Canadian Natural Resources Limited Announces 2021 First Quarter Results

Calgary, Alberta–(Newsfile Corp. – May 6, 2021) – Commenting on the Company’s first quarter 2021 results, Tim McKay, President of Canadian Natural stated “The COVID-19 pandemic continues to challenge our everyday living and the way we operate our businesses. With our strong measures in place we have minimized impacts on our operations, but it remains a daily challenge for our field staff to do it safe and do it right. As the global vaccine distribution increases and crude oil demand recovers, especially in the United States, we are seeing improved commodity pricing, and when combined with our top tier execution and disciplined capital program we are well positioned to generate significant free cash flow in 2021.

Our first quarter results were strong as we achieved record quarterly production of approximately 1,246 MBOE/d and record quarterly liquids production of over 979,000 bbl/d, as a result of our effective and efficient operations and high operating levels. As our large and diverse asset base realized strong netbacks, we drove significant adjusted funds flow in the quarter of over $2.7 billion.

In Q1/21 our Oil Sands Mining and Upgrading segment continued to achieve strong operating results with record quarterly production of approximately 468,800 bbl/d of high value Synthetic Crude Oil (“SCO”) and industry leading operating costs of $19.82/bbl (US$15.66/bbl), a decrease of 5% from Q1/20 levels, despite increased energy costs.”

Canadian Natural’s Chief Financial Officer, Mark Stainthorpe, added “Canadian Natural is in a strong financial position. Our robust business model delivered strong financial results with net earnings of approximately $1.4 billion and adjusted net earnings of over $1.2 billion in the first quarter.

Our top tier operating results generated strong quarterly free cash flow of approximately $1.4 billion after capital expenditures and dividends. Accordingly our balance sheet strengthened significantly in Q1/21, as we were able to reduce our net long-term debt by approximately $1.4 billion in Q1/21. Our first quarter debt reduction included the permanent repayment and cancellation of term debt totaling approximately $1.0 billion. Subsequent to quarter end we permanently repaid and cancelled approximately $0.7 billion of additional term debt.

Annual 2021 WTI strip pricing has strengthened and using approximately US$60/bbl our targeted free cash flow increases significantly to $5.7 billion to $6.2 billion, after our budgeted capital program of approximately $3.2 billion and dividends of approximately $2.2 billion. As a result our balance sheet is targeted to further strengthen throughout 2021, with debt to adjusted EBITDA targeted to improve to approximately 1.1x and debt to book capitalization targeted to improve to approximately 29%, at the mid-point of our targeted free cash flow range.”

