CALGARY, ALBERTA–(Marketwired – Nov. 2, 2017) – Commenting on Company results, Steve Laut, President of Canadian Natural (TSX:CNQ)(NYSE:CNQ) stated, “Canadian Natural has reached a major milestone with the successful completion of the Phase 3 expansion at our world class Horizon Oil Sands Mining and Upgrading asset, a significant event. The completion of the Phase 3 expansion also marks the final step of our transition to a long life low decline asset base. High value upgraded products will represent approximately 45% of total corporate liquids production in the fourth quarter of 2017 and approximately 70% of our liquids production volumes are from long life low decline assets, and will increase going into 2018. Our long life low decline assets combined with our strong portfolio of conventional E&P assets will drive significant sustainable free cash flow providing flexibility for continued balanced capital allocation to our four pillars; economic resource development, returns to shareholders, opportunistic acquisitions and balance sheet strength, with continued focus on increasing return on equity and capital employed.”
Canadian Natural’s Chief Operating Officer, Tim McKay, added, “The Horizon Phase 3 expansion and the turnaround and tie-in activities are complete and were on budget, strong results for this large scale, world class project. Optimization and reliability work on the fractionation tower, the vacuum distillate unit and diluent recovery unit furnaces were also successfully completed during the turnaround on time and on budget. With completion of the Horizon turnaround, startup activities are underway and are going as expected, with production ramping up through November and December.
In the third quarter, operations across our balanced asset base were strong as quarterly production reached record levels for the second straight quarter at just under 1,040,000 BOE/d, up 14% from the second quarter of 2017. Production increases were achieved as a result of strong utilization and high reliability at the Athabasca Oil Sands Project for a full quarter and drilling programs that delivered as expected at Pelican Lake, primary heavy crude oil and light crude oil. Our continued focus on effectiveness and efficiencies delivered strong quarterly operating costs at AOSP of $24.60/bbl of synthetic crude oil.”
Canadian Natural’s Chief Financial Officer, Corey Bieber, continued, “The Company was able to achieve funds flow from operations of approximately $1.7 billion in the quarter, contributing to absolute debt reduction of $350 million when compared to second quarter 2017 debt levels, even as we funded the Pelican Lake acquisition in the quarter. Liquidity improved to $3.9 billion and debt metrics strengthened at the end of the quarter. Debt to EBITDA decreased to 3.0x at quarter end, while debt to book capital remains in the Company’s targeted range at 42%. With completion of the Horizon Phase 3 expansion, strong reliability at AOSP and continued focus on effective operations across our asset base, the Company will generate significant growing sustainable free cash flow, allowing for balanced capital allocation that includes a focus on continued strengthening of our balance sheet.”
QUARTERLY HIGHLIGHTS | ||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||
($ millions, except per common share amounts) | Sep 30 2017 |
Jun 30 2017 |
Sep 30 2016 |
Sep 30 2017 |
Sep 30 2016 |
|||||||||
Net earnings (loss) | $ | 684 | $ | 1,072 | $ | (326 | ) | $ | 2,001 | $ | (770 | ) | ||
Per common share | – basic | $ | 0.56 | $ | 0.93 | $ | (0.29 | ) | $ | 1.72 | $ | (0.70 | ) | |
– diluted | $ | 0.56 | $ | 0.93 | $ | (0.29 | ) | $ | 1.71 | $ | (0.70 | ) | ||
Adjusted net earnings (loss) from operations (1) | $ | 229 | $ | 332 | $ | (355 | ) | $ | 838 | $ | (1,108 | ) | ||
Per common share | – basic | $ | 0.19 | $ | 0.29 | $ | (0.32 | ) | $ | 0.72 | $ | (1.01 | ) | |
