MEG Energy's (MEGEF) CEO Derek Evans on Q1 2020 Results - Earnings Call Transcript

MEG Energy Corp. (OTCPK:MEGEF) Q1 2020 Earnings Conference Call May 5, 2020 8:30 AM ET

Company Participants

Derek Evans – Chief Executive Officer

Eric Toews – Chief Financial Officer

Chi-Tak Yee – Chief Operating Officer

Conference Call Participants

Mike Dunn – Stifel FirstEnergy

Phil Skolnick – Eight Capital

Greg Pardy – RBC Capital Markets

Manas Gupta – Credit Suisse

Joe Gemino – Morningstar

Operator

Good morning. My name is Colin, and I will be your operator today. At this time, I would like to welcome everyone to the MEG Energy 2020 First Quarter Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions]

Thank you. Mr. Derek Evans, CEO, you may begin your conference.

Derek Evans

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 have 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 an unprecedented challenges, the COVID pandemic, associated demand destruction and resulting impact to oil prices has created real challenges to the health and safety of our employees and to the short-term viability of our business.

MEG is responding proactively to the safety and financial challenges associated with the COVID-19 pandemic. At this time only essential staffs 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 policies, 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 plant – plant turnaround, cutting capital by a hundred million versus original guidance and reducing non-energy 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 assets. I would like to touch on some of the financial and operating results highlights from the first quarter.

On January 16th, we refinanced US$1.2 billion of existing indebtedness and concurrently utilized cash on hand to repay an additional CAD132 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 funds 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 gain 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 roll back 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 1st 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 strong hedge position in light of the current weak oil price environment and MEG’s focus on maintaining its financial liquidity, MEG is further reducing its 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 that 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 corporations to take advantage of the current low oil price environment by reducing turnaround requirements in 2021. MEG currently expects first half 2020 production to our 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 non-energy 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.

Question-and-Answer Session

Operator

Thank you, ladies and gentlemen. We will now begin the question-and-answer session. [Operator Instructions] Okay. So your first question comes from Mike Dunn of Stifel FirstEnergy. Please go ahead.

Mike Dunn

Thanks. Good morning folks. 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 on Flanagan South doubled to 100,000 barrels a day. I'm not aware of what a portion of that's going to be looking like there, but are you going to be in a position where you're going to need to either by Darryl's to fulfill that or just incur the – I guess incur the fixed costs there for maybe a month or so?

Derek Evans

Hi, Mike. It's Derek Evans. 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 these are the maximum productive capability as a facility would be about 60,000 barrels a day of bitumen and so obviously less than a hundred thousand 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 a hundred thousand barrels in July.

And then a question comes back to do we – 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 the cost on the space that we're now using.

Mike Dunn

Okay. Thanks Derek. And that's all for me.

Operator

Derek Evans

Thank you.

Operator

Your next question comes from Phil Skolnick of Eight Capital. Please go ahead.

Phil Skolnick

Yes, thanks. Good morning. You talk about production can get to in excess of 80,000 barrels a day, which is below the kind of mid 90,000 barrel a day level. I am 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 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?

Derek Evans

Phil, it's Derek. Thank you for the question. I think the short answer is we expect two things. First and foremost, when we come out of turnaround, that plant of 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 all come out of the sustaining capital aspects of the business.

The other thing I'd point to is, there's a big turnaround still in our cost structure for this year a $25 million extended turnaround, which further cuts into this 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 talk 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.

Phil Skolnick

Okay, great. Perfect. And just – final question, just what are you seeing because it seems like Alberta inventories have – 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 out – down there and because it seems like pricing is improving down there. Now, we've got the OPEC plus cuts put in place. What are you hearing from refiners sort of demand of Canadian crude?

Derek Evans

I – 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.

Eric Toews

Thanks, Derek. Thanks, Phil. Yes, we're seeing – given we're seeing numbers of about 750 to – 750,000 to a 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 above five to six bucks off of Mars, which is obviously the medium sour barrels, which is in the normal range. So we're seeing a decent demand and pricing in the Gulf coast.

Obviously, there's been a demand pickup from refiners we've been hearing that and seeing that in the press and that'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 the June, July timeframe 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, Phil, 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 dips up will be simply an increase in WTI pricing. So constraint – it's constructive from a dip perspective…

Phil Skolnick

Constructive.

Eric Toews

Yes, thanks, Phil.

Phil Skolnick

Thanks, Eric.

Operator

Your next question comes from Emily Chieng of Goldman Sachs. Please go ahead.

Emily Chieng

Good morning. 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 to start spending on those sustaining well pads. Should we assume that this comes on in 2021? Or is it still very much dependent on the oil price trajectory towards the later part of this year?

Derek Evans

Emily, it’s Derek. I think the – I'm going to give you two 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 the $44, $45 WTI type in prior – investment sort of our price to – to be putting sustaining capital back to work and we would be sustaining production at that sort of price.

Emily Chieng

Great. Thanks. 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.

