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Good morning. My name is Joanna, and I will be your conference operator today. At this time, I would like to welcome everyone to the MEG Energy 2020 Second Quarter Results Conference Call. [Operator Instructions]Thank you. Mr. Derek Evans, CEO. You may begin your conference.
Thank you, Joanna, and good morning, everyone, and thanks for joining us to review MEG's Q2 2020 operating and financial results. I have on the line with me Eric Toews, our CFO; and Lyle Yuzdepski, our General Counsel and Corporate Secretary. Just a reminder that this call contains forward-looking information. Please refer to the advisories in our disclosure documents filed on SEDAR and on our website. I'd like to start the call by taking a few seconds to express my thanks and gratitude for all the support that we've received from so many different areas as we've navigated our COVID experience. First and foremost, I want to thank our staff for all that they've done and continue to do to ensure the health and safety of their teammates as well as the safe and reliable operation of the Christina Lake facility. I also want to acknowledge, in addition to the new and challenging work environments at sites and in Calgary, our staff have made major contributions to our business cost reductions, having taken significant reductions in their base salaries and their long-term compensation, while stepping up to take on additional responsibilities as a result of our recent organizational review. If they were on this call, they would want our investors and other stakeholders to know that they're doing everything they can to help ensure that we all get through these challenging times together so that we can continue to grow and thrive. Our contractors and suppliers have shown up in a significant way throughout this crisis as well. They've stepped forward at this critical time to play an essential role and to be part of the solution. We appreciate all the support we have received. Finally, I would also like to acknowledge the support we've received from the federal, provincial and municipal governments that we work with. Thank you for the meaningful programs you put in place to support us through these challenging times. It is appreciated and never taken for granted. MEG continues to proactively respond to the safety and financial challenges associated with the COVID-19 pandemic and remains committed to ensuring the health and safety of all of its personnel and the safe and reliable operation of the Christina Lake facility. Second quarter was characterized by extreme negative movements in commodity prices, coupled with unprecedented uncertainty regarding near-term crude oil supply demand balances due to COVID-19. Our team continued to react quickly during the quarter to protect MEG's financial liquidity by voluntarily curtailing production, making additional cuts to our capital budget and further reducing G&A and nonenergy operating costs, all of which were supplemented by our strong hedge position, allowed -- which allowed MEG to exit the quarter with an undrawn revolver and $120 million of cash on hand. On May 4, 2020, as a result of the negative and uncertain commodity price environment at the time, MEG reduced full year 2020 capital investment by an additional $50 million to $150 million or 40% below our original guidance of $250 million. Approximately 75% of the aggregate $100 million capital reduction in the year was associated with future bitumen production. MEG also reduced nonenergy operating costs and G&A expense guidance by $20 million and $10 million, respectively. During the quarter, a decision was made to roll back salaries across the company with an emphasis on board, executive and senior leadership compensation. Effective June 1, 2020, Board members received a 25% base cash compensation reduction. As President and CEO, my annual base salary was reduced by 25%. Chief Operating Officer and Chief Financial Officer each took a 15% annual base salary reduction. Vice Presidents received a 12% annual base salary roll back and all other employees received a 7.5% annual base salary roll back. In addition, the value of the target 2020 long-term incentive awards issued to employees and directors on April 1 were reduced by 20%. All of these actions are entirely consistent with ensuring that we lived within our cash flow and did not impair our financial liquidity. I would like to touch on some of the financial and operating highlights of the second quarter. In the quarter, we produced 75,678 barrels per day of bitumen. Production was impacted by planned turnaround activities, where the timing was advanced to June from September and where the scope and duration of the turnaround was expanded relative to the original budget. Turnaround is expected to be longer in duration, with completion expected by mid-August, while being undertaken at a lower total cash cost by relying on internal resources. This allows the company to take advantage of the current low oil price environment by reducing turnaround requirements in 2021. Our continued focus on cost reduction generated net operating cost of $6.14 per barrel, including nonenergy operating costs of $4.09 per barrel and record low G&A cost of $1.29 per barrel. Free cash flow of $69 million in the quarter was driven by adjusted funds flow of $89 million or $0.29 a share and disciplined capital spending of $20 million. Cash on hand grew by $58 million from Q1 to $120 million at quarter end, benefiting from a $215 million realized gain on commodity risk management at the quarter. At the end of Q2, MEG's $800 million modified