Northern Oil and Gas Inc (NOG) 2017 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Northern Oil and Gas, Inc. First Quarter 2017 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call may be recorded.

I would now like to turn the conference over to Brandon Elliott. You may begin.

Thank you. Good morning, everyone. We are happy to welcome you to Northern's first quarter 2017 earnings call. I will read our safe harbor language and then turn the call over to Tom Stoelk for his opening comments and discussion of the financial results for the quarter. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by these forward-looking statements, those risks including, among others, matters that we have described in our earnings release as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements.

During this conference call, we may discuss certain non-GAAP financial measures, including adjusted net income and adjusted EBITDA. Reconciliations of these measures to the closest GAAP measures can be found in the earnings release that we issued this morning.

With the disclosures out of the way, I will turn the call over to Tom.

Thanks, Brandon. Good morning, and thank you, everyone, for joining the call today. I'd like to begin the call with a few operational and financial comments to provide some color as you review our earnings release and then get to your questions.

Our production in the first quarter averaged 13,299 BOE per day, which reflects a 2.8% decrease compared to the fourth quarter of 2016. The slight drop in sequential quarterly production was driven by a reduction in capital spending over the last 2 years as we continue our strategy of disciplined spending and balance sheet management as we seek to maximize the value of our asset base.

Our 2017 production guidance remains unchanged as we expect our yearly production to be relatively flat or perhaps modestly exceed our 2016 total production. We believe production in the second quarter will remain fairly flat with first quarter levels. For the second half of 2017, we expect to see production increase off first half levels as weather improves and more of our in-process wells are brought online. So at present, we continue to expect our production base to be more back-half weighted in 2017.

We are seeing an uptick in drilling activity in the basin. The rig count has increased from a low of 27 in May of 2016 to approximately 50 rigs running today. The increase in drilling activity has translated into a corresponding increase in the number of well proposals we are receiving. We elected to participate in the majority of well proposals we received in the first quarter, with most wells that we elected to being planned for enhanced completions.

During the quarter, we added 4.5 net wells to our wells-in-process inventory and reduced that inventory by 2 net wells that were added to production. As a result, our inventory of wells in process grew to 15.9 wells at March 31, which we anticipate will begin to decrease as weather improves and operations begin ramping up completion activities.

As we've discussed before, over half of our uncompleted wells are operated by Continental Resources, who have recently indicated their intent to aggressively begin completing their in-process inventory during 2017. So as they progress through their backlog of uncompleted wells, we expect to see a drop in our uncompleted well inventory.

Let me provide some data points on the improved well productivity we're seeing. Our 2016 producing well additions are tracking at 1 million BOE average type curve, which is 59% over our 2015 producing well additions. Enhanced completion designs are obviously driving these results. The wells we participated in since the beginning of 2016, which were completed with 10 million or more pounds of proppant, are tracking at 1.2 million BOE average type curve. So far, we are continuing to see further productivity increase improvements in 2017. Early results on our 2017 well additions are indicating a 30-day average IP rate of approximately 1,485 BOE per day, which is a 34% increase over the 30-day average of our 2016 well additions. We believe the improvements we are seeing are representative of the quality of our acreage and the performance improvements on wells using enhanced completion techniques. We've placed an investor presentation on our website today that highlights some of these productivity improvements.

Capital expenditures totaled $27.3 million for the quarter, in line with our expectations, given the increase in number of wells on our in-process list. Our improved well performance is being complemented by a decrease in the weighted average AFE cost per well that we consented to during the first quarter of $6.6 million. Our continued focus on return-based capital allocation process allows us significant flexibility as it relates to our capital expenditures. This non-operated capital allocation advantage has allowed us to adapt quickly to changing conditions, while at the same time, remaining disciplined in our balance sheet and liquidity management. We believe this advantage will benefit our shareholders of the current and future commodities cycles as we continue to consent only to those wells that we believe will generate an appropriate rate of return in the current commodity price environment.

