Northern Oil and Gas, Inc. (NOG) Q4 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and welcome to the Northern Oil and Gas Inc. Fourth Quarter and Year End 2014 Conference Call. At this time, all participants are in listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions]. As a reminder this conference is being record. I'd 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're happy to welcome you to Northern's 2014 year-end conference call. I would read our Safe Harbor language and then turn the call over to Mike Reger, our Chairman and Chief Executive Officer, for his opening comments. And 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 on 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've 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 our 2014 modelling 15% production growth on 44 net wells 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 is 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 had elected not to participate and 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 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 wellbore, 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 than we really lose nothing because the operator would be required to re-propose the well, if and when they decide to drill and at that time, we would get the same opportunity to review and 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 and changing rapidly to today's challenging environment. And as a result, we expect drilling and completion cost to trend lower throughout the year. Operators have begun to cut capital expenditure significantly and many are delaying completions while negotiating lower cost structures with their service providers. As expected cost decline and returns improved, Northern will increase the number of wells we elect to participate in. Based on our acreage and the core of 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 look through 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 total 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 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 sub floors, 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 to 2015. I will hand the call of 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 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 of 29% and fourth quarter production of 29% as well on a year-over-year basis. Fourth quarter production average 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 successful workovers performed on some of our producing wells as Mike commented, these combined results certainly exceeded our expectations. Oil and natural gas sales for the full year 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 sale 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 differentials 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 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 to primarily to low oil prices received during the quarter. As a result of the significant drop and forward oil prices, we had a non-cash mark-to-market derivative gain of $145.8 million this quarter compared to 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 production expenses on a per unit basis will range between $9.75 to $10 per Boe during 2015. Production taxes totalled $9.6 million during the quarter or approximately 10.2% as percentage of oil and gas sales. As compared to 10.1% last quarter, as a percent of oil and gas sales, I would expect this rate to trend up slightly as we move through 2015 averaging 10.5% for the full year. Our production tax expenses 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, 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 administrative expense per Boe during the fourth quarter was essentially flat, when you compared it to last quarter and decreased 15% when compared to the fourth quarter, 2013. We expect G&A on a per unit basis to be approximately $3 per Boe for 2015. Depreciation, amortization and accretion per Boe was $29.57 this quarter, which compares to $30.34 per Boe in the fourth quarter, 2013. The depletion rate per Boe which accounts for almost all of our DD&A rate dropped this quarter, that's $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 totalled to $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 and 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 wait in completion during the year increased our capital expenditures in 2014 by $86 million. Turning to liquidity, we had $298 million of borrowing on our credit facility at year end leaving us $252 million of borrowing availability. With another $9.3 million 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 quarter adjusted EBITDA was 2.7 times at year-end. Kind of given the current environment, other E&P's have been discussing final 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 one-to-one, but allows us to include our borrowing availability under the revolver in that computation. The second financial covenant requires a ratio of total adjusted EBITDA, total debt to adjusted EBITDA no greater than four 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 $4.37 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 total debt to adjusted EBITDA at approximately three times or well below the four 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, we're 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, in average price of $90. That significant amount of hedging is extremely valuable in a current pricing environment and helps us protect our balance sheet. Second, our asset base is substantially helped by production and is located in an area with some of the lowest breakeven 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 us 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 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 have reduced our 2015 capital budget by over 70% just compared to 2014, but 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 give please give instructions for Q&A.

[Operator Instructions] our first question comes from Jason Wangler of Wunderlich. Your line is now open.

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, in the 2015 or even just a cadence of how you see that CapEx kind of 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 payable, 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 it. The numbers we provided last night and approximately 20 net wells added to production to the year.

Okay and I mean, I guess I'm not trying to hold you down on it more, but I guess would you, I guess released the cadence do you see a kind of CapEx number kind of slowing as we go throughout the year or kind of having a topping off if you will, it's beginning of the year and then kind of getting into more steady state as we go, second half, is that fair to say, I guess?

I think so, I think what we are 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 typical road restriction dates are March 15 to call it, May 1, May 15 somewhere in there. So that gives a wide range for 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.

No, I think that makes sense and I appreciate it. I'll turn it back. Thank you.

Thank you.

Our next question comes from Ryan Oatman of SunTrust. Your line is now open.

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

Yes, I think what we saw in the fourth quarter which was exciting for us. It was really a culmination of what we've been talking about over the last 1.5 year, 2 years. We keep reiterating the fact that the wells in process, the wells that were electing to participate in are all over 90% in those four core counties of Montreal, 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 right, it's just because of that core activity that we've been focusing on and then, as you can imagine, with winter months and then as we've begun to scale back activity. It's pretty easy math to get to flat production over 2015 levels. So it's really you can kind of 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 to it, so.

Hi Ryan, this 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 whether you can maybe use 2014 as little bit of analogy for that.

Thanks that's helpful. I mean, it looks like the guidance implies about, I apologize not $8 million, a $7 million average well cost. Can you speak to where those AFEs have been and where there 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 handle seeing wells in the 7 range, with an 8 handle. 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 of weeks right in the core of Montreal and McKenzie 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're trying to address and frankly I think I missed it. Am I correct in saying, 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 $80 million plus number sort of cost in process, cost accrued for the end of 2014. Will all those cash cost sort of arrive in 2015, what's kind of the proper way to think about sort of cash CapEx.

