CALGARY, ALBERTA–(Marketwired – May 4, 2017) – Commenting on the first quarter 2017 results, Steve Laut, President of Canadian Natural (TSX:CNQ)(NYSE:CNQ) stated, “The strength of our well balanced and diverse portfolio, combined with Canadian Natural’s ability to effectively and efficiently execute, delivered a strong first quarter for the Company. Funds flow from operations were strong in the quarter, exceeding capital expenditures by approximately $800 million, and as a direct result, contributed to over $500 million of debt reduction in the quarter, strengthening our balance sheet quickly.
Execution continues at Horizon with strong production following the ramp up of Phase 2B. Expansion volumes drove 9% growth in our crude oil production volumes and 4% growth on an overall BOE basis when compared with the first quarter of 2016, impressive results given natural gas volumes were once again impacted by third party facility reliability issues. Furthermore at Horizon, record low operating costs of just over $22.00/bbl of SCO were achieved, another strong result. The Phase 3 expansion continues to be on schedule and costs are on track. Phase 3 is targeted to add an additional 80,000 bbl/d of SCO in only six months, the next step in our transition to a long-life, low decline asset base.”
Canadian Natural’s Chief Financial Officer, Corey Bieber, continued, “Our financial performance was strong during the first quarter. The Company achieved net earnings of $245 million as production increased by 2% from the fourth quarter of 2016, with benchmark crude oil prices stabilizing in the US$50 region in the quarter. Funds flow from operations for the Company in the quarter was also robust at $1.64 billion. This translates to free cash flow after capital expenditures and dividends requirements of roughly $515 million, further translating to a reduction in absolute debt levels of $500 million. Commensurate with this debt reduction, available liquidity to the Company increased by approximately $500 million to $3.5 billion from the $3.0 billion available at the end of 2016.”
QUARTERLY HIGHLIGHTS
| Three Months Ended | |||||||||||||
| ($ millions, except per common share amounts) | Mar 31 2017 |
Dec 31 2016 |
Mar 31 2016 |
||||||||||
| Net earnings (loss) | $ | 245 | $ | 566 | $ | (105 | ) | ||||||
| Per common share | – basic | $ | 0.22 | $ | 0.51 | $ | (0.10 | ) | |||||
| – diluted | $ | 0.22 | $ | 0.51 | $ | (0.10 | ) | ||||||
| Adjusted net earnings (loss) from operations (1) | $ | 277 | $ | 439 | $ | (543 | ) | ||||||
| Per common share | – basic | $ | 0.25 | $ | 0.40 | $ | (0.50 | ) | |||||
| – diluted | $ | 0.25 | $ | 0.40 | $ | (0.50 | ) | ||||||
| Funds flow from operations (2) | $ | 1,639 | $ | 1,677 | $ | 657 | |||||||
| Per common share | – basic | $ | 1.47 | $ | 1.52 | $ | 0.60 | ||||||
| – diluted | $ | 1.46 | $ | 1.50 | $ | 0.60 | |||||||
| Net capital expenditures | $ | 846 | $ | 411 | $ | 1,040 | |||||||
| Daily production, before royalties | |||||||||||||
| Natural gas (MMcf/d) | 1,673 | 1,646 | 1,786 | ||||||||||
| Crude oil and NGLs (bbl/d) | 598,113 | 585,185 | 546,927 | ||||||||||
| Equivalent production (BOE/d) (3) | 876,907 | 859,577 | 844,531 | ||||||||||
(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) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
– Canadian Natural generated funds flow from operations of $1,639 million in Q1/17, an increase of almost $1.0 billion from $657 million in Q1/16 and comparable with $1,677 million in Q4/16. The increase from Q1/16 primarily reflects higher synthetic crude oil (“SCO”) sales volumes and realized prices from the Company’s North America Oil Sands Mining and Upgrading (“Horizon”), higher North America E&P crude oil and NGL netbacks and higher natural gas netbacks.
