Canadian Natural Resources Ltd Q2 FY2020 Earnings Call

Good morning, ladies and gentlemen, and welcome to the Canadian Natural Resources earnings results conference call webcast. Please note that this call is being recorded today, August 6, 2020, at 9:00 a.m. Mountain Time. I would now like to turn the meeting over to your host for today's call, Corey Bieber, Executive Advisor. Please go ahead, Mr. Bieber.

Thank you, operator, and good morning, everyone, and thank you for joining our second quarter 2020 conference call. With me this morning are Tim McKay, our President; and Mark Stainthorpe, our Chief Financial Officer. Before we begin, I would refer you to the special note regarding non-GAAP measures contained in our press release. These measures used to evaluate the company's performance should not be considered to be more meaningful than those determined in accordance with IFRS. I would also like to refer you to the comments regarding forward-looking statements 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 noted. With that, I will now pass the call over to Tim McKay.

Thank you, Corey. Good morning, everyone. Canadian Natural delivered top-tier operational results in the second quarter, as we have robust, long-life, low-decline assets, operational excellence, capital discipline, and the ability to enhance our margins, which delivers sustainable cash flow. The strengths of Canadian Natural's business model were also applied to environmental, social, and governance matters, to deliver industry-leading performance across the board, a significant factor in our long-term sustainability. When it comes to environmental performance, Canada leads the world. Canadian Natural, and indeed, the Canadian oil and gas sector, have delivered game-changing environmental performance. For instance, Canadian Natural has already reduced our overall corporate carbon intensity by 30% since 2012. At Horizon, our intensity is down 38%. As a leading capture and sequester of CO2 in the oil and gas sector worldwide, in just these areas, Canadian Natural has taken the equivalent of over 2 million cars off the road, equivalent to 5% of the entire vehicles in Canada. That is just what Canadian Natural has accomplished. The entire industry has achieved similar, equally impressive results. In our oil sands operations, we can develop technologies, and by using Canadian ingenuity, we can even do better, moving closer to Canadian Natural's aspirational goal of reaching net-zero emissions. Canadian Natural has multiple pathways to achieve net zero with actions identified in the near, mid, and long term. The strength of the Canadian Oil Sands Mining asset, with its long life, low decline, and its manufacturing-like operations, has one of the clearest, if not the clearest route, to net-zero of any global oil asset. Canadian Natural had very strong operational results, achieving quarterly production of 1.165 million barrels of oil equivalent per day, with natural gas production of 1.46 billion cubic feet per day and liquids production of 922,000 barrels per day. During the quarter, we effectively and efficiently reacted to temporarily curtail production and completed maintenance due to low prices while prioritizing high-margin production. As prices improved, we quickly reinstated production cost effectively. Starting with natural gas, overall, Q2 production was 1.462 billion cubic feet per day, an increase from our Q1 production of 1.44 billion cubic feet per day, with North American Q2 natural gas at 1.431 billion cubic feet per day, up from Q1 of 1.407 billion cubic feet per day as we started to execute our plan to add 60 million cubic feet per day of natural gas volumes at less than $3,000 per barrel of oil equivalent per day. We continue to focus on operational excellence, and our Q2 North American natural gas operating cost was very strong at $1.11 per Mcf versus Q1 of $1.24 per Mcf. In the second quarter, Canadian Natural realized a corporate natural gas price of $2.03 per Mcf as a result of our diversified natural gas sales portfolio, of which 49% is used within operations, 32% exported, and 19% exposed to AECO pricing. Our Q2 North American light oil and natural gas liquids production was 82,422 barrels a day, down approximately 7%, primarily due to the company's decision to temporarily curtail production and reduce well servicing activities in the second quarter. Q2 operating costs decreased to $14.41 per barrel versus Q1 operating costs of $15.99 per barrel. Overall, our international assets had a strong Q2 with oil production approximately 44,000 barrels a day, comparable to Q1. Offshore Africa production was 17,444 barrels, up from Q1's approximately 16,000, as expected, due to the planned maintenance program completed in Q1, offset by natural field declines. Our operating costs in Q2 were strong at $7.67 per barrel versus Q1 of $8.83 per barrel. In the North Sea, production averaged 26,627 barrels a day in Q2, down from Q1 of 27,755, primarily due to natural field declines, with strong operating costs of $28.47 per barrel, a reduction compared to our Q1 operating costs of $29.73 per barrel. In South Africa, we are moving the rig and targeting an exploration well in Q3 of 2020. Contingent on results, an additional exploration well could be drilled on the block. Q2 heavy oil production was reduced to approximately 62,500 barrels per day in the quarter versus 88,100 in Q1 as we temporarily curtailed production and reduced well servicing activities related to the low pricing in the quarter. Q2 operating costs decreased to $17.97 per barrel from the Q1 operating cost of $18.68 per barrel, reflecting the company's focus on cost control. A key component of our long-life, low-decline assets is our world-class Pelican pool, where leading-edge polymer flood continues to deliver significant value. Second-quarter production was 55,731 barrels a day, down from the first quarter of 57,986, primarily as a result of reduced well servicing activities in the quarter. Operating costs continue to be very strong at $6.31 per barrel versus Q1 operating costs of $6.18 per barrel. At Pelican, our team continues to drive operational excellence. With our low decline and very low operating costs, Pelican continues to have an excellent netback. Our second-quarter thermal production was 212,807 barrels per day, down from Q1's approximately 228,000. Operating costs in Q2 were $10.13 per barrel versus Q1 operating costs of $11.02. During the quarter, planned maintenance was conducted at Jackfish and in our thermal production areas, where we temporarily curtailed production as a result of the low prices in May. In the second quarter, in the Kirby area, production was approximately 56,000 barrels a day, which includes both Kirby North and Kirby South. The Kirby North ramp-up is ahead of schedule, averaging approximately 43,200 barrels a day, roughly 8% higher than the nameplate capacity of 40,000 barrels a day, a great result by our team. At our Oil Sands Mining operations, we had an outstanding second quarter with record production of 464,318 barrels a day, inclusive of the Horizon maintenance in May, with record low quarterly operating costs of $17.74 per barrel of synthetic crude oil. Our teams continue to capture synergies between the two sites, leveraging technical expertise, services, and operating efficiencies, driving our costs down consistently, with year-over-year hard dollar costs, excluding fuel, down approximately $96 million in the first six months compared to 2019. Our teams are very focused on driving operational excellence. As part of the company's overall strategy to maximize value and enhance margins, during June, we were able to test the Albian mine capability, with an average test rate of approximately 339,000 barrels a day in that period. With the Scotford upgrader targeting to increase capacity to approximately 320,000 barrels a day in Q3 of this year, we are confident we can fill the extra capacity. This additional capacity at AOSP will allow us increased flexibility, margin improvements, and will be managed through the company's curtailment optimization strategy. Work on the commercial engineering for IPEP continues, while the field pilot testing is temporarily delayed as we reduced personnel on our sites due to COVID-19. We will only continue to pilot when it's safe to do so. I will now turn it over to Mark for the financial review.

