Exhibit Number | Description |
99.1 | Press Release dated November 7, 2019 |
99.2 | |
99.3 |
Canadian Natural Resources Limited (Registrant) | |||
Date: November 7, 2019 | By: | /s/ Paul M. Mendes | |
Paul M. Mendes | |||
VP, Legal, General Counsel & Corporate Secretary | |||
Three Months Ended | Nine Months Ended | |||||||||||||||||||||
($ millions, except per common share amounts) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||||||
Net earnings | $ | 1,027 | $ | 2,831 | $ | 1,802 | $ | 4,819 | $ | 3,367 | ||||||||||||
Per common share | – basic | $ | 0.87 | $ | 2.37 | $ | 1.48 | $ | 4.04 | $ | 2.75 | |||||||||||
– diluted | $ | 0.87 | $ | 2.36 | $ | 1.47 | $ | 4.03 | $ | 2.74 | ||||||||||||
Adjusted net earnings from operations (1) | $ | 1,229 | $ | 1,042 | $ | 1,354 | $ | 3,109 | $ | 3,518 | ||||||||||||
Per common share | – basic | $ | 1.04 | $ | 0.87 | $ | 1.11 | $ | 2.61 | $ | 2.88 | |||||||||||
– diluted | $ | 1.04 | $ | 0.87 | $ | 1.11 | $ | 2.60 | $ | 2.86 | ||||||||||||
Cash flows from operating activities | $ | 2,518 | $ | 2,861 | $ | 3,642 | $ | 6,375 | $ | 8,724 | ||||||||||||
Adjusted funds flow (2) | $ | 2,881 | $ | 2,652 | $ | 2,830 | $ | 7,773 | $ | 7,859 | ||||||||||||
Per common share | – basic | $ | 2.43 | $ | 2.22 | $ | 2.32 | $ | 6.51 | $ | 6.42 | |||||||||||
– diluted | $ | 2.43 | $ | 2.22 | $ | 2.31 | $ | 6.50 | $ | 6.39 | ||||||||||||
Cash flows used in investing activities | $ | 908 | $ | 4,464 | $ | 1,265 | $ | 6,401 | $ | 3,772 | ||||||||||||
Net capital expenditures, excluding Devon Canada asset acquisition costs (3) | $ | 963 | $ | 908 | $ | 1,473 | $ | 2,848 | $ | 3,550 | ||||||||||||
Total net capital expenditures, including Devon Canada asset acquisition costs (3) | $ | 963 | $ | 4,125 | $ | 1,473 | $ | 6,065 | $ | 3,550 | ||||||||||||
Daily production, before royalties | ||||||||||||||||||||||
Natural gas (MMcf/d) | 1,469 | 1,532 | 1,553 | 1,504 | 1,568 | |||||||||||||||||
Crude oil and NGLs (bbl/d) | 931,546 | 770,409 | 801,742 | 829,031 | 816,539 | |||||||||||||||||
Equivalent production (BOE/d) (4) | 1,176,361 | 1,025,800 | 1,060,629 | 1,079,641 | 1,077,953 |
(1) | Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance, as it demonstrates the Company’s ability to generate after-tax operating earnings from its core business areas. The derivation of this measure is discussed in the "Advisory" section of this press release. |
(2) | Adjusted funds flow (previously referred to as funds flow from operations) is a non-GAAP measure that the Company considers key to evaluate its performance as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The derivation of this measure is discussed in the "Advisory" section of this press release. |
(3) | Net capital expenditures is a non-GAAP measure that the Company considers a key measure as it provides an understanding of the Company’s capital spending activities in comparison to the Company's annual capital budget. For additional information and details, refer to the net capital expenditures table in the "Advisory" section of this press release. |
(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 $1,027 million were realized in Q3/19, while adjusted net earnings of $1,229 million were achieved in Q3/19, a $187 million increase from Q2/19 levels. |
▪ | Cash flows from operating activities were $2,518 million in Q3/19, a decrease of $343 million compared to Q2/19 levels. |
▪ | Canadian Natural generated record quarterly adjusted funds flow of $2,881 million in Q3/19, an increase of 9% or $229 million over Q2/19 levels. The increase over Q2/19 was primarily due to higher production volumes from the Company's Thermal in situ, Oil Sands Mining and Upgrading, Primary Heavy and Pelican Lake crude oil segments and strong operating costs which were partially offset by lower light crude oil and heavy crude oil pricing in the quarter. |
▪ | Cash flows used in investing activities were $908 million in Q3/19. |
Canadian Natural Resources Limited | 2 | Nine Months Ended September 30, 2019 |
▪ | Canadian Natural delivered strong quarterly free cash flow of $1,471 million after net capital expenditures of $963 million, and dividend requirements of $447 million in Q3/19, reflecting the strength of our long life low decline asset base and our effective and efficient operations. |
• | Balance sheet strength remains a focus and free cash flow was used to reduce debt levels in Q3/19 as the Company balances its free cash flow according to the defined free cash flow allocation policy. As a result gross long-term debt was reduced in Q3/19 by $1,018 million from Q2/19 levels. |
◦ | The Company utilized adjusted funds flow to repay and cancel $800 million of its $1,800 million non-revolving term loan facility; $1,000 million remained outstanding and fully drawn at quarter end. |
– | Subsequent to quarter end the Company repaid and canceled an additional $500 million of the remaining $1,000 million non-revolving term loan; $500 million remains outstanding and fully drawn as at November 6, 2019. |
• | Canadian Natural is committed to returns to shareholders, returning a total of $616 million to shareholders in Q3/19, $447 million by way of dividends and $169 million by way of share purchases. In the first nine months of 2019, the Company has returned a total of $2,100 million to shareholders, $1,299 million by way of dividends and $801 million by way of share purchases. |
◦ | Share purchases for cancellation in the quarter totaled 5,050,000 common shares at a weighted average share price of $33.45. |
◦ | Subsequent to quarter end, up to and including November 6, 2019, the Company executed on additional share purchases for cancellation of 1,350,000 common shares at a weighted average share price of $33.70. |
◦ | Returns to shareholders have been significant as Canadian Natural has returned approximately $5.4 billion by way of dividends and share purchases between January 1, 2018 and November 6, 2019. |
◦ | Subsequent to quarter end, the Company declared a quarterly dividend of $0.375 per share, payable on January 1, 2020. |
▪ | The Company continues to manage within its curtailment optimization strategy which in addition to strong operational performance, contributed to production levels that are at the top end of guidance guidance. The Company continues to execute operational flexibility through its curtailment optimization strategy as follows: |
• | Mitigating production impacts, from lower production at Horizon due to planned maintenance activities, by increasing Athabasca Oil Sands Project ("AOSP"), conventional crude oil and thermal in situ crude oil production. As a result, strong production was realized at the Company's North America Exploration and Production ("E&P") and thermal in situ oil sands assets in Q3/19. |
• | Modified timing of the Company's planned turnaround activities to achieve its monthly curtailment allowable. |
• | Maximizing value through production optimization of higher netback assets and reducing operating costs. |
▪ | The Company achieved quarterly production volumes of 1,176,361 BOE/d in Q3/19, increases of 15% and 11% over Q2/19 and Q3/18 levels respectively, reflecting production additions from the Devon Canada asset acquisition that closed on June 27, 2019, together with strong operational performance at both Horizon and AOSP. |
• | As a result of accretive acquisitions, effective and efficient operations and execution on the Company's free cash flow allocation policy, annual production per share growth was significant at 14% when compared to Q3/18 levels. |
• | The Company achieved record quarterly liquids production volumes of 931,546 bbl/d in Q3/19, increases of 21% and 16% over Q2/19 and Q3/18 levels respectively and at the top end of previously issued guidance. |
▪ | At the Company's world class Oil Sands Mining and Upgrading assets, production volumes were strong, at the top end of production guidance, averaging 432,203 bbl/d of Synthetic Crude Oil ("SCO") in Q3/19, increases of 15% and 10% over Q2/19 and Q3/18 levels respectively. The increases were primarily as a result of strong operational performance as well as modified timing of the Horizon turnaround schedule as a part of the Company's curtailment optimization strategy. |
• | Effective and efficient operations and high reliability resulted in strong quarterly operating costs of $20.05/bbl (US$15.18/bbl) of SCO in Q3/19, comparable to record low operating costs of $19.97/bbl (US$15.12/bbl) of SCO achieved in Q4/18, impressive results given the planned turnaround activities in the quarter. Q3/19 operating costs represent decreases of 17% and 12% from Q2/19 and Q3/18 levels respectively. |
• | At the Albian mines, top tier operations combined with enhancing and optimization of equipment resulted in record gross bitumen production averaging approximately 318,000 bbl/d in September and October, forming a part of |
Canadian Natural Resources Limited | 3 | Nine Months Ended September 30, 2019 |
• | At Horizon, subsequent to quarter end the Company successfully completed a planned turnaround on schedule and under budget demonstrating strong execution by the Company's teams. |
• | As part of the Company’s proactive inspection at Horizon, the team identified a need to repair piping on one of the hydrogen manufacturing units during post turnaround start-up. As a result, Horizon is currently running at restricted rates of approximately 155,000 bbl/d and is targeted to return to full rates by early December 2019. The Company’s targets to remain within its previous annual production guidance range. |
▪ | Thermal in situ oil sands production volumes exceeded the top end of quarterly production guidance as the Company demonstrated the flexibility and available capacity of its thermal in situ assets by utilizing allowable volumes during the Horizon turnaround of approximately 28,000 bbl/d in September from Jackfish, Kirby North and pad additions at Primrose. Production in Q3/19 averaged 206,395 bbl/d, an 88% increase over Q2/19 levels, primarily reflecting a full quarter of production from the Devon Canada asset acquisition and the successful execution on the Company's curtailment optimization strategy. |
• | Thermal in situ operating costs were strong in Q3/19 at $9.77/bbl, reductions of 17% and 14% from Q2/19 and Q3/18 levels respectively, primarily as a result of synergies captured to date from the Devon Canada acquisition and lower energy costs. |
• | At Kirby North, top tier execution and productivity have resulted in production averaging approximately 6,600 bbl/d in September 2019, exceeding production forecasts. Strong performance results are primarily due to improved well design, high plant reliability and other operational improvements. Production volumes will be managed as part of the Company's curtailment optimization strategy as the Company ramps up towards Kirby North's overall capacity of 40,000 bbl/d targeted in early 2021. |
• | At Primrose, as a result of strong execution the Company's high return pad additions came on ahead of schedule and on budget. Production from the pad additions were strong, beginning on September 16, 2019, utilizing available oil processing and steam capacity with managed production averaging approximately 13,600 bbl/d in September, offsetting production impacts from the planned turnaround at Horizon as part of the Company's curtailment optimization strategy. |
• | At Jackfish, pad additions that have been successfully drilled and not completed to date due to curtailments in Alberta have a production capability of 21,000 bbl/d. These pads require minimal capital of approximately $8 million to complete tie in activities that are targeted for Q4/19. Production from these pads is targeted to offset conventional production declines with long life low decline thermal in situ production, as the Company manages within its curtailment optimization strategy and targets to reach peak production in 2022. |
▪ | The Company continues to execute its plan to achieve its initially identified targeted annual cost savings of at least $135 million for both primary heavy and thermal in situ crude oil assets acquired from Devon Canada. As previously announced, approximately $25 million of these initially identified synergies are being realized more than one year ahead of the initial plan. |
• | Additionally, in the short time since closing Canadian Natural has identified incremental targeted annual savings of approximately $10 million and approximately $50 million of one time capital cost savings on its thermal in situ and primary heavy crude oil assets driving incremental value for the Company's shareholders. |
▪ | Canadian Natural's continued focus on delivering effective and efficient operations and cost control was demonstrated as the Company's E&P Q3/19 operating costs were $11.11/BOE, 5% and 7% reductions from Q2/19 and Q3/18 levels respectively. |
▪ | Canadian Natural's North America E&P crude oil and NGLs production volumes, excluding thermal in situ, averaged 244,267 bbl/d in Q3/19, a 4% increase over Q2/19 and in line with Q3/18 levels. The increase over Q2/19 was primarily due to a full quarter of production from primary heavy crude oil assets acquired from Devon Canada. |
• | At Pelican Lake the Company continues to demonstrate effective and efficient operations as operating costs have averaged approximately $6.50/bbl over the last 4 years. These sustainable and consistent results continued in Q3/19 where operating costs of $6.10/bbl were achieved, representing decreases of 9% and 5% from Q2/19 and Q3/18 levels respectively. The reductions were mainly as a result of the Company's focus on cost control and savings achieved from facility consolidation completed in Q2/19. |
Canadian Natural Resources Limited | 4 | Nine Months Ended September 30, 2019 |
▪ | International E&P production volumes were strong in Q3/19, exceeding quarterly production guidance, averaging 48,681 bbl/d, a decrease of 5% from Q2/19 and an increase of 2% over Q3/18 levels. The decrease from Q2/19 is primarily due to planned turnaround activities in the North Sea and natural field declines partially offset by strong performance from new wells. The increase from Q3/18 was primarily as a result of strong volumes from new wells drilled at Baobab and in the North Sea in late 2018 and 2019. |
▪ | Corporate natural gas production averaged 1,469 MMcf/d in Q3/19, exceeding the top end of quarterly guidance as a result of phasing of turnaround activities. As compared to Q2/19 and Q3/18 levels, natural gas production decreased by 4% and 5% respectively, primarily due to natural field declines and reduced capital investment. |
• | Strong operating costs of $1.12/Mcf were achieved in Q3/19, decreases of 9% and 16% from Q2/19 and Q3/18 levels respectively. The operating cost decreases were primarily due to the Company's continued focus on cost control and the impact of increased processed volumes at strategically owned and operated facilities. |
▪ | Incremental egress of approximately 225,000 bbl/d to move incremental crude oil production out of the Western Canadian Sedimentary Basin ("WCSB") is targeted to be added over the near term, providing opportunities for the Company before new export pipelines are constructed: |
• | Mainline enhancements are targeted to add approximately 85,000 bbl/d of capacity targeted to be available in December 2019. |
• | Express pipeline optimization expansion is targeted to add approximately 50,000 bbl/d of capacity in Q1/20. |
• | The North West Redwater Refinery ("NWR") is targeted to add approximately 40,000 bbl/d of incremental crude oil conversion capacity. Upon start-up, the refinery will process a total of approximately 80,000 bbl/d of diluted bitumen, increasing effective takeaway capacity out of the WCSB. |
• | Base Keystone export pipeline optimization expansion of approximately 50,000 bbl/d was recently announced. In Q3/19, Canadian Natural committed to approximately 10,000 bbl/d of the expansion, which is targeted to be available early in 2020. |
• | Crude by rail volumes continue to be strong at approximately 310,000 bbl/d for the month of August 2019. |
Canadian Natural Resources Limited | 5 | Nine Months Ended September 30, 2019 |
Nine Months Ended Sep 30 | ||||||||
2019 | 2018 | |||||||
(number of wells) | Gross | Net | Gross | Net | ||||
Crude oil | 80 | 74 | 402 | 381 | ||||
Natural gas | 21 | 15 | 19 | 15 | ||||
Dry | 3 | 3 | 7 | 7 | ||||
Subtotal | 104 | 92 | 428 | 403 | ||||
Stratigraphic test / service wells | 411 | 358 | 617 | 524 | ||||
Total | 515 | 450 | 1,045 | 927 | ||||
Success rate (excluding stratigraphic test / service wells) | 97 | % | 98 | % |
▪ | The Company's total crude oil and natural gas drilling program of 92 net wells for the nine months ended September 30, 2019, excluding strat/service wells, represents a decrease of 311 net wells from the same period in 2018. The Company's drilling levels primarily reflect the impacts of reduced capital allocation as a result of Alberta curtailments and execution of the Company's curtailment optimization strategy. |
