CALGARY, ALBERTA–(Marketwired – May 7, 2015) – Commenting on first quarter results, Steve Laut, President of Canadian Natural (TSX:CNQ) (NYSE:CNQ) stated, “As expected, low commodity prices impacted first quarter cash flow and earnings. Operationally, the first quarter was very strong with record quarterly production approaching 900,000 BOE/d. Crude oil production increased by 23% and natural gas production increased by 51% from the first quarter of 2014. Canadian Natural’s operations continue to be effective and efficient as operating costs reduced by 22% for total liquids and 10% for North America natural gas in the first quarter of 2015 versus the same quarter in 2014. Our performance reflects the resilience of our strong, diverse and well balanced asset base, the robustness of our business model, and the effectiveness of our strategies combined with our ability to execute these strategies.”
Canadian Natural’s Chief Financial Officer, Corey Bieber, continued, “Canadian Natural continues to prudently manage its balance sheet and liquidity. Following the precipitous fall in crude oil pricing, we proactively adjusted our capital spending profile to reflect targeted internal cash flow generation while optimizing the value of investments made and protecting the growth profile of the Horizon Project. We continue to focus on cost reduction and efficiency improvements to further improve returns in the current price environment. Our balance sheet metrics remain strong, giving us the financial flexibility to deliver our defined growth plan and continue to drive long-term shareholder value creation irrespective of the business cycle.”
QUARTERLY HIGHLIGHTS
Three Months Ended
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($ Millions, except per common Mar 31 Dec 31 Mar 31
share amounts) 2015 2014 2014
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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
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(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.
– 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.
CORPORATE UPDATE
Dr. Eldon Smith, due to reaching the mandatory retirement age, and Mr. Keith A.J. MacPhail, due to a desire to free up more time for personal interests, have chosen to not stand for re-election to the Company’s Board of Directors in 2015. The Board of Directors and the Senior Management of Canadian Natural wish to thank Dr. Smith and Mr. MacPhail for their service and for their contributions over the years to the success of the Company.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its activities in core regions where the Company owns a substantial land base and associated infrastructure. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning and operating associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Furthermore, the Company maintains large project inventories and production diversification among each of the commodities it produces; light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen and SCO (herein collectively referred to as “crude oil”), natural gas and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.
Drilling activity
Three Months Ended Mar 31
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2015 2014
(number of wells) Gross Net Gross Net
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Crude oil 48 42 300 271
Natural gas 13 9 32 25
Dry 2 2 4 3
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Subtotal 63 53 336 299
Stratigraphic test / service wells 121 86 330 330
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Total 184 139 666 629
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Success rate (excluding
stratigraphic test / service
wells) 96% 99%
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– 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.
North America Exploration and Production
Crude oil and NGLs - excluding Thermal In Situ Oil Sands
Three Months Ended
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Mar 31 Dec 31 Mar 31
2015 2014 2014
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Crude oil and NGLs production
(bbl/d) 286,333 291,002 266,110
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Net wells targeting crude oil 40 332 263
Net successful wells drilled 38 324 260
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Success rate 95% 98% 99%
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– 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.
– 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.
Thermal In Situ Oil Sands
Three Months Ended
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Mar 31 Dec 31 Mar 31
2015 2014 2014
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Bitumen production (bbl/d) 146,086 118,974 82,077
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Net wells targeting bitumen 3 - 11
Net successful wells drilled 3 - 11
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Success rate 100% - 100%
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– 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.
Natural Gas
Three Months Ended
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Mar 31 Dec 31 Mar 31
2015 2014 2014
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Natural gas production (MMcf/d) 1,713 1,705 1,147
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Net wells targeting natural gas 9 16 25
Net successful wells drilled 9 16 25
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Success rate 100% 100% 100%
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– 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.
– 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.
International Exploration and Production
Three Months Ended
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Mar 31 Dec 31 Mar 31
2015 2014 2014
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Crude oil production (bbl/d)
North Sea 23,036 21,927 16,715
Offshore Africa 13,188 12,047 10,791
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Natural gas production (MMcf/d)
North Sea 34 10 7
Offshore Africa 24 18 21
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Net wells targeting crude oil 0.6 1.0 -
Net successful wells drilled 0.6 1.0 -
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Success rate 100% 100% -
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– 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 Cote 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 Cote 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.
