Brandon Elliott – EVP, Corporate Development and Strategy Thomas Stoelk – Interim CEO and CFO.

Neal Dingmann – SunTrust Robinson Humphrey Unidentified Analyst - Raymond James Scott Hanold – RBC Capital Markets John Aschenbeck - Seaport Global Securities Sean Sneeden – Oppenheimer & Company Owen Douglas – Robert W. Baird Jason Wangler – Wunderlich Securities.

Good day, ladies and gentlemen, and welcome to the Northern Oil and Gas Incorporated First Quarter 2017 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will be given at that time. [Operator Instructions].

As a remainder, this conference call maybe 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 thanks everyone for joining the call today. I'd like to begin the call with a few operational and financial comments, to provide some color to review 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 of capital spending over the last two years and 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 of 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 number of well proposals we are receiving.

We elected to participate in the majority 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 two net wells that were added to production.

As a result our inventory of wells in process grew to 15.9 wells at March 31st which we anticipate will begin to decrease as weather improves and operator began ramping up completion activities.

As we've discussed before over half of our uncompleted wells that are operated by continental resources who had 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 tight curve which is 59% over a 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 profit are tracking at 1.2 million Boe average type curve. So far we are continuously look for the productivity increase improvements in 2017.

Early results on our 2017 well additions are indicating a 30 day average IP rate of approximately 1485 Boe per day which is a 34% increase over the 30 day average of our 2016 well addition.

We believe the improvements we are seeing are representative of the quality of our acreage and the performance improvements of wells using enhanced completion techniques. We 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 giving the increasing number of wells on our in process list. Our improved well performance is being complimented 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-operative 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 to the current and future commodity 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 two thirds 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 the costless collars with a floor price of $50 and 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 bulk in differentials will range between $7 and $9 per barrel. There is a potential for future improvements once pipeline additions are brought online later this year.

Lease 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 a 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 non-cash 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 EUR 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.

Alright at this time we will turn the call over to the operator for Q&A, if you can please give the instructions for the Q&A portion..

[Operator Instructions]. Our first question comes from the line of Neal Dingmann from SunTrust. .

Good morning gentleman. First question, it still seems get a reasonably bit in defensive mode and with that sort of backdrop as you continue that critique deals you are looking.

What are you getting as far as percent working interest size, is that range or is that still staying pretty consistent?.

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

Okay, and then -- you mentioned that in the press release today it does sound like all those wells, one of the operators there have definitely seen some improvement on the enhanced completions, can you just talk about that discussions you're having is in most areas is just more a better across the board or how do you all view that?.

Yeah, I think our view is that it's pretty much better across the board when they're using the enhanced completions in the higher profit 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 QE P&L stuff, the foreman wells which were in on the Southern envelope and they had over a 2800 barrels oil equivalent per day.

One of our operators WPX announced some great results on a 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 estimate of rates of return given our performance kind of in the recent completions with respect to that.

We are fairly well exposed to Continental on our drilling and completion list. We have a little over 100 growth wells on that list and Continental had indicated not only an 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, a 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 get up when it comes due in 2020 or something like that or a few years.

I mean and 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 liquidity you have and given that CAPEX programs just kind of take it to kind of what you're doing right now instead?.

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

Very good, thanks so much Tom. .

Yeah, thanks Neal. .

Thank you and our next question comes from the line of Carlos Noah [ph] from Raymond James. .

Good morning guys.

Well so this past quarter you indicated average these 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 especially with upsize 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?.

You know 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 amount 5% per year. Some are more able to offset that with -- kind of with a multipad 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. .

Yeah, Carlos this is Brandon. I think you mentioned the AFE that you have a consent continues to turn down, obviously the wells that we're bringing on and the wells in the DNC list had 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 cost that are in 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 consent to this quarter and last quarter will be the well add cost as we move forward over the next couple quarters. .

Got it. It is very helpful.

One quick follow-up, what percentage of wells are being non consented and how does it compare to last year?.

You know 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. .

Thanks guys, that's it for me. .

Thank you and our next question comes from the line of Scott Hanold from RBC Capital Markets. .

Good morning Scott. .

Yeah, thanks, good morning.

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 is at right now.

Considering that obviously when your not op partners are drilling really good wells, Continental and is going to get the work pretty aggressively here, how do you step back and look at the fact that you've got liquidity and leverage ratios maybe a little bit high and you've got some uncertainty involved 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?.

I think kind of a multipart answer a little bit. One is that over the near-term as you mentioned we have -- we are in a good liquidity position with respect to that. And one of the ways we maintained that obviously as you referenced is increasing our hedging levels.

So we're about two thirds hedged through 2017 and we have about 2 million to 2.1 million of hedging in 2018. 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 but 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, what can you say, where we're at right now and it seems like there was a little bit more of an hint of a direction here and 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 both things on that -- or merger is something that may makes sense?.

Well, yeah, we won't comment on any of the specific transactions going forward. But to your point, the strategic of this process is still ongoing. I really won’t add to the comments other than what I 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 we will be able to execute on what we've got in front of us and outside of that I really can't comment any further..

That's fair enough and if I can just slip one more quick one on differentials, obviously things it looks like they're set to improve.

Is there anything internally you guys could do to even further enhance that, have you looked at in doing a little bit more in the marketing effort, are you typically going to look more to basically sell your oil to your operating partners?.

Yeah, 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 the second half of the year, middle 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 more sense just to market it with your operating partners versus trying to take that in-house?.

You bet. .

Okay. Thank you..

Thanks Scott. .

Thank you. [Operator Instructions]. Our next question comes from the line of John Aschenbeck from Seaport Global. .

Good morning John..

Good morning, thanks for taking my question. I had a follow up on the high intensity completions, obviously some really strong results so congrats on those.

