Enerplus Corporation (ERF) Q2 2018 Earnings Conference Call Transcript

Enerplus Corporation (ERF 0.25%)
Q2 2018 Earnings Conference Call
Aug. 10, 2018, 11:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Good morning, ladies and gentlemen, and welcome to the Enerplus Q2 2018 results conference call. At this time, all lines are in listen-only mode. After the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press *0 for the operator. 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.

Drew Mair -- Manager, Investor Relations

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.

Ian C. Dundas -- President and Chief Executive Officer

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. We brought 11 gross operating wells on-stream 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 a 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, 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.

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 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 meaningful 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 the Marcellus, along with some modest cost pressures we're seeing, which Ray will speak to 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.

Jodi Jenson Labrie -- Senior Vice President and Chief Financial Officer

Thanks, Ian. Starting with pricing, our realized Bakken differential was US$3.42 per barrel below WTI this quarter, which is in line with our annual guidance of US$3.50 per barrel below WTI. The tight Bakken differential combined with the strength in WTI, and the Canadian dollar drove our realized price per oil to C$80.00 per barrel in the quarter.

We continue to see the Bakken as well positioned for takeaways. 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 brand 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 have ample access to reach those export markets, differentials to WTI should strengthen. This is what happened during June. Rent 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 US$3.50 per barrel below WTI.

Turning now to the Marcellus. Our sales price differential averaged US$0.69 per Mcf below NYMEX in the second quarter. This was wider than both the first quarter and our 2018 average guidance of US$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 [inaudible] differential to NYMEX for this winter are continuing to tighten and are currently trading around US$0.40 per Mcf below NYMEX.

Moving on to 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 US$22 million principal repayment on our 2009 senior notes during the second quarter. At June 30th, 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.

Raymond J. Daniels -- Senior Vice President, Operations, People & Culture

Thanks, Jodi. We say 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 increased footprint at 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 on-stream in North Dakota, and in the back half of the year, we expect to bring another 20 net wells on. These wells will come on-stream 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-operating and higher working interest wells that have come into the forecast in the second half of the year in both North Dakota and in Marcellus.

In addition, we are seeing a little cost pressure in North Dakota, primarily related to steel costs. But we have also chosen to secure availability of a cold shipping unit and water transport to ensure we remain nimble on execution, which has added some cost. However, in terms of real cost inflation, we're still not seeing anything too significant.

In the Marcellus, production down 3% from the previous quarter largely due to pipeline maintenance and seasonally weaker gas pricing. We participated in just over 3 net wells brought on-stream in the Marcellus in the first half of the year and expect a similar number of on-streams 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. With that, I'll pass back the call to Ian.

Ian C. Dundas -- President and Chief Executive Officer

Thanks, Ray. I'll just conclude by reiterating that we plan to continue to build on this strong operating momentum and we look forward to delivering a solid second half of the year. With that, I will turn the call over to the operator and we will be ready for your questions.

Questions and Answers:

Operator

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Should you have a question, please press * followed by 1 on your touchtone phone. You will hear a three-tone prompt accelerating your request and your questions will be polled in the order they are received. Should you wish to decline from the polling process, please press * followed by 2. If you are using a speakerphone, please lift the handset before pressing any keys.

Your first question comes from Neal Dingham with SunTrust. Neal, Please go ahead.

Neal Dingham -- SunTrust Robinson Humphrey -- Analyst

Good morning, all. Nice details on the quarter. Drew, a quick question for you. Could you talk a bit about your choke and artificial lift philosophy on these Bakken wells? 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 have 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.

Ian C. Dundas -- President and Chief Executive Officer

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

Raymond J. Daniels -- Senior Vice President, Operations, People & Culture

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

Neal Dingham -- SunTrust Robinson Humphrey -- Analyst

Thanks. Very good. 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. Thanks again, Ian.

Ian C. Dundas -- President and Chief Executive Officer

Thanks, Neal. I guess we try 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. 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, folks who 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.