— The Company generated significant free cash flow of approximately $800 million in Q1/17 after net capital expenditures. After capital expenditures and quarterly dividend requirements, approximately $515 million of free cash flow was realized in the quarter, which was largely used to reduce the Company’s debt levels.
– For Q1/17, the Company had net earnings of $245 million compared to net earnings of $566 million in Q4/16 and a net loss of $105 million in Q1/16. The adjusted net earnings from operations was $277 million in Q1/17 compared to adjusted net earnings of $439 million in Q4/16 and an adjusted net loss of $543 million in Q1/16.
– Canadian Natural’s corporate crude oil and NGLs production volumes averaged 598,113 bbl/d representing a 9% increase from Q1/16 levels. Crude oil and NGL production volume increases were primarily due to the successful ramp up of the Horizon Phase 2B expansion.
– The Company’s corporate production volumes averaged 876,907 BOE/d in Q1/17, representing a 4% increase from Q1/16 levels, despite 3rd party natural gas facility outages experienced in the quarter.
– At Horizon, Canadian Natural’s world class oil sands mining and upgrading operations, record quarterly production volumes were achieved for the second consecutive quarter. In Q1/17 production reached 192,491 bbl/d of SCO, within the Company’s previously issued guidance, representing increases of 8% and 50% over Q4/16 and Q1/16 levels respectively.
— Through safe, steady and reliable operations and a strong focus on continuous improvement, the Company realized record low quarterly average operating costs of $22.08/bbl of SCO in Q1/17, representing 2% and 17% reductions from Q4/16 and Q1/16 levels respectively.
— During Q1/17, Canadian Natural continued to advance the Horizon Phase 3 expansion toward completion with project capital expenditures of $139 million in the quarter. The next component of the Company’s transition to a long-life, low decline asset base is progressing as planned, reaching 92% physical completion as at March 31, 2017. Targeted project capital in 2017 is $1.05 billion, with start-up of Phase 3 targeted for Q4/17. This phase is targeted to add incremental production capacity of 80,000 bbl/d of SCO, which will result in a further step change towards lower operating costs for Horizon.
— The previously announced debottleneck option at Horizon continues to move forward, with a target to be executed during the Q3/17 turnaround. The scope and impact on production capacity of the debottleneck will be determined once the full engineering evaluation is completed in late Q2/17. The engineering evaluation primarily involves the fractionation tower which includes quantifying all product yields of naphtha, distillate, gas oil, natural gas and coke from the output of the coker unit on an optimized throughput basis. Concurrently, a process review of the flow dynamics to determine pump and vessel capacities throughout the upgrader is ongoing. A decision on final scope, capital requirements and impact on production capacity is scheduled for late Q2/17, as the Company continues to fully define the debottleneck and optimize production capability.
– As previously announced on March 9, 2017 Canadian Natural has entered into agreements, subject to regulatory approvals, to acquire 70% of the Athabasca Oil Sands Project (“AOSP”), including 70% of the Muskeg River Mine, Jackpine Mine, Scotford upgrader, Quest Carbon Capture and Storage as well as additional working interests in other producing and non-producing oil sands leases. Additionally, the Company acquired 100% working interest in the Peace River operations, the Cliffdale heavy oil field and other oil sands leases. The acquisitions do not include any interest in the 100% Shell owned Scotford refinery or chemical plants.
— Pre-closing activities and regulatory processes related to the transaction are proceeding as planned with closing targeted for Q2/17.
– Thermal in situ operations were strong in Q1/17, with production averaging 128,372 bbl/d, representing a 9% increase from Q1/16 levels and within the Company’s previously issued quarterly guidance.
— Kirby South, the Company’s Steam Assisted Gravity Drainage (“SAGD”) project, continues to operate near facility capacity, resulting in production of 37,311 bbl/d in Q1/17, an increase of 8% over Q1/16 levels. Including energy costs, operating costs of $9.12/bbl were achieved in the quarter, representing a 13% decrease from Q1/16 levels, supported by a strong Steam to Oil Ratio (“SOR”) of 2.7.