I think you're going to have a lot of that working capital that you've accrued and reflected in 2014 kind of hit you a little bit in 2015. You're going to have your working capital kind of decrease, if you take a look at our cost payable and our balance sheet. It's a little over $220 million so you will that kind of flow in from a cash standpoint. You will end the year probably with maybe about $60 million kind of coming out the other side. So you will have just a natural spend as well as a completed probably about a $160 million about $140 million of budgeted 2015 development cost is kind of 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 and I was kind of projecting kind of at year end, but basically on the wells. 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 cost from 2014 budget, but to your point we'll be paying them and that's why I was trying to kind of walk you through at least what our internal projections were and try to give you some pricing information to better help you.

It's all helpful. Even Mike, just conceptual question here. I see your hedges are simple swaps, no sub floors, you're probably about as hedges it 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, would you look at colors perhaps to keep some upside exposure?

I think it all depends on the on the forward curve in years passed. Where we've had Contango in the market. It's becoming attracted to do certain colors, in the past few years we've seen certain amount of backwardation where really the best we were able to do swaps in that $90 range. Just to 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 it was a prudent thing to do, just given margin that $90 were quite strong for us. So we have the courage to do that and hedge that far out, when in the face of the backwardation. 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 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 as to lock in those rates of return because the Bakken as I've 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 are happy to do it. We think about this is as manufacturing and returns. So that's how we're going to continue looking at it. We're happy to continue to hedge up.

Make sense. Thank you.

Thank you.

Our next question comes from Adam Leight of RBC Capital Markets. Your line is now open.

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, I mean that's pretty tough, you know kind of given commodity prices. It's pretty broad because on depending on kind of 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 continue to stay low, you're probably talking in the neighborhood of anywhere between 12 wells to 20 wells I would imagine at that point in time. Service cost are obviously going to come down, if you have continued pressure from oil and gas pricing. So if you want to pick 20 is kind of status quo $7 million well cost that's probably is good a number as any right now, but I will suggest 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 cost. So it's a don't want to try to avoid your question, but it's a hard one to answer given where we're at.

Right in way, it shouldn't be any different than any other company, we ask the same question, so.

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 within coming with your determinations?

I don't see it changing very much. We're currently at $550 million, I'm hopeful to kind of maintain after the April re-determination, 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 tax [ph] at least I have in hand now. So fall, we have to see where the price tax [ph] 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 to 5%.

That would be positive. Can you talk a little bit about what's involved in negotiating 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?

Hi, 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 wellbore back to the operator, which is really not much different than a non-consent. So we've just been in negotiations there, specifically with the specific operators in the wells that we participate with them and we have such a good relationship with our operating partners that, a lot of that is met with success subsequent to the end of the year.

No cash?

No cash. We don't have to pay to get out of it. So

Okay, fair enough and then, 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 would like to participate. How much opportunities do you think there might be, if you wanted to spend more money? If the world was 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. I mean Northern is been the largest non-operator in the Bakken since 2006 basically and so we've built a franchise around basically being in the middle of all of that deal flow. So as things continue to improve, we will look to expand our opportunity set. We say regularly or whenever ask, we'd like to remind people that although we started the company in 2006. We really built in 2009 coming out of the credit crisis. So given the scale of 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 you know we're not going to make the determination when it's time to start making the big moves or the acquisition. I think the market usually tells us when it's time to go and given the strengthen of our balance sheet, we're going to look at this more opportunistically at this point.

And one last one, from me. Can you see your private company operators behaving any differently more conservative, less conservative than the public companies that you're from?

No, it seems to fall under the same the similar percentages especially from a call it a rig count standpoint. Our biggest operators 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 under appreciated the strength of Slawson Exploration, our partner. They're only partner that doesn't have any debt, which I think is 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] our next question comes from Andrew Smith of Global Hunter Securities. Your line is now open.

In your recent presentation, you give an EUR assumption of 500 and 700 MBoe, just given the increase in productivity per well you've been seeing recently to drill the outperformance in the fourth quarter? What are you assuming for your 2015 production guidance?

I think the production guidance was fairly clear on our earnings release. I think flat over 2014 and that's assuming basically where the commodity price. I think what we want to do now is just be conservative on how we see the activity in the field. The rig count has given a determined 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 wells that we've received well proposals on recently have been kind of in the upper range of the EUR brackets that we've seen. Again, in November and December we're receiving well proposals in wells that and we were either consenting or non-consenting and as commodity prices continues to decline. Those wells actually didn't even get drilled. So they'll probably be re-proposed as commodity prices improve. So 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 and I think to echo Mike's point I think, if you look at the legacy. Obviously the wells that are getting through are returned threshold at this point are going to bump, the high end of that range of 500 to 700. I mean, those are probably the new wells that are making through at lease prices are probably in that 700 to 800 range and obviously as cost fall, that will allow some of those lower EUR wells to meet threshold, but certainly for the time being the new wells that are not the ones that are in the process, but the new wells that we've committed probably since October, November obviously at the top end of that range.

Thanks guys.

By definition, the only thing that will make it through the IRR hurdle.

Thank you and at this time. I'm not showing any further questions. I'd 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 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 day and good a weekend.

Ladies and gentlemen. Thank you for participating in today's conference. To access the replay, you may dial 855-859-2056 and entering conference ID 884-333-62. The replay will be available today at 2 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.