© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good morning. My name is Colin, and I'll be your operator today. At this time, I would like to welcome everyone to the MEG Energy 2020 First Quarter Results Conference Call. [Operator Instructions] Thank you. Mr. Derek Evans, CEO, you may begin your conference.
Thank you, Colin. Good morning, everyone, and thanks for joining us to review MEG's first quarter 2020 operating and financial results. I have on the line with me, Eric Toews, our CFO; Chi-Tak Yee, our Chief Operating Officer; and Lyle Yuzdepski, our General Counsel and Corporate Secretary. This is the first time that we've not all been in the same room together while hosting this call. So please bear with us through any technical challenges. 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. Past few months have delivered unprecedented challenges. The COVID pandemic associated demand distraction and resulting impact to oil prices has created real challenges to the health and safety of our employees and to the short-terms viability of our business. MEG is responding proactively to the safety and financial challenges associated with the COVID-19 pandemic. At this time, only a essential staff are working at our sites and offices in accordance with social distancing measures, with the vast majority working at home. We are taking measures to ensure the safety of all of our employees by following the guidance of provincial and federal health officials, mandatory self-quarantine policy, travel restrictions, screening and enhanced cleaning and sanitation practices. The current business environment demands swift, decisive actions to enhance MEG's already strong financial liquidity position. To that end, we're reducing production to minimum levels and advancing the planned plant turnaround, cutting capital by $100 million versus original guidance and reducing nonenergy operating and G&A guidance by $20 million and $10 million, respectively. MEG remains well positioned from a financial liquidity perspective, benefiting not only from its significant 2020 hedge book, 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. I'd like to touch on some of the financial and operating results highlights from the first quarter. On January 16, we refinanced USD 1.2 billion of existing indebtedness, and concurrently, utilized cash on hand to repay an additional CAD 132 million of long-term debt. The combination of these transactions is neutral to ongoing cash costs and results in no outstanding debt maturities before 2024. Free cash flow for the first quarter was $24 million, driven by adjusted fund flow of $78 million, a disciplined capital spend of $54 million and a realized commodity price risk management gain of $106 million. At current strip pricing, the full year 2020 value of MEG's commodity price risk management hedge positions, including $106 million realized gains, is estimated at $525 million and will provide strong financial liquidity through the remainder of the year. MEG exited the first quarter with $62 million of cash on hand after making a debt repayment of $132 million in the quarter. Based on the current commodity price environment, MEG does not expect this level of cash on hand to materially change in the second quarter of 2020. Subsequent to our quarter end, a decision was made to rollback salaries across the company with an emphasis on Board, executive and senior leadership compensation. Effective June 1, 2020, Board members will receive a 25% cash compensation reduction. As President and CEO, I'll have my annual base salary reduced by 25%. Eric Toews, CFO; and Chi-Tak Yee, our COO; will each take a 15% annual base salary reduction. Vice Presidents will receive a 12% annual base pay salary rollback, and all other employees will receive a 7.5% annual base salary rollback. In addition, the value of the 2020 long-term incentive awards issued to all employees and directors on April 1 were reduced by 20%. On May 10, 2020, MEG reduced its full year capital investment by 20% to $200 million from original guidance of $250 million. Notwithstanding the corporation's strong hedge position, in light of the current weak oil price environment and MEG's focus on maintaining its liquidity, MEG is further reducing it's 2020 full year capital investment by an additional $50 million to $150 million, of which $125 million will be directed towards sustaining and maintenance activities, including approximately $25 million related to plant turnaround activities at the Corporation's Phase 1 and 2 facilities scheduled to begin in early June 2020. Relative to the original budget, the turnaround is expected to be longer in duration, with completion expected in August, while being undertaken at a lower total cash cost by relying on internal resources. This allows Corporation to take advantage of the current low oil price environment by reducing turnaround requirements in 2021. MEG currently expects first half 2020 production to average approximately 75,000 barrels a day. In light of the current oil price environment, we are suspending full year 2020 production guidance. At present, MEG expects to produce approximately 30,000 barrels a day during the Phase 1 and 2 turnaround. This production volume reflects the minimum production level required to maintain the integrity of its operations at the Phase 2B facility, which currently has productive capability of 60,000 barrels a day. Upon completion of turnaround activities in August, we will determine based on the price -- oil price environment at that time, when to bring these facilities back into operation. Irrespective of actual production levels in the second half of 2020, which will be a function of the oil price environment as we move through the year, MEG will have the ability to achieve production levels of approximately 85,000 barrels a day post turnaround, once Phase 1 and 2 are brought back into operation. MEG has taken further steps to reduce its 2020 full year nonenergy operating costs and G&A expense. Non-energy operating costs are now targeted at $140 million to $150 million, which is $20 million or approximately 12% lower than original guidance. The majority of these cost reductions were a result of reduction in staffing levels and rationalization of ongoing administrative costs. Targeted 2020 G&A is approximately $15 million or 20% lower than the actual 2019 G&A expense and approximately $30 million or 35% lower than 2018 G&A expense. We continue to respond quickly to the rapidly changing external environment. We remain nimble and decisive and not only draw on the collective value of our executive team, but also are working closely with our Board to ensure they're kept up-to-date with management's actions and plans, but also to bring its experience and perspective from other entities with which they may be involved. 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, we'll open the line to questions.
