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Good morning. My name is Joanna, and I will be your conference operator today. At this time, I'd like to welcome everyone to MEG's Year-End 2018 Results Conference Call. [Operator Instructions] Thank you. Ms. Helen Kelly, Director of Investor Relations and External Communications, you may begin your conference.
Thank you, Joanna. Good morning, everyone, and thank you for listening in to our fourth quarter year-end 2018 conference call. In the room with me this morning, I have Derek Evans, our President and CEO; and Eric Toews, our CFO.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. For the call today, we will follow the normal protocol, where Derek will make a few remarks on the quarter and for the year before we open it up for questions.With that, I will hand it over to Derek.
Thank you, Helen, and good morning, everyone. I am sure it's no surprise to anyone who follows this industry closely that the fourth quarter was historic in its extremely wide and unsustainable differentials. In fact, we consider the WTI, WCS and diluent prices experienced by bitumen producers through the fourth quarter to be the perfect storm and highly unusual. In response to this short-term market dynamic, MEG focused on preserving liquidity. We reduced the number of barrels that we had to sell at a loss by advancing a portion of our 2019 turnaround into November 2018 and voluntarily restricting our production in December.In addition, our diversified marketing strategy also helped to partially mitigate the impact of the wider differentials. Our Flanagan-Seaway Pipeline capacity and rail together enabled us to sell 1/3 of our blend volume into the higher-priced U.S. Gulf Coast market, which after accounting for transportation costs, saw approximately $35 per barrel higher netbacks than our Edmonton sales. Despite WTI:WCS differentials of more than USD 39 per barrel, MEG delivered a positive cash operating netback of $5.73 per barrel during the fourth quarter, more than $10 a barrel higher than some of our in situ peers. As we look at our January and February results, we can see the positive impact of the Government of Alberta's mandated production curtailment, returning all of our barrels to profitability with a significant reduction in the WTI:WCS differential. I don't want to let the fourth quarter cast a dark shadow over what, on the whole, was a record year in 2018 for MEG. We had record bitumen sales of 87,731 barrels a day at a record low steam-oil ratio of 2.19x. This is an industry-leading steam-oil ratio that continues to decline for the fifth year in a row. We also had record low net operating cost of $5.09 per barrel and a cost structure that continues to decline for the fourth year in the row.We finished last year's capital program at $52 million under budget to end 2018 with $318 million of cash and cash equivalents on hand, which along with the 2019 expected fund flow, will more than enable MEG to fully fund its 2019 capital program.As we reflect on the volatile and challenging commodity price market we experienced in the fourth quarter of 2018 and the continued delay in new pipeline egress capacity, we've modified our business focus. In the current commodity price environment, financial discipline and balance sheet protection will take precedence over production growth. Our 2019 capital investment plan of $200 million signals our commitment to live within our means while retaining the flexibility to pursue debt reduction and/or advance profitable development when new pipeline capacity becomes available.In addition to our low operating cost structure, we continue to reduce our G&A expenses. G&A expense averaged $2.58 in 2018, a 12% decrease from $2.94 in 2017. In February, we reduced our office and field staffing levels to align with the lower levels of capital associated with the business plan, now more focused on sustaining versus growing production. Based on current production guidance, MEG anticipates G&A costs in the range of $1.95 to $2.05 per barrel in 2018. Based on current strip pricing, we expect our net debt to last 12 months EBITDA to be in the range of 3.5 to 3.75x by the end of 2019 and to exit 2019 with cash and cash equivalent levels in excess of what we entered the year with. The increasing difficulties and challenges in Venezuela and Mexico have placed a premium on Canadian heavy oil in the U.S. Gulf Coast as well as significantly increasing the demand for this product. We are well positioned to participate in this premium market with our capacity on the Flanagan-Seaway Pipeline system. As our capacity on Flanagan-Seaway moves from 50,000 barrels a day to 100,000 barrels a day in the second half of 2020, we will be moving 2/3 of our blend sales barrels to the highest price market in North America. You will note that in the second quarter, we doubled our rail capacity, and we will double it again in 2019, allowing us even greater exposure to the U.S. Gulf Coast market in 2019.With provincially mandated production curtailment, stronger commodity markets and ever-increasing demand for our heavy oil barrels, our strategy is sound and will provide significant uplift in shareholder value.With that, I will pass the call back to Helen.