QUARTERLY HIGHLIGHTS

• Net earnings of $1,377 million and adjusted net earnings from operations of $1,219 million were realized in Q1/21.
  • Adjusted net earnings increased by $1,043 million from Q4/20 levels as a result of higher realized pricing and effective and efficient operations.
• Cash flows from operating activities were $2,536 million in Q1/21.
• The strength of the Company’s assets supported by its safe, effective and efficient operations demonstrated its ability to generate significant and sustainable free cash flow over the long-term, making Canadian Natural’s business unique, robust and sustainable.
  • As a result, Canadian Natural generated strong quarterly adjusted funds flow of $2,712 million in Q1/21, increases of $1,375 million and $1,004 million from Q1/20 and Q4/20 levels respectively, driven by higher realized pricing and effective and efficient operations.
• Canadian Natural generated robust quarterly free cash flow of $1,401 million in Q1/21, after net capital expenditures of $808 million and dividend payments of $503 million, reflecting the strength of the Company’s effective and efficient operations and its high quality, long life low decline asset base.
  • The Company’s 2021 budgeted capital expenditure program of approximately $3.2 billion provides a targeted production range of 1,190 MBOE/d to 1,260 MBOE/d, an increase of 5% at the mid-point from 2020 levels.
• Canadian Natural demonstrated our focus on further strengthening our balance sheet with strong financial results in Q1/21, reducing net debt by approximately $1.4 billion from Q4/20 levels. Since Q2/20 net debt has decreased by approximately $2.9 billion.
  • In Q1/21 the Company repaid $962.5 million on its $3,088 million non-revolving term loan, more than satisfying the required annual amortization of $162.5 million due in June 2021. Subsequent to quarter end, an additional $650 million was repaid on this facility, reducing the outstanding balance to $1,475 million.
  • In Q1/21 the Company’s $1,000 million non-revolving term credit facility, originally due February 2022, was extended to February 2023.
• In March 2021, the Company declared a quarterly dividend of $0.47 per share, an increase of 11% from the previous level of $0.425 per share, marking 2021 as the Company’s 21st consecutive year of dividend increases, reflecting the Board of Directors’ confidence in Canadian Natural’s strength and the robustness of the Company’s assets and its ability to generate significant and sustainable free cash flow.
  • Subsequent to quarter end the Company declared a quarterly dividend of $0.47 per share, payable on July 5, 2021.
• In March 2021, the Board of Directors authorized management to repurchase shares under a Normal Course Issuer Bid (“NCIB”) to approximately offset options exercised throughout the coming year, in order to minimize or eliminate dilution to shareholders.
  • Share repurchases for cancellation in Q1/21 totaled 600,000 common shares at a weighted average price of $38.61.
  • Subsequent to quarter end, up to and including May 5, 2021, the Company executed on additional share repurchases for cancellation of 960,000 common shares at a weighted average share price of $38.15.
• Returns to shareholders have been significant as Canadian Natural has returned approximately $1.1 billion by way of dividends and share repurchases in 2021 up to and including May 5, 2021.
• In Q1/21 the Company achieved record quarterly production volumes of 1,245,703 BOE/d, increases of 6% and 4% from Q1/20 and Q4/20 levels respectively, with continued focus on safe, effective and efficient operations.
  • Record quarterly liquids production was achieved in Q1/21 averaging 979,352 bbl/d, increases of 4% and 6% from Q1/20 and Q4/20 levels respectively.
  • Corporate natural gas production averaged 1,598 MMcf/d in Q1/21, an increase of 11% from Q1/20 levels. The increase from Q1/20 was primarily as a result of acquired production in Q4/20, strong base production and volume additions, partially offset by natural field declines and the shutdown of our Pine River gas plant in February 2021.
    • Corporate natural gas operating costs in Q1/21 averaged $1.27/Mcf, a decrease of 3% from Q1/20 levels and an increase of 15% from Q4/20 levels. The increase from Q4/20 was primarily due to normal seasonality including an increase in electricity costs, partially offset by the impact of the continuous focus on operating costs.
• The Company’s world class Oil Sands Mining and Upgrading assets achieved record quarterly production averaging 468,803 bbl/d of SCO in Q1/21, increases of 7% and 12% from Q1/20 and Q4/20 levels respectively. Record SCO production was primarily as a result of industry leading utilization and operational enhancements.
  • Operating costs from the Company’s Oil Sands Mining and Upgrading assets are top tier, averaging $19.82/bbl (US$15.66/bbl) of SCO in Q1/21, decreases of 5% and 2% from Q1/20 and Q4/20 levels respectively. The reductions were primarily due to our focus on continuous improvement, effective and efficient operations and operational enhancements, offsetting the impact of higher energy costs, including natural gas, in Q1/21.
    • In Q1/21 the Company increased SCO sales from the Oil Sands Mining and Upgrading segment by over 41,000 bbl/d from Q1/20 levels while essentially maintaining absolute operating cost levels, excluding natural gas costs, over the same period, demonstrating the continued focus on effective and efficient operations and the underlying value of high utilization relative to fixed costs.
  • Subsequent to quarter end the planned turnaround at Horizon was successfully completed and SCO production is targeted to resume on May 8, 2021. Additionally, at the Athabasca Oil Sands Project (“AOSP”) the Company targets to perform planned de-coking in May 2021. The Company’s annual 2021 budgeted total production volume range remains unchanged.
• Canadian Natural’s North America E&P liquids production, including thermal in situ, was strong in Q1/21 averaging 478,736 bbl/d, an increase of 5% from Q1/20 levels and comparable with Q4/20 levels.
  • North American E&P liquids, including thermal in situ operations, achieved operating costs of $12.80/bbl (US$10.11/bbl) in Q1/21, comparable with Q1/20 levels of $12.69/bbl and an increase of 18% from Q4/20 levels of $10.81/bbl. The increase in operating costs from Q4/20 levels was primarily due to higher energy costs with the remainder from normal seasonality costs.
• Canadian Natural’s thermal in situ production was strong in Q1/21, averaging 267,530 bbl/d, an increase of 17% over Q1/20 levels and comparable with Q4/20 levels.
  • Strong operating costs from the Company’s thermal in situ assets were achieved in Q1/21, averaging $11.40/bbl (US$9.01/bbl) an increase of 3% from Q1/20 levels. The increase in operating costs was primarily due to increases in energy costs, partially offset by cost reductions as a result of higher production volumes and effective and efficient operations.

