Mark Stainthorpe - Vice President, Capital Markets Steve Laut - Executive Vice Chairman Tim McKay - President Corey Bieber - Chief Financial Officer and Senior Vice President, Finance

Philip Gresh - JP Morgan Securities Inc Roger Read - Wells Fargo Securities LLC Paul Cheng - Barclays Asit Sen - Bank of America Merrill Lynch Matt Murphy - Tudor, Pickering, Holt & Co. Neil Mehta - Goldman Sachs Michael Dunn - GMP FirstEnergy Capital Corp.

Good morning, ladies and gentlemen, and welcome to the Canadian Natural's Q3 2018 Earnings Results Conference Call. After the presentation, we will conduct a question-and-answer session. Instructions will be given at that time. Please note that this call is being recorded today, November 1, 2018, at 9:00 AM Mountain Time. I would now like to turn the meeting over to your host for today's call, Mark Stainthorpe, Vice President, Finance, Capital Markets of Canadian Natural Resources. Please go ahead, Mr. Stainthorpe.

Thank you, Mike. Good morning, everyone, and thank you for joining our third quarter 2018 conference call. In addition to discussing our third quarter results, we will provide an update on our strategy, operations, ongoing activities, and strong financial position. With me this morning are Steve Laut, our Executive Vice Chairman; Tim McKay, our President; and Corey Bieber, our Chief Financial Officer. Before we begin, I would like to refer you to the comments regarding forward-looking information contained in our press release. And also, note that all amounts are in Canadian dollars; and production and reserves are expressed as before royalties unless otherwise stated. With that, I'll now pass the call over to Steve.