Crude oil and NGLs – excluding Thermal In Situ Oil Sands | ||||||||||
Three Months Ended | Nine Months Ended | |||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||
Crude oil and NGLs production (bbl/d) | 244,267 | 235,066 | 247,314 | 234,944 | 243,857 | |||||
Net wells targeting crude oil | 33 | 9 | 140 | 70 | 299 | |||||
Net successful wells drilled | 33 | 7 | 135 | 68 | 292 | |||||
Success rate | 100 | % | 78 | % | 96 | % | 97 | % | 98 | % |
▪ | Canadian Natural's North America E&P crude oil and NGLs production volumes, excluding thermal in situ, averaged 244,267 bbl/d in Q3/19, a 4% increase over Q2/19 and in line with Q3/18 levels. The increase was primarily due to a full quarter of production from the acquired primary heavy crude oil assets from Devon Canada. |
Canadian Natural Resources Limited | 6 | Nine Months Ended September 30, 2019 |
• | Canadian Natural's primary heavy crude oil production averaged 88,008 bbl/d in Q3/19, a 13% increase over Q2/19 levels primarily due to additional volumes from the Devon Canada asset acquisition. Primary heavy crude oil production decreased by 4% from Q3/18 levels primarily due to curtailments and natural field declines, partially offset by additional volumes from the Devon Canada asset acquisition. |
◦ | Operating costs of $17.08/bbl were achieved in the Company's primary heavy crude oil operations in the quarter, a 3% decrease from Q2/19 levels. |
◦ | As a result of curtailments in Alberta the Company drilled 7 net primary heavy crude oil wells in Saskatchewan in Q3/19, targeting strategic opportunities for future development, as these wells are not impacted by curtailment. Canadian Natural is leveraging the Company's multilateral horizontal technology expertise on these wells where early results of approximately 140 bbl/d per well are in line with expectations. |
• | Pelican Lake quarterly production averaged 60,146 bbl/d in Q3/19, an increase of 9% from Q2/19 levels, reflecting normal production levels after the temporary shut-in of crude oil production in Q2/19 due to wildfires in northern Alberta. |
◦ | At Pelican Lake the Company continues to demonstrate effective and efficient operations as operating costs have averaged approximately $6.50/bbl over the last 4 years. These sustainable and consistent results continued in Q3/19 where operating costs of $6.10/bbl were achieved, representing decreases of 9% and 5% from Q2/19 and Q3/18 levels respectively. The reductions were mainly as a result of the Company's focus on cost control and savings achieved from facility consolidation completed in Q2/19. |
• | North American light crude oil and NGL production averaged 96,113 bbl/d in Q3/19, a 6% decrease from Q2/19 levels primarily as a result of curtailments in Alberta and natural field declines. Production increased 3% from Q3/18 levels reflecting the Company's strategic decision to reallocate capital to light crude oil and liquids rich areas, along with strong results from the 2018 and 2019 drilling programs at Wembley, Karr, and Southeast Saskatchewan combined with the execution of the Company's curtailment optimization strategy. |
◦ | In Q3/19 operating costs were $14.96/bbl in the Company's North America light crude oil and NGL areas, an increase of 2% over Q2/19 and a decrease of 4% from Q3/18 levels. The changes from Q2/19 and Q3/18 levels primarily reflect changes in production volumes noted above and the Company's focus on cost control. |
◦ | Within the greater Wembley area, results from the 27 net wells drilled in 2018 and 3 net wells drilled in 2019 continue to be strong with production averaging approximately 10,400 bbl/d liquids and 68 MMcf/d, exceeding expectations by approximately 40%. |
◦ | In Southeast Saskatchewan, the Company drilled 8 gross (6.6 net) light crude oil wells in Q3/19, with 3 gross (3.0 net) wells previously drilled in Q2/19 as a part of the program. These high return wells came on stream in Q3/19 with strong initial rates from the total program averaging approximately 100 bbl/d per well, exceeding expectations. The Company strategically reallocated conventional capital from Alberta to Saskatchewan as production from these wells is not impacted by the Government of Alberta mandated production curtailment. |
▪ | The Company’s annual 2019 North America E&P crude oil and NGL production guidance remains unchanged and is targeted to range between 231,000 bbl/d - 251,000 bbl/d. |
Thermal In Situ Oil Sands | ||||||||||
Three Months Ended | Nine Months Ended | |||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||
Bitumen production (bbl/d) | 206,395 | 109,599 | 112,542 | 137,124 | 109,769 | |||||
Net wells targeting bitumen | — | — | 41 | — | 84 | |||||
Net successful wells drilled | — | — | 41 | — | 84 | |||||
Success rate | — | — | 100 | % | — | 100 | % |
▪ | Thermal in situ oil sands production volumes exceeded the top end of quarterly production guidance as the Company demonstrated the flexibility and available capacity of its thermal in situ assets by utilizing allowable volumes during the Horizon turnaround of approximately 28,000 bbl/d in September from Jackfish, Kirby North and pad additions at Primrose. Production in Q3/19 averaged 206,395 bbl/d, an 88% increase over Q2/19 levels, primarily reflecting a full quarter of production from the Devon Canada asset acquisition and the successful execution on the Company's curtailment optimization strategy. |
Canadian Natural Resources Limited | 7 | Nine Months Ended September 30, 2019 |
• | Thermal in situ operating costs were strong in Q3/19 at $9.77/bbl, reductions of 17% and 14% from Q2/19 and Q3/18 levels respectively, primarily as a result of synergies captured to date from the Devon Canada acquisition and lower energy costs. |
• | At Primrose, Q3/19 production volumes averaged 73,652 bbl/d, an increase of 2% over Q2/19 levels, primarily due to execution on the Company's curtailment optimization strategy. Including energy costs, operating costs were strong at $9.91/bbl in Q2/19, decreases of 20% and 16% from Q2/19 and Q3/18 levels respectively, reflecting the Company's focus on cost control, higher volumes and lower energy costs. |
◦ | At Primrose, as a result of strong execution the Company's high return pad additions came on ahead of schedule and on budget. Production from the pad additions were strong, beginning on September 16, 2019, utilizing available oil processing and steam capacity with managed production averaging approximately 13,600 bbl/d in September, offsetting production impacts from the planned turnaround at Horizon as part of the Company's curtailment optimization strategy. |
• | At Kirby, which now includes both Kirby South and Kirby North projects, Steam Assisted Gravity Drainage ("SAGD") production volumes averaged 31,260 bbl/d in Q3/19, a 9% increase over Q2/19 and a 13% decrease from Q3/18 levels. The increase from Q2/19 was primarily as a result of strong initial Kirby North production. Including energy costs, Kirby quarterly operating costs were strong at $8.69/bbl in Q3/19, reductions of 18% and 5% from Q2/19 and Q3/18 levels respectively, primarily as a result of the Company's focus on cost control, higher production volumes and lower energy costs. |
◦ | Results from the first five months of the Company's solvent enhanced SAGD pilot at Kirby South continue to be positive, indicating that targeted reductions of 30% to 50% to Steam to Oil Ratios ("SORs") remain achievable. If success continues during the two year duration of the pilot, solvent enhanced SAGD has the potential to significantly reduce SORs, operating costs and greenhouse gas emissions by upwards of 50%, if fully commercialized. |
◦ | At Kirby North, top tier execution and productivity have resulted in production averaging approximately 6,600 bbl/d in September 2019, exceeding production forecasts. Strong performance results are primarily due to improved well design, high plant reliability and other operational improvements. Production volumes will be managed as part of the Company's curtailment optimization strategy as the Company ramps up towards Kirby North's overall capacity of 40,000 bbl/d targeted in early 2021. |
• | At Jackfish, SAGD production volumes averaged 97,537 bbl/d in Q3/19. Including energy costs, Jackfish quarterly operating costs were strong at $9.44/bbl in Q3/19, approximately $3.00/bbl lower than operating cost indications for the asset at time of the acquisition primarily as a result of lower energy costs and synergies captured to date. |
◦ | At Jackfish, pad additions that have been successfully drilled and not completed to date due to curtailments in Alberta have a production capability of 21,000 bbl/d. These pads require minimal capital of approximately $8 million to complete tie in activities that are targeted for Q4/19. Production from these pads is targeted to offset conventional production declines with long life low decline thermal in situ production, as the Company manages within its curtailment optimization strategy and targets to reach peak production in 2022. |
▪ | The Company’s annual 2019 thermal in situ production guidance remains unchanged and is targeted to range between 157,000 bbl/d - 172,000 bbl/d. |
North America Natural Gas | ||||||||||
Three Months Ended | Nine Months Ended | |||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||
Natural gas production (MMcf/d) | 1,425 | 1,482 | 1,489 | 1,454 | 1,506 | |||||
Net wells targeting natural gas | 5 | 2 | 6 | 16 | 15 | |||||
Net successful wells drilled | 5 | 2 | 6 | 15 | 15 | |||||
Success rate | 100 | % | 100 | % | 100 | % | 94 | % | 100 | % |
▪ | North America natural gas production was 1,425 MMcf/d in Q3/19, decreases of 4% from both Q2/19 and Q3/18 levels. The decreases were primarily due to natural field declines and reduced capital investment. |
Canadian Natural Resources Limited | 8 | Nine Months Ended September 30, 2019 |
▪ | Strong operating costs of $1.07/Mcf were achieved in Q3/19, decreases of 7% and 11% from Q2/19 and Q3/18 levels respectively. The operating cost decreases were primarily due to the Company's continued focus on cost control and the impact of increased processed volumes at strategically owned and operated facilities. |
• | Septimus operating costs were strong at $0.26/Mcfe in Q3/19, decreases of 21% and 26% from Q2/19 and Q3/18 levels respectively. Focus on cost control supports the Company's high value liquids rich development at Septimus. |
▪ | The Company's natural gas reinjection pilot at Septimus commenced its first injection of 5 MMcf/d in Q2/19. Depending on results of the pilot, this technology has the potential to materially increase liquids recovery while storing natural gas in the reservoir, preserving the value of the natural gas for periods with higher market prices. |
• | Initial results from the pilot are targeted for late 2019 with the potential to proceed with additional cycles at the same location. Given the opportunities for this process across Canadian Natural's vast liquids rich Montney land base, the Company is advancing readiness for a second pilot site within the Company's Greater Wembley area. |
▪ | In 2019 the Company strategically reallocated capital from crude oil projects to the Company's liquids rich Gold Creek assets, which are not subject to curtailment. In Q3/19, 2 net wells came on production averaging approximately 660 bbl/d and 4 MMcf/d per well, exceeding expectations by approximately 110 bbl/d or 20% per well. |
▪ | At Pine River, the Company's planned plant turnaround began in mid-September and was completed on November 6, 2019. The turnaround was designed to improve plant efficiency, run time, lower operating costs, and improve plant capability to 120 MMcf/d from current levels of 95 MMcf/d. |
▪ | In Q3/19, based upon corporate quarterly Natural Gas production, Canadian Natural used the equivalent of approximately 44% within its operations, providing a natural hedge from the challenging Western Canadian natural gas price environment. Approximately 32% of the Company's Q3/19 natural gas production was exported to other North American markets and sold internationally, with the remaining 24% of the Company's Q3/19 natural gas production exposed to AECO/Station 2 pricing. |
▪ | The Company’s annual 2019 corporate natural gas production guidance remains unchanged and is targeted to range between 1,485 MMcf/d - 1,545 MMcf/d. |
Three Months Ended | Nine Months Ended | |||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||
Crude oil production (bbl/d) | ||||||||||
North Sea | 27,454 | 27,594 | 28,702 | 26,927 | 24,940 | |||||
Offshore Africa | 21,227 | 23,650 | 18,802 | 22,341 | 18,812 | |||||
Natural gas production (MMcf/d) | ||||||||||
North Sea | 20 | 23 | 38 | 24 | 35 | |||||
Offshore Africa | 24 | 27 | 26 | 26 | 27 | |||||
Net wells targeting crude oil | 3.0 | 0.9 | 1.6 | 5.5 | 4.5 | |||||
Net successful wells drilled | 3.0 | 0.9 | 1.6 | 5.5 | 4.5 | |||||
Success rate | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
▪ | International E&P production volumes were strong in Q3/19, exceeding quarterly production guidance, averaging 48,681 bbl/d, a decrease of 5% from Q2/19 and an increase of 2% over Q3/18 levels. The decrease from Q2/19 is primarily due to planned turnaround activities in the North Sea and natural field declines partially offset by strong performance from new wells. The increase from Q3/18 was primarily as a result of strong volumes from new wells drilled at Baobab and in the North Sea in late 2018 and 2019. |
▪ | International production volumes benefit from premium Brent pricing, generating significant free cash flow for the Company. |
• | In the North Sea, production volumes of 27,454 bbl/d were achieved in Q3/19, comparable to Q2/19 and a 4% decrease from Q3/18 levels. The decrease from Q3/18 was primarily as a result of planned maintenance activities and natural field declines partly offset by volumes from new wells. |
Canadian Natural Resources Limited | 9 | Nine Months Ended September 30, 2019 |
◦ | Q3/19 operating costs in the North Sea averaged $37.11/bbl (£23.04/bbl), in line with Q2/19 and Q3/18 levels. |
◦ | The Company completed its 2019 drilling program in Q3/19 drilling 3 gross (3.0 net) high netback producer wells. Initial production from the total drilling program consisting of 5 gross (4.9 net) wells is exceeding expectations by approximately 1,300 bbl/d net per well in the quarter. |
• | Offshore Africa production volumes in Q3/19 averaged 21,227 bbl/d, a decrease of 10% from Q2/19 and an increase of 13% over Q3/18 levels. The decrease from Q2/19 was primarily as a result of natural field declines and turnaround activities in the quarter. The increase from Q3/18 was primarily as a result of production from new wells drilled late in 2018 and early in 2019 at Baobab, partially offset by natural field declines. |
◦ | Côte d'Ivoire crude oil operating costs averaged $11.06/bbl (US$8.42/bbl) in Q3/19, an increase of 32% from Q2/19 and a decrease of 21% from Q3/18 levels primarily due to timing of liftings from various fields that have different cost structures. |
◦ | Following the previously announced discovery of significant gas condensate in South Africa, where Canadian Natural has a 20% working interest, the operator is preparing to commence a comprehensive 3D and 2D seismic acquisition program in Q4/19, with targeted completion in Q2/20. |
– | The operator has contracted a rig with targeted spud of an exploration well in the first half of 2020. Depending on the results of this well, the operator may drill an additional well in 2020 to further define volumes and deliverability. |
– | Canadian Natural is carried to a maximum gross cost of approximately US$300 million. |
▪ | The Company's annual 2019 International production guidance remains unchanged and is targeted to range from 46,000 bbl/d - 50,000 bbl/d. |
Three Months Ended | Nine Months Ended | |||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||
Synthetic crude oil production (bbl/d) (1) (2) | 432,203 | 374,500 | 394,382 | 407,695 | 419,161 |
(1) | SCO production before royalties and excludes volumes consumed internally as diesel. |
(2) | Consists of heavy and light synthetic crude oil products. |
▪ | At the Company's world class Oil Sands Mining and Upgrading assets, production volumes were strong, at the upper end of production guidance, averaging 432,203 bbl/d of SCO in Q3/19, increases of 15% and 10% over Q2/19 and Q3/18 levels respectively. The increases were primarily as a result of strong operational performance as well as modified timing of the Horizon turnaround schedule as a part of the Company's curtailment optimization strategy. |
• | Effective and efficient operations and high reliability resulted in strong quarterly operating costs of $20.05/bbl (US$15.18/bbl) of SCO in Q3/19, comparable to record low operating costs of $19.97/bbl (US$15.12/bbl) of SCO achieved in Q4/18, impressive results given the planned turnaround activities in the quarter. Q3/19 operating costs represent decreases of 17% and 12% from Q2/19 and Q3/18 levels respectively. |