Thank you, Derek. Joanna, we can now open up the line for questions, please.
[Operator Instructions] Your first question comes from Phil Skolnick from Eight Capital.
Just a couple of questions. Number one, before the Line 3 delay, you had expressed the potential to spend the rest of the money needed for the 2B brownfield expansion. In light of last week's news, has that been pushed by -- out by about 9 to 12 months?
Phil, it's Derek. Thanks for the question because it is very apropos. And when we're out marketing, you could see the level of interest in when we were going to actually put the pin in and then spend the incremental $75 million there. I think I was pretty clear that one of my concerns was that Line 3 or continued availability of egress capacity was one of our considerations. So I think the probability of that going ahead this year has decreased. It's not the only factor in the decision but certainly, it's a big one. We don't want to be building capacity into a system where we don't have the ability to move it.
Okay. Fair enough. Then my other question is, do you see any kind of opportunity, like one of your competitors out there utilizing dynamic storage? Is that something that you have looked at as well to manage any kind of price volatility or differential volatility?
I think, by virtue of the fact that we've got this production curtailment, we're storing heated barrels in the reservoir. We're not going to be able to extract those as quickly as we may want to. But I don't think we've actively engaged or looked at any other form of storage at this point in time.
Your next question comes from Greg Pardy from RBC.
Derek, with the Mainline potentially going to contract its status and, of course, I guess your capacity on Flanagan-Seaway will -- the uptick will precede that. But would that be something you would be interested in, in terms of signing up for firm on the Mainline if that actually comes together?
Greg, great question. I think my priority, first and foremost, is ensuring that the 100,000 barrels a day of Flanagan-Seaway capacity I have is honored and that I have the ability to get those barrels to -- on the Enbridge system to move downstream on Flanagan. And so it's a bit challenging. I support the concept of trying to ensure greater visibility and greater reliability for producers being able to move their barrels. But a challenge for us is making sure -- and a challenge for our shareholders is wanting to know that, that 100,000 barrels a day of long-haul capacity that we have coming off the -- or going on to Flanagan-Seaway is actually going to be actualized and not constrained in a contract-carriager type of arrangement. So we're looking at it. We're trying to understand it. But again, and my primary responsibility and concern is making sure that I can utilize all of that 100,000 barrels that I've already contracted for.
Okay. Great. The other piece on is, is just in terms of where your barrels are going. I think, you guys noted in the release that about 56% of blend, I think was going to the Gulf Coast. Curious where else you were railing.
So we're really railing to -- I guess we have 2 types of rail: We have FOB rail, and we have our own rail capacity. We're currently railing to the Gulf Coast with our own leased rail sets. And then we have FOB-type product that we're not exactly sure where that's all going, but some of it's going to the West Coast of the United States.
Greg, just a quick note of highlight. We did this quarter add a supplemental on the website that discloses our sales by market. If you haven't seen it, you might find that document helpful.
Your next question is from Neil Mehta from Goldman Sachs.
This is Emily on behalf of Neil. Just around the basin egress strategy and particularly in light of the delay in start-up to the Line 3 replacement and couple that with the apportionment rates on Mainline, can we expect MEG to sign any further rail contracts throughout the year? I know you guys are ramping up to about 30,000 barrels per day, but there's still some exposure there to WCS pricing.
