Enerplus Corp (ERF) 2018 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Enerplus Corporation Third Quarter 2018 Results Conference Call. (Operator Instructions) This call is being recorded on Friday, November 9, 2018.

I would now like to turn the call over to Mr. Drew Mair, Manager Investor Relations. 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 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 discussions.

Our financials have been prepared in accordance with U.S. GAAP. All discussion sort 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 Operating Officer; Jodi Jenson Labrie, Senior Vice President and Chief Financial Officer; Ray Daniels, Senior Vice President Operations; Shaina Morihira, Vice President Finance; and Garth Doll, Manager Marketing.

Following our discussion, we will open up the call for questions.

With that, I'll turn it over to Ian.

Thanks, Drew. Good morning, everyone, and thanks, for joining us today. I'll drive right into our third quarter results.

Quarterly production was up 4% sequentially and 22% from the same period 1 year ago. However, the real story is over oil growth, which is where 90% of our capital is allocated. Quarterly oil production was up 8% sequentially and almost 40% from 1 year ago.

Our capital program in the fourth quarter is largely focused on drilling in North Dakota in preparation for the 2019 program and with only modest completion activity. However, we still expect to see flat to modest growth for oil production as we close out the year.

We've tightened up our production guidance to the high end of the range. We anticipate annual production of 92,500 to 93,000 BOE per day, with liquids production 49,500 to 50,000 barrels per day.

Importantly, our capital budget remains on track and unchanged at $585 million. We have visibility to meaningful cash -- free cash flow in the fourth quarter, and expect to allocate a portion of this to continue repurchasing our shares. In September and October, we repurchased $25 million in stock and we see a compelling capital allocation opportunity in continuing down this path.

Operationally, we continue to demonstrate strong well performance and capital efficiencies across our plays, particularly in the Bakken. We brought 18 wells on production at the Bakken during the quarter with average peak 30-day rates of over 1,500 BOE per day per well.

In our press release this morning, we provided some encouraging results from our emerging asset in the DJ Basin. It's worth highlighting that we acquired our position in the DJ for a few hundred dollars per acre. And therefore, have only modest capital exposed to play. In addition, our land position in Colorado is removed from urban areas, which we believe expose us to less regulatory uncertainty.

With the positive well results we're seeing and with the defeat of Proposition 112, we're planning to continue delineating our position and have line of sight to competitive development economics. Given our modest entry cost in the play, we see strong value-creation potential here.

And with that, I will now pass the call to Jodi, to talk through some of the financials and marketing highlights.

Great. Thanks, Ian. We generated adjusted fund flow of $210 million in the third quarter compared to $193 million in CapEx. And as Ian mentioned previously, we expect strong free cash flow generation in the fourth quarter given the lighter capital spending forecast. In terms of priorities for this free cash flow, we anticipate being active in continuing to buy back shares under our normal course issuer bid.

Moving on to realize pricing, Bakken differentials have been very topical of late. Our realized Bakken differential in the third quarter was very attractive at USD 2.54 per barrel below WTI. However, Bakken differentials began to widen in October, and we have seen substantial volatility. We believe this is largely transitory, and primarily a function of significant seasonal refinery maintenance, the level of which is double -- is about double the norm that -- for this time of year. We also believe that as the refinery starts to come back to online, we will see differentials improve from current -- levels currently seen in the spot market. Given where we've seen December Bakken production trade to date, we expect our fourth quarter Bakken differentials to come in around USD 6 per barrel below WTI. Our fixed physical differential sales on approximately 20,000 barrels per day at around USD 2.50 per barrel below WTI have meaningfully reduced our exposure to the current weakness in spot prices. The wider fourth quarter Bakken differential has resulted in a slightly wider full year differential forecast of $3.80 per barrel below WTI.

Production growth in the basin has been higher this year than we had initially forecast, and this is causing takeaway to get tighter. But the Bakken continues to be in an advantageous position in terms of pipeline optionality and rail infrastructure. In addition, we expect to see the expansion of existing pipeline capacity and potentially, new pipelines in the basin. This should all help keep Bakken differentials in a competitive range longer term.

We also think some of the Bakken supply forecast in the market are too aggressive. Our work points to Bakken production growing by approximately 125,000 barrels per day, year-over-year in 2019, to average about 1.4 million barrels per day. So while this growth will add to the tightness, directionally, we think our 2019 realized Bakken differential will be approximately USD 1 per barrel wider than what we expect to average in 2018.