– diluted | $ | 0.19 | $ | 0.29 | $ | (0.32 | ) | $ | 0.72 | $ | (1.01 | ) | ||
Funds flow from operations (2) | $ | 1,675 | $ | 1,726 | $ | 1,021 | $ | 5,040 | $ | 2,616 | ||||
Per common share | – basic | $ | 1.38 | $ | 1.50 | $ | 0.93 | $ | 4.34 | $ | 2.38 | |||
– diluted | $ | 1.37 | $ | 1.49 | $ | 0.92 | $ | 4.32 | $ | 2.38 | ||||
Capital expenditures, excluding AOSP acquisition costs (3) | $ | 2,094 | $ | 889 | $ | 1,185 | $ | 3,829 | $ | 3,383 | ||||
Total net capital expenditures (3) | $ | 2,094 | $ | 13,046 | $ | 1,185 | $ | 15,986 | $ | 3,383 | ||||
Daily production, before royalties | ||||||||||||||
Natural gas (MMcf/d) | 1,664 | 1,656 | 1,645 | 1,664 | 1,707 | |||||||||
Crude oil and NGLs (bbl/d) | 759,189 | 637,127 | 460,986 | 665,399 | 503,286 | |||||||||
Equivalent production (BOE/d) (4) | 1,036,499 | 913,171 | 735,212 | 942,776 | 787,718 |
(1) Adjusted net earnings (loss) 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) Funds flow from operations (formally 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) For additional information and details, refer to the net capital expenditures table in the Company’s MD&A.
(4) 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.
– The Company’s corporate production volumes averaged a record 1,036,499 BOE/d in Q3/17, representing 14% and 41% increases from Q2/17 and Q3/16 levels, respectively.
– Canadian Natural’s corporate crude oil and NGLs production volumes averaged a record 759,189 bbl/d representing 19% and 65% increases from Q2/17 and Q3/16 levels respectively. Crude oil and NGLs production volume increases were primarily due to high reliability and strong production from the Horizon Phase 2B expansion and a full quarter of production from the Athabasca Oil Sands Project (“AOSP”).
– Canadian Natural generated funds flow from operations of $1,675 million in Q3/17, comparable to Q2/17 and an increase of $654 million over Q3/16 levels.
– The Company has generated significant free cash flow year to date of approximately $1.2 billion after net capital expenditures, including the Company’s Pelican Lake acquisition expenditures, and excluding the AOSP acquisition expenditures.
– The Company’s strong financial performance in the quarter resulted in Q3/17 ending debt being reduced by approximately $350 million from Q2/17 levels. Additionally, liquidity increased by approximately $300 million over the same period, after capital expenditures relating to the Pelican Lake acquisition. Debt to book capitalization decreased to 42% and debt to adjusted EBITDA strengthened to 3.0x.
– For Q3/17, the Company had net earnings of $684 million compared to net earnings of $1,072 million in Q2/17 and a net loss of $326 million in Q3/16. Adjusted net earnings from operations was $229 million in Q3/17, compared to adjusted net earnings of $332 million in Q2/17 and an increase of $584 million from the adjusted net loss of $355 million in Q3/16.
– At the AOSP, high reliability continued in Q3/17, the Company’s first full quarter of operations. Strong quarterly production of approximately 282,700 bbl/d (197,900 bbl/d net to Canadian Natural) of AOSP synthetic crude oil (“SCO”) was realized in Q3/17. A combination of strong production and modest integration gains resulted in operating costs of $24.60/bbl for upgraded products.
— Subsequent to quarter end, Canadian Natural successfully completed planned pit stops at both the Jackpine and Muskeg River mines. The production impacts from the planned pit stops were incorporated in the Company’s quarterly and annual guidance, which remain unchanged.
– At Horizon, Q3/17 production of 156,465 bbl/d of SCO was strong, with high reliability and utilization during the quarter. Q3/17 production decreased from Q2/17 levels by 18%, as Horizon began the planned turnaround activities and the Phase 3 expansion tie-in on September 11, 2017.
