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Canadian Natural Resources Limited Announces 2019 First Quarter Results

GlobeNewswire - Thu May 9, 4:45AM CDT

Commenting on the Company's first quarter 2019 results, Steve Laut, Executive Vice-Chairman of Canadian Natural stated, "In the first quarter, the Company demonstrated the resilience and strength of its long life low decline and low capital exposure assets, generating significant adjusted funds flow of approximately $2.2 billion. The Company was able to achieve adjusted funds flow that exceeded net capital expenditures by approximately $1.3 billion, largely due to a strong operational quarter and improvement in crude oil differentials, driven by the Government of Alberta's mandatory production curtailments which is strongly supported by Canadian Natural.

Canadian Natural's top tier low sustaining capital required to maintain production levels, combined with industry leading effective and efficient operations, were evident in Q1/19 as adjusted funds flow less net capital expenditures was comparable to Q1/18 when West Texas Intermediate ("WTI") was approximately US$8.00/bbl higher."

Canadian Natural's President, Tim McKay, added, "Operations were strong in the first quarter as our large, balanced and diverse asset base allowed the Company to strategically manage through the mandatory production curtailments to maximize value. Production was as expected in Q1/19, reaching approximately 1,035,000 BOE/d, consisting of 54% light crude oil, NGLs and Synthetic Crude Oil ("SCO"), 22% heavy crude oil and 24% natural gas.

Effective and efficient operations across the Company continue to be a significant driver of value creation for Canadian Natural. Our Oil Sands Mining and Upgrading segment Q1/19 operating costs were top tier at $21.46/bbl (US$16.14/bbl) of SCO. Equally as impressive were our Conventional E&P assets achieving operating costs of $12.68/BOE (US$9.54/BOE) in Q1/19, a reduction of 6% from Q4/18 levels, strong results given mandatory production curtailments in the quarter."

Canadian Natural's Chief Financial Officer, Mark Stainthorpe, continued, "In the first quarter, Canadian Natural realized solid results as profitability and value from our diverse asset base generated net earnings of approximately $1.0 billion. Net earnings were up dramatically from Q4/18, reflecting the dysfunctional crude oil market which existed in Q4/18 and the success of the Government of Alberta's mandatory production curtailment program to restore a normal market in Q1/19.

The Company's capital discipline and financial strength resulted in robust free cash flow of $860 million, after net capital expenditures and dividends. Share purchases were $241 million (6.65 million shares) in Q1/19 pursuant to the Company's free cash flow allocation policy. As a result of the increased confidence in free cash flow levels for the remainder of 2019, the rate of share purchases has increased as Q2/19 commenced, with purchases totaling $159 million (4.05 million shares) from April 1, 2019 to May 8th, 2019."

QUARTERLY HIGHLIGHTS

Three Months Ended
($ millions, except per common share amounts)                Mar 31       Dec 31        Mar 31
                                                             2019         2018          2018
Net earnings (loss)                                          $    961     $    (776  )  $    583
Per common share                     - basic                 $    0.80    $    (0.64 )  $    0.48
                                     - diluted               $    0.80    $    (0.64 )  $    0.47
Adjusted net earnings (loss) from operations                 $    838     $    (255  )  $    885
Per common share                     - basic                 $    0.70    $    (0.21 )  $    0.72
                                     - diluted               $    0.70    $    (0.21 )  $    0.71
Cash flows from operating activities                         $    996     $    1,397    $    2,469
Adjusted funds flow                                          $    2,240   $    1,229    $    2,323
Per common share                     - basic                 $    1.87    $    1.02     $    1.90
                                     - diluted               $    1.86    $    1.02     $    1.89
Cash flows used in investing activities                      $    1,029   $    1,042    $    1,369
Net capital expenditures                                     $    977     $    1,181    $    1,103
Daily production, before royalties
Natural gas (MMcf/d)                                         1,510        1,488         1,614
Crude oil and NGLs (bbl/d)                                   783,512      833,358       854,558
Equivalent production (BOE/d)                                1,035,212    1,081,368     1,123,546

    -- Share purchases for cancellation in the quarter totaled 6,650,000 common shares at a weighted average share price of $36.24. Subsequent to quarter end and up to and including May 8, 2019, the Company executed on additional share purchases of 4,050,000 common shares for cancellation at a weighted average share price of $39.34.

