Good day, ladies and gentlemen and welcome to the Northern Oil and Gas Second Quarter 2015 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 follow at that time. [Operator Instructions]. As a reminder, this conference call is being record. I would now like to introduce your host for today’s conference Brandon Elliott, Executive Vice President of Corporate Development and Strategy. Please go ahead.

Thanks Ashley. Good morning everyone. This is Brandon, we’re happy to welcome you to Northern’s second quarter 2015 earnings 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. And then, Tom Stoelk, our Chief Financial Officer will walk you through 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 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. Good morning and thanks for joining our call today. Today I'll start off with how the years is played out so far for Northern. How this is setting us up for the remainder of the year and then I will share a few thoughts on how we're thinking about 2016. So far 2015 is playing out according to plan. Our guidance remains intact and approximately 80% of our expected oil production in 2015 is hedge to roughly $90 per barrel. So we have mitigated most of the cash flow volatility in 2015 that would come with a lower commodity price environment. As a results of strong completion activity and higher well productivity in the first half of the year. Our production is running slightly higher than we originally anticipated. Specifically second quarter production came in above our forecast as per well productivity of the new additions increase due to our operating partners high grading the drilling activity in the core of play. Capital expenditures have been trending basically in line with our expectation. Year-to-date capital expenditures have been roughly 78 million of our $140 million budget. Based on our expectations for net well additions in the second half of the year we continue to believe that we are on course to meet this CapEx guidance. Operationally we have added 13.5 net wells the production so far this year. While in a normal year we would expect 40% of net well additions to come in the first half of the year we are expecting the opposite effect this year were 60% of our estimated 20 net well additions completed in the first half of the year. As of June 30, we had 10.8 net wells in process on our drilling and completion list and we expect add approximately 6.5…

Thanks, Mike. Today, I am going to cover some of the financial highlights for the second quarter and provide some commentary on our liquidity and capital expenditures. Adjusted net income from the second quarter 2015 was $11.5 million or $0.19 per diluted share. Adjusted EBITDA for the second quarter were $70.4 million. Both of these amounts were impacted during this quarter by local crude oil, natural gas and NGL prices. Production was up 8% year-over-year, the second quarter production averaging 16,610 barrels of oil equivalent per day. The year-over-year production growth was primarily driven by the improved economics and recoveries on the 34 net wells added to production over the last 12 months. As Mike, mentioned earlier we entered the year believing that well completions would be lighter in the first half and heavier in the second half as operated for weighed out service cost reductions and commodity price recovery. As it turned out we added 13.5 net wells to production during the first half putting a slightly ahead of our internal production estimate for 2015. Realized price per barrel of oil equivalent after reflecting our settled derivative transactions was $62.22 per BOE for the second quarter which was down approximately 21% on a year-over-year basis. This decrease were due to low commodity prices, lower commodity prices in the same period a year ago. Our average oil differentials to NYMEX WTI benchmark was a $11.50 per barrel in the second quarter of 2015 this compared to a $12.25 per barrel in the second quarter of 2014. We recently seen an improvement in oil differentials and expected they will trend towards $10 a barrel for the second half of 2015. In the second quarter of 2015 oil, natural gas and NGL sales, which include the effect of our settled derivatives totaled…

Thank you. [Operator Instructions] Our first question comes from Scott Hanold of RBC Capital Markets. Your line is open.

Thanks. Good morning guys.

Good morning Scott.

Mike, if you could go a step back in just again give us your views on how you take a look at the well proposals deciding to elect or non-elect in them. In this oil price environment obviously with productivity increasing and cost coming down more these walls may make your hurdle rate as thing focused on the core operative. If we get into 2016 and you are seeing improved economics, but still a modest oil price recovery. How do you balance between AFE is meeting that threshold versus trying to keep the balance sheet where you wanted to be?

