Northern Oil and Gas Inc (NOG) 2014 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Northern Oil and Gas Inc. fourth-quarter and year-end 2014 conference call.

(Operator Instructions)

As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Brandon Elliott, Executive Vice President of Corporate Development and Strategy. Sir, you may begin.

Thanks, Sam. Good morning, everyone. We are happy to welcome you to Northern's 2014 year-end conference call. I will read our Safe Harbor language, and then turn the call over to Mike Reger, our Chairman and Chief Executive Officer, for his opening comments, then Tom Stoelk, our Chief Financial Officer, will walk you through the financial results for the year and the fourth quarter of 2014.

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 include, 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 will also make references to 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 last night.

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

Thanks, Brandon, and thanks everybody, for joining our call today. 2014 was a strong year for Northern, as the capital allocation process that we have been talking to you about over the last two years continues to show in our performance. A great example is the fourth quarter, where despite adding fewer wells than anticipated, our production growth really surpassed our expectations.

Consistent with prior quarters, those fourth-quarter well additions were heavily weighted, over 90%, to our four core counties in North Dakota. Looking back, we started out 2014 modeling 15% production growth on 44 net well additions, and instead ended up generating almost 30% production growth on just over 41 net well additions.

Part of that outperformance is due to the timing of our net well additions throughout the year, but there's no doubt that our capital allocation discipline is improving our overall average well productivity. In fact, never has our capital discipline and flexibility been more important than when oil prices began their slide late last year.

On our last earnings call, we talked about October activity, and the fact that we elected not to participate in approximately 25% of the well proposals we received that month, because they didn't meet our internal rate of return hurdles. During November and December, as oil prices really began to drop, that number jumped to over 70%.

Let me take a minute here to talk briefly about what happens when we elect not to participate in a well proposal, which we also refer to as non-consenting a well. I want to make clear, when we non-consent a well, we only lose a portion of the economics of that specific well bore.

We still retain our acreage in the drilling unit and the right to participate in future wells in that unit, and if for whatever reason that operator doesn't drill that well or delays spudding the well for more than 90 days after the consent deadline, then we really lose nothing, because the operator would be required to re-propose the well if and when they decide to drill. At that time, we would get the same opportunity to review and run our rate of return analysis all over again. We remain committed to only deploying our capital to the projects that meet or exceed our rate of return acceptance levels.

Based on discussions with operators, the industry is making adjustments in changing rapidly to today's challenging environment. And as a result, we expect drilling and completion costs to trend lower throughout the year. Operators have began to cut capital expenditures significantly, and many are delaying completions, while negotiating lower cost structures with their service providers.

As expected cost decline and returns improve, Northern will increase the number of wells we elect to participate in. Based on our acreage in the core of the play, we believe that we have many years of economic drilling opportunities, that will provide solid returns, even in the current price environment.

Subsequent to the end of the year, in an effort to preserve capital, certain wells where we had previously elected to participate, but where the returns no longer meet our return thresholds, we have been negotiating with operators to reverse our consent decisions. This will further enhance our capital efficiency by holding that capital for higher return opportunities down the road.

As we looked to the remainder of 2015, we are expecting our capital budget to decrease significantly this year, over 70% versus 2014. Our 2015 capital expenditure budget is comprised of approximately $120 million of drilling and completion capital, and approximately $20 million of acreage acquisitions, workovers, and other capitalized costs.

This budget reflects approximately 20 net wells added to production in 2015, a portion of which were in process at the end of 2014, and were partially accrued for in the 2014 capital budget. On this budget, we still expect to generate a total of 2015 production on par with 2014 production.

Our reduced capital budget, combined with almost 5 million barrels of oil hedged at approximately $90 through June of 2016 puts us in a great liquidity position to return to production growth when it's prudent. Also, it is important to note that our hedges are swaps, with no subfloors, which is why you saw such a dramatic mark-to-market increase in the value of these derivative contracts at year end. These hedges represent nearly 80% of our expected oil production in 2015.

