Brandon Elliott - Executive Vice President of Corporate Development and Strategy Michael Reger - Chairman and Chief Executive Officer Thomas Stoelk - Chief Financial Officer.

Scott Hanold - RBC Capital Markets Peter Kissel - Howard Weil, Inc. Neal Dingmann - SunTrust Robinson Humphrey Phillips Johnston - CapitalOne Southcoast, Inc. Stephen Berman - Canaccord Genuity Inc. Ryan Oatman - Cowen and Company John Aschenbeck - Seaport Global Securities LLC Adam Leight - RBC Capital Markets.

Good day everyone and welcome to Northern Oil and Gas Incorporated’s Fourth Quarter and Year-End 2015 Earnings Results Conference Call. This call is being recorded. With us today from the Company is the Chairman and Chief Executive Officer Mike Reger; Chief Financial Officer Tom Stoelk and Executive Vice President Brandon Elliott.

At this time, I will turn the call over to Brandon. Please go ahead, sir..

Thanks, Chelsea. Good morning everybody. We are happy to welcome you to Northern's year-end 2015 earnings call. I will read our Safe Harbor language and then turn the call over to Mike Reger, our 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, adjusted EBITDA and PV-10 values. Reconciliation 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'll turn the call over to Mike..

Thanks Brandon. Good morning and thank you all for joining the call today. I would like to begin the call with few highlights and accomplishments from 2015. Discuss our plans for 2016 and then turn the call over to Tom Stoelk, our CFO to cover the financial highlights. Despite the challenging macro environment 2015 was another good year for Northern.

We continued our focus on capital allocation, balance sheet strength and liquidity. Our capital discipline allowed us to generate free cash flow in the second half of 2015, which we used to reduce the amount we have drawn on our revolving credit facility from $188 million as of June 30 of 2015 to $150 million as of the end of the year.

We have reduced that balance even further to $125 million as of March 1. This is a result of the speed of which we were able to cut our capital spending in late 2014 and early 2015. The strong hedge position we had in place as we entered 2015 and a 76% reduction in year-over-year capital expenditures.

Even with this dramatic cut in capital spend and the addition of fewer net wells than we originally modeled. We were still able to beat guidance and increase year-over-year production by 3% due to our returns based capital allocation approach. Northern has been very proactive throughout this downturn.

At the beginning of 2015 we very quickly reversed our consent decision on quite a few wells that we had elected to participate in at higher oil prices resulting in the elimination of over $80 million of CapEx on wells that no longer met our internal rate of return thresholds.

Next, we added to our hedge book as oil prices temporarily improved in the spring of 2015 by layering in $65 swaps in the second half of 2016. We also took the opportunity to term out some additional debt in May when the high yield markets strengthened listing our unsecured bonds back nearly to par.

We completed both of our 2015 revolving credit facility borrowing base redeterminations without any downward revisions despite the dramatic drop in oil prices. We work to reduce cash G&A during 2015, including a 20% workforce reduction last fall.

We did all of this in more while adding nearly 5,000 core Bakken acres to the portfolio completing 292 gross, 18.6 net wells and growing production by 3%. Before I turn the call over to Tom, I would like to comment on our 2016 capital spending plans and production outlook.

As mentioned in our earnings release we have approved a 2016 capital expenditure budget of up to $99.8 million.

I would like to emphasize the up to portion of that statement because our business model gives us great flexibility in the amount, timing and allocation of our capital expenditures and what we will actually spend is subject to change based on a variety of factors primarily oil prices.

Our current development plan does not anticipate us outspending our discretionary cash flow and will be adjusted as commodity prices and our liquidity permits. The full $99.8 million budget would provide completion funding for the 9.7 net wells or DUCs in process at year-end. And an additional six net wells for a total of about 16 net wells.

And depending on the timing of completions this would result in relatively flat production.

However, given the current low commodity prices, we expect the majority of wells added to production in 2016 will occur during the second half of the year as a number of our operators are delaying well completions waiting on higher pricing or better weather to minimize completion costs.

Therefore, due to the variability of the timing of completions, our initial 2016 production forecast assumes completion of only 10 net wells during the year which result in closer to $60 million to $70 million of CapEx for the year.

We estimate that this much lower 10 well capital budget with completions heavily waited to the second half of the year would result in approximately a 15% decline in annual production in 2016 as compared to 2015. Again, our business model gives us great flexibility on CapEx spend. With all this said, 2016 will be very simple.