Thanks, Mark, and good morning, everyone, and thank you for joining the call this morning. The third quarter was a very good quarter with strong cash flow per share, up 4.5% from Q2 at $2.31 a share. And importantly, earnings per share, up 83% percent from Q2 at $1.47 a share, driving increasing returns on capital employed. Canadian Natural is in a very strong and enviable position, with significant competitive advantages, competitive advantages we are leveraging to generate significant, sustainable and growing free cash flow. 72% of our oil assets are long life low decline assets and are the key drivers of our sustainable free cash flow. Long life low decline assets are very valuable as reservoir risk is low to non-existent, and the scale these operations matters, allowing Canadian Natural to leverage technology and use continuous improvement processes to minimize our environment footprint, maximize utilization, reliability, and deliver ever-increasing effective and efficient operations. The impact of long life low decline assets on our sustainability is significant. Our average corporate decline rate is targeted at 9%. As a result, our maintenance capital to hold production is flat is significantly less compared to a typical E&P company, making Canadian Natural more robust and generating more free cash flow. Canadian Natural's ability to generate significant and sustainable free cash flow sets us apart from our peers. So far in 2018, you've seen us deliver or maximizing value by optimizing our allocation to the four pillars. Balance sheet strength, which was allocated 30% of our cash flow, along with FX result in our balance sheet strengthening by $32 billion, since Q3 2017. Return to shareholders was allocated 26% of our cash flow with dividends at $1.6 billion for the year, up 20% and a significant ramp up in share buybacks at $1.1 billion year-to-date, reflecting that at current market conditions, it creates value to buy back shares. Resource development, we maintained or we have remained disciplined and will remain disciplined as we go forward. Resource development capital has remained unchanged at 41% of our cash flow. That being said, we're still preserving our ability to execute on significant and exciting high value adding and growth opportunities at both Horizon and Athabasca Oil Sands Project. These opportunities will have between 75,000 and 95,000 barrels a day of production in smaller stepwise projects, that will also increase reliability and lower both operating and sustaining capital costs at very good capital efficiencies. Smaller stepwise projects preserve our capital flexibility, as they are shorter duration from initial capital spend to on-stream date. As we become larger, more robust, and sustainable, the opportunities for Canadian Natural to execute on value-adding and growth opportunities have significantly exceeded our expectations. The timing of when we execute on these opportunities depends on improvements in market access, fiscal competitiveness and regulatory effectiveness and efficiency. We have ways to go. The fourth pillar, opportunistic acquisitions as we see it a very small allocation 3% related to tuck-in acquisitions that complement our core areas. We see no gaps in our portfolio and are building asset base, the significant organic opportunities. Based on the significant progress made to date in strengthening the Canadian Natural's balance sheet as well as sustainability of our free cash flow, the board of directors has approved to a more defined free cash flow allocation policy in accordance with the company's four cash flow allocation pillars. Under the new policy, the company will target to allocate 50% of its residual free cash flow, after budgeted capital expenditures and dividends, to share purchases under the Normal Course Issuer Bid, and the remaining 50% to debt levels on the company's balance sheet. The free cash flow policy targets a debt - ratio of debt to adjusted 12 months trailing EBITDA of 1.5 times, and an absolute debt level of $15 billion. This policy will be reviewed by the board on a quarterly basis and expected to be in place at least until the NCIB renewal in May 2019 and provides additional clarity on Canadian Natural's free cash allocation going forward. In addition to balancing the four pillars, part of creating long-term value is reducing our environmental footprint, where we have taken significant steps to reduce our environmental footprint and delivered meaningful results. I go through these points on every conference call, because we believe it's important we communicate the great progress Canadian Natural, and the entire oil and gas sector is making and reducing our environmental footprint. Next week, Canadian Natural, along with one of our industry peers will be in Toronto and New York at sessions illustrating these achievements and how by leveraging technology, we have a clear pathway deliver even greater performance in the near term. Since 2012, Canadian Natural has reduced our methane emissions in our commercial heavy oil operations by 71%. In addition, we have invested significant capital to capture and sequester CO2. We have CO2 captures sequester - and sequestration facilities at Horizon, a 70% interest in the Quest Carbon Capture and Storage facilities at Scotford and the capture sequestration facilities at Northwest refinery, when it's up and running. As a result, Canadian Natural will be conserving roughly 2.7 million tons of CO2 a year, equivalent to taking 570,000 vehicles off the road, making Canadian Natural that third largest owner in the global oil and gas sector of CO2 capture and sequestration capacity, and the fourth largest of all industries in the world. This makes a significant impact on reducing our greenhouse gas emissions intensity with more reductions to come. In addition, Canadian Natural minimizes our land usage and recycles 90% of our water used in Oil Sands Mining and Upgrading, significantly reducing our freshwater usage. Canadian Natural is also the largest investor in research and development in the oil and gas sector and fourth largest in all sectors in Canada. With investment in technology, we have made significant progress in reducing our greenhouse gas emissions. And there is a pathway to reducing the greenhouse gas emission intensity from oil sands production to levels that are below that of the average oil produced globally. For reference, today, at Horizon, we recognize our carbon capture initiatives, our emissions intensity is only slightly higher, 5% from the average for all global oils. The impact technology and effective operation has on lowering Canada's oil sands greenhouse gas emissions intensity, and our ability to leverage technology to continue to reduce emissions intensity is generally not well understood. Many external opinions in oil sands' operations are based on outdated data from many years ago that unfortunately continue to be used as reference materials in many reports. In fact, a report published last month by a major firm, likely, listening this morning, uses outdated data without contacting oil sands producers to get the correct data. To that end, we're working with highly respected academic institutions to review and verify our data and update to reference material. The long life, low decline nature of oil sands assets allows producers to continue to leverage technology, further reducing our environmental footprint and driving ever-increasing effective and efficient operations. This is exactly what has happened and continues as we achieve further improvements. The value of Canada's oil sands is very important to Canada and Canadian Natural. We believe the oil sands will ultimately stand the test of volatile oil prices and any potential demand forecast scenario, as we believe the oil sands will have the lowest environmental footprint and lowest total cost. At Horizon, we've taken operating cost from over US$40 a barrel to roughly US$17 a barrel. And, importantly, there are no reserve replacement costs, a fundamental factor in Canadian Natural's strategy to invest in the oil sands and be a leader in research and development. Canadian Natural is doing an excellent job, when it comes to reducing our environmental footprint and balancing the four pillars of cash flow allocation to maximize shareholder value. With additional clarity provided today, and how we allocate cash flow going forward. There are very few E&P companies that can deliver substantial, sustainable, and growing free cash flow. And at the same time deliver production growth per share, top tier effectiveness and efficiency, a defined cash flow allocation program to maximize value for shareholders, and drive increasing returns on equity and returns on capital employed as well as increasing returns to shareholders and at the same time both strengthen the balance sheet and reduce our environmental footprint. Canadian Natural is robust, sustainable and clearly a unique E&P company. With that, I'll turn it over to Tim.

