MEG Energy Corp

TSX:MEG

Earnings Call Transcript 2021-Q1

[Operator]

Good morning. My name is Colin, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the MEG Energy 2021 First Quarter Results Conference Call. [Operator Instructions] Thank you, Mr. Derek Evans, CEO, you may begin your conference.

[Derek W. Evans, President, CEO & Director]

Thank you, Colin, and good morning, everyone, and thank you for joining us to review MEG Energy's first quarter operating and financial results. In the room with me this morning are Eric Toews, our Chief Financial Officer; Chi-Tak Yee, our Chief Operating Officer; and Lyle Yuzdepski, our General Counsel and Corporate Secretary. I'd like to remind our listeners that this call contains forward-looking information. Please refer to the advisory in our disclosure documents filed on SEDAR and on our website. I'll keep my remarks brief today and refer listeners to yesterday's press release for more detail. MEG continues to proactively respond to the safety challenges associated with COVID-19 and remains committed to ensuring the health and safety of all of our personnel and business partners and the safe and reliable operation of the Christina Lake facility. The screening procedures and protocols implemented by the company's COVID-19 task force during the first quarter of 2020 continue to be enhanced to ensure continued safe and reliable operations. Flexibility and adaptability continue to be integral to the company's response to the pandemic. We continue to monitor the developing COVID-19 situation to determine what, if any, additional measures might be needed to be taken to ensure the health and safety of our people remain a top priority. I want to commend our teams for their outstanding diligence and focus that they have exercised in helping to ensure the health and safety of all of our employees and contractors. MEG had a strong first quarter from both a financial and an operating perspective. On the financial side of the business, we benefited from both the strength in the global oil market dynamic as well as the structural improvement in heavy oil differentials. We remain very constructive that these changes will persevere and the headwinds that we've battled over the last 6 years with respect to egress and weakness in oil prices will abate and become tailwinds that will continue to drive significant free cash flow from our low decline and low cost business. On the operational front, we've now had 2 solid quarters of strong production performance at full capacity post our extended 75-day turnaround in the summer of 2020. This has given us the confidence to increase our production guidance from a range of 86,000 to 90,000 barrels a day to 88,000 to 90,000 barrels a day. 2020 turnaround was extended to bring forward 2021 turnaround activities and eliminate the need for a turnaround this year. The elimination of a 2021 turnaround has been extremely helpful in managing the number of people at site from a COVID-19 perspective and the health and safety of our employees and contractors. Our strategy remains unchanged. We remain focused on executing on our capital program as efficiently and as effectively as possible, continuing to work on all our cost structures and using free cash flow to reduce debt. First quarter financial and operating highlights include: adjusted funds flow of $127 million, impacted by a realized commodity risk -- price management risk loss of approximately $69 million; quarterly production volumes of 90,842 barrels per day at a steam-oil ratio of 2.37; net operating costs of $5.25 per barrel, including nonenergy operating costs of $4.05 a barrel. In that quarter, power revenue offset energy operating costs by 72%, resulting in a net impact of $1.21 per barrel. We successfully refinanced USD 600 million of existing indebtedness at a coupon of 5.78% due February 29, which pushed out the earliest outstanding long-term debt maturity to 2025. Total capital investment of $70 million in the quarter was directed to sustaining and maintenance capital, resulting in $57 million of free cash flow in the quarter. We exited the quarter with $54 million of cash on hand and our $800 million modified covenant-lite revolver essentially undrawn. MEG's bitumen realization averaged $52.34 per barrel in the first quarter of 2021 compared to $38.64 per barrel in the fourth quarter of 2020. The increase in average bitumen realization was due to a higher WTI price quarter-over-quarter. Offsetting the increase in bitumen realization during the first quarter of 2021 compared to the fourth quarter of 2020 was a realized commodity risk management loss of $8.80 per barrel in the first quarter of 2021 compared to a realized commodity risk management gain of $1.31 per barrel in the fourth quarter of 2020. This reflects stronger WTI settlement prices compared to WTI fixed-price contracts put in place in late 2020. [ The ] corporation's cash operating netback averaged $26.03 per barrel in the first quarter of 2021 compared to $18.66 per barrel in the fourth quarter of 2020. Increased cash operating netback drove the increase in the corporation's adjusted funds flow from $84 million in the fourth quarter of 2020 to $127 million in the first quarter. For the last 9 months of 2021, MEG has outstanding benchmark WTI fixed price hedges and enhanced WTI fixed price hedges with sold put options for approximately 37% of forecast bitumen production at an average price of USD 46.20 per barrel. No new WTI fixed-price contracts have been entered into since mid-January 2021. As previously mentioned, based on better-than-expected production performance in the first quarter, MEG is revising its full year 2021 average production from 86,000 to 90,000 barrels a day to 88,000 to 90,000 barrels a day. Due to increased apportionment on the Enbridge Mainline, we're revising downwards our expected sales into the U.S. Gulf Coast via the Flanagan South/Seaway Pipeline Systems from approximately 2/3 to a full year average AWB blend sales volumes to approximately 50%. As a result, MEG is revising down its estimated full year 2021 transportation cost from USD 7.75 to USD 8.25 per barrel of AWB blend sales to a range of USD 6.75 to USD 7.25 per barrel of AWB blend sales. As I bring my remarks to a close, I again want to thank our team at MEG for their commitment and perseverance through these exceptionally challenging times. MEG's performance continues to demonstrate our resilience, and I'm proud of our performance and confidence in our ability to continue this momentum throughout 2021. Looking ahead, we're confident in our ability to execute on our business plan and remain committed to sustainable, innovative and responsible energy development. We look forward to updating you on our progress in the coming quarters. With that, we'll now open the line for questions.