We've also recently added to our 2019 Bakken fixed physical sales and we now have around 16,000 barrels per day fixed, at a differential of about USD 3 per barrel below WTI for 2019.

Moving on to the gas side. Our Marcellus differential in the quarter was USD 0.48 per Mcf below NYMEX. And we expect to see this tighten further in the fourth quarter, as the Atlantic Sunrise pipeline began slowing in early October. The spot market in the Marcellus is very strong today, due largely to low storage balances in the region heading into the winter. Leidy cash prices have averaged around USD 3 per Mcf, so for this month, and are now trading near USD 3.65 per Mcf. With current spot prices in the Transco Z 6 non-New York market trading near USD 4 per Mcf.

We anticipate this strength to continue through the end of the year.

As a result, we expect our realized Marcellus basis differentials for the fourth quarter will average USD 0.30 per Mcf below NYMEX or better, and are maintaining our 2018 Marcellus differential guidance of USD 0.40 per Mcf below NYMEX for the entire year.

I'll now turn the call over to Ray.

Thanks, Jodi. North Dakota volumes were up 7% quarter-over-quarter and almost 60% year-on-year. This significant growth has been driven by consistently strong well performance across our concentrated position at Fort Berthold. In the third quarter, we had several wells with peak consecutive 30-day production rates of over 2,000 barrels of oil equivalent per day.

We continue to focus on maximizing economics and improving capital efficiencies. And as a result, we are constantly tailoring elements of our completions design. This past quarter, we varied proppant intensity from 600 to 1,600 pounds per foot, varied the number of clusters between 5 and 15 per compartment and increased the compartment length to 300 feet on a number of wells.

On the production side, we've begun to test gas lift or ESPs on certain wells before moving to rod and pump. ESPs offer the potential to significantly increase production rates in the first 12-plus months. Results to date have been positive. And the acceleration of production volumes improves well economics. Although, not a uniform solution, we plan to continue to utilize ESPs where appropriate.

Briefly, on gas process -- processing in the Bakken, it is getting tight and we expect it to remain tight until Q2 next year. We continue to manage through the tightness by deploying portable NGL units as needed and don't foresee this impacting our plans in 2019.

Coming to our well results in the DJ Basin. We now have 5 wells in the DJ and the results are encouraging. The Maple well completed in the Codell formation has produced approximately 100,000 barrels of oil in the first of 12 producing months. This number excludes down days when the well was shut for facilities modifications.

The subsequent 4 wells, 3 Codell and 1 Niobrara, brought online in July, are all meeting or tracking above the Maple well and compare favorably to recent wells across the basin.

The Niobrara well was completed in the lower Niobrara B choke and is among the strongest of our DJ wells to date. The Niobrara potentially adds meaningfully to the scope of this asset. And there could be further upside, given the additional Niobrara benches of significant oil saturations. We plan to continue delineation in 2019, along with advancing with stream plans. We will provide more granularity around the capital plans for the DJ with our 2019 budget.

And with that, I'll pass the call back to Ian.

Thanks, Ray. In summary, we remain on track this year to deliver the strong results that our shareholders have come to expect. Looking ahead to 2019, we are well positioned to deliver another year of disciplined returns-focused growth, while maintaining our strong financial capacity.

And so I will now turn the call over to the operator. And we'll open for any questions you may have.

(Operator Instructions) Your first question is from Dennis Fong from Canaccord Genuity.

Just 2 questions here. The first is just on the share repurchases. You, kind of, noted in Q4, obviously, given that you have a breadth of free cash flow at that point in time and you're interested in continuing pursuing that -- the repurchase program. Looking into 2019, how should we think about that? I know you've stated in the past that you, kind of, have a number and valuation metric in mind. And given, kind of, your cash flow profile as well as your current leverage metric, like how should we be thinking about this going forward?

Yes, so when we look at the opportunity now, we really see buying our shares as a highly competitive compelling capital allocation choice that's pretty easy thinking about in the context of free cash flow. As we've said for the long time, we think keeping our eye on share repurchases is a really important thing, as you're thinking about delivering value to shareholders, and we will continue to keep our eye on that. I think we'll frame all of that, as we roll out a comprehensive budget likely towards the end of the year. But it's a tool, we will continue to keep in our toolkit and give people a little more context then.

