CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES
2018 FIRST QUARTER RESULTS
CALGARY, ALBERTA – MAY 3, 2018 – FOR IMMEDIATE RELEASE
Commenting on first quarter 2018 results, Steve Laut, Executive Vice-Chairman of Canadian Natural stated, "The strength of our well balanced and diverse portfolio, combined with our long life low decline asset base, delivered a strong first quarter for Canadian Natural. Our balanced production mix is a key component of our strategy to create shareholder value throughout the commodity price cycle. In 2018, the Company remains focused on delivering on its capital allocation program through disciplined economic resource development, strengthening the balance sheet, and increasing returns to shareholders. The Company continues to maximize value while operating with a top tier safety record and an ongoing commitment to reduce its environmental footprint in all aspects of its operations."
Canadian Natural's President, Tim McKay, added, "In the first quarter of 2018, Canadian Natural achieved record quarterly production of 1,123,546 BOE/d, growth of 10% over fourth quarter 2017 levels, primarily as a result of strong production performance at our Oil Sands Mining and Upgrading assets. A full quarter of production from the successful Phase 3 expansion at Horizon and strong operational performance at the Athabasca Oil Sands Project ("AOSP") resulted in record production of approximately 456,000 bbl/d of Synthetic Crude Oil ("SCO"). Our focus on cost control and efficiencies, high utilization rates and safe, reliable operations resulted in record low quarterly operating costs of $21.37/bbl (US$16.89/bbl) of SCO. As a result of our industry leading operations at both Horizon and the AOSP, the Company reduced the midpoint of annual Oil Sands Mining and Upgrading operating cost guidance by $2.00/bbl to $22.50/bbl of SCO. Canadian Natural continues to focus on effective and efficient operations, continuous improvement and leveraging technology, while maintaining its capital discipline, as a result the 2018 capital expenditure program remains unchanged."
Canadian Natural's Chief Financial Officer, Corey Bieber, continued, "The Company had a solid first quarter, achieving funds flow from operations of $2,323 million and net earnings of $583 million demonstrating the value of our diverse asset base as we remain on track to deliver strong financial results in 2018. As a result, free cash flow was significant at approximately $1,220 million before dividends and approximately $880 million after dividend commitments.
Our continued focus on balance sheet strength has resulted in the decrease of long term net debt and the retirement of the deferred AOSP acquisition liability, a total reduction of approximately $1.9 billion since Q2/17. Debt to adjusted EBITDA strengthened to 2.5x at quarter end and debt to book capitalization improved to 40.5%, within our targeted range.
As previously announced, the Company increased its quarterly dividend by 22% to $0.335 per common share and renewed and increased its Normal Course Issuer Bid ("NCIB") program. Subsequent to quarter end, Canadian Natural initiated share purchases as part of its NCIB program, evidence of our commitment to deliver returns to our shareholders. The Company will look to continue share purchases throughout the year on an opportunistic basis, if it makes economic sense to do so.”
QUARTERLY HIGHLIGHTS
| Three Months Ended | |||||||||||||
| ($ millions, except per common share amounts) | Mar 31 2018 | Dec 31 2017 | Mar 31 2017 | ||||||||||
| Net earnings | $ | 583 | $ | 396 | $ | 245 | |||||||
| Per common share | – basic | $ | 0.48 | $ | 0.32 | $ | 0.22 | ||||||
| – diluted | $ | 0.47 | $ | 0.32 | $ | 0.22 | |||||||
Adjusted net earnings from operations (1) | $ | 885 | $ | 565 | $ | 277 | |||||||
| Per common share | – basic | $ | 0.72 | $ | 0.46 | $ | 0.25 | ||||||
| – diluted | $ | 0.71 | $ | 0.46 | $ | 0.25 | |||||||
Funds flow from operations (2) | $ | 2,323 | $ | 2,307 | $ | 1,639 | |||||||
| Per common share | – basic | $ | 1.90 | $ | 1.89 | $ | 1.47 | ||||||
| – diluted | $ | 1.89 | $ | 1.88 | $ | 1.46 | |||||||
Total net capital expenditures (3) | $ | 1,103 | $ | 1,143 | $ | 846 | |||||||
| Daily production, before royalties | |||||||||||||
| Natural gas (MMcf/d) | 1,614 | 1,656 | 1,673 | ||||||||||
| Crude oil and NGLs (bbl/d) | 854,558 | 744,100 | 598,113 | ||||||||||
Equivalent production (BOE/d) (4) | 1,123,546 | 1,020,094 | 876,907 | ||||||||||