— Primrose production results of 91,061 bbl/d in Q1/17 were strong, up 9% over Q1/16 levels. Including energy costs, operating costs of $12.55/bbl were realized in Q1/17.
— Strong results from the Company’s low pressure steamflood at Primrose continue to be achieved, with March 2017 production under steamflood averaging approximately 31,000 bbl/d.
– Pelican Lake polymer flood production remained relatively constant at 46,617 bbl/d in Q1/17, a decrease of 2% from both Q4/16 and Q1/16 levels due to natural declines and planned downtime to conduct wellbore cleanouts to improve polymer flood conformance. Operations continued to be optimized in the quarter, resulting in industry leading operating costs of $6.37/bbl in Q1/17, a 3% and 8% decrease from Q4/16 and Q1/16 levels respectively.
– Primary heavy crude oil production averaged 94,803 bbl/d in Q1/17. As a result of the Company’s proactive decision to reduce its primary heavy crude oil drilling program in 2015 and the first half of 2016, production volumes have declined 2% from Q4/16 levels. Canadian Natural is the industry leading primary heavy crude oil producer and continues to focus on operations optimization, realizing quarterly operating costs of $14.55/bbl in Q1/17, comparable to Q4/16 levels.
– North America light crude oil and NGL quarterly production averaged 90,171 bbl/d, a 3% increase from Q4/16 and comparable to Q1/16 levels. Strong quarterly operating costs of $13.72/bbl were realized in Q1/17, a 3% decrease from Q4/16 levels.
– Within the Company’s North America natural gas assets, operations continued to be optimized during the quarter. Q1/17 production was 1,613 MMcf/d with operating costs of $1.20/Mcf. Production was lower than expected in the quarter due to the unexpected 3rd party natural gas facility outages, which negatively impacted production by approximately 70 MMcf/d in the quarter.
— Operating costs in Canadian Natural’s key natural gas areas in the Deep Basin and Montney continued to be top tier at $0.42/Mcfe and $0.25/Mcfe respectively in Q1/17.
– Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit facilities. As at March 31, 2017, the Company had in place bank credit facilities of $7.4 billion, of which $3.5 billion was available, an increase of approximately $500 million from December 31, 2016 availability.
– Balance sheet strength continues to be a focus of the Company, with debt to book capitalization of 38% at March 31, 2017, within the Company’s targeted operating range.
– Canadian Natural declared a quarterly cash dividend on common shares of C$0.275 per share payable on July 1, 2017.
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 Oil Sands 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
| Three Months Ended Mar 31 | |||||||
| 2017 | 2016 | ||||||
| (number of wells) | Gross | Net | Gross | Net | |||
| Crude oil | 164 | 155 | 11 | 8 | |||
| Natural gas | 11 | 11 | 5 | 4 | |||
| Dry | 1 | 1 | – | – | |||
| Subtotal | 176 | 167 | 16 | 12 | |||
| Stratigraphic test / service wells | 226 | 226 | 199 | 199 | |||
| Total | 402 | 393 | 215 | 211 | |||
| Success rate (excluding stratigraphic test / service wells) | – | 99 | % | – | 100 | % | |
– The Company’s total Q1/17 North America E&P crude oil and natural gas drilling program of 167 net wells, excluding strat/service wells, was a significant increase from the 12 net wells drilled in Q1/16. 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 and Horizon Oil Sands | |||||||
| Three Months Ended | |||||||
| Mar 31 2017 |
Dec 31 2016 |
Mar 31 2016 |
|||||
| Crude oil and NGLs production (bbl/d) | 231,591 | 232,019 | 251,943 | ||||
| Net wells targeting crude oil | 147 | 75 | 7 | ||||
| Net successful wells drilled | 147 | 72 | 7 | ||||
| Success rate | 100 | % | 96 | % | 100 | % | |
– Quarterly production volumes of North America crude oil and NGLs averaged 231,591 bbl/d in Q1/17, within quarterly corporate guidance and comparable to Q4/16 levels. Q1/17 production volumes represent a decrease of 8% from Q1/16 levels as a result of limited drilling activity in 2016.
