Canadian Natural Resources Limited Announces 2018 Third Quarter Results

CALGARY, Alberta, Nov. 01, 2018 (GLOBE NEWSWIRE) -- Commenting on third quarter 2018 results, Steve Laut, Executive Vice-Chairman of Canadian Natural stated, "The strength of our well balanced and diverse portfolio, combined with Canadian Natural's ability to effectively and efficiently execute, delivered a strong third quarter for the Company. Record quarterly adjusted funds flow of over $2.8 billion was achieved in the third quarter and adjusted funds flow of $7.9 billion was achieved in the first nine months of 2018. Capital allocation continued to be balanced amongst our four pillars to maximize shareholder value. In the first nine months of 2018, economic resource development remained disciplined at 40% of adjusted funds flow. Returns to shareholders were robust at 26% of adjusted funds flow and 31% of adjusted funds flow was allocated to the balance sheet further strengthening our financial position. Lastly, the Company executed on minor tuck-in acquisitions, 3% of adjusted funds flow, that add optionality and significant future value.

Based on the significant progress made to date in strengthening the Company's balance sheet as well as the sustainability of Canadian Natural's free cash flow, the Board of Directors has approved a more defined free cash flow allocation policy in accordance with the Company's four stated pillars. Under the new policy, the Company will target to allocate, on an annual basis, 50% of its residual free cash flow, after budgeted capital expenditures and dividends, to share purchases under its Normal Course Issuer Bid (“NCIB”) and the remaining 50% to reducing debt levels on the Company's balance sheet. This free cash flow policy will target a ratio of debt to adjusted 12 months trailing EBITDA of 1.5x and an absolute debt level of $15.0 billion, at which time the policy will be reviewed by the Board. At present, this policy is expected to be in place until at least the Company's NCIB renewal in May 2019, subject to quarterly review by the Board of Directors. This policy is effective November 1, 2018."

Canadian Natural's President, Tim McKay, added, "Operations were strong in the third quarter of 2018 across our large, balanced and diverse asset base. The planned turnaround at our Horizon operations was successfully completed under budget and production ramped up on schedule. Our focus on effective and efficient operations resulted in strong quarterly unadjusted operating costs of $22.90/bbl (US$17.52/bbl) of Synthetic Crude Oil ("SCO") and adjusted operating costs of $19.95/bbl (US$15.26/bbl) of SCO at our Oil Sands Mining and Upgrading operations. International production volumes were strong in the quarter and exceeded previously issued Q3 guidance as a result of the successfully completed 2018 drilling program in the North Sea and strong production from a newly drilled well in Offshore Africa. Our International light crude oil volumes receive Brent pricing which averaged US$75.46/bbl in the third quarter, generating significant adjusted funds flow. Thermal in situ quarterly production volumes averaged 112,542 bbl/d, exceeding Q3/18 guidance, primarily due to the cyclical nature of steaming cycles and from production resuming following the completion of planned maintenance activities in Q2/18, as a result of proactive and strategic decisions made earlier in the year.

Canadian Natural maintains a flexible and disciplined capital allocation strategy with a focus on maintaining a strong financial position and delivering significant shareholder value. In light of current market conditions driven by market access restrictions, lack of fiscal competitiveness and regulatory uncertainties, the Company will exercise its capital flexibility and allocate capital to those areas that maximize shareholder value. Canadian Natural will continue to make strategic decisions to reduce drilling activity, delay well completions and shut in production. The effectiveness of our strategies, combined with our ability to execute on these strategies, allows us to be nimble, capture opportunities and be more sustainable through these challenges."

Canadian Natural's Chief Financial Officer, Corey Bieber, continued, "In the third quarter Canadian Natural continued to deliver on its commitment to strengthen the balance sheet. The Company achieved quarterly net earnings of $1,802 million and record quarterly adjusted funds flow of $2,830 million, contributing to absolute net long-term debt reduction of approximately $2,880 million year to date. In the quarter, available liquidity improved to $5,350 million, an increase of approximately $550 million from the second quarter of 2018. Debt to adjusted EBITDA strengthened to 1.7x and debt to book capitalization improved to 36.8% over the quarter. Our focus on returns to shareholders has resulted in $2,030 million being returned to shareholders, in the first nine months of 2018, by way of dividends of $1,156 million and share purchases of $874 million. Subsequent to the quarter, an additional 6,900,000 shares were purchased at a weighted average share price of $38.66. Our balance sheet strength gives us the flexibility to deliver our defined growth plan and continue to drive long-term shareholder value creation."

HIGHLIGHTS

1. Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation of this measure is discussed in the Management’s Discussion and Analysis (“MD&A”).
2. Adjusted funds flow (previously referred to as funds flow from operations) is a non-GAAP measure that the Company considers key as it demonstrates the Company’s ability to fund capital reinvestment and debt repayment. The derivation of this measure is discussed in the MD&A.
3. Net capital expenditures is a non-GAAP measure that the Company considers a key measure as it provides an understanding of the Company’s capital spending activities in comparison to the Company's annual capital budget. For additional information and details, refer to the net capital expenditures table in the Company's MD&A.
4. A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.

