Enerplus Corp (ERF) 2018 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Enerplus Year-end Results Conference Call. (Operator Instructions) This call is being recorded on Friday, February 22, 2019. I would now like to turn the conference over to Drew Mair. Please go ahead.

Thank you, operator, and good morning, everyone. Thanks for joining the call. Before we get started, please take note of the advisories located at the end of the today's news release. These advisories describe the forward-looking information, non-GAAP information and oil and gas terms referenced today as well as the risk factors and assumptions relevant to this discussion. Our financials have been prepared in accordance with U.S. GAAP. All discussions of production volumes today are on a gross company working-interest basis, and all financial figures are in Canadian dollars, unless otherwise specified.

I'm here this morning with Ian Dundas, our President and Chief Executive Officer; Jodi Jenson Labrie, Senior VP and Chief Financial Officer; Ray Daniels, Senior VP Operations; Shaina Morihira, VP Finance; and Garth Doll, VP Marketing. Following our discussions we will open the call for questions. With that, I'll turn it over to Ian.

Thanks, Drew. And thanks to all of you for joining us today. I'll start by sharing some thoughts on our 2018 results released this morning before moving onto our plans for 2019, the deals of which -- the details of which we released to the market a few weeks ago.

We had strong results across the company in 2018, which we believe demonstrate our commitment to creating value for our stockholders. We have designed a capital program focused on maximizing returns, which position the company to generate free cash flow and competitive growth, while ensuring we retained our financial strength. We believe that our full year results screen very well relative to these objectives.

We generated a return on capital employed in excess of 20%. We delivered 22% liquids production growth, the high end of our guidance range. We increased our annual adjusted funds flow by 44%, which drove $160 million in free cash flow, and we returned a portion of that free cash flow to our investors through dividends and stock buybacks, which totaled over $100 million over the course of the year. In addition, we maintained our best-in-class balance sheet, ending the year with a net debt-to-adjusted funds flow ratio of 0.4x.

This morning we also released our 2018 reserves performance. We replaced 194% of our 2018 production through 2P reserve additions, including revisions and economic factors at a competitive finding and development costs of $13.74 per BOE. At an asset level, we replaced 244% of North Dakota production on a 2P-reserves basis. Overall, we grew our 2P reserves by 8% with oil reserves growing 9%.

In summary, 2018 was another year of differentiated execution for Enerplus, and I'd like to take a moment to thank our dedicated team for delivering these results.

As we turn our focus to 2019, our framework for value creation remains unchanged. We continue to prioritize reserved returns, capital efficiency improvements and positioning the business for enhanced free cash flow and return of capital to shareholders.

2019 capital budget of between $565 million to $635 million is expected to generate a double-digit return on capital employed and competitive production growth, while operating within cash flow at $50 per barrel for West Texas. As we proved in 2018, we will prioritize our ability to generate free cash flow at oil prices above $50 rather than chasing incremental growth. At our current market valuation, we continue to see the repurchase of our own stock as a compelling investment opportunity.

Lastly, in connection with our 2019 budget, we also provided an outlook through 2021 underpinned by the same principles; returns-focused capital allocation, largely directed to our high-margin Bakken oil asset, which sets up approximately 10% to 13% annual liquids production growth corporately. This plan positions the company to generate enhanced free cash flow with the outlook expected to be cash flow neutral at $50 for West Texas and the potential for meaningful free cash flow generation at higher prices.

I'll now pass the call to Jodi to talk through some of the financial highlights and details on 2019 capital allocation.

Great. Thanks, Ian. Starting with our fourth quarter financial highlights. Our fourth quarter adjusted funds flow was $214 million, resulting in full year 2018 adjusted funds flow of $754 million. With annual capital spending coming in at $594 million, we realized free cash flow of $160 million in 2018. Our fourth quarter adjusted funds flow benefited from a $27 million Alternative Minimum Tax refund that we expect to realize in 2019.

As a reminder, this is related to the 2017 U.S. tax legislation change, which repealed the Alternative Minimum Tax. We've previously indicated that we expect to receive a cash refund of just over $100 million between the years 2018 and 2021 related to this.

Last year, we recognized half of this or $50 million and with the addition of $27 million was realized in the fourth quarter of 2018, we have approximately $27 million left, which we expect to record in 2019 and 2020.

Moving onto differentials. Our Bakken differential widened in the fourth quarter to USD 5.60 per barrel below WTI. As we mentioned during our third quarter in November, we believe that the weaker Bakken pricing in the fourth quarter was primarily a function of significant refinery maintenance, which temporarily reduced demand for Bakken oil.