— Through safe, steady and reliable operations and a strong focus on continuous improvement, the Company realized average unadjusted operating costs of $25.68/bbl in Q3/17, a strong result given 19 days of planned downtime in the quarter related to the planned major turnaround and tie-in of the Phase 3 expansion. After normalizing for downtime in relation to the planned turnaround, quarterly operating costs reached a record low of $20.24/bbl of SCO in Q3/17.
— During the Company’s planned turnaround, optimization and reliability work on the fractionation tower, vacuum distillate unit (“VDU”) and diluent recovery unit (“DRU”) furnaces was completed on schedule and on budget. Ramp up of the units is currently underway, and progress is going as expected.
— The Horizon Phase 3 expansion was completed subsequent to quarter end, marking the completion of the Company’s transformational transition to a long life low decline asset base.
— Commissioning activities have begun with production ramping up through November and December 2017. Targeted production volumes in December 2017 are expected to be approximately 240,000 bbl/d of SCO. The construction of the Horizon Phase 3 expansion was ahead of schedule and within the cost estimate.
— The Company’s annual 2017 production guidance at Horizon remains unchanged at 170,000 – 184,000 bbl/d, due to the strong production results before the turnaround and targeted production volume ramp up through November and December 2017.
– Thermal in situ operations were strong in Q3/17, with production averaging 122,372 bbl/d, above the midpoint of quarterly guidance, representing 16% and 18% increases from Q2/17 and Q3/16 levels, respectively. Results were strong after the completion of planned turnaround activities in Q2/17 at Primrose and a full quarter of production from the previously announced acquired Peace River assets.
— Kirby South, the Company’s Steam Assisted Gravity Drainage (“SAGD”) project achieved production of 37,157 bbl/d in Q3/17.
— Including energy costs, strong operating costs of $8.94/bbl were achieved in the quarter, a 13% reduction from Q2/17 and in-line with Q3/16 levels. Kirby South’s Steam to Oil Ratio (“SOR”) was 2.7 in Q3/17.
— Primrose production was strong in Q3/17 averaging 80,668 bbl/d. Including energy costs, operating costs of $10.24/bbl were achieved in the quarter.
— The development of the Company’s low pressure steamflood at Primrose East continues as planned. The average production volumes under steamflood were strong in Q3/17 at approximately 43,600 bbl/d, representing an increase of 36% from Q2/17 levels.
– Pelican Lake heavy crude oil production of 47,604 bbl/d in Q3/17 was in-line with Q2/17 and Q3/16 levels, reflecting the low decline nature of this asset. Operations continued to be optimized in the quarter, resulting in record low operating costs of $6.00/bbl in Q3/17, a decrease of 6% from Q2/17 and in-line with Q3/16 levels.
— On September 29, 2017, the Company successfully closed the previously announced Pelican Lake acquisition, adding approximately 19,100 bbl/d of heavy crude oil production. The integration of the assets is proceeding as planned.
– Primary heavy crude oil production averaged 98,564 bbl/d in Q3/17, representing a 10% increase from Q2/17 as a result of the Company’s successful heavy crude oil drilling program and a full quarter of production from the previously announced acquired Cliffdale asset.
– North America light crude oil and NGLs quarterly production averaged 92,676 bbl/d, representing 2% and 3% increases from Q2/17 and Q3/16 levels respectively, as a result of a successful drilling program.
– The Company’s North America natural gas production in Q3/17 averaged 1,593 MMcf/d, in-line with Q2/17 and Q3/16 levels. Operating costs of $1.15/Mcf were achieved in the quarter, a decrease of 2% from Q2/17 levels.
– International quarterly crude oil production volumes were within the Company’s production guidance and averaged 43,608 bbl/d in Q3/17.
– Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit facilities. At September 30, 2017 the Company had $3.9 billion of available liquidity, including cash and cash equivalents, an increase of $300 million from Q2/17.
– Canadian Natural declared a quarterly cash dividend on common shares of C$0.275 per share payable on January 1, 2018.