◦ | Total production costs were $784 million in Q3/19, $30 million lower than Q2/19. Production costs for the first nine months of 2019 were $2,420 million, a 6% or $150 million decrease from the comparable period in 2018, demonstrating the Company's focus on effective and efficient operations. |
• | At the Albian mines, top tier operations combined with enhancing and optimization of equipment resulted in record gross bitumen production averaging approximately 318,000 bbl/d in September and October, forming a part of the Company’s curtailment optimization strategy during the Horizon turnaround. These results are significant as the two month average throughput was approximately 38,000 bbl/d or 14% above capability announced at the time of the acquisition. The Company continues to maximize value from acquired assets through lower operating costs and enhancing and optimizing production. |
• | At Horizon, subsequent to quarter end the Company successfully completed a planned turnaround on schedule and under budget demonstrating strong execution by the Company's teams. |
• | The Company continues to progress engineering work on a prudent basis for potential expansion opportunities at Horizon to increase reliability and lower costs, targeting to add production of 75,000 bbl/d to 95,000 bbl/d. The final investment decision on these opportunities will not be made until there is greater clarity on market access. |
Canadian Natural Resources Limited | 10 | Nine Months Ended September 30, 2019 |
▪ | The Company's annual 2019 Oil Sands Mining and Upgrading production guidance remains unchanged and is targeted to range between 405,000 bbl/d - 415,000 bbl/d of SCO. |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||||||
Crude oil and NGLs pricing | |||||||||||||||||||||
WTI benchmark price (US$/bbl) (1) | $ | 56.45 | $ | 59.83 | $ | 69.50 | $ | 57.06 | $ | 66.79 | |||||||||||
WCS heavy differential as a percentage of WTI (%) (2) | 22 | % | 18 | % | 32 | % | 21 | % | 33 | % | |||||||||||
SCO price (US$/bbl) | $ | 56.87 | $ | 59.96 | $ | 68.44 | $ | 56.36 | $ | 65.75 | |||||||||||
Condensate benchmark pricing (US$/bbl) | $ | 52.00 | $ | 55.86 | $ | 66.82 | $ | 52.79 | $ | 66.28 | |||||||||||
Average realized pricing before risk management (C$/bbl) (3) | $ | 55.19 | $ | 63.45 | $ | 57.89 | $ | 57.49 | $ | 54.26 | |||||||||||
Natural gas pricing | |||||||||||||||||||||
AECO benchmark price (C$/GJ) | $ | 0.99 | $ | 1.11 | $ | 1.28 | $ | 1.31 | $ | 1.33 | |||||||||||
Average realized pricing before risk management (C$/Mcf) | $ | 1.64 | $ | 1.98 | $ | 2.32 | $ | 2.24 | $ | 2.34 |
(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. |
▪ | Incremental egress of approximately 225,000 bbl/d to move incremental crude oil production out of the WCSB is targeted to be added over the near term, providing opportunities for the Company before new export pipelines are constructed: |
• | Mainline enhancements are targeted to add approximately 85,000 bbl/d of capacity targeted to be available in December 2019. |
• | Express pipeline optimization expansion is targeted to add approximately 50,000 bbl/d of capacity in Q1/20. |
• | The NWR Refinery is targeted to add approximately 40,000 bbl/d of incremental crude oil conversion capacity. Upon start-up, the refinery will process a total of approximately 80,000 bbl/d of diluted bitumen, increasing effective takeaway capacity out of the WCSB. |
• | Base Keystone export pipeline optimization expansion of approximately 50,000 bbl/d was recently announced. In Q3/19, Canadian Natural committed to approximately 10,000 bbl/d of the expansion, which is targeted to be available early in 2020. |
• | Crude by rail volumes continue to be strong at approximately 310,000 bbl/d for the month of August 2019. |
▪ | Q3/19 differentials between WCS and WTI benchmark pricing narrowed from Q3/18 levels following the Government of Alberta's announcement of mandatory curtailments of crude oil production that came into effect January 1, 2019. |
▪ | AECO natural gas prices decreased in Q3/19 from Q2/19 and Q3/18 levels, reflecting pipeline egress constraints out of the basin as well as increased natural gas production in North America. |
• | During Q3/19, TC Energy announced the Temporary Service Protocol ("TSP") on the Nova Gas Transmission Line that targets to manage system constraints during planned outages and maintenance during the summer months (April through October). TSP targets to be in place until October 2020, potentially resulting in reduced volatility of AECO benchmark pricing over that period. |
▪ | The NWR refinery, upon completion, targets to strengthen the Company’s position by providing a competitive return on investment and by creating incremental demand for approximately 80,000 bbl/d of heavy crude oil blends that will not require export pipelines, helping to reduce pricing volatility in all Western Canadian heavy crude oil. |
• | The Company has a 50% interest in the NWR Partnership. For updates on the project, please refer to: https://nwrsturgeonrefinery.com/whats-happening/news/. |
Canadian Natural Resources Limited | 11 | Nine Months Ended September 30, 2019 |
▪ | In July 2019, Canadian Natural published its 2018 Stewardship Report to Stakeholders, which is available on the Company's website at https://www.cnrl.com/report-to-stakeholders. The report displays how Canadian Natural continues to focus on safe, reliable, effective and efficient operations while minimizing its environmental footprint. Highlights from the 2018 report are as follows: |
▪ | In the report, the Company confirmed that 100% of direct emissions from our Alberta oil sands in situ and mining operations were third party verified. The 2018 verification was completed by professional engineering firm GHD Limited. |
• | Canadian Natural's corporate greenhouse gas ("GHG") emissions intensity has decreased by approximately 29% from 2012 to 2018, a material reduction in emissions intensity. |
• | The Company's corporate GHG emissions intensity decreased in 2018 by approximately 29% from 2012 levels, including a reduction of approximately 37% at Horizon Oil Sands. |
◦ | The Company's corporate GHG emissions intensity decreased in 2018 by approximately 5% from 2017 levels, including a reduction of approximately 18% in Oil Sands Mining and Upgrading. |
• | Methane emissions have decreased 78% from 2012 to 2018 at the Company's Alberta primary heavy conventional crude oil operations. |
• | In the Company's North America E&P segment, in 2018 natural gas flaring decreased by 4% and natural gas venting decreased by 6% from 2017 levels. |
• | In 2018, in the Company's North America E&P segment, Canadian Natural abandoned 1,293 wells, an increase of 68% over 2017 levels, and submitted 1,012 reclamation certificates, an increase of approximately 67% over 2017 levels. |
• | The Company reclaimed 1,383 hectares of land in 2018 in the Company's North America E&P segment, equivalent to approximately 1,700 Canadian football fields and a 9% increase over 2017 levels. |
• | In the Oil Sands Mining and Upgrading segment, water use intensity decreased in 2018 by 30% from 2017 levels. |
• | Approximately 75% of water used at Primrose was sourced from recycled produced water in 2018. |
▪ | Canadian Natural has invested over $3.4 billion in research and development from 2009 to 2018 year ended and continues to invest in technology to unlock reserves, become more effective and efficient, increase production and reduce the Company's environmental footprint. Canadian Natural's culture of continuous improvement leverages the use of technology and innovation to drive sustainable operations and long-term value for shareholders. |
▪ | 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 by way of carbon capture facilities at its 50% interest in the NWR refinery when on stream. As a result, Canadian Natural targets capacity to capture and sequester 2.7 million tonnes of CO2 annually, equivalent to taking 576,000 vehicles off the road per year, making the Company one of the largest CO2 capturer and sequester for the oil and natural gas sector globally. |
▪ | 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 determine the feasibility of producing stackable dry tailings. The project has the potential to reduce the Company's carbon emissions and environmental footprint by reducing the distance driven by its fleet of haul trucks, the size and need for tailings ponds and accelerating site reclamation. In addition, this process has the potential to significantly reduce capital and operating costs. |
• | The initial testing phase for the Company's IPEP pilot has concluded and results have been positive, with excellent recovery rates and evidence of stackable tailings. Given that the pilot continues to produce positive results, the Company is targeting to proceed with pilot enhancements in 2020. |
Canadian Natural Resources Limited | 12 | Nine Months Ended September 30, 2019 |
▪ | The Company’s strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved production levels of 1,176,361 BOE/d in Q3/19, with approximately 98% of total production located in G7 countries. |
• | Canadian Natural maintains a balance of products with Q3/19 production mix on a BOE/d basis of 49% light crude oil and SCO blends, 30% heavy crude oil blends and 21% natural gas. |
▪ | Canadian Natural delivered strong quarterly free cash flow of $1,471 million after net capital expenditures of $963 million, and dividend requirements of $447 million in Q3/19, reflecting the strength of our long life low decline asset base and our effective and efficient operations. |
• | Balance sheet strength remains a focus and free cash flow was used to reduce debt levels in Q3/19 as the Company balances its free cash flow according to the defined free cash flow allocation policy. As a result gross long-term debt was reduced in Q3/19 by $1,018 million from Q2/19 levels. |
• | Net long-term debt was reduced by $796 million to $22,313 million in Q3/19. |
• | The Company utilized adjusted funds flow to repay and cancel $800 million of the $1,800 million non-revolving term loan facility; $1,000 million remained outstanding and fully drawn at quarter end. |
◦ | Subsequent to quarter end the Company repaid and canceled an additional $500 million of the remaining $1,000 million non-revolving term loan; $500 million remains outstanding and fully drawn as at November 6, 2019. |
• | Debt to book capitalization strengthened to 39.1% in Q3/19. |
• | Canadian Natural maintains strong financial stability and liquidity represented by cash balances, and committed and demand bank credit facilities. At September 30, 2019 the Company had approximately $4,680 million of available liquidity, including cash and cash equivalents, an increase of approximately $120 million over Q2/19 levels. |
• | Canadian Natural is committed to returns to our shareholders, returning a total of $616 million in Q3/19, $447 million by way of dividends and $169 million by way of share purchases. In the first nine months of 2019, the Company has returned a total of $2,100 million to our shareholders, $1,299 million by way of dividends and $801 million by way of share purchases. |
◦ | Share purchases for cancellation in the quarter totaled 5,050,000 common shares at a weighted average share price of $33.45. |
◦ | Subsequent to quarter end, up to and including November 6, 2019, the Company executed on additional share purchases for cancellation of 1,350,000 common shares at a weighted average share price of $33.70. |
◦ | Subsequent to quarter end, the Company declared a quarterly dividend of $0.375 per share, payable on January 1, 2020. |
▪ | In addition to the Company's strong adjusted funds flow, capital flexibility and access to debt capital markets, Canadian Natural has additional financial levers at its disposal to effectively manage its liquidity. As at September 30, 2019, these financial levers include the Company’s third party equity investments of $567 million, and cross currency swaps with a total value of $321 million. |
▪ | In 2018, the Board of Directors approved a more defined free cash flow allocation policy in accordance with the Company's four stated pillars. Under the policy, in 2019 the Company will target to allocate, on an annual basis, 50% of its residual free cash flow, after budgeted capital expenditures, dividends and large opportunistic acquisitions, to share purchases under its NCIB and the remaining 50% to reducing debt levels on the Company's balance sheet. This free cash flow policy will target a ratio of debt to adjusted 12 months trailing EBITDA of 1.5x, and an absolute debt level of $15.0 billion, at which time the policy will be reviewed by the Board. This policy was effective November 1, 2018. |
Canadian Natural Resources Limited | 13 | Nine Months Ended September 30, 2019 |
Canadian Natural Resources Limited | 14 | Nine Months Ended September 30, 2019 |
Canadian Natural Resources Limited | 15 | Nine Months Ended September 30, 2019 |
Canadian Natural Resources Limited | 16 | Nine Months Ended September 30, 2019 |
Canadian Natural Resources Limited | 17 | Nine Months Ended September 30, 2019 |
CANADIAN NATURAL RESOURCES LIMITED |
2100, 855 - 2nd Street S.W. Calgary, Alberta, T2P4J8 Phone: 403-514-7777 Email: ir@cnrl.com www.cnrl.com |
STEVE W. LAUT Executive Vice-Chairman TIM S. MCKAY President MARK A. STAINTHORPE Chief Financial Officer and Senior Vice-President, Finance Trading Symbol - CNQ Toronto Stock Exchange New York Stock Exchange |
Canadian Natural Resources Limited | 18 | Nine Months Ended September 30, 2019 |
Canadian Natural Resources Limited | 1 | Nine Months Ended September 30, 2019 |
Canadian Natural Resources Limited | 2 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
($ millions, except per common share amounts) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||||
Product sales (1) | $ | 6,587 | $ | 5,931 | $ | 6,327 | $ | 18,059 | $ | 18,451 | |||||||||||||
Crude oil and NGLs | $ | 6,324 | $ | 5,597 | $ | 5,967 | $ | 17,003 | $ | 17,341 | |||||||||||||
Natural gas | $ | 257 | $ | 324 | $ | 360 | $ | 1,037 | $ | 1,110 | |||||||||||||
Net earnings | $ | 1,027 | $ | 2,831 | $ | 1,802 | $ | 4,819 | $ | 3,367 | |||||||||||||
Per common share | – basic | $ | 0.87 | $ | 2.37 | $ | 1.48 | $ | 4.04 | $ | 2.75 | ||||||||||||
– diluted | $ | 0.87 | $ | 2.36 | $ | 1.47 | $ | 4.03 | $ | 2.74 | |||||||||||||
Adjusted net earnings from operations (2) | $ | 1,229 | $ | 1,042 | $ | 1,354 | $ | 3,109 | $ | 3,518 | |||||||||||||
Per common share | – basic | $ | 1.04 | $ | 0.87 | $ | 1.11 | $ | 2.61 | $ | 2.88 | ||||||||||||
– diluted | $ | 1.04 | $ | 0.87 | $ | 1.11 | $ | 2.60 | $ | 2.86 | |||||||||||||
Cash flows from operating activities | $ | 2,518 | $ | 2,861 | $ | 3,642 | $ | 6,375 | $ | 8,724 | |||||||||||||
Adjusted funds flow (3) | $ | 2,881 | $ | 2,652 | $ | 2,830 | $ | 7,773 | $ | 7,859 | |||||||||||||
Per common share | – basic | $ | 2.43 | $ | 2.22 | $ | 2.32 | $ | 6.51 | $ | 6.42 | ||||||||||||
– diluted | $ | 2.43 | $ | 2.22 | $ | 2.31 | $ | 6.50 | $ | 6.39 | |||||||||||||
Cash flows used in investing activities | $ | 908 | $ | 4,464 | $ | 1,265 | $ | 6,401 | $ | 3,772 | |||||||||||||
Net capital expenditures (4) | $ | 963 | $ | 4,125 | $ | 1,473 | $ | 6,065 | $ | 3,550 |
(1) | Further details related to product sales, including 'Other' income, for the three and nine months ended September 30, 2019 are disclosed in note 17 to the Company’s unaudited interim consolidated financial statements. |
(2) | Adjusted net earnings from operations is a non-GAAP measure that represents net earnings as presented in the Company's consolidated Statements of Earnings, adjusted for the after-tax effects of certain items of a non-operational nature. The Company considers adjusted net earnings from operations a key measure in evaluating its performance, as it demonstrates the Company’s ability to generate after-tax operating earnings from its core business areas. The reconciliation “Adjusted Net Earnings from Operations, as Reconciled to Net Earnings" is presented in this MD&A. Adjusted net earnings from operations may not be comparable to similar measures presented by other companies. |
(3) | Adjusted funds flow (previously referred to as funds flow from operations) is a non-GAAP measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment expenditures and movements in other long-term assets, including the unamortized cost of the share bonus program and prepaid cost of service tolls. The Company considers adjusted funds flow a key measure in evaluating its performance as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities” is presented in this MD&A. Adjusted funds flow may not be comparable to similar measures presented by other companies. |
(4) | Net capital expenditures is a non-GAAP measure that represents cash flows used in investing activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, investment in other long-term assets, share consideration in business combinations and abandonment expenditures. The Company considers net capital expenditures a key measure as it provides an understanding of the Company’s capital spending activities in comparison to the Company's annual capital budget. The reconciliation “Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities” is presented in the "Net Capital Expenditures" section of this MD&A. Net capital expenditures may not be comparable to similar measures presented by other companies. |
