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Good morning, ladies and gentlemen, and welcome to the Enerplus Second Quarter 2019 Results Conference Call. [Operator Instructions] This call is being recorded on Friday, August 9, 2019.And 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 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 discussion, we will open up the call for questions.With that, I'll turn it over to Ian.
Thanks, Drew. I'll start by diving right into the quarter. As we had indicated with our first quarter results, we anticipated strong volume growth in the second quarter as completions activity was ramping up in the Bakken. I'm pleased to report that we delivered that volume growth at the high end of our expected range.Quarter-over-quarter, our total production was up 14% and our liquids production was up 16%. Bakken volumes were the primary driver of that growth. They were up 22%. We also continued to see capital-efficient productivity from the Marcellus with volumes up 14% from the prior quarter. As a result of this operational momentum, we're increasing our total production guidance and tightening the range on our liquids guidance.Importantly, we're maintaining our capital discipline. Our tightened capital budget guidance is inside of our original range. Additionally, we're forecasting lower unit operating and G&A expenses and stronger Bakken differentials, which are supporting the resiliency of our plan.So to recap our outlook this year. Our plan is expected to generate 14% liquids production per share growth, double-digit corporate level returns, return of capital to shareholders with over $115 million returned year-to-date and plans to continue buying back stock, and we're maintaining our peer-leading balance sheet. We believe this is a highly competitive outlook, and we continue to see compelling value in our equity at current levels, which we see trading at or near the discounted cash flow value of our producing reserves and little, if any, value ascribed to our high-quality Bakken inventory. As a result, we've been actively buying back stock this year and continue to see this as an attractive capital allocation decision based on current trading levels.Our Board has approved the repurchase of the full 7% authorized under our existing normal course issuer bid, which translates into just under an additional 9 million shares. Once completed, this would represent approximately 24 million shares repurchased since last September or about 10% of our shares outstanding.I'll leave it there for now and pass the call to Jodi to talk through the financial highlights.
Thanks, Ian. Continued strength in Bakken oil realizations, lower cash cost and higher production helped drive second quarter adjusted funds flow 10% higher compared to the first quarter, despite the reduction in natural gas prices following exceptional prices we saw during the winter months.Our second quarter Bakken oil differential was USD 3 per barrel under WTI. Given the strength year-to-date in Bakken pricing, we're revising our full year outlook for our Bakken oil differential to USD 3.25 per barrel below WTI from USD 4 per barrel previously. We continue to believe that the Bakken is in an advantageous position in terms of oil takeaway capacity.With significant rail infrastructure and the potential for existing pipeline expansion as well as new pipelines in the basin, we expect Bakken differentials will remain competitive longer term. Despite all this, we will continue to manage the risk and volatility through sales and marketing arrangements. We currently have close to 60% of our Bakken oil production in the second half of the year tied to fixed physical sales within the basin and the U.S. Gulf Coast at an average differential of USD 2.66 per barrel below WTI.Moving on to Marcellus pricing. As expected, we saw our realizations weakened from the premium pricing in the first quarter. With a meaningful portion of our sales tied to the Transco Zone 6 non-New York market, a change in seasonal demand from winter to spring drives lower quarter-over-quarter pricing in this region. Our realized Marcellus differential averaged USD 0.57 per Mcf below NYMEX in the second quarter.We continue to expect our Marcellus differential to remain at these more moderate levels in the third quarter before strengthening again in the fourth quarter on the back of seasonal heating demand. As a result, we widened our full year Marcellus differential guidance modestly to USD 0.35 per Mcf below NYMEX from USD 0.30 per Mcf previously. Finally, we've reduced our operating and G&A cost guidance per BOE, which is largely a function of the higher volumes we are forecasting.Turning to the balance sheet. Our total debt net of cash remained largely flat from the prior quarter, and our net debt to adjusted funds flow ratio was maintained at 0.5x. As we indicated in this morning's release, we plan to maximize our share repurchases to the full stock exchange approved limit, which was 7% of the company's public float as of March 19, 2019. As Ian mentioned, upon completion, this would equate to 24 million shares repurchased since September last year representing approximately 10% of shares outstanding.Our buybacks have meaningfully enhanced per share growth. The midpoint of our 2019 liquids production implies 10% year-on-year growth, which translates to 14% on a per share basis currently before considering our plans for additional repurchases. Underpinning our share repurchase plans is our view of the deep value in our stock today and the flexibility that our strong balance sheet provides to execute the full repurchase.We think about value from several perspectives, one of which is our ability to acquire an increased interest in our own high-quality reserves at a significant discount to the drill bit or through acquisition. Based on our current trading level, we could proof by our producing reserves at about $11 per BOE and our netback this quarter was over $20 per BOE. That sets up a recycle ratio of almost 2 times on producing reserves, and the cost on approved plus probable basis is even more attractive.Lastly, I'd like to highlight a change to our 2020 WTI oil hedges. We took advantage of an opportunity in the market to restructure our 2020 three-way hedges by essentially buying back the sold calls at a very modest cost. This removes the caps on the upside and lays our downside protection in place.With that, I'll turn the call over to Ray.