I will hand the call off to Tom, but let me just summarize where we stand before I do. We are in a great liquidity position with a substantial hedge book, we have the capital necessary to execute our plan, and our capital allocation process is driving improved returns. The non-op business model, our capital allocation flexibility, and our hedge position will continue to protect our balance sheet. We are confident that as commodity prices rebound, we will be able to resume production growth with this increased exact capital efficiency.

With that, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss the financial highlights from 2014.

Thanks, Mike. Today I'm going to cover some of our financial highlights for the fourth quarter and give you our thoughts on guidance for 2015. I'm also going to comment on our liquidity and capital expenditures.

For the fourth quarter of 2014 we reported net income on a GAAP basis of $103.6 million, or $1.71 per diluted share. Adjusted net income from the quarter was $12.8 million or $0.21 per diluted share, and fourth-quarter adjusted EBITDA was $81.6 million.

Production was strong for both the year in total and the fourth quarter, with annual production up 29% and fourth quarter production up 29% as well, on a year-over-year basis. Fourth-quarter production averaged approximately 18,000 barrels of oil equivalent per day, which was a 9% sequential increase, when compared to the third quarter of 2014.

The strength of our production growth was driven primarily by improved economics and recoveries on the 41.6 net wells added to production this year, and was also aided by successful workovers performed on some of our producing wells. As Mike commented, these combined result certainly exceeded our expectations.

Oil and natural gas sales for the full year of 2014, when you include the impact of settled derivatives, were up 19% as compared to 2013, and reached $423.7 million. Fourth-quarter oil and gas sales, also again including the impact of settled derivatives, increased 16% when compared to the same quarter last year, and reached $111.7 million.

Our average oil differential to the NYMEX WTI benchmark was $12.89 per barrel in the fourth quarter, essentially flat with that compared to the third quarter. In discussions with some of our operators, that are indicating that January's oil differentials are averaging in the $10 to $12 range, so for now we're assuming this range will hold for the entire year.

Realized price per barrel of oil equivalent after reflecting our settled derivative transactions was $67.49 per BOE for the fourth quarter, which was down approximately 9% sequentially compared to last quarter, and that was due primarily to low oil prices received during the quarter. As a result of the significant drop in forward oil prices, we had a non-cash mark-to-market derivative gain of $145.8 million this quarter, compared to a non-cash gain of $6 million in the fourth quarter of 2013.

On a per unit basis, production expenses increased $0.10 from last quarter, and reached $9.83 per BOE. We're currently estimating that production expenses on a per-unit basis will range between $9.75 to $10 per BOE during 2015.

Production taxes totaled $9.6 million during the quarter, or approximately 10.2% as a percentage of our oil and gas sales, as compared to 10.1% last quarter. As a percent of oil and gas sales, I would expect his rate to trend up slightly as we move through 2015, averaging 10.5% for the full year.

Our production tax expense is tied directly to the net realized price received at the wellhead, and scales up and down with commodity prices. Accordingly, you can expect to see production tax per BOE to decrease in 2015.

General and administrative expense was $4.9 million this quarter, compared to $4.5 million in the fourth quarter of 2013. On a per-unit basis our general and administrative expense per BOE during the fourth quarter was essentially flat when you compare it to last quarter, and decreased 15% when compared to the fourth quarter of 2013. We expect G&A on a per unit basis to be approximately $3 per BOE for 2015.

Depletion, depreciation, amortization and accretion per BOE was $29.57 this quarter, which compares to $30.34 per BOE the fourth quarter of 2013, but the depletion rate per BOE, which accounts for almost all of our DD&A rate, dropped this quarter to $29.45, in connection with the completion of our 2014 year-end reserve report. We expect our DD&A rate in 2015 to continue to be in line with recent results of approximately $30 per BOE.

Our capital expenditures during the quarter totaled $141.2 million. The breakdown of that total is as follows; approximately $129.3 million of drilling and completion capital, and that includes capitalized workover expense; $10.4 million on acreage and other acquisition activities; and $1.5 million of capitalized interest net of other capitalized cost.

