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Canadian Natural Resources Ltd
Symbol CNQ
Shares Issued 1,184,355,541
Close 2019-11-06 C$ 34.14
Recent Sedar Documents

Canadian Natural's Q3 earnings drop to $1,027-million

2019-11-07 07:06 ET - News Release

Mr. Steve Laut reports

CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES 2019 THIRD QUARTER RESULTS

Canadian Natural Resources Ltd. has released its third quarter 2019 financial results.

Commenting on the company's third quarter 2019 results, Steve Laut, executive vice-chairman of Canadian Natural, stated: "Canadian Natural's third quarter results are an excellent example of how the company's effective and efficient operations can drive value creation for our shareholders as a result of execution excellence and economies of scale. We achieved record quarterly adjusted funds flow of approximately $2.9-billion as operating costs were below forecast and production was at the top end of quarterly corporate guidance, resulting in 12-month production-per-share growth of 14 per cent from Q3 2018 levels. Free cash flow of approximately $1.9-billion was significant following our disciplined capital expenditures in the quarter. Our free cash flow was used to strengthen our balance sheet and returned to our shareholders, through dividends and share purchases as we balance according to our defined free cash flow allocation policy."

Canadian Natural's president, Tim McKay, added: "The third quarter of 2019 was an excellent operational quarter for the company. Our continued focus on cost control and effective and efficient operations was evident as operating costs were reduced across most of our assets, resulting in higher netbacks and margin growth. Corporate operating costs per barrel of oil equivalent were reduced by approximately 11 per cent, including at our Pelican Lake asset where strong and sustainable operating costs of $6.10/barrel were achieved, a reduction of 5 per cent year over year. Also on a year-over-year basis our thermal in situ assets operating costs improved by approximately 14 per cent to $9.77/bbl and our oil sands mining and upgrading assets delivered an approximate 12-per-cent reduction in operating costs to $20.05/bbl of synthetic crude oil (SCO), comparable to the record low of $19.97/bbl of SCO in Q4 2018.

"The company delivered strong performance in the third quarter, a reflection of our robust assets, effective and efficient operations and our operational flexibility, as we effectively executed our curtailment optimization strategy, delivering production at the top end of quarterly guidance. Oil sands mining and upgrading achieved a record production month in the quarter, producing approximately 462,000 bbl/d of SCO in August, 2019. In September and October, as a part of our curtailment optimization strategy, we utilized available capacity from our flexible thermal in situ assets to coincide with the Horizon turnaround ensuring we maximized production within our curtailment allotment. This flexibility demonstrates the value of having a large, balanced and diverse asset base. As a result of top-tier execution, the planned turnaround at Horizon was successfully completed on schedule with overall costs under budget."

Canadian Natural's chief financial officer, Mark Stainthorpe, continued: "Canadian Natural's robust business model was on display in the third quarter as financial results were strong with net earnings of over $1.0-billion and adjusted net earnings of approximately $1.2-billion.

"The company's long-life low decline asset base delivered quarterly record adjusted funds flow of approximately $2.9-billion and as a result free cash flow generation was significant at approximately $1.5-billion after capital expenditures and dividends. Our financial position strengthened in Q3 2019 as we reduced gross debt by over $1.0-billion from Q2 2019 levels. This included the permanent repayment and cancellation of term debt by $800-million in the quarter, followed by an additional $500-million repayment and cancellation subsequent to quarter-end. Based on corporate guidance and current strip pricing we target to exit 2019 with debt to adjusted EBITDA at or below 1.9 times, debt to cash flow at or below 2.2 times and debt to book capital at or below 38 per cent, all levels that are stronger than those exiting Dec. 31, 2018, notwithstanding the completion of the Devon Canada asset acquisition."