Thanks, Tim. The second quarter demonstrated the advantages of having a low-cost structure and a unique portfolio of assets with low decline when navigating the low commodity price cycle. Adjusted funds flow was $415 million in the quarter, effectively covering capital expenditures, which were 50% below Q1 2020 levels at $421 million in the second quarter. In addition, we stored a higher portion of our Oil Sands Mining synthetic crude oil and international light crude oil in the low commodity price quarter. The estimated increase in adjusted funds flow would have been approximately $60 million in the quarter had those barrels been sold in June. Liquidity remains strong at the end of Q2, with total availability on our bank lines and cash of $4.1 billion. In the quarter, we increased our $750 million term facility to $1 billion and extended the maturity to 2022. We also retired as scheduled $163 million of our $3.25 billion facility and a $900 million Canadian medium-term note. Because of our operational excellence and solid financial position, we were able to be patient and prudent and obtained attractive pricing when raising a total of $1.1 billion of notes in the quarter, consisting of $600 million of 5-year, 2.05 coupon bonds and $500 million of 10-year, 2.95 coupon bonds. Net debt at the end of the quarter was $22.8 billion, with debt to book capital just over 41%, well below our bank covenant and within the company target range of 25% to 45%. With our low maintenance capital program of $2.7 billion and the ability to keep production flat, we target significant free cash flow in the second half of the year at current strip pricing, which would result in the ending 2020 debt being flat to down from the ending 2019 levels. Our long-life, low-decline assets and effective and efficient operations give us the ability to sustain returns to shareholders over the long term. In March, we increased the dividend by 13%, which is the 20th consecutive year of dividend increases. Due to our ability to generate sustainable cash flow, we maintain the dividend through the low commodity price cycle. Our culture of continuous improvement, our ability to be effective and efficient, and the relentless focus at Canadian Natural in controlling our costs led to the solid financial results in a very challenging and volatile commodity price environment. With that, I'll turn it back to you, Tim.