Thank you, Steve. Good morning, everyone. Our strength and ability to execute shows in our third quarter results, as we exceeded the midpoint of guidance in many areas and generated significant adjusted fund flow. We continue to be effective and allocate capital to maximize our value to our shareholders. With that, I will do a brief overview of our assets. Starting with natural gas, our third quarter production at 1.553 Bcf was expected at a midpoint of Q3 guidance. In the third quarter, the Pine River plant started at four weeks turnaround outage, which was completed mid-October, but due to additional integrity issues encountered is now targeting a mid-November startup. While the facility was down on turnaround, our team was able to complete an assessment of plants potential to match our fuel capacity of 145 million a day, which would add significant value. This investment decision is currently being assessed and would be included in the 2019 budget should we decide to proceed. As well, we continue to wait on regulatory approval for the transfer the plant, and once received, we will look to take over the facility later this year. So overall, third quarter natural gas production for North America was 1.489 Bcf. Our field operations team have been very focused at reducing our natural gas costs across the company. With Q3 operating cost averaging above 20, which is down from Q2 of $1.28 and Q1 of $1.31, which shows the benefit owned and operated infrastructure giving us flexibility to reduce volumes without materially impacting our cost. Impressive, considering we have deferred activity, curtailed and shut in natural gas to the tune of 146 million cubic feet per day year-to-date. Q4 2018 natural gas guidance is targeted to be 1.48 to 1.51 Bcf, down from Q3 primarily due to the Pine River extended outage as well as our strategic decision to differ activities, curtail and shut in production in Western Canada due to the temporary low gas - natural gas prices, as a result of the [T-cell line] [ph] failure and east gate restriction. Our natural gas portfolio is very diversified and balanced in which 37% is used internally, 28% is exported and only 35% exposed AECO pricing. Our North American light oil and NGL production for Q3 was approximately 93,000 barrels a day, up from Q3 2017 and as expected approximately 3,000 barrels a day, up from Q2. We continued to reduce heavy oil capital and shifted to drill light oil wells, which adds value and set us up for future growth opportunities in these areas. Our third quarter operating costs were $15.51, down from Q2 of $15.81. At Tower, six wells are on production at approximately 900 BOE per day, 370 barrels a day of oil, a very good result, last well will come on as gas handling capacity comes available in Q4. In the short period, these wells have been on production, they have already made over 200,000 barrels of oil, which highlights power, quick payout of low capital exposure assets and our capital flexibility. Tower has significant upside, potential on our lands who can drill additional 41 wells that can leverage of our infrastructure over time, and if we choose expand the facility. At Wembley the upside potential is even larger than tower, as we have significant Montney oil development opportunity on our 77 net sections of land, which could support 175 wells over time. The two Montney oil wells drilled in the first quarter continue to outperform and are currently producing about 500 barrels per day per well. With this success, we have followed up and drilled four net wells in Q3 targeting to come on in late November. Finally, in Southeast Saskatchewan, away from the apportionment issues in Alberta, we drilled nine net wells. For Q3, we successfully drilled 27 net light oil crude wells, 19 more than we had originally budget showing the strength of our asset base, capital flexibility and the company's ability to execute to maximize value. Our International light oil crude area had a very strong quarter, exceeding the third quarter guidance, generating significant free cash flow as we receive Brent base pricing there. In Offshore Africa, one of our highest return capital areas production was 18,802 barrels a day in Q3, up from Q2. In Q3, CDI operating costs were very strong at $13.94 per barrel. At Baobab, drilling has gone very well and currently we have two wells on production at approximately 5,900 barrels a day net and we're on track to exceed our sanctioned production at 5,400 barrels net by Q4, with the third well yet to come on. With a strong performance of the rig and results so far, the company is reviewing the opportunity to exercise an option to drill one more production well at Baobab, which would happen in 2019. In the North Sea, we had strong drilling results and averaged 28,702 barrels a day in Q3, up almost 4,000 barrels a day from Q2. We had excellent operating results in the third quarter. Operating costs in the North Sea were $37.32 per barrel. Q4 international guidance is 40,000 to 44,000 barrels a day, as we have planned turnarounds that Ninian Central and Tiffany platforms as well as the FPSO in the fourth quarter. Canadian Natural is focused on creating value with the success than light oil in the short term volatility in the heavy oil market, it continues to make sense to move capital from heavy oil to light oil in a disciplined manner. We also made the strategic decision not to sell into anonymous heavy oil market, and have taken action to maximize value for shareholders. In Q4, we are only drilling wells that are strategic and set us up for additional future opportunities. We target to reduce our original budget well count by 127 net wells this year, and did not complete 33 net wells drilled in Q3, and continue to shift capital to our light oil projects that are being drilled in the latter half of 2018. Our Q3 production was up from Q2 averaging 91,631 barrels a day even as we curtailed activity in the third quarter. Our third quarter operating costs were very strong at $15.58 per barrel versus our Q2 operating costs at $17.02 per barrel. At Smith, our six multilateral heavy oil wells continue to outperform the original sanctioned projection, as they're currently at 300 barrels per day per well, well above 175 barrels per day well estimate. This continues to be a great result from a small program and has the potential development program that could target up to 125 wells across our 19 net sections of land. In our thermal properties, production was strong after completion of turnarounds in Q2 at Primrose, Peace River and Kirby South producing overall 112,542 barrels a day versus Q2 of 104,907 barrels a day. The Kirby South third quarter production was 35,839 barrels a day with excellent operating costs at $9.14 per barrel including fuel, which is very consistent with previous quarters. At Primrose, Q3 production was 72,500 barrels a day as we had very strong production after completion of a turnaround followed by CSS cycle. Our thermal operating costs continue to be effective and efficient with $11.80 barrel operating costs down from Q2 of $14.66. We continue to execute on our growth projects at Primrose and Kirby, both are proceeding very well ahead of schedule. And combined, we target at production capacity of over 70,000 barrels a day in 2020. At Kirby North, the company's 40,000 barrels a day SAGD project, which originally targeted first oil in Q1 2020. We continue to have top tier execution and very strong productivity. The project continues to be three months ahead of schedule with contingency and targeting first oil in Q4 2019, as we talked last quarter. Cost performance remains on budget. And the Central Processing Facility is now 80% complete and drilling is now 70% complete. At Primrose, drilling had a highly profitable pad adds continue, which is on cost and now one month ahead of schedule with planned steam in Q4 2019, which is targeting to add 32,000 barrels a day in 2020 and now has a target readout at of over 10,000 barrels a day in Q4 2019. Thermal Q4 guidance is 96,000 to 102,000 barrels a day. Key component of our long life load decline transition is our world class Pelican Lake pool, where leading-edge polymer flood is driving significant reserves and value growth. Q3 production was 62,727 barrels a day, down from the Q2 of 63,914 barrels a day, as we continue converting existing water flood areas on acquired lands to polymer flooding. With 62% under the polymer flood by the end of the Q3, this project is now complete for this year ahead of schedule and we - as we targeted 63% by the end of the year. This process maximizes long-term value as we convert more injection wells to the more viscous polymer. It temporarily impacts production rates in the short-term, however over the long-term, it creates better sweep and performance, maximizing oil recovery and adding significant long-term value. At Pelican lake, Q3 operating costs continue to be top tier on a combined basis were $6.43 per barrel, down from the Q2 of $6.96 per barrel, as we optimize the polymer flood. With our low decline and very low operating cost, Pelican Lake has excellent netback and recycle ratios. At Oil Sands Mining operations in the third quarter, we produced 394,382 barrels a day of our midpoint of guidance. Our industry-leading third quarter operating costs was very impressive at $22.90 per barrel on unadjusted basis, as we successfully completed turnaround at Horizon. We continue to track to our lower operating cost guidance of $20.50 per barrel to $24.50 per barrel. We continue to capture synergies between the two sites leveraging technical expertise, services and buying power as well as operating efficiency. We continue to advance our autonomous truck pilot, which is targeted for Q3 2019 based on our current view with our top tier mining utilization, it could reduce our cost by additional $0.30 to $0.50 per barrel, when in place. During the quarter, we acquired the Joslyn lease to the South of Horizon with proximity of the lease to south mine pit at Horizon, we are targeting to capture synergies, adjusting our mining plan, which will give us savings of over $500 million in our new mine plant versus advancing to the original North Pit plant. Finally, we continue to advance some engineering in a measured pace to Horizon to preserve our future growth opportunities we have there. Our Oil Sands Mining Q4 SCO production guidance is 433,000 to 463,000 barrels a day. There has been much said and published about the market anomaly we see today resulting in very wide differentials for Canadian oil types. That being said, we will briefly share Canadian Natural's view of the current market. To be clear, the anomaly is clearly created by lack of market access. However, it's exacerbated by the nomination process that's ineffective and creates further distortions in the market. Canadian Natural is working with producers through the crude oil logistics committee talk to optimize the nomination process. It is taking some time, as clearly some parties capture windfall revenues at the expense of Alberta citizens and Alberta producers are determined to continue to capture windfall revenues. Although it's taking time, we are confident the nomination process will be optimized and these distortions removed from the markets. Market access for a lack of takeaway capacity is a major driver of the current Canadian pricing. The root cause for the lack of takeaway capacity is Canada's dysfunctional regulatory, legal and political systems that allow analysts delays to put forward by minor risk factors. Canadian Natural believes all these pipelines will ultimately be built as they meet all regulatory, environmental and stakeholder concerns. And with the construction of pipelines, this will generate huge benefits for all Canadians. We expect full Trans Mountain and Keystone will be built. Of course, some pipelines have managed to get through this dysfunctional system and are being built and real capacity is being added. As a result, it's our view the market anomaly is most likely a 9- to 12-month event. Capacity is committing [ph]. Line 3, 370,000 barrels a day in Q4 2019 and line field may occur sooner. Rail capacity, we expect 150,000 barrels a day will be added over the course of the next nine months. Canadian Natural has 10,000 barrels a day for one year of rail capacity. North West refinery, which we have 50% interest and we'll begin taking heavy oil at 80,000 barrels a day. Conventional declines are conservatively estimated in the range of 30,000 to 60,000 barrels a day. This will result in over 600,000 barrels a day of effective increase in takeaway capacity, offsetting this will be increase in the production, which in our view will not be material and relative to the 6,000 barrels a day of effective increase in takeaway capacity. This forms basis to what we believe to be constructive pricing, as we approach the second half of 2019. In the meantime, we expect to see reduced industry activity and the jobs that go with the activity as well is shut-in production, shut-in curtailments. Canadian Natural, for October, we estimate that impact to be 10,000 to 15,000 barrels a day, and for November and December targeting 45,000 to 50,000 - 55,000 barrels a day of mostly heavy oil. We've adjusted our guidance both E&P and thermal to account for our strategic decision to differ activities as well as shut-in and curtail volumes in October, November and December. Our assets are strong, and we will look to recover volumes and prices recover, preserving value for our company, our shareholders, Albertans and all Canadians. Canadian Natural's advantage is our ability to effectively allocate cash flow to our four pillars and light up market conditions. In 2018, you've seen us deliver on maximizing value by optimizing our allocation to the four pillars. We will continue to execute excellence and be effective and efficient operator. We are a very strong position and being nimble enhances our capacity to create value for our shareholders as we continue to high grade opportunities in the company. We will continue to focus on safe, reliable operations, enhancing our top tier operation. We will continue to balance and optimize our capital allocation, and deliver free cash flow and strengthen our balance sheet that Corey will highlight further in the financial review. With that, I will now turn it over to Corey.

