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Good morning. My name is Sylvie, and I will be your conference operator today. At this time, I would like to welcome everyone to the MEG Energy 2019 First Quarter Results Conference Call. [Operator Instructions] I now would like to turn the conference over to Helen Kelly, Director, Investor Relations. Please go ahead.
Thank you, Sylvie. Good morning, everyone, and thank you for listening in on our first quarter 2019 conference call. In the room with me this morning, I have Derek Evans, our President and CEO; Eric Toews, our CFO; and Chi-Tak Yee, our COO.Just a reminder that this call contains forward-looking information. Please refer to the advisories in our disclosure documents filed on SEDAR as well as on our website. On the call today, Derek will provide his remarks on the quarter before we open it up for questions. With that, I'll hand it over to Derek.
Thanks, Helen, and good morning, everyone. Thank you for joining us today. I'll try to keep my remarks concise to leave time for Q&A. I want to touch on our financial and operating results for the quarter but also give you a picture of where we are today relative to some of the objectives I laid out for the organization earlier on in the year and where our focus and priorities are going forward.First, our strong first quarter results illustrate the cash flow generating capacity of the organization under a more conducive price environment. With cash netbacks of approximately $30 a barrel, we generated adjusted funds flow of $151 million in the first quarter of 2019 compared to negative 300 -- excuse me, negative $38 million in the last quarter of 2018. Taking into account the $53 million of capital investments, we generated free cash flow of nearly $100 million in the quarter. It goes without saying, one of the most significant impacts on our strong Q1 results was dramatic narrowing of the WCS differential from USD 39 to USD 12 a barrel from Q4 2018 to Q1 2019.However, in addition to the improvement in WCS pricing, is MEG's ability to access the premium Gulf Coast market where we trade relative to global heavy oil prices. Through our 50,000 barrels per day commitment on Flanagan South Seaway and delivered rail capacity, 1/3 of our barrels realized an average of USD 3 per barrel premium relative to those sold within Western Canada after taking into account transportation costs. This advantage will only grow in significance. By the middle of next year, we will have contracted egress in place for up to 90% of our production to high-value markets. Even with the impact of forecast apportionment, we expect roughly 2/3 of our barrels will reach the premium U.S. Gulf Coast next year where, historically, they have realized a USD 5 to USD 7 per barrel discount to Mars pricing. This will reduce our exposure to the landlocked Edmonton price marker. Obviously, there's additional upside going forward as Enbridge Line 3 and other export pipelines are brought into service. There continues to be a very favorable demand outlook for our barrels on the U.S. Gulf Coast. We continue to see additional U.S. Gulf Coast import sources challenged. It's estimated that the Gulf Coast was short 600,000 barrels of heavy oil during the first quarter with Mexico production at record low and as political turmoil in Venezuela continued.Additionally, analysts currently estimate an incremental 1.5 million barrels per day of global demand for heavy oil coming onstream in 2019. This is to meet the surge in petrochemical processing capacity being added globally, in particular in China, as well as demand for traditional refinery projects.Turning back to our results. Also helpful to our margins this quarter were lower diluent costs. This is a result of the combination of the positive impact of the lower purchase price of diluent relative to WTI and the narrowing of differentials, which increased the amount we recover on diluent purchases when we sell our blended product.Going forward, we expect to see favorable condensate costs for the remainder of 2019. Together, stronger price realizations and lower diluent costs in the quarter allowed us to deliver the strongest bitumen realization in the last 4 years.During the quarter, production averaged approximately 87,000 barrels per day against our production capacity of 100,000 barrels a day, reflecting the impact of the Alberta-wide curtailment with sales slightly exceeding production. Our full year production guidance of 90,000 to 95,000 barrels per day takes into account current levels of curtailment and assumption that it eases throughout the second half of the year.Let me spend a few minutes addressing our progress against some of the objectives I outlined for the company a number of months ago. One of the key objectives for 2019 was cost reduction and organizational realignment. As mentioned in March, we made some significant organizational changes during the first quarter to reduce G&A and to better align our workforce with the lower levels of capital spending within the company going forward. While the changes are not fully reflected in the quarter, the changes support our 2019 G&A guidance of approximately $2 a barrel.Perhaps, just as important as reducing cost, our recent staff reductions reaffirm our commitment to a more prudent pace of growth, which is tied to another important objective around