Canadian Natural Resources Limited | 3 | Nine Months Ended September 30, 2019 |
Adjusted Net Earnings from Operations, as Reconciled to Net Earnings | |||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Net earnings | $ | 1,027 | $ | 2,831 | $ | 1,802 | $ | 4,819 | $ | 3,367 | |||||||||||
Share-based compensation, net of tax (1) | 7 | (7 | ) | (85 | ) | 62 | 2 | ||||||||||||||
Unrealized risk management gain, net of tax (2) | (2 | ) | (13 | ) | (11 | ) | (2 | ) | (53 | ) | |||||||||||
Unrealized foreign exchange loss (gain), net of tax (3) | 129 | (219 | ) | (182 | ) | (323 | ) | 158 | |||||||||||||
Realized foreign exchange loss on repayment of US dollar debt securities, net of tax (4) | — | — | — | — | 146 | ||||||||||||||||
Loss from investments, net of tax (5) (6) | 68 | 68 | 89 | 171 | 240 | ||||||||||||||||
Gain on acquisition and revaluation of properties, net of tax (7) | — | — | (259 | ) | — | (342 | ) | ||||||||||||||
Effect of statutory tax rate and other legislative changes on deferred income tax liabilities (8) | — | (1,618 | ) | — | (1,618 | ) | — | ||||||||||||||
Adjusted net earnings from operations | $ | 1,229 | $ | 1,042 | $ | 1,354 | $ | 3,109 | $ | 3,518 |
(1) | The Company’s employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded as a liability on the Company’s balance sheets and periodic changes in the fair value are recognized in net earnings or are charged to (recovered from) the Oil Sands Mining and Upgrading segment. |
(2) | Derivative financial instruments are recorded at fair value on the Company’s balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than those amounts reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil, natural gas and foreign exchange. |
(3) | Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps, and are recognized in net earnings. |
(4) | During the first quarter of 2018, the Company repaid US$600 million of 1.75% notes and US$400 million of 5.90% notes. |
(5) | The Company's investment in the 50% owned North West Redwater Partnership ("Redwater Partnership") is accounted for using the equity method of accounting. Included in the non-cash loss from investments is the Company's pro rata share of the Redwater Partnership's equity loss for the period. |
(6) | The Company’s investments in PrairieSky Royalty Ltd. (“PrairieSky”) and Inter Pipeline Ltd. ("Inter Pipeline") have been accounted for at fair value through profit and loss and are measured each period with changes in fair value recognized in net earnings. |
(7) | During the third quarter of 2018, the Company recorded a pre-tax gain of $272 million ($259 million after-tax) related to acquisitions in the North America Exploration and Production segment. During the second quarter of 2018, the Company recorded a pre-tax gain of $120 million ($72 million after-tax) on the acquisition of the remaining interest at Ninian in the North Sea and a pre-tax gain of $19 million ($11 million after-tax) relating to the revaluation of the Company's previously held interest at Ninian. |
(8) | In the second quarter of 2019, the Government of Alberta enacted legislation that decreased the provincial corporate income tax rate from 12% to 11% effective July 1, 2019, with a further 1% rate reduction every year on January 1 until the provincial corporate income tax rate is 8% on January 1, 2022. As a result of these corporate income tax rate reductions, the Company's deferred corporate income tax liability decreased by $1,618 million. |
Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities (1) | |||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Cash flows from operating activities | $ | 2,518 | $ | 2,861 | $ | 3,642 | $ | 6,375 | $ | 8,724 | |||||||||||
Net change in non-cash working capital | 299 | (230 | ) | (889 | ) | 1,085 | (1,067 | ) | |||||||||||||
Abandonment expenditures (2) | 63 | 41 | 57 | 212 | 197 | ||||||||||||||||
Other (3) | 1 | (20 | ) | 20 | 101 | 5 | |||||||||||||||
Adjusted funds flow | $ | 2,881 | $ | 2,652 | $ | 2,830 | $ | 7,773 | $ | 7,859 |
(1) | Adjusted funds flow was previously referred to as funds flow from operations. |
(2) | The Company includes abandonment expenditures in “Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities” in the "Net Capital Expenditures" section of this MD&A. |
(3) | Movements in other long-term assets, including the unamortized cost of the share bonus program and prepaid cost of service tolls. |
Canadian Natural Resources Limited | 4 | Nine Months Ended September 30, 2019 |
▪ | lower realized SCO prices in the Oil Sands Mining and Upgrading segment; and |
▪ | lower SCO sales volumes in the Oil Sands Mining and Upgrading segment; |
▪ | higher crude oil and NGLs sales volumes in the Exploration and Production segments; |
▪ | higher crude oil and NGLs netbacks in the North America Exploration and Production segment; |
▪ | higher crude oil and NGLs netbacks in the Offshore Africa segment; and |
▪ | higher realized foreign exchange gains. |
▪ | lower natural gas netbacks in the North America Exploration and Production segment; |
▪ | lower realized SCO prices in the Oil Sands Mining and Upgrading segment; and |
▪ | higher realized foreign exchange losses; |
▪ | higher crude oil and NGLs sales volumes in the Exploration and Production segments; and |
▪ | higher SCO sales volumes in the Oil Sands Mining and Upgrading segment. |
▪ | higher SCO sales volumes in the Oil Sands Mining and Upgrading segment; and |
▪ | higher crude oil and NGLs sales volumes in the Exploration and Production segments; |
▪ | lower realized SCO prices in the Oil Sands Mining and Upgrading segment. |
Canadian Natural Resources Limited | 5 | Nine Months Ended September 30, 2019 |
($ millions, except per common share amounts) | Sep 30 2019 | Jun 30 2019 | Mar 31 2019 | Dec 31 2018 | ||||||||||||
Product sales (1) | $ | 6,587 | $ | 5,931 | $ | 5,541 | $ | 3,831 | ||||||||
Crude oil and NGLs | $ | 6,324 | $ | 5,597 | $ | 5,082 | $ | 3,327 | ||||||||
Natural gas | $ | 257 | $ | 324 | $ | 456 | $ | 504 | ||||||||
Net earnings (loss) | $ | 1,027 | $ | 2,831 | $ | 961 | $ | (776 | ) | |||||||
Net earnings (loss) per common share | ||||||||||||||||
– basic | $ | 0.87 | $ | 2.37 | $ | 0.80 | $ | (0.64 | ) | |||||||
– diluted | $ | 0.87 | $ | 2.36 | $ | 0.80 | $ | (0.64 | ) | |||||||
($ millions, except per common share amounts) | Sep 30 2018 | Jun 30 2018 | Mar 31 2018 | Dec 31 2017 | ||||||||||||
Product sales | $ | 6,327 | $ | 6,389 | $ | 5,735 | $ | 5,516 | ||||||||
Crude oil and NGLs | $ | 5,967 | $ | 6,071 | $ | 5,303 | $ | 5,098 | ||||||||
Natural gas | $ | 360 | $ | 318 | $ | 432 | $ | 418 | ||||||||
Net earnings (loss) | $ | 1,802 | $ | 982 | $ | 583 | $ | 396 | ||||||||
Net earnings (loss) per common share | ||||||||||||||||
– basic | $ | 1.48 | $ | 0.80 | $ | 0.48 | $ | 0.32 | ||||||||
– diluted | $ | 1.47 | $ | 0.80 | $ | 0.47 | $ | 0.32 |
(1) | Further details related to product sales, including 'Other' income, for the three months ended September 30, 2019 are disclosed in note 17 to the Company’s unaudited interim consolidated financial statements. |
Canadian Natural Resources Limited | 6 | Nine Months Ended September 30, 2019 |
▪ | Crude oil pricing – Fluctuating global supply/demand including crude oil production levels from the Organization of the Petroleum Exporting Countries (“OPEC”) and its impact on world supply, the impact of geopolitical uncertainties on worldwide benchmark pricing, the impact of shale oil production in North America, the impact of the Western Canadian Select ("WCS") Heavy Differential from the West Texas Intermediate reference location at Cushing, Oklahoma ("WTI") in North America including the impact of a shortage of takeaway capacity out of the Western Canadian Sedimentary Basin (the "Basin"), the impact of the differential between WTI and Dated Brent ("Brent") benchmark pricing in the North Sea and Offshore Africa and the impact of production curtailments mandated by the Government of Alberta that came into effect January 1, 2019. |
▪ | Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, third-party pipeline maintenance and outages and the impact of shale gas production in the US. |
▪ | Crude oil and NGLs sales volumes – Fluctuations in production due to the cyclic nature of the Company’s Primrose thermal projects, production from Kirby South, the results from the Pelican Lake water and polymer flood projects, the impact of the Company’s drilling program in North America and the International segments, the impact and timing of acquisitions, including the acquisition of assets from Devon Canada Corporation ("Devon") in the second quarter of 2019, production from Horizon Phase 3 as well as the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, voluntarily curtailed production in late 2018 due to low commodity prices in North America and production curtailments mandated by the Government of Alberta that came into effect January 1, 2019. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the International segments. |
▪ | Natural gas sales volumes – Fluctuations in production due to the Company’s allocation of capital to higher return crude oil projects, natural decline rates, fluctuating capacity at the Pine River processing facility, shut-in production due to third-party pipeline restrictions and related pricing impacts, shut-in production due to low commodity prices and the impact and timing of acquisitions. |
▪ | Production expense – Fluctuations primarily due to the impact of the demand and cost for services, fluctuations in product mix and production volumes, the impact of seasonal costs that are dependent on weather, the impact of increased carbon tax and energy costs, cost optimizations across all segments, the impact and timing of acquisitions, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, maintenance activities in the International segments and the impact of the adoption of IFRS 16 on January 1, 2019. |
▪ | Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes including the impact and timing of acquisitions and dispositions, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company’s proved undeveloped reserves, fluctuations in International sales volumes subject to higher depletion rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment and the impact of the adoption of IFRS 16 on January 1, 2019. |
▪ | Share-based compensation – Fluctuations due to the determination of fair market value based on the Black-Scholes valuation model of the Company’s share-based compensation liability. |
▪ | Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company’s risk management activities. |
▪ | Foreign exchange rates – Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the Company receives for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Fluctuations in realized and unrealized foreign exchange gains and losses were also recorded with respect to US dollar denominated debt, partially offset by the impact of cross currency swap hedges. |
▪ | Income tax expense – Fluctuations in income tax expense due to statutory tax rate and other legislative changes substantively enacted in the various periods. |
▪ | Gains on acquisition, disposition and revaluation of properties and gains/losses on investments – Fluctuations due to the recognition of the acquisition, disposition and revaluation of properties in the various periods, fair value changes in the investments in PrairieSky and Inter Pipeline shares, and the equity loss (gain) on the Company's interest in the Redwater Partnership. |
Canadian Natural Resources Limited | 7 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
(Average for the period) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
WTI benchmark price (US$/bbl) | $ | 56.45 | $ | 59.83 | $ | 69.50 | $ | 57.06 | $ | 66.79 | |||||||||||
Dated Brent benchmark price (US$/bbl) | $ | 61.85 | $ | 68.36 | $ | 75.46 | $ | 64.51 | $ | 72.35 | |||||||||||
WCS heavy differential from WTI (US$/bbl) | $ | 12.24 | $ | 10.65 | $ | 22.17 | $ | 11.76 | $ | 21.89 | |||||||||||
SCO price (US$/bbl) | $ | 56.87 | $ | 59.96 | $ | 68.44 | $ | 56.36 | $ | 65.75 | |||||||||||
Condensate benchmark price (US$/bbl) | $ | 52.00 | $ | 55.86 | $ | 66.82 | $ | 52.79 | $ | 66.28 | |||||||||||
Condensate differential from WTI (US$/bbl) | $ | 4.45 | $ | 3.96 | $ | 2.68 | $ | 4.27 | $ | 0.51 | |||||||||||
NYMEX benchmark price (US$/MMBtu) | $ | 2.23 | $ | 2.64 | $ | 2.90 | $ | 2.67 | $ | 2.89 | |||||||||||
AECO benchmark price (C$/GJ) | $ | 0.99 | $ | 1.11 | $ | 1.28 | $ | 1.31 | $ | 1.33 | |||||||||||
US/Canadian dollar average exchange rate (US$) | $ | 0.7573 | $ | 0.7474 | $ | 0.7651 | $ | 0.7523 | $ | 0.7766 |
Canadian Natural Resources Limited | 8 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | |||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||
Crude oil and NGLs (bbl/d) | ||||||||||
North America – Exploration and Production | 450,662 | 344,665 | 359,856 | 372,068 | 353,626 | |||||
North America – Oil Sands Mining and Upgrading (1) | 432,203 | 374,500 | 394,382 | 407,695 | 419,161 | |||||
North Sea | 27,454 | 27,594 | 28,702 | 26,927 | 24,940 | |||||
Offshore Africa | 21,227 | 23,650 | 18,802 | 22,341 | 18,812 | |||||
931,546 | 770,409 | 801,742 | 829,031 | 816,539 | ||||||
Natural gas (MMcf/d) | ||||||||||
North America | 1,425 | 1,482 | 1,489 | 1,454 | 1,506 | |||||
North Sea | 20 | 23 | 38 | 24 | 35 | |||||
Offshore Africa | 24 | 27 | 26 | 26 | 27 | |||||
1,469 | 1,532 | 1,553 | 1,504 | 1,568 | ||||||
Total barrels of oil equivalent (BOE/d) | 1,176,361 | 1,025,800 | 1,060,629 | 1,079,641 | 1,077,953 | |||||
Product mix | ||||||||||
Light and medium crude oil and NGLs | 12% | 15% | 13% | 14% | 13% | |||||
Pelican Lake heavy crude oil | 5% | 5% | 6% | 5% | 6% | |||||
Primary heavy crude oil | 8% | 8% | 9% | 7% | 8% | |||||
Bitumen (thermal oil) | 18% | 11% | 11% | 13% | 10% | |||||
Synthetic crude oil | 36% | 36% | 37% | 38% | 39% | |||||
Natural gas | 21% | 25% | 24% | 23% | 24% | |||||
Percentage of gross revenue (1) (2) | ||||||||||
(excluding Midstream and Refining revenue) | ||||||||||
Crude oil and NGLs | 97% | 95% | 95% | 94% | 94% | |||||
Natural gas | 3% | 5% | 5% | 6% | 6% |
(1) | SCO production before royalties excludes SCO consumed internally as diesel. |
(2) | Net of blending costs and excluding risk management activities. |
Canadian Natural Resources Limited | 9 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | |||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||
Crude oil and NGLs (bbl/d) | ||||||||||
North America – Exploration and Production | 397,456 | 307,413 | 307,668 | 329,126 | 303,833 | |||||
North America – Oil Sands Mining and Upgrading | 407,592 | 354,975 | 372,521 | 386,771 | 400,444 | |||||
North Sea | 27,399 | 27,525 | 28,609 | 26,873 | 24,873 | |||||
Offshore Africa | 20,095 | 22,694 | 17,264 | 21,016 | 17,467 | |||||
852,542 | 712,607 | 726,062 | 763,786 | 746,617 | ||||||
Natural gas (MMcf/d) | ||||||||||
North America | 1,421 | 1,427 | 1,455 | 1,416 | 1,445 | |||||
North Sea | 20 | 23 | 38 | 24 | 35 | |||||
Offshore Africa | 22 | 25 | 22 | 23 | 23 | |||||
1,463 | 1,475 | 1,515 | 1,463 | 1,503 | ||||||
Total barrels of oil equivalent (BOE/d) | 1,096,329 | 958,499 | 978,481 | 1,007,669 | 997,044 |
Canadian Natural Resources Limited | 10 | Nine Months Ended September 30, 2019 |
Canadian Natural Resources Limited | 11 | Nine Months Ended September 30, 2019 |
(bbl) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | |||
North Sea | 871,362 | 969,651 | 881,768 | |||
Offshore Africa | 309,443 | 1,076,772 | 868,589 | |||
1,180,805 | 2,046,423 | 1,750,357 |
Canadian Natural Resources Limited | 12 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||||||
Crude oil and NGLs ($/bbl) (1) | |||||||||||||||||||||
Sales price (2) | $ | 55.19 | $ | 63.45 | $ | 57.89 | $ | 57.49 | $ | 54.26 | |||||||||||
Transportation | 3.69 | 3.35 | 3.00 | 3.47 | 3.13 | ||||||||||||||||
Realized sales price, net of transportation | 51.50 | 60.10 | 54.89 | 54.02 | 51.13 | ||||||||||||||||
Royalties | 6.02 | 6.35 | 7.08 | 6.11 | 6.54 | ||||||||||||||||
Production expense | 13.25 | 14.42 | 14.47 | 14.39 | 15.25 | ||||||||||||||||
Netback | $ | 32.23 | $ | 39.33 | $ | 33.34 | $ | 33.52 | $ | 29.34 | |||||||||||
Natural gas ($/Mcf) (1) | |||||||||||||||||||||
Sales price (2) | $ | 1.64 | $ | 1.98 | $ | 2.32 | $ | 2.24 | $ | 2.34 | |||||||||||
Transportation | 0.40 | 0.40 | 0.42 | 0.42 | 0.47 | ||||||||||||||||
Realized sales price, net of transportation | 1.24 | 1.58 | 1.90 | 1.82 | 1.87 | ||||||||||||||||
Royalties | 0.01 | 0.08 | 0.05 | 0.07 | 0.08 | ||||||||||||||||
Production expense | 1.12 | 1.23 | 1.33 | 1.23 | 1.38 | ||||||||||||||||
Netback | $ | 0.11 | $ | 0.27 | $ | 0.52 | $ | 0.52 | $ | 0.41 | |||||||||||
Barrels of oil equivalent ($/BOE) (1) | |||||||||||||||||||||