| (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) | Funds 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. |
| ▪ | Net earnings of $583 million were realized in Q1/18, an increase of 47% over Q4/17 levels, and adjusted net earnings of $885 million were achieved, a 57% increase from Q4/17 levels. |
| ▪ | Canadian Natural generated significant funds flow from operations of $2,323 million in Q1/18, comparable to $2,307 million in Q4/17 and an increase of $684 million over $1,639 million in Q1/17. The increase over Q1/17 primarily reflects higher Synthetic Crude Oil ("SCO") sales volumes and realized prices from the Company's North America Oil Sands Mining and Upgrading segment. |
| ▪ | The Company achieved record production volumes in Q1/18 averaging 1,123,546 BOE/d, above the midpoint of previously issued Q1/18 guidance, representing 10% and 28% increases from Q4/17 and Q1/17 levels, respectively. |
| ▪ | In Q1/18, Canadian Natural delivered free cash flow of approximately $1,220 million and approximately $880 million after dividend commitments. The Company maintained a balance on allocation of its funds flow from operations: |
| • | The Company remained disciplined in economic resource development with Q1/18 capital expenditures of $1,103 million. |
| • | Balance sheet strength continues to be a focus as the Company decreased long term net debt and retired the deferred Athabasca Oil Sands Project ("AOSP") acquisition liability totaling a reduction of approximately $965 million from Q4/17 levels, resulting in debt to adjusted EBITDA strengthening to 2.5x and debt to book capitalization improving to 40.5%. |
| • | Canadian Natural maintains strong financial stability and liquidity represented by cash balances and committed bank credit facilities. At March 31, 2018 the Company had approximately $4.0 billion of available liquidity, including cash and cash equivalents. |
| Canadian Natural Resources Limited | 2 | Three months ended March 31, 2018 |
| • | Returns to shareholders remain a key focus for Canadian Natural and as previously announced on March 1, 2018, the Company increased its quarterly dividend by 22% to $0.335 per common share. |
| • | Subsequent to quarter end, the Company initiated share buybacks and purchased 700,000 common shares for cancellation at a weighted average price of $41.95 per common share. |
| ▪ | Canadian Natural’s corporate crude oil and NGL production volumes averaged 854,558 bbl/d, increases of 15% and 43% from Q4/17 and Q1/17 levels respectively, primarily as a result of a full quarter of production from the Horizon Phase 3 expansion, as well as high reliability and strong production from acquisitions completed in 2017. |
| ▪ | At the Company's world class Oil Sands Mining and Upgrading assets, operations were strong in Q1/18 with quarterly production reaching a record 456,076 bbl/d of SCO. Through safe, steady and reliable operations, a strong focus on cost control and efficiencies, and high utilization rates, the Company realized industry leading, record low operating costs of $21.37/bbl (US$16.89/bbl) of SCO in Q1/18, a 14% decrease from Q4/17 levels. |
| • | As a result of the Oil Sands Mining and Upgrading segment's strong operational performance and cost savings, the Company reduced annual operating cost guidance by $2.00/bbl of SCO, with annual operating costs now targeted between $20.50/bbl and $24.50/bbl (approximately US$16.25/bbl - US$19.50/bbl). |
| • | At Horizon, following the successful completion of the Phase 3 expansion, the Company is evaluating Horizon Upgrader reliability enhancements and potential creep capacity improvements. |
| ◦ | Stage 1 detailed engineering for reliability improvement which involves pump and piping modification is targeted to be completed by the end of 2018, with most of the activity taking place during the planned 21 day turnaround targeted later this year. |
| �� | Stage 2 design based memorandum activities related to capacity increases within the Upgrader is targeted to add 5,000 bbl/d to15,000 bbl/d of potential creep capacity. |
| • | At Horizon, work continues on the potential Paraffinic Froth Treatment and Vacuum Gas Oil ("VGO") expansions. |
| ◦ | The engineering and design specification work on the potential Paraffinic Froth Treatment expansion at Horizon is underway and has the ability to produce high quality diluted bitumen, targeting to add approximately 30,000 bbl/d to 40,000 bbl/d. |
