank credit facilities (March 31, 2015 – US$455 million;
December 31, 2014 – $nil)
|
$
|
577
|
$
|
–
|
||||
Commercial paper (US$500 million)
|
634
|
580
|
||||||
US dollar debt securities (US$7,500 million)
|
9,512
|
8,701
|
||||||
Less: original issue discount on US dollar debt securities (1)
|
(20
|
)
|
(21
|
)
|
||||
10,703
|
9,260
|
|||||||
Long-term debt before transaction costs
|
15,751
|
14,064
|
||||||
Less: transaction costs (1) (2)
|
(62
|
)
|
(62
|
)
|
||||
15,689
|
14,002
|
|||||||
Less: current portion of commercial paper
|
634
|
580
|
||||||
current portion of long-term debt (1) (2)
|
1,033
|
400
|
||||||
$
|
14,022
|
$
|
13,022
|
(1) | The Company has included unamortized original issue discounts 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 $1,500 million revolving syndicated credit facility maturing June 2016; |
§ | a $1,000 million non-revolving term credit facility maturing January 2017; |
§ | a $3,000 million revolving syndicated credit facility maturing June 2017; |
§ | a $1,500 million non-revolving term credit facility maturing April 2018; and |
§ | a £15 million demand credit facility related to the Company’s North Sea operations. |
46
|
Canadian Natural Resources Limited
|
Mar 31
2015
|
Dec 31
2014 |
|||||||
Asset retirement obligations
|
$
|
4,254
|
$
|
4,221
|
||||
Share-based compensation
|
273
|
203
|
||||||
Other
|
54
|
70
|
||||||
4,581
|
4,494
|
|||||||
Less: current portion
|
312
|
319
|
||||||
$
|
4,269
|
$
|
4,175
|
Mar 31
2015
|
Dec 31
2014
|
|||||||
Balance – beginning of period
|
$
|
4,221
|
$
|
4,162
|
||||
Liabilities incurred
|
3
|
41
|
||||||
Liabilities acquired
|
2
|
404
|
||||||
Liabilities settled
|
(144
|
)
|
(346
|
)
|
||||
Asset retirement obligation accretion
|
43
|
193
|
||||||
Revision of cost, inflation rates and timing estimates
|
–
|
(907
|
)
|
|||||
Change in discount rate
|
–
|
558
|
||||||
Foreign exchange adjustments
|
129
|
116
|
||||||
Balance – end of period
|
4,254
|
4,221
|
||||||
Less: current portion
|
78
|
121
|
||||||
$
|
4,176
|
$
|
4,100
|
Canadian Natural Resources Limited
|
47
|
Mar 31
2015 |
Dec 31
2014 |
|||||||
Balance – beginning of period
|
$
|
203
|
$
|
260
|
||||
Share-based compensation expense
|
64
|
66
|
||||||
Cash payment for stock options surrendered
|
(1
|
)
|
(8
|
)
|
||||
Transferred to common shares
|
(7
|
)
|
(129
|
)
|
||||
Capitalized to Oil Sands Mining and Upgrading
|
14
|
14
|
||||||
Balance – end of period
|
273
|
203
|
||||||
Less: current portion
|
207
|
158
|
||||||
$
|
66
|
$
|
45
|
Three Months Ended
|
||||||||
Mar 31
2015 |
Mar 31
2014 |
|||||||
Current corporate income tax expense – North America
|
$
|
8
|
$
|
192
|
||||
Current corporate income tax recovery – North Sea
|
(64
|
)
|
(15
|
)
|
||||
Current corporate income tax expense – Offshore Africa
|
2
|
4
|
||||||
Current PRT (1) recovery – North Sea
|
(54
|
)
|
(61
|
)
|
||||
Other taxes
|
3
|
6
|
||||||
Current income tax (recovery) expense
|
(105
|
)
|
126
|
|||||
Deferred corporate income tax (recovery) expense
|
(289
|
)
|
91
|
|||||
Deferred PRT (1) expense – North Sea
|
7
|
66
|
||||||
Deferred income tax (recovery) expense
|
(282
|
)
|
157
|
|||||
Income tax (recovery) expense
|
$
|
(387
|
)
|
$
|
283
|
(1) | Petroleum Revenue Tax. |
48
|
Canadian Natural Resources Limited
|
Three Months Ended Mar 31, 2015 | ||||||||
Issued common shares
|
Number of shares (thousands)