North America Oil Sands Mining and Upgrading – Horizon
Three Months Ended
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Mar 31 Dec 31 Mar 31
2015 2014 2014
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Synthetic crude oil production
(bbl/d) (1) 134,166 128,090 113,095
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(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).
– 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.
ROYALTY PRODUCTION AND REVENUE
Based on the analysis completed to date, Canadian Natural reports the following information for quarterly royalty volumes, which are based on the Company’s current estimate of revenue and volumes attributable to Q4/14:
– 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.
Royalty Production Volumes Comparison (1)
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 Production Volumes (1)
Royalty volumes for Q4/14 attributable to
---------------------------------------------
Canadian
Third Party Natural(2) Total
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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
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Total (BOE/d) 7,442 1,290 8,732
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Royalty Revenue by Product (1)
Royalty revenue for Q4/14 attributable to
---------------------------------------------
Canadian
($ millions) Third Party Natural(2) Total
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Natural gas $ 7 1 8
Crude oil $ 22 4 26
NGLs $ 2 - 2
Other revenue (3) $ 4 - 4
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Total $ 35 5 40
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Revenue by Royalty Classification (1)
Royalty revenue for Q4/14 attributable to
---------------------------------------------
Canadian
($ millions) Third Party Natural(2) Total
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Fee title $ 19 4 23
Gross overriding royalty (4) $ 12 1 13
Other revenue (3) $ 4 - 4
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Total $ 35 5 40
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Royalty Realized Pricing (1)
---------------
Q4/14
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Natural gas ($/Mcf) $ 3.60
Crude oil ($/bbl) $ 67.84
NGLs ($/bbl) $ 41.15
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Total ($/BOE) $ 50.35
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Royalty Acreage
Leased to
---------------------------------------------
Third Party Canadian
(gross acres, millions) and Unleased Natural(2) Total
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Fee title (5) 3.14 0.21 3.35
Gross overriding royalty (4) 1.90 1.64 3.54
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Total 5.04 1.85 6.89
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(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.
MARKETING
Three Months Ended
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Mar 31 Dec 31 Mar 31
2015 2014 2014
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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
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(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.
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WCS Blend
WCS Blend Differential
WTI Pricing Differential from WTI
Benchmark Pricing (US$/bbl) from WTI (%) (US$/bbl)
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2015
January $ 47.33 36% $ (16.90)
February $ 50.72 28% $ (14.20)
March $ 47.85 27% $ (13.09)
April $ 54.63 26% $ (14.37)
May(i) $ 60.65 20% $ (11.87)
June(i) $ 61.67 14% $ (8.73)
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SCO Dated Brent Condensate
Differential Differential Differential
from WTI from WTI from WTI
Benchmark Pricing (US$/bbl) (US$/bbl) (US$/bbl)
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2015
January $ (3.16) $ 0.74 $ (4.89)
February $ (3.43) $ 7.21 $ (4.24)
March $ (3.33) $ 7.94 $ 0.09
April $ 0.86 $ 5.13 $ 0.68
May(i) $ 3.43 $ 5.95 $ 1.54
June(i) $ 3.68 $ 5.77 $ (1.37)
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(i) Based on current indicative pricing as at May 5, 2015.
– 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.
NORTH WEST REDWATER UPGRADING AND REFINING
The North West Redwater refinery, upon completion, will strengthen the Company’s position by providing a competitive return on investment and by adding 50,000 bbl/d of bitumen conversion capacity in Alberta which will help reduce pricing volatility in all Western Canadian heavy crude oil. The Company has a 50% interest in the North West Redwater Partnership. For project updates, please refer to:www.nwrpartnership.com/brief-updates.
FINANCIAL REVIEW
The Company continues to implement proven strategies and its disciplined approach to capital allocation. As a result, the financial position of Canadian Natural remains strong. Canadian Natural’s cash flow generation, credit facilities, US commercial paper program, diverse asset base and related flexible capital expenditure programs and commodity hedging policy all support a flexible financial position and provide the appropriate financial resources for the near-, mid- and long-term.
– 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.
OUTLOOK
The Company forecasts 2015 production levels before royalties to average between 562,000 and 602,000 bbl/d of crude oil and NGLs and between 1,730 and 1,770 MMcf/d of natural gas. Q2/15 production guidance before royalties is forecast to average between 513,000 and 540,000 bbl/d of crude oil and NGLs and between 1,750 and 1,770 MMcf/d of natural gas. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company’s website at www.cnrl.com.