We are in good shape financially. We have a modest plan budget to continue to buy core non-operated acreage in North Dakota and we will continue to use great discipline and discretion in wells which we plan to participate. This should give us real staying power in a lower to longer oil price environment.

At this point, I will turn the call over to our CFO, Tom Stoelk..

Thanks Mike. Today, I am going to cover some of the financial highlights for the fourth quarter and provide some commentary on our liquidity. Adjusted net income from the fourth quarter of 2015 was $15.6 million or $0.25 per diluted share. Adjusted EBITDA for the fourth quarter was $67.7 million.

Both of these amounts were impacted by the low oil and natural gas prices during the quarter. Fourth quarter production averaged 15,716 barrels of oil equivalent per day. In light of the low price commodity environment, our total capital expenditures declined approximately 76% in 2015 as compared to our actual CapEx spend in 2014.

Despite the reduction in capital spending, our year-over-year production growth was 3%. This year-over-year production growth was partly driven by completion of our large inventory wells and process entering 2015 as well as the improved economics and recoveries on the 18.6 net wells that we added during the year.

Realized price per barrel of oil equivalent after reflecting our settled derivative transactions was $59.83 per Boe for the fourth quarter which was down approximately 11% on a year-over-year basis. This decrease was due to low commodity prices in 2015 as compared to last year.

Partially offsetting the lower commodity prices was an improvement in the average oil price differentials to NYMEX WTI benchmark which averaged $8.30 per barrel in the fourth quarter of 2015 as compared to $12.89 per barrel in the fourth quarter of 2014. We currently expect that oil price differentials will be in the $8 to $10 range during 2016.

Oil, natural gas and NGL sales, when you include our cash derivative settlements totaled $86.5 million in the fourth quarter. A high level of oil hedged under fixed price agreements helped to mitigate the current low price environment.

For the fourth quarter of 2015, we incurred a gain on settled derivatives of $47.2 million compared to a $17.2 million gain in the fourth quarter of 2014. A gain on settled derivatives increased our average realized price per Boe by $32.62 this quarter.

As a result of forward oil price changes, we recognized a non-cash mark-to-market derivative loss of $29.6 million in the fourth quarter of 2015 and that compared to $145.8 million gain in the fourth quarter of 2014.

Looking at expenses, our combined per unit production expenses, production taxes and G&A for the fourth quarter of 2015 declined by $3.51 per Boe or 19% when compared to the fourth quarter of 2014. The decrease in per unit operating cost was driven by lower workover and maintenance costs and a smaller taxable base for production taxes.

In 2016, we expect production expense to range between $8.50 to $9 per Boe and production tax expense as a percentage of unhedged oil and gas sales to approximately 10%. General and administrative expense was $5.8 million for the fourth quarter of 2015 compared to $4.9 million same period a year ago.

General and administrative expense for the fourth quarter of 2015 was comprised of $2.8 million of cash expense and $3 million of non-cash expense. The increase in 2015 was primarily due to $1.8 million in higher compensation expense which was partially offset by lower legal and professional expenses and travel costs.

The higher compensation expenses during the quarter were primarily driven by $1.9 million in non-cash stock-based compensation expense recognized in connection with a new employment agreement with Northern's Chief Executive Officer. In 2016, we expect general and administrative expenses to range between $3.75 to $4.25 per Boe.

Our capital expenditures during this quarter totaled $23.3 million. The breakdown of that total was as follows; approximately $18.9 million of drilling and completion capital which includes capitalized workover expenses. $2.9 million on acreage and other acquisition activities and $1.5 million of capitalized interest and other capitalized cost.

Total capital spending in 2015 amounted to $128.7 million and that was comprised of $116.3 million of drilling and completion capital again including capitalized workover expense, $7.8 million on acreage and other acquisition activities and $4.6 million of capitalized interest and other capitalized cost.

We continue to see cost reductions on the new well proposals being submitted, which are recently range in $6.5 million to $7.5 million area. As you might expect these wells are located in the core areas of play, where operators are just seeing 30% plus increases in estimated ultimate recovery uplifts due to the higher intensity completions.

Turning to liquidity. We exited 2015 with only $150 million borrowings on our credit facility and we currently have a borrowing base of $550 million. As of today, we have $125 million on the facility and we plan on keeping our spending for the year within discretionary cash flow.