|
Amount
|
||||||
Balance – beginning of period
|
1,091,837
|
$
|
4,432
|
|||||
Issued upon exercise of stock options
|
1,104
|
35
|
||||||
Previously recognized liability on stock options exercised for
common shares
|
–
|
7
|
||||||
Balance – end of period
|
1,092,941
|
$
|
4,474
|
Three Months Ended Mar 31, 2015 | ||||||||
Stock options (thousands)
|
Weighted
average
exercise price |
|||||||
Outstanding – beginning of period
|
71,708
|
$
|
35.60
|
|||||
Granted
|
4,697
|
$
|
33.16
|
|||||
Surrendered for cash settlement
|
(92
|
)
|
$
|
32.98
|
||||
Exercised for common shares
|
(1,104
|
)
|
$
|
31.96
|
||||
Forfeited
|
(4,992
|
)
|
$
|
34.65
|
||||
Outstanding – end of period
|
70,217
|
$
|
35.56
|
|||||
Exercisable – end of period
|
19,852
|
$
|
36.82
|
Canadian Natural Resources Limited
|
49
|
Mar 31
2015
|
Mar 31
2014
|
|||||||
Derivative financial instruments designated as cash flow hedges
|
$
|
83
|
$
|
85
|
||||
Foreign currency translation adjustment
|
(47
|
)
|
(41
|
)
|
||||
$
|
36
|
$
|
44
|
Mar 31
2015
|
Dec 31
2014
|
|||||||
Long-term debt (1)
|
$
|
15,689
|
$
|
14,002
|
||||
Total shareholders’ equity
|
$
|
28,415
|
$
|
28,891
|
||||
Debt to book capitalization
|
36%
|
|
33%
|
|
(1) | Includes the current portion of long-term debt. |
Three Months Ended
|
||||||||
Mar 31
2015 |
Mar 31
2014
|
|||||||
Weighted average common shares outstanding
– basic (thousands of shares) |
1,092,350
|
1,089,929
|
||||||
Effect of dilutive stock options (thousands of shares) (1)
|
–
|
3,298
|
||||||
Weighted average common shares outstanding
– diluted (thousands of shares) |
1,092,350
|
1,093,227
|
||||||
Net earnings (loss)
|
$
|
(252
|
)
|
$
|
622
|
|||
Net earnings (loss) per common share – basic
|
$
|
(0.23
|
)
|
$
|
0.57
|
|||
– diluted
|
$
|
(0.23
|
)
|
$
|
0.57
|
(1) | For the three months ended March 31, 2015, the dilutive effect of 2,053,000 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. |
50
|
Canadian Natural Resources Limited
|
Mar 31, 2015
|
||||||||||||||||||||
Asset (liability)
|
Financial
assets at
amortized
cost
|
Fair value
through profit
or loss
|
Derivatives
used for
hedging
|
Financial
liabilities at amortized
cost
|
Total
|
|||||||||||||||
Accounts receivable
|
$
|
1,458
|
$
|
–
|
$
|
–
|
$
|
–
|
$
|
1,458
|
||||||||||
Other long-term assets
|
238
|
399
|
482
|
–
|
1,119
|
|||||||||||||||
Accounts payable
|
–
|
–
|
–
|
(598
|
)
|
(598
|
)
|
|||||||||||||
Accrued liabilities
|
–
|
–
|
–
|
(2,651
|
)
|
(2,651
|
)
|
|||||||||||||
Other long-term liabilities
|
–
|
–
|
–
|
(27
|
)
|
(27
|
)
|
|||||||||||||
Long-term debt (1)
|
–
|
–
|
–
|
(15,689
|
)
|
(15,689
|
)
|
|||||||||||||
$
|
1,696
|
$
|
399
|
$
|
482
|
$
|
(18,965
|
)
|
$
|
(16,388
|
)
|
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. |
Mar 31, 2015
|
||||||||||||||||
Carrying amount
|
Fair value
|
|||||||||||||||
Asset (liability) (1) (2)
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
Other long-term assets (3)
|
$
|
1,119
|
$
|
–
|
$
|
881
|
$
|
238
|
||||||||
Fixed rate long-term debt (4) (5)
|
$
|
(11,830
|
)
|
$
|
(12,904
|
)
|
$
|
–
|
$
|
–
|
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
|
51
|
Asset (liability)
|
Mar 31, 2015
|
Dec 31, 2014
|
||||||
Derivatives held for trading
|
||||||||
Crude oil price collars
|
$
|
382
|
$
|
410
|
||||
Crude oil WCS (1) differential swaps
|
–
|
(16
|
)
|
|||||
Foreign currency forward contracts