I think the process that we’re using essentially solves for all scenarios, each time we receive a well proposal we are going to run our internal price tag on the three-year strip, which is getting us fairly accurate prediction of kind of where we are going to be with the assumption that we’re going to continue to layer and hedges as we go. And as you know in the first half of 2016 we were running economics in the low 60s because there is a certain amount of Contango in the futures curve for the next three years and as we just mentioned we were able to then layer and 65 WTI swaps in the back half of 2016 and will continue later in hedges, essentially opportunistically. The way we are looking at if you just want to quantify it and Scott you and have done this in the past. You kind of look at the number of rigs that are in the field you look at how many wells each rig can drill per year use assume that Northern is generally can be in about 25% of the wells that are drilled in the field. You can pretty quickly come to around that 15 to 20 net well-arranged as far as activity goes. That map works itself out pretty accurately. The way were seeing the rig count stays that around 75 is pretty clear how much activity we are going to be seeing for the rest of 2015 and then going into 2016. If you just assume all things remain equal. So we feel really good about our estimates and our thoughts the bottom line is commodity prices improve, rig counts increase obviously your activity levels can increase. However you know cash flow continue to increase and will basically grow with the field. But we really in a good spot as far as deciding on estimating were we’re going to land from CapEx and cash flow standpoint. And again as always Northern is an IRR driven shop you know we don't we don't have any opinions about oil here we look at the returns on each and every individual well and has an operator at each well comes in we get to decide specifically whether we deploy capital to that project or not.

Yes, just to clarify something you'd mentioned about looking at layering in hedges you know for Roger confirming is that more conceptually or is that what we should expect as you continue to obviously go into - in the 2016 is that you will later on hedges as you add these at the wells?

I think the answer is yes and more specifically just incrementally, if you look at Northern’s behavior over the last probably 5, 6, 7 years. We’ve usually been hedged out about we typically been hedged out about two years. And so we will continue to layer in hedges as we move on through the year. If you look back based on the current commodity prices you’re going to see the corresponding amount of activity in the field and so it correlates very nicely with commodity prices if oil prices stay in the 40s, low-40s for the next year. So you are going to see activity levels continue to go down. And so you will see CapEx continue to go down. And therefore we won't have the same needs to hedges much however we will continue to layer in sort of incrementally which we always have to keep about a two-year hedged book. Right now were hedged through is got a pretty substantial hedged book that goes through December of 2016. So we feel really good about it.

Okay understood and one of the other things that you all done pretty well over the last few years is the acreage capture opportunities and there been some larger operators in the core the base that had the indicated that they monetize some of their non-operated activity you tighten up their budgets are you all seeing any of that occurring and participated any of it?

We are seeing a lot of different opportunities what we do best Northern as you know is we see a lot of the really potent smaller opportunities were we are picking up no 100 acres here or there to come with other existing production or mediate drilling activity we see a lot of that stuff we operate really well in that environment. We’re starting to see more and more of the larger packages, but I'll just reiterate that as far as Northern is concerned we’re very comfortable with our liquidity position and from our standpoint we are going continue to be very patient as it relates to the larger acquisitions. In the light of just protecting our precious liquidity cushion.

Okay thanks and may be one last one for Tom on the liquidity front. Can you discuss know what you anticipate from the [indiscernible] basically termination?

You know we are not really expecting in a significant movements to be [indiscernible] we are expecting and thanks we are other there price tags from what was on the spring this fall but I think offsetting that lease in our cases is larger reserve, better reserve the reduced completion cost and in the improving differentials I think at least in our individual situation more than mitigate that. So I am not expecting much nothing significant Scott.

Appreciate it. Thanks, guys.

Thanks, Scott.

Thank you. Our next question comes from Neal Dingmann of SunTrust. Your line is open.

.:

We continue to see, as I mentioned a lot of really potent smaller opportunities, some of them come in and some of the wells were we've seen existing, where you have existing working interest, that actually is something that we’re really good at here is consolidating up our higher working interest in the wells that we are actually electing to participate in. But again Northern effectively run primarily by you IRR analysis. And so if there is a well that meets our internal rate of return thresholds it's very likely that there are other participants in that well who have more precarious balance sheet issues or liquidity issues and we’re able to take advantage in some of those opportunities.

Okay and then just secondly Mike when you're looking at, all the hedges that you got on right now. Any thought that there be a certain price range when you see you know what you can do additional deals that. So I guess my thought is any thoughts about where you would monetize some of these hedges and then take them redeploy that either buying some stock back or actually you are looking at more acreage?

Yes. I think we’ve looked at our hedges very simply and that the only reason we've ever added hedges or layered in hedges in the past few years or forever basically has been to mitigate cash flow volatility. So we don't have any intention of monetizing these hedges, these hedges are primarily or I should say 100% to mitigate cash flow volatility.