On the hedging front, we continue to protect our future cash flows from downside risk due to lower oil prices. For the remainder of 2017, we have approximately 2/3 of our forecast oil production hedged with a combination of swaps at an average price of $52.82 per barrel and costless collars with an average floor price of $50 and average ceiling price of $60.06.

In 2018, we have 1.7 million barrels hedged with swaps at an average price of $53.52 per barrel and an additional 360,000 barrels hedged under costless collars with a floor price of $50 and an average ceiling price of $60.25 per barrel.

Crude oil differentials during the first quarter of 2017 were $8.06 per barrel below the average NYMEX price. With significant pipeline capacity additions planned for later this year, we believe that our full Bakken differentials will range between $7 and $9 per barrel. There is, though, potential for future improvements once pipeline additions are brought online later this year.

We saw operating expense for the first quarter came in at $9.75 per BOE compared to $9.70 for the same period a year ago. We believe our full year LOE per BOE will range between $9 and $9.30 per BOE in 2017, with the first half averaging higher and the second half trending lower than our full range average as production ramps up throughout 2017.

General and administrative expense in the first quarter of 2017 was $3.6 million, down 17% as compared to the first quarter of 2016. The decrease was primarily due to lower noncash compensation expenses in 2017. Our full year 2017 general and administrative expense is expected to range between $3 and $3.50 per BOE.

We just completed the semiannual redetermination under our revolving credit facility, where borrowing base was established at $325 million. Based on this new borrowing base, we have availability of $196.5 million, comprised of $5.5 million of cash and $191 million of revolving credit facility availability. Given our capital spending plans and the hedging levels that we have in place, we're confident of our ability to execute on our development activities.

In conclusion, we will continue to use our flexible capital allocation process to protect the value of our assets and seek the highest returns available to us. The increases we're seeing in well productivity and EURs are giving us confidence for 2017 and beyond. By maintaining capital discipline and protecting our liquidity, we are navigating this commodity price cycle and at the same time preparing ourselves for future opportunities and value creation as we begin to work our way back to a more normalized level of activity.

All right. At this time, we will turn the call over to the operator for Q&A. If you could please give the instructions for the Q&A portion.

(Operator Instructions) Our first question comes from the line of Neal Dingmann from SunTrust.

First question, Tom, and it still seems, again, well, reasonably a bit in defensive mode. And with that sort of backdrop, as you continue to critique deals you're looking at, what are you getting as far as percent working interest size? Is that range or is that still staying pretty consistent?

I think it's still staying fairly consistent. We saw, really, an uptick a little bit in our average working interest on our D&C list. So it's kind of, I think, consistent, Neal, with our historical of around 7% kind of weighted average.

Okay, okay. And then on -- you mentioned there in the press release today, it does sound like you all, as well as a lot of the operators up there, are definitely seeing some improvement on enhanced completions. Could you just talk about that -- the discussions you're having is, in most areas, is just more better across the board? Or how do you all view that?

Yes, I think our view is that it's pretty much better across the board when they're using the enhanced completions in the higher proppant levels. It's certainly encouraging. We've seen various operators that we work with apply those, and those levels are certainly making a difference. We've had a couple of our operators -- I mean, QEP announced the Foreman wells, which were in on the -- on Southern Antelope, and that had over a 2,800 barrel oil equivalent per day. Another one of our operators, WPX, announced some great results on the Grizzly pad, which was over 700 barrels of oil per day. And maybe one of the most encouraging for us is that Continental's commentary on their estimated rates of return, given their outperformance kind of in the recent completions with respect to that. We're fairly well exposed to Continental on our drilling and completion list. We have a little over 100 gross wells on that list, and Continental had indicated, not only in addition to the encouraging outperformance of the recent completions, but they were getting after pretty hard the 200 uncomplete locations kind of on their list. So long-winded answer, but certainly really encouraging, and it's pretty much across the board.