Perfect. And then, the second question here is just on the differentials and so forth. It sounds like from your prepared remarks that you feel pretty comfortable about the Bakken just, kind of, narrowing where they happen to be, call, in September as refining capacity comes back available. Does that mean that the 16,000 barrels a day in 2019 is something that you're comfortable with? Are you not interested in pursuing anymore in terms of the curing the differentials of WTI on that basis? How should I think about that? And then just secondarily on the hedging program, are you guys comfortable with the just shy of 25,000 barrels a day you have in your three-way collars?

Sure. Dennis, it's Jodi. So we do feel that the current market in the Bakken is overdone with over 1 million barrels a day offline right now in demand. We do believe that once we see the refiners come back on, later in November and into December, we're going to see that differential tighten in. As I mentioned, we have 16,000 barrels a day currently now, most recently added to that, actually, at attractive levels, WTI minus $3 net Bakken. So we would look, if given the opportunity, to add to that. That wouldn't be right now, just given the current spot prices. So I believe, we'd look to add to that going forward. I guess, one other -- your other question was about our three-ways, we're actually feeling quite comfortable with our hedge position. We do have upside, we've protected the downside and we participate in 2019 up to about $65 WTI. So we're comfortable with where we're at with that portion of our hedging program.

Okay, perfect. And then just lastly, if I can sneak in one last one. Now that, kind of, Proposition 112 has been defeated and, kind of, the state of your balance sheet, are you guys looking to, we'll call it, increase your exposure or land position in the Niobrara? How do you feeling about your current land position? And I'll leave at that.

So as we said, we gave people some color today on well results that are encouraging. They also look consistent with Maple, and that -- the Niobrara well is particularly important, given, it gives us another zone to be talking about more resource. Yes, it's nice that 112 is done. I think that's taken a lot of noise out of the system. When we think about that play, I would expect -- or I guess, we plan to allocate some capital now to that play next year to continue to delineation activity. It's early stage, but we could anticipate putting some money into infrastructure next year as well, based on the results we've had to date. In terms of expanding the opportunity set, how comfortable we are positioned? I think like a lot of these things, we've got to really -- we're in a really good position financially that we can do whatever makes sense. And we'll be opportunistic, we'll look for opportunities to expand it. But we've got a pretty good footprint right now that's going to -- have potential to drive some metrics for us.

Your next question is from Neal Dingmann from SunTrust Robinson.

This is actually Jordan. Just wanted to know how you guys are thinking about completing in the Bakken? And how you approach basin, kind of, between the Three Forks and the Bakken? Any if changes have been made there or kind of -- if you're thinking about doing anything differently there. The result of have been really strong. Any color would be great.

So for those who don't know, and we have -- Bakken across the acreage position in first bench of Three Forks everywhere. There's some deeper bench potential in places but typically it's -- if we think about the 2 zones, our base development now, the inventory that we talk about assumes spacing at 6 wells in the Bakken and 3 wells -- sorry, 4 wells in the Three Forks. We sort of view those as single unit on some levels. So 10 wells and a DSU. We've tested tighter, we've watched other people test tighter. We think that's the number that make sense for us. We'll continue to watch. I guess, there's the possibility of going tighter in the Three Forks. We don't see a lot of evidence that says that's the best economic choice right now. So it's not as much basing optimization in our minds now, it's completion optimization. And as Ray talked about in his remarks, a lot of work is going on there relative to moving -- playing within our proppant, playing with per foot clusters, playing with tighter proppant. And I would say, oh gosh, half of our wells were testing and thinking things looking to optimize the economic equation.

Great. And then just, kind of, over to the DJ. And you guys have been happy to results there. Just Kind of, question how you would approach, kind of, Codell versus Niobrara. I know in the press release you guys discuss that you like what you're seeing out of the Niobrara. Just kind of thinking about how you are approaching that as you continue the delineation in the play?

So we -- when we got into the play, I mean, you knew the resource was there in both zones. The Codell and Niobrara, Niobrara being the bigger prize. In our view, the Codell was probably the lower-risk choice initially. And that's why we initially dedicated our capital to the Codell. We've now -- Niobrara, and have been really pretty pleased with what we've seen there, a little bit because how we were thinking about risk initially, and then, obviously, it's -- for those who know, it's a pretty big prize is there in terms of resource. So as we move into next year, I think it'll be fair to assume we'll be advancing both zones. We see pad development that can facilitate testing both at the same time, effectively or off the same pad. And so we'll move forward with some more drilling next year to advance our understanding of both of the zones. We're -- I think, we've transitioned past science project now to something where we see line of sight into development economics, albeit, it is still early stage.

