Good day, ladies and gentlemen and welcome to today's Northern Oil and Gas Third 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 is being recorded. With us today from the Company is the Chairman and Chief Executive Officer, Mr. Mike Reager; Chief Financial Officer Mr. Tom Stoelk and Executive Vice President, Mr. Brandon Elliot. At this time I would like to turn the call over to Mr. Elliott. Please go ahead, sir.

Thanks, Nikita. Good morning, everybody. We are happy to welcome you to Northern's third quarter 2015 earnings call. I will read our Safe Harbor language and then turn the call over to Mike for his opening remarks 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. Reconciliation 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'll turn the call over to Mike.

Good morning and thank you all for joining our call today. The third quarter was another solid quarter for Northern as we continue to bear the fruit of being 80% hedged at $90 a barrel. As we wrap up 2015 and look toward 2016 we will continue to focus on capital preservation with an eye towards remaining flexible and opportunistic in the volatile environment. During the third quarter our positive cash flows allowed us to pay down the balance on our revolving credit facility by $18 million. And after a completion of our recent bank redetermination our borrowing base was reaffirmed at $550 million which provides us of $380 million of current borrowing availability under our current credit facility. We believe this demonstrates the confidence our bank group has in the quality of our assets and in the execution of our strategic plan. We will also continue to leverage our franchise as the largest non-operator in the Bakken play by acquiring acreage and working interest in active drilling units that meet our internal rate of return threshold. Our non op business model allows us to be very flexible on deployment of our CapEx. We continue to participate in highly economic drilling opportunities as well costs have dropped significantly and drilling activity is focused on the core of the Bakken play where Northwestern holds meaningful lease hold interests. During the third quarter we added 85 gross 2.7 net wells to production. Wells brought online by Conoco in the Corral Creek field in Dunn County, made up 40% of the additions with Slawson's wells in Montreal County making up a significant portion of the rest. All of the wells added to production this quarter were in the core of the big four Counties of Montreal, McKenzie, Williams and Dunn. Given the current…

Today I'm going to cover some of the financial highlights for the third quarter and provide some commentary on the liquidity and capital expenditures. Adjusted net income for the third quarter of 2015 was $14.6 million, or $0.24 per diluted share, adjusted EBITDA for the third quarter was $71.7 million. Both of these amounts were impacted during this quarter by the lower oil and gas prices. Third quarter production averaged 15,844 barrels of oil equivalent per day in light of the low commodity price environment our annual capital expenditures budget has declined approximately 74% in 2015 as compared to our actual CapEx spend in 2014. Despite the reduction in capital spending our year-over-year production growth for the first nine months of the year was 9%. The year-over-year production growth was partially driven by completion of a large well inventory entering this year as well as improved economics and recoveries on the 24.4 net wells that we added to production over the last 12 months. A lower level of well completions during the third quarter caused production levels to be approximately 4% lower than the same period a year ago. Realized price per barrel of oil equivalent, after reflecting our several derivative transactions, was $63.62 per BOE for the third quarter. The 14% year-over-year decrease was due to lower commodity prices than a year ago. Partially offsetting the lower commodity prices was an improvement in our average oil differentials to the NYMEX WTI benchmark that averaged $8.24 per barrel in the quarter of 2015 as compared to $12.93 per barrel in the third quarter of 2014. Oil, natural gas and NGL sales, when you include the effect of settled derivatives, totaled $92.7 million in the third quarter which was a 1% sequential decline compared to the second quarter of 2015. A…

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

Hi, Mike, when you are looking at, I guess two questions here first. Just on that slide, you know, where you always show the inner circle and outer. Today is everything, how focused is that on, let's call it even the core of the inner, you talk about which ones you are contending to?

I think anything that we are seeing penciling today is in that red circle on one of our slides in our slide deck on our website. We continue to see, the bulk of the deals that we are buying and that the deals that are attractive to us, acreage and working interest in, within that circle. And it is usually because some folks might not have the capital in this environment to participate in those wells and given what we just covered with the liquidity position, we are actively adding in that inner core, bullseye.

Mike and then, just the follow-up as far as, when you look at, I guess going to next year based on different sensitivities how do you see non-consent activities? Percentage wise, are you still consenting to most?