Thank you, Tim, for that very comprehensive update on the company strong operational performance for 2018. We also had strong financial performance during the quarter. Net earnings of approximately $1.8 billion were achieved in the third quarter of 2018, accumulating to a robust $3.4 billion over the first nine months of the year. Adjusted earnings from operations were about $1.4 million for the third quarter, up about $1.2 billion, when compared with the third quarter of 2017. Year-to-date adjusted net earnings accumulated to $3.5 billion, up about $2.7 billion from the first nine months of 2017. The third quarter improvement reflects solid crude oil production volumes and effective and efficient operations that Tim spoke about, as offset by slightly weaker crude oil pricing - the oil pricing. Quarterly fund flow from operating activities was $3.6 billion for the quarter and $8.7 billion for the first nine months of 2018. Adjusted fund flow for the corporation was $2.8 billion, 69% higher than that recorded during Q3 of last year. For the first nine months, our adjusted fund flow was a record $7.9 billion, 56% increase over 2017 levels. During the first nine months, we invested approximately $3.4 billion in economic development and tuck-in acquisitions, repaid net debt and deferred acquisition liabilities totaling $3.1 billion and returned over $2 billion of cash to shareholders in the form of dividends and share buybacks, essentially balancing the four pillars of capital allocation. Since the Albian, AOSP acquisition, we have been able to reduce long-term debt and acquisition liabilities by approximately $4.2 billion, improving our debt-to-book capitalization to about 37% from above 43% and debt-to-adjusted EBITDA to $1.7 billion from $3.4 billion, clearly demonstrating our commitment to strengthening the balance sheet. At quarter end, available liquidity was exceptional at $5.35 billion. Based upon current strip pricing, including the much wider than normal differentials, we would expect to exit the year with similar debt metrics reflecting the impact of extraordinarily wide light and heavy oil differentials. For the fourth quarter, we continue to target adjusted fund flow to be substantially in excess of capital expenditures and dividends paid to shareholders. In terms of activity on the company's Normal Course Issuer Bid, Canadian Natural remains very active with a total of 26.9 million shares repurchased over the first 10 months of the year at an average cost of $42.37 per share for total proceeds $1.14 billion. Additionally with the new cash flow allocation guidelines adopted by our board of directors, we can provide greater transparency on disposition of free cash flow. This methodology allows for an - both for an ever strengthening balance sheet as well as enhanced cash returns to shareholders. Clearly, the company has transitioned into a very robust free cash flow enterprise, demonstrated by both significant debt reduction and significant cash returns to shareholders. In closing, I believe Canadian Natural continues to represent a sustainable flexible and balanced E&P company with a high degree of resilience to commodity price volatility. With that, I'll hand it back to you Tim for your closing comments.