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 (thermal oil) and Synthetic Crude Oil (“SCO”) (herein collectively referred to as “crude oil”) and 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, representing approximately 81% of the Company’s total liquids production in Q1/21, the majority of which is zero decline high value SCO production from the Company’s world class Oil Sands Mining and Upgrading assets. The remaining balance of long life low decline production comes from Canadian Natural’s top tier thermal in situ oil sands operations and the Company’s 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.

In addition, 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, in the right economic conditions, provide excellent returns and maximize value for shareholders. Supporting these projects is the Company’s undeveloped land base which enables large, repeatable drilling programs that 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.

• Canadian Natural’s North America E&P crude oil and NGL production volumes, excluding thermal in situ operations, averaged 211,206 bbl/d in Q1/21, a decrease of 8% from Q1/20 levels and comparable with Q4/20 levels. The decrease from Q1/20 was primarily due to natural field declines and deferred 2020 drilling activity.
  • Primary heavy crude oil production averaged 62,695 bbl/d in Q1/21, decreases of 24% and 4% from Q1/20 and Q4/20 levels respectively, primarily due to natural field declines.
    • Operating costs in the Company’s primary heavy crude oil operations averaged $18.89/bbl (US$14.92/bbl) in Q1/21, comparable with Q1/20 levels, strong results given the decrease in production volumes and increase in energy costs.
    • As a part of the 2021 budget, 13 net slant wells and 14 net horizontal multilateral wells were drilled in Q1/21 as planned.
      • The majority of these wells are in the early stages of ramping up or target to come on production in Q2/21 as budgeted. Early highlights from the Q1/21 drilling include 5 net Clearwater horizontal multilateral wells at Smith, that are now on-stream. Production from these wells has been strong totaling approximately 2,700 bbl/d, above budgeted rates by approximately 900 bbl/d, with low capital efficiencies of approximately $3,400 per flowing BOE.
  • Pelican Lake production was strong in Q1/21 averaging 55,498 bbl/d, comparable with prior periods, demonstrating the strength of this long life low decline asset and the continued success of the Company’s world class polymer flood.
  • • The Company continues to focus on safe, effective and efficient operations, realizing strong operating costs in Q1/21 at Pelican Lake, averaging $7.38/bbl (US$5.83/bbl), an increase of 19% from Q1/20 primarily due to increases in energy costs.
  • North American light crude oil and NGL production averaged 93,013 bbl/d in Q1/21, increases of 5% and 6% from Q1/20 and Q4/20 levels respectively. The increases are primarily as a result of strong results from drilling completed in Q4/20 and Q1/21.
    • Operating costs in the Company’s North America light crude oil and NGL areas averaged $16.07/bbl (US$12.70/bbl) in Q1/21, comparable with Q1/20 levels, as a result of effective and efficient operations.
    • The Company continues to advance its high value Montney light crude oil development plan at Wembley, where 5 net wells have been drilled to date from the budgeted 18 net wells targeted to be on stream in 2021. Construction on the new crude oil battery is proceeding on time and on budget and is targeted to be on-stream in October 2021.
      • With the crude oil battery in place the new wells are targeted to be brought on stream at strong capital efficiencies of approximately $9,400 per flowing BOE. This project is targeting to exit 2021 at total production rates of approximately 8,500 bbl/d of liquids and 28 MMcf/d.