Till year to date we have elected to 72% of the well proposals we have received. And then one thing we have been highlighting and that we’ve also noted is that of the wells that we non-consented, we have some of those wells haven't been drilled. Therefore at the end of, after 90 days, if we non-consent a well after the well proposal is due, if it hasn't been drilled in 90 days, the well proposal has to be re-sent and that typically means that the operator isn't actually going to drill that well so we get another kick at the cat there. So we are pretty pleased with the way the operators are behaving and their particular capital. We haven't seen a lot of well proposals to drill wells in areas that at this current commodity price would be uneconomic. So we are feeling pretty good and I think our operators are making great decision.

That make sense. And then, just lastly, you had a nice debt pay down and kind of alluded to that. I guess, your thoughts going forward if you continue to have this positive cash flow will you continue to do so?

Yes, I think we will have, we'll kind of stay in the positive cash flow in the first quarter and then through 2016, as we sit here today we are probably at about 160 million outstanding on the facility with about 16 million in cash. We have got a semiannual interest payment coming up 28 million 1st December. But as I look at the facility, I think we will probably finish probably fairly flat given that we have an interest payment but from a positive cash flow standpoint I think we are kind of over the hump and you are going to see that this quarter as well as through 2016.

[Operator Instructions] Our next question from the line of Peter Kissel with Howard Weil.

Good morning, guys. I guess, I want to start with on the AFBs we've heard operators talk about well costs with the five handle, your average is more in the upper sevens right now. Just curious to see, is that more of an operator mix? You highlighted Conoco and Slawson Recently is it the frac designs and maybe more than anything, do you think that that could come down materially, kind of, closer to that five to six range?

Yeah, I think that 7.7, Pete, is the year to date average. The bulk of all of the wells that are in process drilled yet uncompleted. We are seeing a lot of wells with a five handle on them. Slawson continues to be a leader in the efficiencies standpoint. But we are seeing a lot of these wells come in with the higher intensity completions, which we think are going to be in the neighborhood of the low 7.7 range. Right now an average mix. But year to date that was the number we shared which is roughly 7.7 so that's a good basket of what we participated in so far.

And then second you mentioned that 60% to 70% of your wells in progress won't be completed until 2016. I'm just curious is that an indication of when you think prices are going to improve or is that when costs come down enough to incentivize the completion of those wells or that come from some sort of dialogue with the operator that you've had? Just curious as to your thoughts there.

As you know, we don't have an opinion on oil prices here. I wish we knew. But I would say that as the largest non-operator in the play we have great relationships with our operating partners and we continue to talk to them every day as it relates to our mix. We are trying to figure out how we can model and best illustrate what our CapEx will be for the fourth quarter and 2016 and they are pretty open about which quarter and which month they intend to complete some of these wells. Now, if oil prices deteriorate some of their estimates for completion in the first, versus second quarter that could get pushed out. The short answer is it is the dialogue we have with our operating partners.

Thank you. Our next question from the line of Scott Hanold with RBC Capital Markets.

Mike, you talked about, obviously, a lot of opportunities out there and smaller deal and larger deals and what not. Can you just kind of step back and, obviously at these reduced oil prices, what are the strategic priorities there in terms of if something comes up that is a little larger, how do you take a bite out of that and is that even something you want to do at this point?

I think that as some of the larger deals have been marketed we are doing the engineering work we are using, we are essentially using the existing strip to model and make our decisions on what kind of the return we would require from any acquisition whether it's large or small. On the larger transactions we have essentially yet to be successful on anything of any size. We are seeing private equity firms beat us out, from what we understand they're using the strip for a year or two and then they're using, sort of, flat call it 65, 70, 75 tiered up as we go and that's not really reflective of the existing strip. The short answer is that we are going to remain very disciplined and we are going to make our decisions based on our ability to lock in cash flow on those volumes that we are acquiring. What we are seeing, that it is more attractive, are some of these smaller deals that Northern has really built a pretty meaningful franchise around for the last ten years. So we are going to continue to pick away at this field like we always have. If there is an unique opportunity where we can take a bigger bite of something we are going to be conservative about our, conservative and disciplined about the price deck we are going to use. We are just being disciplined. If we don't get anything we don't get anything but we are going to keep working and we keep evaluating every interesting opportunity that we see. We definitely have our engineers working overtime.