Thanks, Jodi. We saw a strong ramp in Bakken volumes in the second quarter with 26 operated wells brought in production. Well, results are tracking expectations. And with a number of these wells being brought in production at the end of the quarter, including a 9-well pad, we expect another solid build in Bakken production in the third quarter.We plan to complete and bring approximately 8 to 9 net wells on production in the Bakken during the third quarter. As our planned activity levels reduce in the fourth quarter, Bakken production is expected to moderate from the high volumes projected in Q3. Capital spending through the first half of the year was $368 million or about 60% of our full year spend based on a tightened capital spending guidance of $610 million to $630 million. Second half capital spending will be weighted approximately 2/3 to the third quarter given the moderating activity levels in Q4.I want to touch briefly on gas processing in the Bakken as we've had several questions recently on this topic. Gas processing capacity in the basin is reasonably tight. This is not new information. We have had this issue in our sites for quite some time and, therefore, our plans have incorporated these limitations. We continue to be compliant with state gas capture regulations, and our growth plans take all of this into account.Additionally, our gas largely goes to a third-party plant, which has very recently undergone a significant expansion. In fact, the expansion has just come online and has more than doubled existing capacity. So we feel good about our look in terms of gas processing.Coming to the Marcellus. We also saw significant growth in the second quarter due to continued strong well performance from longer lateral wells. The average lateral length of our Marcellus wells this year has been over 7,600 feet compared to 6,500 feet last year. This outperformance is driving our total annual production forecast higher with our guidance now 99,000 to 102,000 barrels of oil equivalent per day, 2% higher at the midpoint.We've also tightened our liquids production guidance to 54,000 to 55,500 barrels per day with no change to the midpoint. Part of our normal course portfolio optimization, we divested a modest amount of Canadian production during the quarter, 350 barrels per day for proceeds of about $10 million.Our focus on capital efficiencies is continuing to show results. In the Bakken, our current average total well cost is approximately USD 700,000 lower than 2018 levels. This has been a function of lower cost, efficiency improvements and continuing to optimize completions. Our current average all-in total well cost is about USD 7.5 million.Lastly, we drilled 5 gross and 4 net wells in the DJ Basin during the second quarter. Our plan is to complete these wells in the third quarter and bring them on production to coincide with a new pipeline connection to a third-party gas plant, which is expected to be completed later this year.With that, I'll pass the call back to Ian.
Thanks, Ray. So in closing, we remain well positioned to deliver our financial and operational targets. We're on track for another year of capital efficient, high-margin growth and strong corporate-level returns. We're also maintaining our significant financial resilience and believe this provides a competitive advantage in this volatile commodity environment. Finally, we see the current value of our equity as being discounted relative to our internal view. And therefore, we'll continue to prioritize the acquisition of our stock.With that, we will turn the call over to the operator and be available for your questions.
[Operator Instructions] Your first question is from Neal Dingmann from SunTrust.
I'm just wondering, how do you view the -- I know you talked about the buyback completing before, or sooner rather than later. But I am wondering, Ian, if the market remains irrational, how you would see that on a sort of go-forward basis versus thinking about acquisitions?