• Net earnings of $1,802 million were realized in Q3/18, an increase of $820 million and $1,118 million over Q2/18 and Q3/17 levels, respectively. Adjusted net earnings in Q3/18 of $1,354 million were achieved, a $75 million increase over Q2/18 and an increase of $1,125 million over Q3/17 levels.
  
  
• Cash flows from operating activities were $3,642 million in Q3/18, increases of $1,029 million and $1,120 million over Q2/18 and Q3/17 levels, respectively.
  
  
• Canadian Natural generated record quarterly adjusted funds flow of $2,830 million in Q3/18, increases of $124 million and $1,155 million from Q2/18 and Q3/17 levels, respectively. The increase over Q2/18 was primarily due to higher natural gas netbacks and the Company's continued focus on lowering operating costs in the Exploration and Production ("E&P") and Oil Sands Mining and Upgrading segments. The increase over Q3/17 primarily reflects higher realized prices from the Company's liquids production and higher liquids production volumes from the completion of the Horizon Phase 3 expansion.
  
  
• In Q3/18, Canadian Natural delivered significant adjusted funds flow in excess of net capital expenditures of approximately $1,360 million, including deferred discounted purchase consideration. In the first nine months of 2018, adjusted funds flow in excess of net capital expenditures was approximately $4,310 million, including deferred discounted purchase consideration.
  
  
• After dividend requirements, free cash flow totaled approximately $950 million in Q3/18 and in the first nine months of 2018, free cash flow totaled approximately $3,150 million.
  
  
• Consistent with the Company's four pillar strategy, the Company has maintained balance in the allocation of its adjusted funds flow:
  
  
  • The Company remained disciplined in its economic resource development investments with year to date net capital expenditures of $3,196 million, excluding net acquisitions.
    
    
  • Year to date, the Company has reduced long term net debt by approximately $2,880 million, including the impact of foreign exchange, working capital and other adjustments, resulting in debt to adjusted EBITDA strengthening to 1.7x and debt to book capitalization improving to 36.8%.
    
    
  • Returns to shareholders remain a key focus for Canadian Natural as the Company has returned approximately $2,030 million in the first nine months of 2018, by way of dividends of $1,156 million and share purchases of $874 million.
    
    • Share purchases for cancellation totaled 9,872,600 common shares in Q3/18 at a weighted average share price of $43.81.
    • In the first nine months of 2018, share purchases totaled 20,012,727 common shares at a weighted average share price of $43.66.
    • Subsequent to quarter end and up to October 31, 2018, the Company executed additional share purchases of 6,900,000 common shares for cancellation at a weighted average share price of $38.66.
    • Subsequent to quarter end Canadian Natural declared a quarterly cash dividend on common shares of $0.335 per share payable on January 1, 2019.
      
      
  • In the first nine months of 2018, the Company has executed on opportunistic acquisitions of approximately $354 million, including Exploration and Evaluation ("E&E") expenditures of $257 million. Included in the E&E expenditures is the deferred discounted purchase consideration of $118 million, payable over the next five years.  These tuck-in acquisitions add significant future value to the Company's long life low decline asset portfolio.
    
    
    • The Joslyn acquisition has the potential to add significant long life low decline reserves as well as cost savings through the extension of existing Horizon South Pit operations. The lease-line development opportunities reduce the need to relocate Horizon operations to the North Pit, to install new equipment, and construct new infrastructure. Over the next decade, synergies with Horizon are targeted to result in cost savings of over $500 million. At the Joslyn lease, the former operator had project regulatory approval for a 100,000 bbl/d project.
      
    • The Laricina corporate asset acquisition which includes the Grand Rapids lands is a great fit with existing lands and operations in the area. The Company's Thermal team sees the opportunity to improve the future performance of the Grand Rapids which is targeted to be piloted through the existing facilities in the future. Additionally, the Company took over operatorship of a key road needed for operations in the area, which will result in immediate savings to the Company. Canadian Natural's lands combined with the acquired lands, have total Grand Rapids bitumen in place potential of 15.9 billion barrels, adding significant future shareholder value.
      
      
  • Based on the significant progress made to date in strengthening the Company's balance sheet as well as the sustainability of Canadian Natural's free cash flow, the Board of Directors has approved a more defined free cash flow allocation policy in accordance with the Company's four stated pillars. Under the new policy, the Company will target to allocate, on an annual basis, 50% of its residual free cash flow, after budgeted capital expenditures and dividends, to share purchases under its Normal Course Issuer Bid (“NCIB”) and the remaining 50% to reducing debt levels on the Company's balance sheet. This free cash flow policy will target a ratio of debt to adjusted 12 months trailing EBITDA of 1.5x, and an absolute debt level of $15.0 billion, at which time the policy will be reviewed by the Board. At present, this policy is expected to be in place until at least the Company's NCIB renewal in May 2019, subject to quarterly review by the Board of Directors. This policy is effective November 1, 2018.
    
    
• The Company's production volumes in Q3/18 averaged 1,060,629 BOE/d, comparable to Q2/18 and an increase of 2% from Q3/17 levels. The increase from Q3/17 was mainly due to the completion of the Horizon Phase 3 expansion, acquisitions completed in 2017 and production from new wells in the North Sea, partially offset by declines in natural gas production along with natural gas and heavy crude oil shut ins and reduced activity of 21,500 BOE/d.
  