• Canadian Natural’s thermal in situ production was strong in Q1/21, averaging 267,530 bbl/d, an increase of 17% over Q1/20 levels and comparable with Q4/20 levels.
  • Strong operating costs for the Company’s thermal in situ assets were achieved in Q1/21, averaging $11.40/bbl (US$9.01/bbl) an increase of 3% from Q1/20 levels. The increase in operating costs was primarily due to increases in energy costs, partially offset by cost reductions as a result of higher production volumes and effective and efficient operations.
• Solvent enhanced oil recovery technology targets to increase bitumen production, reduce Steam to Oil Ratio (“SOR”), reduce Green House Gas (“GHG”) intensity and have high solvent recovery. This technology has the potential for application throughout the Company’s extensive thermal in situ asset base.
  • At Kirby South, results from our on-going two year pilot of this technology indicate a significant SOR and GHG intensity reduction of approximately 45%, within the targeted range, can be achieved with the process. Monitoring of solvent recovery will continue for the remainder of 2021 to conclude the pilot results.
  • At Primrose, in the steam flood area, a solvent injection pilot is targeted to commence in Q4/21. This second pilot will consist of 9 wells (5 producers and 4 injectors) and similar to the first pilot at Kirby South, is targeted to operate for a two year period.

• North America natural gas production was strong in Q1/21 averaging 1,585 MMcf/d, an increase of 13% from Q1/20 levels. The increase from Q1/20 was primarily as a result of acquired production in Q4/20, strong base production and volume additions, partially offset by natural field declines and the shutdown of our Pine River gas plant in February 2021.
  • North America natural gas operating costs in Q1/21 averaged $1.24/Mcf, comparable with Q1/20 levels and an increase of 16% from Q4/20 levels. The increase from Q4/20 was primarily due to normal seasonality including an increase in electricity costs, partially offset by the impact of the continuous focus on operating costs.
• As part of the 2021 budget, in the liquids rich Montney, the Company targets to utilize facility capacity through its drill to fill strategy adding low cost, high value liquids rich natural gas volumes.
  • At Septimus, production was strong in Q1/21, essentially at facility capacity of 150 MMcf/d and 9,000 bbl/d of liquids.
    • A 5 net well pad is being drilled at Septimus, with a targeted on stream date in June 2021 and low capital efficiency of approximately $5,000 per flowing BOE. These wells target to keep the capacity full for the remainder of 2021.
    • Operating costs at Septimus remained strong in Q1/21, averaging $0.28/Mcfe, a decrease of 7% from Q1/20 levels.
  • At Townsend, Q1/21 production was approximately 255 MMcf/d and 5,500 bbl/d of liquids, above 2021 budget by 17 MMcf/d and 340 bbl/d of liquids.
    • Completions on a 6 well pad at Townsend are progressing, with total targeted rates of approximately 44 MMcf/d, targeted to come on stream in June 2021 with a strong capital efficiency of approximately $4,200 per flowing BOE.
    • Townsend remains on target to exit 2021 at a production rate of approximately 340 MMcf/d.

• International E&P crude oil production volumes averaged 31,813 bbl/d in Q1/21, decreases of 27% and 7% from Q1/20 and Q4/20 levels respectively.
  • In Q2/21 and Q3/21 the Company is planning turnarounds at two platforms in the North Sea and at one field in Offshore Africa. Targeted production impacts were included in the Company’s annual 2021 budgeted production volume range.
  • In the North Sea, crude oil production volumes averaged 19,959 bbl/d in Q1/21, a decrease of 28% from Q1/20 levels and an increase of 17% from Q4/20 levels. The decrease in production from Q1/20 was primarily a result of the permanent cessation of production from the Banff and Kyle fields and natural field declines. The increase in production from Q4/20 primarily reflects the impact of planned turnaround activity during Q4/20, partially offset by natural field declines.
    • Crude oil operating costs in the North Sea averaged $42.24/bbl (US$33.37/bbl) in Q1/21, an increase of 42% from Q1/20 levels primarily due to lower volumes on a relatively fixed cost base and higher energy costs. Targeted operating costs remain in line with 2020 annual levels.
  • Offshore Africa crude oil production volumes averaged 11,854 bbl/d in Q1/21, decreases of 26% and 31% from Q1/20 and Q4/20 levels respectively. The decreases were primarily due to a planned turnaround at Baobab and an unplanned outage at Espoir in Q1/21.
    • Offshore Africa crude oil operating costs averaged $16.57/bbl (US$13.09/bbl) in Q1/21, an increase of 39% from Q1/20 levels, primarily due to the timing of liftings from various fields that have different cost structures and lower volumes on a relatively fixed cost base. Targeted operating costs remain in line with 2020 annual levels.