Accordingly, we certainly have adequate liquidity to execute in our 2016 development plan.

We have an upcoming borrowing base redetermination in April and we do anticipate our borrowing base will drop as banks lower the price tags is difficult to estimate the amount of the drop as have been provided their price tags, but I believe a reasonable assumption will be between 20% and 30% which will leave us with a significant amount of available liquidity.

We currently have no near-term maturities on our debt and we are in very good shape on our credit facility covenants.

The required ratio of secured debt to adjusted EBITDA of no greater than 2.5 times and we are at 0.5 times in that ratio year-end and adjusted EBITDA to cash interest coverage ratio of no less than 2.5 times and we are at 5.2 times on that ratio year-end.

We have already had discussions with our banks about amending our covenants just nothing we will be much more comfortable with should low prices not recover, but hopefully get this done in connection with our April borrowing base redetermination.

We remained well-positioned from a liquidity and debt maturity perspective to deal with lower prices and we maintain a strong hedging position. As a reminder, we have a total of 900,000 barrel of oil hedged with swaps at an average price of $90 per barrel in the first half of 2016.

After that we have an additional 900,000 barrels hedged with swaps at an average price of $65 per barrel in the second half of 2016. That amount of hedging is obviously very valuable in the current pricing environment and helps protect our balance sheet.

The SEC PV-10 of our proved reserve base at year-end total approximately $576 million, keep in mind the SEC PV-10 proved reserves did not reflect the value of our unsettled hedges.

Although, our year-end 2015 producing reserves increased over 2014, our total proved reserve of 65.3 million barrels of oil equivalent reflect a reduction from 2014 levels.

Nearly all of that reduction was driven by revisions to our proved undeveloped reserves, which is a reflection of both the 52% increase in 2015’s SEC price tag as compared to 2014’s price tag, as well as reduced activity levels being forecast during SEC’s five-year forecast period.

This impact was partially offset a positive performance revisions and reserve additions to drilling. At year-end 90% of our SEC PV-10 as proved developed with a remaining 10% being proved undeveloped.

In concluding my comments, I would like to point out their asset base is substantially helped by production and as a non-operator Northern has extensive control over its capital spending because we have the ability to elect and participate on a well-by-well basis.

This provides the ability to be more selective in the allocation of capital to the highest rate of return projects without the burden of drilling commitments, large operational administrative staffs or other infrastructure concerns. Given the uncertainty around future oil prices we are continuing to take aggressive steps to protect our balance sheet.

By maintaining capital discipline we continue to work hard to build resilience given the uncertainty of how long the low price environment will last. By reducing commitment levels and protecting our liquidity we are navigating this low price environment and at the same time preparing ourselves for future opportunities and value creation.

At this time, I would like to turn it over to the operator for Q&A, if you can open up the lines..

Certainly. [Operator Instructions] And our first question comes from the line of Scott Hanold with RBC Capital Markets. Your line is now open..

Thanks. When I look at the fourth quarter production results, they came in pretty strong, and obviously you guys had made some indication to the better productivity you are seeing from your operators.

Can you give us a little color on some of those fourth quarter completions you saw? Is there a specific operator that helped boost that? And give us a little color on the better productivity, as well as maybe the shift to more core acreage, how that mix shift all benefited 4Q?.

Yes, thanks Scott. This is Mike. I think the - we had decent completion activity in the core of the play in the fourth quarter. One of the highlights would have been our high working interest exposure to Whiting's Tarpon area. We had a handful of wells completed with Whiting in October, November and those came online in the fourth quarter.

Several other operators were completing some wells in the core of the play, and so it increased our production little higher than we had expected as well.

So we continue to see the core of the play get even better almost all of our operating partners are using the higher intensity completions and we’re seeing substantially increased EURs across the board..

Okay.

Can you quantify that at all, the size of the EUR uplift that you are seeing, on average?.

We are seeing 30% to 50% depending on the area and depending on the operator..

Okay, okay, good.

And can you also discuss with the plan to stay within cash flows, well productivity improving, but your well costs coming down, it seems like that required threshold that you all have to consent to a well is improving, and how do you weigh that versus what that limitation or the governor is on how much you want to spend?.

Yes, I think it just it all comes down to what kind of drilling activity we see in 2016, obviously each time we receive a well proposal and we receive them every day. We run the economics on that well based on the current strip if it meets our economic threshold we participate if it doesn't then we don't.