  
• In the first nine months of 2018, strong operating costs of $11.91/BOE were realized in the Company's E&P segment, a 7% decrease from Q2/18 levels, a significant achievement given strategic and proactive decisions to curtail, defer and shut in production during the year.
  
  
• At the Company's world class Oil Sands Mining and Upgrading assets, operations were strong and above the midpoint of guidance in Q3/18, with quarterly production of 394,382 bbl/d of Synthetic Crude Oil ("SCO"), a decrease of 3% from Q2/18 levels, as planned pit stop activities at the Athabasca Oil Sands Project ("AOSP") and a major planned turnaround at Horizon were successfully completed in the quarter. Quarterly production increased from Q3/17 levels by 11% mainly due to the production from the Horizon Phase 3 expansion.
  
  
  • Through safe, steady and reliable operations, high utilization, and leveraging expertise to capture synergies, the Company realized average unadjusted operating costs of $22.90/bbl (US$17.52/bbl) of SCO in Q3/18, an impressive result given the planned downtime at Horizon in the quarter. After normalizing for planned turnaround downtime, operating costs reached $19.95/bbl (US$15.26/bbl) of SCO in Q3/18.
    
    
  • At Horizon, during the planned turnaround, optimization and reliability work on the Vacuum Distillate Unit ("VDU") furnaces and coker train was completed under budget and the units ramped up on schedule.
    
    
• At Pelican Lake, polymer flood restoration for 2018 on the acquired lands was completed ahead of schedule, where approximately 62% of acquired lands are now under polymer flood. To optimize long term oil recovery and effectiveness of the polymer flood, the Company is using modified injection parameters in the near term. As polymer flood conformance improves, the Company expects to increase oil recovery and further maximize value. In Q3/18, as a result of effective and efficient operations, strong operating costs of $6.43/bbl were achieved, an 8% decrease from Q2/18 levels and a 9% decrease from Q1/18 levels.
  
  
• Thermal in situ quarterly production volumes exceeded Q3/18 guidance, averaging 112,542 bbl/d, resulting in an increase of 7% from Q2/18 levels. The increase was primarily due to the cyclical nature of steaming cycles and from production resuming following the completion of planned maintenance in Q2/18 and proactive and strategic decisions to curtail production earlier in the year.
  
  
  • Pad additions at Primrose are ahead of schedule and on budget with initial production targeted to add approximately 10,000 bbl/d in Q4/19 and the total program is targeted to add approximately 32,000 bbl/d in 2020. These pad additions are high return activities as the Company targets to utilize available excess oil processing and steam capacity at Primrose.
    
    
  • At Kirby North, top tier execution and strong productivity has resulted in the project progressing ahead of the sanctioned schedule. Cost performance remains on budget with 80% of the Central Processing Facility complete and Steam Assisted Gravity Drainage ("SAGD") drilling nearing 70% completion. Kirby North targets to add 40,000 bbl/d of SAGD production with first oil targeted for Q4/19, one quarter earlier than originally planned.
    
    
• International E&P quarterly production volumes were strong in Q3/18, exceeding quarterly production guidance and reaching 47,504 bbl/d. International production receives Brent pricing that averaged US$75.46/bbl in Q3/18, generating significant adjusted funds flow. The increase in production of 11% and 9% from Q2/18 and Q3/17 levels respectively, was primarily due to a successful drilling program in the North Sea, partially offset by natural field declines.
  
  
  • The 2018 drilling program in the North Sea was successfully completed on time and on budget with 3.9 net production wells drilled year to date. Current light crude oil production is exceeding sanctioned expectations.
    
    
  • In Q3/18, the Company successfully drilled the first of three gross production wells at Baobab. Current light crude oil production from the first well is exceeding sanctioned expectations at approximately 2,200 bbl/d net. Subsequent to the quarter, the second well came on production with initial rates at approximately 3,700 bbl/d net. The Company is targeting the third well to come on production in Q4/18, and is on target to exceed the original budgeted production adds for the program of 5,370 bbl/d net, and as a result, Canadian Natural is currently evaluating the option to drill an additional production well in 2019, extending the drilling program at Baobab.
    
    
• Balance sheet strength and strong financial performance were demonstrated in Q3/18 through reduced long-term debt and upgraded credit ratings.
  
  
  • In Q3/18, Moody's Investors Service, Inc. upgraded the Company's senior unsecured rating to Baa2 from Baa3 and its short term rating to P-2 from P-3 with a stable outlook.
    
    
  • In Q3/18, Canadian Natural reduced long-term net debt by approximately $1,780 million from Q2/18 levels.
    
    
  • Canadian Natural maintains strong financial stability and liquidity represented by cash balances and committed bank credit facilities. At September 30, 2018 the Company had approximately $5,350 million of available liquidity, including cash and cash equivalents, an increase of approximately $550 million from Q2/18.
    
    
• Due to current market conditions driven by lack of market access for both oil and natural gas, regulatory uncertainty, and lack of fiscal competitiveness, the Company continues to exercise its capital flexibility along with proactive decisions to strategically shift capital, curtail volumes, shut in production and delay completion of recently drilled crude oil wells. These factors will play a prominent role in 2019 and future capital allocation decisions.