| ◦ | The proposed VGO expansion at Horizon is in early scoping and is targeted to add approximately 10,000 bbl/d to 15,000 bbl/d. |
| ▪ | At Kirby North, the Company's targeted 40,000 bbl/d Steam Assisted Gravity Drainage ("SAGD") project is targeting first oil in Q1/20. Over the quarter, top tier execution and strong productivity was achieved and as a result, the project is trending ahead of schedule and cost performance is on budget. Currently, over 75% of the Central Processing Facility equipment has been delivered to site and SAGD drilling is nearing 25% completion. |
| ▪ | Canadian Natural continues to focus on safe, reliable, effective and efficient operations while minimizing its environmental footprint. |
| • | Canadian Natural has invested significant capital to capture and sequester CO2. The Company has carbon capture and sequestration facilities at Horizon, a 70% working interest in the Quest Carbon Capture and Storage project at Scotford and has carbon capture facilities at its 50% interest in the North West Redwater ("NWR") refinery. As a result, Canadian Natural targets capacity to capture and sequester 2.7 million tonnes of CO2 annually, equivalent to taking 570,000 vehicles off the road, making the Company the 5th largest capturer and sequester of CO2 globally once the NWR refinery is fully running. |
| • | At Canadian Natural's Oil Sands operations, which represent approximately 66% of the Company's liquids production, the Company's emissions intensity is only approximately 5% higher than the average intensity for all global crude oils. By investing in and leveraging technology, specifically carbon capture initiatives, Canadian Natural has developed a pathway to reduce the Company's greenhouse gas ("GHG") emissions intensity to be below the average for global crude oils. |
| • | Canadian Natural's commitment to leverage technology, adopting innovation and continuous improvement is evidenced by its In Pit Extraction Process ("IPEP") pilot at Horizon, which will test the possibility to produce stackable dry tailings. The project has the potential to reduce the Company's carbon emissions and environmental footprint by reducing the usage of haul trucks, the size and need for tailings ponds and accelerating site reclamation. In addition this has the potential to significantly reduce capital and operating costs. |
| • | The Company's GHG emissions intensity has decreased materially since 2013 as GHG emissions intensity has decreased by 18% from 2013 to 2017. |
| Canadian Natural Resources Limited | 3 | Three months ended March 31, 2018 |
| • | Methane emissions have decreased 71% from 2013 to 2017 from the Company's primary heavy crude oil operations. |
| ▪ | Balance sheet strength continues to be a focus of the Company and strong financial performance was demonstrated in Q1/18 through the retirement of US$ denominated notes and early retirement of certain credit facilities as detailed in the Company's financial statements. |
| • | Since the AOSP acquisition in Q2/17 Canadian Natural has decreased long term net debt and retired the deferred AOSP acquisition liability, totaling a reduction of approximately $1.9 billion. |
| • | In Q1/18, the Company has decreased long term net debt and retired the deferred AOSP acquisition liability, totaling a reduction of approximately $965 million, since Q4/17. |
| ▪ | Subsequent to quarter end, Canadian Natural declared a quarterly cash dividend on common shares of $0.335 per share payable on July 1, 2018. |
| Canadian Natural Resources Limited | 4 | Three months ended March 31, 2018 |
OPERATIONS REVIEW AND CAPITAL ALLOCATION
Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section 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 the Company's Oil Sands Mining and Upgrading, thermal in situ oil sands and Pelican Lake heavy crude oil assets. The combination of low decline, low reserves 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 which 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 be quickly 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 | ||||||||
| 2018 | 2017 | |||||||
| (number of wells) | Gross | Net | Gross | Net | ||||
| Crude oil | 127 | 122 | 164 | 155 | ||||
| Natural gas | 8 | 5 | 11 | 11 | ||||
| Dry | 2 | 2 | 1 | 1 | ||||
| Subtotal | 137 | 129 | 176 | 167 | ||||
| Stratigraphic test / service wells | 528 | 450 | 226 | 226 | ||||
| Total | 665 | 579 | 402 | 393 | ||||
| Success rate (excluding stratigraphic test / service wells) | 98 | % | 99 | % | ||||
