Enerplus Corp (ERF) 2018 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Enerplus Q2 2018 Results Conference Call. (Operator Instructions) This call is being recorded on Friday, August 10, 2018.

I would now like to turn the conference over to Drew Mair. Please go ahead.

Thank you, operator, and good morning, everyone. Thank you 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 discussion. Our financials have been prepared in accordance with U.S. GAAP. All discussion 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 Vice President and Chief Financial Officer; Ray Daniels, Senior Vice President, Operations; and Shaina Morihira, Vice President Finance. Following our discussion, we will open up the call for questions.

With that, I'll turn the call over to Ian.

Good morning, everyone. Thanks for joining us in the middle of August. Second quarter production was approximately 93,000 BOE per day, 54% liquids. We had given second quarter liquids production guidance of 48,000 to 50,000 barrels per day and ended up just above the high end of that range. The growth in the quarter was all driven by the Bakken. We brought 11 gross operated wells onstream during the quarter, which helped increase North Dakota production by over 10,000 BOE per day compared to the first quarter. We're going to continue to build on this momentum, and there's still meaningful amount of oil growth coming in the second half of the year.

Given the strong well performance we're seeing in the Bakken and higher than forecast production out of the Marcellus, we are increasing our 2018 production guidance to 91,000 to 93,000 BOE per day. This includes an increase to our liquids production guidance to the upper end of the previous range, now 49,000 to 50,000 barrels per day. Based on our increased guidance, our implied second half of 2018 liquids production is approximately 53,000 barrels per day at the midpoint compared to the first half of the year, which averaged approximately 46,000 barrels per day. Adjusted funds flow in the quarter was $174 million.

Through the first 6 months of 2018, our funds flow and capital expenditures have been essentially balanced. As we move through the second half of the year, however, with the higher production levels and strong commodity outlook, we have line of sight to meaningful free cash flow generation. At current strip prices, we see in excess of $100 million in free cash flow after dividends and capital expenditures. Despite this free cash flow visibility, we remain confident that the operational plan we have in place is the right one, and we have no plans to meaningfully increase our activity levels.

We're driving competitive light oil production growth, while generating robust returns on our capital program. And in parallel, we're further enhancing our financial strength, which gives us a lot of flexibility if we see oil prices retreat or may allow us to take advantage of attractive resource capture opportunities. In short, we will remain disciplined with our approach to capital allocation. We have tightened up our capital spending guidance to $585 million which was the upper end of the previous range.

This change reflects some additional non-operated activity in both the Bakken and Marcellus, along with some modest cost pressures we're seeing, which Ray will speak to these items later on. In summary, it was a strong quarter for us, and we remain well positioned relative to our plans this year. We've got a solid growth outlook, and we continue to see supportive regional pricing dynamics for both our Bakken light oil and our Marcellus gas as we move through the rest of the year.

I'll now pass the call to Jodi to talk to some of the financial highlights.

Great. Thanks, Ian. Starting with pricing. Our realized Bakken differential was USD 3.42 per barrel below WTI this quarter, which is in line with our annual guidance of USD 3.50 per barrel below WTI. The tight Bakken differential combined with the strength in WTI and weaker Canadian dollar drove our realized price for oil to CAD 80 per barrel in the quarter. We continue to see the Bakken as well positioned for takeaway. The basin has approximately 1.4 million barrels per day of regional refining demand and pipeline egress capacity as well as another 1.5 million barrels per day of rail loading capacity.

Current Bakken production is approximately 1.25 million barrels per day with around 200,000 currently moving by rail. This leaves around 300,000 barrels per day of available pipeline takeaway within the region plus the additional unutilized rail capacity.

As the spread between WTI and Brent prices increase, it creates significant demand for U.S. light sweet crude to reach export markets. This drives up the price paid for light sweet crude grades in the U.S., and for regions like the Bakken that had ample access to reach those export markets, differentials to WTI should strengthen. This is what happened during June, Brent WTI spreads increased, which drove prices for July Bakken production significantly higher. Since then, Bakken differentials have reverted to more normal levels, and we continue to expect our annual Bakken differential to be USD 3.50 per barrel below WTI.