capital discipline and balance sheet strength. As I mentioned earlier, capital spending came in at $53 million during the quarter relative to our base budget of $200 million. While we have the optionality to layer on $75 million of discretionary capital in 2019 to advance our highly economic 13,000 barrel a day Phase 2B brownfield expansion project, our thinking on when to advance this project has not changed. We will need to see certainty around curtailment and egress prior to making that decision. Whether or not we proceed with the expansion this year, we anticipate to generate substantial free cash flow in 2019 to support debt reduction, which will remain a top priority for the organization in the coming years.Finally, Board renewal. We anticipate 3 new Board members to stand for election at our June Annual General Meeting. These qualified and experienced individuals will bring a fresh approach to how we position ourselves for the future. We expect to announce the 3 new Board nominees shortly.In conclusion, the MEG of today is a very different company than the one of the past. At current strip pricing, we anticipate a significant strengthening of our balance sheet with net debt to EBITDA coming in below 3x by the end of this year. We expect to generate material free cash flow going forward as we shift our focus from growth and a history of significant outspending of cash flow to harvesting and optimizing the value of our business.As I have said before, our primary focus in the short and medium term will be strengthening our balance sheet. We will continue to expand our market and improve our efficiencies. I want MEG to become one of the most sustainable oil and gas companies in North America, both in terms of our ESG performance as well as our financial sustainability.With that, I'll pass it back to Helen.
Thank you, Derek. Now I think we're going to hand the line over back to Sylvie to open it up for questions. As a reminder, our team will be available to answer any questions and myself, specifically, for remodeling questions after this call. So please, if you can keep the questions to a strategic level, we can follow up afterwards. With that, I'll hand it over to Sylvie.
[Operator Instructions] And your first question will be from Greg Pardy at RBC Capital Markets.
Three quick ones for you. I mean the first is just around the turnaround for the second quarter. Like from what I understand, this will be a shorter one. But could you give us any color on that? And then do you typically -- just remind me if you typically expense or capitalize turnarounds.
Greg, it's Derek. I'm going to turn that question over to Chi-Tak to answer.
Greg, Chi-Tak here. So on the turnaround as you recall last year because of the very high differential, we moved quite a bit of turnaround work from this year back to November last year. So with that done, we're expecting a pretty small turnaround, and the impact would be virtually none because now we are under a curtailment situation. So we can actually do some of this work while we are restricted on production. So we expect the impact will be rather small, if any. As far as turnaround is concerned now, historically, we'll be capitalized on all of these turnarounds.
Okay. I think we've got modeled in a few days, which sounds like it's not too far off. Just around the shape of your capital program this year, so then with the -- are we kind of looking at $50-odd million a quarter give or take?
Yes. That's kind of the number we're looking at.
Okay. And last one from me is just your barrels into storage. I think you built storage in the first quarter as well, so we're assuming that then you'll start drawing those down kind of over the second, third quarters just to shore up sales?
So -- it's Derek, Greg. We use storage as a bit of -- a couple of things. It helps us nominate long-haul capacity. So we try and keep it as full as we possibly can to minimize the impact of apportionment. And although published apportionment runs close to 30% or 40%, our actual apportionments in the 10% to 11% type of range, the actual physical apportionment of barrels we can't move. So storage is an important element for that. And obviously, in the first quarter, you saw us draw down storage opportunistically because I think our production is about 2,000 barrels a day. Our sales are about 2,000 barrels a day higher than our actual production. So it's a marketing and -- tool to help us take advantage of price optionality that we see, and obviously, in the first quarter and really as well in April, we've seen some great opportunities to move barrels.
Okay. Last one from me is, is priority -- is debt reduction -- near-term plan then I guess would be to kind of build cash. But do you -- is there any potential here in terms of just repaying term loans, what have you?
I'll ask Eric to take that one.
Greg, it's Eric speaking. Yes, our current plan is to continue to build cash. Obviously, we had some working capital draws in the first quarter. So our cash build remains on track for the year. We do see building considerable cash balances. As it relates to how we would approach debt reduction, we're working through that right now. I think you can probably expect us not to signal to the market how we're going to do that until we actually start executing on it.
Next question will be from Phil Skolnick at Eight Capital.