OPERATIONS REVIEW AND CAPITAL ALLOCATION

Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural’s production is well balanced between light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen and SCO (herein collectively referred to as “crude oil”), natural gas and NGLs. This balance provides optionality for capital investments, facilitating improved value for the Company’s shareholders.

Underpinning this asset base is long life low decline production from the Company's Oil Sands Mining and Upgrading, thermal in situ oil sands and Pelican Lake heavy crude oil assets. The combination of low decline, low reserve replacement cost, and effective and efficient operations means these assets provide 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 a major component of its operating cost and minimize production commitments. Low capital exposure projects can be quickly stopped or started depending upon success, market conditions, or corporate needs.

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

Drilling Activity

• The Company's total crude oil and natural gas drilling program of 403 net wells for the nine months ended September 30, 2018, excluding strat/service wells, was an increase of 10 net wells from the same period in 2017. The Company's drilling levels reflect the disciplined capital allocation process and proactive actions to improve execution and control costs by balancing overall drilling levels throughout the year.

North America Exploration and Production

• North America crude oil and NGLs averaged 247,314 bbl/d in Q3/18, representing a 4% increase from both Q2/18  and Q3/17 levels. The volume increase from Q2/18 was primarily a result of increased production in primary heavy crude oil due to the ramp up of new wells previously curtailed and increased production in light crude oil due to the additional capital allocated from primary heavy crude oil, partially offset by curtailed primary heavy crude oil production volumes. The increase from Q3/17 was mainly due to the successful integration of acquired assets at Pelican Lake.
  
  
• Due to widening price differentials driven by market access restrictions, the Company made the proactive and strategic decision to shut in, curtail and reduce activity on heavy crude oil production resulting in production impacts of approximately 10,000 bbl/d to 15,000 bbl/d in October and approximately 45,000 bbl/d to 55,000 bbl/d targeted for November and December.
  
  
• Canadian Natural's primary heavy crude oil production averaged 91,631 bbl/d in Q3/18, an 8% increase from Q2/18 levels primarily due to ramp up of new wells previously curtailed along with a full quarter of production at the Company's Smith primary heavy crude oil play.
  
  
  • In Q3/18, to maximize value as a result of widening price differentials, Canadian Natural continued to implement and execute proactive decisions and strategic actions to allocate more capital from primary heavy crude oil assets to light crude oil assets. As a result, the Company drilled 63 less net wells in Q3/18, with a year to date impact of 83 less net primary heavy crude oil wells in the year than originally budgeted. Additionally, in Q3/18, the Company delayed completion on 33 net primary heavy crude oil wells as well as shut in production. The Company targets to bring on the delayed and shut in production when primary heavy crude oil netbacks improve.
    
    
  • At the Company's Smith primary heavy crude oil play, production results continue to be strong from the 6 net multilateral wells on production with current rates of approximately 300 bbl/d per well, which are exceeding original production expectations of 171 bbl/d from sanction. Additionally, actual decline rates are coming in significantly lower than sanctioned rates. There is significant potential at Smith for future development as Canadian Natural has 19 net sections in the fairway with the potential to add approximately 125 net horizontal multilateral primary heavy crude oil wells.
    
    
  • Controlling costs remains a focus with operating costs of $15.58/bbl in Q3/18, an 8% decrease from Q2/18 levels, due to increased volumes from previously curtailed primary heavy crude oil production.
    
    
• North America light crude oil and NGL quarterly production averaged 92,956 bbl/d, an increase of 3% from Q2/18 levels and comparable to Q3/17 levels. The increase from Q2/18 is primarily as a result of a successful drilling program and increased production in light crude oil due to the additional capital allocated from primary heavy crude oil, partially offset by natural declines.
  
  
  • The Company successfully drilled 27 net light crude oil wells in Q3/18, 19 net wells above the original plan as the Company reallocated capital from primary heavy crude oil to light crude oil. Highlights from wells coming on production to date are as follows:
    
    
    • At Wembley, production remains strong at approximately 500 bbl/d per well from wells drilled earlier in 2018. With this success, an additional 4 net wells were drilled in Q3/18 with production targeted to come on in Q4/18. The Company has 77 net Montney sections of lands in the area with greater than 175 potential premium light crude oil well locations.
      • Including the greater Wembley area, the Company has an additional 54 net Montney sections and over 125 incremental potential premium light crude oil well locations.
    • In Southeast Saskatchewan, the Company drilled 9 net light crude oil wells in Q3/18 with some wells on production late in the quarter and the remaining wells are targeting to come on production in Q4/18. These light crude oil wells were drilled as a result of the strategic decision to shift capital to light crude oil and were not originally budgeted. Additionally, production from these Saskatchewan wells are less impacted by the apportionment issues and price differentials experienced in Alberta.
      
      
  • At the Company's light crude oil development at Tower, operations are currently ramping up with 6 out of 7 net wells on production, and current facility constrained production averaging approximately 5,500 BOE/d due to gas handling at capacity at the facility. With the positive results on the first wells, the Company has 11 net sections with the potential for an additional 41 net wells that would leverage off the existing facility over time, adding significant value.
    
    
  • Operating costs of $15.51/bbl were realized in Q3/18, a decrease of 2% from Q2/18 levels in the Company's light crude oil and NGL areas.
    