Thanks, Corey. As you all read, Corey Bieber, our CFO for the last six years had decided to take a somewhat less demanding role in the company as Executive Advisor effective March 31, 2019. As a result of this change, effect of March 31, Mark Stainthorpe will be promoted to Chief Financial Officer. Many of you know Mark, who is a very talented individual with strong financial and leadership skills, and has been mentored by both Corey and Steve over the last 12 years. I'm very confident that he will do a great job in leading a strong financial team. Of course, Corey will still be around to provide Mark and Ron with all the help they will need. Similarly, Ron Kim would be promoted to Principal Accounting Officer effective March 31, 2019, working together with Mark. Ron brings great deal of technical, accounting and taxation expertise. We believe that this team will add significant value to shareholders and complements the experience that Corey has brought to the table. These changes would be subject to board approval in March of next year. In summary, Canadian Natural has many advantages, our balance sheet is strong, we continue to strengthen it, we have a well-balanced, diverse and large asset base. A significant portion of our asset base is long life low decline assets, which requires less capital to maintain volumes. Our balance for commodities with approximately 50% of BOEs, light crude 25% heavy and 25% natural gas, which lessens our exposure and volatility in any one commodity. We're delivering substantial free cash flow, which we're effectively allocating to our four pillars. Canadian Natural will continue to allocate cash flow to our four pillars to maximize value our balance sheet continues to strengthen, we continue with discipline resource development, return to shareholders has been strong at 22% dividend increase earlier this year, and year-to-date we have bought back 27 million shares. Finally, while we have no gaps in our portfolio, potential acquisitions should we choose so. This is all driven by effective capital allocation, effective and efficient operations by our teams deliver top tier results. With that, we will open the call to questions.

[Operator Instructions] Your first question comes from the line of Phil Gresh from JP Morgan.

Hi, good morning.

Good morning.

Good morning.

First question, I guess, would be on the production curtailments 45,000 to 55,000 for November and December. And your comments about the market and your outlook for the next nine to 12 months. I mean, do you - at this point would you say that you see kind of a need to do this in the 2019? And I'm just kind of going off of your press release, where you talked about how these would be factors, you'd be thinking about as you plan ahead for next year. So what would be a current thinking?