Just a question on your U.S. Gulf Coast storage. Any kind of -- I guess, how much do you have down there? Are you able to use that as part of your nomination on the mainline? And then finally, how should we think about timing of getting barrels exported? Have you had discussions with counterparties?
So I'll take a crack at it, and then I'll ask Eric to fill in some of the blanks. We do have some storage on the U.S. Gulf Coast. I'm not sure how much it is. I know we have 2 tanks at the current time, and I know we're also looking at expanding that capacity as we think about the logistics associated with moving crude out of the U.S. Gulf Coast by tankers. So as to your question, can we use that capacity in terms of nomination? I'm not 100% sure.
Okay. And I guess just on rail with the Alberta government's rail given the new government there, are you interested in taking some of that rail off their hand?
No. Phil, thanks for that question. It's -- we are in a pretty privileged position with an incremental 50,000 barrels of Flanagan Seaway capacity coming on. So as we think about where we'll be in the middle of next year, we'll have 100,000 barrels a day on pipeline capacity on Flanagan and Seaway South as well as 30,000 barrels a day of committed rail capacity out of Bruderheim. So that's 130,000 barrels of production on something, like I say, notionally could be 145,000 to 150,000. So 90% of our production is already committed to existing egress-type options. So we'd be happy to listen to whatever the Alberta government is doing in if we can be helpful in any sort of way. But I don't think we really need to add to our egress optionality at this point in time.
Understood. And then -- and just on the -- when you do expand your capacity to 100,000 on Flanagan to a -- that doubles your nomination power on the mainline. So if you're getting to roughly 35,000 down right now, then once that doubles, you'll be able to get to 70,000, assuming that's single apportionment. Is that the right way to think about it?
Yes, and exactly. And I think you should think about the rail as being apportionment protected as well. So when we talk about having 66% of our production sort of -- or 2/3 of our production moving in a sort of an apportionment-protected type of range now mostly through the U.S. Gulf Coast, that's what we're talking about is the 70 plus the 30 being 100 out of notionally 150.
Okay. Just finally -- sorry. This is the last question. Just your $23 rail cost. That's all inclusive from Christina Lake down to the Gulf Coast, right?
Exactly, and it includes about sort of -- the difference to somebody else's rail cost would be there's about $2 of what we call access transportation cost included in there, and that's really they cost from Christina Lake down to notionally Edmonton.
And your next question will be from Mike Dunn at GMP FirstEnergy.
A couple of questions from me. First, I just want to clarify on your doubling of the Flanagan Seaway capacity mid- next year. Is that contingent upon any pipeline projects being complete? Or is it either Line 3 replacements, which I don't think it is, or anything in terms of expansions within the U.S.?
Mike, it's Derek Evans. The answer to that: It's not contingent on anything. This is capacity that already exists, but it just moves into our name in July of 2020.
Great. And then second question from me and last one, the -- your reports showed, I think, about a $12 million asset sale proceeds, I believe, related to emissions performance credits. Can you just talk to what you did there? And maybe any sense for whether or not you have any more surplus credits left that you can monetize?
Chi-Tak, you want to take that?
Yes. So these emission performance credit, or EPC, record is when you perform -- when your facility emission is below the government point of value or you've banned these credits. And that's what we did was we sold essentially all the credits that we had. We still had a little bit on that earlier this year for the $12 million.
Great. Well, it sounds like a good move ahead of the uncertainty with how the new government is going to implement the carbon tax.
Yes, we agree that, that was a good move, too. Thank you.
Well, I think the other part that Chi-Tak is not telling you is that we've got a very good price for those credits at that point in time, and we would not be able to get the same price today, given the uncertainty associated with the value of carbon credits. But also I think it's a tremendous recognition of the very low steam-oil ratio that the organization has that we are actually receiving those credits and had the ability to sell them.
Next question will be from Neil Mehta at Goldman Sachs.
The first question is, just want to get your big-picture view on Western Canadian crude differentials. A lot of moving pieces from a geopolitical perspective to what's happening in Alberta. But how do you think about what is normal and what is sort of mid-cycle as you think about the spread?
Neil, it's Derek Evans. I think the way we are looking at differentials today is not so much from the Edmonton perspective but more from the U.S. Gulf Coast perspective. We think the tightness in the U.S. Gulf Coast primarily deliver as a result of shrinking Venezuelan volumes making their way to the U.S. Gulf Coast and shrinking Mexican volumes of heavy has really created a premium market for heavy in North America. And what you're seeing is that premium sort of backing up into the Edmonton market. I think the other piece that we would point to, ultimately, we think in an unconstrained or a well-supplied market on the U.S. Gulf Coast, you should probably expect to see differentials in that USD 18 to USD 19 per barrel WCS:WTI differential-type price range.