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

Just a couple of quick questions here. First, you mentioned the 16,000 BOE a day, -- pardon me, barrel a day of the Bakken differential that you've locked in for 2019, it's obviously a little bit of slope to that Clearbrook dip right now, when you look at the futures curve. Just wondering, if you can give us a little bit of color, is that 16,000 -- is that a flat throughout the years? Is there any slope? Are you more heavily hedged or locked in for the first half than the second half? Or maybe some color on that structure there.

Patrick, it's Garth. We have a little bit of shape to it, but it's not significant. We've got hedge volumes in place on that, pretty much monthly January through the year, maybe a little bit less in parts of Q1 than we see the rest of the year. But 16,000 is -- it's a pretty good average for the entire year. That's the right way to think of it.

Okay. And then second question. In terms of the Marcellus volume, I know you're non-operated there. But in the past, there's been some, call it, volume behind high probability to capture as differentials improved there. Just wondering, as we head into the winter here, storage is low, if we get some cold weather and we see some really strong northeast gas pricing, do you have the ability or in combination with Chief to increase some of the volumes there and capture that?

No, I don't think you should think about it that way any longer. I mean, there were times where there was a lot behind pipe. Today, we've run through a fair amount of that. If you think about the profile capital in the last year, so it's been pretty modest. And we work through ducts, we work through capacity. And so yes, don't view that into being something that would ramp up dramatically based on a near-term spike. I do think, longer term, if you start to see start to see some real strength in the foremarket and maybe more than just a year, it will be very easy to allocate capital there to start to grow at the higher rate. I don't -- I wouldn't anticipate -- it wouldn't be what we want to do and it hasn't been a practice of our partner at all to react to really near-term changes in the market.

Your next question is from Travis Wood from National Bank Financial.

Three questions here. This first is just around some of the marketing conversation. As you look to get the product to some of the higher netback regions, are you using rail for any of that at the moment?

No, we don't move any of our own crude on rail in our name, but we would consider selling to buyers who have rail capacity. About 70% of our production is sold into the DAPL system at either fixed dips or index pricing.

Okay. And then from a theoretical 2019 capital budget, what -- and especially considering DJ success here, what types of outputs or other more qualitative items are you guys considering right now as you contemplate that capital program and try to decide between -- or more of the allocation between North Dakota and Colorado?

Hypothetical budget? Qualitatively, Travis, it will be similar principles that we've applied for quite a few years. I guess, balance sheet strength is now one that gives us a lot of flexibility. As we think about transitioning into a little more Colorado spend, I mean, don't think Colorado is going to dominate our budget next year, that's just not the nature of it. So there will be spend there to advance the resource, to build for the future, to bring deliverables on, sort of, associate more towards the end of the year than the beginning of the year. We're always focused on having an operational plan that makes a lot of sense, and we're interested in managing our growth and managing economics. So on a lot of levels, you could anticipate, but it could look similar year-on-year. Bend a bit more, allocate some to Colorado, just continue to grow. And we'll put a fine point to all of that stuff specifically as we move through the end of the year and see where oil stabilizes, and all those sorts of things. As Jodi highlighted, we're really in good place from a resiliency perspective to make what we think the right choices here.

Okay. And then from an infrastructure perspective, any issues or constraints, kind of, through 2019 period, that you could anticipate whether it's maybe both processing or egress from that type of perspective in the DJ?

In the DJ, specifically. So for those who don't know, one of the reasons that we were able to acquire this opportunity at such attractive terms and one we did it in a low point in '14 and '15. But it's also area where it's an oil development and you need gas infrastructure and gas infrastructure wasn't in place. I mean, the main trunk lines, the interstates were there, but you didn't have gathering and you didn't have processing. And so now that there's been some interesting well results in the area, there are a series of choices available to producers in terms of dealing with the gas. And I say dealing with a gas, it's actually something where there's an economic value to it as well. Those choices range from Enerplus putting its own capital into a gathering system and a plant to a portion of that, there's some third-party choices available. So those things have to be advanced and that will impact the timing of the spend next year and there is a -- only a, sort of, a stencil pace that you can go on those drilling side. But we'll put a prospective around all of that as we put our whole plan together.

Your next question is from Brian Kristjansen from Macquarie.

Just looking for a bit more granularity on the DJ, either Ray or Ian. How much better was the Niobrara well producing versus the Codell?

Comparable. It was comparable.

Can you give us a sense of what the Niobrara inventory is at this point?