    -- Share purchases for cancellation in the quarter totaled 6,650,000 common shares at a weighted average share price of $36.24. Subsequent to quarter end and up to and including May 8, 2019, the Company executed on additional share purchases of 4,050,000 common shares for cancellation at a weighted average share price of $39.34.

    -- In Q1/19 the Company increased its quarterly dividend by 12% from Q4/18 levels, marking the 19th consecutive year that the Company has increased its dividend, reflecting the Board of Directors' confidence in Canadian Natural's sustainability and robustness of the Company's asset base and its ability to generate significant adjusted funds flow.

    -- Subsequent to quarter end, the Company declared a quarterly dividend of $0.375 per share, payable on July 1, 2019.

    -- The Company's Board of Directors has approved a motion to renew the Normal Course Issuance Bid ("NCIB") and the continuation of the free cash flow allocation policy.

      -- The Company continues to strategically adjust timing of planned maintenance activities across its asset base, including Oil Sands Mining and Upgrading, thermal in situ and North American Exploration & Production ("E&P") to maximize value within the current curtailment environment.

      -- The Company continues to strategically adjust timing of planned maintenance activities across its asset base, including Oil Sands Mining and Upgrading, thermal in situ and North American Exploration & Production ("E&P") to maximize value within the current curtailment environment.

        -- Operating costs were top tier, as the Company realized quarterly unadjusted operating costs of $21.46/bbl (US$16.14/bbl) of SCO in Q1/19, in-line with Q1/18 levels, strong results given curtailment and maintenance activities in the quarter.

        -- Operating costs were top tier, as the Company realized quarterly unadjusted operating costs of $21.46/bbl (US$16.14/bbl) of SCO in Q1/19, in-line with Q1/18 levels, strong results given curtailment and maintenance activities in the quarter.

        -- As previously announced on May 1, 2019, Canadian Natural provided a follow up on a fire which occurred at the Scotford Upgrader on April 15, 2019, in which the Company has a 70% interest. The fire was promptly extinguished, all personnel were accounted for, and there were no reported injuries.

          -- The fire was contained to a process furnace in the North Upgrader, while operations at the base upgrader plant ("South Upgrader") were not impacted by the fire. The planned 38 day turnaround began on April 14, 2019 at the Scotford Upgrader, during which time the South Upgrader will run at a restricted net processing rate of approximately 140,000 bbl/d of SCO. Upon completion of the planned maintenance, May and June average net production at the Albian mines is targeted to be approximately 171,500 bbl/d versus the Company's previously targeted net curtailment production volumes at the Albian mines of approximately 178,500 bbl/d. The cost for repairs of the North Upgrader is estimated to be approximately $15 million gross and is targeted to be fully operational by early June. The Company continues to optimize other assets in Alberta to mitigate the impacts of curtailments on its production.

          -- The fire was contained to a process furnace in the North Upgrader, while operations at the base upgrader plant ("South Upgrader") were not impacted by the fire. The planned 38 day turnaround began on April 14, 2019 at the Scotford Upgrader, during which time the South Upgrader will run at a restricted net processing rate of approximately 140,000 bbl/d of SCO. Upon completion of the planned maintenance, May and June average net production at the Albian mines is targeted to be approximately 171,500 bbl/d versus the Company's previously targeted net curtailment production volumes at the Albian mines of approximately 178,500 bbl/d. The cost for repairs of the North Upgrader is estimated to be approximately $15 million gross and is targeted to be fully operational by early June. The Company continues to optimize other assets in Alberta to mitigate the impacts of curtailments on its production.

            -- International production volumes benefit from premium Brent pricing, generating significant adjusted funds flow for the Company.

            -- International production volumes benefit from premium Brent pricing, generating significant adjusted funds flow for the Company.