– Pelican Lake polymer flood production remained relatively constant at 46,617 bbl/d in Q1/17, a decrease of 2% from both Q4/16 and Q1/16 levels due to natural declines and planned downtime to conduct wellbore cleanouts to improve polymer flood conformance. Operations continued to be optimized in the quarter, resulting in industry leading operating costs of $6.37/bbl in Q1/17, a 3% and 8% decrease from Q4/16 and Q1/16 levels respectively.
— Late in Q1/17 the Company successfully drilled 2 net wells at Pelican Lake, with first production coming on stream in early Q2/17. Initial production rates are strong, averaging 270 bbl/d per well.
– Primary heavy crude oil production averaged 94,803 bbl/d in Q1/17. As a result of the Company’s proactive decision to reduce its primary heavy crude oil drilling program in 2015 and the first half of 2016, production volumes have declined 2% from Q4/16 levels. Canadian Natural is the industry leading primary heavy crude oil producer and continues to focus on operations optimization, realizing quarterly operating costs of $14.55/bbl in Q1/17, comparable to Q4/16 levels.
— In Q1/17 the Company successfully drilled 122 net primary heavy crude oil wells with strong initial production and targeted rates averaging 65 bbl/d per well.
– North America light crude oil and NGL quarterly production averaged 90,171 bbl/d, a 3% increase from Q4/16 and comparable to Q1/16 levels. Strong quarterly operating costs of $13.72/bbl were realized in Q1/17, a 3% decrease from Q4/16 levels.
— In Q1/17 the Company successfully drilled 23 net light crude oil wells.
— Highlights of the drilling program were 9 net wells in Manitoba and SE Saskatchewan, successfully completed with strong initial production results of approximately 110 bbl/d per well, above targeted rates.
— Additionally, 7 net wells were successfully drilled in Southern Alberta with initial production rates of approximately 125 bbl/d per well, positive results.
– The Company’s 2017 North America E&P crude oil and NGL annual production guidance remains unchanged and is targeted to range from 232,000 bbl/d – 242,000 bbl/d.
| Thermal In Situ Oil Sands | ||||||
| Three Months Ended | ||||||
| Mar 31 2017 |
Dec 31 2016 |
Mar 31 2016 |
||||
| Bitumen production (bbl/d) | 128,372 | 129,329 | 118,044 | |||
| Net wells targeting bitumen | 8 | 8 | – | |||
| Net successful wells drilled | 8 | 8 | – | |||
| Success rate | 100 | % | 100 | % | – | |
– Thermal in situ operations were strong in Q1/17, with production averaging 128,372 bbl/d, representing a 9% increase from Q1/16 levels and within the Company’s previously issued quarterly guidance.
– Primrose production results of 91,061 bbl/d in Q1/17 were strong, up 9% over Q1/16 levels. Including energy costs, operating costs of $12.55/bbl were realized in Q1/17.
— Strong results from the Company’s low pressure steamflood at Primrose continue to be achieved, with March 2017 production under steamflood averaging approximately 31,000 bbl/d.
– Kirby South continues to operate near facility capacity, resulting in production of 37,311 bbl/d in Q1/17, an increase of 8% over Q1/16 levels. Including energy costs, operating costs of $9.12/bbl were achieved in the quarter, representing a 13% decrease from Q1/16 levels, supported by a strong SOR of 2.7.
– Planned turnarounds are being completed at both Primrose and Kirby South plants in Q2/17. Primrose is targeted to be restricted for 35 days relating to the processing facilities and an additional 26 days relating to the steam generation plants. Kirby South is targeted to be down for 21 days. All production volume impacts are reflected in the Company’s quarterly and annual guidance.
– In Q1/17 the Company successfully targeted and drilled 8 net thermal in situ SAGD wells, which are targeted to come on production late in Q2/17.