                                              QUARTERLY HIGHLIGHTS
                                  (in millions, except per-common-share amounts) 

                                                              Three months ended                 Nine months ended
                                 Sept. 30, 2019   June 30, 2019   Sept. 30, 2018   Sept. 30, 2019   Sept. 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                           1,229           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                       2,881           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                     963             908            1,473            2,848            3,550
Total net capital
expenditures,
including Devon Canada asset
acquisition costs                           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 NGL (bbl/d)               931,546         770,409          801,742          829,031          816,539
Equivalent production (boe/d)         1,176,361       1,025,800        1,060,629        1,079,641        1,077,953

  • Net earnings of $1,027-million were realized in Q3 2019, while adjusted net earnings of $1,229-million were achieved in Q3 2019, a $187-million increase from Q2 2019 levels.
  • Cash flows from operating activities were $2,518-million in Q3 2019, a decrease of $343-million compared with Q2 2019 levels.
  • Canadian Natural generated record quarterly adjusted funds flow of $2,881-million in Q3 2019, an increase of 9 per cent or $229-million over Q2 2019 levels. The increase over Q2 2019 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 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 2019, reflecting the strength of the company's long-life low decline asset base and the company's effective and efficient operations:
    • Balance sheet strength remains a focus and free cash flow was used to reduce debt levels in Q3 2019 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 2019 by $1,018-million from Q2 2019 levels:
      • The company utilized adjusted funds flow to repay and cancel $800-million of its $1.8-billion non-revolving term loan facility; $1,000-million remained outstanding and fully drawn at quarter-end:
        • Subsequent to quarter-end the company repaid and cancelled an additional $500-million of the remaining $1-billion non-revolving term loan; $500-million remains outstanding and fully drawn as at Nov. 6, 2019.
    • Canadian Natural is committed to returns to shareholders, returning a total of $616-million to shareholders in Q3 2019, $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 $2.1-billion to shareholders, $1,299-million by way of dividends and $801-million by way of share purchases:
      • Share purchases for cancellation in the quarter totalled 5.05 million common shares at a weighted average share price of $33.45.
      • Subsequent to quarter-end, up to and including Nov. 6, 2019, the company executed on additional share purchases for cancellation of 1.35 million 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 Jan. 1, 2018, and Nov. 6, 2019.
      • Subsequent to quarter-end, the company declared a quarterly dividend of 37.5 cents per share, payable on Jan. 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. 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 2019;
    • 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 2019, increases of 15 per cent and 11 per cent over Q2 2019 and Q3 2018 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 per cent when compared with Q3 2018 levels.
    • The company achieved record quarterly liquids production volumes of 931,546 bbl/d in Q3 2019, increases of 21 per cent and 16 per cent over Q2 2019 and Q3 2018 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 2019, increases of 15 per cent and 10 per cent over Q2 2019 and Q3 2018 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 ($15.18 (U.S.)/bbl) of SCO in Q3 2019, comparable with record low operating costs of $19.97/bbl ($15.12 (U.S.)/bbl) of SCO achieved in Q4 2018, impressive results given the planned turnaround activities in the quarter. Third quarter 2019 operating costs represent decreases of 17 per cent and 12 per cent from Q2 2019 and Q3 2018 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 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 per cent 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. As part of the company's pro-active inspection at Horizon, the team identified a need to repair piping on one of the hydrogen manufacturing units during postturnaround 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 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 2019 averaged 206,395 bbl/d, an 88-per-cent increase over Q2 2019 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 2019 at $9.77/bbl, reductions of 17 per cent and 14 per cent from Q2 2019 and Q3 2018 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 toward 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 Sept. 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 2019. 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 2019 operating costs were $11.11/boe, 5-per-cent and 7-per-cent reductions from Q2 2019 and Q3 2018 levels, respectively.
  • Canadian Natural's North America E&P crude oil and NGL (natural gas liquids) production volumes, excluding thermal in situ, averaged 244,267 bbl/d in Q3 2019, a 4-per-cent increase over Q2 2019 and in line with Q3 2018 levels. The increase over Q2 2019 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 four years. These sustainable and consistent results continued in Q3 2019 where operating costs of $6.10/bbl were achieved, representing decreases of 9 per cent and 5 per cent from Q2 2019 and Q3 2018 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 2019.
  • International E&P production volumes were strong in Q3 2019, exceeding quarterly production guidance, averaging 48,681 bbl/d, a decrease of 5 per cent from Q2 2019 and an increase of 2 per cent over Q3 2018 levels. The decrease from Q2 2019 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 2018 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 million cubic feet per day in Q3 2019, exceeding the top end of quarterly guidance as a result of phasing of turnaround activities. As compared with Q2 2019 and Q3 2018 levels, natural gas production decreased by 4 per cent and 5 per cent, respectively, primarily due to natural field declines and reduced capital investment:
    • Strong operating costs of $1.12/1,000 cubic feet were achieved in Q3 2019, decreases of 9 per cent and 16 per cent from Q2 2019 and Q3 2018 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 2020.
    • The Northwest 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 2019, 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.