Emily, that's -- I don't think you should expect to see us expanding our rail capacity beyond 30,000 barrels a day nor expanding the term or lengthening of the term. We're quite confident that the Enbridge capacity on Flanagan-Seaway will be there. And as I said in a previous question, we're working very hard to make sure that, that won't be apportioned by any changes that Enbridge may contemplate moving from common carrier to contract carrier. But so we have put in place years ago the capacity and capability to move up to 2/3 of our volumes to the U.S. Gulf Coast. And that will be our focus, ensuring that those volumes continue to move to that market as that capacity becomes available.
Great. And my follow-up is just on the production growth profile that you guys have outlined on Slide 4 of the slide deck -- oh, sorry, Slide 5. I guess now that MEG is spending about $200 million in CapEx this year, what is the capital spend required to drive the production growth beyond the 113,000 barrels per day? And I guess what is the anticipated time line of these incremental growth projects?
Yes, Emily, so I think there's been a -- well, what we've been trying to communicate to the market is a very fundamental shift. Until we can see greater egress pipe capacity and capability for the bitumen business in Western Canada, we are going to sustain production at approximately 100,000 barrels a day. So as you look forward, I think on Page 5, we outlined some of the cost structures associated with some of the things that we could do if we were going to grow, and those tend to be in the $20,000 to $25,000 per flowing BOE range. But I think the key focus and the message that we would want you to take away is we are not planning on growing production beyond 100,000 barrels a day. We will be pocketing any incremental free cash flow or excess cash flow and using that to reduce debt as we drive forward. And then I think as you think about what capital we require on a yearly basis to maintain that, you should be looking at that sustaining capital somewhere in that CAD 7 to CAD 8 a barrel.
Your next question comes from Nick Lupick from AltaCorp.
I got 2 questions for you. Is there any color you can give us on the production levels that you're anticipating for the first half of 2019? My understanding is that the curtailment allotments have been given out for April thus far. So any comment you could have on that would be great. And the second question I have for you is a follow-up on the apportionments. I was wondering if you could speak -- obviously, with the curtailments in place, I'm sure producers were hoping that the apportioned volumes would start to minimalize. And I wondered if you could give us some clarity on whether -- what apportionment levels you are currently seeing, keeping in mind that the nomination and process is currently flawed. So just how that dynamic is working today?
Nick, thanks for the question. I think on curtailments, I think a big part of the driver behind the curtailments was that -- and one of the premier stated objectives was that the very high current storage levels, that I think she quoted as being about 36 million barrels at the time, she wanted to see those reduce down closer to 18 million. I think as you look at those storage levels today, they still look to be very high, in the 34 million to 35 million range. And so absent any changes in government, one of the things that we're sort of thinking about and trying to understand is do those curtailment levels continue into the second quarter? And do those create any challenges to our production forecast and anybody else's forecast in the business? And I -- we think that those -- so the curtailment is a big unknown for us and especially given that the government is -- where the storage levels are at the current time. So I really can't provide you any greater color on where we see those going, other than I think one of the things in terms of some of the analyst and institutional work that we did was we were criticized for being too conservative in terms of our production forecast. And we've taken that on, and we understand it. But I definitely want to be on the conservative side of our production forecast with the big questions around how long curtailments continue, especially given the current storage level. Your question on apportionment. I don't think there's been a substantial change in apportionment. And then partly because -- or one of the things that's happened is not only has storage not changed that much, but rail capacity has dropped off fairly dramatically in the last couple of whiles. Looks like we've lost somewhere in the neighborhood of 160,000 barrels a day of rail capacity in February alone. And we think there may be reasons for that in terms of big producers in the United States having turnaround activity. But we would expect to see that rail come back in the coming months, storage go down and hopefully, apportionment start to get back to more reasonable levels.
Your next question comes from Jacob Gomolinski-Ekel from Morgan Stanley.
Given you're putting on hold the brownfield expansions, and you've got about $318 million of cash on the balance sheet and an undrawn $1.4 billion revolver, it seems like liquidity is pretty ample. And you mentioned you'll generate some cash this year. How do you think about balance sheet efficiency, particularly given you've got bonds that are trading in -- at the 10% range and in the mid-80s now?