We’ll continue to obviously participate in the better wells, which is again makes our strategic business model very unique and then we can tack our production - our CapEx and production according to well prices.

We gave you - during my comments I gave you just kind of a range and what we could possibly see given the up to component of our approved capital budget and what we think is kind of our latest most likely case given lower oil prices. So that’s kind of the range I want to push it to and again if oil prices stay low it could even be lower CapEx spend.

So that's the beauty of our business models we have the ability to increase our production or CapEx spend based on activity levels and oil prices - at our discretion..

Yes, I appreciate that, and to that point, if this is a lower-for-longer environment and you are actually reducing spending on completions, could you guys be a little bit more opportunistic on the acreage and outspend cash flow in that way, just being it is the right time as the acreage prices are low? Is that a consideration?.

You know, it is, but I would say that the operative word here is discipline I think you know we - anytime we see a drilling unit where we have existing working interest or we see that a unit is being proposed where we - where that drilling unit, that location, that operator would generate and those wells would generate an acceptable rate of return for us.

We will spend a lot of time picking away at working interest in that unit. And so where we receive well proposals that don't meet our rate of return thresholds we’ll not consent those wells, and units where we - where it does meet our internal rate of return threshold, we’re going to attack..

Okay, and I guess this is a quick follow-up to that.

Have you guys been seeing more acreage opportunities come through with this last downturn in oil prices?.

It started to pick up a little bit and I’m trying to figure out the best way to say this, but we’ve seen a pickup in deal activity, but what we are starting to see that’s relatively new is opportunities in the very, very core of the play.

You could see that our average cost per acre in the fourth quarter actually increased a little bit just because we were spending a lot of time in a very, very core of the play picking away at acreage opportunities.

So we’re starting to see more and more opportunities in those better areas and so we think that there's a lot of work to do here in 2016 in that very core area..

Appreciate it. Thanks for the time..

Thanks Scott..

Thank you. And our next question comes from the line of Peter Kissel with Howard Weil. Your line is now open..

Thank you. Good morning guys, and thanks for taking my questions. Mike, thanks for walking through how you derive the CapEx and the associated production there, but I just have one logistics question, I guess.

When you receive an AFE, is there any way to determine the operators intent to either defer completions or complete immediately? I am just trying to see how you are balancing the cash outflow with the potential cash inflow and the lag that could exist with some of the deferred completions that are going on..

Sure. Well, first of all just to say the overarching theme as we got a good liquidity position so we can make our decisions based on quality of rock, whether we’re going to participate in the drilling of a well regardless of when it’s completed. We aren’t reliant upon that well being completed in order to shoot the gap if you will.

Here is the way we do it over here and Northern is the largest non-operator in the Williston Basin. Our relationships with our operating partners are very good and extensive down to every level from their land departments to ours and their accounting department to ours. We have very good visibility on timing of wells.

Our entire duct portfolio or of the portfolio of drilled that uncompleted wells, we haven't basically mapped out by operator when those wells are expected to be completed. And then any wells, obviously it helps us further model the economics on that well based on our discussions with the operator on when those wells are expected to be completed.

So it’s something we worked really hard at and we’re really good at it..

Great. Thanks, Mike, that's helpful. Earlier, the questions were on asset acquisitions or acreage acquisitions. I'm just wondering.

Conversely, have you seen any of the operators out there looking to buy out non-operated partners to core up their positions in this sort of market? And if so, is that something you would be interested in to continue to boost liquidity, if it is a possibility?.

We’ve seen a little bit of that from some of our larger partners, but I think more than anything just given the quality of our balance sheet relative to some of our peers, we’re actually seeing the opposite were some of the larger operating partners we have are looking to potentially sell some of their non-op DUCs to us.

So we’re seeing - it’s across the board, Pete and it's a really interesting environment, but we’re being as opportunistic as possible as you can probably imagine this environment were really redlining our engineering department - there is a lot of activity..

Okay, all right. And one last question for me. You have had great hedges in 2015. You still have good hedges in 2016. Presumably, some of your economics still work here at the 20% hurdle rate at the strip because you are still electing to participate in some wells.

So I guess my question is, would you be willing to hedge at these levels based on the strip in 2017 and 2018 to try to lock in those cash flows at this point or do you think that there is a better reward if you wait it out a little bit to hedge?.