            OPERATIONS REVIEW AND CAPITAL ALLOCATION

            Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural's production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen and SCO (herein collectively referred to as "crude oil"), natural gas and NGLs. This balance provides optionality for capital investments, 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 its conventional asset base. These projects can be executed quickly and with the right economic conditions, can provide excellent returns and maximize value for shareholders. Supporting these projects is the Company's undeveloped land base which enables large, repeatable drilling programs which can be optimized over time. Additionally, by owning and operating most of the related infrastructure, Canadian Natural is able to control major components of its 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

            Three Months Ended Mar 31
                                                                        2019           2018
            (number of wells)                                           Gross  Net     Gross  Net
            Crude oil                                                   30     30      127    122
            Natural gas                                                 10     8       8      5
            Dry                                                         1      1       2      2
            Subtotal                                                    41     39      137    129
            Stratigraphic test / service wells                          375    332     528    450
            Total                                                       416    371     665    579
            Success rate (excluding stratigraphic test / service wells)        97  %          98  %

            North America Exploration and Production

            Crude oil and NGLs - excluding Thermal In Situ Oil Sands
                                                  Three Months Ended
                                                  Mar 31     Dec 31     Mar 31
                                                  2019       2018       2018
            Crude oil and NGLs production (bbl/d) 225,291    240,942    245,609
            Net wells targeting crude oil         28         62         101
            Net successful wells drilled          28         61         99
            Success rate                          100      % 98       % 98       %

              -- Canadian Natural's primary heavy crude oil production averaged 68,473 bbl/d in Q1/19, reflecting mandatory production curtailments, and the strategic decision to reduce activity on drilling, workovers, recompletions and optimization activities in a curtailed market in Q1/19, representing a decrease of 14% from Q4/18 levels that were already voluntarily curtailed by approximately 9,600 bbl/d.

              -- Canadian Natural's primary heavy crude oil production averaged 68,473 bbl/d in Q1/19, reflecting mandatory production curtailments, and the strategic decision to reduce activity on drilling, workovers, recompletions and optimization activities in a curtailed market in Q1/19, representing a decrease of 14% from Q4/18 levels that were already voluntarily curtailed by approximately 9,600 bbl/d.

                -- Operating costs of $17.30/bbl were achieved in the Company's primary heavy crude oil operations in the quarter, a 2% increase from Q1/18 levels, strong results given lower production volumes due to mandatory production curtailments.

                -- Operating costs of $17.30/bbl were achieved in the Company's primary heavy crude oil operations in the quarter, a 2% increase from Q1/18 levels, strong results given lower production volumes due to mandatory production curtailments.

                -- North America light crude oil and NGL production averaged 95,578 bbl/d in Q1/19, reflecting mandatory production curtailments in the Company's light crude oil segment, representing a decrease of 3% from Q4/18 levels that were already voluntarily curtailed by approximately 1,000 bbl/d.

                  -- Within the greater Wembley area, results continue to exceed expectations. The Company brought 10 net wells on production in Q1/19 that were drilled late in 2018, with initial 30 day liquids production rates averaging approximately 580 bbl/d per well. An additional 3 net wells are targeted to come on production in Q2/19 and Q3/19. Within the greater Wembley area, the Company has identified 155 net Montney sections and 363 incremental potential premium light crude oil and liquids rich well locations.

                  -- Within the greater Wembley area, results continue to exceed expectations. The Company brought 10 net wells on production in Q1/19 that were drilled late in 2018, with initial 30 day liquids production rates averaging approximately 580 bbl/d per well. An additional 3 net wells are targeted to come on production in Q2/19 and Q3/19. Within the greater Wembley area, the Company has identified 155 net Montney sections and 363 incremental potential premium light crude oil and liquids rich well locations.

                  -- In the Company's Karr area, 12 net wells came on production in Q1/19, 9 were drilled in Q4/18 and 3 were drilled in Q1/19. Early results have been strong from these wells, with total liquids production of approximately 315 bbl/d per well, exceeding expectations.