Just locking to returns over electing gift.

Yes.

All right, thanks.

Thank you.

Thank you. Our next question comes from Sameer Uplenchwar of GMP Securities. Your line is open.

Thank you. Mike on the hedging question. So what do you need to see to layer in more in the back half of 2016 going into 2017? How are you looking at it considering the AFEs and trying to manage that, right? Like how much production you are going to have in the second half of 2016 and 2017 and how are you looking at it? Could you walk a little bit?

Yes, thanks for that question. We naturally just roll it as we’ve been going and depending on, if oil prices remain lower here, a lot of wells that well proposal, we see may or may not get drilled will see a significant slowdown in AFEs. So it's really a nicely correlated system where as oil prices began to perk-up which they did, if you remember just after Easter you saw oil make a move from the low 40s up to the low 60s, obviously increased activity in the field that increase the number of wells that we're electing to participate in and we continue to that we began layering an additional hedges into the back half of 2016. So as we go, we’ll just be monitoring essentially, activity will be monitoring the number of wells we’re electing to participate in, you know obviously we've had in the last month year here we’ve had a pretty material drop in oil prices, which we think would again limit the number of wells that would pass our current internal rate of return threshold. And so we’re just going to opportunistic and layer them in almost robotically, as we as it relates to the wells that were electing to participate in.

Got it. And then on the E&D front I mean with the oil price coming down like you said, what are you seeing out there in the field, is the bid ask spread coming in, is it still wide like what's some color on that end would be great?

I think we’re on the front edge of the bid ask spread tightening. I will just say that that if you do the work on Northern you'll find that Northern has a really nice liquidity cushion as it relates to some of our peers. We know that there are assets out there that we would love to own, but we are going to be patience and we are going to watch this oil cycle on fold and again we are going to be very patience. We are not actively looking for big acquisition if we see an acquisition that is really good we are going to be looking at that acquisition primarily through what that means for our liquidity position.

Got it. Thank you.

Thank you.

Thank you. [Operator Instructions] Our next question comes from Adam Leight of RBC Capital Markets. Your line is open.

Hey, good morning everybody.

Good morning, Adam.

First question I appreciate the color you provided around the estimating well count, do you have any level of higher confidence in a specific set of wells that you - will get drilled next year that are less sensitive to pricing so you can put your confidence in more than just general estimate?

Yes, if you look at where the existing 75 rigs are in the field and you can see this from the North Dakota Industrial Commission website and just look at it every day it is updated literally daily. You can see where the rigs are located and based on the different operators and where they are actively drilling where our acreage sits within those operators - those operators field. We have a really good idea of where we are going to see our activity and the math again it's surprisingly easy when you look at that our relative activity to where the rigs are currently located. So we a - and we have a really good idea now as the Bakken is roughly and it’s fairly a mature field. We are seeing these permits at AFEs companies operators in these areas we know what the EURs are going to be on each one of these wells. It actually makes it fairly easy for us to model with 75 rigs in a very defined bull's-eye or very defined core of the play.

That’s great. Thanks. And sort of on the flipside of the non-consent issue what have you seeing and this probably changed, but in the wells you did go non-consent what proportion of those actually got drilled?

As I mentioned in my earlier comments in November and December we were only electing about 25% of the well proposals that we are receiving. However, of the 75% that we non-consent it very few of those actually got drilled because it's really a delay issue by the time the letter goes out and the 30-day period starts to come to an end. The operator has 90 days to spud that well or else they have to re-propose or rebalance the well and so in most cases we got a letter from the operator saying that they weren’t actually going to spud the well and they would re-propose those well at later date. So that's really nice from us from an inventory standpoint so we didn’t missed out on any of those spuds and I think our operators are being smart about this. We are not in an acreage holding pattern here this is - every well that being drilled is being drilled because our best operators are drilling their highest return wells now and only their highest return wells now with a very limited number of rigs. So we are pleased with the way that this is playing out and we are pleased with our liquidity position. Our operating partners are strong and so we are excited to just to weather the storm with good operators and really good decision-making on their part.

Okay, that’s great. Sorry if I missed some components of what you said. On the differentials to what extent is there any - how much flex is there in the percentage differential as we see prices go down. I forgot what the component is that’s related to marketing gathering costs as opposed to just revenue of that price?