– Canadian Natural’s 2018 budget is targeted to be released on November 7, 2017, followed by a webcast with more details on the Company’s current and future plans. Details will be available on our website www.cnrl.com.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK sector of the North Sea and Offshore Africa. Canadian Natural’s production is well balanced between 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. This balance provides optionality for capital investments, facilitating improved value for the Company’s shareholders.
Underpinning this asset base is long life low decline production from Horizon mining and upgrading and the AOSP mining and upgrading, thermal in situ oil sands and Pelican Lake heavy crude oil assets. The combination of low decline, low reserve replacement costs, and effective and efficient operations means these assets provide substantial and sustainable cash flow throughout the commodity price cycle.
Augmenting this, Canadian Natural maintains a substantial inventory of low capital exposure projects within its conventional asset base. These projects can be executed quickly and with the right economic conditions, can provide excellent returns and maximize value for shareholders. Supporting these projects is the Company’s undeveloped land base which enables large, repeatable drilling programs; programs that can be optimized over time. Additionally, by owning and operating most of the related infrastructure, Canadian Natural is able to control a major component of its operating cost and minimize production commitments. Low capital exposure projects can typically be easily stopped or started depending upon success, market conditions, or corporate needs.
Canadian Natural’s balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.
Drilling Activity | |||||||
Nine Months Ended Sep 30 | |||||||
2017 | 2016 | ||||||
(number of wells) | Gross | Net | Gross | Net | |||
Crude oil | 395 | 370 | 99 | 93 | |||
Natural gas | 19 | 19 | 6 | 5 | |||
Dry | 4 | 4 | 4 | 4 | |||
Subtotal | 418 | 393 | 109 | 102 | |||
Stratigraphic test / service wells | 238 | 238 | 206 | 206 | |||
Total | 656 | 631 | 315 | 308 | |||
Success rate (excluding stratigraphic test / service wells) | 99 | % | 96 | % |
– The Company’s total crude oil and natural gas drilling program of 393 net wells for the nine months ended September 30, 2017, excluding strat/service wells, was a significant increase of 291 net wells from the same period in 2016. The change in drilling reflects the flexibility of Canadian Natural’s resource development program and the Company’s disciplined capital allocation process.
North America Exploration and Production
Crude oil and NGLs – excluding Thermal In Situ Oil Sands | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
Sep 30 2017 |
Jun 30 2017 |
Sep 30 2016 |
Sep 30 2017 |
Sep 30 2016 |
|||||||
Crude oil and NGLs production (bbl/d) | 238,844 | 227,083 | 240,298 | 232,533 | 242,561 | ||||||
Net wells targeting crude oil | 145 | 57 | 88 | 349 | 95 | ||||||
Net successful wells drilled | 144 | 55 | 84 | 346 | 91 | ||||||
Success rate | 99 | % | 96 | % | 95 | % | 99 | % | 96 | % |
– Quarterly production volumes of North America crude oil and NGLs averaged 238,844 bbl/d in Q3/17, representing a 5% increase from Q2/17 and in-line with Q3/16 levels.
– Pelican Lake heavy crude oil production of 47,604 bbl/d in Q3/17 was in-line with Q2/17 and Q3/16 levels, reflecting the low decline nature of this asset, given little to no drilling in 2015 and 2016. Operations continued to be optimized in the quarter, resulting in record low operating costs of $6.00/bbl in Q3/17, a decrease of 6% and 1% from Q2/17 and Q3/16 levels, respectively.
— On September 29, 2017, the Company successfully closed the previously announced Pelican Lake acquisition, adding approximately 19,100 bbl/d of heavy crude oil production. The integration of the assets is proceeding as planned.
— Drilling activities at Pelican Lake saw 6 net wells drilled in Q3/17. In the first nine months of 2017, drilling activity increased to 17 net wells. Results from the Company’s drilling program have been as expected, with current total production of approximately 1,700 bbl/d from the new drills.
– Primary heavy crude oil production averaged 98,564 bbl/d in Q3/17, representing a 10% increase from Q2/17 as a result of the Company’s successful heavy crude oil drilling program and a full quarter of production from the previously announced acquired Cliffdale asset.