As refineries came back online throughout December and January, we saw the bid for Bakken barrel strengthened and the differential has now significantly tightened with Bakken index prices trading between USD 1 to USD 2 per barrel below WTI.

In terms of (inaudible) Bakken differential risk, we have 16,000 barrels per day of fixed physical sales in place for 2019 at USD 3 per barrel below WTI, and we have recently added about 3,500 barrels per day of firm capacity on the DAPL pipeline, which gives us direct access to the U.S. Gulf Coast and waterborne markets. So in total, that's just under 20,000 barrels per day at either fixed differentials or with exposure to Gulf Coast pricing in 2019. As a result, we have guided to a 2019 realized Bakken differential of USD 4 per barrel below WTI. Generally, we continue to believe that the Bakken is in an advantageous position in terms of pipeline optionality and rail infrastructure, especially given the potential for existing pipe expansions as well as new pipelines in the basin. This should all help keep Bakken differentials in a competitive range longer term.

In the Marcellus, natural gas pricing improved to USD 0.34 per Mcf below NYMEX in the fourth quarter, this led to a full year 2018 realized differential for Enerplus of USD 0.43 per Mcf below NYMEX. That represents an improvement of just over USD 0.30 per Mcf year-over-year. We continue to expect our realized Marcellus differential to improve in 2019 as a result of the significant pipeline capacity that was added during 2018 and are guiding to a realized differential of USD 0.30 per Mcf below NYMEX in 2019.

We do expect there to be some decent shape to our Marcellus differential this year. However, we have increased exposure to the TZ6 non-New York market, which is typically a very strong market in winter, however, more moderate during the summer. As a result, we are expecting strong first quarter Marcellus pricing with realizations moderating during the remainder of the year.

Moving onto 2019 capital allocation. Our spending will once again largely directed to the Bakken, where we are running 2 rigs throughout most of the year. Although, there is a short period where we are running 3 rigs before laying 1 down. The number of completions is expected to be fairly similar to 2018 levels and, although, production growth is expected to be more back-half weighted, capital spending will be more heavily weighted to the first 3 quarters and a lighter Q4 spend.

Outside of the Bakken, approximately 15% of 2019 capital will be allocated across the Marcellus and Canadian water floods and about 5% to the DJ Basin. We have recently signed an agreement for third-party gas processing at a new-build facility in the DJ Basin. The third-party gas plant is expected to be operational late in 2019, and we have no minimum financial commitments associated with this agreement. Our capital spending in the DJ Basin will be allocated toward drilling 5 gross wells to further delineate our position and hold acreage. We also plan to lay a gathering system to tie in existing and future wells to the third-party gas plant. And lastly, we have bought back approximately $7 million worth of our common shares to date in 2019, and plan to renew our normal course issuer bid with the Toronto Stock Exchange for 7% of the public float when the existing term expires in March 2019. With that, I will pass the call back to Ian.

Thanks, Jodi. So in closing, we remain well positioned to build on our success in 2018, underpinned by our financial strength and capital efficient assets. We will continue to generate strong corporate-level returns and a competitive high-margin oil growth, while positioning the company for enhanced free cash flow and to continue return of capital to shareholders.

Thank you for listening. With that, we will now turn the call over to the operator and open it up for any questions you might have.

(Operator Instructions) The first question is from Neal Dingmann from SunTrust.

Ian, my question is, how do you weigh the shareholder return? You guys have been fairly aggressive on shareholder repurchase versus, again, now that Bakken dips have improved, it looks like you all are still taking a pretty conservative route given all the wells that you have drilled. And obviously, as you mentioned in your release, the sort of conservative completion schedule that you have not only for 4Q but for 1Q. So really just wondering how you sort of weigh those 2 things against each other in today's market.

All right. Neal, so capital, dips, share buybacks, like the whole thing? Is that what your question is?

Yes, really just comparing -- I guess, it would come down to how do you compare maybe -- you guys were in such a fantastic financial shape, commodities have improved a bit. So how do you sort of compare either stepping up buyback versus stepping up activity?