– The Company’s 2017 thermal in situ annual production guidance remains unchanged and is targeted to range from 105,000 bbl/d – 115,000 bbl/d.
| Natural Gas | |||||||
| Three Months Ended | |||||||
| Mar 31 2017 |
Dec 31 2016 |
Mar 31 2016 |
|||||
| Natural gas production (MMcf/d) | 1,613 | 1,578 | 1,722 | ||||
| Net wells targeting natural gas | 12 | 4 | 4 | ||||
| Net successful wells drilled | 11 | 4 | 4 | ||||
| Success rate | 92 | % | 100 | % | 100 | % | |
– North America natural gas volumes averaged 1,613 MMcf/d in Q1/17, a decrease of 6% from Q1/16 levels and an increase of 2% from Q4/16 levels. Production was lower than expected due to the unexpected 3rd party natural gas facility outages, which negatively impacted production by approximately 70 MMcf/d in the quarter. The 3rd party is targeting to reinstate the plant to full capability in June 2017.
— The Company’s North America natural gas operations achieved operating costs of $1.20/Mcf in Q1/17.
— Operating costs in Canadian Natural’s key natural gas areas in the Deep Basin and Montney continued to be top tier at $0.42/Mcfe and $0.25/Mcfe respectively in Q1/17.
— In Q1/17 the Company successfully drilled 11 net natural gas wells.
— At Septimus, the Company’s liquids rich Montney play, 4 net natural gas wells were successfully drilled and brought on production keeping the plant at full capacity (approximately 150 MMcf/d and 7,700 bbl/d of liquids). Production results for the new wells were strong, with per well natural gas and NGL volumes currently averaging approximately 9 MMcf/d and 450 bbl/d, respectively.
— In the Deep Basin, 2 net wells were successfully drilled in the Bilbo area and are providing strong results. Current per well natural gas and NGL production is averaging approximately 14 MMcf/d and 500 bbl/d, respectively.
— Additionally, performance has been positive at the Company’s liquid rich Montney play at Gold Creek where 2 net wells were successfully drilled. Current per well NGL and natural gas production is averaging approximately 850 bbl/d and 4 MMcf/d, respectively.
– The Company’s 2017 total natural gas annual production guidance remains unchanged and is targeted to range from 1,700 MMcf/d – 1,760 MMcf/d.
International Exploration and Production
| Three Months Ended | ||||||
| Mar 31 2017 |
Dec 31 2016 |
Mar 31 2016 |
||||
| Crude oil production (bbl/d) | ||||||
| North Sea | 23,042 | 24,085 | 23,317 | |||
| Offshore Africa | 22,616 | 21,689 | 25,714 | |||
| Natural gas production (MMcf/d) | ||||||
| North Sea | 37 | 44 | 29 | |||
| Offshore Africa | 23 | 24 | 35 | |||
| Net wells targeting crude oil | – | 0.9 | 1.2 | |||
| Net successful wells drilled | – | 0.9 | 1.2 | |||
| Success rate | – | 100 | % | 100 | % | |
– International E&P quarterly crude oil production volumes were within the Company’s production guidance and averaged 45,658 bbl/d in Q1/17.
— In the North Sea, the Company’s continued focus on production enhancements, increased reliability and water flood optimization, resulted in average production volumes of 23,042 bbl/d in Q1/17, a decrease of 1% from Q1/16 and 4% from Q4/16 levels. North Sea quarterly crude oil operating costs decreased to $36.86/bbl, representing reductions of 23% and 12% from Q1/16 and Q4/16 levels respectively.
— The Company’s drilling program in the North Sea in the quarter consisted 1 gross injector well, 0.9 on a net basis. Additionally, subsequent to quarter end, 1 gross production well, 0.9 net, was successfully completed. Current net production from the drilling program, consisting of 1.7 net production wells is strong, averaging approximately 3,500 bbl/d.
— The Company is targeting to begin the decommissioning and abandonment of the Ninian North platform in June 2017.
— Offshore Africa production volumes averaged 22,616 bbl/d in Q1/17, a 4% increase over Q4/16 levels. Crude oil operating costs of $18.54/bbl were realized in Q1/17, representing a 3% reduction from Q4/16 levels.