Operations review and capital allocation

Canadian Natural has a balanced and diverse portfolio of assets, primarily Canada based, with international exposure in the United Kingdom section of the North Sea and offshore Africa. Canadian Natural's production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, thermal in situ crude oil, bitumen and SCO, natural gas and NGL. This balance provides optionality for capital investments, maximizing value for the company's shareholders.

Underpinning this asset base is long-life low decline production from the company's oil sands mining and upgrading, thermal in situ oil sands and Pelican Lake heavy crude oil assets. The combination of long-life low decline, low reserves replacement cost, and effective and efficient operations results in substantial and sustainable adjusted funds flow throughout the commodity price cycle.

Augmenting this, Canadian Natural maintains a substantial inventory of low capital exposure projects within the company's conventional asset base. These projects can be executed quickly and with the right economic conditions, can provide excellent returns and maximize value for shareholders. Supporting these projects is the company's undeveloped land base which enables large, repeatable drilling programs which can be optimized over time. Additionally, by owning and operating most of the related infrastructure, Canadian Natural is able to control major components of the company's operating costs and minimize production commitments. Low-capital-exposure projects can be quickly stopped or started depending upon success, market conditions, or corporate needs.

Canadian Natural's balanced portfolio, built with both long-life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.

                                     DRILLING ACTIVITY
                                                                   Nine months ended Sept. 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 Sept. 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.

North America exploration and production

                             CRUDE OIL AND NGL -- EXCLUDING THERMAL IN SITU OIL SANDS    
                                          
                                                                  Three months ended              Nine months ended
                                       Sept. 30, 2019   June 30, 2019 Sept. 30, 2018  Sept. 30, 2019 Sept. 30, 2018

Crude oil and NGL 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 NGL production volumes, excluding thermal in situ, averaged 244,267 bbl/d in Q3 2019, a 4-per-cent increase over Q2 2019 and in line with Q3 2018 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's primary heavy crude oil production averaged 88,008 bbl/d in Q3 2019, a 13-per-cent increase over Q2 2019 levels primarily due to additional volumes from the Devon Canada asset acquisition. Primary heavy crude oil production decreased by 4 per cent from Q3 2018 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-per-cent decrease from Q2 2019 levels.
      • As a result of curtailments in Alberta the company drilled seven net primary heavy crude oil wells in Saskatchewan in Q3 2019, 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 2019, an increase of 9 per cent from Q2 2019 levels, reflecting normal production levels after the temporary shut-in of crude oil production in Q2 2019 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 four years. These sustainable and consistent results continued in Q3 2019 where operating costs of $6.10/bbl were achieved, representing decreases of 9 per cent and 5 per cent from Q2 2019 and Q3 2018 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 2019.
    • North American light crude oil and NGL production averaged 96,113 bbl/d in Q3 2019, a 6-per-cent decrease from Q2 2019 levels primarily as a result of curtailments in Alberta and natural field declines. Production increased 3 per cent from Q3 2018 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 southeastern Saskatchewan combined with the execution of the company's curtailment optimization strategy:
      • In Q3 2019 operating costs were $14.96/bbl in the company's North America light crude oil and NGL areas, an increase of 2 per cent over Q2 2019 and a decrease of 4 per cent from Q3 2018 levels. The changes from Q2 2019 and Q3 2018 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 three net wells drilled in 2019 continue to be strong with production averaging approximately 10,400 bbl/d liquids and 68 million cubic feet per day, exceeding expectations by approximately 40 per cent.
      • In southeastern Saskatchewan, the company drilled eight gross (6.6 net) light crude oil wells in Q3 2019, with three gross (3.0 net) wells previously drilled in Q2 2019 as a part of the program. These high-return wells came on stream in Q3 2019 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 to 251,000 bbl/d.