I guess I’ll take this opportunity to use the word discipline again. We really - we’ve always looked at our CapEx as a returns based exercise as you known - you’ve known me personally for 10 years, Pete I’ve never had an opinion on oil prices in 10 years I’ve only ever had an opinion on returns.

If we elect to participate in a substantial number of wells, it's based on essentially a current strip and we are more than prepared to hedge those and lock in those returns. It has nothing to do with oil price, there's no magic number, we hear some of our operating partners talking about 50 or 60 or what have you.

If we see somewhat of a larger acquisition or if we see a substantial pickup and wells that we participate in that we’re participating in and at the current strip we’re more than happy to lock in those returns. All we care about is returns..

Great. Thanks Mike. Appreciate the answers..

Thanks Pete..

Thank you. And our next question comes from the line of Neal Dingmann with SunTrust. Your line is now open..

Mike, just one for - I just have two questions. The first overall question I had, obviously you mentioned discipline several times today.

So I guess when you package everything together and look between deciding on participating with additional AFEs, and when you’re looking at the DUCs versus hedging, et cetera, is all this based on when you and Tom sit down you want X amount of liquidity? That's the key? Or is it more about - all about required rate of returns.

I get the discipline idea that you are definitely forecasting, but I was wondering when you package it all together really what is driving this for you?.

Yes, I’ll give you one - somewhat simple answer, if you model anyone of our well proposals that we received in our engineering, our Aries Engineering Software essentially if the well meets our rate of return threshold then it’s effectively going to be liquidity positive.

So the way we look at it is that anything in this current oil price environment if any well in this current oil price environment meets or exceeds our economic thresholds it’s going to be a net positive from a liquidity standpoint from reserves and what have you.

When we look at the current rig count, it essentially solves for itself and in my comments I wanted to provide somewhat of a range of what a CapEx spend would look like under a certain completed well scenario and in a normal environment we would expect to complete our wells, our DUCs this year and complete and with the current rig count add another six net wells.

And if those all came on straight line that would result in that certain production profile. If oil prices stay low and rig counts continue to drop, our CapEx spend will drop. It's just a function of activity levels in the basin.

That’s the beauty of our business model and our ability to manage our CapEx as we think our greatest strength in this current environment and makes our business model ideal in this environment..

Good answer, Mike, and just one follow-up on that.

On that very first part when you said to make sure these wells are I would like to say be your cash flow positive, is that - you are looking at, what - obviously not necessarily from day one or is that just a certain payback period or how do you all - how do you define that?.

Okay, I’ll just laid out, what we look at is on a basic - assuming a well that’s being drilled is going to be completed in relatively short order and we haven't received any confirmation from our operating partners that wells going to be drilled and then that completion will be materially delayed.

We would run essentially a two-year strip starting in six months from well proposal and that’s a good hand wave and kind of how those cash flows will roll in and if that strip, actual strip meets our economic threshold as it relates to our engineering work then we will participate in the wells and to echo the previous answer I gave all we care about is returns.

If we hedge it has nothing to do with the arbitrary price, it has to do with locking in a rate of return that we feel is acceptable..

Got it. Great details. Thanks a lot..

Thanks a lot..

Thank you. And our next question comes from the line of Phillips Johnston with CapitalOne. Your line is now open..

Hey, guys. Thank you. Just a question on your reserve adds last year for both your PDP wells and the PUD locations that you booked.

What was the average EUR that Ryder Scott assumed for all of your new additions and how did that compare to the average EURs booked in 2014?.

I think that the average is on the PUDs are in a low 600’s and that was probably up about 30% from the average EURs booked in 2014 and that’s just really due to the - there is a reduction in number of PUD locations, but the quality of where those wells and those PUDs are located at..

Okay, and the PDP wells, was it roughly the same [a year] or so?.

Not as much of an uplift on PDP because you have a mix of over completions in there, so you have a smaller increase kind of year-over-year with respect to that..

Okay..

You’ve got a basis, got a lot of over completions I guess is what I’m trying to tell you..

Okay, makes sense. And then, just looking at the balance sheet, Tom, as you pointed out, liquidity is very strong. You have got no debt maturities until 2020. Your spending for this year looks pretty close to cash flow, so you're not adding any new debt.