It's clearly -- stock buyback is clearly a priority right now. We see dislocation in the market that's sort of difficult to understand. And as Jodi highlighted, you compare buying the quality of our reserves at $11 a BOE on a producing basis with anything you can see in the marketplace. And it feels sort of like a no-brainier right now. So I mean that's where our focus is. Acquisitions, how's that all going to play out? I would think something has to break in that market too. It just hasn't yet. And so we do keep our eye on that marketplace. I think our focus probably these days are on smaller things, things that you could very easily tuck in and put on the balance sheet and still keep financially strong. There is such a dislocation out there, though, in that acquisition market. With a few high-profile M&A exceptions, nothing is really happening there because there's such dislocation out there.
Yes. Make sense. And then just lastly there is -- a couple peers had some takeaway in just line pressure issues. Could you talk about -- in the Bakken that is, could you talk about how your outlook for that looks?
Sure. Yes. I'll turn that over to Jodi or Garth, if you want to handle it.
Yes, sure. No. I mean the plant expansion that we mentioned or that Ray mentioned earlier is significant. It's more than doubling the existing capacity of the plant where we take our gas. Elsewhere in the basin, there is additional capacity being added later this year and into Q1. So we think this will help alleviate constraints later in the year. But for us, we're pretty happy with the amount of takeaway that we have, and we see this being excess capacity for several years.
Your next question is from Travis Wood from National Bank.
As I think Ray touched on it from the infrastructure side, I just wanted to see if you could share what your throughput is on the Little Missouri expansion expected to ramp up to capacity at the end of the year.
Sure. I mean I think our current throughput right now is about 40 million cubic feet a day that's going into the Little Missouri. And we think there would be excess room there once that Little Missouri completes its full ramp. It just started in -- or the beginning of August actually. And so they are doing a bit of a ramp, but most of that should come on in Q3. So we saw an immediate uptick in the amount of gas going through as of August 1.
And are you contracted on a take-or-pay through that plan?
Yes. Like our land is dedicated to that plant.
It's not a take-or-pay concept though. It's dedication.
Okay. So the -- of the 200 million capacity, what would Enerplus be able to have as throughput?
So the 200 million in capacity, half of that though was a joint venture with Hess and so -- Targa that operates the plant has the other 100 million, and they currently have the 90 million that's currently available over their previous trains. So Targa will now have doubled their capacity from 90 million to 190 million.
Okay. And then last question, Ian, you touched on costs in North Dakota, or maybe it was Ray, down about $700,000 to $750,000. Do you see further opportunity through the second half of the year to get that closer to $700,000?
Yes. I mean if you look at absolute best-in-class performance that dwells in the middle of summer, we're at those kind of levels. Then winter comes and stuff happens. And so we're trying to give you a really good feel for what's happened over the course of the year. We're on a good run rate now, and -- but we still have some activity in the winter, which costs more money in heating. So yes, I mean the team is exceptionally focused on continuing to look for nickels and dimes. And drilling performance -- it's not as big a ticket item as completion cost is, but we just had to face at our well the other day just a squidge over 9 days since spud to TD, which is quite exceptional when you think we're moving through 21,000-foot holes. So yes, I see opportunities there, Travis. We don't see external pressures relative to activity picking up any meaningful way. We don't see that stuff going on. So it's really about us and what we're able to do with people and equipment, and it's going pretty well right now.
Your next question is from Patrick O'Rourke from AltaCorp.
I was actually going to ask on the gas capture there, but you seem to have fairly eloquently answered that. The other thing we were kind of looking at and wondering here. In terms of the DJ Basin drilling completion activity that's going to be coming up, will there be separate horizons tested in that? And what sort of exploration could that potentially -- inventory impact to that have?
Patrick, so the DJ, 2 zones that we think about, the Codell and the Niobrara, are existing wells, 4 in the Codell, 1 in the Nile, and our 2 wells, similar kind of split. So I guess the Nile would be the exploratory zone, if you will. It's a big, big package, and it's a big prize for sure. Generally speaking in this area, it's been a little bit less productive with completion designs that have been tested to date. So I guess that would be sort of the upside that sits there. We've highlighted 400 locations. We're just seeing some contribution from both. There -- if you really want to sort of think about a Blue Sky scenario, that Nile package we're sort of landing in 1 sub-zone, one interval, and there is actually more that's there as well. We're not really testing any of that right now. We've got a pretty big opportunity in front of us just with the Codell and 1 interval in the Niobrara, which is a ruffled scissor at this moment. Those wells are being completed as we speak, and so we'll have data as we sort of move through the year, which will roll into our plans as we're thinking about what this play look like in 2020.