                                          THERMAL IN SITU OIL SANDS            
                                                        
                                                         Three months ended                Nine months ended
                              Sept. 30, 2019  June 30, 2019  Sept. 30, 2018  Sept. 30, 2019   Sept. 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 2019 averaged 206,395 bbl/d, an 88 per cent increase over Q2 2019 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 2019 at $9.77/bbl, reductions of 17 per cent and 14 per cent from Q2 2019 and Q3 2018 levels, respectively, primarily as a result of synergies captured to date from the Devon Canada acquisition and lower energy costs.
    • At Primrose, Q3 2019 production volumes averaged 73,652 bbl/d, an increase of 2 per cent over Q2 2019 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 2019, decreases of 20 per cent and 16 per cent from Q2 2019 and Q3 2018 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 was strong, beginning on Sept. 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 2019, a 9-per-cent increase over Q2 2019 and a 13-per-cent decrease from Q3 2018 levels. The increase from Q2 2019 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 2019, reductions of 18 per cent and 5 per cent from Q2 2019 and Q3 2018 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 per cent to 50 per cent 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 per cent, 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 toward 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 2019. Including energy costs, Jackfish quarterly operating costs were strong at $9.44/bbl in Q3 2019, approximately $3/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 2019. 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 to 172,000 bbl/d.

                                              NORTH AMERICA NATURAL GAS         

                                                                  Three months ended                   Nine months ended
                                  Sept. 30, 2019     June 30, 2019    Sept. 30, 2018    Sept. 30, 2019    Sept. 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 million cubic feet per day in Q3 2019, decreases of 4 per cent from both Q2 2019 and Q3 2018 levels. The decreases were primarily due to natural field declines and reduced capital investment.
  • Strong operating costs of $1.07/1,000 cubic feet were achieved in Q3 2019, decreases of 7 per cent and 11 per cent from Q2 2019 and Q3 2018 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 26 cents/1,000 cubic feet equivalent in Q3 2019, decreases of 21 per cent and 26 per cent from Q2 2019 and Q3 2018 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 five million cubic feet per day in Q2 2019. 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 2019, two net wells came on production averaging approximately 660 bbl/d and four million cubic feet per day per well, exceeding expectations by approximately 110 bbl/d or 20 per cent per well.
  • At Pine River, the company's planned plant turnaround began in mid-September and was completed on Nov. 6, 2019. The turnaround was designed to improve plant efficiency, run time, lower operating costs and improve plant capability to 120 million cubic feet per day from current levels of 95 million cubic feet per day.
  • In Q3 2019, based upon corporate quarterly natural gas production, Canadian Natural used the equivalent of approximately 44 per cent within its operations, providing a natural hedge from the challenging Western Canadian natural gas price environment. Approximately 32 per cent of the company's Q3 2019 natural gas production was exported to other North American markets and sold internationally, with the remaining 24 per cent of the company's Q3 2019 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 million cubic feet per day and 1,545 million cubic feet per day.

                                    INTERNATIONAL EXPLORATION AND PRODUCTION
 
                                                             Three months ended               Nine months ended
                                  Sept. 30, 2019  June 30, 2019  Sept. 30, 2018  Sept. 30, 2019  Sept. 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 2019, exceeding quarterly production guidance, averaging 48,681 bbl/d, a decrease of 5 per cent from Q2 2019 and an increase of 2 per cent over Q3 2018 levels. The decrease from Q2 2019 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 2018 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 2019, comparable with Q2 2019 and a 4-per-cent decrease from Q3 2018 levels. The decrease from Q3 2018 was primarily as a result of planned maintenance activities and natural field declines partly offset by volumes from new wells:
      • Third quarter 2019 operating costs in the North Sea averaged $37.11/bbl (23.04 British pounds/bbl), in line with Q2 2019 and Q3 2018 levels.
      • The company completed its 2019 drilling program in Q3 2019 drilling three gross (3.0 net) high netback producer wells. Initial production from the total drilling program consisting of five 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 2019 averaged 21,227 bbl/d, a decrease of 10 per cent from Q2 2019 and an increase of 13 per cent over Q3 2018 levels. The decrease from Q2 2019 was primarily as a result of natural field declines and turnaround activities in the quarter. The increase from Q3 2018 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:
      • Ivory Coast crude oil operating costs averaged $11.06/bbl ($8.42 (U.S.)/bbl) in Q3 2019, an increase of 32 per cent from Q2 2019 and a decrease of 21 per cent from Q3 2018 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-per-cent working interest, the operator is preparing to commence a comprehensive 3-D and 2-D seismic acquisition program in Q4 2019, with targeted completion in Q2 2020:
        • 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 $300-million (U.S.).
  • The company's annual 2019 international production guidance remains unchanged and is targeted to range from 46,000 bbl/d to 50,000 bbl/d.