Thanks, Phil. It's really - we'll just measure this as we go through the year, if you look back at 2018 with the apportionment issue, it's been all over the map like back in March and April, we had about 51%, 50% and differentials were in the $25 to $27 range. So you know, it's very volatile, we will react to the market as that differential comes in.

I would add, Phil, I think, you'll see entertainments for ourselves and others, and we also believe that there will be some action taken on the apportionment rules. I think this is all going to be very constructive for pricing going forward. And how soon that takes effect will be seen to go forward, but we think there's a lot of constructive things happening.

Yeah, I appreciate that. I guess, embedded partially in my question is whether you think maintenance - refinery maintenance is having a big temporary factor on this or whether you think that we really - it really is going to require waiting until Line 3 and/or apportionment gets fixed?

The maintenance activities is minor in our opinion. Obviously, the apportionment and the rules around the apportionment is a bigger factor and takeaway capacity, which we see leaving itself over the next year.

Sure. Okay. And then, I know, you've - CNQ has been renascent to sign up the rail. You said, you've been doing 10,000 barrels a day, and I think, some of the other companies that have been committing to rail. It hasn't been a 100% fixed cost, I guess, situation in terms of the cost of signing up for that. So - is there any willingness to look at rail on your part? Or you'd rather just - you're confident and you rather just wait it out for the nine months?

If you go back in history Canadian Natural has never been adverse to doing a rail deal. Onetime, we had over 30,000 barrels a day going by rail. For us, it's always been to do the right deal for the right term. And so we have a deal to do roughly 10,000 barrels a day for 2019. It's flexible deal that we feel is the right amount. So it's always difficult in these situations to go with a longer term deal, when you feel that a lot of these distortions in the market are rather temporary.

I'd add, Phil. If you look, we have 50% percent ownership in North West, which will take 80,000 barrels a day heavy oil here shortly. We also, as you've heard Tim talk about, believe that there will be 600,000 barrels a day of effect of takeaway capacity are coming here over the course of the year, obviously, Line 3 is the biggest part of that in Q4, but a lot of that capacity will come as it progresses through the year, particularly North West. So that sort of influences is how look at rail.

And is the North West refinery running at 100% lights right now, is it actually up to 100%?

It's taking light oil right now, I'll defer you to North West give you more details on that, and they will be taking heavy oil here in the near term.

Okay. Last question just be on the capital allocation framework that's been laid out, certainly appreciates the additional commitment. I guess, I'm trying to read into it, I guess, it sounds like it's going through May of next year. Is that just a technicality is this something that you'd expect to continue beyond that period of time? And I guess, maybe just a little color on why you decided to put something more formal in place?

Phil, it's Corey. Yeah, so it's going through May at the very least that's when our statutory allowance under the exchanges expires. And that also gives our board the right time to reexamine the policy. But right now, the intent is until we hit those debt targets that is our intention. We've been doing it, it's actually isn't really a change in policy, Phil. So we've been doing it. It's - just when you look at more transparent in terms of the approach we've been adopting. But we've been very, very active through this point on the share buyback. So we've been - we've heard a lot of shareholders ask for that transparency, and we're providing that transparency in terms of what our actual plans are.

Okay. Fair enough. Congratulations, Corey and Mark. I'll turn it over.

Thanks.

Thanks very much. I appreciate it.

Your next question comes from the line of Roger D. Read from Wells Fargo.

And thanks for the clarity, particularly on the takeaway capacity issues. I don't know, if you can offer any more on that front, but just sort of maybe a little more detail on just sort of the process of how this works like who has to actually make the decision, is it the NAB? Or is it the strict higher up in the federal government? I'm just curious, what - who makes the decision here.

Are you referring to the apportionment rule?

Yes, specifically apportionment.

Yeah. So with that there is a committee, a producer committee or industry committee called the Crude Oil Logistics committee. And what that committee was doing was trying to fix this issue. And obviously, what happens is, because of the committee they had a vote on it, and even though 70% of the players in that committee or part of the committee agreed to the process. So it's 75%, I think for carry forward. So right now, it's kind of in no man's land to say. Obviously, what we would need is some apportionment that could come through the Alberta government or by industry players agreeing that needs to be fixed and move forward with the recommendations of the Crude Oil Logistics committee.

Okay. So essentially there is winners and losers and somewhat is interested and others is changing the setup, I guess?

Yeah. And it's unfortunate in my mind 70% is a very strong majority. And that - it shouldn't be more consensus, we should do what's right to optimize the system.

Yeah, it's a fair argument. For changing gears slightly here to look at the change in production guidance for the fourth quarter, and I totally recognize why you would do it is. But when you look at what to shut in here, what to curtail, what should we think about as an impact on either the margins or on the cost structure of the company. And I'm not just talking about the specific guidance on OpEx, but kind of how we should think about what the mix of what's being shut in here should flow through to kind of top and bottom lines? Or is it not always the lowest margin production that's being curtailed.

No. I think, you're absolutely right. Obviously, we will curtail the most expensive higher operating cost ones first. And then as well on the thermal side, really were able to just dial back on our steaming strategy to modify, when we'll get that oil. So we were - it will not materially impact our bottom line on our operating costs. As you saw with the gas side, we're able to adjust our operating costs and move people to where we need to, to keep our costs low.