So as you make these decisions it seems like you guys are kind of leaning on the strip a little bit more in terms of whether or not we can do it and what's that. Is that a fair statement?

I think that's probably the best way to look at it at this point. I don't think there is any clarity. I don't think anybody has any clarity on where oil prices are going to be. So I think the most disciplined way to go about this is to use the strip.

Okay. Okay. Fair enough. And then one other question kind of going back to the AFEs you have in process indicated there was about $7.9 million. What are the chances that when those actually costs, do actually shake through that there is going to be some sort of adjustment on those numbers? Is that a highly likely event where it looks like $8 million now but ultimately when these guys drill they're come in at $7 million, $7.5 million or something to that effecting? Have you seen a lot of that as you've done your, kind of, accrual adjustments for the year?

We've seen that over the last year, we have seen that occur as we go. But the way we look at it it's pretty simple, we take the, essentially, the weighted average AFE that was sent to us by the operator and that's just input into our system and that's how we model and track it. Actuals, obviously, would likely continue to come down when we are sent our joint interest bills those actuals will likely be lower because we've continued to see and we continue to hear from our operators that costs are still trending down. So, again, $7.7 million has been our average, weighted average AFE, year to date on the in process wells.We think that lately that's probably going to be closer to the low sevens and then actuals we'll just see. But we've seen that trend as the wells have been completed and we've seen the joint interest bills flow through. We've seen the trend of lower cost, actually, follow through.

Okay. And you guys obviously were very well hedged this year and have a good position going into 2016. At what point do you consider more hedges to continue to protect the downside or do you not think it makes sense at the current strip?

Well, I think it's all dependent on how much CapEx we are willing to deploy. We feel really comfortable with our hedge book now. Maybe a little over 40% of our production in the first half is hedged at 90. The first half of 2016. And then the second half of 2016, a little over 40% of our production is hedged at 65. We layered the 65 swaps in May when the oil price perked up there to around, the front month perked up lot close to $60. Will continue to be opportunistic there. But I would say that we will always be disciplined, if we make any meaningful acquisition or if we begin to meaningfully more CapEx we have no problem locking in the first couple of years of cash flows at the strip that we are using to evaluate those opportunities and those drilling projects.

[Operator Instructions] Our next question from the line of John Aschenbeck.

Good morning, everyone. I had a bigger question about the Bakken in general, since you all have such a large footprint there. What's your sense of total in ducts the play and how do you think operators are thinking about adding ducts and putting them online going forward?

Well, I think the way we are hearing it from our operators is that our operators are planning their budget throughout, they are starting to plan their budgets 2016 and they are giving pretty good idea of what they're going to complete assuming similar oil prices. Obviously if oil prices deteriorate I think they get pushed out and if oil prices improve for one reason or another I think that they may start accelerating the completion of those ducts.

Yes, I also think that as we are approaching year-end they're delaying a number of those wells just for budgetary reasons and to try to keep the CapEx down. So I think right now you're probably seeing a little bit higher level of uncompleted out there and that will probably normalize once we get into the first quarter, weather permitting and things a like that.

Great. And those ones that you say that they could potentially be deferring right now in Q4, do you think, maybe you see an uptick in activity in Q1 just since things all got pushed out into the following quarter?

I think it just depends on a couple of things, primarily oil prices. But again the first quarter is typically your trickiest weather quarter. So we are modelling our ducts and our estimate for new wells that we'll participate in more back end loaded. But typically the second, third and fourth quarter are better quarters for completions and weather. First quarter can be tricky.

John, this is Brandon. Normally, I think, what we have seen is a, probably like a 65/35 split for the back half of net well adds, weighted to the back half 65%. We are just kind of assuming that’s a normal pattern but, as Mike said, obviously probably weather in 1Q and 2Q is the key driver.

Thank you. At this time I'm showing no further questions. I would like to turn the call back over to Mr. Brandon Elliott for closing remarks.

Thanks, Nikita, thanks, everyone for their participation in the call today and your answers to Northern Oil & Gas. Nikita will give you the replay information and we look forward to talking with you all again soon. Everybody have a good day and the rest of the week.