But as you point out in the release, you do have about $75 million of hedging gains rolling off at the end of this year, which is a headwind to next year's cash flow and leverage ratio even if pricing improves.

My question is, what additional levers are you guys considering in order to prevent the leverage ratio from expanding next year? And would you consider new equity or is that something that you would [Audio Dip]?.

Well, it’s really hard and really don’t want to speculate any kind of capital decisions but I think first and foremost what we’ll do is in the spring borrowing base redetermination go in as I referenced in the call I think will have a 20% to 30% probably reduction somewhere there.

In connection to that we’ve already had discussion with our banks about changing the covenants to get to something that that we would be more comfortable with should lower prices kind of not recover and that’s probably our first line of attack with respect to it and then see where it kind of it plays out from there..

Okay..

But we know a number of levers that we could pull with respect to it..

Okay, sounds good. Thank you..

Thank you. And our next question comes from the line of Steve Berman with Canaccord Genuity. Your line is now open..

Good morning. Mike, one clarification. When we were talking about the 100 million keep production flat scenario, was that flat relative to the full-year average of [16.3] or flat for Q4? I hear the train going by there..

We got some oil moving by, sorry about that..

Yes, we see an oil train going by our office here. I think it would be year-over-year and the way we - and the way we model that if you take the 16 net wells and they come on ratably or straight line you know that that model shows relatively flat production to slightly down.

And then looking at kind of where oil prices are now and in the last literally in the last week we've seen another dramatic drop in rig count in North Dakota - again, the beauty of our business model is we’re going to elect to participate in the wells that get drilled in the best spots and then meet our economic returns and if not then we won't and we have pretty good visibility on when the 9.7 net wells will come on and right now we don’t see whole lot of those coming on in the first half of the year.

So we feel really good about our spend regardless of pace..

Got it. Tom, a couple for you. The G&A guidance you gave, was that cash only or all in on the….

No, that’s all in..

All in..

Yes, that’s all in..

Okay, and then DD&A was down in Q4 from prior quarters.

Is that a good number to use for 2016?.

Yes, that is exactly what I would use. I mean obviously, the depletion will be based on reserves that we calculate at the end of March, which is going to be factor of price, so that’s still moving around. But at this point I’d use the $16.59 depletion rate and the $0.11 depreciation and accretion rate to model.

It will likely change somewhat after we finalize reserves and record those but that’s a good number to use right now..

Great. Thank you..

Yep..

Thank you. And our next question comes from the line of Ryan Oatman with Cowen and Company. Your line is now open..

Hi, good morning. Thanks for taking the question. Want to take just a little bit of a different tack here to talk conceptually. There has been some operators talking about the opportunity in the Williston Basin for refracs. I just wanted to walk through how that works with you guys.

Do they speak to those as capital expenditures, and you guys incur those costs alongside the operator, or do they classify those as operating expense and it is a free benefit for you? You don't outlay any capital, but you get the benefit on the production side?.

Yes, I think over the last 10 years I can’t remember a supplemental AFE showing up that didn’t meet our economic thresholds just because a very small amount of capital can mean a lot when it comes to any re-completions, we’ve seen a lot of that, we saw that really start to take hold as new completion design started showing the positive results.

So anytime we receive a supplemental AFE for a re-completion, it's usually a very substantial rate of return on that additional spend..

And it’s capital right mostly..

Yes..

Okay.

And can you speak to how that has trended over time here? I mean is that just more talk here or have you actually seen more AFEs coming in here recently?.

We’ve seen a lot from Marathon over the last, call it year.

Marathon actively developed the Bailey Field and Dunn County, which is some of the best rocks in North Dakota and we saw a lot of re-completions on these older completions where we had some substantial working interest in some good areas, we’ve seen it from - we’ve seen it from a handful of other operators that.

Lot of these wells, if you remember, when we started drilling in 2007, 2008 you know was - some of them were even open hole, no frac, so our open hole, no stages and so the ability to get in there and try to crack open those really high quality rocks has been great.

And again we saw a lot of different Marathon in 2015 so it ebbs and flows, but they’re great returns for both our operating partners and us..

That's great. And then, I do appreciate the comments on guidance, and understanding the capital program is fluid, obviously, at this point, I'm wondering if you could provide whatever sort of incremental clarity you may have at this point.

You are decently into 1Q, understanding that the non-op cycle tends to make some visibility in terms of AFEs going out a little bit more fluid.