(1) SCO production before royalties and excludes volumes consumed internally as diesel.

(2) Consists of heavy and light synthetic crude oil products.

• The Company’s world class Oil Sands Mining and Upgrading assets achieved record quarterly production averaging 468,803 bbl/d of SCO in Q1/21, increases of 7% and 12% from Q1/20 and Q4/20 levels respectively. Record SCO production was primarily as a result of industry leading utilization and operational enhancements.
  • Operating costs from the Company’s Oil Sands Mining and Upgrading assets are top tier, averaging $19.82/bbl (US$15.66/bbl) of SCO in Q1/21, decreases of 5% and 2% from Q1/20 and Q4/20 levels respectively. The reductions were primarily due to our focus on continuous improvement, effective and efficient operations and operational enhancements, offsetting the impact of higher energy costs, including natural gas, in Q1/21.
    • In Q1/21 the Company increased SCO sales from the Oil Sands Mining and Upgrading segment by over 41,000 bbl/d from Q1/20 levels while essentially maintaining absolute operating cost levels, excluding natural gas costs, over the same period, demonstrating the continued focus on effective and efficient operations and the underlying value of high utilization relative to fixed costs.
  • Subsequent to quarter end the planned turnaround at Horizon was successfully completed and SCO production is targeted to resume on May 8, 2021. Additionally, at the Athabasca Oil Sands Project (“AOSP”) the Company targets to perform planned de-coking in May 2021. The Company’s annual 2021 budgeted total production volume range remains unchanged.

• Crude oil prices continues to improve with WTI averaging US$57.80/bbl in Q1/21, an increase of 25% from Q1/20 levels. The increase in WTI from comparable periods primarily reflected increased demand as a result of the positive impact of the global roll out of COVID-19 vaccinations on economic activity, the continuation of agreements by OPEC+ to maintain production cuts implemented in 2020 and the strengthening of the global economy.
  • As at May 5, 2021 for crude oil, annual WTI pricing of US$62.50/bbl is currently 59% higher than 2020 levels and the annual WCS heavy oil differential has improved significantly from 2020, currently at approximately 21%, in line with average historical levels.
• Natural gas prices continue to improve with AECO averaging $2.77/GJ in Q1/21, an increase of 36% from Q1/20 levels. The increase in natural gas prices from the comparable period primarily reflected increased intra-provincial and export demand.
• Market egress is targeted to improve in the short- and mid-term as construction is progressing on the Trans Mountain Expansion (“TMX”) and the Enbridge Line 3 replacement.
  • Enbridge Line 3 is targeted to be on stream in Q4/21.
  • Canadian Natural is committed to approximately 10,000 bbl/d of the targeted 50,000 bbl/d base Keystone export pipeline optimization expansion, which is targeted to be on-stream in the latter half of 2021.
  • TMX construction is on track for a targeted on stream date in early 2023, on which Canadian Natural has 94,000 bbl/d committed capacity.
  • The North West Redwater (“NWR”) Refinery with targeted processing capacity of approximately 80,000 bbl/d of diluted bitumen, which improves heavy oil demand in western Canada, effectively increasing egress out of the WCSB. For more details, please contact the North West Redwater Partnership.

FINANCIAL REVIEW

The Company continues to implement proven strategies including 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 program, all support a flexible financial position and provide the appropriate financial resources for the near-, mid- and long-term.