[Operator Instructions] So your first question comes from Mike Dunn of Stifel FirstEnergy.
Just a question, I guess, Derek, on your reduced volumes there, I guess, from June through August. I think at some point in there, your committed volumes of Flanagan South doubled, 200,000 barrels a day. I'm not aware of what apportionment is going to be looking like there, but are you going to be in a position where you're going to need to either buy barrels to fulfill that or just incur the -- I guess, incur the fixed cost there for maybe a month or so?
Mike, it's Derek Eves. Thank you for the question. I think the answer to that is, it really is highly dependent on the volume that we are actually going to produce. Obviously, through the June through August period and this sort of maximum productive capability of the facility would be about 60,000 barrels a day of bitumen. And so obviously, less than 100,000 barrels a day of blend. In that situation, we will be directing the majority of our production to the Flanagan system when it goes to 100,000 barrels in July. And then comes back to, do we buy other volumes to move down that line to utilize the space? Or do we rent out the space to third parties? And that will be highly dependent upon where the differentials are pricing out in the individual months and where the WTI price is. Obviously, stronger WTI prices and lower differentials will create greater demand for some of that Flanagan space and will provide us with the opportunity for us to minimize the impact of OSE and cost on the space that we're now using.
Your next question comes from Phil Skolnick of Eight Capital.
You talk about production can get to in excess of 80,000 barrel a day, which is below the kind of mid-90,000 barrel day level. Assuming that's because you're not spending on sustaining pads this year, that's been removed from the CapEx budget. So I guess, is that really that's kind of what just is needed to be done to get back to that mid-90s level, also a better oil price environment as well. And then given that, like how should we think about sustaining CapEx in 2021, assuming a normalized oil price environment?
Phil, it's Derek. Thank you for the question. I think, the short answer is we expect 2 things: first and foremost, when we come out of turnaround, that plant productive capability should be somewhere in that 85,000 barrel a day range. So down slightly from our Q1 volumes. But the decrease in productive capability is really a function of the fact that we're not spending sustaining capital in 2020. We've reduced our capital by 40%, and that will as well, have all come out of the sustaining capital aspects of the business. The other thing I'd point to is, there's a big turnaround in -- still in our cost structure for this year, a $25 million extended turnaround, which further cuts into the sustaining capital. So -- but I don't think you should read into our comments here, that the underlying facility is any way impaired. What is needed to bring production back up is, capital dollars being spent in a -- on new pads. And I think, as you think about sustaining capital, as you move forward, you should be -- we talked to a range of sustaining capital between $6 and $8, and you should be using that range probably on the low end of the range.
Okay. Great. Perfect. And just a follow-up question. Just what are you seeing -- because it seems like Alberta inventories have -- that the increase has flattened out, and we've heard other companies talking about that. But what are you seeing on the Gulf Coast now in terms of heavy oil, potential asset down there? Because it seems like, pricing is improving down there. Now we've got the OPEC Plus that's put in place. What are you hearing from refiners sort of demand of Canadian crudes?