— Cote d’Ivoire (“CDI”) crude oil production expense in Q1/17 averaged $9.10/bbl. CDI production expense for Q1/17 was below the Company’s previously issued annual guidance of $10.50/bbl to $12.50/bbl which anticipated cessation of production from Gabon.
– The Company’s 2017 International E&P 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 | |||
| Mar 31 2017 |
Dec 31 2016 |
Mar 31 2016 |
|
| Synthetic crude oil production (bbl/d) (1) | 192,491 | 178,063 | 127,909 |
(1) The Company produces diesel for internal use at Horizon. First quarter 2017 SCO production before royalties excludes 428 bbl/d of SCO consumed internally as diesel (fourth quarter 2016 – 1,619 bbl/d; first quarter 2016 – 2,562 bbl/d).
– At Horizon, Canadian Natural’s world class oil sands mining and upgrading operations, record quarterly production volumes were achieved for the second consecutive quarter. In Q1/17 production reached 192,491 bbl/d of SCO, within the Company’s previously issued guidance, representing increases of 8% and 50% over Q4/16 and Q1/16 levels respectively.
— Through safe, steady and reliable operations and a strong focus on continuous improvement, the Company realized record low quarterly average operating costs of $22.08/bbl of SCO in Q1/17, representing 2% and 17% reductions from Q4/16 and Q1/16 levels respectively.
— January and February 2017 were strong production months reaching approximately 195,000 bbl/d and 202,600 bbl/d of SCO respectively, as the Company worked to optimize the Horizon Phase 2B expansion. In March 2017 the Company performed unplanned maintenance on the Phase 1 diluent recovery unit and the repairs were completed in 9 days, as a result March 2017 production averaged approximately 180,500 bbl/d of SCO, strong results given the downtime.
— Subsequent to quarter end, the previously announced planned maintenance activities on the Phase 2B diluent recovery systems began in April 2017 restricting production for 19 days in the month. As a result, April 2017 average production was approximately 165,000 bbl/d of SCO with full production capacity reinstated late in the month with current production rates of approximately 205,000 bbl/d of SCO.
— During Q1/17, Canadian Natural continued to advance the Horizon Phase 3 expansion toward completion with project capital expenditures of $139 million in the quarter. The next component of the Company’s transition to a long-life, low decline asset base is progressing as planned, reaching 92% physical completion as at March 31, 2017. Targeted project capital in 2017 is $1.05 billion, with start-up of Phase 3 targeted for Q4/17. This phase is targeted to add incremental production capacity of 80,000 bbl/d of SCO, which will result in a further step change towards lower operating costs at this world class asset.
— The previously announced debottleneck option at Horizon continues to move forward, with a target to be executed during the Q3/17 turnaround. The scope and impact on production capacity of the debottleneck will be determined once the full engineering evaluation is completed in late Q2/17. The engineering evaluation primarily involves the fractionation tower which includes quantifying all product yields of naphtha, distillate, gas oil, natural gas and coke from the output of the coker unit on an optimized throughput basis. Concurrently, a process review of the flow dynamics to determine pump and vessel capacities throughout the upgrader is ongoing. A decision on final scope, capital requirements and impact on production capacity is scheduled for late Q2/17, as the Company continues to fully define the debottleneck and optimize production capability.
– Directive 85 (formerly Directive 74) of the Horizon expansion remains on track and was 69% physically complete as at March 31, 2017. This project includes research into tailings management and investments in technological advancements to advance the cessation of the use of traditional tailings ponds.
– The Company’s 2017 Horizon annual production guidance remains unchanged and is targeted to range from 170,000 bbl/d – 184,000 bbl/d of SCO.