Our full-year 2014 capital expenditures are broken down as follows; approximately $479.5 million of drilling and completion capital, which includes capitalized workover expenses; $49.9 million on acreage and other acquisition activities; and $7.5 million of capitalized interest and other capitalized cost. The increase in the number of wells drilling or awaiting completion during the year increased our capital expenditures in 2014 by $86 million.

Turning to liquidity, we had $298 million of borrowing on a credit facility at year end, leaving us with $252 million of borrowing availability. With another $9.3 million in cash on hand the Company had available liquidity of approximately $261 million at year end. Including our senior notes, our ratio of long-term debt to trailing four quarters adjusted EBITDA was 2.7 times at year end.

Kind of given the current environment, other E&Ps have been discussing financial covenants, so I thought I'd do the same. Our credit facility contains just two financial covenants. We have a current ratio requirement, which requires us to maintain a ratio of no less than 1 to 1, but allows us to include our borrowing availability under the revolver in that computation.

The second financial currently buyers a ratio of total adjusted EBITDA, total debt to adjusted EBITDA of no greater than 4 times. We continue to comfortably be within these limits and expect to remain so in 2015.

Based on our internal projections, using a realized oil price of $47 per barrel of oil, and that's before hedging, and a $4.30 per MCF for natural gas, and that includes our natural gas NGL uplift, we currently estimate that we will end 2015 with borrowings under our credit facility of approximately $375 million, which would leave our ratio of total adjusted -- total debt to adjusted EBITDA at approximately 3 times, or well below the 4 times requirement at year end 2015. Obviously these internal projections could vary materially from actual results, due to a number of factors, which include but are not limited to realized commodity prices, timing of development and completion activities, as well as just overall commodity prices.

Given the recent decline in oil prices, we thought it might be helpful to provide some additional comments about how we're thinking about liquidity and capital allocation. First, we believe are in a good liquidity position, given our existing borrowing base and our strong hedge position.

As a reminder, in 2015, we have hedged approximately 4 million barrels of oil at an average price of $89.43 per barrel, and for the first half of 2016, we have hedged 900,000 barrels of oil at an average price of $90. That significant amount of hedging is extremely valuable in the current pricing environment, and helps us protect our balance sheet.

Second, our asset base is substantially held by production, and is located in an area with some of the lowest break-even economics in the US. As a non-operator, Northern has extensive control over its capital spending, because we have the ability to elect to participate on a well by well basis. This provides the ability to be more selective in the allocation of capital to the highest rate of return projects, without the burden of contractual drilling commitments, large operational or administrative staffs, or other infrastructure concerns.

Given the uncertainty around oil prices, we are continuing to take aggressive steps to protect our balance sheet. To be prudent during this low price environment, we reduced our 2015 capital budget by over 70%, as compared to 2014. While we still expect the capital budget will allow us to maintain 2015 production relatively flat with that of 2014.

By maintaining capital discipline, we continue to work hard to build resilience given the uncertainty of how long the low price environment will last. Through these methods and additional steps to reduce commitment levels, we will navigate through the low price environment, and at the same time, better prepare ourselves for future opportunities and value creation.

At this time, I'd like to turn it over to the operator for Q&A. Sam, if you could please give the instructions for Q&A?

(Operator Instructions)

Jason Wangler of Wunderlich.

Mike, just curious, as far as -- and appreciate the CapEx discussion. Could you give us an idea of what you have left over in 2014, into 2015, or even just the cadence of how you see that CapEx falling, even if it's just the first quarter or first half of this year?

We had a certain number of wells that were in process at the end of the year, which had obviously associated payables. So, that will be part of the CapEx going into -- or working capital going into 2015. But we really just -- you can be comfortable with the numbers we provided last night, and approximately 20 net wells added to production through the year.

Okay, and, not trying to hold you down on it more, but would you, at least the cadence, do you see the CapEx number slowing as we go throughout the year, or having a topping off, if you will, at the beginning of the year, and then getting to a more steady state as we go, second half. Is that fair to say?