Turning now to the Marcellus. Our sales price differential averaged USD 0.69 per Mcf below NYMEX in the second quarter. This was wider than both the first quarter and our 2018 average guidance of USD 0.40 per Mcf below NYMEX. The wider differential was largely anticipated and was a result of seasonality and certain pipeline maintenance issues. Despite the weaker second quarter differential, we are maintaining our 2018 Marcellus differential guidance. Today, cash prices in the Northeast Pennsylvania region are strong, given the hot weather. Also, the Atlantic Sunrise pipeline, which is 1.7 Bcf a day, is expected to be in full service later this month, which should help support realized prices going forward. Looking ahead, Marcellus Leidy differentials to NYMEX for this winter are continuing to tighten and are currently trading around USD 0.40 per Mcf below NYMEX.

Moving onto our cost structure. We continue to remain on track. There was no change to our operating and transportation cost guidance, and we reduced our cash G&A guidance by $0.10 to $1.55 per BOE. Lastly, on the balance sheet, we made a USD 22 million principal repayment on our 2009 senior notes during the second quarter. At June 30, our total debt net of cash was $312 million, and our trailing net debt to adjusted funds flow was 0.5x.

I'll now turn the call over to Ray.

Thanks, Jodi. We saw some strong operational results during the quarter. In North Dakota, we brought 11 gross operated wells on production at the Cats and Metals North pads, which are centrally located at the South end of our acreage footprint of Fort Berthold. At Cats, we brought 6 wells on production, 4 Bakken and 2 Three Forks wells. Peak consecutive 30-day rates on the 6 Cats wells averaged over 2,000 barrels of oil equivalent per day. At Metals North, we brought 5 wells on production, 3 Bakken and 2 Three Forks wells. Peak consecutive 30-day rates on the 5 Metals North wells averaged just under 1,700 barrels of oil equivalent per day.

Through the first half of 2018, we brought 16 net wells onstream in North Dakota. And in the back half of the year, we expect to bring another 20 net wells on. These wells will come onstream during Q3 and into early Q4. As a result, our capital spending in the second half of the year will be third quarter weighted.

We did tighten our capital spending guidance to $585 million, which is the higher end of our initial range. The reason for this is predominantly due to some additional non-operated and higher working interest wells that have come into the forecast in the second half of the year in both North Dakota and the Marcellus. In addition, we are seeing a little cost pressure in North Dakota, primarily related to steel costs. But we've also chosen to secure availability of a cold shipping unit and water transport to ensure we remain nimble on execution, which has added some costs. However, in terms of real cost inflation, we're still not seeing anything too significant.

In the Marcellus, production was down 3% from the previous quarter, largely due to pipeline maintenance and seasonally weaker gas pricing. We've participated in just over 3 net wells brought onstream in the Marcellus in the first half of the year and expect a similar number of onstreams in the second half.

Lastly, a brief update on the DJ Basin. We've drilled and completed 4 gross wells in 2018, in addition to the Maple well that we drilled last year. A brief update on the Maple well. It has now produced approximately 100,000 barrels of oil equivalent or around 85,000 barrels of oil in approximately 10 months on production. We continue to be encouraged by these results. The 4 recently completed wells are all now flowing back. Given the limited run time, there isn't much to add except that we will update the market in due course.

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

Thanks, Ray. I'll just conclude by reiterating that we plan to continue to build on the strong operating momentum, and we look forward to delivering a solid second quarter -- second half of the year.

And so with that, I will turn the call over to the operator. And we will be ready for your questions.

(Operator Instructions) Your first question comes from Neal Dingmann, SunTrust.

Nice details and good quarter. Drew, a quick question for you. Could you talk a bit about your choke and artificial lift philosophy on these Bakken wells? I mean, really, I guess, what I'm getting at is your view of trying to boost initial IPs either through the choke or artificial lift because again, to me, it appears your wells are as good, if not better, than most in your general area. But as you and I've seen, there's been some sort of crazy IPs out there as well in the Bakken. So just want to hear around your philosophy.