So when you guys are planning out these pads, you've done a fairly pragmatic job in the Bakken where you've spaced things out and you haven't densified in any 1 particular area quite yet. Is that how you're going to approach this play as well as -- as we see it develop?
Yes, depending where this goes. We've got 35,000 acres. Our activity to date has been focused on sort of a blocky chunk, about third of that. And the delineation cost optimization activities are focused in that area. And our infrastructure build-outs are happening directly in that area. That's where pipe's being laid and tie-ups are occurring. So yes, I think you could see a similar kind of pattern to the thing. We do have -- one of the differences here is how the Nile sort of unfolds. We sort of think about the Bakken and Three Forks -- at least operationally, we think about those as sort of singular unit. That's -- not sure how we'll think about this one, still some uncertainty there.
Your next question is from Mike Dunn at GMP FirstEnergy.
Ian, just wondering if you have any comments on how you're viewing 2020, I guess, rate of liquids growth relative to how you may have been thinking about it 3 months ago or so given changes in commodities and investor sentiment?
3 months ago? I mean that's eternity. That's not fair. So for those who are not familiar, we're in sort of early stages of a 3-year plan anchored on -- delivers 10% liquids growth. That plan was based on some principles around financial resiliency, strong economics and being able to deliver sort of an attractive total return proposition to shareholders. So all of those conditions exist really. Oil's still over $50, and our economics are still looking good. And the singular difference -- and so that's still our plan. That's still our plan. It made sense when we did it, and I think it still does. You step back though and your nature of your question is in part, what the heck is going on in the marketplace. And so when we rolled that plan out, we weren't anticipating that we would be as aggressive on share buybacks as we are. And so I think you would be foolish not to continue to think about the marketplace and to think about alternative capital allocation choices. So I think our plan right now still makes a lot of sense. It makes operational sense. It's attractive growth, and we can afford it. As we think about budgets for next year, could it evolve? Sure, it could evolve. But right now, I think it's still something that's pretty attractive.
[Operator Instructions] The next question is from Jamie Kubik from CIBC.
Just a quick question on your Marcellus assets here. Output during the quarter was well above historical levels, and fully appreciate that Enerplus is non-op in that asset. But what are your thoughts on where output is at here versus where gas prices are currently sitting?
Sorry, versus where they are sitting. Are you asking about curtailments or capital spending or what's the -- help me out there, Jamie.
Yes. I mean just with respect to gas prices are fairly weak for NYMEX. Are there any curtailments planned or how you think about output going forward in that asset?
Yes. So the growth in that asset this year has been more than we would have anticipated. But it's not a function of more spending. It's been a very modest capital program by many levels, and it just keeps delivering well results that are exceeding everyone's expectations out there. So as a general rule, you're seeing all the operators in that core, the core area, including our partner -- our primary partner, spend modest levels. It's a modest program. So I don't see that changing. I don't see anyone spending more money. Do I see people curtailing? I guess we'll see where the cash market goes. I mean that's always a possibility. If the cash market went to that sub-dollar level, we've sort of seen that historically, that's not what we're anticipating. We think we're sort of in the lower levels right now of that demand dynamic, and prices aren't as good as they were, but they are still a heck of a lot better than they were. I'd say, broadly speaking as well, there are some minimum levels and producers -- this wouldn't be our situation. But other producers would have some meaningful demand commitments or transport commitments that sort of put some floors on how they think about their volume commitments. So we don't see it now. Good things change. Sure. That's always a possibility. That's not what we see, and in fact, we see some possible real strength as we come sort of into the winter months.
Okay. Great. Another quick question from me. You guys had a pretty decent tax recovery in Q2 to the tune of about $14 million. Are you expecting any further revisions on this front to the balance of the year that could impact cash flow?
No, that was actually due to a former dispute in Canada that was result favorably for us. So that was kind of a nice benefit in the quarter for us, but we don't expect that going forward. Sorry, and just 1 last thing, I guess. We do still have a small AMT refund that will come through in Q4, but that should be small and accounted for.
There are no further questions. Ian, you may proceed.
All right. Well, thank you, everyone. Appreciate everyone's time today. People can enjoy the last little bit of summer. Game on again. Thank you. Have a good day. Bye.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.