MARKETING
| Three Months Ended | |||||||||
| Mar 31 2017 |
Dec 31 2016 |
Mar 31 2016 |
|||||||
| Crude oil and NGL pricing | |||||||||
| WTI benchmark price (US$/bbl) (1) | $ | 51.86 | $ | 49.33 | $ | 33.51 | |||
| WCS blend differential from WTI (%) (2) | 28% | 30 | % | 42 | % | ||||
| SCO price (US$/bbl) | $ | 51.45 | $ | 48.91 | $ | 33.77 | |||
| Condensate benchmark pricing (US$/bbl) | $ | 52.21 | $ | 48.37 | $ | 34.45 | |||
| Average realized pricing before risk management(C$/bbl) (3) | $ | 47.05 | $ | 45.00 | $ | 23.31 | |||
| Natural gas pricing | |||||||||
| AECO benchmark price (C$/GJ) | $ | 2.79 | $ | 2.67 | $ | 2.00 | |||
| Average realized pricing before riskmanagement (C$/Mcf) | $ | 3.25 | $ | 3.14 | $ | 2.23 | |||
(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$51.86/bbl for Q1/17, an increase of 55% from US$33.51/bbl in Q1/16, and an increase of 5% from $49.33/bbl in Q4/16.
– 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$54.05/bbl for Q1/17, an increase of 59% from US$33.92/bbl in Q1/16, and an increase of 8% from $50.27/bbl in Q4/16.
– WTI and Brent pricing for Q1/17 continued to reflect volatility in supply and demand factors and geopolitical events. The OPEC decision in November 2016 to implement a production cut effective January 1, 2017 followed by additional production cuts by certain non-OPEC countries contributed to an increase in first quarter pricing from comparable quarters.
– The WCS Heavy Differential averaged $14.58/bbl in Q1/17, consistent with comparable periods. The WCS Heavy Differential reflects US Gulf Coast pricing, adjusted for transportation costs.
– Canadian Natural contributed approximately 194,000 bbl/d of its heavy crude oil stream to the WCS blend in Q1/17. The Company remains the largest contributor to the WCS blend, accounting for 44% of the total blend.
– The SCO price averaged US$51.45/bbl in Q1/17, an increase of 52% from $33.77/bbl in Q1/16, and an increase of 5% from US$48.91/bbl in Q4/16. The fluctuations in SCO pricing in Q1/17 from the comparable periods were primarily due to changes in WTI benchmark pricing.
– AECO natural gas prices averaged $2.79/GJ in Q1/17, an increase of 40% from $2.00/GJ in Q1/16, and an increase of 4% from $2.67/GJ in Q4/16. The increase in natural gas prices in Q1/17 compared with Q1/16 and Q4/16 reflected the rebalancing of natural gas storage inventory to historically normal levels, primarily due to reduced drilling activity in 2016 resulting in lower US natural gas production. Additionally, pricing during Q1/17 reflected colder weather in the 2016/2017 winter season as compared with the previous year.
– 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: 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 cash 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 production of 876,907 BOE/d in Q1/17, with approximately 97% of total production located in G7 countries.
– The Company generated significant free cash flow of approximately $800 million in Q1/17 after net capital expenditures. After capital expenditures and quarterly dividend requirements, approximately $515 million of free cash flow was realized in the quarter, which was largely used to reduce the Company’s debt levels.
– Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit facilities. As at March 31, 2017, the Company had in place bank credit facilities of $7.4 billion, of which $3.5 billion was available, an increase of approximately $500 million from December 31, 2016 availability.
– Balance sheet strength continues to be a focus of the Company, with debt to book capitalization of 38% at March 31, 2017, within the Company’s targeted operating range.
– In addition to its strong cash flow and access to debt capital markets, Canadian Natural has additional financial levers at its disposal to effectively manage its liquidity. As at March 31, 2017, these financial levers include the Company’s third party investments of approximately $815 million.
– At March 31, 2017, 50,000 GJ/d of natural gas volumes were hedged using AECO swaps for April 2017 to October 2017. Additionally, 67,000 bbl/d of crude oil volumes were hedged for April 2017 through December 2017 using WTI costless collars with a floor of US$50. 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 July 1, 2017.
OUTLOOK
The Company’s outlook and guidance excludes production volumes and capital associated with the AOSP acquisition announced on March 9, 2017. The transaction is targeted to close in Q2/17.