• The Company’s strategy to maintain a diverse portfolio, balanced across various commodity types, achieved record quarterly production of 1,245,703 BOE/d in Q1/21, with approximately 99% of total production located in G7 countries.
• Canadian Natural generated robust free cash flow of $1,401 million in Q1/21, after net capital expenditures of $808 million and dividend payments of $503 million in the quarter, reflecting the strength of the Company’s effective and efficient operations and its high quality, long life low decline asset base.
  • Canadian Natural demonstrated our focus on further strengthening of the balance sheet with its strong financial results in Q1/21, reducing net debt by $1,426 million, from Q4/20 levels. Since Q2/20 levels net debt has been decreased by $2,944 million.
    • In Q1/21 the Company repaid $962.5 million on its $3,088 million non-revolving term loan, more than satisfying the required annual amortization of $162.5 million originally due in June 2021. Subsequent to quarter end, an additional $650 million was repaid on this facility, reducing the outstanding balance to $1,475 million.
    • In Q1/21 the Company’s $1,000 million non-revolving term credit facility, originally due February 2022, was extended to February 2023.
    • As at March 31, 2021, the Company had undrawn revolving bank credit facilities of approximately $5.0 billion. Including cash and cash equivalents and short-term investments, the Company had significant liquidity of approximately $5.5 billion. At March 31, 2021, the Company had approximately $0.1 billion drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.
  • In March 2021, the Company declared a quarterly dividend of $0.47 per share, an increase of 11% from the previous level of $0.425 per share, marking 2021 as the Company’s 21st consecutive year of dividend increases, reflecting the Board of Directors’ confidence in Canadian Natural’s strength and the robustness of the Company’s assets and its ability to generate significant and sustainable free cash flow.
    • Subsequent to quarter end the Company declared a quarterly dividend of $0.47 per share, payable on July 5, 2021.
  • In March 2021, the Board of Directors authorized management to repurchase shares under a NCIB to approximately offset options exercised throughout the coming year, in order to minimize or eliminate dilution to shareholders.
    • Share repurchases for cancellation in Q1/21 totaled 600,000 common shares at a weighted average price of $38.61.
    • Subsequent to quarter end, up to and including May 5, 2021, the Company executed on additional share repurchases for cancellation of 960,000 common shares at a weighted average share price of $38.15.
• Returns to shareholders have been significant as Canadian Natural has returned approximately $1.1 billion by way of dividends and share repurchases in 2021 up to and including May 5, 2021.
• The strength of the Company’s assets supported by its safe effective and efficient operations demonstrated its ability to generate significant and sustainable free cash flow over the long-term, making Canadian Natural’s business unique, robust and sustainable.
  • 2021 free cash flow is targeted to be robust at $5.7 billion to $6.2 billion using approximately US$60/bbl WTI, after budgeted capital expenditures and dividends.
  • The Company’s 2021 budgeted capital expenditure program of approximately $3.2 billion, provides a targeted production range of 1,190 MBOE/d to 1,260 MBOE/d, an increase of 5% at the mid-point from 2020 levels.
    • Corporate annual natural gas production is targeted to range between 1,620 MMcf/d to 1,680 MMcf/d in 2021, representing significant growth of over 170 MMcf/d at the mid-point from 2020 levels.
    • Corporate annual liquids production is targeted to be strong in 2021 ranging from 920,000 bbl/d to 980,000 bbl/d, an increase of approximately 32,000 bbl/d at the mid-point from 2020 levels.
    • Free cash flow is targeted to be allocated to the balance sheet in the near term resulting in targeted 2021 year ended debt to book capitalization and debt to adjusted EBITDA of approximately 29% and 1.1x respectively, at the mid-point of targeted free cash flow range.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE (“ESG”) HIGHLIGHTS

Canada and Canadian Natural are well positioned to deliver responsibly produced energy that the world needs through leading ESG performance. Canadian Natural’s culture of continuous improvement provides a significant advantage and results in continued improvement in the Company’s environmental performance.