                           NORTH AMERICA OIL SANDS MINING AND UPGRADING
 
                                                      Three months ended                 Nine months ended
                        Sept. 30, 2019    June 30, 2019   Sept. 30, 2018   Sept. 30, 2019   Sept. 30, 2018
Synthetic crude oil
production (bbl/d)             432,203          374,500          394,382          407,695          419,161

  • 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 2019, increases of 15 per cent and 10 per cent over Q2 2019 and Q3 2018 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 ($15.18 (U.S.)/bbl) of SCO in Q3 2019, comparable with record low operating costs of $19.97/bbl ($15.12 (U.S.)/bbl) of SCO achieved in Q4 2018, impressive results given the planned turnaround activities in the quarter. Third quarter 2019 operating costs represent decreases of 17 per cent and 12 per cent from Q2 2019 and Q3 2018 levels, respectively:
      • Total production costs were $784-million in Q3 2019, $30-million lower than Q2 2019. Production costs for the first nine months of 2019 were $2,420-million, a 6-per-cent 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 per cent 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.
  • The company's annual 2019 oil sands mining and upgrading production guidance remains unchanged and is targeted to range between 405,000 bbl/d and 415,000 bbl/d of SCO.

Marketing:

  • 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 2020.
    • 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 2019, 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.
  • Third quarter 2019 differentials between WCS and WTI benchmark pricing narrowed from Q3 2018 levels following the government of Alberta's announcement of mandatory curtailments of crude oil production that came into effect Jan. 1, 2019.
  • AECO natural gas prices decreased in Q3 2019 from Q2 2019 and Q3 2018 levels, reflecting pipeline egress constraints out of the basin as well as increased natural gas production in North America. During Q3 2019, 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-per-cent interest in the NWR partnership.

Environmental highlights:

  • In July, 2019, Canadian Natural published its 2018 stewardship report to stakeholders, which is available on the company's website. 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 per cent of direct emissions from its Alberta oil sands in situ and mining operations were third party verified. The 2018 verification was completed by professional engineering firm GHD Ltd.:
    • Canadian Natural's corporate greenhouse gas (GHG) emissions intensity has decreased by approximately 29 per cent from 2012 to 2018, a material reduction in emissions intensity.
    • The company's corporate GHG emissions intensity decreased in 2018 by approximately 29 per cent from 2012 levels, including a reduction of approximately 37 per cent at Horizon oil sands:
      • The company's corporate GHG emissions intensity decreased in 2018 by approximately 5 per cent from 2017 levels, including a reduction of approximately 18 per cent in oil sands mining and upgrading.
    • Methane emissions have decreased 78 per cent 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 per cent and natural gas venting decreased by 6 per cent from 2017 levels.
    • In 2018, in the company's North America E&P segment, Canadian Natural abandoned 1,293 wells, an increase of 68 per cent over 2017 levels, and submitted 1,012 reclamation certificates, an increase of approximately 67 per cent 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-per-cent increase over 2017 levels.
    • In the oil sands mining and upgrading segment, water use intensity decreased in 2018 by 30 per cent from 2017 levels.
    • Approximately 75 per cent 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-end 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 carbon dioxide. The company has carbon capture and sequestration facilities at Horizon, a 70-per-cent working interest in the Quest carbon capture and storage project at Scotford, and by way of carbon capture facilities at its 50-per-cent 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 capturers and sequesters 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.