The Company forecasts annual 2017 production levels to average between 550,000 and 590,000 bbl/d of crude oil and NGLs and between 1,700 and 1,760 MMcf/d of natural gas, before royalties. Q2/17 production guidance before royalties is forecast to average between 544,000 and 570,000 bbl/d of crude oil and NGLs and between 1,675 and 1,730 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 $3.9 billion.
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the “Company”) in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”, “should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule”, “proposed” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, operating costs, capital expenditures, income tax expenses and other guidance provided, constitute forward-looking statements. Disclosure regarding the anticipated closing of the proposed acquisitions of interests in the Athabasca Oil Sands Project, as well as additional working interests in certain other producing and non-producing oil and gas properties, described herein as the “proposed acquisitions of interests in the Athabasca Oil Sands Project” and plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands operations and future expansions, Primrose thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the construction and future operations of the North West Redwater bitumen upgrader and refinery, and construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas or synthetic crude oil (“SCO”) that the Company may be reliant upon to transport its products to market also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts, and is reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.
In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and natural gas liquids (“NGLs”) reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company’s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company’s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company’s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company’s and its subsidiaries’ ability to secure adequate transportation for its products; unexpected disruptions or delays in the resumption of the mining, extracting or upgrading of the Company’s bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company’s bitumen products; availability and cost of financing; the Company’s and its subsidiaries’ success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the adequacy of the Company’s provision for taxes; and other circumstances affecting revenues and expenses.
The Company’s operations have been, and in the future may be, affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or Management’s estimates or opinions change.
Special Note Regarding Currency, Production and Non-GAPP Financial Measures
This release should be read in conjunction with the Management’s Discussion and Analysis (“MD&A”) and the unaudited interim Consolidated Financial Statements for the three months ended March 31, 2017, December 31, 2016 and for the three months ended March 31, 2016.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company’s unaudited interim consolidated financial statements for the period ended March 31, 2017 and MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. This release includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings (loss) from operations, funds flow from operations (previously referred to as cash flow from operations), and adjusted cash production costs. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings (loss) and cash flows from operating activities, as determined in accordance with IFRS, as an indication of the Company’s performance. The non-GAAP measures adjusted net earnings (loss) from operations and funds flow from operations are reconciled to net earnings (loss), as determined in accordance with IFRS, in the “Financial Highlights” section of the Company’s MD&A. The non-GAAP measure funds flow from operations is also reconciled to cash flows from operating activities. The derivation of adjusted cash production costs and adjusted depreciation, depletion and amortization are included in the “Operating Highlights – Oil Sands Mining and Upgrading” section of the Company’s MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the “Liquidity and Capital Resources” section of the Company’s MD&A.
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. In addition, for the purposes of this MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO.
Production volumes and per unit statistics are presented throughout this release on a “before royalty” or “gross” basis, and realized prices are net of blending costs and exclude the effect of risk management activities. Production on an “after royalty” or “net” basis is also presented for information purposes only int the Company’s MD&A.
CONFERENCE CALL
A conference call will be held at 8:00 a.m. Mountain Time, 10:00 a.m. Eastern Time on Thursday, May 4, 2017.
The North American conference call number is 1-866-521-4909 and the outside North American conference call number is 001-647-427-2311. Please call in 10 minutes prior to the call starting time.
An archive of the broadcast will be available until 6:00 p.m. Mountain Time, Thursday, May 18, 2017. To access the rebroadcast in North America, dial 1-800-585-8367. Those outside of North America, dial 001-416-621-4642. The conference archive ID number is 10699011.
The conference call will also be Webcast live on the internet and may be accessed on the home page our website at www.cnrl.com.
2100, 855 – 2nd Street S.W.
Calgary, Alberta, T2P 4J8 Canada
T 403-517-7777
Email: ir@cnrl.com
www.cnrl.com
Steve W. Laut
President
Corey B. Bieber
Chief Financial Officer and Senior Vice-President, Finance
Mark A. Stainthorpe
Director, Treasury and Investor Relations