Sales price (2) | $ | 40.36 | $ | 43.38 | $ | 40.77 | $ | 41.02 | $ | 38.20 | |||||||||||
Transportation | 3.27 | 2.97 | 2.83 | 3.11 | 3.03 | ||||||||||||||||
Realized sales price, net of transportation | 37.09 | 40.41 | 37.94 | 37.91 | 35.17 | ||||||||||||||||
Royalties | 4.07 | 4.06 | 4.44 | 3.98 | 4.10 | ||||||||||||||||
Production expense | 11.11 | 11.68 | 11.91 | 11.76 | 12.44 | ||||||||||||||||
Netback | $ | 21.91 | $ | 24.67 | $ | 21.59 | $ | 22.17 | $ | 18.63 |
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
Canadian Natural Resources Limited | 13 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||||||
Crude oil and NGLs ($/bbl) (1) (2) | |||||||||||||||||||||
North America | $ | 51.51 | $ | 59.45 | $ | 52.45 | $ | 53.83 | $ | 50.05 | |||||||||||
North Sea | $ | 83.64 | $ | 88.25 | $ | 97.77 | $ | 86.25 | $ | 91.67 | |||||||||||
Offshore Africa | $ | 82.97 | $ | 95.33 | $ | 98.66 | $ | 86.79 | $ | 96.55 | |||||||||||
Average | $ | 55.19 | $ | 63.45 | $ | 57.89 | $ | 57.49 | $ | 54.26 | |||||||||||
Natural gas ($/Mcf) (1) (2) | |||||||||||||||||||||
North America | $ | 1.51 | $ | 1.84 | $ | 1.96 | $ | 2.07 | $ | 2.04 | |||||||||||
North Sea | $ | 4.67 | $ | 5.34 | $ | 12.67 | $ | 7.03 | $ | 11.65 | |||||||||||
Offshore Africa | $ | 7.08 | $ | 6.94 | $ | 7.78 | $ | 7.12 | $ | 7.35 | |||||||||||
Average | $ | 1.64 | $ | 1.98 | $ | 2.32 | $ | 2.24 | $ | 2.34 | |||||||||||
Average ($/BOE) (1) (2) | $ | 40.36 | $ | 43.38 | $ | 40.77 | $ | 41.02 | $ | 38.20 |
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
Three Months Ended | ||||||||||||
(Quarterly Average) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | |||||||||
Wellhead Price (1) (2) | ||||||||||||
Light and medium crude oil and NGLs ($/bbl) | $ | 48.21 | $ | 53.23 | $ | 62.81 | ||||||
Pelican Lake heavy crude oil ($/bbl) | $ | 56.75 | $ | 66.71 | $ | 54.57 | ||||||
Primary heavy crude oil ($/bbl) | $ | 55.47 | $ | 64.71 | $ | 50.91 | ||||||
Bitumen (thermal oil) ($/bbl) | $ | 49.80 | $ | 57.61 | $ | 43.54 | ||||||
Natural gas ($/Mcf) | $ | 1.51 | $ | 1.84 | $ | 1.96 |
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
Canadian Natural Resources Limited | 14 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||||||
Crude oil and NGLs ($/bbl) (1) | |||||||||||||||||||||
North America | $ | 6.50 | $ | 6.99 | $ | 7.44 | $ | 6.57 | $ | 6.87 | |||||||||||
North Sea | $ | 0.17 | $ | 0.22 | $ | 0.31 | $ | 0.18 | $ | 0.23 | |||||||||||
Offshore Africa | $ | 4.43 | $ | 3.85 | $ | 8.07 | $ | 4.77 | $ | 7.72 | |||||||||||
Average | $ | 6.02 | $ | 6.35 | $ | 7.08 | $ | 6.11 | $ | 6.54 | |||||||||||
Natural gas ($/Mcf) (1) | |||||||||||||||||||||
North America | $ | 0.01 | $ | 0.07 | $ | 0.04 | $ | 0.06 | $ | 0.06 | |||||||||||
Offshore Africa | $ | 0.63 | $ | 0.59 | $ | 1.20 | $ | 0.69 | $ | 1.07 | |||||||||||
Average | $ | 0.01 | $ | 0.08 | $ | 0.05 | $ | 0.07 | $ | 0.08 | |||||||||||
Average ($/BOE) (1) | $ | 4.07 | $ | 4.06 | $ | 4.44 | $ | 3.98 | $ | 4.10 |
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited | 15 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||||||
Crude oil and NGLs ($/bbl) (1) | |||||||||||||||||||||
North America | $ | 11.86 | $ | 13.10 | $ | 12.67 | $ | 13.16 | $ | 13.52 | |||||||||||
North Sea | $ | 37.11 | $ | 37.31 | $ | 37.32 | $ | 37.78 | $ | 37.84 | |||||||||||
Offshore Africa | $ | 11.06 | $ | 8.40 | $ | 19.53 | $ | 9.87 | $ | 23.03 | |||||||||||
Average | $ | 13.25 | $ | 14.42 | $ | 14.47 | $ | 14.39 | $ | 15.25 | |||||||||||
Natural gas ($/Mcf) (1) | |||||||||||||||||||||
North America | $ | 1.07 | $ | 1.15 | $ | 1.20 | $ | 1.17 | $ | 1.26 | |||||||||||
North Sea (2) | $ | 3.08 | $ | 5.09 | $ | 5.22 | $ | 3.45 | $ | 5.20 | |||||||||||
Offshore Africa (2) | $ | 2.78 | $ | 2.49 | $ | 2.69 | $ | 2.45 | $ | 2.69 | |||||||||||
Average | $ | 1.12 | $ | 1.23 | $ | 1.33 | $ | 1.23 | $ | 1.38 | |||||||||||
Average ($/BOE) (1) | $ | 11.11 | $ | 11.68 | $ | 11.91 | $ | 11.76 | $ | 12.44 |
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | North Sea and Offshore Africa natural gas production expense for the nine months ended September 30, 2019 reflected a decrease of $17 million ($2.72 per Mcf) and $4 million ($0.49 per Mcf) respectively, related to the adoption of IFRS 16. |
Canadian Natural Resources Limited | 16 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions, except per BOE amounts) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Expense | $ | 1,021 | $ | 929 | $ | 917 | $ | 2,793 | $ | 2,661 | |||||||||||
$/BOE (1) | $ | 14.89 | $ | 15.60 | $ | 15.11 | $ | 15.32 | $ | 14.99 |
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions, except per BOE amounts) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Expense | $ | 34 | $ | 31 | $ | 31 | $ | 93 | $ | 94 | |||||||||||
$/BOE (1) | $ | 0.51 | $ | 0.49 | $ | 0.52 | $ | 0.51 | $ | 0.53 |
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited | 17 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($/bbl) (1) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
SCO realized sales price (2) | $ | 71.60 | $ | 74.98 | $ | 81.69 | $ | 70.64 | $ | 77.61 | |||||||||||
Bitumen value for royalty purposes (3) | $ | 51.70 | $ | 58.74 | $ | 51.64 | $ | 52.64 | $ | 43.64 | |||||||||||
Bitumen royalties (4) | $ | 3.76 | $ | 3.79 | $ | 4.31 | $ | 3.27 | $ | 3.46 | |||||||||||
Transportation | $ | 1.16 | $ | 1.53 | $ | 1.73 | $ | 1.28 | $ | 1.63 |
(1) | Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods. |
(2) | Net of blending and feedstock costs. |
(3) | Calculated as the quarterly average of the bitumen valuation methodology price. |
(4) | Calculated based on bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes. |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Production costs | $ | 784 | $ | 814 | $ | 842 | $ | 2,420 | $ | 2,570 | |||||||||||
Less: costs incurred during turnaround periods | (48 | ) | — | (109 | ) | (48 | ) | (109 | ) | ||||||||||||
Adjusted production costs | $ | 736 | $ | 814 | $ | 733 | $ | 2,372 | $ | 2,461 | |||||||||||
Adjusted production costs, excluding natural gas costs | $ | 721 | $ | 789 | $ | 714 | $ | 2,289 | $ | 2,383 | |||||||||||
Natural gas costs | 15 | 25 | 19 | 83 | 78 | ||||||||||||||||
Adjusted production costs | $ | 736 | $ | 814 | $ | 733 | $ | 2,372 | $ | 2,461 |
Canadian Natural Resources Limited | 18 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($/bbl) (1) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Adjusted production costs, excluding natural gas costs | $ | 18.43 | $ | 23.45 | $ | 19.43 | $ | 20.60 | $ | 20.74 | |||||||||||
Natural gas costs | 0.39 | 0.72 | 0.52 | 0.75 | 0.69 | ||||||||||||||||
Adjusted production costs | $ | 18.82 | $ | 24.17 | $ | 19.95 | $ | 21.35 | $ | 21.43 | |||||||||||
Sales (bbl/d) | 425,140 | 369,846 | 399,514 | 406,923 | 420,790 |
(1) | Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods. |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions, except per bbl amounts) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Expense | $ | 401 | $ | 374 | $ | 385 | $ | 1,192 | $ | 1,161 | |||||||||||
Less: depreciation incurred during turnaround period | (22 | ) | — | (56 | ) | (22 | ) | (56 | ) | ||||||||||||
Adjusted depletion, depreciation and amortization | $ | 379 | $ | 374 | $ | 329 | $ | 1,170 | $ | 1,105 | |||||||||||
$/bbl (1) | $ | 9.68 | $ | 11.12 | $ | 8.96 | $ | 10.53 | $ | 9.62 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions, except per bbl amounts) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Expense | $ | 16 | $ | 15 | $ | 16 | $ | 47 | $ | 46 | |||||||||||
$/bbl (1) | $ | 0.38 | $ | 0.46 | $ | 0.41 | $ | 0.41 | $ | 0.40 |
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited | 19 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Revenue | $ | 21 | $ | 20 | $ | 26 | $ | 62 | $ | 78 | |||||||||||
Less: | |||||||||||||||||||||
Production expense | 4 | 5 | 5 | 15 | 16 | ||||||||||||||||
Depreciation | 4 | 4 | 4 | 11 | 11 | ||||||||||||||||
Equity loss from investment | 88 | 66 | 2 | 214 | 5 | ||||||||||||||||
Segment earnings (loss) before taxes | $ | (75 | ) | $ | (55 | ) | $ | 15 | $ | (178 | ) | $ | 46 |
Canadian Natural Resources Limited | 20 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions, except per BOE amounts) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Expense | $ | 95 | $ | 84 | $ | 77 | $ | 249 | $ | 234 | |||||||||||
$/BOE (1) | $ | 0.88 | $ | 0.90 | $ | 0.79 | $ | 0.85 | $ | 0.80 |
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Expense (recovery) | $ | 7 | $ | (7 | ) | $ | (85 | ) | $ | 62 | $ | 2 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions, except per BOE amounts and interest rates) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Expense, gross | $ | 239 | $ | 214 | $ | 198 | $ | 664 | $ | 610 | |||||||||||
Less: capitalized interest | 8 | 17 | 18 | 45 | 50 | ||||||||||||||||
Expense, net | $ | 231 | $ | 197 | $ | 180 | $ | 619 | $ | 560 | |||||||||||
$/BOE (1) | $ | 2.14 | $ | 2.12 | $ | 1.85 | $ | 2.11 | $ | 1.92 | |||||||||||
Average effective interest rate | 3.9% | 4.1% | 4.0% | 4.0% | 3.9% |
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited | 21 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Crude oil and NGLs financial instruments | $ | 11 | $ | 13 | $ | — | $ | 52 | $ | — | |||||||||||
Natural gas financial instruments | (4 | ) | (2 | ) | 6 | (7 | ) | 3 | |||||||||||||
Foreign currency contracts | (8 | ) | 16 | (14 | ) | 8 | (57 | ) | |||||||||||||
Realized (gain) loss | (1 | ) | 27 | (8 | ) | 53 | (54 | ) | |||||||||||||
Crude oil and NGLs financial instruments | (7 | ) | (15 | ) | (25 | ) | (17 | ) | (25 | ) | |||||||||||
Natural gas financial instruments | 7 | 1 | (14 | ) | 8 | 2 | |||||||||||||||
Foreign currency contracts | (2 | ) | (2 | ) | 18 | 5 | (39 | ) | |||||||||||||
Unrealized gain | (2 | ) | (16 | ) | (21 | ) | (4 | ) | (62 | ) | |||||||||||
Net (gain) loss | $ | (3 | ) | $ | 11 | $ | (29 | ) | $ | 49 | $ | (116 | ) |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Net realized (gain) loss | $ | (14 | ) | $ | 2 | $ | 14 | $ | (18 | ) | $ | 123 | |||||||||
Net unrealized loss (gain) | 129 | (219 | ) | (182 | ) | (323 | ) | 158 | |||||||||||||
Net loss (gain) (1) | $ | 115 | $ | (217 | ) | $ | (168 | ) | $ | (341 | ) | $ | 281 |
(1) | Amounts are reported net of the hedging effect of cross currency swaps. |
Canadian Natural Resources Limited | 22 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions, except income tax rates) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
North America (1) | $ | 133 | $ | 78 | $ | 169 | $ | 374 | $ | 566 | |||||||||||
North Sea | 15 | 28 | 12 | 72 | 20 | ||||||||||||||||
Offshore Africa | 14 | 11 | 22 | 37 | 43 | ||||||||||||||||
PRT (2) – North Sea | (4 | ) | (43 | ) | (9 | ) | (89 | ) | (29 | ) | |||||||||||
Other taxes | 3 | 3 | 3 | 9 | 8 | ||||||||||||||||
Current income tax expense | 161 | 77 | 197 | 403 | 608 | ||||||||||||||||
Deferred corporate income tax expense (recovery) | 176 | (1,359 | ) | 145 | (1,089 | ) | 428 | ||||||||||||||
Deferred PRT (2) – North Sea | — | 1 | 1 | 1 | 18 | ||||||||||||||||
Deferred income tax expense (recovery) | 176 | (1,358 | ) | 146 | (1,088 | ) | 446 | ||||||||||||||
337 | (1,281 | ) | 343 | (685 | ) | 1,054 | |||||||||||||||
Income tax rate and other legislative changes | — | 1,618 | — | 1,618 | — | ||||||||||||||||
$ | 337 | $ | 337 | $ | 343 | $ | 933 | $ | 1,054 | ||||||||||||
Effective income tax rate on adjusted net earnings from operations (3) | 22 | % | 26 | % | 19 | % | 25 | % | 22 | % |
(1) | Includes North America Exploration and Production, Midstream and Refining, and Oil Sands Mining and Upgrading segments. |
(2) | Petroleum Revenue Tax |
(3) | Excludes the impact of current and deferred PRT expense and other current income tax expense. |
Canadian Natural Resources Limited | 23 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Exploration and Evaluation | |||||||||||||||||||||
Net property (dispositions) acquisitions (2) | $ | (2 | ) | $ | 91 | $ | 41 | $ | 90 | $ | 39 | ||||||||||
Net expenditures | 5 | 37 | 38 | 74 | 104 | ||||||||||||||||
Total Exploration and Evaluation | 3 | 128 | 79 | 164 | 143 | ||||||||||||||||
Property, Plant and Equipment | |||||||||||||||||||||
Net property acquisitions (2) | 30 | 3,134 | 5 | 3,188 | 97 | ||||||||||||||||
Well drilling, completion and equipping | 181 | 171 | 416 | 606 | 1,087 | ||||||||||||||||
Production and related facilities | 232 | 271 | 325 | 790 | 897 | ||||||||||||||||
Capitalized interest and other (3) | 14 | 23 | 26 | 66 | 74 | ||||||||||||||||
Total Property, Plant and Equipment | 457 | 3,599 | 772 | 4,650 | 2,155 | ||||||||||||||||
Total Exploration and Production | 460 | 3,727 | 851 | 4,814 | 2,298 | ||||||||||||||||
Oil Sands Mining and Upgrading | |||||||||||||||||||||
Project costs (4) | 133 | 106 | 131 | 315 | 260 | ||||||||||||||||
Sustaining capital | 249 | 210 | 173 | 599 | 430 | ||||||||||||||||
Turnaround costs | 36 | 17 | 41 | 61 | 100 | ||||||||||||||||
Acquisitions of Exploration and Evaluation assets (5) | — | — | 218 | — | 218 | ||||||||||||||||
Capitalized interest and other (3) | 10 | 9 | (3 | ) | 29 | 22 | |||||||||||||||
Total Oil Sands Mining and Upgrading | 428 | 342 | 560 | 1,004 | 1,030 | ||||||||||||||||
Midstream and Refining | 4 | 3 | 2 | 9 | 11 | ||||||||||||||||
Abandonments (6) | 63 | 41 | 57 | 212 | 197 | ||||||||||||||||
Head office | 8 | 12 | 3 | 26 | 14 | ||||||||||||||||
Total net capital expenditures | $ | 963 | $ | 4,125 | $ | 1,473 | $ | 6,065 | $ | 3,550 | |||||||||||
By segment | |||||||||||||||||||||
North America (2) | $ | 365 | $ | 3,612 | $ | 727 | $ | 4,501 | $ | 2,067 | |||||||||||
North Sea | 55 | 42 | 35 | 133 | 73 | ||||||||||||||||
Offshore Africa | 40 | 73 | 89 | 180 | 158 | ||||||||||||||||
Oil Sands Mining and Upgrading (5) | 428 | 342 | 560 | 1,004 | 1,030 | ||||||||||||||||
Midstream and Refining | 4 | 3 | 2 | 9 | 11 | ||||||||||||||||
Abandonments (6) | 63 | 41 | 57 | 212 | 197 | ||||||||||||||||
Head office | 8 | 12 | 3 | 26 | 14 | ||||||||||||||||
Total | $ | 963 | $ | 4,125 | $ | 1,473 | $ | 6,065 | $ | 3,550 |
(1) | Net capital expenditures exclude the impact of lease assets and fair value and revaluation adjustments, and include non-cash transfers of property, plant and equipment to inventory due to change in use. |
(2) | Includes cash consideration paid of $91 million for exploration and evaluation assets and $3,126 million for property, plant and equipment acquired from Devon in the second quarter of 2019. |
(3) | Capitalized interest and other includes expenditures related to land acquisition and retention, seismic, and other adjustments. |
(4) | Includes Horizon Phase 2/3 construction costs. |
(5) | In the third quarter of 2018, total purchase consideration for the acquisition of the Joslyn oil sands project included $222 million for exploration and evaluation assets and $4 million for asset retirement obligations assumed. |
(6) | Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table. |
Canadian Natural Resources Limited | 24 | Nine Months Ended September 30, 2019 |
Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities | |||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
($ millions) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||||
Cash flows used in investing activities | $ | 908 | $ | 4,464 | $ | 1,265 | $ | 6,401 | $ | 3,772 | |||||||||||
Net change in non-cash working capital (1) | (8 | ) | (380 | ) | 151 | (548 | ) | (391 | ) | ||||||||||||
Investment in other long-term assets | — | — | — | — | (28 | ) | |||||||||||||||
Abandonment expenditures (2) | 63 | 41 | 57 | 212 | 197 | ||||||||||||||||
Net capital expenditures | $ | 963 | $ | 4,125 | $ | 1,473 | $ | 6,065 | $ | 3,550 |
(1) | Includes net working capital and other long-term assets of $195 million related to the acquisition of assets from Devon in the second quarter of 2019. |
(2) | The Company excludes abandonment expenditures from “Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities” in the "Financial Highlights" section of this MD&A. |
Three Months Ended | Nine Months Ended | ||||||||||||||
(number of net wells) | Sep 30 2019 | Jun 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||
Net successful natural gas wells | 5 | 2 | 6 | 15 | 15 | ||||||||||
Net successful crude oil wells (2) | 36 | 8 | 178 | 74 | 381 | ||||||||||
Dry wells | — | 2 | 5 | 3 | 7 | ||||||||||
Stratigraphic test / service wells | 23 | 3 | 47 | 358 | 524 | ||||||||||
Total | 64 | 15 | 236 | 450 | 927 | ||||||||||
Success rate (excluding stratigraphic test / service wells) | 100% | 83% | 97% | 97% | 98% |
(1) | Includes drilling activity for North America and International segments. |
(2) | Includes bitumen wells. |
Canadian Natural Resources Limited | 25 | Nine Months Ended September 30, 2019 |
($ millions, except ratios) | Sep 30 2019 | Jun 30 2019 | Dec 31 2018 | Sep 30 2018 | ||||||||||||
Working capital (1) | $ | 859 | $ | 709 | $ | (601 | ) | $ | 111 | |||||||
Long-term debt (2) (3) | $ | 22,489 | $ | 23,507 | $ | 20,623 | $ | 19,733 | ||||||||