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 one of the most important overriding principle is we're looking for things, line of sight to adding good shareholder value. That doesn't mean attractive projects. 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 end developed 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.

Neal Dingham -- SunTrust Robinson Humphrey -- Analyst

Thank you.

Operator

Thank you. Your next question comes from Patrick O'Rourke, AltaCorp Capital. Patrick, please go ahead.

Patrick O'Rourke -- AltaCorp Capital -- Analyst

Thanks, guys. Good morning. Excellent results on that Cats 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 talked about 1,250 pounds per foot being an average but testing up to 2,000 pounds per foot. Just wondering maybe with this Cats pad where you've had the good results, maybe give us a little bit of color on how the wells were completed and the prop and intensity?

Ian C. Dundas -- President and Chief Executive Officer

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

Raymond J. Daniels -- Senior Vice President, Operations, People & Culture

Patrick, we varied the profit loading on the Cats pad. We put higher profit loading into the Bakken, and lower profit loading into the Three Forks to balance cost and optimize deliverability. There is also good, we're pleased with what we're seeing. That work was based on all of the analysis that was done on the basin wells to make sure that we are maximizing the economics of these wells. Yeah, higher loading in the Bakken and lower loading in the Three Forks.

Patrick O'Rourke -- AltaCorp Capital -- Analyst

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

Raymond J. Daniels -- Senior Vice President, Operations, People & Culture

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

Patrick O'Rourke -- AltaCorp Capital -- Analyst

Okay. 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. You know, there's three places where free cash flow can go to: debt repayment, potentially a dividend increase, or share buy-back. 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?

Ian C. Dundas -- President and Chief Executive Officer

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'll obviously play at the edges of that as that makes sense, but strategically, we're not interested in driving more growth there. When you think about those other toggles that you've highlighted -- inventory, share buy-backs, 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, we clearly think balance sheet is a distinguishing competitive advantage for us, which will allow us to do things to move us forward. Share buy-backs we've tried to be pretty clear with. We have a price that is monitored on a real-time basis and if we hit that price and the conditions make sense at that moment, absolutely we'll do that. Dividends -- today, the model is supporting robust growth, highly sustainable, and we see lines of sight to a lot of free cash flow.

Again, it hasn't happened yet, but line of sight to a lot of free cash flow. 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. At this moment, growth is trumping dividend. Does that help you out?

Patrick O'Rourke -- AltaCorp Capital -- Analyst

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

Ian C. Dundas -- President and Chief Executive Officer

Yeah. We could over beers talk about what under-levered means. I really like where we are right now. 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. We certainly expect more volatility to occur. So, our strategy 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. I'm very comfortable keeping our powder dry as we look for opportunities to expand inventory. Those can come 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. Having the balance sheet to do that, to be able to think about what the appropriate midstream solution is, all of that kinds of things, that balance sheet is a very, very powerful tool 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.

Patrick O'Rourke -- AltaCorp Capital -- Analyst

Okay, Thanks, Ian. That's very helpful.

Operator

Thank you. Your next question comes from Tom Callahan, RBC. Tom, please go ahead.

Greg Pardy -- RBC Capital Markets -- Analyst

Hi, good morning. It's actually Greg Pardy standing in for Tom. Just a couple of questions then. Maybe just to revisit the Cats area, 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?

Ian C. Dundas -- President and Chief Executive Officer

Maybe 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 is an area that we had anticipated being good, which we said on the last call. It's 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. Yeah, 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?

Raymond J. Daniels -- Senior Vice President, Operations, People & Culture

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

Greg Pardy -- RBC Capital Markets -- Analyst

Great. 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? Just given the exit rates that we're now looking at, it looks like you'll be somewhere around 100,000 BOE a day next year. Is that directionally the right way to think about your business or is it just too early?

Ian C. Dundas -- President and Chief Executive Officer

I'm not going to comment on that number.