Thanks for the question, Neal. I think actually I'll have Ray answer that question.

So yes -- so we don't aggressively pull on the wells initially. Our goal is to maximize deliverability over the first 6 months without jeopardizing reservoir integrity of the facilities or safety. Other constraints, of course, when we bring big wells on, are the size of the facilities and we don't want to have any unnecessary flaring. As we move out of IP30 into sort of the IP60 range, we would put on artificial lift, and we're actually testing some submersible pumps right now, and we'll be monitoring their performance through Q3. We will be balancing sort of near-term deliverability with cost to make sure we're optimizing our economics.

Very good. And one more, if I could. Could you just talk about sort of any M&A as far as bolt-ons or anything that you guys are looking at, particularly in the Bakken?

Yes, thanks, Neal. Yes, I mean I guess we've been trying to be pretty clear with people, the balance sheet is very strong. And so that certainly gives us financial flexibility to think about those sorts of things. Inventory expansion in North Dakota would make a lot of sense for us on many levels. And when we think about the market over time, we think there's a good chance there will be opportunities there. Today, it's not a hung market. There are a few things happening, but it is not highly liquid. I think people -- probably most people understand that. You've got public companies with some limited access to equity, some of the incumbents have maybe shifted their focus to other plays.

So from our perspective, we pay attention to everything that happens in our core area. At a high level, we'd be looking for things that have a really good operational fit, maybe the -- one of the overriding -- the most important overriding principle is we're looking for things we're able -- line of sight to adding good shareholder value on -- and that doesn't just mean attractive projects; like that's on a full cycle corporate basis. Maybe a final comment might be the things that we see where we get more interested in are things that typically have a higher undeveloped component than a producing component. So we're paying attention to the stuff, but like a lot of basins, there's not a lot of stuff clearing right now.

Your next question comes from Patrick O'Rourke, AltaCorp Capital.

Excellent results on that Cat pad. I was just wondering if you could maybe give us a little color. It looks sort of in line with the results that you'd seen from the Snakes Pad previously in 2017. At that time, you'd talked about 1,250 feet -- pounds per foot being an average, but testing up to 2,000 pounds per foot. Just wondering, with this Cats pad, you've had the good result, maybe give us a little bit of color on how the wells were completed and the proppant intensity?

Sure, Patrick. I think, I'll -- again, I'll have Ray speak to that.

Yes, Patrick, we did proppant loading on the Cats pad, we put a higher proppant loading into the Bakken, a lower proppant loading into the Three Forks to balance cost and optimize deliverability. And there is also good -- we're pleased with what we're seeing. And that work was based on all of the analysis that was done in the basin wells to make sure that we are maximizing the economics of these wells. But so yes, higher loading in the Bakken and lower loading on the Three Forks.

So would you be reaching up to that 2,000 pound per foot level with some of the higher loaded wells?

Yes. We were putting 1,400 pounds per foot in the Bakken and 600 down in the Three Forks.

Okay. And then just a second question, maybe more top-down on the business. You're talking about free cash flow here in the second half of the year, but also being acquisitive and there is 3 places where free cash flow can go to, debt repayment, potentially a dividend increase or share buybacks. And just thinking about balance sheet being one of your key assets that you have right now, how you think about keeping your powder dry versus maybe creating some of those returns on capital to shareholders?

Yes. It's nice to have options. If you sort of go through the list -- we really like the capital program right now. It's giving strong growth, attractive returns. We might -- we'll, obviously, play at the edges of that as that makes sense, but strategically, we're not interested in driving more growth there. So when you think about those other toggles that you've highlighted, inventory, share buybacks, dividend increase, the most interesting thing for us now strategically when we think about the market and everything at this moment is inventory increase.

And so how do we think -- we clearly think balance sheet is a distinguishing competitive advantage for us, which will allow us to do things to move us forward. Share buybacks, dividends -- share buybacks, we've tried to be pretty clear with. We have a price that is monitored on a realtime kind of basis. And if we hit that price and the conditions makes sense at that moment, absolutely, we'll do that. Dividends, today, the model is supporting robust growth, highly sustainable, and we see line of sights to a lot of free cash flow. Again, it hasn't happened yet, but line of sight to a lot of free cash flow.