| ▪ | The Company's total Q1/18 crude oil and natural gas drilling program was 129 net wells, excluding strat/service wells, a decrease of 38 net wells drilled in Q1/17. The change in drilling reflects Canadian Natural's disciplined capital allocation process and proactive steps to improve execution excellence and control costs by balancing overall drilling levels throughout the year. |
North America Exploration and Production
| Crude oil and NGLs – excluding Thermal In Situ Oil Sands | |||||||
| Three Months Ended | |||||||
| Mar 31 2018 | Dec 31 2017 | Mar 31 2017 | |||||
| Crude oil and NGLs production (bbl/d) | 245,609 | 259,416 | 231,591 | ||||
| Net wells targeting crude oil | 101 | 123 | 147 | ||||
| Net successful wells drilled | 99 | 120 | 147 | ||||
| Success rate | 98 | % | 98 | % | 100 | % | |
| Canadian Natural Resources Limited | 5 | Three months ended March 31, 2018 |
| ▪ | Quarterly production volumes of North America crude oil and NGLs averaged 245,609 bbl/d in Q1/18, within quarterly corporate guidance and a 6% increase from Q1/17 levels. Q1/18 volumes represent a decrease of 5% from Q4/17 levels as a result of reduced drilling activity and delayed completion and ramp up of certain primary heavy crude oil wells drilled in Q1/18. The Company made a proactive decision to temporarily curtail heavy crude oil production in Q1/18 to maximize value as a result of the wider than expected Western Canadian Select ("WCS") differential. While this temporary curtailment in production resulted in slightly higher operating costs, it has created significant value for the Company going forward. |
| ▪ | Pelican Lake quarterly production averaged 63,274 bbl/d, an increase of 36% from Q1/17 and a decrease of 4% from Q4/17 levels. The increase from Q1/17 was as a result of the Company's successful integration of the acquired assets. The decrease from the prior quarter was primarily due to the restoration of polymer flooding on the acquired lands. |
| • | Polymer flood restoration on the acquired lands is proceeding ahead of schedule. To optimize long term oil recovery and effectiveness of the polymer flood, the Company is using modified injection parameters in the near term. As polymer flood conformance improves, the Company expects to increase oil recovery and further maximize value. |
| • | Operating costs of $7.07/bbl were achieved in Q1/18, a 4% increase from Q4/17 levels, reflective of lower production volumes in the quarter as the Company optimizes the polymer flood on acquired lands. |
| • | In the quarter, the Company successfully drilled 7 net producer wells. Subsequent to the quarter, all new wells are currently on production at approximately 110 bbl/d per well, as expected. |
| ▪ | Primary heavy crude oil production decreased to 89,176 bbl/d in Q1/18 as the Company curtailed approximately 7,100 bbl/d due to the wider than expected WCS differential in the quarter. To maximize value, Canadian Natural proactively decided to curtail volumes and delay completions, recompletions and the ramp up of primary heavy crude oil wells in Q1/18. |
| • | Canadian Natural's disciplined capital allocation and proactive steps to improve execution excellence and control costs by balancing drilling levels in our heavy crude oil assets, resulted in 64 net wells drilled in Q1/18 compared to 122 net wells drilled in Q1/17. Completions were delayed on 31 net wells due to the strategic decision to curtail production. |
| • | Operating costs of $17.03/bbl were realized in Q1/18, an increase over Q4/17 levels, primarily due to proactive curtailments in primary heavy crude oil production volumes. |
| ▪ | North America light crude oil and NGL quarterly production averaged 93,159 bbl/d, comparable to Q4/17 levels and a production increase of 3% from Q1/17 levels due to development activity and minor property acquisitions. |
| • | Operating costs of $15.68/bbl were realized in Q1/18 reflecting higher fuel, electricity and service costs in the Company's light crude oil areas. |
| • | The Company successfully drilled 30 net light crude oil wells in Q1/18 with 19 net wells currently on production. The initial production results from the Q1/18 new light crude oil wells are: |
| ◦ | 6 net wells in the Company's Tower light crude oil initial development and related facility construction is proceeding on budget and schedule with targeted production of approximately 3,000 bbl/d in early Q3/18. |
| ◦ | In the Wembley area, 1 net Montney well drilled is currently on production producing approximately 740 bbl/d, as expected. |