That's helpful. Second question, and this one is a little more out of left field. When we talk about M&A, MEG Energy is not necessarily talked about as a logical acquirer of assets, but we have seen companies with higher amounts of leverage consolidate -- consolidate basis, and as a result, increased EBITDA that gets net debt to EBITDA lower. Is there any appetite to look at consolidating assets? Or -- and certainly, there are some that are up for sale in Western Canada. Or is the logic to organically delever and then reinvestment there?
I think the first quarter is a grand example of how -- the cash flow torque that this organization has. So the organic deleveraging, I think, is already underway, and we will continue to show that as we drive forward. So as you think about M&A, though, really the -- a very big part of M&A is making sure that you're bringing assets into the mix that are, from our perspective, either better or they bring some unique attribute to the table. And it's very challenging to do M&A in the oil sands space where you've got 40 years of inventory. One of the things that I think is sometimes talked about out there is, would we be interested in a Devon? And I can tell you, categorically, we're not talking to a Devon. So we'll get that out of the way, but a Devon would have -- is a very -- it's a very good company. It's got very good assets but much shorter reserve life. And if we were thinking about doing a Devon, we would look at the reserve life, and we'd look at their egress capability. I've just spent quite a few minutes talking about how well we are set up for egress. A Devon wouldn't have that opportunity, neither would it have the other reserve life. So the quality of the asset is really important to us as well as sort of the attributes associated with transportation, which is a big factor, obviously, in our business today.
And last question from me is you gave us color on 2019 capital spending. How do we think about post-2019, 2020, 2021? What's the P50 level that we should be running through the models?
So I think the key thing you should focus on is that we've said we want to sustain our production at that 100,000 barrel a day level. So I think we've got in our presentation sort of something notionally in the $310 million range. I think that's probably a pretty good place to start, and that would allow us to replace the very low production decline that we have and hold production at about 100,000 barrels a day.
[Operator Instructions] And your next question will be from Joe Gemino at Morningstar.
Just a question about rail. How do you think about where your production goes between the Midwest and the Gulf Coast?
So Joe, it's Derek Evans. The -- most of our -- all of our production that we're moving on our own railcars or at least railcars are all going to the U.S. Gulf Coast. So we're not making a Midwest call on that production. Our FOB production, which is a growing component of the production that's coming out of our Bruderheim or BTO capacity, we're not sure where that's going, but we do know that we're getting a premium pricing for that product out of that market. So anything that we're directing is being directed to the U.S. Gulf Coast at this point in time.
Next question will be from Jon Morrison at CIBC Capital Markets.
You tightened up the range of where you think you're going to exit 2019 on a net debt to EBITDA basis on strip in the numbers that you laid out last night versus your most recent marketing deck. Can you just share, one, what drove the tightening in the range? And was that just a function of actualizing the Q1 print? And two, is the numbers that you've quoted in the last slides reflective of kind of the changes that we've seen in strip over the last week or so? Or would they be a little bit more dated than that?
Yes, John, it's Eric Toews speaking. The numbers are -- that's based on current strip as of last night. So it really was driven that -- that improvement in leverage was simply the realization that we were seeing and we're forecasting for that into the strip as we go forward.
And Eric, it will be fair to assume that you're not including any divestitures or any unknowns that we wouldn't be thinking about in our numbers right now as we compare kind of apples to apples? That's all operational numbers?
That's correct, Jon.
Got it. Is there anything that could drive the CapEx number to be below the base $200 million program that you guys have put out to The Street right now based on anything that you're seeing?
I'm going to ask Chi-Tak to answer that.
It's Chi-Tak here. I guess you never say never, but the -- typically, our first quarter is our heaviest CapEx spending. So the fact that we came in $53 million, which is approximately 1/4 of the year, I think there's a chance that we could be below that. But having said that, we already started with a very small project -- or small CapEx this year. So I think the chance of getting CapEx below that is not high, in my view.