And we have a modest dividend, which is in place strategically. Over time, conditions may change. And as they change, we'll assess whether a dividend increase makes sense. But at this moment, dividend -- the growth is trumping dividend. Does that help you out?

Yes, I guess, takeaway would be that staying under levered is a strategic advantage, if your primary target's being acquisitive on inventory for now?

Yes. We could over beers talk about what under levered means. I really like where we are right now. We're -- if you sort of run us forward over the next year, we go debt-free under the strip. We don't need to be debt free. I think we've all learned lessons about the value of balance sheet as we've come through this crisis, and we certainly expect more volatility to occur. So our strategy is to maintain a -- is to maintain relative balance sheet strength compared to (inaudible). That being said, we could move the balance sheet a bit and still be in a really, really good place. So I'm very comfortable being patient and very comfortable keeping our powder dry as we look for opportunities to expand inventory. And -- those can come in lots of different ways, and we have lots of time for this.

So we're not talking a lot about the DJ because it seems premature to do that. But fast forward on that play with strong well results, we will go spend money there. And having the balance sheet to do that, to be able to think about what the appropriate midstream solution is, all of those kinds of things that balance sheet is a very, very powerful tool that we can use. The right answer for our business today is underspending cash flow. But if the right answer was to overspend cash flow and we could afford it and we had cash on the balance sheet to do it, I want to be in a position to do that for people.

Your next question comes from Tom Callaghan, RBC.

It's actually Greg Pardy standing in for Tom. Just a couple of questions then. Maybe just to revisit the -- just the Cats area, I mean, just as a follow-up to the other question that was asked. How much running room do you have there in the broader area, just inventory wise?

Maybe just -- if we just step back for a sec. We talk about approximately 500 locations -- undrilled locations. We talk about a range of type curves. I think it was Patrick that talked about this looks like the Snakes Pad. This looks good. This was an area -- this is an area that we've -- have -- had anticipated being good, which we said on the last call and it is doing well, maybe a little bit ahead of expectations, but it's doing well. We wouldn't think this would be the best of the best of the best in our area, but it's maybe better than average. So yes, we've got running room, we've got more pads like this. This is maybe in an area that's better than average, but not the best of the best. Ray, would you add something to that or?

Not really. I mean, it's a good area. We've got adjacent land down there. It's probably 4 or 5 pads that we've got down there.

Great. And then, look, I know, it's August and you're probably just commencing your budgeting and so on. But how would you frame 2019 maybe from an activity standpoint just broadly? I mean, just given the exit rates that we're now looking at, looks like you'll be somewhere around 100,000, I would think, BOE a day next year, but is that directionally the right way to think about your business or is it just too early?

I'm not going to comment on that number, but...

Oh, come on, Ian.

Okay, Tom. We have put out a 3-year plan that drives our liquids growth at a 20% CAGR, and we are executing that well. So as you roll that forward into next year, we see more growth on our oil, and that directionally has more onstreams than this year and that should tie to more capital. The things that could move us around would be things like the DJ. Do we spend money on the DJ, how much does that look like, things along those lines. And out of that, we haven't put a number behind it, but think about that 20% liquids growth running forward into next year on some kind of level, and that's going to continue to support the model we put forward. We'll run that forward. Probably Q3 we'll tighten that up for people. At the margin, you can see non-operated spending moving around a little bit here and there. The Bakken asset is, it's high, high working interest, high, high degree of operatorship. But we are seeing a little bit of stuff creep into the non-op side, which is moving our numbers around at the edges.

Okay. And just remind me, I think, it's about 2,000 -- it's back to 2,000 BOE a day did you mention?

That's a decent number to think about.

Okay.