— Drilling continued in primary heavy crude oil in Q3/17 with 136 net wells drilled, an increase of 97 wells from Q2/17. Early results of the Q3/17 heavy crude oil drilling program have been as expected, with the wells ramping up to the targeted 50 bbl/d per well.
– North America light crude oil and NGLs quarterly production averaged 92,676 bbl/d, representing 2% and 3% increases from Q2/17 and Q3/16 levels respectively, as a result of a successful drilling program. Operating costs in the quarter averaged $14.45/bbl.
– The Company’s 2017 North America E&P crude oil and NGLs annual production guidance remains unchanged and is targeted to range from 236,000 bbl/d – 246,000 bbl/d.
Thermal In Situ Oil Sands | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
Sep 30 2017 |
Jun 30 2017 |
Sep 30 2016 |
Sep 30 2017 |
Sep 30 2016 |
|||||||
Bitumen production (bbl/d) | 122,372 | 105,719 | 103,481 | 118,798 | 104,908 | ||||||
Net wells targeting bitumen | 10 | 4 | 1 | 22 | 1 | ||||||
Net successful wells drilled | 10 | 4 | 1 | 22 | 1 | ||||||
Success rate | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
– Thermal in situ operations were strong in Q3/17, with production averaging 122,372 bbl/d, above the midpoint of quarterly guidance, representing 16% and 18% increases from Q2/17 and Q3/16 levels, respectively. Results were strong after the completion of planned turnaround activities in Q2/17 at Primrose and a full quarter of production from the previously announced acquired Peace River assets.
— Kirby South, the Company’s SAGD project achieved production of 37,157 bbl/d in Q3/17.
— Including energy costs, strong operating costs of $8.94/bbl were achieved in the quarter, a 13% reduction from Q2/17 and in-line with Q3/16 levels. Kirby South’s SOR was 2.7 in Q3/17.
— Steam circulation is targeted to begin in Q4/17 for the 8 producer and 3 injection wells that were drilled in Q3/17, with production targeted in Q1/18.
— Primrose production was strong in Q3/17 averaging 80,668 bbl/d. Including energy costs, operating costs of $10.24/bbl were achieved in the quarter.
— The development of the Company’s low pressure steamflood at Primrose East continues as planned. The average production volumes under steamflood were strong in Q3/17 at approximately 43,600 bbl/d, representing an increase of 36% from Q2/17 levels.
— At Kirby North, the project is trending ahead of schedule and cost performance is trending below budget. Civil works at the plant site are nearing completion and the major mechanical work is ramping up with module and equipment setting underway. Project construction manpower is currently at 220 and will be increasing to over 300 in early 2018.
– The Company’s 2017 thermal in situ annual production guidance remains unchanged and is targeted to range between 112,000 bbl/d – 122,000 bbl/d.
Natural Gas | ||||||||||
Three Months Ended | Nine Months Ended | |||||||||
Sep 30 2017 |
Jun 30 2017 |
Sep 30 2016 |
Sep 30 2017 |
Sep 30 2016 |
||||||
Natural gas production (MMcf/d) | 1,593 | 1,603 | 1,567 | 1,602 | 1,637 | |||||
Net wells targeting natural gas | 3 | 5 | – | 20 | 5 | |||||
Net successful wells drilled | 3 | 5 | – | 19 | 5 | |||||
Success rate | 100 | % | 100 | % | – | 95 | % | 100 | % |
– The Company’s North America natural gas production in Q3/17 averaged 1,593 MMcf/d, in-line with Q2/17 and Q3/16 levels. Operating costs of $1.15/Mcf were achieved in the quarter, a decrease of 2% from Q2/17 levels.