So Eric is not in the room with me, but -- so I'm going to throw this question at Eric and -- virtually and hope that he can respond. Eric, over to you.
Thanks, Derek. Thanks, Phil. Yes, we're seeing -- given -- we're seeing numbers about 750,000 to 1 million barrels of heavy or total demand taken out of Western Canada, or supply taken out of Western Canada, that's translating down to the Gulf. The pricing down there for AWB right now is around a couple of bucks off WTI, but it's really about $5 to $6 off of Mars, which is obviously the medium, sour barrels, which is in the normal range. So we're seeing decent demand and pricing in the Gulf Coast. Obviously, there's been a demand pickup of refiners. We've have been hearing that, seeing that in the press, now it's translating back to PADD 2, tighter than full-pipe economics, but we expect that to moderate. In PADD 2, as we move through sort of June, July time frame and we see -- we get past this shut-in or this -- the weakness in the WTI market in the near term. But as it relates to the Gulf Coast specifically, so we don't see anything changing from a pricing perspective in the Gulf, sort of the tightness against Mars and WTI. What we see -- that would move the diffs, that would be simply an increase in WTI prices. So it's conservative from diff -- yes. Thanks, Phil.
Your next question comes from Emily Chieng of Goldman Sachs.
My first question is just around what crude prices you would need to see to be able to turn on the taps, on production a little more fully? Or even if you start spending on those sustaining well pads, should we assume that this comes on in 2021? Or is this still very much dependent on the oil price trajectory towards the latter part of this year?
Emily, it's Derek. I think the -- I'm going to give you 2 prices. Sort of our breakeven price is about $38 WTI. We would be in a positive cash flow situation, but not in one where we would be sustaining production. We need something closer to today in that $44, $45 WTI-type investment sort of -- our price to be putting, sustaining capital back to work, and we would be sustaining production at that sort of price.
Great. And just maybe my follow-up is just a bit more technical. Maybe if you could give some color on your level of confidence and what you would need to be seeing take place in sort of the operations today to make sure that the production does come back to the 60,000 to 80,000, 85,000 barrels per day of production that you're expecting?
I'm going to turn that over to Chi-Tak Yee, our Chief Operating Officer so -- and he can talk to -- give you an answer to that.
Thank you, Derek. So our plan is, as we talked earlier in June, we're going to bring it down to a minimum level of 30,000 barrels per day. And -- but the facility can go up to about 60,000 barrels with Phase 1 and 2 down. So that will be kind of the range, we're seeing for the time that during the turnaround. Post the turnaround, we'll bring back the full capacity. So at that point in time that's the one that Derek talks about in the mid-80 rage to go back to the 90,000 type of rage, then we will have to invest the capital to 2 additional wells to get there. So that's kind of the thinking we have. In terms of the technical nature of it, I guess, it really comes down to -- the well was performing well, all we need to do is the 2 wells to get there.
Your next question comes from Greg Pardy of RBC Capital Markets.
Derek, just a bunch of almost knitty questions, but just around maybe things like capital spending. I mean do you expect that to be evenly distributed over the back 3 quarters? Or is there a bit of a hump here just with the turnaround commencing?
Chi-Tak?
Yes, the profile is going to be more loaded on the June to August time frame, when we go to the turnaround timing. And then the rest of them will be spread more or less evenly. So it will be loaded on the Q3 range.
Okay. Okay. Sorry, loaded on the Q3 range?
Well, in terms of the debt $25 million that we talked about. But the rest of the capital that we spend more or less evenly between now and end of the year.
Okay. Okay. That's good. Derek, I've asked the question before, but you were certainly right the last time, and you're probably going to be right this time. But you're sitting on a ton of cash in terms of the hedges. Are you kind of indifferent between crystallizing versus just kind of running them out?
We -- I think what we've said in our quarterly release here is that we don't need to -- if you look at what our cash balance is going to be at the end of the quarter, we don't see it fundamentally changing and moving. And that's really is the result of the value of the hedge book as we drive forward. So the hedges were put in place to provide price protection, and they're doing just that. And so we have no plans to crystallize them. If you were going to crystallize them, then you have to have use of those proceeds or you would be making a bet that the oil price wasn't going any lower, and we're not allowed to speculate in that fashion.