Sure, yes. Thank you for that question. I guess balance is a key word I'd like people to think about. Today, it looks great and December 24 was sort of crummy, if you recall. So we're trying to maintain some balance in this. When we look at the plan right now, I think it's really pretty darn resilient. We've given a range of capital there, would not expect it to move very much in a 45 to 60 kind of world. You start living in the 40 range for a while. We certainly have flexibility to keep spending, but we'd be thinking about economics pretty carefully in that kind of an environment. Trying to decide whether slowing down might be a better way to maximize value. You start to get up through the 60s, I think you might be -- we're past the 50s into 60s, you might be dealing with inflationary pressures that we're not experiencing right now. So really like the growth profile that we're delivering. It's competitive, it's sustainable, and a little bit of extra cash flow where a lot of extra cash flow, my first thought is, not to put that into the ground. Relative to other capital allocation choices, I'm quite comfortable putting that on the balance sheet right now. I mean, that's what we have been doing for quite some time. We have been building our cash position, but we do see value in the stock. And so again, balance is a pretty good way to think about it. We started to buy stock last year. We started to buy stock before we were free cash flow positive, levering off the balance sheet a little bit. Obviously, in the fourth quarter where we had a lot of free cash flow and a bit of a weak stock price, we put a fair amount of that cash against stock buyback. So I guess, the concept will be one of sort of continuing the same kind of plan we have right now. I don't see putting all of our free cash flow against share buybacks, I don't know that that's a balanced plan. But as Jodi highlighted, we actually bought a little bit of stock in January, and in January, we weren't free cash flow positive. Feeling pretty good about how things are looking at this moment, but we are expecting volatility as -- and I think we should all do. Hopefully, that gives you a feel for it.

It does. And then the other sort of weighing question is, you continue to say you're looking at acquisitions, but that versus I know a lot of your offset operators, peers are definitely more aggressive than you all when it comes to how many locations per DSU, I mean, you guys continue to be, I think, around 10 versus some, I don't want to say closer to 15 or more. So my question would be, how do you weigh going to buy something versus if others seem to be putting a lot more value just end up selling to them versus buying something else?

Yes. Ultimate development scenario, visions of my development scenarios evolve over time, don't they? We've been pretty steady with ours, although it has been increasing over time. We've never had to walk something back, which sort of feels pretty good to us. In terms of the acquisition market out there and what people say and what they believe and what they're developing and all those good wonderful things, I think there is probably more balance due in the market as to how far you really go in some of these areas, certainly, that would be where the A&D market is. We certainly pay attention to opportunities in the marketplace, and if there is things in our backyard where we think that we can make money doing that, we'll take a look at it. And we think as everyone knows it's been a pretty difficult A&D market for a quite some time, very, very high centered. And so we have a very, very rigid disciplined approach to thinking about how we would bring something in. Value is one of those factors, affordability is one of those factors, accretion is one of those factors. So the thing I think I like people to really sort of remind themselves on -- or remind themselves of, yes, we've got this 3-year plan out there that delivers double-digit oil growth and that all anchors on our existing asset. So we'll be patient, we'll look and we'll see if there's something that makes sense.

Your next question is from Greg Pardy from RBC Capital Markets.

Strong finish to a nice year. Just really 2 questions. One had to do with just, I guess, how you're -- how you're thinking about your nonop production in the Bakken right now. Can you remind us how large that is? And in the past, you've certainly looked to sell that down. I mean, is something like that possible as well as you go forward?

So -- for people who might not remember, a very high percentage of operated production, if you go back a couple of years, we were in the 90-ish percent range. But we did have a -- call it, almost 10% of our land was nonoperated then and we sold that. Operators became more aggressive approach to it, it began from a very small thing to a larger thing and we sold that. We -- in fact, we would've told you, we sold all of our nonop, everything. And yet today, we've got nonoperated production. That is largely coming from lease line wells, right? And so guys on other side or people on other side of the lease line proposed they drill, some of them becomes nonop in connection with that. And so selling those things is not quite as simple as it was before. And so that number, 2,000 to 3,000 barrels, and it's been growing and we expect it will continue to grow. When we think about our capital range this year, it's a little bit wider than it has been percentage-wise. And part of that is it gives us a bit of flexibility for planning for nonoperated spend out there, which -- it's a bit hard to call, not everyone's balance sheet is as strong as ours, and we have a range of nonoperated assumptions. So I guess, the story out of all of that is, it's not as likely to sell as it has been. But the teams do look at this thing, they look at swaps and those sorts of things as well. But it's a number, it's a number.

Okay, great. And the second one, just technically with the reserve reconciliations. So FDC was -- the change in FDC was a pretty big number. Can you just walk us through the -- how that kind of came about the $300 million?

Yes. So most of the capital is obviously associated with North Dakota. I mean, those are -- still the sort of the big numbers. So the FDC changed there. We would've drilled 40 wells and we would have added 40 wells onto the books. We -- so -- and maybe a few more, I suppose. And so the net increase probably mostly associated with North Dakota additional UDs. A little bit associated with the DJ, although, it's a very small number right now. FX moves around a little bit also like -- we report in Canadian dollars and most of our capital is in the U.S. So those are single biggest thing. But I think it's important to frame it. Yes, we would have, in CAD, $2 billion of FDC on the books, that's like 3.5 years of our capital. It's a very, very small number compared to most of our peers.