I think it's premature for that. I guess, the only thing I would add is, everywhere we see the Codell, sort of in, sort of, our core area, we see the Niobrara. And I suppose there's a couple of places we see the Niobrara and think it might be a little bit more perspective than the Codell. For the geologists on the call, there is a far thicker package in the Niobrara. And so you have, I guess, the potential for multiple bench. But it sets up the potential for, sort of, a double of where we were on the Codell, and we'll as we get more information but that's sort of what the logs we'll tell you.

All right. And then what do you see as your run -- like your target well costs, and when do you think you'll get there by the end of 2019?

Target well cost, if you look at best-in-class today, people would be talking in the $5 million range, I mean the EOG talks tighter than that or lower than that. But that's our, sort of, feels like best-in-class today, people running full developments. We are not talking about a full development scenario next year, that wouldn't make any sense at all, given where the infrastructure is. So if today, we'd raise an AFE at $7 million, it will be pretty easy to see a $6 million kind of number in full development scenario. So nothing changes, but we go to full developments, we'd be expecting something like $6 million and you have economics that you'd be proud to talk about and the goal, for sure, would be to drive past there as we move forward.

Your next question is from Aaron Swanson from Tudor, Pickering, Holt & Company.

Just a quick question from me. Curious with all the changes in the Bakken completions. What is a good well cost to use at Three Forks and the Bakken. And if it changed at all, it'd be interesting to know?

Still thinking $8 million is a good number. D&C plus infrastructure on top of that. So D&C around $7 million. And that gives you some latitude for a pretty big completion for probably more than a 1,000 pounds per foot. I'd say, as we think about this year versus next year, we're seeing some stability in prices on some levels or costs on some levels, although we do see fracs getting cheaper, sand getting cheaper, drilling maybe a bit more expensive on day rate, little bit of pressure on trucking here and there. So you put it all together and stability is a pretty good way to think about it right now.

Just on the Canada side, you guys have some heavy oil production, are we looking at economics, are you looking at shutting in or is that covered off by hedges or how should we look at that?

We've got a great hedge position. We're rushing -- so we've got a great hedge position in Canada for heavy use. And our -- where we're positioned on our oil and, again, this is 10,000 barrels out of the 50,000, so its relatively modest. But where we're positioned, we're generally getting better pricing as well. So we wouldn't have some of the acute issues that other producers would be facing. And we have talked about shut-ins and those kind of things, we're certainly not doing it right now. And some of that's operational, logistics is based on the nature, the specific nature of our assets under flood and under tertiary. But yes, we're always off the bottom relative to the specifics of our plays and our hedges and our realizations.

(Operator Instructions) Your next question is from Brian from Capital One Securities.

I've just got one, and it's, kind of, an add-on to the DJ commentary. Thanks for the color on the well cost there and what to think about it looking forward. I wondered if -- now that you've got a few more wells under your belt, if you were willing to provide maybe some guidepost for what you were thinking about in terms of IRRs that those wells might provide, as we, kind of, go from 0 to 60 here? Or maybe not quite 60, I know that that's not the plan for next year, Ian, but in these early days what type of rate of return you might be looking for?

I think it's a little premature, we'll frame that out a bit as we roll the program forward. If you want to take a look at our well results and you plot those well results up against core DJ drilling, we're right in the middle of it. And so I think you can extrapolate a fair amount of that what from what others are talking about, that Maple well produced 100,000 barrels of oil in its first 12 producing months, you can fit some kind of curve on that. And with the $50 netback out there, it looks pretty robust. But we'll frame that up a little bit more as we move to the end of the year.

Your next question is from Mike Dunn with GMP FirstEnergy.

Just a follow-up question, folks, on the new DJ Basin wells, were the Codell formation wells, were they -- was the completion and engineering, et cetera fairly consistent with the Maple well horizontal lengths, et cetera? And whether or not you're doing anything materially different with the Niobrara well?

The short answer is, there's consistency amongst all the wells. The longer answer though is, even though it was delineation, we used the opportunity to advance certain -- understanding of certain variables. So we don't move 7 things around from one completion to the next, at this stage of development. But we are learning things as we move forward. They are all bigger, kind of, fracs, high rate, they're [ultimate] oil wells, laterals as well, but there is a consistency to them.

There are no further questions at this time. Please proceed.

All right. Well, appreciate everyone's time. Busy morning for many of you. I appreciate your attention today. Have a good weekend. Cheers.

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