— The decrease in natural gas production during the first nine months of 2017 from the previous comparable period was primarily due to shut-in production volumes of approximately 27 MMcf/d related to low natural gas prices and 41 MMcf/d related to the impact of reliability issues at a third party facility. Natural gas production at the third party facility restarted at the end of July, with plant operations reinstated to near full capacity in the latter half of August 2017. In the month of September 2017 the plant operated reliably at 130 MMcf/d.
– The Company’s 2017 total natural gas annual production guidance remains unchanged and is targeted to range from 1,655 MMcf/d – 1,705 MMcf/d.
International Exploration and Production | |||||||||
Three Months Ended | Nine Months Ended | ||||||||
Sep 30 2017 |
Jun 30 2017 |
Sep 30 2016 |
Sep 30 2017 |
Sep 30 2016 |
|||||
Crude oil production (bbl/d) | |||||||||
North Sea | 24,832 | 26,304 | 23,450 | 24,733 | 23,376 | ||||
Offshore Africa | 18,776 | 20,480 | 26,171 | 20,610 | 27,576 | ||||
Natural gas production (MMcf/d) | |||||||||
North Sea | 46 | 37 | 50 | 40 | 36 | ||||
Offshore Africa | 25 | 16 | 28 | 22 | 34 | ||||
Net wells targeting crude oil | – | 1.8 | – | 1.8 | 1.2 | ||||
Net successful wells drilled | – | 1.8 | – | 1.8 | 1.2 | ||||
Success rate | – | 100 | % | – | 100 | % | 100 | % |
– International quarterly crude oil production volumes were within the Company’s production guidance and averaged 43,608 bbl/d in Q3/17.
— In the North Sea, the Company’s continued focus on production enhancements, increased reliability and water flood optimization resulted in average production volumes of 24,832 bbl/d in Q3/17 as expected, a decrease of 6% from Q2/17 levels and a 6% increase from Q3/16 levels.
— North Sea quarterly crude oil operating costs were $35.72/bbl, representing a reduction of 9% from Q3/16 levels.
— Offshore Africa production volumes averaged 18,776 bbl/d in Q3/17 as expected, an 8% decrease from Q2/17 levels, primarily due to normal well declines, as well as down time relating to the successfully completed planned turnaround in Q3/17 at Baobab.
— Production expense related to the Baobab and Espoir fields in Cote d’Ivoire, decreased to $12.51/bbl in Q3/17, a reduction of 28% from Q2/17. After incorporating production from the Olowi field in Gabon, production expense was $29.24/bbl.
– The Company’s 2017 International annual production guidance remains unchanged and is targeted to range from 43,000 bbl/d – 49,000 bbl/d.
North America Oil Sands Mining and Upgrading – Horizon | |||||
Three Months Ended | Nine Months Ended | ||||
Sep 30 2017 |
Jun 30 2017 |
Sep 30 2016 |
Sep 30 2017 |
Sep 30 2016 |
|
Synthetic crude oil production (bbl/d) (1) | 156,465 | 190,837 | 67,586 | 179,799 | 104,865 |
(1) During the Q3/17, no SCO production was consumed internally as diesel (Q2/17 – 438 bbl/d; Q3/16 – 1,464 bbl/d; nine months ended September 30, 2017 – 287 bbl/d; nine months ended September 30, 2016 – 2,083 bbl/d).
– At Horizon, Q3/17 production of 156,465 bbl/d of SCO was strong, with high reliability and utilization during the quarter. Q3/17 production decreased from Q2/17 levels by 18%, as Horizon began the planned turnaround activities and the Phase 3 expansion tie-in on September 11, 2017.
— Through safe, steady and reliable operations and a strong focus on continuous improvement, the Company realized average unadjusted operating costs of $25.68/bbl in Q3/17, a strong result given 19 days of planned downtime in the quarter related to the planned major turnaround and tie-in of the Phase 3 expansion. After normalizing for downtime in relation to the planned turnaround, quarterly operating costs reached a record low of $20.24/bbl of SCO in Q3/17.
— During the Company’s planned turnaround, optimization and reliability work on the fractionation tower, VDU and DRU furnaces was completed on schedule and on budget. Ramp up of the units is currently underway, and progress is going as expected.