Less: cash and cash equivalents | 176 | 398 | 101 | 296 | ||||||||||||
Long-term debt, net | $ | 22,313 | $ | 23,109 | $ | 20,522 | $ | 19,437 | ||||||||
Share capital | $ | 9,314 | $ | 9,320 | $ | 9,323 | $ | 9,393 | ||||||||
Retained earnings | 25,382 | 24,927 | 22,529 | 24,033 | ||||||||||||
Accumulated other comprehensive income (loss) | 98 | 27 | 122 | (33 | ) | |||||||||||
Shareholders’ equity | $ | 34,794 | $ | 34,274 | $ | 31,974 | $ | 33,393 | ||||||||
Debt to book capitalization (3) (4) | 39.1% | 40.3% | 39.1% | 36.8% | ||||||||||||
Debt to market capitalization (3) (5) | 34.8% | 35.4% | 34.1% | 27.4% | ||||||||||||
After-tax return on average common shareholders’ equity (6) | 12.1% | 14.7% | 8.0% | 11.6% | ||||||||||||
After-tax return on average capital employed (3) (7) | 8.4% | 9.9% | 5.9% | 8.0% |
(1) | Calculated as current assets less current liabilities, excluding the current portion of long-term debt. |
(2) | Includes the current portion of long-term debt. |
(3) | Long-term debt is stated at its carrying value, net of fair value adjustments, original issue discounts and premiums and transaction costs. |
(4) | Calculated as net current and long-term debt; divided by the book value of common shareholders’ equity plus net current and long-term debt. |
(5) | Calculated as net current and long-term debt; divided by the market value of common shareholders’ equity plus net current and long-term debt. |
(6) | Calculated as net earnings (loss) for the twelve month trailing period; as a percentage of average common shareholders’ equity for the twelve month trailing period. |
(7) | Calculated as net earnings (loss) plus after-tax interest and other financing expense for the twelve month trailing period; as a percentage of average capital employed for the twelve month trailing period. |
▪ | Monitoring cash flows from operating activities, which is the primary source of funds; |
▪ | Actively managing the allocation of maintenance and growth capital to ensure it is expended in a prudent and appropriate manner with flexibility to adjust to market conditions. The Company continues to exercise its capital flexibility to address commodity price volatility and its impact on operating expenditures, capital commitments and long-term debt; |
▪ | Reviewing the Company's borrowing capacity: |
◦ | During the third quarter of 2019, the Company repaid and cancelled $800 million of the $1,800 million non-revolving term credit facility scheduled to mature in May 2020. Subsequent to September 30, 2019, the Company repaid and cancelled an additional $500 million of the remaining $1,000 million outstanding on this non-revolving term credit facility. |
Canadian Natural Resources Limited | 26 | Nine Months Ended September 30, 2019 |
◦ | During the second quarter of 2019, the Company entered into a $3,250 million non-revolving term credit facility to finance the acquisition of assets from Devon. The facility matures in June 2022 and is subject to annual amortization of 5% of the original balance. |
◦ | Borrowings under the Company's non-revolving term credit facilities may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers’ acceptances, LIBOR, US base rate or Canadian prime rate. As at September 30, 2019, the non-revolving term credit facilities were fully drawn. |
◦ | During the second quarter of 2019, the Company extended $330 million of the $2,425 million revolving syndicated credit facility originally due June 2019 to June 2021. The remaining $2,095 million outstanding under this facility continues under the previous terms and matures in June 2021.The other $2,425 million revolving credit facility matures in June 2022. Each of the $2,425 million revolving credit facilities is extendible annually at the mutual agreement of the Company and the lenders. If the facilities are not extended, the full amount of the outstanding principal is repayable on the maturity date. Borrowings under these facilities may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers' acceptances, LIBOR, US base rate or Canadian prime rate. |
◦ | During the second quarter of 2019, the Company repaid $500 million of 3.05% medium-term notes. |
◦ | The Company’s borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million. The Company reserves capacity under its revolving bank credit facilities for amounts outstanding under this program. |
◦ | In July 2019, the Company filed new base shelf prospectuses that allow for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada and US$3,000 million of debt securities in the United States, expiring in August 2021, and replacing the Company's previous base shelf prospectuses, which would have expired in August 2019. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance. |
▪ | Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages; and |
▪ | Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place, and as applicable, taking other mitigating actions to minimize the impact in the event of a default. |
Canadian Natural Resources Limited | 27 | Nine Months Ended September 30, 2019 |
Less than 1 year | 1 to less than 2 years | 2 to less than 5 years | Thereafter | ||||||||||||
Long-term debt (1) | $ | 4,040 | $ | 3,112 | $ | 7,067 | $ | 8,383 | |||||||
Other long-term liabilities (2) | $ | 273 | $ | 205 | $ | 435 | $ | 1,041 | |||||||
Interest and other financing expense (3) | $ | 936 | $ | 786 | $ | 1,771 | $ | 5,038 |
(1) | Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs. |
(2) | Lease payments included within other long-term liabilities reflect principal payments only and are as follows: less than one year, $244 million; one to less than two years, $180 million; two to less than five years, $390 million; and thereafter, $1,041 million. |
(3) | Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates as at September 30, 2019. |
($ millions) | Remaining 2019 | 2020 | 2021 | 2022 | 2023 | Thereafter | |||||||||||||||||
Product transportation (2) | $ | 177 | $ | 719 | $ | 688 | $ | 615 | $ | 502 | $ | 4,722 | |||||||||||
North West Redwater Partnership service toll (3) | $ | 17 | $ | 118 | $ | 163 | $ | 148 | $ | 158 | $ | 2,854 | |||||||||||
Offshore vessels and equipment | $ | 26 | $ | 70 | $ | 64 | $ | 9 | $ | — | $ | — | |||||||||||
Field equipment and power | $ | 13 | $ | 20 | $ | 21 | $ | 20 | $ | 21 | $ | 274 | |||||||||||
Other | $ | 7 | $ | 25 | $ | 21 | $ | 18 | $ | 17 | $ | 48 |
(1) | Subsequent to adoption of IFRS 16, the Company reports its payments for lease liabilities in the maturity table in the 'Liquidity and Capital Resources' section of this MD&A. |
(2) | On June 27, 2019, the Company assumed $2,381 million of product transportation commitments related to the acquisition of assets from Devon. |
(3) | Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt portion of the monthly cost of service toll, currently consisting of interest and fees, with principal repayments beginning in 2020. Included in the cost of service toll is $1,126 million of interest payable over the 30 year tolling period. |
Canadian Natural Resources Limited | 28 | Nine Months Ended September 30, 2019 |
• | the use of a single discount rate to a portfolio of leases with reasonably similar characteristics; |
• | leases with a remaining lease term of less than twelve months as at January 1, 2019 were treated as short-term leases; |
• | exclusion of initial direct costs for the measurement of lease assets at the date of initial application; and |
• | the application of the Company's previous assessment for onerous contracts under IAS 37, instead of re-assessing impairment on the Company's lease assets as at January 1, 2019. |
• | Cash flow from operating activities and adjusted funds flow increased as the principal portion of lease payments, previously classified as cash flows from operating activities is now reported as a financing activity; |
• | Increased depletion, depreciation and amortization expense and interest expense; |
• | Decreased production expense, transportation expense and administration expense; and |
• | Commitments for leases, previously reported in the "Commitments and Contingencies" section of this MD&A, are now reported in the maturity table in the "Liquidity and Capital Resources" section of this MD&A. |
Canadian Natural Resources Limited | 29 | Nine Months Ended September 30, 2019 |
Canadian Natural Resources Limited | 30 | Nine Months Ended September 30, 2019 |
As at | Note | Sep 30 2019 | Dec 31 2018 | ||||||
(millions of Canadian dollars, unaudited) | |||||||||
ASSETS | |||||||||
Current assets | |||||||||
Cash and cash equivalents | $ | 176 | $ | 101 | |||||
Accounts receivable | 2,405 | 1,148 | |||||||
Inventory | 1,151 | 955 | |||||||
Prepaids and other | 309 | 176 | |||||||
Investments | 6 | 567 | 524 | ||||||
Current portion of other long-term assets | 7 | 70 | 116 | ||||||
4,678 | 3,020 | ||||||||
Exploration and evaluation assets | 3 | 2,616 | 2,637 | ||||||
Property, plant and equipment | 4 | 68,088 | 64,559 | ||||||
Lease assets | 5 | 1,839 | — | ||||||
Other long-term assets | 7 | 1,311 | 1,343 | ||||||
$ | 78,532 | $ | 71,559 | ||||||
LIABILITIES | |||||||||
Current liabilities | |||||||||
Accounts payable | $ | 662 | $ | 779 | |||||
Accrued liabilities | 2,561 | 2,356 | |||||||
Current income taxes payable | 85 | 151 | |||||||
Current portion of long-term debt | 8 | 4,036 | 1,141 | ||||||
Current portion of other long-term liabilities | 5,9 | 511 | 335 | ||||||
7,855 | 4,762 | ||||||||
Long-term debt | 8 | 18,453 | 19,482 | ||||||
Other long-term liabilities | 5,9 | 7,075 | 3,890 | ||||||
Deferred income taxes | 10,355 | 11,451 | |||||||
43,738 | 39,585 | ||||||||
SHAREHOLDERS’ EQUITY | |||||||||
Share capital | 11 | 9,314 | 9,323 | ||||||
Retained earnings | 25,382 | 22,529 | |||||||
Accumulated other comprehensive income | 12 | 98 | 122 | ||||||
34,794 | 31,974 | ||||||||
$ | 78,532 | $ | 71,559 |
Canadian Natural Resources Limited | 1 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | |||||||||||||||||
(millions of Canadian dollars, except per common share amounts, unaudited) | Note | Sep 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||
Product sales | 17 | $ | 6,587 | $ | 6,327 | $ | 18,059 | $ | 18,451 | |||||||||
Less: royalties | (427 | ) | (428 | ) | (1,089 | ) | (1,126 | ) | ||||||||||
Revenue | 6,160 | 5,899 | 16,970 | 17,325 | ||||||||||||||
Expenses | ||||||||||||||||||
Production | 1,566 | 1,585 | 4,629 | 4,837 | ||||||||||||||
Transportation, blending and feedstock | 1,248 | 1,031 | 3,283 | 3,325 | ||||||||||||||
Depletion, depreciation and amortization | 4,5 | 1,426 | 1,306 | 3,996 | 3,833 | |||||||||||||
Administration | 95 | 77 | 249 | 234 | ||||||||||||||
Share-based compensation | 9 | 7 | (85 | ) | 62 | 2 | ||||||||||||
Asset retirement obligation accretion | 9 | 50 | 47 | 140 | 140 | |||||||||||||
Interest and other financing expense | 231 | 180 | 619 | 560 | ||||||||||||||
Risk management activities | 15 | (3 | ) | (29 | ) | 49 | (116 | ) | ||||||||||
Foreign exchange loss (gain) | 115 | (168 | ) | (341 | ) | 281 | ||||||||||||
Gain on acquisition and revaluation of properties | — | (272 | ) | — | (411 | ) | ||||||||||||
Loss from investments | 6,7 | 61 | 82 | 150 | 219 | |||||||||||||
4,796 | 3,754 | 12,836 | 12,904 | |||||||||||||||
Earnings before taxes | 1,364 | 2,145 | 4,134 | 4,421 | ||||||||||||||
Current income tax expense | 10 | 161 | 197 | 403 | 608 | |||||||||||||
Deferred income tax expense (recovery) | 10 | 176 | 146 | (1,088 | ) | 446 | ||||||||||||
Net earnings | $ | 1,027 | $ | 1,802 | $ | 4,819 | $ | 3,367 | ||||||||||
Net earnings per common share | ||||||||||||||||||
Basic | 14 | $ | 0.87 | $ | 1.48 | $ | 4.04 | $ | 2.75 | |||||||||
Diluted | 14 | $ | 0.87 | $ | 1.47 | $ | 4.03 | $ | 2.74 |
Three Months Ended | Nine Months Ended | ||||||||||||||||
(millions of Canadian dollars, unaudited) | Sep 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||
Net earnings | $ | 1,027 | $ | 1,802 | $ | 4,819 | $ | 3,367 | |||||||||
Items that may be reclassified subsequently to net earnings | |||||||||||||||||
Net change in derivative financial instruments designated as cash flow hedges | |||||||||||||||||
Unrealized income (loss) during the period, net of taxes of $6 million (2018 – $1 million) – three months ended; $12 million (2018 – $1 million) – nine months ended | 48 | 8 | 97 | (7 | ) | ||||||||||||
Reclassification to net earnings, net of taxes of $2 million (2018 – $2 million) – three months ended; $5 million (2018 – $5 million) – nine months ended | (13 | ) | (9 | ) | (36 | ) | (31 | ) | |||||||||
35 | (1 | ) | 61 | (38 | ) | ||||||||||||
Foreign currency translation adjustment | |||||||||||||||||
Translation of net investment | 36 | (44 | ) | (85 | ) | 73 | |||||||||||
Other comprehensive income (loss), net of taxes | 71 | (45 | ) | (24 | ) | 35 | |||||||||||
Comprehensive income | $ | 1,098 | $ | 1,757 | $ | 4,795 | $ | 3,402 |
Canadian Natural Resources Limited | 2 | Nine Months Ended September 30, 2019 |
Nine Months Ended | |||||||||
(millions of Canadian dollars, unaudited) | Note | Sep 30 2019 | Sep 30 2018 | ||||||
Share capital | 11 | ||||||||
Balance – beginning of period | $ | 9,323 | $ | 9,109 | |||||
Issued upon exercise of stock options | 148 | 320 | |||||||
Previously recognized liability on stock options exercised for common shares | 17 | 118 | |||||||
Purchase of common shares under Normal Course Issuer Bid | (174 | ) | (154 | ) | |||||
Balance – end of period | 9,314 | 9,393 | |||||||
Retained earnings | |||||||||
Balance – beginning of period | 22,529 | 22,612 | |||||||
Net earnings | 4,819 | 3,367 | |||||||
Purchase of common shares under Normal Course Issuer Bid | 11 | (627 | ) | (720 | ) | ||||
Dividends on common shares | 11 | (1,339 | ) | (1,226 | ) | ||||
Balance – end of period | 25,382 | 24,033 | |||||||
Accumulated other comprehensive income (loss) | 12 | ||||||||
Balance – beginning of period | 122 | (68 | ) | ||||||
Other comprehensive income (loss), net of taxes | (24 | ) | 35 | ||||||
Balance – end of period | 98 | (33 | ) | ||||||
Shareholders’ equity | $ | 34,794 | $ | 33,393 |
Canadian Natural Resources Limited | 3 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | |||||||||||||||||
(millions of Canadian dollars, unaudited) | Note | Sep 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||
Operating activities | ||||||||||||||||||
Net earnings | $ | 1,027 | $ | 1,802 | $ | 4,819 | $ | 3,367 | ||||||||||
Non-cash items | ||||||||||||||||||
Depletion, depreciation and amortization | 1,426 | 1,306 | 3,996 | 3,833 | ||||||||||||||
Share-based compensation | 7 | (85 | ) | 62 | 2 | |||||||||||||
Asset retirement obligation accretion | 50 | 47 | 140 | 140 | ||||||||||||||
Unrealized risk management gain | (2 | ) | (21 | ) | (4 | ) | (62 | ) | ||||||||||
Unrealized foreign exchange loss (gain) | 129 | (182 | ) | (323 | ) | 158 | ||||||||||||
Realized foreign exchange loss on repayment of US dollar debt securities | — | — | — | 146 | ||||||||||||||
Gain on acquisition and revaluation of properties | — | (272 | ) | — | (411 | ) | ||||||||||||
Loss from investments | 6,7 | 68 | 89 | 171 | 240 | |||||||||||||
Deferred income tax expense (recovery) | 176 | 146 | (1,088 | ) | 446 | |||||||||||||
Other | (1 | ) | (20 | ) | (101 | ) | (5 | ) | ||||||||||
Abandonment expenditures | (63 | ) | (57 | ) | (212 | ) | (197 | ) | ||||||||||
Net change in non-cash working capital | (299 | ) | 889 | (1,085 | ) | 1,067 | ||||||||||||
Cash flows from operating activities | 2,518 | 3,642 | 6,375 | 8,724 | ||||||||||||||
Financing activities | ||||||||||||||||||
(Repayment) issue of bank credit facilities and commercial paper, net | 8 | (1,182 | ) | (1,468 | ) | 2,726 | (1,847 | ) | ||||||||||
Repayment of medium-term notes | 8 | — | — | (500 | ) | — | ||||||||||||
Repayment of US dollar debt securities | — | — | — | (1,236 | ) | |||||||||||||
Payment of lease liabilities | 5 | (64 | ) | — | (173 | ) | — | |||||||||||
Issue of common shares on exercise of stock options | 30 | 47 | 148 | 320 | ||||||||||||||
Purchase of common shares under Normal Course Issuer Bid | (169 | ) | (433 | ) | (801 | ) | (874 | ) | ||||||||||
Dividends on common shares | (447 | ) | (409 | ) | (1,299 | ) | (1,156 | ) | ||||||||||
Cash flows (used in) from financing activities | (1,832 | ) | (2,263 | ) | 101 | (4,793 | ) | |||||||||||
Investing activities | ||||||||||||||||||
Net expenditures on exploration and evaluation assets | (3 | ) | (297 | ) | (73 | ) | (361 | ) | ||||||||||
Net expenditures on property, plant and equipment | (897 | ) | (1,119 | ) | (2,563 | ) | (2,992 | ) | ||||||||||
Acquisition of Devon assets | 4 | — | — | (3,412 | ) | — | ||||||||||||
Investment in other long-term assets | — | — | — | (28 | ) | |||||||||||||
Net change in non-cash working capital | (8 | ) | 151 | (353 | ) | (391 | ) | |||||||||||
Cash flows used in investing activities | (908 | ) | (1,265 | ) | (6,401 | ) | (3,772 | ) | ||||||||||
(Decrease) increase in cash and cash equivalents | (222 | ) | 114 | 75 | 159 | |||||||||||||
Cash and cash equivalents – beginning of period | 398 | 182 | 101 | 137 | ||||||||||||||