                  -- In Southeast Saskatchewan and Manitoba, the Company drilled 9 net light crude oil wells in Q1/19. Subsequent to quarter end, these wells came on stream and are currently producing approximately 85 bbl/d per well, in-line with expectations. Production from these Saskatchewan and Manitoba wells are not impacted by production curtailments.

                  -- In Q1/19 operating costs of $15.86/bbl were realized in the Company's North America light crude oil and NGL areas, comparable to Q1/18 levels.

                  -- Pelican Lake quarterly production averaged 61,240 bbl/d in Q1/19, a decrease of 2% from Q4/18 levels.

                    -- Strong operating costs of $6.69/bbl were achieved in Q1/19 at Pelican Lake, a reduction of 5% from Q1/18 levels.

                    -- Strong operating costs of $6.69/bbl were achieved in Q1/19 at Pelican Lake, a reduction of 5% from Q1/18 levels.

                    -- Subsequent to quarter end, in April 2019 facility consolidation was completed on time and on budget, and as a result operating cost savings of approximately $6 million per year are targeted.

                    -- The Company targets to expand the polymer flood further in Q2/19, with the conversion of 3 additional pads from water flood to polymer flood.

                    Thermal In Situ Oil Sands
                                                 Three Months Ended
                                                 Mar 31  Dec 31      Mar 31
                                                 2019    2018        2018
                    Bitumen production (bbl/d)   94,146  102,112     111,851
                    Net wells targeting bitumen  --      41          22
                    Net successful wells drilled --      40          22
                    Success rate                 --      98      %   100     %

                      -- At Primrose, Q1/19 production volumes averaged 61,925 bbl/d, a decrease of 9% from Q4/18 levels, as a result of production curtailments. Including energy costs, operating costs were $20.23/bbl in Q1/19, an increase of 22% from Q1/18, reflecting lower volumes due to curtailments and higher energy costs.

                      -- At Primrose, Q1/19 production volumes averaged 61,925 bbl/d, a decrease of 9% from Q4/18 levels, as a result of production curtailments. Including energy costs, operating costs were $20.23/bbl in Q1/19, an increase of 22% from Q1/18, reflecting lower volumes due to curtailments and higher energy costs.

                        -- Pad additions at Primrose continue to be on budget and ahead of schedule with initial production targeted in Q4/19. The program targets to add approximately 26,000 bbl/d in the first 12 months of production. These pad additions are high return activities as the Company utilizes available excess oil processing and steam capacity at Primrose.

                        -- Pad additions at Primrose continue to be on budget and ahead of schedule with initial production targeted in Q4/19. The program targets to add approximately 26,000 bbl/d in the first 12 months of production. These pad additions are high return activities as the Company utilizes available excess oil processing and steam capacity at Primrose.

                        -- At Kirby South, SAGD production volumes averaged 29,692 bbl/d in Q1/19, a decrease of 8% from Q4/18 levels. Including energy costs, Kirby South quarterly operating costs were $12.31/bbl in Q1/19, an increase of 35% from Q1/18 as a result of lower volumes and higher energy costs.

                        -- As previously announced, at the Company's Kirby North SAGD project, top tier execution and strong productivity have resulted in the project progressing two quarters ahead of the sanctioned schedule with overall cost performance remaining on budget. The commissioning of the central processing facility was also top tier and as a result the project began steaming on May 1, 2019 and targets to progressively ramp up production towards Kirby North's overall capacity of 40,000 bbl/d, in late 2020.

                        North America Natural Gas
                                                        Three Months Ended
                                                        Mar 31     Dec 31     Mar 31
                                                        2019       2018       2018
                        Natural gas production (MMcf/d) 1,454      1,441      1,547
                        Net wells targeting natural gas 9          3          5
                        Net successful wells drilled    8          3          5
                        Success rate                    89     %   100    %   100    %

                          -- Modest drilling activity from prolific wells targets to return the Septimus plant to full capacity, while reducing already low Q1/19 operating costs of $0.36/Mcfe, supporting high netbacks and maximizing value.

                          -- Modest drilling activity from prolific wells targets to return the Septimus plant to full capacity, while reducing already low Q1/19 operating costs of $0.36/Mcfe, supporting high netbacks and maximizing value.