Okay. And then just lastly, I mean, you definitely have time before, I think you've got that bond that comes due in 2020 or something like that, or 2 years. I mean, any -- in still pretty good liquidity. Any thought on, would you address -- look at trying to do something with that bond? Or just kind of, right now, given the liquidity you have and given the CapEx programs, just kind of take it to kind of what you're doing right now instead?

Yes, I don't think our focus probably is on the senior notes at this point. I mean, you hit it on the head. Our focus is really return-based and maintaining adequate liquidity so we can kind of execute on our development plans.

And our next question comes from the line of Carlos Newall from Raymond James.

Well, so this past quarter, you indicated average AFEs coming in at roughly $6.6 million, but your wells in process are expected to cost roughly $7.3 million. Recognizing that it's probably not apples-to-apples, can you give us a sense of how much of the increase is associated with upsized completions relative to service cost inflation? And building off of that, what kind of service cost inflation are you expecting for the remainder of the year?

We're not seeing a lot of service cost inflation currently. I think a lot of our operators are basically kind of telling us, around 5% per year. Some of them are able to offset that with -- kind of with the multi-pad completions, given the economics. Most of the operators are using the multi-well completions because they're more efficient. It does make production a little bit more lumpy kind of on our end with respect to that, but...

Yes, and Carlos, this is Brandon. I think you mentioned the AFE, the -- yes, the consent continues to trend down. Obviously, the wells that we're bringing on and the wells in the D&C list have some of those wells that we consented in the earlier quarter. So if you look at that slide on the website, you'll see that there are some average AFE costs that are in the 7s. Those are the wells that are coming online. And I think, to Tom's point on the confidence, that we're not seeing a lot of inflation yet. That AFE continues to trend down. So those wells that we consented this quarter and last quarter will be the well-add costs as we move forward over the next couple of quarters.

Got it, that's very helpful. One quick follow-up. What percentage of wells are being nonconsented? And how does it compare to last year?

I think, first quarter, about 85% of our wells had enhanced completion, and our consent rate was around 80%. And that's fairly consistent, I think, with kind of the overall 2016 average.

And our next question comes from the line of Scott Hanold from RBC Capital Markets.

Yes, can you just give us a broad picture? It looks like you all have obviously bolted on some more hedges there, which was really good, and you've got good liquidity right now. It seems like wells are getting better, but obviously, commodity price seems to be the thing that is being a bit volatile, especially where it's at right now. Considering that, obviously, when your non-op partners are drilling really good wells, Continental and -- going to get to work pretty aggressively here, how do you step back and look at the fact that you've got liquidity, leverage ratios may be a little bit high and you've got some uncertainty and volatility in oil prices in determining whether or not you try to keep pace with them if they do start to ramp things up even more?

Yes, I think kind of a multipart answer, a little bit. One is that, over the near term, as you mentioned, we have -- we're in a good liquidity position with respect to that. And one of the ways we maintain that, obviously, as you referenced, is increasing our hedging levels. So we're about 2/3 hedged through 2017, and we have about $2 million, $2.1 million of hedging in '18. So in the near term, I would anticipate, we're going to kind of keep pace with those elections, while at the same time kind of remaining focused on our liquidity. As I mentioned in our prior calls, we're looking for solutions that are going to grow our cash flow and reduce our borrowings. We're certainly in a good liquidity position today, but over the near term, I don't really anticipate, really, any problem with respect to that.

Yes, Scott, this is Brandon. Obviously, we look at the IRRs, and we think if those IRRs are where we think they're going to be or better, that obviously the returns on that should help us from, down the road, liquidity borrowing base kind of amounts in the future.

Okay. And Tom, you sort of alluded to it, so I get to ask the question, I guess, right? Strategic options, where can you say we're at right now? And it seems like there was a little bit more of a hint of a direction here in talking about buying cash or actually adding on cash flow. Does that indicate that your view has shifted a little bit more to, how do we continue to build the company and bolt things on that or merge with something that may make sense?