— On September 11, 2017, during ramp down at Horizon for the planned turnaround, a fire occurred at an electrical control building on the plant site. Repairs have now been successfully completed, however an extra 7 days of incremental time was needed in addition to the planned 45 day turnaround.
— Overall the turnaround and additional work related to the electrical control building was completed very effectively and efficiently, with overall costs for both the turnaround and work allocated to the electrical building being within the 45 day turnaround budget.
— The Horizon Phase 3 expansion was completed subsequent to quarter end, marking the completion of the Company’s transition to a long life low decline asset base.
— Commissioning activities have begun with production ramping up through November and December 2017. Targeted production volumes in December 2017 are expected to be approximately 240,000 bbl/d of SCO. The construction of the Horizon Phase 3 expansion was ahead of schedule and within the cost estimate.
– Directive 85 (formerly Directive 74) implementation at the Horizon project remains on track and was 72% physically complete as at September 30, 2017. This project includes research into tailings management and investments in technological advancements to advance the cessation of the use of traditional tailings ponds.
– The Company’s annual 2017 production guidance at Horizon remains unchanged at 170,000 – 184,000 bbl/d, due to the strong production results before the turnaround, and strong targeted production volume ramp up in Q4/17.
North America Oil Sands Mining and Upgrading – AOSP | |||||
Three Months Ended | Nine Months Ended | ||||
Sep 30 2017 |
Jun 30 2017 |
Sep 30 2016 |
Sep 30 2017 |
Sep 30 2016 |
|
Synthetic crude oil production (bbl/d) (1) | 197,900 | 66,704 | – | 88,926 | – |
(1) Consists of heavy and light synthetic crude oil products.
– At the AOSP, high reliability continued in Q3/17, the Company’s first full quarter of operations. Strong quarterly production of approximately 282,700 bbl/d (197,900 bbl/d net to Canadian Natural) of AOSP SCO was realized in Q3/17. A combination of strong production and modest integration gains resulted in operating costs of $24.60/bbl of upgraded products.
— In early Q4/17, Canadian Natural successfully completed planned pit stops at both the Jackpine and Muskeg River mines. The production impacts from the planned pit stops were incorporated in the Company’s quarterly and annual guidance.
– The Company’s 2017 AOSP annual production guidance remains unchanged and is targeted to range from 102,000 bbl/d – 116,000 bbl/d of AOSP SCO.
MARKETING | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
Sep 30 2017 |
Jun 30 2017 |
Sep 30 2016 |
Sep 30 2017 |
Sep 30 2016 |
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Crude oil and NGLs pricing | |||||||||||
WTI benchmark price (US$/bbl) (1) | $ | 48.19 | $ | 48.29 | $44.94 | $ | 49.43 | $ | 41.37 | ||
WCS blend differential from WTI (%) (2) | 21% | 23% | 30% | 24% | 33% | ||||||
SCO price (US$/bbl) | $ | 48.83 | $ | 49.83 | $ | 45.63 | $ | 50.03 | $ | 42.27 | |
Condensate benchmark pricing (US$/bbl) | $ | 47.96 | $ | 48.44 | $ | 43.05 | $ | 49.52 | $ | 40.54 | |
Average realized pricing before risk management (C$/bbl) (3) | $ | 46.33 | $ | 47.12 | $ | 39.66 | $ | 46.82 | $ | 34.14 | |
Natural gas pricing | |||||||||||
AECO benchmark price (C$/GJ) | $ | 1.94 | $ | 2.63 | $ | 2.08 | $ | 2.45 | $ | 1.75 | |
Average realized pricing before riskmanagement (C$/Mcf) | $ | 2.29 | $ | 2.97 | $ | 2.44 | $ | 2.83 | $ | 2.06 |
(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.
– WTI averaged US$48.19/bbl in Q3/17, an increase of 7% from US$44.94/bbl in Q3/16, and in-line with Q2/17.