                          -- The Company's natural gas reinjection pilot at Septimus is targeted to commence first injection of 5 MMcf/d late in Q2/19. 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.

                            -- Results from the first injection and production cycle 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.

                            -- Results from the first injection and production cycle 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.

                            International Exploration and Production

                            Three Months Ended
                                                            Mar 31     Dec 31     Mar 31
                                                            2019       2018       2018
                            Crude oil production (bbl/d)
                            North Sea                       25,714     21,071     21,584
                            Offshore Africa                 22,155     22,185     19,438
                            Natural gas production (MMcf/d)
                            North Sea                       28         22         37
                            Offshore Africa                 28         25         30
                            Net wells targeting crude oil   1.6        1.1        1.0
                            Net successful wells drilled    1.6        1.1        1.0
                            Success rate                    100    %   100    %   100    %

                            -- International production volumes benefit from premium Brent pricing, generating significant adjusted funds flow for the Company.

                              -- In the North Sea, production volumes of 25,714 bbl/d were achieved in Q1/19, increases of 22% and 19% over Q4/18 and Q1/19 levels respectively. The increase over Q4/18 primarily reflected the impact of production resuming following the planned turnarounds and maintenance activities completed during Q4/18. The increase over Q1/18 primarily reflected the impact of the drilling program completed in 2018, partially offset by natural field declines.

                              -- In the North Sea, production volumes of 25,714 bbl/d were achieved in Q1/19, increases of 22% and 19% over Q4/18 and Q1/19 levels respectively. The increase over Q4/18 primarily reflected the impact of production resuming following the planned turnarounds and maintenance activities completed during Q4/18. The increase over Q1/18 primarily reflected the impact of the drilling program completed in 2018, partially offset by natural field declines.

                              • Q1/19 operating costs in the North Sea averaged $39.68/bbl (£22.60/bbl), a reduction of 9% from Q1/18 levels.

                                -- Offshore Africa production volumes in Q1/19 averaged 22,155 bbl/d, in-line with Q4/18 levels and an increase of 14% over Q1/18 levels. The increase in production over Q1/18 primarily reflected volumes from new wells drilled at Baobab in 2018, partially offset by the cessation of production at the Olowi field in Gabon in December 2018 and natural field declines.

                                • Cote d'Ivoire crude oil operating costs averaged $9.79/bbl (US$7.36/bbl) in Q1/19, a reduction of 3% from Q1/18 levels.

                                    -- The total Baobab drilling program included 4 gross (2.4 net) producer wells and 2 gross (1.2 net) injector wells, of which the second gross (0.6 net) injector well was completed subsequent to quarter end in Q2/19.

                                    -- The total Baobab drilling program included 4 gross (2.4 net) producer wells and 2 gross (1.2 net) injector wells, of which the second gross (0.6 net) injector well was completed subsequent to quarter end in Q2/19.

                                      -- The Espoir drilling program is targeting 3 gross producer wells (1.8 net) and 2 gross injector wells (1.2 net) with the potential to add an average of approximately 2,500 BOE/d of high netback production per well in the first 12 months. Approximately 75% of production is targeted to be light crude oil.

                                      -- The Espoir drilling program is targeting 3 gross producer wells (1.8 net) and 2 gross injector wells (1.2 net) with the potential to add an average of approximately 2,500 BOE/d of high netback production per well in the first 12 months. Approximately 75% of production is targeted to be light crude oil.

                                      -- In Q1/19, the operator of the South Africa exploration well, where Canadian Natural owns a 20% working interest, announced a discovery of significant gas condensate. The cost of the first exploration well is fully carried.

                                      • In 2019, the operator targets to acquire 3D seismic on the Block.

                                        North America Oil Sands Mining and Upgrading

                                        Three Months Ended
                                                                               Mar 31   Dec 31   Mar 31
                                                                               2019     2018     2018
                                        Synthetic crude oil production (bbl/d) 416,206  447,048  456,076

                                        -- SCO production before royalties and excludes volumes consumed internally as diesel.