    
• Pelican Lake quarterly production averaged 62,727 bbl/d, comparable with Q2/18 levels and an increase of 32% from Q3/17 levels. The increase from Q3/17 was as a result of the Company's successful integration of acquired assets in late 2017.
  
  
  • Polymer flood restoration for 2018 on the acquired lands was completed ahead of schedule, where approximately 62% of acquired lands are now under polymer flood. To optimize long term oil recovery and effectiveness of the polymer flood, the Company is using modified injection parameters in the near term. As polymer flood conformance improves, the Company expects to increase oil recovery and further maximize value.
    
    
  • Strong operating costs of $6.43/bbl were achieved in Q3/18, an 8% decrease from Q2/18 levels and a 9% decrease from Q1/18 levels.
    
    
• The Company’s 2018 North America E&P crude oil and NGL annual production guidance is targeted to range between 240,000 bbl/d - 246,000 bbl/d.

• Thermal in situ quarterly production volumes exceeded Q3/18 guidance, averaging 112,542 bbl/d, resulting in an increase of 7% from Q2/18 levels. The increase was primarily due to the cyclical nature of steaming cycles and from production resuming following the completion of planned maintenance in Q2/18 and proactive and strategic decisions to curtail production earlier in the year.
  
  
  • At Primrose, Q3/18 production volumes averaged 72,500 bbl/d, an increase of 7% from Q2/18 levels, primarily as a result of the timing of cyclical steaming where additional wells entered the production cycle. Including energy costs, operating costs were strong at $11.80/bbl in Q3/18, a decrease of 20% from Q2/18 levels.
    
    
    • Pad additions at Primrose are ahead of schedule and on budget with initial production targeted to add an approximate 10,000 bbl/d in Q4/19 and the total program is targeted to add approximately 32,000 bbl/d in 2020. These pad additions are high return activities as the Company targets to utilize available excess oil processing and steam capacity at Primrose.
      
      
  • At Kirby South, SAGD production volumes of 35,839 bbl/d were achieved in Q3/18, comparable to Q2/18 and a 4% decrease from Q3/17 levels. Including energy costs, Kirby South achieved strong Q3/18 operating costs of $9.14/bbl, comparable to Q2/18 and a 2% increase from Q3/17 levels.
    
    
  • At Kirby North, top tier execution and strong productivity has resulted in the project progressing ahead of the sanctioned schedule. Cost performance remains on budget with 80% of the Central Processing Facility complete and SAGD drilling nearing 70% completion. Kirby North targets to add 40,000 bbl/d of SAGD production with first oil targeted for Q4/19, one quarter earlier than originally planned.
    
    
• The Company’s 2018 thermal in situ annual production guidance remains unchanged and is targeted to range between 107,000 bbl/d - 127,000 bbl/d.

• North America natural gas production was as expected at 1,489 MMcf/d in Q3/18, comparable to Q2/18 and a decrease of 7% from Q3/17 levels. The decrease from Q3/17 was primarily due to strategic decisions made to reduce drilling and development activities and shut in production as a result of low natural gas prices and third party facility constraints.
  
  
• Operating costs of $1.20/Mcf were realized in Q3/18, a decrease of 6% from Q2/18 levels, strong results given lower natural gas production volumes due to the Company's proactive decision to shut in volumes and delay activity on certain natural gas assets.
  
  
• In 2018, the Company continues to make proactive and strategic decisions to maximize value in the Company's natural gas assets and as a result, Q3/18 production volumes were reduced by approximately 146 MMcf/d due to the following:
  
  
  • Deferred capital and development activity including recompletions and workovers of certain natural gas assets along with production shut ins, resulted in a production impact of approximately 96 MMcf/d in Q3/18. The Company targets to re-evaluate these development activities when natural gas prices improve.
    
    
  • Q3/18 production was impacted by approximately 8 MMcf/d related to solution gas associated with the curtailment of primary heavy crude oil production.
    
    
  • Additionally, the Company's natural gas production capability was reduced by approximately 42 MMcf/d in Q3/18 due to restrictions at the Pine River plant, operated by a third party. The third party completed the planned four week turnaround from mid-September to mid-October, but due to additional integrity issues, the plant is now targeting to start up in mid-November. During the turnaround, Canadian Natural was able to assess the potential for the plant to be restored to match the field capacity of 145 MMcf/d. The Company is evaluating the work that would be required and will decide on an investment decision as part of its 2019 budget process. As previously announced, Canadian Natural agreed to acquire the facility from the third party and is waiting for regulatory approval.
    
    
• In Q3/18, Canadian Natural used natural gas in its operations representing approximately 37% of its total equivalent gas production providing a natural hedge from the challenging Western Canadian natural gas price environment. Approximately 28% of the total natural gas production is exported to other North American markets at an average  Q3/18 price of $3.26/GJ or sold internationally at a Q3/18 average price of $11.31/GJ. The remaining 35% of the Company's production is exposed to AECO/Station 2 pricing.
  
  
• The Company’s 2018 corporate natural gas annual production guidance remains unchanged and is targeted to range between 1,550 MMcf/d - 1,600 MMcf/d.