I think so. I think what we're seeing now, which is actually encouraging, is that a lot of our operating partners are delaying some completions, as well. As we see contango on the commodity markets, and also the winter months are harder to complete these wells in, and then also, road restriction -- typical road restriction dates are March 15 to, call it, May 1, May 15, somewhere in there. So, that gives a wide range of that.

So, I would say that it might be fairly ratable, which is good, as we go throughout the year. Because we're still bringing wells on here -- pretty good completions in January, but we'll continue to -- we think it's going to be fairly ratable throughout the year. And I think we're encouraged by the delays in some of the completions.

I think that makes sense, and I appreciate it. I'll turn it back. Thank you.

Ryan Oatman of SunTrust.

Nice quarter. I was wondering if you could speak to what drove that production 10%-some above expectations in 4Q? And then, recognizing that the non-consent activity was pretty significant in the fourth quarter, was curious if you guys have any thoughts or color on what 1Q production so far is looking like?

I think what we saw in the fourth quarter, which was exciting for us, was really a culmination of what we've been talking about over the last 1 1/2, 2 years. We keep reiterating the fact that the wells in process, the wells that we're electing to participate in, are all over 90% in those four core counties of Mountrail, McKenzie, Williams, and Dunn. And really what we ended up seeing in the fourth quarter is -- although we only completed just over eight net wells in the fourth quarter, the overall productivity of those wells were some of the better ones that we've seen. And it's just because of that core activity that we've been focusing on.

And then, as you can imagine, with winter -- with the winter months, and then, as we have begun to scale back activity, it's pretty easy math to get to flat production over 2015 levels. There's really -- you can do your math, but I think one thing that we're probably seeing is some of the operators are doing a little -- they're curtailing a little bit, but we're also delaying some completions too, so.

Ryan, this is Brandon. I think if you look back historically, maybe to use last year as a little bit of reference, I think 2014 first quarter was down almost 5% sequentially versus fourth quarter. So, just assuming the normal delays and weather, you can maybe use 2014 as a little bit of an analogy for that.

Thanks, that's helpful.

And it looks like the guidance implies about a $7-million average well cost. Can you speak to where those AFEs have been, and where they are now?

I think we're seeing them across the board. What I think we look to, in addition to the wells that we're seeing coming in, we're seeing wells with a $6-million handle, we're seeing wells in the $7-million range, we're still seeing wells with an $8-million handle, and I think it just depends on the type of completion. Continental -- we received a handful of well proposals from them here in the last couple weeks, right in the core of Mountrail and McKenzie, and those well costs have come down significantly. But I think our average well cost is probably going to be somewhere in the $7.5 million to $8.5 million range for the year, just to be conservative.

Got you. And then, Tom, I think you were trying to address this, and frankly, I think I missed it. Am I correct in saying that the 2015 budget of $140 million -- that's on an accrual basis?

And I guess what I'm trying to get at is: I think you mentioned an $80-million-plus number -- sort of cost in process, cost accrued for at the end of 2014. Will all those cash costs arrive in 2015? What's the proper way to think about cash CapEx?

I think you're going to have a lot of that working capital that you have accrued, and to reflect it in 2014 hits you a little bit in 2015. You're going to have your working capital decrease, if you take a look at our accounts payable and our balance sheet. It's a little over $220 million; so, you'll have that flow in from a cash standpoint.

You'll end the year probably with maybe about $60 million coming out the other side. So, you'll have just a natural spend as those wells are completed of probably about $160 million -- about $140 million of budgeted 2015 development cost. When you run those numbers, that's why you're going to see the credit facility go up from $298 million to the $375 million that I was projecting at year end.

But basically on the wells that we had in process, our 2014 capital expenditures included about $86 million of spend, or accrual is probably a better word to use, for wells that were in process. So, we won't have to accrue those costs in our 2014 budget. But to your point, we'll be paying them, and that's why I was trying to walk you through, at least what our internal projections were, and try to give you some pricing information to better help you.