Cash and cash equivalents – end of period | $ | 176 | $ | 296 | $ | 176 | $ | 296 | ||||||||||
Interest paid on long-term debt, net | $ | 263 | $ | 224 | $ | 674 | $ | 707 | ||||||||||
Income taxes paid (received) | $ | 86 | $ | (118 | ) | $ | 372 | $ | (195 | ) |
Canadian Natural Resources Limited | 4 | Nine Months Ended September 30, 2019 |
• | the use of a single discount rate to a portfolio of leases with reasonably similar characteristics; |
• | leases with a remaining lease term of less than twelve months as at January 1, 2019 were treated as short-term leases; |
• | exclusion of initial direct costs for the measurement of lease assets at the date of initial application; and |
• | the application of the Company's previous assessment for onerous contracts under IAS 37, instead of re-assessing impairment on the Company's lease assets as at January 1, 2019. |
Canadian Natural Resources Limited | 5 | Nine Months Ended September 30, 2019 |
Canadian Natural Resources Limited | 6 | Nine Months Ended September 30, 2019 |
Exploration and Production | Oil Sands Mining and Upgrading | Total | |||||||||||||
North America | North Sea | Offshore Africa | |||||||||||||
Cost | |||||||||||||||
At December 31, 2018 | $ | 2,348 | $ | — | $ | 37 | $ | 252 | $ | 2,637 | |||||
Additions | 38 | — | 35 | — | 73 | ||||||||||
Acquisition of Devon assets (note 4) | 91 | — | — | — | 91 | ||||||||||
Transfers to property, plant and equipment | (185 | ) | — | — | — | (185 | ) | ||||||||
At September 30, 2019 | $ | 2,292 | $ | — | $ | 72 | $ | 252 | $ | 2,616 |
Exploration and Production | Oil Sands Mining and Upgrading | Midstream and Refining | Head Office | Total | |||||||||||||||||||||||
North America | North Sea | Offshore Africa | |||||||||||||||||||||||||
Cost | |||||||||||||||||||||||||||
At December 31, 2018 | $ | 67,007 | $ | 7,321 | $ | 5,471 | $ | 43,147 | $ | 441 | $ | 435 | $ | 123,822 | |||||||||||||
Additions | 2,170 | 237 | 171 | 1,316 | 9 | 26 | 3,929 | ||||||||||||||||||||
Acquisition of Devon assets | 3,325 | — | — | — | — | — | 3,325 | ||||||||||||||||||||
Transfers from E&E assets | 185 | — | — | — | — | — | 185 | ||||||||||||||||||||
Disposals/derecognitions and other | (393 | ) | — | (1,515 | ) | (166 | ) | — | (3 | ) | (2,077 | ) | |||||||||||||||
Foreign exchange adjustments and other | — | (219 | ) | (175 | ) | — | — | — | (394 | ) | |||||||||||||||||
At September 30, 2019 | $ | 72,294 | $ | 7,339 | $ | 3,952 | $ | 44,297 | $ | 450 | $ | 458 | $ | 128,790 | |||||||||||||
Accumulated depletion and depreciation | |||||||||||||||||||||||||||
At December 31, 2018 | $ | 43,881 | $ | 5,735 | $ | 4,203 | $ | 4,981 | $ | 138 | $ | 325 | $ | 59,263 | |||||||||||||
Expense | 2,309 | 174 | 172 | 1,126 | 11 | 18 | 3,810 | ||||||||||||||||||||
Disposals/derecognitions | (393 | ) | — | (1,515 | ) | (166 | ) | — | (3 | ) | (2,077 | ) | |||||||||||||||
Foreign exchange adjustments and other | (3 | ) | (152 | ) | (138 | ) | (1 | ) | — | — | (294 | ) | |||||||||||||||
At September 30, 2019 | $ | 45,794 | $ | 5,757 | $ | 2,722 | $ | 5,940 | $ | 149 | $ | 340 | $ | 60,702 | |||||||||||||
Net book value | |||||||||||||||||||||||||||
- at September 30, 2019 | $ | 26,500 | $ | 1,582 | $ | 1,230 | $ | 38,357 | $ | 301 | $ | 118 | $ | 68,088 | |||||||||||||
- at December 31, 2018 | $ | 23,126 | $ | 1,586 | $ | 1,268 | $ | 38,166 | $ | 303 | $ | 110 | $ | 64,559 |
Project costs not subject to depletion and depreciation | Sep 30 2019 | Dec 31 2018 | ||||||
Thermal Oil Sands | $ | 165 | $ | 1,424 |
Canadian Natural Resources Limited | 7 | Nine Months Ended September 30, 2019 |
Property, plant and equipment | $ | 3,325 | |
Exploration and evaluation assets | 91 | ||
Inventory, prepaids and other long-term assets | 195 | ||
Accrued liabilities | (21 | ) | |
Asset retirement obligations | (178 | ) | |
Net assets acquired | $ | 3,412 |
Canadian Natural Resources Limited | 8 | Nine Months Ended September 30, 2019 |
Product transportation and storage | Field equipment and power | Offshore vessels and equipment | Office leases and other | Total | |||||||||||||||
At January 1, 2019 (1) | $ | 823 | $ | 332 | $ | 252 | $ | 132 | $ | 1,539 | |||||||||
Additions | 444 | 40 | 12 | 6 | 502 | ||||||||||||||
Depreciation | (76 | ) | (40 | ) | (50 | ) | (20 | ) | (186 | ) | |||||||||
Derecognitions | — | (4 | ) | — | — | (4 | ) | ||||||||||||
Foreign exchange adjustments and other | (4 | ) | 1 | (9 | ) | — | (12 | ) | |||||||||||
At September 30, 2019 | $ | 1,187 | $ | 329 | $ | 205 | $ | 118 | $ | 1,839 |
Sep 30 2019 | ||||
Exploration and Production | ||||
North America | $ | 309 | ||
North Sea | 50 | |||
Offshore Africa | 164 | |||
Oil Sands Mining and Upgrading | 1,217 | |||
Head office | 99 | |||
$ | 1,839 |
Sep 30 2019 | ||||
Lease liabilities | $ | 1,855 | ||
Less: current portion | 244 | |||
$ | 1,611 |
Three Months Ended | Nine Months Ended | |||||||
Sep 30 2019 | Sep 30 2019 | |||||||
Expenses relating to short-term leases (1) | $ | 110 | $ | 336 | ||||
Interest expense on lease liabilities | $ | 18 | $ | 52 | ||||
Variable lease payments not included in the measurement of lease liabilities | $ | 37 | $ | 89 |
Canadian Natural Resources Limited | 9 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | |||||||
Sep 30 2019 | Sep 30 2019 | |||||||
Total cash outflows for leases during the period (1) | $ | 299 | $ | 879 |
Jan 1 2019 | ||||
Leases previously reported as commitments at December 31, 2018 (1) (2) | $ | 1,430 | ||
Impact of discounting | (317 | ) | ||
Leases previously reported as commitments, discounted at January 1, 2019 | 1,113 | |||
Leases recognized at adoption on January 1, 2019: | ||||
Lease extension options and renewals reasonably certain to be exercised | 243 | |||
Arrangements determined to be leases under IFRS 16 | 83 | |||
Leases entered into on behalf of a joint operation (3) | 100 | |||
Lease liabilities recognized at January 1, 2019 | $ | 1,539 |
(1) | At December 31, 2018, the Company did not report any finance leases in accordance with its previous accounting policy for leases. |
(2) | Commitments for operating leases, previously reported in note 16, are now reported as part of lease liabilities and included in other long-term liabilities in note 9. Operating leases previously reported in note 16 have been aggregated into one line in the reconciliation table. Other non-lease commitments continue to be reported in the table in note 16. |
(3) | In accordance with the previous accounting for operating leases used in joint operations, the Company reported commitments and related expenses in accordance with the Company's proportionate interest in the joint operation. Under IFRS 16, where the Company acts as the operator of a joint operation, the Company recognizes 100% of the related lease asset and lease liability. |
Canadian Natural Resources Limited | 10 | Nine Months Ended September 30, 2019 |
Sep 30 2019 | Dec 31 2018 | |||||||
Investment in PrairieSky Royalty Ltd. | $ | 418 | $ | 400 | ||||
Investment in Inter Pipeline Ltd. | 149 | 124 | ||||||
$ | 567 | $ | 524 |
Three Months Ended | Nine Months Ended | ||||||||||||||||
Sep 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||
Fair value (gain) loss from PrairieSky | $ | (2 | ) | $ | 73 | $ | (18 | ) | $ | 212 | |||||||
Dividend income from PrairieSky | (4 | ) | (5 | ) | (13 | ) | (13 | ) | |||||||||
$ | (6 | ) | $ | 68 | $ | (31 | ) | $ | 199 |
Three Months Ended | Nine Months Ended | ||||||||||||||||
Sep 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | ||||||||||||||
Fair value (gain) loss from Inter Pipeline | $ | (18 | ) | $ | 14 | $ | (25 | ) | $ | 23 | |||||||
Dividend income from Inter Pipeline | (3 | ) | (2 | ) | (8 | ) | (8 | ) | |||||||||
$ | (21 | ) | $ | 12 | $ | (33 | ) | $ | 15 |
Canadian Natural Resources Limited | 11 | Nine Months Ended September 30, 2019 |
Sep 30 2019 | Dec 31 2018 | |||||||
Investment in North West Redwater Partnership | $ | 73 | $ | 287 | ||||
North West Redwater Partnership subordinated debt (1) | 636 | 591 | ||||||
Prepaid cost of service toll | 113 | 62 | ||||||
Risk management (note 15) | 329 | 373 | ||||||
Other | 230 | 146 | ||||||
1,381 | 1,459 | |||||||
Less: current portion | 70 | 116 | ||||||
$ | 1,311 | $ | 1,343 |
(1) | Includes accrued interest. |
Canadian Natural Resources Limited | 12 | Nine Months Ended September 30, 2019 |
Sep 30 2019 | Dec 31 2018 | |||||||
Canadian dollar denominated debt, unsecured | ||||||||
Bank credit facilities | $ | 2,403 | $ | 831 | ||||
Medium-term notes | 4,800 | 5,300 | ||||||
7,203 | 6,131 | |||||||
US dollar denominated debt, unsecured | ||||||||
Bank credit facilities (September 30, 2019 – US$3,613 million; December 31, 2018 – US$2,954 million) | 4,785 | 4,031 | ||||||
Commercial paper (September 30, 2019 – US$365 million; December 31, 2018 – US$104 million) | 483 | 141 | ||||||
US dollar debt securities (September 30, 2019 – US$7,650 million; December 31, 2018 – US$7,650 million) | 10,131 | 10,439 | ||||||
15,399 | 14,611 | |||||||
Long-term debt before transaction costs and original issue discounts, net | 22,602 | 20,742 | ||||||
Less: original issue discounts, net (1) | 17 | 17 | ||||||
transaction costs (1) (2) | 96 | 102 | ||||||
22,489 | 20,623 | |||||||
Less: current portion of commercial paper | 483 | 141 | ||||||
current portion of other long-term debt (1) (2) | 3,553 | 1,000 | ||||||
$ | 18,453 | $ | 19,482 |
(1) | The Company has included unamortized original issue discounts and premiums, and directly attributable transaction costs in the carrying amount of the outstanding debt. |
(2) | Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other professional fees. |
• | a $100 million demand credit facility; |
• | a $1,000 million non-revolving term credit facility maturing May 2020; |
• | a $2,200 million non-revolving term credit facility maturing October 2020; |
• | a $750 million non-revolving term credit facility maturing February 2021; |
• | a $2,425 million revolving syndicated credit facility maturing June 2021; |
• | a $2,425 million revolving syndicated credit facility maturing June 2022; |
• | a $3,250 million non-revolving term credit facility maturing June 2022; and |
• | a £15 million demand credit facility related to the Company’s North Sea operations. |
Canadian Natural Resources Limited | 13 | Nine Months Ended September 30, 2019 |
Sep 30 2019 | Dec 31 2018 | |||||||
Asset retirement obligations | $ | 5,334 | $ | 3,886 | ||||
Share-based compensation | 172 | 124 | ||||||
Lease liabilities (note 5) | 1,855 | — | ||||||
Risk management (note 15) | 4 | 17 | ||||||
Deferred purchase consideration (1) | 95 | 118 | ||||||
Other | 126 | 80 | ||||||
7,586 | 4,225 | |||||||
Less: current portion | 511 | 335 | ||||||
$ | 7,075 | $ | 3,890 |
Canadian Natural Resources Limited | 14 | Nine Months Ended September 30, 2019 |
Sep 30 2019 | Dec 31 2018 | |||||||
Balance – beginning of period | $ | 3,886 | $ | 4,327 | ||||
Liabilities incurred | 3 | 19 | ||||||
Liabilities acquired, net | 198 | 6 | ||||||
Liabilities settled | (212 | ) | (290 | ) | ||||
Asset retirement obligation accretion | 140 | 186 | ||||||
Revision of cost, inflation rates and timing estimates | 146 | (111 | ) | |||||
Change in discount rates | 1,199 | (334 | ) | |||||
Foreign exchange adjustments | (26 | ) | 83 | |||||
Balance – end of period | 5,334 | 3,886 | ||||||
Less: current portion | 98 | 186 | ||||||
$ | 5,236 | $ | 3,700 |
Sep 30 2019 | Dec 31 2018 | |||||||
Balance – beginning of period | $ | 124 | $ | 414 | ||||
Share-based compensation expense (recovery) | 62 | (146 | ) | |||||
Cash payment for stock options surrendered | (1 | ) | (5 | ) | ||||
Transferred to common shares | (17 | ) | (120 | ) | ||||
Charged to (recovered from) Oil Sands Mining and Upgrading, net | 4 | (19 | ) | |||||
Balance – end of period | 172 | 124 | ||||||
Less: current portion | 124 | 92 | ||||||
$ | 48 | $ | 32 |
Canadian Natural Resources Limited | 15 | Nine Months Ended September 30, 2019 |
Three Months Ended | Nine Months Ended | ||||||||||||||||
Expense (recovery) | Sep 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||
Current corporate income tax – North America | $ | 133 | $ | 169 | $ | 374 | $ | 566 | |||||||||
Current corporate income tax – North Sea | 15 | 12 | 72 | 20 | |||||||||||||
Current corporate income tax – Offshore Africa | 14 | 22 | 37 | 43 | |||||||||||||
Current PRT (1) – North Sea | (4 | ) | (9 | ) | (89 | ) | (29 | ) | |||||||||
Other taxes | 3 | 3 | 9 | 8 | |||||||||||||
Current income tax | 161 | 197 | 403 | 608 | |||||||||||||
Deferred corporate income tax | 176 | 145 | (1,089 | ) | 428 | ||||||||||||
Deferred PRT (1) – North Sea | — | 1 | 1 | 18 | |||||||||||||
Deferred income tax | 176 | 146 | (1,088 | ) | 446 | ||||||||||||
Income tax | $ | 337 | $ | 343 | $ | (685 | ) | $ | 1,054 |
Canadian Natural Resources Limited | 16 | Nine Months Ended September 30, 2019 |
Nine Months Ended Sep 30, 2019 | |||||||
Issued common shares | Number of shares (thousands) | Amount | |||||
Balance – beginning of period | 1,201,886 | $ | 9,323 | ||||
Issued upon exercise of stock options | 4,470 | 148 | |||||
Previously recognized liability on stock options exercised for common shares | — | 17 | |||||
Purchase of common shares under Normal Course Issuer Bid | (22,150 | ) | (174 | ) | |||
Balance – end of period | 1,184,206 | $ | 9,314 |
Nine Months Ended Sep 30, 2019 | |||||||
Stock options (thousands) | Weighted average exercise price | ||||||
Outstanding – beginning of period | 46,685 | $ | 37.92 | ||||
Granted | 15,924 | $ | 34.79 | ||||
Surrendered for cash settlement | (689 | ) | $ | 34.80 | |||
Exercised for common shares | (4,470 | ) | $ | 33.05 | |||
Forfeited | (2,777 | ) | $ | 38.03 | |||
Outstanding – end of period | 54,673 | $ | 37.44 | ||||
Exercisable – end of period | 16,150 | $ | 37.52 |
Canadian Natural Resources Limited | 17 | Nine Months Ended September 30, 2019 |
Sep 30 2019 | Sep 30 2018 | |||||||
Derivative financial instruments designated as cash flow hedges | $ | 74 | $ | 9 | ||||
Foreign currency translation adjustment | 24 | (42 | ) | |||||
$ | 98 | $ | (33 | ) |
Sep 30 2019 | Dec 31 2018 | |||||||
Long-term debt, net (1) | $ | 22,313 | $ | 20,522 | ||||
Total shareholders’ equity | $ | 34,794 | $ | 31,974 | ||||
Debt to book capitalization | 39.1% | 39.1% |
(1) | Includes the current portion of long-term debt, net of cash and cash equivalents. |
Three Months Ended | Nine Months Ended | |||||||||||||||||
Sep 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||||
Weighted average common shares outstanding – basic (thousands of shares) | 1,185,589 | 1,218,784 | 1,193,184 | 1,223,449 | ||||||||||||||
Effect of dilutive stock options (thousands of shares) | 1,533 | 6,083 | 2,143 | 6,186 | ||||||||||||||
Weighted average common shares outstanding – diluted (thousands of shares) | 1,187,122 | 1,224,867 | 1,195,327 | 1,229,635 | ||||||||||||||
Net earnings | $ | 1,027 | $ | 1,802 | $ | 4,819 | $ | 3,367 | ||||||||||
Net earnings per common share | – basic | $ | 0.87 | $ | 1.48 | $ | 4.04 | $ | 2.75 | |||||||||
– diluted | $ | 0.87 | $ | 1.47 | $ | 4.03 | $ | 2.74 |
Canadian Natural Resources Limited | 18 | Nine Months Ended September 30, 2019 |
Sep 30, 2019 | ||||||||||||||||||||
Asset (liability) | Financial assets at amortized cost | Fair value through profit or loss | Derivatives used for hedging | Financial liabilities at amortized cost | Total | |||||||||||||||
Accounts receivable | $ | 2,405 | $ | — | $ | — | $ | — | $ | 2,405 | ||||||||||
Investments | — | 567 | — | — | 567 | |||||||||||||||
Other long-term assets | 636 | 1 | 328 | — | 965 | |||||||||||||||
Accounts payable | — | — | — | (662 | ) | (662 | ) | |||||||||||||
Accrued liabilities | — | — | — | (2,561 | ) | (2,561 | ) | |||||||||||||
Other long-term liabilities (1) | — | (4 | ) | — | (1,950 | ) | (1,954 | ) | ||||||||||||
Long-term debt (2) | — | — | — | (22,489 | ) | (22,489 | ) | |||||||||||||
$ | 3,041 | $ | 564 | $ | 328 | $ | (27,662 | ) | $ | (23,729 | ) |
Dec 31, 2018 | ||||||||||||||||||||
Asset (liability) | Financial assets at amortized cost | Fair value through profit or loss | Derivatives used for hedging | Financial liabilities at amortized cost | Total | |||||||||||||||
Accounts receivable | $ | 1,148 | $ | — | $ | — | $ | — | $ | 1,148 | ||||||||||
Investments | — | 524 | — | — | 524 | |||||||||||||||
Other long-term assets | 591 | 12 | 361 | — | 964 | |||||||||||||||
Accounts payable | — | — | — | (779 | ) | (779 | ) | |||||||||||||
Accrued liabilities | — | — | — | (2,356 | ) | (2,356 | ) | |||||||||||||
Other long-term liabilities (1) | — | (17 | ) | — | (118 | ) | (135 | ) | ||||||||||||
Long-term debt (2) | — | — | — | (20,623 | ) | (20,623 | ) | |||||||||||||
$ | 1,739 | $ | 519 | $ | 361 | $ | (23,876 | ) | $ | (21,257 | ) |
(1) | Includes $1,855 million of lease liabilities (December 31, 2018 – $nil) and $95 million of deferred purchase consideration payable over the next four years (December 31, 2018 – $118 million). |
(2) | Includes the current portion of long-term debt. |
Sep 30, 2019 | |||||||||||||||||
Carrying amount | Fair value | ||||||||||||||||