|
17
|
21
|
||||||
Cash flow hedges
|
||||||||
Foreign currency forward contracts
|
7
|
11
|
||||||
Cross currency swaps
|
475
|
173
|
||||||
$
|
881
|
$
|
599
|
|||||
Included within:
|
||||||||
Current portion of other long-term assets
|
$
|
521
|
$
|
436
|
||||
Other long-term assets
|
360
|
163
|
||||||
$
|
881
|
$
|
599
|
(1) | Western Canadian Select. |
Asset (liability)
|
Three Months Ended
Mar 31, 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
|
(14
|
)
|
451
|
|||||
Foreign exchange
|
308
|
270
|
||||||
Other comprehensive income (loss)
|
(12
|
)
|
14
|
|||||
Balance – end of period
|
881
|
599
|
||||||
Less: current portion
|
521
|
436
|
||||||
$
|
360
|
$
|
163
|
52
|
Canadian Natural Resources Limited
|
Three Months Ended
|
||||||||
Mar 31
2015
|
Mar 31
2014
|
|||||||
Net realized risk management gain
|
$
|
(256
|
)
|
$
|
(75
|
)
|
||
Net unrealized risk management loss
|
14
|
49
|
||||||
$
|
(242
|
)
|
$
|
(26
|
)
|
a) | Market risk |
Remaining term
|
Volume
|
Weighted average price
|
Index
|
|||||
Crude oil
|
||||||||
Price collars
|
Apr 2015
|
–
|
Dec 2015
|
50,000 bbl/d
|
US$80.00
|
–
|
US$120.52
|
Brent
|
Canadian Natural Resources Limited
|
53
|
Remaining term
|
Amount
|
Exchange rate
(US$/C$)
|
Interest rate
(US$)
|
Interest rate
(C$)
|
|||
Cross currency
|
|||||||
Swaps
|
Apr 2015
|
–
|
Mar 2016
|
US$500
|
1.109
|
Three-month
LIBOR plus
0.375%
|
Three-month
CDOR (1) plus
0.309%
|
Apr 2015
|
–
|
Aug 2016
|
US$250
|
1.116
|
6.00%
|
5.40%
|
|
Apr 2015
|
–
|
May 2017
|
US$1,100
|
1.170
|
5.70%
|
5.10%
|
|
Apr 2015
|
–
|
Nov 2021
|
US$500
|
1.022
|
3.45%
|
3.96%
|
|
Apr 2015
|
–
|
Mar 2038
|
US$550
|
1.170
|
6.25%
|
5.76%
|
(1) | Canadian Dealer Offered Rate (“CDOR”). |
b) | Credit risk |
c) | Liquidity risk |
54
|
Canadian Natural Resources Limited
|
Less than
1 year |
1 to less than
2 years |
2 to less than
5 years |
Thereafter
|
|||||||||||||
Accounts payable
|
$
|
598
|
$
|
–
|
$
|
–
|
$
|
–
|
||||||||
Accrued liabilities
|
$
|
2,651
|
$
|
–
|
$
|
–
|
$
|
–
|
||||||||
Other long-term liabilities
|
$
|
27
|
$
|
–
|
$
|
–
|
$
|
–
|
||||||||
Long-term debt (1)
|
$
|
1,668
|
$
|
1,429
|
$
|
5,776
|
$
|
6,898
|
(1) | Long-term debt represents principal repayments only and does not reflect interest, original issue discounts or transaction costs. |
Remaining
2015
|
2016
|
2017
|
2018
|
2019
|
Thereafter
|
|||||||||||||||||||
Product transportation
and pipeline |
$
|
367
|
$
|
354
|
$
|
324
|
$
|
284
|
$
|
248
|
$
|
1,527
|
||||||||||||
Offshore equipment operating
leases and offshore drilling
|
$
|
290
|
$
|
101
|
$
|
72
|
$
|
65
|
$
|
21
|
$
|
–
|
||||||||||||
Office leases
|
$
|
32
|
$
|
42
|
$
|
45
|
$
|
46
|
$
|
48
|
$
|
292
|
||||||||||||
Other
|
$
|
151
|
$
|
126
|
$
|
41
|
$
|
1
|
$
|
1
|
$
|
–
|
Canadian Natural Resources Limited
|
55
|
Exploration and Production
|
||||||||||||||||||||||||||||||||
North America
|
North Sea
|
Offshore Africa
|
Total Exploration and
Production
|
|||||||||||||||||||||||||||||
(millions of Canadian dollars,
unaudited) |
Three Months Ended
Mar 31 |
Three Months Ended
Mar 31 |
Three Months Ended
Mar 31 |
Three Months Ended
Mar 31 |
||||||||||||||||||||||||||||
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
|||||||||||||||||||||||||
Segmented product sales
|
2,334
|
3,657
|
152
|
198
|
67
|
24
|
2,553
|
3,879
|
||||||||||||||||||||||||
Less: royalties
|
(177
|