covenant-lite revolver remained undrawn. On May 4, MEG suspended full year 2020 production guidance due to the global oil price environment at that time, which was experiencing multi-decade lows, coupled with extreme levels of volatility, driven primarily by the unprecedented demand shock due to COVID-19. Since that time, crude oil price levels and volatility have stabilized to a level that allows the corporation to reinstate full year production guidance, which is now targeted at 78,000 to 80,000 barrels per day. Guidance for nonenergy operating costs, G&A expense and capital expenditures remain unchanged from the revised guidance announced on May 4, 2020. MEG remains well positioned from a financial liquidity perspective, benefiting not only from its 2020 hedge book and the term and structure of its outstanding indebtedness and credit facility but also from the low decline, low-cost structure of its high-quality Christina Lake asset. Company's earliest long-term debt maturity is approximately 4 years out, represented by USD 600 million of senior unsecured notes due March 2024. None of the corporation's outstanding long-term debt contain financial maintenance covenants. Additionally, MEG's modified covenant-lite $800 million revolving credit facility has no financial maintenance covenants unless drawn in excess of $400 million. At current strip pricing, we expect to exit the year with cash on hand and to be one of the few companies that has reduced its debt by over $100 million in 2020. As the pandemic continues to evolve, we'll remain nimble and agile with respect to the execution of our sustainable business model that generates material free cash flow supported by our low decline and low-cost structure at Christina Lake. In conclusion, we remain committed to sustainable, innovative and responsible energy development, and we'll continue to drive efficiencies in our business from a financial, operational and cost perspective.With that operator, we will open the line for questions.
[Operator Instructions] The first question comes from Phil Gresh from JPMorgan.
First question is just your latest thoughts around sustaining capital needs for the business just to maintain the 80,000 barrels a day on a go forward? And then if you were to try to ramp that back to 100 kBd at some point, how do you think about the capital required to do that?
Sure. Phil, I think we -- it's early days for us, as we're starting to really put the pen to pencil -- or pen to the paper with respect to what our capital should look like for 2021, which should be a very good proxy of sustaining capital required to hold production at that 85,000 barrel a day range. At this juncture, we think that's about $250 million, give or take. And as we think about additional capital that would be required to take production from 85,000 back to 100,000 barrels a day, we think that at this point, it's somewhere in the neighborhood of an additional $150 million.
Okay. Great. Very helpful. And then second question would just be with the additional pipeline capacity to the Gulf Coast in the second half of the year, and with where Canadian production is and your view on apportionments, how much of that capacity do you think you'll be able to utilize in the second half? Would it be the full amount or something less?
At this juncture, I'd say we're not planning on moving our own proprietary volumes down through the line. We'll probably -- we utilized about 70% of the line for our own volumes, and we will undertake sort of what we would consider to be or call buy and sell agreements to utilize the remaining 30% of the lines' capacity.
The next question comes from Emily Chieng from Goldman Sachs.
My first question is just around what the extended scope of work is being undertaken this year during the Phase 1 and 2 maintenance activities that sort of eliminates the need for turnaround activity in 2021?
It's -- what we've done is we've taken 2021's turnaround and moved it, effectively, into 2020. So turnarounds on HRSG and the GTG have been moved up. We pulled those units apart and have gone into do sort of the, what I would call the 5-year annual inspection type work that needs to be done on those units. We've done it a year early. And I'm happy to say that the turnaround is on time and on budget with very, very little sound work at this point.
Great. And just my follow-up is around WTI:WCS differentials. So they do remain quite tight. I guess the question is, what are you seeing in terms of production across the broader industry? And how quickly that's ramping back from 2Q trough levels? And then perhaps the second part is just around what you're seeing in terms of U.S. Gulf Coast heavy pricing as well?
So we've seen -- well, Western Canadian production, especially heavy production, there's still -- we're not the only party or company that's down on turnaround. And I think large part of the tightness in the differential that you're seeing today is being driven by that lack of production that's on. As you know, the Enbridge apportionment came in for August at 7%. So it would -- that's a great sort of harbinger of how tight the market is or the lack of supply fundamentally at this point in time. Interestingly enough, in the discussions that we do have with refiners, both in PADD 2 and PADD 3, we see some concern about supply over the long term. And we see -- as a result, we've seen very tight dips in PADD 2, but in the U.S. Gulf Coast, we're also seeing, I would call, lower-than-normal differentials at this point in time for our particular product, which is AWB.
The next question comes from Greg Pardy from RBC Capital Markets.