| ◦ | In southeast Saskatchewan, 9 net wells drilled are currently on production meeting expectations of approximately 125 bbl/d per well. |
| ◦ | 6 net wells drilled in southern Alberta are currently producing at a rate of approximately 120 bbl/d per well, as expected. |
| ◦ | In northwest Alberta, 3 net wells drilled are currently on production at expected rates of approximately 145 bbl/d per well. |
| ▪ | The Company’s 2018 North America E&P crude oil and NGL annual production guidance remains unchanged and is targeted to range from 253,000 bbl/d - 263,000 bbl/d. |
| Canadian Natural Resources Limited | 6 | Three months ended March 31, 2018 |
| Thermal In Situ Oil Sands | |||||||
| Three Months Ended | |||||||
| Mar 31 2018 | Dec 31 2017 | Mar 31 2017 | |||||
| Bitumen production (bbl/d) | 111,851 | 124,121 | 128,372 | ||||
| Net wells targeting bitumen | 22 | 5 | 8 | ||||
| Net successful wells drilled | 22 | 5 | 8 | ||||
| Success rate | 100 | % | 100 | % | 100 | % | |
| ▪ | Thermal in situ quarterly production volumes averaged 111,851 bbl/d, at the midpoint of Q1/18 guidance, as the Company curtailed approximately 9,700 bbl/d due to the wider than expected WCS differential in the quarter. To maximize value, Canadian Natural proactively decided to curtail volumes and delay ramp up activities of certain Thermal in situ assets in Q1/18. |
| • | At Primrose, Q1/18 production volumes averaged 71,875 bbl/d, a decrease of 15% from Q4/17 levels. Including energy costs, operating costs of $16.61/bbl were realized in Q1/18, reflective of the curtailed production volumes. |
| • | At Kirby South, the Company's SAGD project, Canadian Natural achieved quarterly production volumes of 36,986 bbl/d in Q1/18, a 5% increase from Q4/17 levels. The production increase was particularly strong given the Company proactively delayed steaming, slowed down completions and the ramp up of new wells due to the wider than expected WCS differential. |
| ◦ | Including energy costs, Kirby South achieved strong Q1/18 operating costs of $9.13/bbl, representing a slight decrease from Q4/17 and comparable to Q1/17 levels, supported by a Steam to Oil Ratio of 2.5 in Q1/18. |
| • | Subsequent to quarter end, the Company began maintenance activities at its thermal in situ facilities at Primrose, Peace River and Kirby South. |
| • | At Kirby North, the Company's targeted 40,000 bbl/d SAGD project is targeting first oil in Q1/20. Over the quarter, top tier execution and strong productivity was achieved and as a result, the project is trending ahead of schedule, while cost performance is on budget. Currently, over 75% of the Central Processing Facility equipment has been delivered to site and SAGD drilling is nearing 25% completion. |
| ▪ | The Company’s 2018 thermal in situ annual production guidance remains unchanged and is targeted to range between 107,000 bbl/d - 127,000 bbl/d. |
| North America Natural Gas | |||||||
| Three Months Ended | |||||||
| Mar 31 2018 | Dec 31 2017 | Mar 31 2017 | |||||
| Natural gas production (MMcf/d) | 1,547 | 1,596 | 1,613 | ||||
| Net wells targeting natural gas | 5 | 2 | 12 | ||||
| Net successful wells drilled | 5 | 2 | 11 | ||||
| Success rate | 100 | % | 100 | % | 92 | % | |
| ▪ | North America natural gas production was 1,547 MMcf/d in Q1/18. Production in Q1/18 decreased 3% from Q4/17 and 4% from Q1/17 levels primarily due to the 32 MMcf/d impact of a third party plant operating with only one train. Also during the quarter, Canadian Natural made a proactive decision to shut-in production volumes and minimize capital on natural gas assets. As a result, the Company shut-in approximately 14 MMcf/d of natural gas production and delayed workovers and recompletions due to low natural gas prices. |
| • | Operating costs of $1.31/Mcf were realized in Q1/18, an increase of 4% primarily as a result of lower natural gas volumes due to the Company's proactive decision to shut-in volumes and delayed activity on natural gas assets. |
| • | The Company uses natural gas in its operations represented by approximately 32% of its total equivalent gas production providing a natural hedge from the challenging Western Canadian natural gas price environment. |
| Canadian Natural Resources Limited | 7 | Three months ended March 31, 2018 |
Approximately 29% of the natural gas production is exported to other North American markets or sold internationally, with the remaining 39% of the Company's production being exposed to AECO/Station 2 pricing.