[Operator]

[Operator Instructions] Your first question comes from Phil Gresh from JPMorgan.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

Derek, first question for you would just be on the takeaway situation and your revision to the percentage you're planning to send down to the Gulf Coast this year due to apportionment. Just wanted to get your broader thoughts, just how you think apportionment and takeaway will play out as we exit the year and into next year?

[Derek W. Evans, President, CEO & Director]

Great question, Phil. I'm going to ask Eric Toews to take that one.

[Eric Lloyd Toews, Chief Financial Officer]

Phil, the reason we took down our -- the amount of barrels we think we're going to move the Gulf Coast is simply mathematics. When we put out our budget in early December, we expected apportionment to be around 35% for an average for 2021. What we've seen through this first part of 2021 is about a 10% to 15% higher level than that. And so simply mathematically, with high apportionment less barrels get taken down the Flanagan Seaway pipeline. I mean we sell less down there now. As it relates to what we see going forward, we expect that apportionment level to go down to that sort of 10% level, plus or minus, once Line 3 comes on. And I think the general view is that it comes on in late Q3 or early Q4. We are aware of the ongoing legal challenges to that, but I think Enbridge has trod that ground pretty well over the past. So we expect that that pipeline comes on in that timeframe, so -- and then we'd see that level mitigate. So obviously, the amount of barrels we move to the Gulf Coast in the back end of the year, if Line 3 -- if that proves to be true when it comes on, you should expect to see our barrels ramp back up till we get down that pipeline.

[Derek W. Evans, President, CEO & Director]

Maybe, Phil, I could just add 2 quick reminders. I know people -- or I hope people remember that even though we do not move those barrels, or cannot move those barrels, that there is no take-or-pay on those barrels. Those barrels -- the cost of moving those barrels is not incurred. Those barrels just get moved to the end of our contract. And I guess the other thing, I'd just point out that there has historically been a negative price associated with high apportionment levels. That is not the case with the apportionment levels that we're seeing today. In fact, we can show you that in months such as February of this year when the post apportionment barrels, i.e., the barrels that had to be turned back from the line, actually sold at a premium to the pre-apportionment barrels. So I guess the long and the short here is that although apportionment levels are high, we're not seeing what we would have seen previously in terms of higher differentials.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

Sure. And I guess just to follow-up. As you look at, say, 2022, and assuming Line 3 is on relative to your 100,000 barrels a day of potential takeaway, I mean would you -- do you think that the production environment would be such that you'd be able to fully utilize that in 2022 in a full Line 3 case?