                                        -- Consists of heavy and light synthetic crude oil products.

                                          -- Operating costs were top tier, as the Company realized quarterly unadjusted operating costs of $21.46/bbl (US$16.14/bbl) of SCO in Q1/19, in-line with Q1/18 levels, strong results given curtailment and maintenance activities in the quarter.

                                          -- Operating costs were top tier, as the Company realized quarterly unadjusted operating costs of $21.46/bbl (US$16.14/bbl) of SCO in Q1/19, in-line with Q1/18 levels, strong results given curtailment and maintenance activities in the quarter.

                                            -- The potential Paraffinic Froth Treatment expansion at Horizon is targeting 40,000 bbl/d to 50,000 bbl/d of high quality diluted bitumen at significantly lower operating costs as the Company leverages its existing infrastructure. The preliminary estimate of the capital required is approximately $1.4 billion.

                                            -- The potential Paraffinic Froth Treatment expansion at Horizon is targeting 40,000 bbl/d to 50,000 bbl/d of high quality diluted bitumen at significantly lower operating costs as the Company leverages its existing infrastructure. The preliminary estimate of the capital required is approximately $1.4 billion.

                                            -- Stage 1 and 2 reliability opportunities at Horizon are targeted to add 35,000 bbl/d to 45,000 bbl/d of SCO.

                                            -- The Company targets to sanction the potential expansion and reliability opportunities with greater clarity on improved market access.

                                              -- The fire was contained to a process furnace in the North Upgrader, while operations at the base upgrader plant ("South Upgrader") were not impacted by the fire. The planned 38 day turnaround began on April 14, 2019 at the Scotford Upgrader, during which time the South Upgrader will run at a restricted net processing rate of approximately 140,000 bbl/d of SCO. Upon completion of the planned maintenance, May and June average net production at the Albian mines is targeted to be approximately 171,500 bbl/d versus the Company's previously targeted net curtailment production volumes at the Albian mines of approximately 178,500 bbl/d. The cost for repairs of the North Upgrader is estimated to be approximately $15 million gross and is targeted to be fully operational by early June. The Company continues to optimize other assets in Alberta to mitigate the impacts of curtailments on its production.

                                              -- The fire was contained to a process furnace in the North Upgrader, while operations at the base upgrader plant ("South Upgrader") were not impacted by the fire. The planned 38 day turnaround began on April 14, 2019 at the Scotford Upgrader, during which time the South Upgrader will run at a restricted net processing rate of approximately 140,000 bbl/d of SCO. Upon completion of the planned maintenance, May and June average net production at the Albian mines is targeted to be approximately 171,500 bbl/d versus the Company's previously targeted net curtailment production volumes at the Albian mines of approximately 178,500 bbl/d. The cost for repairs of the North Upgrader is estimated to be approximately $15 million gross and is targeted to be fully operational by early June. The Company continues to optimize other assets in Alberta to mitigate the impacts of curtailments on its production.

                                              MARKETING

                                              Three Months Ended
                                                                                                        Mar 31       Dec 31       Mar 31
                                                                                                        2019         2018         2018
                                              Crude oil and NGLs pricing
                                              WTI benchmark price (US$/bbl)                             $   54.90    $   58.83    $   62.89
                                              WCS heavy differential as a percentage of WTI (%)         23        %  67        %  39        %
                                              SCO price (US$/bbl)                                       $   52.19    $   37.48    $   61.45
                                              Condensate benchmark pricing (US$/bbl)                    $   50.49    $   45.27    $   63.12
                                              Average realized pricing before risk management (C$/bbl)  $   53.98    $   25.95    $   43.06
                                              Natural gas pricing
                                              AECO benchmark price (C$/GJ)                              $   1.84     $   1.80     $   1.75
                                              Average realized pricing before risk management (C$/Mcf)  $   3.09     $   3.46     $   2.74

                                              -- West Texas Intermediate ("WTI").

                                              -- Western Canadian Select ("WCS").

                                              -- Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities.

                                              -- The North West Redwater ("NWR") refinery, upon completion, will 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/.