I was just listening to other operators across the basin, it seems like the general idea right now is that more profit is better and really the focus is just determining at what point you hit a level of diminishing returns more or less 10 million pounds, 20 million pounds, etc.

So since you had such a large sample set as a non operator was curious if you've seen anything that might suggest where that optimum amount of profit might actually lie?.

You know I think everybody is 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 it and -- more naturally fractured, you're not seeing the operators use of much profit there but I don't think they have 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 advantage point we’ll let the operators call when they think they have seen the diminishing returns but probably too early to tell from our perspective but no sign that we've hit it quite yet. .

And certainly great results when it's around 10 million pounds and just getting higher to date what we've seen. .

Got it, appreciate it, it's really helpful. And just couple of follow up here on 2017s production profile.

It seems like you’re going to have some nice momentum exiting the year, was wondering if you could continue that sequential growth profile as you head into the next year, just -- go ahead?.

Yeah, I would think you'd actually see some sequential production growth in 2018 to your point where we have 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 would continue to see some small sequential growth again as we exit 2017 kind of in the 2018 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 maybe mid single-digits to get us -- to get us to that guidance and obviously that exit quarter rate would put you at a little built in sequential production growth or built in growth in 2018.

Obviously don't forget that we typically assume that 1Q and 2Q are the kind of tougher weather quarters, don't necessarily have sequential production growth. So when you when you look at 2018 keep that in mind. .

Okay, got it. I think that last point was kind of what I was getting at, that’s all really helpful. Just 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 well or is it perhaps you know it's... .

It depends on the quality well obviously but it's somewhere in the 10-12 range should be where I would peg it right now. The pipe fees are certainly up so that's causing me to maybe think that it's a little bit lower than the 12 week given to you historically but right now I think I would range you between 10 to 12. .

Alright, great, appreciate the time. That’s it for me. .

Great, thanks. .

Thank you and our next question comes from the line of Sean Sneeden from Oppenheimer..

Good morning Sean. .

Good morning, how are you? 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 you could you give us a sense of how you're thinking about pushing out that maturity I believe starts…?.

Yeah, this time around we really didn't really talk about amending and extending the term on the facility. As you know it's got a September 2018 maturity on it and it is something that we're clearly focused on.

So we’ll likely be addressing that either next determination or the next six to nine month period 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 six months. .

Okay, that makes sense and is the ultimate goal there to try to have something similar to what you having right now or meaning can just support extension of kind of a borrowing base facility or you looking at other options?.

Yeah, I mean I think you always consider other options but at present you know we like 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 new gas realizations pretty significantly versus the fourth quarter, what was going on there, was that -- I guess how should we be thinking about that type of realization going -- your NYMEX Gas?.

Well I think it was really the impact of NGLs kind of in our blended pricing and really 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. .

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

Hold on a sec, we’re looking. .

36% are NGLs and propane probably makes up about a third of that. And I'm not sure that I got the data in front of me..

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

Okay, we’ll follow up on that. .

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

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

Okay.

And then just in your slide deck, slide seven 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?.

Yeah, at the time we can sense on those and obviously as Tom mentioned kind of going back to the hedging thing 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 this trip to kind of lock some of that in but yes, a short answer is at the time of consent.

.

Okay, and just to be clear are you guys using your hedge gains or losses between your IRR calculation, or was that just going to….

No, no, we're not..

Okay, perfect. Alright, thanks guys..

Sure, thanks. .

Thank you and our next question comes from the line of Owen Douglas with Baird. .

Hi, good morning guys. So by the way it was pretty good news about the borrowing base determination, only $25 million decline so good job there. .

Thanks. .

And just to an earlier question around the 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 is 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 did that sort of affect any sort of thoughts on your ability to go out and sort of snap up acreage position or in existing wells?.

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 wellbore sort of acquisitions. We've picked up a small amount of acreage in the current year and will 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 have to step back and look at how we do it. But day in and 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 of 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 non-organic 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 kind of utilize the current revolver capability, you would probably look for something a little bit more longer-term financing?.

Yeah, 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 -- it's a more longer term financing if such an acquisition were out there. .

Okay, that's pretty helpful.

And then final one from me here, just wanted to get a little bit of an update, I think I ask this almost every quarter, how was that A&D market looking, can you give any sort of updates whether it's directionally, whether you have seen bid outspreads tighten, increased competition, just really any color would be greatly appreciated. .

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 a drop in WTI it's got some people kind of, you know, I think it softened just maybe a little bit with respect to what the seller and buyers 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 are permitted over our acreage and things like that.

But, A&D wise I think I characterize it as remaining strong but, I think in the real recent term given the volatility in the commodity on the oil side, it has 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. .

Okay, thank you very much.

Thanks..

Thank you and our next question comes from the line of Jason Wangler from Wunderlich. .

Hey, good morning guys.

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 then obviously you're at 6.6 is what it looks like for first quarter, obviously it 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 -- as you are looking at them today even are you still seeing those well cost coming in around that 6.6 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 up profit there.

I would think that where April AFE election rate was more like 7.3 million so, I think 7 to mid 7 is probably if you're looking going forward kind of what our expectations is..

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

Yeah, as I mentioned before about 85% of what we elected to in Q1 was completion, that was up even higher percentage back in Q4 so..

Jason, I think if you look at 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 six months.

But to Tom's point I think that 7 million range given the enhanced completions is probably a reasonable expectation at this point..

Okay, great, thank you guys. I’ll turn it back..

Great, thanks Jason. .

Thank you, 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 in 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 1474-1485. International callers may dial 404-537-3406 and again enter the code 1474-1485. That does conclude our conference call for today. We thank you for your participation, and you may now disconnect.

Everyone have a great day..