That's all helpful. And then, Mike, just conceptual question here: I see your hedges are simple swaps, no subfloors, you're probably about as hedged as you can be for 2015. So, I guess I'll ask about 2016. What are your thoughts on adding hedges, and would you look at swaps, or would you look at collars perhaps to keep some upside exposure?

I think it all depends on the forward curve. In years past, where we've had contango in the markets, it's become attractive to do certain collars. In the past few years, we've seen a certain amount of backwardation, where, really the best we were able to do was swaps in that $90 range.

Just a note: We were swapping volumes in the first half of 2016 at $90, when the front month was over $100. And that was -- we thought was a prudent thing to do, just given margins at $90 were quite strong for us. So, we had the courage to do that, and hedge that far out -- in the face of that backwardation.

But one thing I'll note, if I can tie it into your question, is that each one of the wells that we elect to participate in -- we're not thinking about it in an absolute oil price. We are looking at this in terms of rate of return. And we're fully prepared to put on certain hedges in the future to lock in those rates of return. Because the Bakken, as I have mentioned and Tom also mentioned in the core of the play, has some of the best returns around, and if we can lock that in, we're happy to do it. We think about this as manufacturing and returns. That's how we're going to continue looking at it, and we're happy to continue to hedge out.

Makes sense, thank you.

Adam Leight, RBC Capital Markets.

Thanks for clarifying the CapEx number. Can we extend that a little bit into 2016 -- how you're thinking about what a sustaining level of CapEx might look like?

Boy, that's pretty tough, given commodity prices. It's pretty broad because, depending on where it goes, I think that one thing you'll certainly see us do as we go into 2016, is that our estimated cash flow for operations wouldn't exceed CapEx. I think that probably maintain, maybe a moderate decline in properties if the pricing environment continued to stay low -- you're probably talking in the neighborhood of anywhere between 12 to 20 wells.

I would imagine at that point in time, service costs are obviously going to come down, if you have continued pressure from oil and gas pricing. So, if you want to pick 20 as a status quo, at a $7-million well cost, that's probably as good a number as any right now. But I would suggest to you that I think in a continued price environment with a downward pressure like that, you're probably going to see some pretty drastic cuts in service costs. So, don't want to try to avoid your question, but it's a hard one to answer, given where we are at.

I don't know why you should be any different than any other company we ask the same questions.

You tell us what your oil price assumption is, we can help you with that, but it's a little hard.

I got you. Borrowing base, Tom -- any thoughts on where your borrowing base might go with [the coming] redeterminations?

I don't see it changing very much. We are currently at $550 million. I'm hopeful to maintain that through the April redetermination.

I think probably the downside, in my mind, to that would possibly be a minor drop -- maybe 5%, $25 million or something like that -- but I don't see anything significantly happening based on the quality of the reserves and running the price decks, at least that I have in hand now. Fall -- we will have to see where the price decks are and things like that, but I think we'll hang in there pretty well. But to answer your question on April, I'm thinking not much -- maybe downside 5%.

That would be positive. Can you talk a little bit about what's involved in negotiating or whatever you want to call it, on the wells you've already consented to? Cash cost to get out of it -- some trade for something else? How do we think about that?

Adam, it's Mike. I think it's even more simple than that. In certain cases, the operators have allowed us to reverse our decision and go non-consent, because it increases their working interest in their wells. In certain wells where we were looking to get out of those obligations because they no longer meet our return thresholds, as oil approached $50, we were prepared then to assign the well bore back to the operator, which is really not much different than a non-consent.

So, we have just been in negotiations there, specifically with the specific operators, and the wells that we participate with them. And we have such a good relationship with our operating partners, that a lot of that has met with success, subsequent to the end of the year

No cash. (multiple speakers)

We don't have to pay to get out of them.

Okay, fair enough.

If I pose a high-class problem to you, don't laugh too hard. But understanding your ability to flex down your CapEx -- if your operators are becoming more conservative in the areas you'd like to participate, how much opportunities do you think there might be, if you wanted to spend more money, if the world is improving, at least in your evaluation, to do that?