                                                ENVIRONMENTAL HIGHLIGHTS

                                                -- 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 usage 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. As a result of the positive results thus far, the Company continues to make enhancements and will operate and test the pilot through 2019.

                                                  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, US 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.

                                                    -- Canadian Natural maintains a balance of products with Q1/19 production mix on a BOE/d basis of 54% light crude oil and SCO blends, 22% heavy crude oil blends and 24% natural gas.

                                                    -- Canadian Natural maintains a balance of products with Q1/19 production mix on a BOE/d basis of 54% light crude oil and SCO blends, 22% heavy crude oil blends and 24% natural gas.

                                                      -- Share purchases for cancellation in the quarter totaled 6,650,000 common shares at a weighted average share price $36.24. Subsequent to quarter end and up to and including May 8, 2019, the Company executed on additional share purchases of 4,050,000 common shares for cancellation at a weighted average share price of $39.34.

                                                      -- Share purchases for cancellation in the quarter totaled 6,650,000 common shares at a weighted average share price $36.24. Subsequent to quarter end and up to and including May 8, 2019, the Company executed on additional share purchases of 4,050,000 common shares for cancellation at a weighted average share price of $39.34.

                                                      -- In Q1/19 the Company increased its quarterly dividend 12% from Q4/18 levels, marking the 19th consecutive year that the Company has increased its dividend, reflecting the Board of Directors' confidence in Canadian Natural's sustainability and robustness of the asset base driving the ability to generate significant adjusted funds flow.

                                                      -- Subsequent to quarter end, the Company declared a quarterly dividend of $0.375 per share, payable on July 1, 2019.

                                                        -- The Company's Board of Director's has approved a motion to renew the NCIB and the continuation of the free cash flow allocation policy.

                                                        -- The Company's Board of Director's has approved a motion to renew the NCIB and the continuation of the free cash flow allocation policy.

                                                        OUTLOOK

                                                        The Company targets annual 2019 production levels to average between 782,000 bbl/d and 861,000 bbl/d of crude oil and NGLs and between 1,485 MMcf/d and 1,545 MMcf/d of natural gas, before royalties. Q2/19 production guidance before royalties is targeted to average between 773,000 bbl/d and 831,000 bbl/d of crude oil and NGLs and between 1,500 MMcf/d and 1,530 MMcf/d of natural gas. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company's website at www.cnrl.com.

                                                        Canadian Natural's annual 2019 capital expenditures are targeted to be approximately $3.7 billion.

                                                        ADVISORY

                                                        Special Note Regarding Forward-Looking Statements

                                                        Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses and other guidance provided throughout the Company's Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the timing and future operations of the North West Redwater bitumen upgrader and refinery, construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market, and the development and deployment of technology and technological innovations also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.

                                                        In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.

                                                        The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company's products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company's current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company's and its subsidiaries' ability to secure adequate transportation for its products; unexpected disruptions or delays in the resumption of the mining, extracting or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's and its subsidiaries' success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); asset retirement obligations; the adequacy of the Company's provision for taxes; and other circumstances affecting revenues and expenses.

                                                        The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available.

                                                        Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in the Company's MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company's estimates or opinions change.

                                                        Special Note Regarding Non-GAAP and Other Financial Measures

                                                        This press release includes references to financial measures commonly used in the crude oil and natural gas industry, such as: adjusted net earnings (loss) from operations; adjusted funds flow (previously referred to as funds flow from operations); net capital expenditures; free cash flow; debt to adjusted EBITDA; available liquidity; adjusted operating costs; unadjusted operating costs; and enterprise value. These financial measures are not defined by International Financial Reporting Standards ("IFRS") and therefore are referred to as non-GAAP measures and other financial measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings (loss), cash flows from operating activities, cash flows used in investing activities, and cash flows used in financing activities as determined in accordance with IFRS, as an indication of the Company's performance.