Well, yes, we won't comment on any specific transactions going forward. But to your point, the strategic alternatives process is still ongoing. I really won't add to the comments other than what I've really said on -- in the past, and that's really our focus remains kind of the same. We're looking at solutions that will either grow cash flow or really reduce our borrowings and -- while maintaining kind of adequate liquidity at all times to be able to execute on what we've got in front of us. And outside of that, I really can't comment any further.

No, that's fair enough. And if I could just slip one more quick one in. On differentials, obviously, things look like they're set to improve. Is there anything internally you guys could do to even further enhance that? Have you looked at doing a little bit more in the marketing efforts? Or are you typically going to look more to basically sell your oil to your operating partners?

Yes, our operating partners pretty much take care of the oil. We don't really get involved in the marketing end of it. To your point on differentials, we've certainly seen them trend down. And I think our expectation is that when you see more pipeline capacity kind of come on to the second half of the year, it'll probably enhance netbacks as well. But certainly, comfortable with the $7 to $9 range, we're trending below $8 right now kind of real time.

And economically, it makes most sense just to market it with your operating partners versus trying to take that in-house?

You bet.

(Operator Instructions) Our next question comes from the line of John Aschenbeck from Seaport Global.

I had a follow-up on the high-intensity completions. Obviously, some really strong results, so congrats on those. And just listening to other operators across the basin, it seems like the general idea right now is that more proppant is better, and really, the focus is just determining at what point you hit a level of diminishing returns, whether that's 10 million pounds, 20 million pounds, et cetera. So since you had such a large sample set as a nonoperator, I was curious if you've seen anything that might suggest where that optimal amount of profit might actually lie.

I think everybody's still trying to find the key with respect to that, and it's sort of maybe not "one size kind of fits all." When you start to get on the anticline, and where it's more naturally fractured, you're not seeing the operators use as much proppant there. But I don't think they've found the magic formula yet with respect to that.

Yes, John, this is Brandon. I think we've participated in some as high as 20 million pounds, and I think it's just a little early to say from our vantage point. We'll let the operators call when they think they've seen diminishing returns, but probably too early to tell from our perspective. But no sign that we've hit it quite yet.

Yes, and certainly great results when it's around 10 million pounds and higher. At least to date, what we've seen.

Got it. Appreciate it. It's really helpful. And then just kind of a follow-up here on '17's production profile. It seems like you're going to have some nice momentum exiting the year. I was just wondering if you could continue that sequential growth profile as you head into next year -- go ahead, yes.

Yes, I would think you'd actually see some sequential production growth in 2018. To your point, we've indicated in the script, and I think in the release this morning, that we expect kind of fairly flat first to second quarter, and then you're going to start to see the growth kick in as production starts to ramp up as the operators kind of get after completing those wells in the better weather time periods and things like that. And I do think that, given development plans as we currently see them, we'd continue to see some small sequential growth again as we exit '17, kind of in the '18 as well.

John, this is Brandon. I think if you look at kind of getting to our guidance, it's got kind of a 4Q-over-4Q that's up maybe mid-single digits to get us to that guidance. And obviously, that exit quarter rate would put you at a little built-in sequential production -- or built-in growth into 2018. Obviously, don't forget that we typically assume that 1Q and 2Q, the kind of tougher weather quarters, don't necessarily have sequential production growth. So when you look out at '18, keep that in mind.

Okay, got it. I think that last point was kind of what I was getting at, but that's all really helpful. Just kind of keeping with that, last one for me, as we think of go-forward maintenance CapEx, do you think it's still around that 12-net-wells level? Or is it perhaps less now that they're (inaudible)

Yes, it depends on the quality of the well, obviously, but it's somewhere in the 10 to 12 range would be where I'd peg it right now. The IPs are certainly up, so that's causing me to maybe think that it's a little bit lower than the 12 we've given you historically. But right now, I think I'd range it between 10 to 12.