| ▪ | The Company’s 2018 corporate natural gas annual production guidance remains unchanged and is targeted to range from 1,650 MMcf/d - 1,710 MMcf/d. |
International Exploration and Production
| Three Months Ended | |||||||
| Mar 31 2018 | Dec 31 2017 | Mar 31 2017 | |||||
| Crude oil production (bbl/d) | |||||||
| North Sea | 21,584 | 19,548 | 23,042 | ||||
| Offshore Africa | 19,438 | 19,519 | 22,616 | ||||
| Natural gas production (MMcf/d) | |||||||
| North Sea | 37 | 37 | 37 | ||||
| Offshore Africa | 30 | 23 | 23 | ||||
| Net wells targeting crude oil | 1.0 | — | — | ||||
| Net successful wells drilled | 1.0 | — | — | ||||
| Success rate | 100 | % | — | — | |||
| ▪ | International E&P quarterly production volumes were within quarterly production guidance and reached 41,022 bbl/d in Q1/18. |
| • | In the North Sea, volumes of 21,584 bbl/d were achieved in Q1/18, an increase of 10% from Q4/17 levels and a decrease of 6% from Q1/17 levels. The increase from Q4/17 was primarily due to production resuming following the temporary unplanned shut down of the Ninian South Platform as well as the Forties Pipeline System outage in December 2017. The decrease from Q1/17 levels was a result of the impact of the shut-in of the Ninian North platform in May 2017 in preparation for decommissioning and natural field declines, partially offset by new wells at Ninian South and production optimization. |
| • | Additionally, the Company's continued focus on production enhancements, increased reliability and water flood optimization in the North Sea resulted in operating costs decreasing by 2% to $43.39/bbl, from Q4/17 levels. Excluding the impacts of the foreign exchange rate, operating costs in the North Sea decreased by 5% from Q4/17 levels. |
| ◦ | In Q1/18, the Company successfully drilled 1.0 net well in the North Sea with current production of approximately 2,000 bbl/d of light crude oil. |
| • | Offshore Africa production volumes averaged 19,438 bbl/d, comparable to Q4/17 levels and a 14% decrease from Q1/17 levels. The decrease from Q1/17 was a result of natural field declines, partially offset by successful production optimization. |
| ◦ | Côte d'Ivoire crude oil production expense in Q1/18 was strong at $10.14/bbl, a 17% decrease from Q4/17 levels and below previously issued annual Company guidance. |
| ◦ | In 2018, the Company is targeting to drill 1.7 net producing wells and 1.2 net injector wells at Baobab where the rig is currently enroute and scheduled to commence in late Q2/18. The program targets to add average net production of approximately 5,700 bbl/d of light crude oil in Q4/18. |
| ▪ | The Company's 2018 International annual production guidance remains unchanged and is targeted to range from 40,000 bbl/d - 45,000 bbl/d. |
| Canadian Natural Resources Limited | 8 | Three months ended March 31, 2018 |
North America Oil Sands Mining and Upgrading
| Three Months Ended | |||||||
| Mar 31 2018 | Dec 31 2017 | Mar 31 2017 | |||||
Synthetic crude oil production (bbl/d) (1) (2) | 456,076 | 321,496 | 192,491 | ||||
| (1) | Q1/18 SCO production before royalties excludes 3,224 bbl/d of SCO consumed internally as diesel (Q4/17 – 1,730 bbl/d; Q1/17 – 428 bbl/d). |
| (2) | Consists of heavy and light synthetic crude oil products. |
| ▪ | At Canadian Natural's world class Oil Sands Mining and Upgrading assets, record quarterly production volumes of 456,076 bbl/d of SCO were achieved in Q1/18, a 42% increase from Q4/17 levels. The increase was as a result of a full quarter of production from the Horizon Phase 3 expansion and strong production from the acquired AOSP assets. |
| ▪ | Through safe, steady and reliable operations and a strong focus on continuous improvement, the Company realized record low quarterly average operating costs of $21.37/bbl (US$16.89/bbl) of SCO at its Oil Sands Mining and Upgrading operations, a 14% reduction from Q4/17 levels, representing strong performance at both Horizon and the AOSP. |
| ▪ | As a result of the Oil Sands Mining and Upgrading segment's strong operational performance and cost savings, the Company reduced the midpoint of annual operating cost guidance by $2.00/bbl, with annual operating costs now targeted between $20.50/bbl and $24.50/bbl (approximately US$16.25/bbl - US$19.50/bbl). |
| • | Operations at Horizon are progressing as expected following the successful ramp up of the Phase 3 expansion. |
| ◦ | At Horizon, following the completion of the Phase 3 expansion, the Company is evaluating Horizon Upgrader reliability enhancements and potential creep capacity improvements. |
| ▪ | Stage 1 detailed engineering for reliability improvement which involves pump and piping modification is targeted to be completed by the end of 2018, with most of the activity taking place during the planned 21 day turnaround targeted in late Q3/18. |
| ▪ | Stage 2 design based memorandum activities related to capacity increases within the Upgrader is targeted to add 5,000 bbl/d to15,000 bbl/d of potential creep capacity. |
| ◦ | At Horizon, work continues on the potential Paraffinic Froth Treatment and VGO expansions. |