Do you have a sense as to how much capital you think will go out the door in 1Q and how we should think about if we're going to use that base of $60 million to $70 million, how - maybe I won't pin it down quarterly, but how that progresses throughout the year?.

Yes, as Mike referenced in his comments, we think it’s going to be more heavily backend loaded somewhere like 30, 70 maybe first half, second half somewhere in there right if that helps..

That’s great. All right, I will hop back in the queue. Thanks..

You bet..

Thank you. And our next question comes from the line of John Aschenbeck with Seaport Global. Your line is now open..

Good morning. Thanks. I had a follow-up here on 2016’s program.

What would - with completion activity starting back up in the second half of the year, what would you anticipate a good ballpark decline Q4 2016 versus Q4 2015 levels?.

Yes. That’s 2015 probably. I think what’s going to happen with our production if we come as we kind of come into the year on a 10 well scenario and we initially forecast 15% that you are going to see it would be backend loaded. So what that means is in the first half, you are going to see the heavier decline.

And then in the second half I think you're actually going to see a probably flatten out. So in the first quarter, it will probably be high single-digits, it will come off a little bit from that sequentially into the second quarter. And I actually think when I look at modeling and as those wells going to come on, it’s pretty flat in the second half.

So I hope that helps..

It does. Thanks. All my other questions have been asked..

Great. Thanks..

Thank you. [Operator Instructions] And our next question comes from the line of Adam Leight with RBC Capital Markets. Your line is now open..

Hey, good morning everybody..

Hey Adam..

Thank you.

Most of my questions were covered, but I guess, Tom, on the borrowing base, how independent is the actual borrowing base from the covenant negotiation? Do you anticipate that is really just a trade of covenant for covenant or is the pricing grid exercise? How is that going to work? And then, sort of the second part is a two-parter itself, but how comfortable would you be using any capacity the banks might allow to use cash to help delever the balance sheet, given where the bonds are trading?.

I guess answer to the first question it’s kind of all over the Board, to be honest we are not trying to dodge your question Adam, but you’ve seen some companies actually take an increase in the prices their interest rate grid to do that.

In our case when you look at it and you look at our outstandings and the discipline that we've done with the banks.

I think we feel we have a great relationship with our banks and probably to be honest with you, we are expecting to take grid for some covenant relief, yes, you got a lot of people struggling in the industry and we’ve kind of been real stand up with respect to our performance and our discipline and kind of the moves that we made with commitment reduction.

So I’m not necessarily anticipating a really difficult time with respect to that.

What was the second?.

Yes, Adam this is Brandon, I think on the second one, I think we’re probably not going to get into kind of future potential capital decisions like that..

Okay.

I mean part of it was just a viewpoint on liquidity versus repositioning the balance sheet for downturn?.

Yes, I think that from that standpoint it’s hard to speculate like Brandon says on capital decisions, but obviously when you do the math on some of the long-term balance it appears attractive, but I think our mindset is that nothing is more important than liquidity right now.

We kind of noted in our comments that we continue to reduce activity and I guess we think that investing some level of capital and drilling does support kind of the long-term business and future financing capacity.

So it's hard to look much past that I think we currently believe we want to maintain liquidity, probably do some drilling to keep the base up there and have future financing capacity with it. Not sure that we are real interested in using some of that capacity to go out and take out some of the senior notes.

I think that’s probably what’s you are really asking me..

That's what I was really asking and you didn't have to try to avoid my question. So thanks..

Okay, all right..

Thank you. And ladies and gentlemen, this does conclude today's question-and-answer session. I would now like to turn the call back to Brandon Elliott for closing remarks..

Thanks everybody for your participation in the call and your interest in Northern Oil & Gas. Chelsea will give you the replay information and we look forward to talking to you guys next quarter or out on the road over the next couple of months. Thanks everyone..

Ladies and gentlemen, thank you for participating in today’s conference. A replay of this conference will be available beginning today March 3, 2016 at 2:00 o’clock PM Eastern Time through March 10, 2016 at 11:59 PM Eastern Time.

You may access the replay at any time by dialing the numbers 800-585-8367 or 855-859-2056 and entering the conference ID number 50772234. Again those numbers are 800-585-8367 and 855-859-2056, conference ID number 50772234. Thank you again for participating in today's conference. This does conclude the program and you may all disconnect.

Everyone have a wonderful day..