And our next question comes from the line of Sean Sneeden from Oppenheimer.

Tom, maybe for you, just on the borrowing base discussion. Congratulations on getting that done. Did you guys talk about an extension of the facility at all? Or could you give us a sense of how you're thinking about pushing out that maturity? I believe it starts to (inaudible)

Yes. We -- this go-around, we really didn't talk about amending and extending the term on the facility. As you know, it's got a September 2018 maturity on it, and that's something that we're clearly focused on. So we'll likely be addressing that either next redetermination or the next 6- to 9-month period. It's going to be -- because it's something we do need to take care of. We're in real good position as far as covenant compliance and things like that, so nothing real pressing, really, at this point. But it's something that we will focus on probably in the next 6 months.

Okay, that makes sense. And is the ultimate goal there to try to have something similar to what you have right now? Meaning kind of just a simple extension of kind of a borrowing base facility, or are you looking at other options?

Yes, I mean, I think you always consider other options. But at present, we like a revolver-type capacity and being able to draw and kind of repay as opposed to -- an alternative might be to kind of term it out, and you've got a little less flexibility with respect to that normally. But directionally, we're looking at, really, a bunch of different alternatives, to be honest with you.

Okay. And then just on the gas realizations, they improved pretty significantly versus the fourth quarter. What was going on there? Was it -- and I guess, how should we be thinking about that type of realization going -- the NYMEX gas?

Well, I think it was really the impact of NGLs kind of in our blended pricing, and really the -- what drove a lot of that was just the increase in propane. So I think if -- propane was up, I think, about 30%, and if that stays at those levels, it will continue to have a very favorable impact on our realization. Nice surprise.

Yes. And I guess, how should we think about the kind of composition there of kind of what you're reporting on like your gas stream? How much of that is really coming from propane or ethane in that sense?

Let me...

Hold on a sec. We're looking.

Well, 36% are NGLs and propane probably makes up about 1/3 of that. I'm not sure I've got the data in front of me, and...

Yes.

That's fine. I can follow up with you guys later.

Okay.

Yes, we'll follow up on that.

And then just 2 quick ones. I guess, one is, how many of the 10 million pounds of sand, or greater, wells have you guys participated in so far?

27.

We've got about 27 gross wells in that data.

Okay. And then just on -- in your slide deck, Slide 7, that kind of shows your average IRRs and AFE cost. Are those IRRs based on the strip at the time? Or how should we kind of think about that?

Yes, at the time we consent on those. And obviously, as Tom mentioned, kind of going back to the hedging thing is, as we feel like we're consenting to wells and adding capital spending, given that those IRRs are based on the strip, we do try to layer on some additional hedges of the strip to kind of lock some of that in. But yes, so short answer is at the time of consent.

Okay. And just to be clear, the -- are you guys using hedge gains or losses in your IRR calculation? Or is that just kind of (inaudible)

No, no.

No. No, we are not.

And our next question comes from the line of Owen Douglas with Baird.

So by the way, it was pretty good news about the borrowing base redetermination, only a $25 million decline, so good job there. And -- but to an earlier question around your thoughts around the extension of that facility, I understand that it's something that you obviously have a little bit of time to work on. But in the meantime, as that process of figuring out a replacement or extension goes on, can you sort of give me a sense for how that may or may not affect some of your thoughts on some of these inorganic transactions you were talking about?

I'm not sure I heard the last part of it. You were saying, what was the impact on...

How does that sort of affect any sort of thoughts on your ability to go out and sort of snap up acreage positions or existing wells?