Yes, I guess I’ll just try to capture your questions with one simple answer is that couple - one point I’ll make is we are still in that roughly 50% pipeline, 50% rail environment as you get into the 2016, 2017 and beyond it’s going to be significantly higher from new pipeline, capacity coming on so that’s going to be really positive for us starting next year. One other - as we looked at differentials in the second quarter differentials were coming in and approaching 10 and in some instances with certain operators in the single digits as we got into June. And so were really - were optimistic that differentials will continue to tighten here, but they’ve been improving over the last really last month or so two months or so.

That’s great and then lastly on working capital can you give us an updated estimate of what you think you might be seen in working changes sources uses in the next quarters?

We kind of reaffirmed our 140 million budget on the cap spend and I think when you take a look at our, you are actually cash spend for the first half it was heavier in Q1 right around 45 million in a dropping to 33. I think you'll probably see it trending down as you go into Q3 and trending down again if you go into Q4 probably cash spend if that’s what’s you are asking me is probably slightly under maybe 50 million to 60 million probably little higher in Q3 little lower in Q4.

Yes, I am Tom just to clarify was asking on working capital is separate from the budgeted CapEx?

Okay well we ended the quarter with working capital of around $21.5 million I think that’s going to increase probably 20 million, 30 million but that’s going to be highly depended on obviously the price while the timing of receives and things like that. You will continue to see improvement would be my expectation as our cash spending as we kind of work of that high level of wells and process so we had coming in the beginning of the year.

Okay, I will make the rest offline. Thanks.

Okay.

Perfect. Thanks, Adam.

Thank you. Our next question comes from Phillips Johnston of Capital One. Your line is open.

Yes. I just want a follow-up with Tom, just on that CapEx, that the cash versus the accruals. It did look like the increase in your liquidity was maybe about $55 million or so less than what it should have been if you just everything, is that just a difference between the percentage of completion on accrual amounts on a GAAP basis versus actual cash out the door, I mean is that mainly the explanation?

Yes, effectively it’s just, it’s really driven by the decrease in wells and process and that’s what’s causing kind of the higher cash expenditures versus reported capital spend. Our cash flow from kind of those investing activities that you see reflected kind of in the statement of cash flows related to the actual cash spend and it’s not always reflective of kind of the current levels with development activity. For example if you think about, during the first six months period of this year, our capitalized cost reported were roughly around $77.9 million, but when you take a look at our cash flow the actual investing activities was about $188.3 million and the delta between that is really just as we continue to work down you know that wells and process amount. So you are going to kind of continue to see that trend down it was about $110 million in Q1, it was about $77 million, $78 million in Q2 on a cash - you will continue to see that go down. And that’s one of the earlier responses as well as referring to. I think you will see a spend roughly around $60 million in cash spend if you are trying to zero in on where you think you are going end on the revolver.

Okay. That completely makes sense. Just second question your DD&A run rate fell from about $30 a barrel in the last six quarter or so it’s just under $25 a barrel. What drove that and what are your expectations going forward?

Really it’s the impairment so when you impair your oil and gas properties you reduce the amount of the net asset and you still have the same kind of amount of reserves, so the denominator stays relatively the same, but the numerator which is the basis of the oil and gas properties is reduced by the impairment. And so the rate that I gave you in the script with a little bit under $25 per BOE is our expectation in the second half. That’s probably a pretty good number for Q3 and then if there is another impairment which I think we expect another impairment in Q3 just due to the continued low commodity prices in the way the SEC pricing works. We are replacing higher dollars with lower dollars in that computation. You’ll continue to see a drop probably little bit further in the fourth quarter, but until we get to the third quarter we won't know what that answer is.

Okay, it makes sense. Thank you.

Thanks.

Thank you. And I’m not showing any further questions in the queue. I’d like to turn the call back over to management for any further remarks.

All right. We appreciate everyone’s participation in the call today and your interest in Northern Oil and Gas. Ashley, if you’ll give the replay information. We look forward to talking to you guys again next quarter on the road soon. Thanks.

Thank you. For this calls replay information please dial 800-585-8367 or 855-859-2056 for international dialing its 404-537-3406. Please use the passcode 94735042. Ladies and gentlemen, thank you for calling in today. This does conclude the conference. Have a wonderful day.