[Eric Lloyd Toews, Chief Financial Officer]

Yes. Phil, it's Eric. We think that that apportionment level that we talked about for the back end of the year sort of carries through 2022 when you factor in what production may come on in 2022.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

Right. Okay. Okay. Just one other quick one for me. Your nonenergy OpEx costs were quite solid in the quarter and well below full year guidance. So maybe you could just share your thinking there on how that would progress? Like is there something specific that would make the nonenergy OpEx per barrel be going higher the rest of the year, or is it just some conservatism since it's still early?

[Derek W. Evans, President, CEO & Director]

Our nonenergy operating costs tend to typically be -- if we look across the year, they tend to be the lowest. And then they grow as we bring in sort of more maintenance-type activities through Q2 and Q3 through the summer months. We try and minimize the amount of work we do outside in the cold in the winter, and as a result it's -- the operating costs in the first quarter tend to be a little bit lower than an on average. We do not see any reason to change our operating cost guidance at this juncture.

[Operator]

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

[Greg M. Pardy, MD & Co]

Derek, you commented on your production rates being in great shape here, right, for a couple of quarters, which has caused you to change your guidance. But what are the main drivers then of keeping those rates higher than what you might have expected?

[Derek W. Evans, President, CEO & Director]

I'm going to ask Chi-Tak Yee, our Chief Operating Officer, to take that question.

[Chi-Tak Yee]

Yes. Greg, one of the main things for the first quarter is we have a very high reliability performance at the plant, [ where ] we typically at about 97% type of reliability, but first quarter is about 98%, 99%, so that really helped. And also, as Derek talked about earlier, the turnaround we did last year, the 75-day turnaround, we put everything in good shape, so we've been able to get that type of reliability, and also we've been doing a little bit optimization of the existing production as well, and that was translating into a better than expected performance in Q1. And we'll be able to expect that momentum will carry through Q2 and the rest of the year.

[Greg M. Pardy, MD & Co]

Okay. Okay. Terrific. And it's -- just related to everything you've said around pricing and diffs and production rates, it's kind of a question for Eric, I guess, is -- cash obviously sitting at $54 million, but what's the path of that you would see through the next 3 quarters? I mean we've modeled it, but I'm curious as to what you see coming.

[Eric Lloyd Toews, Chief Financial Officer]

I guess the only way to answer that, I guess, when you look at the -- Derek talked about the hedging loss we had in the quarter. That dissipates as we move through the year, as you can see from our table on the hedging, barrels we have hedged. So I think when you model WTI and if you keep the diffs, we think diffs for the rest of the year are in that sort of $11 to $12 range, WCS diffs. Gulf Coast has obviously been very tight. We don't see that changing for the rest of the year. So as the back end of the curve has moved up here, I think you should expect to see higher cash flow in each quarter as we move through the year, at the current strip pricing.

[Operator]

Your next question comes from Neil Mehta from Goldman Sachs.

[Unknown Analyst]

This is Carly on for Neil. The first one is just kind of around the balance sheet, which has been a big focus for you guys. So can you just talk a little bit about how you're thinking about the path of debt reduction and kind of what you view as the optimal leverage level on a sort of normalized basis going forward?

[Eric Lloyd Toews, Chief Financial Officer]

Yes, sure. The first part, I guess, every -- I think, as Derek said in the start of the call, all the free cash flow right now is going to go towards debt repayment. That's basically what we've been doing for the last number of quarters or number of years. The second question is, we've talked about sort of a USD 1.75 billion to USD 1.85 billion level of debt on a sort of first stopping off basis, and that's about 2.25x to 2.5x debt-to-EBITDA multiple. And based on the quality of the asset and the sort of low decline rate, we think that's an acceptable first stopping off level. So that's about another USD 500 million of debt reduction that we have targeted. Our intention wouldn't be to stop there, but that's our first stopping off point from a leverage reduction perspective.