Okay. Great. And then can you walk me through just a little bit where you talked about this bit last night, but just on your crude volumes, so is the -- just the FOB deals that you've got with the -- are you -- is the first quarter kind of consistent with what the run rate would be through the entire year? And then, can you just remind me, if those are priced at basically just a spread to WCS or spread to TI?
So our production volumes are going to vary. We've suspended guidance through the second half. We've talked about setting a minimum of 30,000 barrels a day. But I can tell you that minimum is based on the physical constraints of the facility and what we consider the dynamic around -- and the financial dynamics around shut-in costs, albeit they're temporary or long term. The turnaround volumes can move all the way up to 60,000 barrels a day. So -- and then as soon as the turnaround is completed in the second half or in the -- at the end of August, we can move up to -- we have the potential to go back to 85,000 plus. So part of the reason for suspending the guidance is, we really don't have the visibility as to what the price is going to be, so that we can ensure that we're covering our variable costs. It -- this -- prices are tremendously volatile, both WTI and the differential, and they're making big changes. So we don't feel comfortable providing guidance with respect to where we think those production levels are going to be. With respect to the FOB deals, those FOB deals are priced at WTI minus the fixed differentials to go to the U.S. West Coast. And then WTI minus a fixed transportation cost to get to the U.S. Gulf Coast. And that's about, I'd say, USD 16.50. And then that -- the U.S. Gulf Coast prices -- the rail that takes it there is priced at U.S. Gulf Coast or WTI minus the AWB price down there. So those 2 particular deals, we continue to have discussions with the buyers, the FOB buyers of those deals. And I can tell you that on a month-to-month basis, we make the decision with those buyers as to whether we're actually going to deliver to those contracts or whether -- and the discussion goes something like this, do you want the volumes? And if you don't want the volumes, then we don't want to -- we're not happy with that differential. We tend to split the difference in terms of what would be the theoretical loss on those types of -- on those deals. So I don't believe in April. We're actually moving any volumes to those rail contracts. And as we move forward, we'll see what May and June look like.
Okay. And the last one for me is, so just that the $7 million contract cancelation. So what was that? Was that with respect to the turnaround or something else?
No. That $7 million contract cancellation deals with the -- what I was just talking about the cancellation of one of -- are with 2 of the rail deals and would not necessarily just deal with the rail deal in the first quarter, but probably overlaps into -- and includes April --
Your next question comes from Manav Gupta of Crédit Suisse.
I had a quick question on the condensate pricing. I think it would probably be a headwind for you in 1Q. But given everything which is going on, those prices have come down materially. So just wanted to understand what you're seeing in the condensate market? And when can we expect you to benefit from the lower condensate prices that we are seeing in the market at this point of time?
Eric, do you want to address Manav's question?
Yes. Q1, it was a headwind we are pricing with the way condensate work for us, we bring about half of it up to the Gulf Coast. We buy half of it in Alberta and the Gulf Coast. Barrels take a month to get up here. So the pricing in Q1 was hurt by the January and February pricing of the barrels. As we move forward, Manav, I think you can think of sort of about 100% for Q2 and then going down to about 90% in Q4. So we'll start -- you'll start to see that high-cost C5, which is caused simply from an inventory/accounting perspective, start to translate through the back end of the year down to sort of a 90% to 95% range against WTI.
Your next question comes from Joe Gemino of Morningstar.
Can you touch a little bit about, if you're not using your crude by rail contracts, what portion of that is fixed? And how that impacts your transportation cost structure?
So all our crude by rail is -- we don't have any direct crude by rail contracts anymore. Those all expired at the end of last year. All of the rail contracts we have are FOB. So they -- people that buy the crude, pick it up FOB on Edmonton.
[Operator Instructions] Okay. So it appears there are no further questions at this time. You may proceed.
Well, thank you, everybody, for joining our call, and thank you for the questions. We look forward to updating you at the end of the second quarter with our results. Until then, have a great day.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.