Yes, I think -- I'll take your question in two different ways. We've always had a really solid pulse on the activity in the field. So, we've been able to not only increase our exposure by additional acreage opportunities, packages of deals -- Northern has been the largest non-operator in the Bakken since 2006, basically. So, we've built a franchise around basically being in the middle of all that deal flow. So, as things continue to improve, we will look to expand our opportunity set.

We say regularly, or whenever asked -- we like to remind people that, although we started the Company in 2006, we really built it in 2009 coming out of the credit crisis. So, given the scale of our hedge book, and our flexibility, and our balance sheet at this point, we're really looking at this opportunistically, and we're hopeful to take advantage of market conditions as things start to improve, whenever that is. Whether it's late 2015, or 2016 or beyond, we're going to make the right decisions.

And, like I've always mentioned, we are not going to make the determination of when it's time to start making the big moves or the acquisitions. I think the market usually tells us when it's time to go. And given the strength of our balance sheet, we're going to look at this more opportunistically at this point.

One last one for me: Do you see your private company operators behaving any differently -- more conservative, less conservative -- than the public companies that we hear from?

It seems to fall under the same -- similar percentages, especially from a rig-count standpoint. Our biggest operator, Slawson -- they were running six rigs in the core of the play. I think that's down to around two, which is, I think, healthy for them, for us, for the field. So, I think you see the private operators behaving the same way as the public operators.

One thing to note is that I think it's probably underappreciated the strength of Slawson Exploration, our partner. They're our only partner that doesn't have any debt, which is I think an important distinction with them. And they're our largest partner, so that's, we think, a strategic advantage for us.

We haven't gotten to them yet. Thanks, Mike.

(Operator Instructions)

Andrew Smith, Global Hunter Securities.

In your recent presentations, you've given an EUR assumption of 500 to 700 MBOE. Just given the increase in productivity per well that you've been seeing recently that drove the outperformance in the fourth quarter, what are you assuming for your 2015 production guidance?

I think that the production guidance was fairly clear on our earnings release. I think flat over 2014, and that's assuming basically where the commodity price sits. I think for us to -- I think what we want to do now is just be conservative on how we see the activity in the field. The rig count is going to determine production -- the production growth in the field and for Northern -- commodity prices will drive that, timing of completions will drive that.

But one thing to note is that a lot of the wells that we have received well proposals on recently have been in the upper range of the EUR brackets that we've seen. Again, in November and December, we were receiving well proposals in wells that -- and we were either consenting or non-consenting. And as commodity prices continued to decline, those wells actually didn't even get drilled, so they'll probably be re-proposed as commodity prices improve. But the ones we are seeing -- well proposals that we've been seeing here lately -- they've been right in the core of the play, where you really see some really healthy EURs.

Andrew, this is Brandon. To echo Mike's point, I think if you look at the legacy, obviously the wells that are getting through our return threshold at this point are going to bump the high end of that range of 500 to 700. Those are probably -- the new wells that are making through at these prices are probably in that 700 to 800 range. And obviously, as costs fall, that will allow some of those lower-EUR wells to meet the threshold. But certainly for the time being, the new wells that are not the ones that are in process, but the new wells that we've committed to, probably since October/November are obviously at the top end of that range.

Thanks, guys.

By definition, they're the only thing that'll make it through the IRR hurdle.

Thank you. At this time, I'm not showing any further questions. I would like to turn the call back to management for closing comments.

All right, we certainly appreciate you guys taking the time for participating in our call today and the interest in our Company. Sam, if you'll go ahead and give the replay information, we look forward to sharing our results with you guys next quarter. Everybody, have a great rest of the day and a good weekend.

Ladies and gentlemen, thank you for participating in today's conference.

To access the replay, you may dial 855-859-2056, and enter in conference ID 88433362. The replay will be available today at 2:00 PM Eastern Standard Time, and will expire March 13, 2015, at 11:59 PM.

This does conclude our program. You may all disconnect. Everyone, have a wonderful day.