And maybe -- sorry, Greg, maybe one more thing on that. So as you think about the model and it sort of comes back to some earlier comments I made, when we rolled out our budget this year, the plan that we thought made the most sense was one that actually had us spending -- sort of spending our cash flow when oil was $50. And that model -- that plan had been in place when oil was $47 and that plan was in place when oil was $60. So as we think about next year, if you got a price deck within between $47 and $65, like we're going to have very, very similar activity levels. And in one scenario, there would be meaningful free cash flow and in the other one, we'd be sort of spending within. So we'll see how it lines up as we're -- as we finalize those things.

Your next question comes from Travis Wood, National Bank.

Yes, very quick question, just related, I know you want to be reasonably quiet with too little to say around the DJ. But on the cost side, you've kind of been guiding to that $6 million, $7 million range with these -- with now 5 wells down for just the late stages of completion. Can you give us a sense of how these wells are comparing to your, what seems to be a bit of a conservative guidance number?

So $7 million is not a bad number to think about for these wells. And there -- you really need to think about them as being one-offy related. I think, if we -- based on what we know today, if we were running a program with more pad development, we'd be raising AFEs probably closer to $6 million, that'd be the thinking. And the goal would be to find yourself in a sub-$6 million moving closer to $5 million kind of range with some of the big questions being, what is the appropriate completion design. If you look at competitor activity, yes, there's places where there's few companies out there who are run pretty hard and have been able to go sub-$5 million. We've seen line of sight to things that could be in the mid-4s, now that would be with the smaller completion.

And so is that the right economic answer, don't know. But I'd say, this is clearly a play where costs are going to matter; it's a very, very, very high netback, very interesting on many levels. As Ray said, Maple is encouraging for us right now. And one of those questions will be certainly as you get your head around well performance, understanding the cost profile for next year is going to be pretty important. But the scope of the program is going to matter for that. It really will matter, you see that on the facility side, in particular.

Okay. And then Ray, you had mentioned, I missed the net or gross you had talked about, bringing on 20 Bakken wells through the second half. Was that a gross number or a net number?

It was a net number and they weren't all in the Bakken, but they were in Fort Berthold.

Okay. And then, can we -- kind of thinking of the profile into next year with the robust capital spend in Q3, a bit of tail-off in Q4 and these wells coming on through the back end of Q3, into Q4, can we think about sequential growth here for the third quarter at least relatively flat with a steeper profile through the back half to hit the guidance numbers?

Thinking about whether we roll out monthly forecast, that's not a bad way to think about it, Travis. You mean, it's -- we see a relatively steady program. Obviously, this is all with the pace of onstreams. And with the pads, we're talking about, you can get a little bit lumpy, but in other quarters where we've anticipated big dips or big changes or those kinds of things we've guided to that, that's not how we see this. So sequential steady-ish over the back half of the year is a good way to think about it. And again, we're talking about [oil here].

(Operator Instructions) Your next question comes from Brian Kristjansen, Macquarie.

Ian, I had a question about, if you could quantify the impact on your acreage position in Colorado if these well setbacks get extended?

Prop 97. Yes, thanks for that question, Brian. So for those who aren't aware, Prop 97 Colorado initiative that could be significant for industry out there, lots of commentary as to why it can't happen in the form proposed because of that. But to answer your question specifically, if it was enacted and legislated as proposed, it would have a big impact generally. For existing operators, there'd be a bit of a mixed impact. So for us, as we understand it, existing permits are exempt from this. By the end of the year, we'll have about 160 permits.

So I guess, that would provide quite a bit of insulation for us. It would be quite helpful for us and those who are in a pretty good place relative to permits. I mean, we can get into all the reasons why this thing sort of can't go ahead in exactly the former fashion, but we've been well aware of this issue for a long time and have been managing our exposures and again, moving quite aggressively on the permitting front in part to help manage some of these risks.

Okay. The 2,500 foot setback, that wouldn't sterilize anything materially...

We're -- we -- so we're in Weld County, and if that all went forward, large, large, large percentages of Weld County would be sterilized. Specific to where we're focusing our efforts and our permitting activities, we'd be quite meaningfully protected because of the permitting that we have in place.

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

All right. Well, we'll leave it at that. Again, thank you very much for dialing in. I know it's the end of the reporting season, and hope everyone enjoys the remainder of their summer. Thank you very much.

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