International Exploration and Production

• International E&P quarterly production volumes were strong in Q3/18, exceeding quarterly production guidance and reaching 47,504 bbl/d which receives Brent pricing that averaged US$75.46/bbl in Q3/18, generating significant adjusted funds flow. The increase in production of 11% and 9% from Q2/18 and Q3/17 levels respectively, was primarily due to a successful drilling program in the North Sea, partially offset by natural field declines.
  
  
  • In the North Sea, production volumes of 28,702 bbl/d were achieved in Q3/18, an increase of 17% and 16% over Q2/18 and Q3/17 levels respectively, primarily due to the successful drilling program completed in 2018 and partially offset by planned maintenance activities at Ninian South during the quarter.
    
    
    • The 2018 drilling program in the North Sea was successfully completed on time and on budget with 3.9 net producer wells drilled year to date. Current light crude oil production is exceeding sanctioned expectations.
    • The Company's continued focus on production enhancements, increased reliability and water flood optimization in the North Sea resulted in Q3/18 operating costs of $37.32/bbl.
    • For Q4/18, the Company has planned turnaround and maintenance activities in the North Sea at Ninian Central and Tiffany.
      
      
  • Offshore Africa production volumes in Q3/18 averaged 18,802 bbl/d, an increase of 3% from Q2/18 and comparable to Q2/17 levels. The increase from Q2/18 was primarily as a result of production resuming following the planned maintenance activities completed during Q2/18, together with new production from the first of three gross production wells planned at Baobab.
    
    
    • Côte d'Ivoire crude oil operating costs in Q3/18 were strong at $13.94/bbl, a 15% decrease from Q2/18 levels.
    • In Q3/18, the Company successfully drilled the first of three gross production wells at Baobab. Current light crude oil production from the first well is exceeding sanctioned expectations at approximately 2,200 bbl/d net. Subsequent to the quarter, the second well came on production with initial rates at approximately 3,700 bbl/d net. The Company is targeting the third well to come on production in Q4/18, and is on target to exceed the original budgeted production adds for the program of 5,370 bbl/d net, and as a result, Canadian Natural is currently evaluating the option to drill an additional production well in 2019, extending the drilling program at Baobab.
    • In Q4/18, the Company has planned maintenance activities in Côte d'Ivoire at the Espoir Floating Production Storage and Offloading vessel.
    • Subsequent to the quarter, the Company farmed out a 25% working interest in the Exploration Right relating to Block 11B/12B located offshore South Africa. The Operator has secured a drilling unit to re-enter an exploration well on the Block with drilling operations targeted to commence during the first quarter of 2019.
      • As part of the farm out, Canadian Natural received an up front cash consideration and will also receive a material financial carry on the exploration well costs and subsequent operations. Subject to there being a commercial discovery, the Company will receive further bonus payments.
      • The transaction was completed on October 29. Canadian Natural's working interest in the Block is now 25%.
        
        
• The Company's 2018 International annual production guidance remains unchanged and is targeted to range from 40,000 bbl/d - 45,000 bbl/d.

North America Oil Sands Mining and Upgrading

1. Q3/18 SCO production before royalties excludes 2,758 bbl/d of SCO consumed internally as diesel (Q2/18 – 3,026 bbl/d; Q3/17 – 0 bbl/d).
2. Consists of heavy and light synthetic crude oil products.

• At the Company's world class Oil Sands Mining and Upgrading assets, operations were strong and above the midpoint of guidance in Q3/18 with quarterly production of 394,382 bbl/d of SCO, a decrease of 3% from Q2/18 levels, as planned pit stop activities at the AOSP and a major planned turnaround at Horizon were successfully completed in the quarter. Quarterly production increased from Q3/17 levels by 11% mainly due to the production from the Horizon Phase 3 expansion.
  
  
  • Through safe, steady and reliable operations, high utilization, and leveraging expertise to capture synergies, the Company realized average unadjusted operating costs of $22.90/bbl (US$17.52/bbl) of SCO in Q3/18, an impressive result given the planned downtime at Horizon in the quarter. After normalizing for planned turnaround downtime, operating costs reached $19.95/bbl (US$15.26/bbl) of SCO in Q3/18.
    
    
  • At Horizon, during the planned turnaround, optimization and reliability work on the VDU furnaces and coker train was completed under budget and the units ramped up on schedule.
    
    
  • The Company continues to evaluate the previously announced potential expansion opportunities at Horizon to increase reliability, lower costs and potentially add targeted production of 75,000 bbl/d to 95,000 bbl/d. The engineering and design specification work is on track, targeting to be substantially completed by year end.
    
    
  • The Company's 2018 Oil Sands Mining and Upgrading capital guidance is targeted to be $200 million less than previously announced. The reduction in capital in 2018 is primarily due to deferral of capital spend and achieved cost savings related to strategic capital projects.

• The Company's 2018 Oil Sands Mining and Upgrading annual production guidance remains unchanged and is targeted to range between 415,000 bbl/d - 450,000 bbl/d of upgraded products.

MARKETING

1. West Texas Intermediate (“WTI”).
2. Western Canadian Select (“WCS”).
3. Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities.

• In Q3/18, the WCS heavy differential widened as a result of a shortage of export pipeline capacity out of the Western Canadian Sedimentary Basin resulting in higher apportionment on the Enbridge Mainline system.
  