Okay. Okay. I understand now. I really don't think it has a significant impact based on the transactional activity that we're seeing. We're still looking at opportunities to acquire and participate in very economic sort of well bore sort of acquisitions. We picked up a small amount of acreage in the current year, and we'll continue to look for opportunities. We're capital allocators, so we're very rate-of-return driven. Where that would potentially impact us is if we saw a very large catalyst-type transaction for the company. Then, I think, we'd have to step back and look at how we do it. But day in, day out, the type of transactional activity historically has been relatively small. We pick up, maybe less attractive because of the size, primarily, but certainly rate-of-return driven. I think our average rate of return on what we elected to in Q1 was over 37%, as I remember. So but it hasn't really slowed us down, don't anticipate, on the organic side, it will really -- or the nonorganic side rather, it will really slow us down.

Okay. But it sounds as though if you were to come across a somewhat larger opportunity out there, you won't have utilized the current revolver capability, you'll probably look for something a little bit more longer-term financing?

Yes, I think it just depends on the facts and circumstances of that acquisition, but that might be one way that you would go, is try to look at some more longer-term financing if such an acquisition were out there.

Okay, that's pretty helpful. And then a final one for me here. I just wanted to get a little bit of an update, and I think I ask this almost every quarter. How is that A&D market looking? Can you give any sort of update to whether it's directionally -- whether you're seeing bid-ask spreads tighten, increased competition? Just really any color would be greatly appreciated.

Yes, I think we're seeing a fairly decent amount of activity with respect to properties kind of being offered. I think there's always a little bit of a bid-ask, I think, that, I think, recently, with the drop in WTI, it's got some people kind of -- I think it softened just maybe a little bit with respect to what the seller and buyer's price expectations are. But we're still getting the smaller ones done. AFE Activity was really strong this quarter, kind of given, I think, the increase in rig count when you take a look in our slide presentation, you look at the number of wells that were permitted over our acreage and things like that. But A&D-wise, I think I'd characterize it as remaining strong. But I think in the real recent term, given the volatility and the commodity on the oil side, it's softened just a little bit, so there's probably a widening gap. Before, I think, maybe it wasn't quite as wide, if that helps you.

And our next question comes from the line of Jason Wangler from Wunderlich.

I was just curious, and I apologize, I had to jump off for a minute, but -- if this is asked. Just the cost of $7.3 million for the weighted average in your in-process wells, and then, obviously you're at $6.6 million is what it looks like for the first quarter. Obviously, it's still -- looks like it's coming down. Can you just maybe talk about what the delta is there that we're thinking about? And then just kind of as you're looking at them today even, are you still seeing those well costs coming in around that $6.6 million level? Or just kind of where those are going.

Yes, I think it's more of the mix that kind of comes in. I think that, in the first quarter, you saw some wells come in that were on the anticline that were more naturally fractured. So not as high proppant there. I would think that -- our April AFE election rate was more like $7.3 million. So I think $7 million to mid-7s is probably, if you're looking going forward, kind of what our expectation is.

Okay. And of course, that's effectively assuming that everybody's doing their enhanced completion of some sort as well, correct?

Yes, yes. As I mentioned before, about 85% of what we elected to in Q1 was an enhanced completion. That was an even higher percentage back in Q4. So...

Yes, Jason, I think if you -- that delta that you're looking at, I think the wells that we consented to in the earlier quarters are the ones that are coming on now. So it's still a little bit of built-in deflation as we move through the next 6 months, but to Tom's point, I think that $7 million range, given the enhanced completions, is probably a reasonable expectation at this point.

And that concludes our question-and-answer session for today. I'd like to turn the conference back over to Brandon Elliott for any closing comments.

Thanks, Karen. We appreciate everyone's participation on the call today and your interest in Northern Oil and Gas. Karen will give you the replay information, and we look forward to talking to you again next quarter or on the road over the next couple of months. Everybody, have a great day.

Thank you. Ladies and gentlemen, to access the replay of this conference, you may dial (855) 859-2056 and enter the access code 14741485. International callers may dial (404) 537-3406 and again enter the code 14741485. That does conclude our conference call for today. We thank you for your participation, and you may now disconnect. Everyone, have a great day.