| ▪ | The engineering and design specification work on the potential Paraffinic Froth Treatment expansion at Horizon is underway and has the ability to produce high quality diluted bitumen, targeting to add approximately 30,000 bbl/d to 40,000 bbl/d. |
| ▪ | The proposed VGO expansion at Horizon is in early scoping and is targeted to add approximately 10,000 bbl/d to 15,000 bbl/d. |
| • | The planned pit stop at the Scotford Upgrader is ongoing and aligned with timing of the planned pit stops at both the Jackpine River and Muskeg River mines. |
| • | Commencing April 8th, at Horizon, planned work began on the Vacuum Distillation Unit ("VDU") furnaces to complete maintenance involving decoking of the VDU furnaces. During this maintenance activity, the Company identified additional repairs required to ensure reliability, as a result production will be restricted for an additional 15 days. The upgrader and mining operations continue at reduced rates of approximately 145,000 bbl/d and are targeted to resume full production on May 7th. Notwithstanding this maintenance work, annual Oil Sands Mining and Upgrading production guidance remains unchanged. |
| ▪ | The Company's 2018 Oil Sands Mining and Upgrading annual production guidance is targeted to range from 415,000 bbl/d - 450,000 bbl/d of upgraded products. |
| Canadian Natural Resources Limited | 9 | Three months ended March 31, 2018 |
MARKETING
| Three Months Ended | ||||||||||||
| Mar 31 2018 | Dec 31 2017 | Mar 31 2017 | ||||||||||
| Crude oil and NGLs pricing | ||||||||||||
WTI benchmark price (US$/bbl) (1) | $ | 62.89 | $ | 55.39 | $ | 51.86 | ||||||
WCS heavy differential from WTI (US$/bbl) (2) | 39 | % | 22 | % | 28 | % | ||||||
SCO price (US$/bbl) | $ | 61.45 | $ | 58.64 | $ | 51.45 | ||||||
| Condensate benchmark pricing (US$/bbl) | $ | 63.12 | $ | 57.96 | $ | 52.21 | ||||||
Average realized pricing before risk management (C$/bbl) (3) | $ | 43.06 | $ | 53.42 | $ | 47.05 | ||||||
| Natural gas pricing | ||||||||||||
| AECO benchmark price (C$/GJ) | $ | 1.75 | $ | 1.85 | $ | 2.79 | ||||||
| Average realized pricing before risk management (C$/Mcf) | $ | 2.74 | $ | 2.55 | $ | 3.25 | ||||||
| (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. |
| ▪ | The WCS heavy differential widened in Q1/18 as a result of third party pipeline outages backing up heavy crude oil into Western Canada. This resulted in anomalous heavy crude oil pricing as the pipeline operators and rail transport worked to remove the backlog of inventory. Currently, the WCS heavy differential is narrowing as the backed up inventory is beginning to be moved to market. Canadian Natural expects a more normalized WCS heavy differential going forward. |
| ▪ | AECO natural gas prices for Q1/18 continued to reflect third party pipeline constraints limiting flow of natural gas to export markets, increased natural gas production in the basin and constraints on export capacity out of Western Canada. |
| ▪ | 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. |
| • | The refinery will create demand for approximately 80,000 bbl/d of dilbit that will not require export pipelines, which will help reduce pricing volatility in all Western Canadian heavy crude oil. |
| • | The North West Redwater refinery began processing light crude oil late in November 2017, and continues to progress as expected. |
| • | 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 production levels of 1,123,546 BOE/d in Q1/18, with approximately 98% of total production located in G7 countries. |
| • | Canadian Natural maintains a balance of products with current product mix on a BOE/d basis of 50% light crude oil and SCO blends, 25% heavy crude oil blends and 25% natural gas, based upon the midpoint of annual 2018 production guidance. |
| • | Canadian Natural’s production is resilient as long life low decline assets make up approximately 73% of 2018 liquids production guidance, when including the AOSP, Horizon, Pelican Lake and Thermal in situ oil sands assets. |
| Canadian Natural Resources Limited | 10 | Three months ended March 31, 2018 |
| • | The Company generated significant free cash flow of approximately $1,220 million in Q1/18 after net capital expenditures. Including dividend commitments, approximately $880 million of free cash flow was realized in the quarter, which was largely used to reduce the Company's debt levels. |
| • | Balance sheet strength continues to be a focus of the Company and strong financial performance was demonstrated in Q1/18 through the retirement of US$ denominated notes and early retirement of certain credit facilities as detailed in the Company's financial statements. |
| • | Since the AOSP acquisition in Q2/17 Canadian Natural has decreased long term net debt and retired the deferred AOSP acquisition liability, totaling a reduction of approximately $1.9 billion. |
| • | In Q1/18, the Company decreased long term net debt and retired the deferred AOSP acquisition liability, totaling a reduction of approximately $965 million from Q4/17. |