  
  • Canadian Natural and other industry participants, as part of a working committee, are working towards a more effective nomination process that verifies actual production and sales. Having an effective nomination process is significant to Canadian Natural as the Company is required to sell portions of its heavy crude oil production at a discount to the WCS index as a result of apportionment on the Enbridge pipeline.
    
    
• AECO natural gas prices for Q3/18 continued to reflect third party pipeline constraints limiting flow of natural gas to export markets, increased natural gas production in the basin and constraints on export capacity out of Western Canada. The increase in natural gas prices for Q3/18 from Q2/18 levels reflected the easing of third party pipeline constraints as well as seasonal demand factors.
  
  
• 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.
  
  

ENVIRONMENTAL HIGHLIGHTS

In Q2/18 Canadian Natural published its 2017 Stewardship Report to Stakeholders, now available on the Company's website at https://www.cnrl.com/corporate-responsibility/stewardship-report/#2017. The report displays how Canadian Natural continues to focus on safe, reliable, effective and efficient operations while minimizing its environmental footprint.

• Canadian Natural has invested significant capital to capture and sequester CO₂. The Company has carbon capture and sequestration facilities at Horizon, a 70% working interest in the Quest Carbon Capture and Storage project at Scotford and carbon capture facilities at its 50% interest through the NWR refinery. As a result, Canadian Natural targets capacity to capture and sequester 2.7 million tonnes of CO₂ annually, equivalent to taking 570,000 vehicles off the road, making the Company the 5th largest capturer and sequester of CO₂ globally once the NWR refinery is fully running.
  
  
• At Canadian Natural's Oil Sands operations, which represent approximately 66% of the Company's liquids production, the Company's emissions intensity is only approximately 5% higher than the average intensity for all global crude oils. By investing in and leveraging technology, specifically carbon capture initiatives, Canadian Natural has developed a pathway to reduce the Company's greenhouse gas ("GHG") emissions intensity to below the average for global crude oils.
  
  
• Canadian Natural's commitment to leverage technology, adopting innovation and continuous improvement is evidenced by its In Pit Extraction Process ("IPEP") pilot at Horizon, which will 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.
  
  
  • Initial results from the Company's IPEP pilot have been positive with excellent recovery rates and evidence of stackable tailings. As a result, the Company will continue running the pilot through the winter.
    
    
• The Company’s GHG emissions intensity has decreased materially by 18% from 2013 to 2017.
  
  
• Methane emissions have decreased 71% from 2013 to 2017 at the Company's Alberta primary heavy crude oil operations.

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.

• The Company’s strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved production levels of 1,060,629 BOE/d in Q3/18, with approximately 98% of total production located in G7 countries.
  
  
  • Canadian Natural maintains a balance of products with current approximate product mix on a BOE/d basis of 50% light crude oil and SCO blends, 25% heavy crude oil blends and 25% natural gas, based upon the midpoint of annual 2018 production guidance.
    
    
  • Canadian Natural’s production is resilient, as long life low decline assets make up approximately 72% of 2018 liquids production guidance, including the AOSP, Horizon, Pelican Lake and thermal in situ oil sands assets.
    
    
• In Q3/18, Canadian Natural delivered significant adjusted funds flow in excess of net capital expenditures,of approximately $1,360 million, including deferred purchase consideration. In the first nine months of 2018, adjusted funds flow in excess of net capital expenditures was approximately $4,310 million, including deferred purchase consideration.
  
  
• Balance sheet strength and strong financial performance were demonstrated in Q3/18 through reduced long-term debt and upgraded credit ratings.
  
  
  • Overall Canadian Natural reduced long-term net debt by approximately $1,780 million from Q2/18 levels and approximately $3,170 million from Q3/17 levels.
    
    
  • In Q3/18, Moody's Investors Service, Inc. upgraded the Company's senior unsecured rating to Baa2 from Baa3 and its short term rating to P-2 from P-3 with a stable outlook.
    
    
  • In Q3/18, the Company utilized adjusted funds flow to repay and cancel $1,050 million of the $2,850 million non-revolving term loan facility; $1,800 million remains outstanding and fully drawn.
    
    
  • Canadian Natural maintains strong financial stability and liquidity represented by cash balances, and committed  and demand bank credit facilities. At September 30, 2018 the Company had approximately $5,350 million of available liquidity, including cash and cash equivalents, an increase of approximately $550 million from Q2/18.
    
    
  • As at September 30, 2018, debt to book capitalization improved to 36.8% from 39.6% in Q2/18 and debt to adjusted EBITDA strengthened to 1.7x from 2.1x in Q2/18.
    
    
• Returns to shareholders remain a key focus for Canadian Natural as the Company has returned approximately $2,030 million by way of dividends of $1,156 million and share purchases of $874 million in the first nine months of 2018.
  
  
  • Share purchases for cancellation totaled 9,872,600 common shares in the quarter at a weighted average share price of $43.81.
    
    
  • In the first nine months of 2018, share purchases totaled 20,012,727 common shares at a weighted average share price of $43.66.
    
    
  • Subsequent to quarter end and up to October 31, 2018, the Company had additional share purchases of 6,900,000 common shares for cancellation at a weighted average share price of $38.66.
    