– Crude oil sales contracts for the Company’s North Sea and Offshore Africa segments are typically based on Brent pricing, which is representative of international markets and overall world supply and demand. Brent averaged US$51.76/bbl in Q3/17, an increase of 13% from US$45.76/bbl in Q3/16, and an increase of 3% from $50.24/bbl in Q2/17.
– WTI and Brent pricing continued to reflect volatility in supply and demand factors and geopolitical events.
– The WCS Heavy Differential averaged US$9.94/bbl in Q3/17, a decrease of 26% from US$13.49/bbl in Q3/16, and a decrease of 11% from $11.11/bbl in Q2/17. The WCS Heavy Differential largely reflects US Gulf Coast pricing, adjusted for transportation costs. The narrowing of the differential in Q3/17 compared with Q2/17 primarily reflects seasonality.
– Canadian Natural contributed approximately 196,000 bbl/d of its heavy crude oil stream to the WCS blend in Q3/17. The Company remains the largest contributor to the WCS blend, accounting for 47% of the total blend.
– The SCO price averaged US$48.83/bbl in Q3/17, an increase of 7% from $45.63/bbl in Q3/16, and in-line with Q2/17. The fluctuations in SCO pricing from the comparable periods were primarily due to changes in WTI benchmark pricing.
– AECO natural gas prices averaged $1.94/GJ in Q3/17, a decrease of 7% from $2.08/GJ in Q3/16, and a decrease of 26% from $2.63/GJ in Q2/17. The fluctuations in natural gas prices in Q3/17 compared with the Q3/16 and Q2/17 reflected third party pipeline maintenance, reducing flow capability of natural gas to discretionary storage and export markets.
– 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 and create demand for 79,000 bbl/d of dilbit that will not require export pipelines, 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: https://nwrsturgeonrefinery.com/whats-happening/news/.
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 funds flow generation, credit facilities, US commercial paper program, diverse asset base and related flexible capital expenditure programs 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 record production levels of 1,036,499 BOE/d in Q3/17, with approximately 98% of total production located in G7 countries.
– The Company has generated significant free cash flow year to date of approximately $1.2 billion after net capital expenditures including the Company’s Pelican Lake acquisition expenditures, and excluding AOSP acquisition expenditures.
– Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit facilities. At September 30, 2017 the Company had $3.9 billion of available liquidity, including cash and cash equivalents, an increase of $300 million from Q2/17.
– Balance sheet strength continues to be a focus of the Company with strong financial performance in the quarter resulting in a Q3/17 ending debt reduction of approximately $350 million, while liquidity increased by approximately $300 million.
— Important metrics improved with debt to book capitalization within the Company’s targeted operating range at 42% and debt to adjusted EBITDA strengthening to 3.0x, as at September 30, 2017.
– In addition to its strong funds flow, capital flexibility and access to debt capital markets, Canadian Natural has additional financial levers at its disposal to effectively manage its liquidity. As at September 30, 2017, these financial levers include the Company’s third party equity investments of approximately $888 million.
– At September 30, 2017, 50,000 GJ/d of natural gas volumes were hedged using AECO swaps through to October 31, 2017. Additionally, 67,500 bbl/d of crude oil volumes were hedged through to December 31, 2017 using WTI costless collars with a floor of US$50.00 and ceiling of US$60.10. For full hedging disclosure please see the Company’s website.
– Canadian Natural declared a quarterly cash dividend on common shares of C$0.275 per share payable on January 1, 2018.
OUTLOOK
The Company forecasts annual 2017 production levels to average between 663,000 and 717,000 bbl/d of crude oil and NGLs and between 1,655 and 1,705 MMcf/d of natural gas, before royalties. Q4/17 production guidance before royalties is forecast to average between 736,000 and 772,000 bbl/d of crude oil and NGLs and between 1,700 and 1,750 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.
Canadian Natural’s annual 2017 capital expenditures are targeted to be approximately $4.9 billion.