[Unknown Analyst]

Great. Super helpful. And then the follow-up is just around hedging. Commodity prices have recovered quite nicely here. So can you just talk about how you're thinking about the hedge book moving into the end of the year and into 2022?

[Derek W. Evans, President, CEO & Director]

Yes. The -- we haven't put on any new WTI hedges since very early in 2021. We haven't looked to 2022 yet. We obviously need to work through our capital budget. We're -- we've seen the strip like everyone else has. As of right now, we haven't put any 2022 hedges on, but we'll consider that as we move through the back end of this year, and whether or not we do that from a sustaining capital preservation perspective.

[Operator]

Your next question comes from William Lacey from ATB Capital Markets.

[William J. Lacey, Research Analyst]

Derek, you've been pretty acutely focused on the whole issue of carbon, and the government of Canada with their announcement in the budget, it was notably vague, and obviously it's evolving. Just wondering what you would be looking to see from, I guess, both the federal and provincial governments, in terms of policies, incentives in order to encourage investment in CCUS and the other sort of related technology?

[Derek W. Evans, President, CEO & Director]

Will, thanks for the question. We've -- MEG's been a leader in reducing the intensity of carbon on a per barrel basis, utilizing our eMVAPEX, our eMSAGP and our -- the cogen facilities that we've put in the field. And I think a number of years ago, we realized that there was still some work to do there, but that ultimately -- that carbon capture and storage was going to be the way that we decarbonized our barrels. We have been looking to both the federal and the provincial government to support that idea, not only in terms of coming to the table with some level of fiscal support to help put in place the facilities to enable that, but also from a regulatory and a pricing perspective. We can't continue to work in a -- you can't put capital to work on carbon capture and storage until you know that every time the provincial government changes that your carbon regulations are going to change or that federal provincial jurisdiction is still under sort of a question. That, of course, as you know, has been sorted out by the Supreme Court here recently. I think what we were looking for in the budget was a much stronger sign of support from the federal government. We saw it in 2 fronts, in terms of an incentive that is currently going to be worked on, income tax incentive, that could be transferable, and we think that held some promise. That's very similar to what the 45Q program is in the United States, which is up to about USD 80 a barrel of carbon now. As well as we'd be looking for some sort of certainty, obviously, that the carbon regulations aren't going to change. We haven't seen that. We saw sort of $319 million, I think, of R&D type expenditure. So we'll continue to work with both levels of government. We believe both levels of government are interested and trying to find a path to get carbon capture and storage going. Obviously, we're not spending any money on this. We're spending a lot of time trying to figure out how and what is the best way to navigate this carbon capture and storage on a go-forward basis. But it is the single biggest lever that we have as an industry to pull to put carbon away, and it's absolutely critical to find a way to make that happen. And it's not something that MEG can do on its own, it's something that our industry, the oil sands industry, needs to find a way to collaborate on and with the assistance of both the provincial and the federal government.

[Operator]

[Operator Instructions] We've got a question from Menno Hulshof from TD Securities.

[Menno Hulshof, Research Analyst]

Derek, on the last call you talked about potentially taking capacity to 100,000 barrels per day at a capital efficiency of -- I believe it was around 15,000 per daily flowing if you believed that oil prices were supportive. Have your thoughts evolved at all since the -- on that front since the last call?

[Derek W. Evans, President, CEO & Director]

It's -- yes, our thoughts continue to evolve on that. Obviously, we've seen some good strong performance in the first quarter. I think a large part of whether we would put any capital back to work is really predicated on the strength and lack of volatility that we would want to see in terms of the WTI oil price and obviously the differential. I think we're very encouraged by what we've seen, but obviously we're not ready at this point in time to put additional capital to work, but we're reevaluating that on a quarter-by-quarter basis.

[Operator]

There are no further questions at this time. Please proceed.

[Derek W. Evans, President, CEO & Director]

Well, thank you very much, everyone, for joining our call today. I appreciate it's going to be a busy day. I hope everyone has a good one, and we look forward to updating you on our continued progress at our next quarterly conference call. Take care.

[Operator]

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.