    
• Based on the significant progress made to date in strengthening the Company's balance sheet as well as the sustainability of Canadian Natural's free cash flow, the Board of Directors has approved a more defined free cash flow allocation policy in accordance with the Company's four stated pillars. Under the new policy, the Company will target to allocate, on an annual basis, 50% of its residual free cash flow, after budgeted capital expenditures and dividends, to share purchases under its NCIB and the remaining 50% to reducing debt levels on the Company's balance sheet. This free cash flow policy will target a ratio of debt to adjusted 12 months trailing EBITDA of 1.5x, and an absolute debt level of $15.0 billion, at which time the policy will be reviewed by the Board. At present, this policy is expected to be in place until at least until the Company's NCIB renewal in May 2019, subject to quarterly review by the Board of Directors. This policy is effective November 1, 2018.
  
  
• In addition to its strong adjusted funds flow, capital flexibility and access to debt capital markets, Canadian Natural has additional financial levers at its disposal to effectively manage its liquidity. As at September 30, 2018, these financial levers include the Company’s third party equity investments of approximately $658 million.
  
  
• Subsequent to quarter end, Canadian Natural declared a quarterly cash dividend on common shares of $0.335 per share payable on January 1, 2019.

CORPORATE UPDATE

• One of Canadian Natural’s many strengths is the depth and strength of our management team and our ability to develop people and execute succession plans. Subject to Board of Directors approval, it is anticipated that, effective March 31, 2019, the following changes will take effect:
  
  
  • Corey B. Bieber Senior Vice-President Finance and Chief Financial Officer will become Executive Advisor, Finance. Corey will remain on the Management Committee and continue to work together with the Finance, Investor Relations, Information Systems, Legal and International teams.
    
    
  • In recognition of the fact that Canadian Natural has grown significantly and the business environment has become more complex, in addition to maintaining the office of the Chief Financial Officer, Management believes it is appropriate to add the role of Principal Accounting Officer. This will facilitate even stronger leadership, depth of expertise and financial discipline.
    
    
  • Mark Stainthorpe, Vice President – Capital Markets, will assume the role of Chief Financial Officer and Senior Vice President, Finance and will join the Management Committee. Mark has accumulated over 16 years of experience at Canadian Natural with progressive responsibilities in various accounting departments, Treasury and Investor Relations. Mark will have overall responsibility for the finance functions at Canadian Natural.
    
    
  • Ron Kim, Vice President, Finance – Corporate will assume the role of Principal Accounting Officer and Vice President, Finance, reporting to Mark Stainthorpe. Ron joined Canadian Natural in 2006 and has held various roles and progressive responsibilities. Ron’s most recent responsibilities included oversight of taxation, corporate accounting and financial reporting. Ron will be responsible for overseeing accounting policy, processes and financial reporting of the Company.

OUTLOOK

The Company forecasts annual 2018 production levels to average between 802,000 and 868,000 bbl/d of crude oil and NGLs and between 1,550 and 1,600 MMcf/d of natural gas, before royalties. Q4/18 production guidance before royalties is forecast to average between 801,000 and 849,000 bbl/d of crude oil and NGLs and between 1,480 and 1,510 MMcf/d of natural gas. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company’s website at www.cnrl.com.

Canadian Natural's annual 2018 capital expenditures are targeted to be approximately $4.6 billion.

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") operations and future expansions, the Athabasca Oil Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the cost and timing of construction 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 or synthetic crude oil (“SCO”) that the Company may be reliant upon to transport its products to market, development and deployment of technology and technological innovations and the assumption of operations at processing facilities also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts, and is reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.

In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and natural gas liquids (“NGLs”) reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve 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 reserve 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 material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by 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 Currency, Production and Non-GAAP Financial Measures

The Company's MD&A should be read in conjunction with the unaudited interim consolidated financial statements for the three and nine months ended September 30, 2018 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2017.

All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company’s unaudited interim consolidated financial statements for the three and nine months ended September 30, 2018 and the Company's MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board ("IASB"). The Company's MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as: adjusted net earnings from operations; adjusted funds flow (previously referred to as funds flow from operations); net capital expenditures; adjusted cash production costs and adjusted depreciation, depletion and amortization. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, cash flows from operating activities, and cash flows from investing activities as determined in accordance with IFRS, as an indication of the Company's performance. The non-GAAP measure adjusted net earnings from operations is reconciled to net earnings, as determined in accordance with IFRS, in the “Financial Highlights” section of the Company's MD&A. The non-GAAP measure 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 measure net capital expenditures is reconciled to cash flows from investing activities, as determined in accordance with IFRS, in the “Net capital expenditures” section of the Company's MD&A. The derivation of adjusted cash production costs and adjusted depreciation, depletion and amortization are included in the "Operating Highlights - Oil Sands Mining and Upgrading" section of the Company's MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the “Liquidity and Capital Resources” section of the Company's MD&A.

A Barrel of Oil Equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of the Company's MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO.

Production volumes and per unit statistics are presented throughout the Company's MD&A on a “before royalty” or “gross” basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. Production on an “after royalty” or “net” basis is also presented for information purposes only.

Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2017, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov.

CONFERENCE CALL

A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Thursday, November 1, 2018.

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, November 15, 2018. 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 5558647.

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

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