Okay. High level, Derek. How are you thinking about incremental hedges from this point forward? You just talked about wanting to create one of the most enduring energy companies out there. Does it imply needing to take some of the potential risk of your cash flow stream off the table in the next 12 to 18 months?
So Jon, as I think about our hedging program, we're really trying to -- we have 2 markets that we sell our product into: we sell it into the U.S. Gulf Coast and we sell it into the Edmonton markets. Obviously, we've seen, last fall, huge volatility in that Edmonton market. So as I look at the remainder of 2019, I've got about 60% of my Edmonton production hedged today. So -- and that's about as much as I'll feel comfortable hedging. We are, as you'll remember, a single-asset company. So we don't want to -- we don't have the luxury of being able to spread our production over 10 different assets. But 2019, the remainder is hedged at 60% of Edmonton production. And as we think about 2020, we're already about 33% of our Edmonton-type volumes hedged at this point in time. And some of those were done physically as well as -- and the remainder are done financially. But for instance, if we look at where we are [ 20 20 ] today, we've got about 30,000 barrels of diluent or dilbit hedged at about $20 fixed WTI:WCS fixed diff. So we're in reasonable shape, but I think the key takeaways from us are we're very focused on managing the risk associated with the Edmonton market. And you can expect us -- you should expect us to be at sort of 60% of Edmonton at -- that would be a maximum position that we would take, and then the rest, we're quite comfortable to let float in U.S. Gulf Coast.
Perfect. That's very helpful. You talked about getting to the full 30,000 barrels of rail capacity that you have at Bruderheim in Q3. Just to clarify, is that at the start of Q3 or at some point in Q3?
We're ramping up as we speak. So we will -- in Q2, we'll be at 24,000, and we'll be at full 30,000 in the start of Q3. So the second half of the year, we'll be running at full capacity out of Bruderheim.
Okay. Eric, obviously very strong free cash in the quarter but because of working capital changes, net debt actually went up. Would you expect all of that working capital noise to kind of unwind in the coming quarters outside of, obviously, the IFRS 16 leasing stuff?
Yes, Jon, it'll all unwind. We have -- as we and others in the industry have, we had negative margins in November and December. And obviously, we snapped that back in January through the quarter. So the majority of that sort of whole, if you will, is all working capital, which will unwind. We had -- receivables were significantly up quarter-over-quarter. Payables were down quarter-over-quarter just given the capital spending in Q4 versus Q1. So that's the bulk of that and that'll all unwind.
Just one last one for me if I could squeeze it in. Derek, just to clarify your answer to the larger M&A question, is it fair to assume that what you're implying is that there's lots of things out there on the market, but if they're not checking those strategic boxes, like you mentioned, they're not off the table but, ultimately, would probably have to come at a very low price and create very good accretion for the map to go around in your mind?
Yes.
Next question is from Benny Wong at Morgan Stanley.
Just had a quick question around the discretionary capital potentially at the end of the year or at back half of the year. Just an update in terms of how you're thinking about that. And also, is there a certain window in terms of where you had to make the decision by? And secondly, is it -- does it have to be a full chunk? Could it be part of that capital that you could decide to move forward as opposed to the full $75 million?
Benny, it's Derek. It's a very good question. I think in my prepared remarks, we've talked about the fact that our thinking about when we would progress this $75 million, the remainder of the 2B [ 2 ex ] project is -- really hasn't changed. We want to see greater certainty with respect to curtailment as well as egress, primarily Enbridge Line 3 replacement. We want to get greater color on that. So that is not changed at this juncture. Is there a tiny element, I think, was your second question that we have to undertake this by? No. We don't have a gun to our head from that perspective. We can make the election to move forward at any point in time. I think one of the key considerations is, though, it's about 12 months from when we start spending that incremental capital to when we would see first steam or -- and associated first production. The third part of your question dealt with, could you do this in parts? That's something that we're investigating. And just at a very high level, yes, you probably could spend more money on the facility and get the facility side of this finished up and hold off on the welfares and the associated -- fieldwork associated with bringing those wells on production at some point in time.
And at this time, we have no other questions registered. So I would like to turn the call back over to Helen Kelly.
Thank you, Sylvie, and thank you, everyone, for joining us this morning. As I said earlier, we're going to be available individually, myself as well as with Derek and Eric to answer any questions that you may have. Thank you for joining us this morning.
Thank you. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your lines. Enjoy the rest of your day.