Jacob, it's Eric speaking. The way we think about right now, it's early in 2019, we do -- we are optimistic from a cash flow perspective as we move through the year. And we did put on our press release where we think our net debt to LTM EBITDA will get to by the end of the year. Right now, I think what you should expect to see from us is sort of a defeasement strategy of debt as opposed to an absolute pay down of debt. Well, we may change that strategy as we move through the year and looking at 2020. But given the comments on curtailment, given the comments on apportionment in Line 3, we want to be careful how we look at the balance sheet and absolute debt repayment versus defeasement of debt on the balance sheet.
Got it. And just in terms of the most updated numbers, I think the -- is the RFP basket for junior bond buybacks still like $100 million from the general basket plus an additional $250 million carve-out? Or is there a different number we should be thinking about?
No. You have the right number.
Okay. And finally, just what is the current corporate decline rate on production as it stands today?
About 10%.
Your next question comes from Jon Morrison at CIBC Capital Markets.
You obviously have a decent hedge book in place. Can you give any more color on how you're thinking about incremental hedges from this point forward, both on a, call it WTI basis as well as a bases perspective?
Jon, it's Eric again. We've been -- looking into 2019, as we started to hedge up to 2019, we focused primarily on the differential. We did -- as well as WTI. I think what you'll see on a go-forward basis, given where prices are and we're seeing the strip for '19, and frankly, into '20, we'll continue to layer on opportunistically further hedges to protect the cash build and the cash balance. So you should expect to see us do that judiciously over here in the next little while.
And Eric, just to follow on the earlier question. I mean, what would really need to change for you to actually look at buying back some of your debt at this point? Is it just a function of price? If it got cheap enough, you'd go ahead and do it? As to your point, financial flexibility kind of trumps everything else right now.
Financial flexibility is key and then also all the things around indentures and timing and that sort of thing. But again, Derek mentioned at the outset of the call and through this call about living within our means and building cash. And so from our perspective, defeasement right now feels like the right thing to do. And we'll revisit that quarter-over-quarter, but that's the current strategy.
And just to follow on Phil's question in terms of the incremental discretionary $75 million of CapEx for Phase 2B expansion. When would you actually need to make that decision to go forward? If you wanted to go forward with it in '19 from a procurement service perspective, when would you actually need to make that decision by to get it done this year versus pushing into future years?
Jon, it's Derek. I think it -- you probably understand this. But for the rest of the audience, we've already got significant capital invested in this project, 50% of the total cost of the project. It -- if we said if we pushed the button today and said we're going forward, it would be about 12 months before we saw first production. So -- and that's about 9 months of incremental production and about 3 months of steam to the reservoir, warming it up before we actually saw the production.
I realize it's looking at a decent amount of time forward and not something you really need to worry about right now. But if there was an issue where you couldn't utilize your throughput capacity on Flanagan South/Seaway in the back half of 2022, [ apportioned up ] line, would you potentially be able to sell that capacity to other participants? Or would you just look at banking those volumes?
I don't think we would look at selling the capacity. I -- let me just make sure I understand the scenario. So are you suggesting that would be -- as a scenario is that we had the capacity on the line but we didn't have the production to run down it? And in that case, we would probably purchase other people's production to move down, and we would use the marketing strategy on that as opposed to actually letting other people utilize the line.
Okay. On the transportation cost side, is it fair to assume that what we saw in Q4 was fairly indicative of what we'll see in Q1 and Q2 given the volume of production that you're going to have?
Yes. We're looking at somewhere between $10 and $10.50 as a blended transportation cost driving forward. That's Canadian.
Thank you. We have no further questions at this time. You may proceed.
Thank you, Joanna, and thank you, everyone. This concludes our call. As usual, we will be available afterwards to answer any of your questions. Thank you for joining us this morning.
Ladies and gentlemen, this concludes today's conference call. We thank you for participating, and ask that you please disconnect your lines.