Great. Thank you.

Your next question comes from the line of Paul Cheng from Barclays.

Good morning, guys.

Good morning.

First just want to say - want to compliment you guys that you gave a more clarity and transparency on the capital allocation process. I really appreciate that. And I think most of your investor that we talk to seems to have to same feeling. So thank you.

Thank you.

Just curious that, with the [prolonged defense] [ph] so initially with heavy oil and then in the last two months, spilling into the light oil. So is it really makes sense that for us to trying to shift the capital from the heavy into the light and trying to increase the production there? We potentially - that causing the bigger problem in the light oil.

So for our program, it's not going to materially impact. The light oil issue obviously the light side has seen a more apportionment. But when you look at the developments we're doing in the Montney area, primarily it's high, I would call, condensate very light oil. As you know, we require a lot of condensate for heavy all operations, and as such won't impact the market.

One thing, Paul, you look at is there's actually a tremendous amount of condensate imported into Canada at the present time. So as we increase our light oil and liquids rich gas drilling to produce more condensate just actually reducing imports of condensate into Canada. So it actually has a minimal impact on market access issues over experience on the rest of the market.

Okay. And then just curious that means Steve and team with the Kirby South has been progressing faster in that potential rate that can come on stream, say, by the fourth quarter of 2019. But just for argument sake that we then see the [defense] [ph] improving by the midyear. Will you guys do at that point that decide to delay the streaming process and not bringing the fuel on stream or that you and the way that is already done mechanically ready to go. So you would just go ahead.

Yes. You're referring to Kirby North, and that…

Yeah, I'm sorry.

That's okay. That the project is going very well. We evaluate that decision at the time, but one thing with this idea, there is a period of time where it's wrapping up. So it's not as if on day one, it goes to 40,000 barrels a day. We actually have do circulate heat reservoir and it's actually a ramp up. So again, it wouldn't materially impact the market obviously we would look at what is going on in the market, we feel today that we are very well timed with the takeaway capacity. And - so it actually works in our favor today as we see the timing.

Hey, Paul, we're very confident that the market access issues with temporary issue here in the short-term will be like Q4 will be resolved.

I'm just curious that, when you're looking at the well capacity order, well agreement. Do you looking at it, just as a hedge. There's a physical hedge against your own production. And in some way there is no different than that the financial hedge that from time to time, you guys entering into? Or that you're looking at it, saying that, okay. Can I get a good deal in here? So I just curious that, when you're looking at that, I mean, how you determine is it considered as a hedge or considered that whether you think is a good investment at this time?

Well, obviously this time it looks like what we believe, it's a good investment. Obviously, we look at this as a very temporary situation market distortion, and taking oil out of the market in Alberta. It is a positive thing for all Alberta. So you know you could look at it in a number of ways. One, by removing these barrels out of the basin, We're helping the apportionment issue and differentials as well as we see some benefit economically and the reason we did the deal for the one year period.

They do - doesn't sounds like that you would be actively trying to maybe increasing to 50,000 to 60,000 barrels per day kind of volume. So you're happy with the 10,000 that you signed?

We will continue to look at all real deals and all of the options forward, not boxing ourselves in here. So we continue to evaluate all options.

Okay. Thank you.

Your next question comes from the line of Asit Sen from Bank of America Merrill Lynch.

Thanks. Good morning. I appreciate the update on the macro, just wondering if you're thinking about this recovery process over the next two to three quarters. How do you view the recovery in light dips? Or should we expect light oil dips normalize before heavy oil. What are the drivers we should look for any thoughts on that front?

If we could predict the market, it would be a great thing. With the apportionment issues with the industry response on curtailing production ourselves and there's been a few other companies curtailing production is very difficult to predict what will happen in the market. I would, suspect it will strengthen on both accounts that differentials will come in, because as industry does respond and does curtail activity and production differentials will shrink.

Okay, thank. And then on the 2019 CapEx, if we just thinking about it and in terms of the growth projects that are on the docket. Could you remind us on, kind of the capital cost and how you're thinking about those particular growth projects.

Well, first of all, we haven't determined our 2019 budget. Obviously, the key issue ahead of us is the takeaway market access issues, so what we'll do is when we have a recommendation on our 2019 budget, we will go to our board and make that recommendation. But obviously, these market access considerations are very key in terms of our timing, and how we allocate capital going forward.

Great. Thank you.

Your next question comes from the line of Matt Murphy from Tudor, Pickering, Holt.

Hey, good morning and thanks for taking my question. On the topic of curtailments. I'm just curious, if there's a length of time you're comfortable having those volumes shut in before you'd run reservoir risks, perhaps, both in - you're more conventional heavy stuff versus in situ potential to have - you have the potential that you would be unable to bring those back?

Yeah. From our perspective, everything we do in terms of the curtailments and shut ins, we do in the face of making sure it doesn't do any long-term damage to the reservoir. So we are very fortunate with the CSS cycles that the big component of it is how quickly we inject the steam. So as you can appreciate we can slow down the steam injection, slowdown that cycle to help mitigate the potential of any reservoir damage.