)
|
(516
|
)
|
–
|
(1
|
)
|
(3
|
)
|
(4
|
)
|
(180
|
)
|
(521
|
)
|
|||||||||||||||||
Segmented revenue
|
2,157
|
3,141
|
152
|
197
|
64
|
20
|
2,373
|
3,358
|
||||||||||||||||||||||||
Segmented expenses
|
||||||||||||||||||||||||||||||||
Production
|
751
|
663
|
134
|
123
|
15
|
7
|
900
|
793
|
||||||||||||||||||||||||
Transportation and blending
|
620
|
828
|
13
|
2
|
1
|
–
|
634
|
830
|
||||||||||||||||||||||||
Depletion, depreciation and amortization
|
1,104
|
816
|
87
|
58
|
22
|
5
|
1,213
|
879
|
||||||||||||||||||||||||
Asset retirement obligation accretion
|
23
|
22
|
9
|
9
|
3
|
2
|
35
|
33
|
||||||||||||||||||||||||
Realized risk management activities
|
(256
|
)
|
(75
|
)
|
–
|
–
|
–
|
–
|
(256
|
)
|
(75
|
)
|
||||||||||||||||||||
Equity loss from investment
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
||||||||||||||||||||||||
Total segmented expenses
|
2,242
|
2,254
|
243
|
192
|
41
|
14
|
2,526
|
2,460
|
||||||||||||||||||||||||
Segmented earnings (loss) before the following
|
(85
|
)
|
887
|
(91
|
)
|
5
|
23
|
6
|
(153
|
)
|
898
|
|||||||||||||||||||||
Non-segmented expenses
|
||||||||||||||||||||||||||||||||
Administration
|
||||||||||||||||||||||||||||||||
Share-based compensation
|
||||||||||||||||||||||||||||||||
Interest and other financing expense
|
||||||||||||||||||||||||||||||||
Unrealized risk management activities
|
||||||||||||||||||||||||||||||||
Foreign exchange loss
|
||||||||||||||||||||||||||||||||
Total non-segmented expenses
|
||||||||||||||||||||||||||||||||
Earnings (loss) before taxes
|
||||||||||||||||||||||||||||||||
Current income tax (recovery) expense
|
||||||||||||||||||||||||||||||||
Deferred income tax (recovery) expense
|
||||||||||||||||||||||||||||||||
Net earnings (loss)
|
56
|
Canadian Natural Resources Limited
|
Oil Sands Mining and Upgrading
|
Midstream
|
Inter-segment elimination and
other
|
Total
|
|||||||||||||||||||||||||||||
(millions of Canadian dollars,
unaudited) |
Three Months Ended
Mar 31 |
Three Months Ended
Mar 31 |
Three Months Ended
Mar 31 |
Three Months Ended
Mar 31 |
||||||||||||||||||||||||||||
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
|||||||||||||||||||||||||
Segmented product sales
|
660
|
1,082
|
35
|
31
|
(22
|
)
|
(24
|
)
|
3,226
|
4,968
|
||||||||||||||||||||||
Less: royalties
|
(12
|
)
|
(51
|
)
|
–
|
–
|
–
|
–
|
(192
|
)
|
(572
|
)
|
||||||||||||||||||||
Segmented revenue
|
648
|
1,031
|
35
|
31
|
(22
|
)
|
(24
|
)
|
3,034
|
4,396
|
||||||||||||||||||||||
Segmented expenses
|
||||||||||||||||||||||||||||||||
Production
|
346
|
412
|
9
|
9
|
(2
|
)
|
(3
|
)
|
1,253
|
1,211
|
||||||||||||||||||||||
Transportation and blending
|
21
|
20
|
–
|
–
|
(20
|
)
|
(19
|
)
|
635
|
831
|
||||||||||||||||||||||
Depletion, depreciation and amortization
|
139
|
130
|
3
|
2
|
–
|
–
|
1,355
|
1,011
|
||||||||||||||||||||||||
Asset retirement obligation accretion
|
8
|
12
|
–
|
–
|
–
|
–
|
43
|
45
|
||||||||||||||||||||||||
Realized risk management activities
|
–
|
–
|
–
|
–
|
–
|
–
|
(256
|
)
|
(75
|
)
|
||||||||||||||||||||||
Equity loss from investment
|
–
|
–
|
15
|
1
|
–
|
–
|
15
|
1
|
||||||||||||||||||||||||
Total segmented expenses
|
514
|
574
|
27
|
12
|
(22
|
)
|
(22
|
)
|
3,045
|
3,024
|
||||||||||||||||||||||
Segmented earnings (loss) before the following
|
134
|
457
|
8
|
19
|
-
|
(2
|
)
|
(11
|
)
|
1,372
|
||||||||||||||||||||||
Non-segmented expenses