Actually, there's a bunch of good questions that have already been asked. But Derek, maybe the hedge book is in great shape this year, and you guys got after that very, very quickly back in December, January. How are you thinking about hedging in 2021?
So Greg, it's a great question. And it's something that as we sit and we try and figure out the capital program that we want to bring to the table, which obviously our desire at a minimum would be to have a capital program that allowed us to sustain production at 85,000 barrels a day. And in even sort of, better world, where commodity prices generated the cash flow where we could start the journey back to 100,000 barrels. We continue to watch the forward strip, and it's continued to march up. I think yesterday, 2021 looked like about $43. It's starting to get into a range where we're looking at a variety of different instruments that we could use to ensure that we had the cash flow certainty to put a program of that magnitude and size. I'd say we're getting closer to making a decision in that regard. But up to this point in time, the volatility in terms of crude prices -- which are now starting to dampen out. And fundamentally, what that supply-demand relationship was going to look like across the world with respect to COVID, we've seen things sort of normalize. But we're concerned about the second wave and the impact that could have on production or oil demand at some point in time. So I'd say we're being very cautious. We're watching very closely, and we know that our objective needs to be from the hedging program, something that will provide us with a high level of certainty to undertake a capital program that would sustain production.
Okay. Great. No, that's helpful. But nothing in place yet, Derek, right, for 2021?
There is -- there's a few condensate hedges in place, but nothing on the WTI or on the differential side.
Okay. So the second one, I'm going to change it up just a little bit, and it's not necessarily a plain normal question per se. You've got additional kit now in the Gulf Coast with your storage. You've reexported to China. You've indicated that there's kind of the supply gap going on in the Gulf Coast. Are -- is there any interest do you think on the part of refiners, Gulf Coast refiners to get into longer-term supply arrangements where -- especially now given that you've now doubled your capacity on Flanagan? Or is this something where they just want to continue to buy spot?
That's a very good question. I would say on the margin that we're seeing more interest in longer-term arrangements than spot arrangements. And I think that fundamentally talks to not only the tightness in the market today, but the perceived tightness in the market on a go-forward basis.
The next question comes from Manav Gupta from Crédit Suisse.
You have some capacity on TMX expansion. Can you talk about that? And also what are the prospects of lines, when do you actually see that line coming on?
Sure, Manav. The -- we have 20,000 barrels a day on TMX. And we're quite excited that there's multiple construction spreads actually putting pipe into the ground on TMX. We see TMX coming on, on late 2022 and adding somewhere in the neighborhood of 590,000 barrels to the market. So we're excited about the fact that it's actually being built and that, that capacity will be available to us in late 2022.
And second question was during 1Q, the condensate prices were a major headwind to bitumen realization. I'm trying to understand during 2Q was they still a headwind, was they a tailwind, or were they absolutely of no consequence? And how do you look at the condensate pricing and the 3Q realization?
I want to say it's a little bit of everything that you described. So if we break it down by month, April and May, we still had high condensate prices, but we found that we were also in an environment where WTI was improving. And by the time we got to June, if you looked at the actual data for June inside of our books, you'd see that our condensate price was effectively 0 because of the small differential and the fact that the condensate that we bought in April and May to blend in June and sell was at a much lower price than what we -- where WTI was in June. So I'd say the beginning of the quarter, it was a bit of a headwind. And by the end of the quarter, it was a full-on tailwind.
Mr. Gupta, are you finished with your questions?
Yes.
Your Next question comes from Joe Gemino from Morningstar.
How sustainable are the nonenergy operating costs that you reported this quarter and in your guidance?
So Joe, that's a great question. And the -- both our G&A costs and our nonenergy operating costs are impacted by the federal program, the Canadian Emergency Wage Subsidy. So I hope that those aren't going to be recurring costs because if they are, well, then we've got much bigger issues to deal with. But I'd say if you look at the sort of cost savings that we've talked about or reductions, sort of $20 million on operating costs and $10 million on G&A, I'd say half of those savings are sort of -- will be recurring on a go-forward basis.
There are no further questions. I will now turn it back over to Derek Evans for closing comments.
Thank you, Joanna, and thank you all for joining us this morning. As always, please do not hesitate to reach out to us if you have any questions, more detailed modeling questions. We're always happy to touch base and answer any and all questions. I appreciate all of you joining us this morning, and we hope that you're all health and safety -- you're all well and safe. Take care.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.