Okay. That's helpful. And then on the topic of shifting capital from heavy to light oil, as you talked about obviously seeing some challenges on both conventional light and synthetic grade pricing as well. Just wondering, what kind of impact that you're seeing from apportionment on your - is it on your ability to move barrels or is it just primarily pricing related?

It is all pricing related, we - through 2018, we moved every barrel that we would like to. As you have seen through 2018, when the pricing gets too out of sync, Canadian Natural and other producers that will not sell into those anomalous markets and curtail production.

Great. Thanks very much, guys.

Your next question comes from the line of Neil Mehta from Goldman Sachs.

Thanks guys, and congratulations to Corey, Mark and everyone else on the changes that were announced this morning.

Thanks, Neil.

Hey just want to kick it off on 2019 capital budget, I don't get ahead of our skews here, but just any early thoughts in terms of what the levels would look like especially just looking at the forward curve to help us frame out where your guys head is at as of right now?

I wouldn't want to speculate at this time. We still have to go through our process, and actually do the work before we presented to the board, and I wouldn't want to spec this time.

Okay. Fair enough. And then on the light oil exposure point, I don't spend too much time on this. But is there a back of the envelope or sensitivity to a dollar changing cash - dollar change in, let's say, Syncrude pricing or light oil pricing in Canada that we could then say this is $1 million impact your cash flow over the next year 2019?

Sure. So this is using 2018 sensitivity, Neil. But as we've talked about before a dollar change in WTI's about $250 million change in heavy oil is about $90 million change in light is in that range of $160 million, but I would caution that includes international. So if we go to Canada's loan, it's probably in that range of $145 million to $150 million.

$145 million to $150 million.

Yeah.

Okay, great. And last thing and congrats on the 50-50 split in terms of cash flow, I think the market - has the market definitely want to see that and appreciate a little bit more clarity around capital returns. So just - I guess, the question is how much flexibility is there around that number if cash flows come in low, because were there suppressed by the differential. Could you go above the implied formula in terms of share repurchases, because theoretically that would - you'd have better opportunity of buying the stock below its intrinsic value, when cash flow is more depressed and differentials are wider. So how much flexibility is there around this - the formula that you laid out as opposed to taking a more prescribed approach to buying back stock.

So Neil you understand well our Canadian Natural is all about creating value. And we're going to balances over on an annual basis. So we have quite a bit of flexibility to make sure that we capture the most value for shareholders. So we'll be strategic and how we manage this share buyback program, but we are targeting a 50% level on annual basis.

That's great. Last one for me, a dividend and the next time you'll get a chance to reevaluate that and how should we think about potential growth levels recognizing it's a board decision? Is that an early 2019 decision for you guys, should we think that the last couple of years run rate, which is mid-teens are still a reasonable base case?

Like as you point out, Neil, it is a board decision, so it's not for us to speculate on, but I think you can look at the robustness and strength to Canadian Natural. We still generate a substantial amount of free cash flow even a very low oil prices. So I think that - maybe we can inform you, where the board will look at it. Again it's a board decision so we won't speculate on what that'll happen, but it's a decision that happens every year, early in the year in the first quarter.

I'd just add to that, Steve. Dividends are very important to both us and to the board. And the one key, we always look at when we look at the board is that sustainable and still providing room for growth on an annual basis through the commodity price cycle. And we believe that we stress test at a very, very low price in that $40 range. So that we can maintain current production and pay the current dividend in that price range. So that's very important to us.

And provide growth as well.

Great. Thanks, Steve.

Thank you.

[Operator Instructions] Your next question comes from the line of Mike Dunn from GMP FirstEnergy.

Good morning, everyone. Most of my questions have been answered. I just was wondering, you mentioned the $0.5 billion eventual cost savings from acquiring that Joslyn lease relative to the alternative, I guess, which was to develop the North pit. What would have been the timing on that $0.5 billion of spending, I mean, it was the North Pit project that was near-term or you know 10 or 15 years out? Thanks.

Hi, Mike. So that's really - what it is north mine pit was actually our next phase. So over the next 10 years, we would be progressing North, with this change, we'll head south. And I should say that $500 million savings is probably conservative, as you're aware we are piloting the IPEP project. And if the IPEP project proves to be successful and the early indications are it is quite successful. We actually see those savings actually increasing as we would use IPEP, as we head south.

Great. Thanks, Tim. Thanks, everyone. That's it for me.

Thank you, Mike.

That was our last question at this time. I'll turn the call back over to Mark Stainthorpe for closing remarks.

Thank you, Mike, and thanks everyone for attending our conference call this morning. Canadian Natural as well positioned to create value and navigate changes in the commodity price environment. Our free cash flow generation is significant and sustainable and along with our flexible capital programs facilitates maximizing value by balancing capital distribution to our four pillars. This along with our balance of long life low decline and low capital exposure assets provide significant opportunity and optionality to create long-term shareholder value. If you have any further questions, please give us a call. Thank you, again, and we look forward to our fourth quarter conference call in early March. Thank you.