Your next question is from Patrick O'Rourke from AltaCorp.

Just a few quick questions here. First, you've had a chance to slow down a little bit in the Bakken over the last, call it, 4 months here. Just curious if you guys have a view on what the base decline on that asset alone would be right now?

Yes, it would be -- again, it depends on the moment in time you're measuring that. But high 30s, low 40s. Corporately, we are a [squidge] above 30s how we would think about it with the Bakken. I use 40, is a sort of a round number for North Dakota.

Okay. And then just wondering, in terms of the reserves here, the future bookings, just wondering the treatment -- a lot of it was step out single wells originally, now you're coming back to pads and such. Just wondering in terms of the -- how the reserve engineers are treating that parent-child relationship on the bookings for the EURs.

I'd say the methodology has been actually quite consistent over the years. We have a perspective on recovery factor that is unit-by-unit and have a lot of data in place -- a lot of control relative to our [own place inside]. So it's recovery-factor driven. As we have been positioning over time for higher-density bookings, you've got to really think about that relationship between the existing well and the future UDs. And so this last year, we would've had, oh, gosh, 8%, 10%. 8%, 10% of our units would be sort of fully drilled. And so in those fully drilled units, we're bringing 10 wells in. And in fact, if you want to get really granular with those lease lines wells I talked about earlier, you actually can have up to 11 in some instances, even 12. We would think those -- of those of being sort of like half a well with lower recoveries on some levels. And so out of all of that comes a governor of EUR, of a recovery factor per unit. And if you're really paying a lot of attention to the reserves, there's a few negative book revisions that showed up in the report. I think context is important there. So the producing reserves went up, the proven reserves went up, but there were a few existing UDs in some of those high-density units, where when you actually look at the amount of oil that we're saying we'll recover in that unit, we had to write down the existing UD, a tiny bit, to make room for the 4 extra wells or the 5 extra wells that were -- we drilled. And then time will tell. Broadly speaking, parent/child, a big issue in the industry. Everything we see says the Bakken's lining up really pretty well in connection with that. And a lot of those parents are performing pretty well and the children look okay, they're taking after mom and dad. So we haven't seen a lot of issues out there. But we've been thinking about this for years, and I think I've been pretty cautious as we brought wells onto the books and pretty cautious as we thought about long-term development scenarios as well.

Okay. And just one kind of capital allocation question here. I know you walked through a scenario earlier where there's a preference for share buybacks over putting additional capital in the ground. But if we walk through a scenario where, perhaps, your stock has a great run and you see less value there, I know you have the 3-year plan but how -- what's your ability to be reactive within the goalposts of 2019? I know there is a delay with pad drilling and kind of getting production on and the steps to get there. But do you have an ability to maybe increase the budget or be reactive if the share price was really strong through the year? And then it, kind of, maybe a view of what the economics in the spot market for services would look like if you could do that?

Yes, thank you for that question. There's a lot going on there. So we have a powerful ability to operationally react, teams have done a spectacular job positioning themselves to move up and down, and you actually saw some of that towards the end of last year where teams were collapsing, we were really having to ensure we didn't overrun our headlights. So the teams are -- have a strong capability. Is the spot market there? Is the service market -- yes, the market is there. In a stronger pricing environment, would it be quite the same extent? It wouldn't be the same, and there'd be some inflationary pressures. But yes, North Dakota's pretty good, and there's some capacity in the systems certainly compared to a lot of basins in the U.S. I think the more important question, though, is strategically, what do we want to do? And so I am not interested in chasing incremental growth. Our stock runs, which I could understand why it would, that's probably telling you people like our plan, and part of the thing they like about -- would like about the plan in that scenario is that we're going to be balanced and we're not going to artificially chase growth. So don't see us needing to do that. The secondary question, though, which is super interesting too is, do we think about valuation of the share price when we think about stock buyback? We do. I think it is an important part of it. Does it mean we would go to completely zero? Yes, we could -- probably could always convince ourselves, we see value in our stock. But we probably wouldn't put as much into it because I think that is part of the equation. And if our best idea in that instance was the balance sheet -- was on the balance sheet. We'd probably also be having a conversation around the dividend level. It's pretty modest right now, and that was by design. In the fullness of time, it may well go up, hopefully, it will because that will mean we've been successful and have built a broader capital base. But if the worst idea we have is to put cash on the balance sheet, that's okay.

(Operator Instructions) We have no further questions at this time. You may proceed.

All right. Thank you, everyone. Appreciate everyone dialing in today. Enjoy your weekend.

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