• The Government of Canada’s announcement on April 19, 2021 of its 2021 budget recognized the important role of carbon capture, utilization and storage projects for the oil sands sector to continue contributing to Canada’s economic growth while working towards climate objectives. As a leader in Carbon, Capture, Utilization and Storage (“CCUS”), Canadian Natural sees many opportunities for industry to advance investments in CCUS projects. Details of the proposed government program are important and the Company looks forward to working together with government through the upcoming consultation period.
• Additionally on April 22, 2021, the Government of Canada announced new targets to reduce GHG emissions by 40% to 45% below 2005 levels by 2030.
  • Based on these new announcements and the upcoming Government of Canada consultation period, the Company plans to update its environmental targets later in 2021.

2020 ESG HIGHLIGHTS

• Canadian Natural’s corporate GHG emissions intensity continues to improve, decreasing by 18% from 2016 to 2020, a material reduction in emissions intensity. For 2020 results showed a decrease of 2% from 2019 levels.
• The Company reduced methane emissions in its North American E&P segment by 28% from 2016 to 2020, which includes a decrease of 14% from 2019 levels.
• The Company continues to improve corporate total recordable injury frequency (“TRIF”) in 2020, with a TRIF of 0.21 in 2020 compared to 0.50 in 2016. The Company’s TRIF is down 58% since 2016, while man-hours have increased over this time period.
• Canadian Natural is one of the largest owners of Carbon Capture and Storage (“CCS”) and sequestration capacity in the oil and natural gas sector globally through projects at Horizon, the Company’s 70% owned Quest CCS facility located at Scotford, and its 50% working interest in the NWR Refinery. As part of our comprehensive GHG emissions reduction strategy, our CCS projects include carbon dioxide (“CO₂“) storage in geological formations, the use of CO₂ in enhanced oil recovery techniques and injection of CO₂ into tailings. Gross carbon capture capacity through these projects combined is approximately 2.7 million tonnes of CO₂ annually, equivalent to taking approximately 576,000 cars off the road per year.
  • The Quest CCS facility captures and stores approximately 1.1 million tonnes of CO₂ per year and in May 2020 reached the milestone of 5 million tonnes of stored carbon dioxide. 5 million tonnes of CO₂ is equal to the annual emissions from approximately 1.25 million cars.
  • At Horizon, annual capture capacity is approximately 0.4 million tonnes of CO₂ from the hydrogen plant, the equivalent of removing approximately 85,000 cars off the road annually.
  • At the NWR Refinery, captured CO₂ from the refinery began to be delivered in March 2020 to the Alberta Carbon Truck Line for enhanced oil recovery and permanent storage in central Alberta. At full capacity, approximately 1.2 million tonnes of CO₂ per year will be captured, the equivalent of removing approximately 256,000 cars off the road annually.
• The Company continues to increase the level of third party verified direct GHG emissions and indirect energy use.
  • The Company targets to increase the total corporate level of third party verification of GHG emissions to 95% in 2021, an increase of 9% from 2020 levels of 87%.
• In 2020 the Company planted its one millionth tree at AOSP and its one and a half millionth tree at Horizon, reclaiming land and contributing to increased carbon capture.
• In 2020 the Company successfully achieved three of our stated four environmental targets for 2025 relating to GHG and methane emissions intensity reductions and reduced fresh water usage.
• The Company targets the release of its 2020 Stewardship Report to Stakeholders in Q3/21. In September 2020, Canadian Natural published its 2019 Stewardship Report to Stakeholders, which is available on the Company’s website at https://www.cnrl.com/report-to-stakeholders.