Derek Evans

I'm going to Emily turn that over to Chi-Tak Yee, our Chief Operating Officer. And he can talk to – and give you an answer to that.

Chi-Tak Yee

Thank you, Derek. So our plan is as we talk in June we are going to bring it down to a minimum level of 30,000 barrels per day, but the facility can go up to about 60,000 barrels with Phase 1 and Phase 2 down. So that would be kind of the range we've seen for the time during the turnaround. Post the turnaround we will bring back the full capacity. So at that point in time the one that talks about the maintaining range. To go back to the 90,000 type of range we have to invest the capital to additional wells to get that. So that's kind of the thinking we have.

In terms of the technical nature of it, I guess it really comes down to that it was performing well. What we need to do is the two wells to get there.

Operator

Your next question comes from Greg Pardy of RBC Capital Markets. Please go ahead.

Greg Pardy

Yes, thanks. Good morning Derek just a bunch of – almost nitty questions, but just around the things like capital spending, I mean, do you expect that to be evenly distributed over the back three quarters or is there a bit of a hump here just with the turnaround commencing?

Derek Evans

Chi-Tak.

Chi-Tak Yee

Yes the profile is going to be more loaded on the June to August timeframe when we go to turnaround timing and then the rest will be spent more or less evenly. So it will be loaded on the Q3 range.

Greg Pardy

Okay. So loaded on the Q3 range.

Eric Toews

Well, in terms of the debt, $25 million that we talked about.

Chi-Tak Yee

Yes.

Greg Pardy

Okay.

Eric Toews

But the rest of the capital that we spent more or less evenly between now and the end of the year.

Greg Pardy

Okay, that's good. Derek, I've asked you the question before, but you were certainly right the last time, and you are probably going to be right this time. You are 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?

Derek Evans

I think what we have said in our quarterly release here is that we don't need to – if you look at where 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 as a 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 are doing just that. So we have no plans to crystallize them. If you were going to crystallize them, you have to have use of those proceeds, or you would be making a bet that the office wasn't going any lower and we are not allowed to speculate in that fashion.

Greg Pardy

Okay, great. And then can you walk me through just a little bit we talked about this a bit last night, but just on your crude volumes, so just the FOB deals that you've got with the – 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 a spread to TI?

Chi-Tak Yee

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 that the dynamic around – the financial dynamics around shutting costs out would be they temporary or long term. The turnaround volumes can move all the way up to 60,000 barrels a day. And then as soon as the turnaround is completed in the second half or at the end of August, we could move up to – we have the potential to go back to 85 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. This – prices are tremendously volatile, both WTI and the differential, and they are 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 fix differential 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 US$1,650. And then the U.S. Gulf Coast prices, the rail that takes it there is priced at a U.S. Gulf Coast, or WTI minus the AWV price down there. So, those two 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 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 not moving any volumes, to those rail contracts. And as we move forward, we'll see what May and June look like.

Greg Pardy

Okay. Thanks for that. And the last one for me is, so just that the $7 million contract cancellations, so what was that? Was that with respect to the turnaround or something else?

Chi-Tak Yee

No, that $7 million contract cancellation deals with the – what I was just talking about the cancellation of one of the – or two of the rail deals.

Greg Pardy

Okay, understood.

Chi-Tak Yee

And would not necessarily just deal with the rail deal in the first quarter, but probably overlaps into and includes April.

Greg Pardy

Got it. Okay, thanks very much.

Chi-Tak Yee

Thank you.

Operator

Your next question comes from Manas Gupta of Credit Suisse. Please go ahead.

Manas Gupta

Thanks for taking my question. 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 want to understand what you are 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?

Chi-Tak Yee

Derek, do you want to address Manas question?

Derek Evans

Good morning Manas. Yes Q1 was a headwind we were pricing with the way a condensate works for us, we bring about half of it up from the Gulf Coast and we buy half of it in Alberta and the Gulf Coast, barrels take a month or two to get up here. So the pricing in Q1 was hooked by the January and February, pricing of the barrels. As move forward Manas, I think, you can think of sort of about a 100% to, and then going down to about 90% in Q4. So you'll start to see that high cost C5 which is caused simply from inventory/accounting perspective starting to translate through the back end of the year down to a sort of a 90% to 95% range against WTI.

Manas Gupta

Thank you for taking my question.

Derek Evans

Thank you.

Operator

Your next question comes from Joe Gemino of Morningstar. Please go ahead.

Joe Gemino

Great, thank you. Can you touch a little bit about, if you are not using your crude-by-rail contracts, what portion of that is fixed and how that impacts your transportation cost structure?

Derek Evans

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 – all expired at the end of last year. All of the rail contracts we have our FOB. So they brought the crude pick it up FOB on – out of Edmonton.

Joe Gemino

Okay, thank you.

Operator

[Operator Instructions] Okay, so it appears there are no further questions at this time. You may proceed.

Chi-Tak Yee

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.

Operator

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