Greg Pardy -- RBC Capital Markets -- Analyst

Oh, come on, Ian.

Ian C. Dundas -- President and Chief Executive Officer

Okay, "Tom." We've put out a 3-year plan that drives our liquids growth at 20% CAGR. We are executing that well. So, as you roll that forward into next year, we see more growth on our oil. That directionally has more on-streams 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. 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 forth. 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 high, high working interest, high, high degree of operatorship. But we are seeing a little bit of stuff creeping into op the side, which is moving our numbers around at the edges.

Greg Pardy -- RBC Capital Markets -- Analyst

Okay, just remind me. I think it's, what, back to 2,000 BOE a day that you mentioned?

Ian C. Dundas -- President and Chief Executive Officer

That's a decent number to think about. Maybe one more thing on that. 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 sort of spending our cash flow when oil was $50. That plan had been in place when oil was $47 and that plan was in place when oil was $60.

As we think about next year, if you've got a price deck within between $47 and $65, we're going to have very similar activity levels. In one scenario, there would be meaningful free cash flow and then the other one, we'd be sort of spending within. We'll see how it lines up as we finalize this thing.

Greg Pardy -- RBC Capital Markets -- Analyst

Okay. Thanks very much. Good context.

Operator

Thank you. Your next question comes from Travis Wood, National Bank. Travis, please go ahead.

Travis Wood -- National Bank -- Analyst

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

Ian C. Dundas -- President and Chief Executive Officer

$7 million is not a bad number to think about for these wells. You really need to think about them as being one-off-y related. I think 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. 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, there's two companies out there who are running 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-$4 million. Now, that would be with a smaller completion. And is that the right economic answer? Don't know. But I'd say this is clearly a play where costs are going to matter. Very high net back. Very interesting on many levels.

As Ray said, Maple is encouraging for us right now. 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 scope of the program is going to matter for that. It really will matter. You see that on the facilities side in particular.

Travis Wood -- National Bank -- Analyst

Okay. 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?

Raymond J. Daniels -- Senior Vice President, Operations, People & Culture

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

Travis Wood -- National Bank -- Analyst

Okay, thank you. Can we, 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?

Ian C. Dundas -- President and Chief Executive Officer

I'm thinking about whether we roll monthly forecasts. That's not a bad way to think about it, Travis. We see a relatively steady program. Obviously, this is all about the pace of on-streams and with the pads we're talking about, it 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. Again, we're talking about [inaudible].

Travis Wood -- National Bank -- Analyst

Great, perfect. Thank you. That's all.

Operator

Thank you. Ladies and gentlemen, as a reminder, should you have a question, please press *1 on your touchtone phone. Your next question comes from Brian Kristjansen, Macquarie. Brian, please go ahead.

Brian Kristjansen -- Macquarie -- Analyst

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

Ian C. Dundas -- President and Chief Executive Officer

Prop 97. Thanks for that question, Brian. For those who aren't aware, Prop 97 is a 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. 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. We can get into all the reasons why this thing can't go ahead in exactly the form or 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.

Brian Kristjansen -- Macquarie -- Analyst

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

Ian C. Dundas -- President and Chief Executive Officer

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.

Brian Kristjansen -- Macquarie -- Analyst

Great. Thanks for the color, Ian.

Operator

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

Ian C. Dundas -- President and Chief Executive Officer

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

Operator

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.

Duration: 34 minutes

Call participants:

Ian C. Dundas -- President and Chief Executive Officer

Jodi Jenson Labrie -- Senior Vice President and Chief Financial Officer

Raymond J. Daniels -- Senior Vice President, Operations, People & Culture

Drew Mair -- Investor Relations

Neal Dingham -- SunTrust Robinson Humphrey -- Analyst

Patrick O'Rourke -- AltaCorp Capital -- Analyst

Greg Pardy -- RBC Capital Markets -- Analyst

Travis Wood -- National Bank -- Analyst

Brian Kristjansen -- Macquarie -- Analyst

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