Asset (liability) (1) (2) | Level 1 | Level 2 | Level 3 (4) (5) | ||||||||||||||
Investments (3) | $ | 567 | $ | 567 | $ | — | $ | — | |||||||||
Other long-term assets | $ | 965 | $ | — | $ | 329 | $ | 636 | |||||||||
Other long-term liabilities | $ | (99 | ) | $ | — | $ | (4 | ) | $ | (95 | ) | ||||||
Fixed rate long-term debt (6) (7) | $ | (14,818 | ) | $ | (16,594 | ) | $ | — | $ | — |
Canadian Natural Resources Limited | 19 | Nine Months Ended September 30, 2019 |
Dec 31, 2018 | |||||||||||||||||
Carrying amount | Fair value | ||||||||||||||||
Asset (liability) (1) (2) | Level 1 | Level 2 | Level 3 (4) (5) | ||||||||||||||
Investments (3) | $ | 524 | $ | 524 | $ | — | $ | — | |||||||||
Other long-term assets | $ | 964 | $ | — | $ | 373 | $ | 591 | |||||||||
Other long-term liabilities | $ | (135 | ) | $ | — | $ | (17 | ) | $ | (118 | ) | ||||||
Fixed rate long-term debt (6) (7) | $ | (15,620 | ) | $ | (15,952 | ) | $ | — | $ | — |
(1) | Excludes financial assets and liabilities where the carrying amount approximates fair value due to the short-term nature of the asset or liability (cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and purchase consideration payable), as well as lease liabilities, where carrying amount approximates fair value. |
(2) | There were no transfers between Level 1, 2 and 3 financial instruments. |
(3) | The fair values of the investments are based on quoted market prices. |
(4) | The fair value of the deferred purchase consideration included in other long-term liabilities is based on the present value of future cash payments. |
(5) | The fair value of Redwater Partnership subordinated debt is based on the present value of future cash receipts. |
(6) | The fair value of fixed rate long-term debt has been determined based on quoted market prices. |
(7) | Includes the current portion of fixed rate long-term debt. |
Asset (liability) | Sep 30 2019 | Dec 31 2018 | ||||||
Derivatives held for trading | ||||||||
Foreign currency forward contracts | $ | 1 | $ | 8 | ||||
Natural gas AECO basis swaps | (2 | ) | 1 | |||||
Natural gas AECO fixed price swaps | (2 | ) | 3 | |||||
Crude oil WCS (1) differential swaps | — | (17 | ) | |||||
Cash flow hedges | ||||||||
Foreign currency forward contracts | 7 | 70 | ||||||
Cross currency swaps | 321 | 291 | ||||||
$ | 325 | $ | 356 | |||||
Included within: | ||||||||
Current portion of other long-term assets | $ | 17 | $ | 92 | ||||
Current portion of other long-term liabilities | (4 | ) | (17 | ) | ||||
Other long-term assets | 312 | 281 | ||||||
$ | 325 | $ | 356 |
(1) | Western Canadian Select |
Canadian Natural Resources Limited | 20 | Nine Months Ended September 30, 2019 |
Asset (liability) | Sep 30 2019 | Dec 31 2018 | ||||||
Balance – beginning of period | $ | 356 | $ | 101 | ||||
Net change in fair value of outstanding derivative financial instruments recognized in: | ||||||||
Risk management activities | 4 | 35 | ||||||
Foreign exchange | (103 | ) | 260 | |||||
Other comprehensive income (loss) | 68 | (40 | ) | |||||
Balance – end of period | 325 | 356 | ||||||
Less: current portion | 13 | 75 | ||||||
$ | 312 | $ | 281 |
Three Months Ended | Nine Months Ended | |||||||||||||||
Sep 30 2019 | Sep 30 2018 | Sep 30 2019 | Sep 30 2018 | |||||||||||||
Net realized risk management (gain) loss | $ | (1 | ) | $ | (8 | ) | $ | 53 | $ | (54 | ) | |||||
Net unrealized risk management gain | (2 | ) | (21 | ) | (4 | ) | (62 | ) | ||||||||
$ | (3 | ) | $ | (29 | ) | $ | 49 | $ | (116 | ) |
a) | Market risk |
Remaining term | Volume | Weighted average price | Index | |||||
Natural Gas | ||||||||
AECO basis swaps | Nov 2019 | – | Mar 2020 | 95,000 MMbtu/d | US$0.96 | NYMEX | ||
AECO fixed price swaps | Apr 2020 | – | Oct 2020 | 102,500 GJ/d | $1.51 | AECO | ||
Oct 2019 | 115,000 GJ/d | $1.32 | AECO |
Canadian Natural Resources Limited | 21 | Nine Months Ended September 30, 2019 |
Remaining term | Amount | Exchange rate (US$/C$) | Interest rate (US$) | Interest rate (C$) | ||||||
Cross currency | ||||||||||
Swaps | Oct 2019 | – | Nov 2021 | US$500 | 1.022 | 3.45 | % | 3.96 | % | |
Oct 2019 | – | Mar 2038 | US$550 | 1.170 | 6.25 | % | 5.76 | % |
Canadian Natural Resources Limited | 22 | Nine Months Ended September 30, 2019 |
Less than 1 year | 1 to less than 2 years | 2 to less than 5 years | Thereafter | ||||||||||||
Accounts payable | $ | 662 | $ | — | $ | — | $ | — | |||||||
Accrued liabilities | $ | 2,561 | $ | — | $ | — | $ | — | |||||||
Long-term debt (1) | $ | 4,040 | $ | 3,112 | $ | 7,067 | $ | 8,383 | |||||||
Other long-term liabilities (2) | $ | 273 | $ | 205 | $ | 435 | $ | 1,041 | |||||||
Interest and other financing expense (3) | $ | 936 | $ | 786 | $ | 1,771 | $ | 5,038 |
(1) | Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs. |
(2) | Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $244 million; one to less than two years, $180 million; two to less than five years, $390 million; and thereafter $1,041 million. |
(3) | Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates at September 30, 2019. |
2019 | 2020 | 2021 | 2022 | 2023 | Thereafter | ||||||||||||||||||
Product transportation (2) | $ | 177 | $ | 719 | $ | 688 | $ | 615 | $ | 502 | $ | 4,722 | |||||||||||
North West Redwater Partnership service toll (3) | $ | 17 | $ | 118 | $ | 163 | $ | 148 | $ | 158 | $ | 2,854 | |||||||||||
Offshore vessels and equipment | $ | 26 | $ | 70 | $ | 64 | $ | 9 | $ | — | $ | — | |||||||||||
Field equipment and power | $ | 13 | $ | 20 | $ | 21 | $ | 20 | $ | 21 | $ | 274 | |||||||||||
Other | $ | 7 | $ | 25 | $ | 21 | $ | 18 | $ | 17 | $ | 48 |
(1) | Subsequent to the adoption of IFRS 16, the Company reports its payments for lease liabilities in the maturity table in note 15. |
(2) | On June 27, 2019, the Company assumed $2,381 million of product transportation commitments related to the acquisition of assets from Devon. |
(3) | Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt portion of the monthly cost of service toll, which currently consists of interest and fees, with principal repayments beginning in 2020. Included in the cost of service toll is $1,126 million of interest payable over the 30 year tolling period (see note 7). |
Canadian Natural Resources Limited | 23 | Nine Months Ended September 30, 2019 |
North America | North Sea | Offshore Africa | Total Exploration and Production | |||||||||||||||||||||||||||||
Three Months Ended | Nine Months Ended | Three Months Ended | Nine Months Ended | Three Months Ended | Nine Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||
Sep 30 | Sep 30 | Sep 30 | Sep 30 | Sep 30 | Sep 30 | Sep 30 | Sep 30 | |||||||||||||||||||||||||
(millions of Canadian dollars, unaudited) | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | ||||||||||||||||
Segmented product sales | ||||||||||||||||||||||||||||||||
Crude oil and NGLs | 2,661 | 2,162 | 6,797 | 6,331 | 218 | 201 | 563 | 535 | 226 | 230 | 538 | 424 | 3,105 | 2,593 | 7,898 | 7,290 | ||||||||||||||||
Natural gas | 199 | 265 | 823 | 834 | 9 | 45 | 45 | 112 | 16 | 18 | 52 | 53 | 224 | 328 | 920 | 999 | ||||||||||||||||
Other (1) | 1 | — | 6 | — | 1 | — | 3 | — | 3 | — | 6 | — | 5 | — | 15 | — | ||||||||||||||||
Total segmented product sales | 2,861 | 2,427 | 7,626 | 7,165 | 228 | 246 | 611 | 647 | 245 | 248 | 596 | 477 | 3,334 | 2,921 | 8,833 | 8,289 | ||||||||||||||||
Less: royalties | (266 | ) | (247 | ) | (690 | ) | (685 | ) | — | — | (1 | ) | (1 | ) | (14 | ) | (22 | ) | (35 | ) | (42 | ) | (280 | ) | (269 | ) | (726 | ) | (728 | ) | ||
Segmented revenue | 2,595 | 2,180 | 6,936 | 6,480 | 228 | 246 | 610 | 646 | 231 | 226 | 561 | 435 | 3,054 | 2,652 | 8,107 | 7,561 | ||||||||||||||||
Segmented expenses | ||||||||||||||||||||||||||||||||
Production | 624 | 576 | 1,797 | 1,816 | 103 | 96 | 270 | 271 | 37 | 52 | 79 | 121 | 764 | 724 | 2,146 | 2,208 | ||||||||||||||||
Transportation, blending and feedstock | 793 | 613 | 1,893 | 2,046 | 5 | 6 | 15 | 18 | — | — | 1 | 1 | 798 | 619 | 1,909 | 2,065 | ||||||||||||||||
Depletion, depreciation and amortization | 858 | 795 | 2,391 | 2,353 | 83 | 53 | 210 | 169 | 80 | 69 | 192 | 139 | 1,021 | 917 | 2,793 | 2,661 | ||||||||||||||||
Asset retirement obligation accretion | 27 | 22 | 68 | 66 | 6 | 7 | 21 | 21 | 1 | 2 | 4 | 7 | 34 | 31 | 93 | 94 | ||||||||||||||||
Risk management activities (commodity derivatives) | 7 | (32 | ) | 36 | (19 | ) | — | — | — | — | — | — | — | — | 7 | (32 | ) | 36 | (19 | ) | ||||||||||||
Gain on acquisition and revaluation of properties | — | (272 | ) | — | (272 | ) | — | — | — | (139 | ) | — | — | — | — | — | (272 | ) | — | (411 | ) | |||||||||||
Equity loss from investments | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||
Total segmented expenses | 2,309 | 1,702 | 6,185 | 5,990 | 197 | 162 | 516 | 340 | 118 | 123 | 276 | 268 | 2,624 | 1,987 | 6,977 | 6,598 | ||||||||||||||||
Segmented earnings (loss) before the following | 286 | 478 | 751 | 490 | 31 | 84 | 94 | 306 | 113 | 103 | 285 | 167 | 430 | 665 | 1,130 | 963 | ||||||||||||||||
Non–segmented expenses | ||||||||||||||||||||||||||||||||
Administration | ||||||||||||||||||||||||||||||||
Share-based compensation | ||||||||||||||||||||||||||||||||
Interest and other financing expense | ||||||||||||||||||||||||||||||||
Risk management activities (other) | ||||||||||||||||||||||||||||||||
Foreign exchange loss (gain) | ||||||||||||||||||||||||||||||||
(Gain) loss from investments | ||||||||||||||||||||||||||||||||
Total non–segmented expenses | ||||||||||||||||||||||||||||||||
Earnings before taxes | ||||||||||||||||||||||||||||||||
Current income tax expense | ||||||||||||||||||||||||||||||||
Deferred income tax expense (recovery) | ||||||||||||||||||||||||||||||||
Net earnings |
Canadian Natural Resources Limited | 24 | Nine Months Ended September 30, 2019 |
Oil Sands Mining and Upgrading | Midstream and Refining | Inter–segment elimination and other | Total | |||||||||||||||||||||||||||||
Three Months Ended | Nine Months Ended | Three Months Ended | Nine Months Ended | Three Months Ended | Nine Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||
Sep 30 | Sep 30 | Sep 30 | Sep 30 | Sep 30 | Sep 30 | Sep 30 | Sep 30 | |||||||||||||||||||||||||
(millions of Canadian dollars, unaudited) | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | ||||||||||||||||
Segmented product sales | ||||||||||||||||||||||||||||||||
Crude oil and NGLs (2) | 3,117 | 3,219 | 8,707 | 9,683 | 21 | 26 | 62 | 78 | 81 | 129 | 336 | 290 | 6,324 | 5,967 | 17,003 | 17,341 | ||||||||||||||||
Natural gas | — | — | — | — | — | — | — | — | 33 | 32 | 117 | 111 | 257 | 360 | 1,037 | 1,110 | ||||||||||||||||
Other (1) | 1 | — | 4 | — | — | — | — | — | — | — | — | — | 6 | — | 19 | — | ||||||||||||||||
Total segmented product sales | 3,118 | 3,219 | 8,711 | 9,683 | 21 | 26 | 62 | 78 | 114 | 161 | 453 | 401 | 6,587 | 6,327 | 18,059 | 18,451 | ||||||||||||||||
Less: royalties | (147 | ) | (159 | ) | (363 | ) | (398 | ) | — | — | — | — | — | — | — | — | (427 | ) | (428 | ) | (1,089 | ) | (1,126 | ) | ||||||||
Segmented revenue | 2,971 | 3,060 | 8,348 | 9,285 | 21 | 26 | 62 | 78 | 114 | 161 | 453 | 401 | 6,160 | 5,899 | 16,970 | 17,325 | ||||||||||||||||
Segmented expenses | ||||||||||||||||||||||||||||||||
Production | 784 | 842 | 2,420 | 2,570 | 4 | 5 | 15 | 16 | 14 | 14 | 48 | 43 | 1,566 | 1,585 | 4,629 | 4,837 | ||||||||||||||||
Transportation, blending and (2) feedstock | 357 | 265 | 976 | 913 | — | — | — | — | 93 | 147 | 398 | 347 | 1,248 | 1,031 | 3,283 | 3,325 | ||||||||||||||||
Depletion, depreciation and amortization | 401 | 385 | 1,192 | 1,161 | 4 | 4 | 11 | 11 | — | — | — | — | 1,426 | 1,306 | 3,996 | 3,833 | ||||||||||||||||
Asset retirement obligation accretion | 16 | 16 | 47 | 46 | — | — | — | — | — | — | — | — | 50 | 47 | 140 | 140 | ||||||||||||||||
Risk management activities (commodity derivatives) | — | — | — | — | — | — | — | — | — | — | — | — | 7 | (32 | ) | 36 | (19 | ) | ||||||||||||||
Gain on acquisition and revaluation of properties | — | — | — | — | — | — | — | — | — | — | — | — | — | (272 | ) | — | (411 | ) | ||||||||||||||
Equity loss from investments | — | — | — | — | 88 | 2 | 214 | 5 | — | — | — | — | 88 | 2 | 214 | 5 | ||||||||||||||||
Total segmented expenses | 1,558 | 1,508 | 4,635 | 4,690 | 96 | 11 | 240 | 32 | 107 | 161 | 446 | 390 | 4,385 | 3,667 | 12,298 | 11,710 | ||||||||||||||||
Segmented earnings (loss) before the following | 1,413 | 1,552 | 3,713 | 4,595 | (75 | ) | 15 | (178 | ) | 46 | 7 | — | 7 | 11 | 1,775 | 2,232 | 4,672 | 5,615 | ||||||||||||||
Non–segmented expenses | ||||||||||||||||||||||||||||||||
Administration | 95 | 77 | 249 | 234 | ||||||||||||||||||||||||||||
Share-based compensation | 7 | (85 | ) | 62 | 2 | |||||||||||||||||||||||||||
Interest and other financing expense | 231 | 180 | 619 | 560 | ||||||||||||||||||||||||||||
Risk management activities (other) | (10 | ) | 3 | 13 | (97 | ) | ||||||||||||||||||||||||||
Foreign exchange loss (gain) | 115 | (168 | ) | (341 | ) | 281 | ||||||||||||||||||||||||||
(Gain) loss from investments | (27 | ) | 80 | (64 | ) | 214 | ||||||||||||||||||||||||||
Total non–segmented expenses | 411 | 87 | 538 | 1,194 | ||||||||||||||||||||||||||||
Earnings before taxes | 1,364 | 2,145 | 4,134 | 4,421 | ||||||||||||||||||||||||||||
Current income tax expense | 161 | 197 | 403 | 608 | ||||||||||||||||||||||||||||
Deferred income tax expense (recovery) | 176 | 146 | (1,088 | ) | 446 | |||||||||||||||||||||||||||
Net earnings | 1,027 | 1,802 | 4,819 | 3,367 |
Canadian Natural Resources Limited | 25 | Nine Months Ended September 30, 2019 |
Nine Months Ended | ||||||||||||||||||||||||
Sep 30, 2019 | Sep 30, 2018 | |||||||||||||||||||||||
Net expenditures | Non-cash and fair value changes (2) | Capitalized costs | Net expenditures | Non-cash and fair value changes (2) | Capitalized costs | |||||||||||||||||||
Exploration and evaluation assets | ||||||||||||||||||||||||
Exploration and Production | ||||||||||||||||||||||||
North America (3) | $ | 129 | $ | (185 | ) | $ | (56 | ) | $ | 114 | $ | — | $ | 114 | ||||||||||
North Sea | — | — | — | — | — | — | ||||||||||||||||||
Offshore Africa | 35 | — | 35 | 29 | — | 29 | ||||||||||||||||||
Oil Sands Mining and Upgrading (4) | — | — | — | 218 | (3 | ) | 215 | |||||||||||||||||
$ | 164 | $ | (185 | ) | $ | (21 | ) | $ | 361 | $ | (3 | ) | $ | 358 | ||||||||||
Property, plant and equipment | ||||||||||||||||||||||||
Exploration and Production | ||||||||||||||||||||||||
North America (3) | $ | 4,372 | $ | 915 | $ | 5,287 | $ | 1,953 | $ | (113 | ) | $ | 1,840 | |||||||||||
North Sea | 133 | 104 | 237 | 73 | 220 | 293 | ||||||||||||||||||
Offshore Africa (5) | 145 | (1,489 | ) | (1,344 | ) | 129 | — | 129 | ||||||||||||||||
4,650 | (470 | ) | 4,180 | 2,155 | 107 | 2,262 | ||||||||||||||||||
Oil Sands Mining and Upgrading (6) | 1,004 | 146 | 1,150 | 812 | (178 | ) | 634 | |||||||||||||||||
Midstream and Refining | 9 | — | 9 | 11 | — | 11 | ||||||||||||||||||
Head office | 26 | (3 | ) | 23 | 14 | — | 14 | |||||||||||||||||
$ | 5,689 | $ | (327 | ) | $ | 5,362 | $ | 2,992 | $ | (71 | ) | $ | 2,921 |
(1) | This table provides a reconciliation of capitalized costs, reported in note 3 and note 4, to net expenditures reported in the investing activities section of the statements of cash flows. The reconciliation excludes the impact of foreign exchange adjustments. |
(2) | Derecognitions, asset retirement obligations, transfer of exploration and evaluation assets, and other fair value adjustments. |
(3) | Includes cash consideration paid of $91 million for exploration and evaluation assets and $3,126 million for property, plant and equipment acquired from Devon in the second quarter of 2019. |
(4) | In the third quarter of 2018, total purchase consideration for the acquisition of the Joslyn oil sands project included $222 million for exploration and evaluation assets and $4 million for asset retirement obligations assumed. |
(5) | Includes a derecognition of $1,515 million following the FPSO demobilization at the Olowi field, Gabon in the first quarter of 2019. |
(6) | Net expenditures for Oil Sands Mining and Upgrading also include capitalized interest and share-based compensation. |
Sep 30 2019 | Dec 31 2018 | |||||||
Exploration and Production | ||||||||
North America | $ | 31,770 | $ | 27,199 | ||||
North Sea | 1,751 | 1,699 | ||||||
Offshore Africa | 1,576 | 1,471 | ||||||
Other | 70 | 33 | ||||||
Oil Sands Mining and Upgrading | 41,728 | 39,634 | ||||||
Midstream and Refining | 1,420 | 1,413 | ||||||
Head office | 217 | 110 | ||||||
$ | 78,532 | $ | 71,559 |
Canadian Natural Resources Limited | 26 | Nine Months Ended September 30, 2019 |
Interest coverage ratios for the twelve month period ended September 30, 2019: | |
Interest coverage (times) | |
Net earnings (1) | 4.7x |
Adjusted funds flow (2) | 11.6x |
(1) | Net earnings plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest. |
(2) | Adjusted funds flow plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest. |
Canadian Natural Resources Limited | 27 | Nine Months Ended September 30, 2019 |
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