Thank you, Mark. Canadian Natural's ability to deliver sustainable cash flow is driven by our effective and efficient operations, our high-quality, long-life, low-decline assets that have low maintenance capital and significant reserves that are resilient in a volatile pricing environment. As WTI prices improve, there is even more upside for our shareholders. At strip pricing, we are targeting significant free cash flow in the second half of 2020. Canadian Natural is focused on continuous improvement, and we continue to find opportunities to drive our costs down, working with our service providers, and for 2020, we are targeting significant savings of approximately $745 million. As a result of our effective and efficient operations and the quality of our assets, we have a low free cash breakeven, including all capital expenditures plus the current dividend of approximately $30 to $31 per barrel. Canadian Natural continues to take proactive and effective steps to ensure the health and safety of the people working for us, and we will continue to enhance our COVID-19 program across the company as well as our safety performance. As I spoke earlier, Canadian Natural is on track to achieve our environmental targets, lowering our GHG intensity. As we achieve that target, we will set our next target, continuing to lower intensity as we work toward our aspirational goal of net-zero in the Oil Sands. In summary, we will continue to focus on safe, reliable operations, reducing our GHG intensity, and enhancing our top-tier operations. Canadian Natural is delivering top-tier cash flow generation. With our $2.7 billion capital forecast, we are keeping production stable. We are unique, sustainable, robust, and clearly demonstrate the ability to deliver returns to shareholders by balancing our four pillars. That concludes our Q2 call. I will now open the line for questions.

Your first question comes from Greg Pardy from RBC Capital Markets.

Yes. A couple of questions, but maybe the first one is just on Horizon AOSP. You mentioned 320,000 of the upgrader in the third quarter. Is that capacity? How should we be thinking about the ongoing capacity on the upgrader? And then just the mirror image of that is, are we now talking maybe a $17, $18 kind of operating expense run rate at Horizon AOSP?

Yes. The first question with the AOSP. The expansion is really for the front end. Obviously, we're not the operator of the upgrader. But when they complete their turnaround, the capacity is going to be in the 320,000 range. So what we'll do is ramp it up and see how well it runs in terms of that 320,000. The good part is we have excess capacity to be able to fill it and keep it full. On Horizon, I would say below 2019 is not a bad number. Our teams are really doing an excellent job in terms of both finding enhancements to the operation so that we can increase reliability and get a little extra capacity from time to time, as well as defining operating cost improvements.

Okay. And just related to that, a lot of turnaround activity in the Oil Sands this year. Does that really negate a big turnaround next year?

No. Actually, a part of it, we have the East Tank expansion that we are doing at Horizon. It's still on track. When we do that work, we will be taking an outage in early spring to complete it. So we're doing what I would call a relatively small one this year, with a little bit bigger one in next year when the expansion piece is ready.

Okay. And last one for me, just shifting gears is a pretty large working capital draw over about $1 billion. I'm just wondering, Mark, can you give us an idea maybe of the components of that? And then reversals and/or how much does that really figure into the debt calculation as you're thinking about it?

Yes, sure, Greg. As you know, working capital generally is a timing thing. There are two bigger components. One, of course, is the receivables. When you come out of March and into June, you had certainly different forecast pricing. So when you get paid the next month, you have that draw or that increase in receivables. The other notable one, though, is the draw on payables. That reflects a little bit about how the costs are coming down and the capital has come down. You may not see that reversal there as we continue to control costs. The last thing to consider going into Q3 is the turnaround, as we are doing turnaround, so there will be more capital and things like that, that go along with that.

Your next question comes from Neil Mehta from Goldman Sachs.

And strong operational quarter here. I just wanted you guys to expand a little bit more on the comments in the release where you said your net debt will be flat at 2019 year-end levels by the end of the year at the forward strip. Can you talk a little bit about sort of the assumptions that are going into that pricing, thoughts on capital? And I think you talked a little bit about the working capital side because it would imply a very robust free cash flow ramp-up in the back half of the year.

Yes. I mean, that's kind of a forecast at strip pricing, so taking into account strip WTI. It’s challenging to determine strip differentials, so we're taking a normalized differential over time just because it's so illiquid in the back half to really get an accurate strip differential. The same with strip FX. You do have an FX draw on that compared to 2019 ending levels. But I think it speaks to the sustainability and free cash flow capability of the assets because of their low decline and low capital requirements. As Tim mentioned, we're on track for the $2.7 billion of capital in 2020, so that makes its way through in the second half. It's about prices stabilizing a little bit higher at WTI in the sort of $41 range. That gives us that free cash flow in the second half.