Financial review

The company continues to implement proven strategies and its disciplined approach to capital allocation. As a result, the financial position of Canadian Natural remains strong. Canadian Natural's adjusted funds flow generation, credit facilities, U.S. commercial paper program, access to capital markets, diverse asset base and related flexible capital expenditure programs all support a flexible financial position and provide the appropriate financial resources for the near, mid- and long term:

  • The company's strategy is to maintain a diverse portfolio balanced across various commodity types. The company achieved production levels of 1,176,361 boe/d in Q3 2019, with approximately 98 per cent of total production located in G7 countries:
    • Canadian Natural maintains a balance of products with Q3 2019 production mix on a boe/d basis of 49 per cent light crude oil and SCO blends, 30 per cent heavy crude oil blends and 21 per cent 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 2019, reflecting the strength of our long-life low decline asset base and the company's effective and efficient operations:
    • Balance sheet strength remains a focus and free cash flow was used to reduce debt levels in Q3 2019 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 2019 by $1,018-million from Q2 2019 levels.
    • Net long-term debt was reduced by $796-million to $22,313-million in Q3 2019.
    • The company utilized adjusted funds flow to repay and cancel $800-million of the $1.8-billion non-revolving term loan facility; $1-billion 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-billion non-revolving term loan; $500-million remains outstanding and fully drawn as at Nov. 6, 2019.
    • Debt to book capitalization strengthened to 39.1 per cent in Q3 2019.
    • Canadian Natural maintains strong financial stability and liquidity represented by cash balances, and committed and demand bank credit facilities. At Sept. 30, 2019, the company had approximately $4.68-billion of available liquidity, including cash and cash equivalents, an increase of approximately $120-million over Q2 2019 levels.
    • Canadian Natural is committed to returns to its shareholders, returning a total of $616-million in Q3 2019, $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 $2.1-billion to its shareholders, $1,299-million by way of dividends and $801-million by way of share purchases:
      • Share purchases for cancellation in the quarter totalled 5.05 million common shares at a weighted average share price of $33.45.
      • Subsequent to quarter-end, up to and including Nov. 6, 2019, the company executed on additional share purchases for cancellation of 1.35 million common shares at a weighted average share price of $33.70.
      • Subsequent to quarter-end, the company declared a quarterly dividend of 37.5 cents per share, payable on Jan. 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 Sept. 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 per cent 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 per cent to reducing debt levels on the company's balance sheet. This free cash flow policy will target a ratio of debt to adjusted 12-month trailing EBITDA (earnings before interest, taxes, depreciation and amortization) of 1.5 times, and an absolute debt level of $15.0-billion, at which time the policy will be reviewed by the board. This policy was effective Nov. 1, 2018.

Corporate update

Canadian Natural is pleased to announce the appointment of Dr. M. Elizabeth Cannon to the board of directors of the company, effective Nov. 5, 2019. Dr. Cannon is currently president emerita and professor of engineering at the University of Calgary having previously served at the University of Calgary as dean of the Schulich School of Engineering from 2006 to 2010, president and vice-chancellor from 2010 to 2018. Dr. Cannon is a fellow of the Royal Society of Canada and the Canadian Academy of Engineering, an associate of the National Academy of Engineering (U.S.) and a corresponding member of the Mexican Academy of Engineering. She has served on the federal government's science, technology and innovation council, is past president of the U.S. Institute of Navigation, and is a past director of the Canada Foundation for Innovation. Dr. Cannon holds a bachelor of applied sciences (mathematics) from Acadia University as well as bachelor of science, master of science and a PhD in geomatics engineering, all from the University of Calgary. Dr. Cannon is a professional engineer and an APEGA member. She also holds honourary doctorates from three universities as well as an honourary bachelor of business administration from SAIT.

Outlook

The company targets annual 2019 production levels to average between 839,000 bbl/d and 888,000 bbl/d of crude oil and NGL and between 1,485 million cubic feet per day and 1,545 million cubic feet per day of natural gas, before royalties. Detailed guidance on production levels, capital allocation and operating costs can be found on the company's website.

Canadian Natural's annual 2019 capital expenditures are targeted to be approximately $3.8-billion.

Conference call

A conference call will be held at 9 a.m. Mountain Time, 11 a.m. Eastern Time on Thursday, Nov. 7, 2019.

The North American conference call number is 1-866-521-4909 and the outside North American conference call number is 001-647-427-2311. Please call in 10 minutes prior to the call starting time.

An archive of the broadcast will be available until 6 p.m. Mountain Time, Thursday, Nov. 21, 2019. To access the rebroadcast in North America, dial 1-800-585-8367. Those outside of North America, dial 001-416-621-4642. The conference archive ID number is 1387024.

The conference call will also be webcast live and can be accessed on the company's website.

About Canadian Natural Resources Ltd.

Canadian Natural is a senior oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the United Kingdom portion of the North Sea and offshore Africa.

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