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”, “aspiration” 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 targets provided throughout this press release and 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, without limitation, those in relation to the Company’s assets at Horizon Oil Sands (“Horizon”), the Athabasca Oil Sands Project (“AOSP”), Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby Thermal Oil Sands Project, the Jackfish Thermal Oil Sands Project, 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, the development and deployment of technology and technological innovations, and the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long term 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 earlier 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 (including as a result of effects of the novel coronavirus (“COVID-19”) pandemic and the actions of the Organization of the Petroleum Exporting Countries Plus (“OPEC+”) which may impact, among other things, demand and supply for and market prices of the Company’s products, and the availability and cost of resources required by the Company’s operations; volatility of and assumptions regarding crude oil and natural gas and NGLs prices including due to actions of OPEC+ taken in response to COVID-19 or otherwise; fluctuations in currency and interest rates; assumptions on which the Company’s current targets are 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 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, maintain, and operate 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; the Company’s ability to meet its targeted production levels; 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 (including production curtailments mandated by the Government of Alberta); 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 sufficiency of the Company’s liquidity to support its growth strategy and to sustain its operations in the short, medium, and long term; the strength of the Company’s balance sheet; the flexibility of the Company’s capital structure; the adequacy of the Company’s provision for taxes; the continued availability of the Canada Emergency Wage Subsidy (“CEWS”) or other subsidies; 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, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all information then available.

Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this press release or 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 in this press release or the Company’s MD&A, 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 and net capital expenditures. These financial measures are not defined by International Financial Reporting Standards (“IFRS”) and therefore are referred to as non-GAAP financial measures. The non-GAAP financial measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP financial measures to evaluate its performance. The non-GAAP financial measures should not be considered an alternative to or more meaningful than net earnings (loss), cash flows from operating activities, and cash flows used in investing activities as determined in accordance with IFRS, as an indication of the Company’s performance. The non-GAAP financial measure adjusted net earnings (loss) from operations is reconciled to net earnings (loss), as determined in accordance with IFRS, in the “Financial Highlights” section of the Company’s MD&A. Additionally, the non-GAAP financial measure adjusted funds flow is reconciled to cash flows from operating activities, as determined in accordance with IFRS, in the “Financial Highlights” section of the Company’s MD&A. The non-GAAP financial measure net capital expenditures is reconciled to cash flows used in investing activities, as determined in accordance with IFRS, in the “Net Capital Expenditures” section of the Company’s MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the “Liquidity and Capital Resources” section of the Company’s MD&A.

Adjusted net earnings (loss) from operations is a non-GAAP financial 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. Adjusted net earnings (loss) from operations may not be comparable to similar measures presented by other companies.

Adjusted funds flow is a non-GAAP financial 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 excluding the impact of government grant income under the provincial well-site rehabilitation programs, and movements in other long-term assets, including the unamortized cost of the share bonus program, accrued interest on subordinated debt advances to North West Redwater Partnership (“NWRP”), and prepaid cost of service tolls. The Company considers adjusted funds flow a key measure in evaluating its performance, as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. Adjusted funds flow may not be comparable to similar measures presented by other companies.

Net capital expenditures is a non-GAAP financial 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, the repayment of NWRP subordinated debt advances, abandonment expenditures including the impact of government grant income under the provincial well-site rehabilitation programs, and the settlement of long-term debt assumed in acquisitions. The Company considers net capital expenditures a key measure in evaluating its performance, as it provides an understanding of the Company’s capital spending activities in comparison to the Company’s annual capital budget. Net capital expenditures may not be comparable to similar measures presented by other companies.

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.

Long-term debt, net and net debt are other financial measures that are calculated as net current and long-term debt less cash and cash equivalents.

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.

Debt to book capitalization is a non-GAAP measure that is derived as net current and long-term debt, divided by the book value of common shareholders’ equity plus net current and long-term debt. 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 and short term investments, 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 8 – Long-term Debt in the Company’s consolidated financial statements.

Special Note Regarding Currency, Financial Information and Production

This press release should be read in conjunction with the unaudited interim consolidated financial statements for the three months ended March 31, 2021 and the Company’s MD&A and audited consolidated financial statements for the year ended December 31, 2020. 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, 2021 and the Company’s MD&A have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (“IASB”).

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.

The Company’s 2021 targeted annual adjusted funds flow, free cash flow and net debt are based upon forecasted commodity prices of US$60.47 WTI/bbl, WCS discount of US$11.95/bbl, AECO price of C$2.74/GJ and FX of US$1.00 to C$1.26. Forecasted net debt reflects estimated timing of cash receipts and expenditures.

Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2020, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. Information on the Company’s website does not form part of and is not incorporated by reference in the Company’s MD&A.

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