Very clear. The follow-up is just on 2021 capital spending. I think on the last call, you indicated in early looks, if prices stay depressed, it would be plus/minus $3 billion. Obviously, the curve has firmed up nicely here for '21. Any flavor for how we should think about spend? And what do you define as sustaining CapEx now that we've gone through a couple more months of this downcycle?

Yes, Neil, it's Tim McKay here. What we're seeing this last year is a huge volatility and change in demand. So I think right now, it's really too early to speculate. We'll go through our process of assessing all the different projects we have as well as decide on our CapEx. If I see it changing significantly based on current strip pricing, maybe not, but it's just really too early. We'll go through our process and make that decision later with the Board.

Tim, as a clarification, when you say, see it changing significantly, you mean changing significantly from 2020 levels?

Yes, exactly. If we're in the $3 billion range, that would be a likely number. But it's just too early to say. We'll go through our normal process and look at it here. As we've seen this last year, we started off with a $4 billion budget, and that was quickly reduced to $2.7 billion, and we were able to do that while keeping production flat. When we look into next year, we'll go through our standard processes and evaluate opportunities ahead of us to determine what's best for the company at that time.

Will you be doing an open house in November? Again, I guess that will have to be virtual to the extent you are...

Yes. We haven't discussed that at this time, but I would suspect we would.

Your next question comes from Asit Sen from Bank of America.

It looks like you have committed 10,000 barrels a day of the targeted 50,000 barrels a day Keystone optimization expansion that becomes available in 2021. Just wondering if you could talk about similar opportunities that might become available. It looks like Keystone has received U.S. permits to increase exports. Just wondering if you could talk about your thoughts on that.

Well, all I can say is that with those 10,000 barrels a day, we're looking forward to getting access as soon as possible. Our understanding is that they are trying to do that as quickly and prudently as they can. The incremental barrels, I suspect, will go to some kind of open season, but really, that would be a question for TC to answer.

Got it. Tim, I have a follow-up on that. Pipelines have recently been in the news due to various regulatory issues. How are you approaching your risk mitigation strategy in light of the new environment? Any thoughts on that?

Canadian Natural has been very supportive of all different pipeline projects. Whether it's a Keystone base expansion or a Keystone expansion, we've committed 200,000 barrels a day there. For TMX, we have 94,000 barrels a day. We have numerous opportunities to diversify our pipeline piece. My understanding with Trans Mountain is that the construction is going very well, and they're on track for December 2022. Today, I feel positive. TMX will be a good stepping stone, looking strong to be completed on time. Regarding Keystone, it's an interesting situation as it's changing almost daily, so I really couldn't comment further on the Keystone one.

Great. Mark, just a follow-up on your earlier answer. Net debt year-end 2020 being flat year-over-year is unique among global energy peers. You've always talked about the four pillars. Is this now a new strategic goal in this environment, to not let net debt rise in any scenario?

Well, we look at the four pillars, which are fundamental to how we allocate capital and cash flow. In 2020, of course, we have seen the suspension of the buyback program for now as free cash flow is directed to the balance sheet. That has been the case. Also, when you look at the return to shareholder pillar, we've maintained our dividend through the price cycle. We increased it here in March by 13%. I think that's a reflection of the low-cost structure of the asset base, the low-decline nature that allows us to sustain cash flow and free cash flow through commodity price cycles.

Your next question comes from Joe Gemino from Morningstar.

How are you thinking about DAPL and the east leg of Line 5 as it may relate to the EPS capacity for your production?

Yes. The pipelines are always interesting in the news. Obviously, DAPL and the Line 5 are changing very rapidly day-to-day, month-to-month. They are in service and reliable, so we feel comfortable. We don't believe there will be a significant impact from DAPL. Looking at the declines happening in the basin, whether it's in North Dakota or Canada, I don't think DAPL will be really of any significance if something were to happen there. For Line 5, we feel very comfortable with what Enbridge is doing. Everything we've heard from Enbridge is always positive.

Your next question comes from Phil Gresh from JPMorgan.

A couple of very quick follow-up questions for you. First, regarding the Oil Sands Mining segment, I know it's already been asked about AOSP, but just overall, the Oil Sands Mining business had 464,000 barrels a day of production this quarter. Taking that performance into account, as well as the capacity increase at AOSP, how do you think about the total capacity or production potential across both assets looking ahead to 2021?

I think it is increasing incrementally. Before looking ahead into next year, we have a bigger outage on Horizon. That piece could be relatively flat year-over-year in terms of volume. AOSP, with the work being done this year, has delayed the further expansion to 2022, so I suspect AOSP will actually be up year-over-year. These are great assets, and our teams are focused on finding incremental gains. Our capability is increasing, and reliability is quite high and well above expectations. There is opportunity, but our teams are doing a fantastic job of finding those opportunities.