| • | Canadian Natural maintains financial stability and liquidity represented by cash balances and committed bank credit facilities. At March 31, 2018 the Company had approximately $4.0 billion of available liquidity, including cash and cash equivalents. |
| • | Debt to book capitalization improved to 40.5% from 41.4% in Q4/17 and debt to adjusted EBITDA strengthened to 2.5x, as at March 31, 2018. |
| ▪ | 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 March 31, 2018, these financial levers include the Company’s third party equity investments of approximately $781 million. |
| ▪ | Subsequent to March 31, 2018, under the Company's Normal Course Issuer Bid, Canadian Natural purchased and canceled 700,000 common shares at a weighted average price of $41.95 per common share. |
| ▪ | Subsequent to quarter end, Canadian Natural declared a quarterly cash dividend on common shares of $0.335 per share payable on July 1, 2018. |
OUTLOOK
The Company forecasts annual 2018 production levels to average between 815,000 and 885,000 bbl/d of crude oil and NGLs and between 1,650 and 1,710 MMcf/d of natural gas, before royalties. Q2/18 production guidance before royalties is forecast to average between 773,000 and 821,000 bbl/d of crude oil and NGLs and between 1,515 and 1,565 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 2018 capital expenditures are targeted to be approximately $4.3 billion.
| Canadian Natural Resources Limited | 11 | Three months ended March 31, 2018 |
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, production expenses, capital expenditures, income tax expenses and other guidance provided throughout the Company's Management’s Discussion and Analysis (“MD&A”), constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands operations and future expansions, the Athabasca Oil Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the cost of 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 reserves 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 and assets; production levels; imprecision of reserves 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 expenditures and production expenses); 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 national, federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other
| Canadian Natural Resources Limited | 12 | Three months ended March 31, 2018 |
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
The Company's MD&A of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements for the three months ended March 31, 2018 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2017.
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, 2018 and the Company's MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. The Company's MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings from operations, funds flow from operations, adjusted cash production costs and adjusted depreciation, depletion and amortization. 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 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 from operations and funds flow from operations are reconciled to net earnings, 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 in this section. 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 the Company's 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 the Company's MD&A on a “before royalty” or “gross” basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. Production on an “after royalty” or “net” basis is also presented for information purposes only. Results from operations for the three months ended March 31, 2017 presented in the Company's MD&A exclude the impact of the acquisition of interests in AOSP on May 31, 2017.
Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2017, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov.
| Canadian Natural Resources Limited | 13 | Three months ended March 31, 2018 |
CONFERENCE CALL
A conference call will be held at 8:00 a.m. Mountain Time, 10:00 a.m. Eastern Time on Thursday, May 3, 2018.
The North American conference call number is 1-866-393-4306 and the outside North American conference call number is 001-734-385-2616. 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 17, 2018. To access the rebroadcast in North America, dial 1-855-859-2056. Those outside of North America, dial 001-404-537-3406. The conference archive ID number is 9856698.
The conference call will also be webcast live and may be accessed on the home page of our website at www.cnrl.com.
Canadian Natural is a senior oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.
| CANADIAN NATURAL RESOURCES LIMITED |
2100, 855 - 2nd Street S.W. Calgary, Alberta, T2P4J8 Phone: 403-517-7777 Email: ir@cnrl.com www.cnrl.com |
STEVE W. LAUT Executive Vice-Chairman TIM S. MCKAY President COREY B. BIEBER Chief Financial Officer and Senior Vice-President, Finance MARK A. STAINTHORPE Vice-President, Finance – Capital Markets Trading Symbol - CNQ Toronto Stock Exchange New York Stock Exchange |
| Canadian Natural Resources Limited | 14 | Three months ended March 31, 2018 |