|
||||||||||||||||||||||||||||||||
Administration
|
104
|
90
|
||||||||||||||||||||||||||||||
Share-based compensation
|
64
|
143
|
||||||||||||||||||||||||||||||
Interest and other financing expense
|
86
|
68
|
||||||||||||||||||||||||||||||
Unrealized risk management activities
|
14
|
49
|
||||||||||||||||||||||||||||||
Foreign exchange loss
|
360
|
117
|
||||||||||||||||||||||||||||||
Total non-segmented expenses
|
628
|
467
|
||||||||||||||||||||||||||||||
Earnings (loss) before taxes
|
(639
|
)
|
905
|
|||||||||||||||||||||||||||||
Current income tax (recovery) expense
|
(105
|
)
|
126
|
|||||||||||||||||||||||||||||
Deferred income tax (recovery) expense
|
(282
|
)
|
157
|
|||||||||||||||||||||||||||||
Net earnings (loss)
|
(252
|
)
|
622
|
Canadian Natural Resources Limited
|
57
|
Three Months Ended
|
||||||||||||||||||||||||
Mar 31, 2015
|
Mar 31, 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
|
$
|
44
|
$
|
(78
|
)
|
$
|
(34
|
)
|
$
|
100
|
$
|
(47
|
)
|
$
|
53
|
|||||||||
North Sea
|
–
|
–
|
–
|
–
|
–
|
–
|
||||||||||||||||||
Offshore Africa
|
2
|
–
|
2
|
17
|
–
|
17
|
||||||||||||||||||
$
|
46
|
$
|
(78
|
)
|
$
|
(32
|
)
|
$
|
117
|
$
|
(47
|
)
|
$
|
70
|
||||||||||
Property, plant and equipment
|
||||||||||||||||||||||||
Exploration and Production
|
||||||||||||||||||||||||
North America
|
$
|
457
|
$
|
(5
|
)
|
$
|
452
|
$
|
987
|
$
|
(18
|
)
|
$
|
969
|
||||||||||
North Sea
|
62
|
–
|
62
|
88
|
–
|
88
|
||||||||||||||||||
Offshore Africa
|
124
|
–
|
124
|
–
|
–
|
–
|
||||||||||||||||||
643
|
(5
|
)
|
638
|
1,075
|
(18
|
)
|
1,057
|
|||||||||||||||||
Oil Sands Mining and Upgrading (3)
|
569
|
(4
|
)
|
565
|
579
|
(7
|
)
|
572
|
||||||||||||||||
Midstream
|
3
|
–
|
3
|
25
|
–
|
25
|
||||||||||||||||||
Head office
|
7
|
–
|
7
|
10
|
(1
|
)
|
9
|
|||||||||||||||||
$
|
1,222
|
$
|
(9
|
)
|
$
|
1,213
|
$
|
1,689
|
$
|
(26
|
)
|
$
|
1,663
|
(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) | Net expenditures for Oil Sands Mining and Upgrading also include capitalized interest and share-based compensation. |
Total Assets
|
||||||||
Mar 31
2015
|
Dec 31
2014 |
|||||||
Exploration and Production
|
||||||||
North America
|
$
|
34,015
|
$
|
34,382
|
||||
North Sea
|
2,834
|
2,711
|
||||||
Offshore Africa
|
1,489
|
1,214
|
||||||
Other
|
51
|
18
|
||||||
Oil Sands Mining and Upgrading
|
21,078
|
20,702
|
||||||
Midstream
|
1,107
|
1,048
|
||||||
Head office
|
125
|
125
|
||||||
$
|
60,699
|
$
|
60,200
|
58
|
Canadian Natural Resources Limited
|
Interest coverage ratios for the twelve month period ended March 31, 2015:
|
|
Interest coverage (times)
|
|
Net earnings (1)
|
7.4x
|
Cash flow from operations (2)
|
17.3x
|
(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. |
Canadian Natural Resources Limited
|
59
|
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 Verschuren, O.C.
Officers
N. Murray Edwards
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 Peter J. Janson
Senior Vice-President, Horizon Operations 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
|
60
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
61
|
62
|
Canadian Natural Resources Limited
|
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
|
64
|
Canadian Natural Resources Limited
|
1 Year Canadian Natural Resources Chart |
1 Month Canadian Natural Resources Chart |
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