If I were to think of 2Q as a new run rate, when there's not maintenance, is that a reasonable way to look at things?

Yes. The Q2 results show how well our teams can run the facilities. We did the pigging maintenance at Horizon in May. When you account for that, it was a fantastic quarter. Once you accomplish that, you'll aim to repeat it, and that's what our goal is, to achieve similar results when we don't have maintenance every quarter.

Just one more debt question. Sometimes you guys will give a leverage ratio target for year-end. Obviously, you gave the net debt aspect of that. Just curious if there's a specific ratio you're thinking that would imply?

Well, I think it would imply a higher leverage ratio than 2019, based on commodity prices in 2020. So I'll leave it at that.

Our next question comes from Manav Gupta from Crédit Suisse.

I wanted an outlook from the WCS differential. It's been widening a little here. Just wanted your thoughts into year-end. On the last conference call, you talked about apportionments being very low and you were spot on. Could you provide your near-term outlook on the apportionments on the pipelines as well?

Sure. It's Tim McKay here. Regarding apportionment when looking ahead here, between maintenance and what's reduced in the market, we believe that apportionment will be relatively low going into the third quarter. For the fourth quarter, it will depend mostly on pricing at that time. Q4 could be similar, maybe a little higher in terms of apportionment as turnarounds are completed in various areas. As for WCS, it's at 22% today. It's always an illiquid market. We think anywhere from that 22% to 30% is probably right for the third and fourth quarter. But, again, it will really depend on pricing and what comes back to the market. We feel confident that apportionment for the third quarter will be low, but might increase a bit toward year-end.

You are doing some turnaround on the Horizon and AOSP side. Should we assume that in the third quarter, we should see an increase from Jackfish and some of your other heavy production to offset the turnaround at Horizon and AOSP?

Yes, exactly. You'll see that we will increase thermal production as we ramp up Primrose and Jackfish, then obviously, as we come off the turnarounds at both AOSP and Horizon, they will decrease.

Your next question comes from Amir Arif from Cormark Securities.

Sorry, can you hear me?

Yes, we can.

Okay. Just a couple of quick questions for you. Just on the gas side, given the strength we're seeing in the '21 strip, how many more productive adds do you have in your inventory in terms of low capital efficiencies, talking about $3,000 per flowing?

Well, obviously, the $3,000 per BOE/d were the kind of the cream opportunity. So we have more opportunities probably between that $3,000 and $5,000 per BOE/d. We always find other opportunities within our portfolio that our teams explore, continuously improving. I wouldn't want to say how much more today, but they are always working to enhance.

Could you provide an update on the Septimus gas flood that you had initiated?

Yes, regarding Septimus, we moved the compressor into an Alberta area for that pilot. Currently, it's on hold due to stronger gas pricing and lower liquids prices, so it didn't make sense to continue that pilot at this time, as we are preserving capital. We will consider that during our budget process moving forward. The Septimus project worked exactly as we intended, and it's another lever we can pull for our company in the future.

With the AOSP expansion, is there any meaningful change or any change on the quality of the upgraded product coming out with the expanded volumes?

Yes. It's actually in two steps. The first step is just increasing the front end. So there will be a little more heavy oil coming out of the upgrader after the expansion. In 2022, they will do another piece of expansion on the backside of the plant, which will yield more synthetic crude oil. It's a two-step process, but since we're not the operator, we will see how the first step performs.

If you look at the 5-year strip, thinking about a $45 to $50 environment, how does the international segment fit into the corporate profile?

Very well. It's a free cash generator. We have exploration opportunities in CDI where we could increase production. It's just another opportunity within our portfolio we can activate when the timing is right. The international operations have provided almost $5 billion of free cash flow from those properties since we’ve owned them, making it a valuable component of our company.

When can we expect the results from that South African exploration well that you're spudding next quarter?

The operator is moving the rig, and I would expect maybe in Q4, around year-end.

The operator is moving the rig, and I would expect maybe in Q4, around year-end.

Thank you, operator, and thank you, everyone, for attending our conference call this morning. Canadian Natural's large, well-diversified asset base continues to drive significant shareholder value. The ability of our teams to deliver effective and efficient operations with top-tier performance is contributing to substantial and sustainable free cash flow throughout the business cycle. This, together with effective capital allocation, contributes to achieving our goal of maximizing shareholder value. If you do have any further questions, please don't hesitate to give us a call. Thanks, and goodbye.