                                                        Adjusted net earnings (loss) from operations is a non-GAAP measure that represents net earnings (loss) as presented in the Company's consolidated Statements of Earnings (Loss), adjusted for the after-tax effects of certain items of a non-operational nature. The Company considers adjusted net earnings (loss) 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 (Loss) from Operations, as Reconciled to Net Earnings (Loss)" is presented in the Company's MD&A.

                                                        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 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 the Company's MD&A.

                                                        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 acquisitions 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 the Company's MD&A.

                                                        Free cash flow 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 from operating activities, abandonment, certain movements in other long-term assets, less net capital expenditures and dividends on common shares. The Company considers free cash flow a key measure in demonstrating the Company's ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders, and to repay debt.

                                                        Adjusted EBITDA is a non-GAAP measure that represents net earnings (loss) as presented in the Company's consolidated Statements of Earnings (Loss), adjusted for interest, taxes, depletion, depreciation and amortization, stock based compensation expense (recovery), unrealized risk management gains (losses), unrealized foreign exchange gains (losses), and accretion of the Company's asset retirement obligation. The Company considers adjusted EBITDA a key measure in evaluating its operating profitability by excluding non-cash items.

                                                        Debt to Adjusted EBITDA is a non-GAAP measure that is derived as the current and long-term portions of long-term debt, divided by the 12 month trailing Adjusted EBITDA, as defined above. The Company considers this ratio to be a key measure in evaluating the Company's ability to pay off its debt.

                                                        Available liquidity is a non-GAAP measure that is derived as cash and cash equivalents, total bank and term credit facilities, less amounts drawn on the bank and credit facilities including under the commercial paper program. The Company considers available liquidity a key measure in evaluating the sustainability of the Company's operations and ability to fund future growth. See note 9 - Long-term Debt in the Company's consolidated financial statements.

                                                        Adjusted operating costs are derived as production expense based on sales volumes excluding costs incurred in turnaround periods. See "Operating Highlights - Oil Sands Mining and Upgrading" section in the Company's MD&A.

                                                        Unadjusted operating costs also referred to as cash production costs in the Company's MD&A. See "Operating Highlights - Oil Sands Mining and Upgrading" section in the Company's MD&A.

                                                        Enterprise value is derived as the sum of the Company's market capitalization and total long-term debt less cash and cash equivalents. Market capitalization is derived as total outstanding common shares multiplied by the market price per common share at any given period.

                                                        Special Note Regarding Currency, Financial Information and Production

                                                        The Company's MD&A should be read in conjunction with the unaudited interim consolidated financial statements for the three months ended March 31, 2019 and the MD&A and the audited consolidated financial statements of the Company for the year ended December 31, 2018.

                                                        All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's unaudited interim consolidated financial statements for the three months ended March 31, 2019 and the Company's MD&A have been prepared in accordance with IFRS as issued by the International Accounting Standards Board ("IASB"). Changes in the Company's accounting policies in accordance with IFRS, including the adoption of IFRS 16 "Leases" on January 1, 2019, are discussed in the "Changes in Accounting Policies" section of the Company's MD&A. In accordance with the new "Leases" standard, comparative period balances in 2018 reported in the Company's MD&A have not been restated.

                                                        Production volumes and per unit statistics are presented throughout the Company's MD&A on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of the Company's MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production on an "after royalties" or "company net" basis is also presented for information purposes only.

                                                        Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2018, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. Detailed guidance on production levels, capital expenditures and production expenses can be found on the Company's website at www.cnrl.com.

                                                        CONFERENCE CALL

                                                        A conference call will be held at 8:00 a.m. Mountain Time, 10:00 a.m. Eastern Time on Thursday, May 9, 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 6:00 p.m. Mountain Time, Thursday, May 23, 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 9681416.

                                                        The conference call will also be webcast live and can be accessed on the home page of our website at www.cnrl.com.

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

                                                        CANADIAN NATURAL RESOURCES LIMITED
                                                        2100, 855 - 2nd Street S.W. Calgary, Alberta, T2P4J8
                                                        Phone: 403-514-7777   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

                                                        https://ml.globenewswire.com/media/df8b42fe-b7cb-416d-afd1-1db36216da75/small/canadian-natural-color2-jpg.jpg

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