Northern Oil and Gas Inc (NOG) 2015 Q4 法說會逐字稿

Good day, everyone, and welcome to Northern Oil and Gas, Inc.'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. 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 thank you all for joining the call today. I would like to begin the call with a 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, 2015, to $150 million as of the end of the year. We have reduced that balance even further to the $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 threshold.

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 market strengthened, lifting 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 worked to reduce cash G&A during 2015, including a 20% workforce reduction last fall.

We did all of this and 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 weighted 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 of this said, 2016 will be very simple. We are in good shape financially. We have a modest land budget to continue to buy core, nonoperated acreage in North Dakota and we will continue to use great discipline and discretion in wells in which we plan to participate. This should give us real staying power in a lower-for-longer oil price environment.

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

Thanks, Mike. Today, I'm 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 a low price commodity environment, our total capital expenditures declined approximately 76% in 2015 as compared to 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 of wells in 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 differential 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. Our high level of oil hedged under fixed-price agreements helped 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. The 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 compares to a $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 approximate 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. Our higher compensation expenses during the quarter were primarily driven by a $1.9 million 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 expense 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 is 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 costs. 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 costs.

We continue to see cost reductions on the new well proposals being submitted, which have recently ranged in the $6.5 million to $7.5 million area. As you might expect, these wells are located in the core area of the play, where operators are 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 on 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 their price decks. It is difficult to estimate the amount of the drops as we haven't been provided their price decks, but I believe a reasonable assumption would 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 that require a ratio of secured debt to adjusted EBITDA of no greater than 2.5 times, and we were at 0.5 times on that ratio at year-end; and adjusted EBITDA to cash interest coverage ratio of no less than 2.5 times, and we were at 5.2 times on that ratio at year-end.

We have already had discussions with our banks about amending our covenants to something we would be much more comfortable with should low prices not recover. We will hopefully get this done in connection with our April borrowing base redetermination.

We remain 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 barrels 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 totaled approximately $576 million. Keep in mind, the SEC PV-10 proved reserves do not reflect the value of our unsettled hedges. Although our year-end 2015 producing reserves increased over 2014, our total proved reserves 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 a 52% increase in 2015's SEC price deck, as compared to 2014's price deck, as well as reduced activity levels being forecast during the SEC's five-year forecast period. This impact was partially offset by positive performance revisions and reserve additions through drilling. At year-end, 90% of our SEC PV-10 is proved developed, with the remaining 10% being proved undeveloped.

In concluding my comments, I would like to point out that our asset base is substantially held 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 and administrative staff, 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 in value creation.

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

(Operator Instructions). Scott Hanold, RBC Capital Markets.

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 a 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 are 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?

On average, we're 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 will continue to, obviously, participate in the better wells, which is again -- makes our strategic business model very unique in that we can tack our production -- or our CapEx and production according to well prices. We gave you -- during my comments, I gave you just a range of what we could possibly see, given the up to component of our approved capital budget and what we think is our latest, most likely case given lower oil prices.

So, that's the range I want to push you to, and again, if oil prices stay low, it could even be lower CapEx spend. So, that's the beauty of our business model is we have the ability to increase our production -- or our CapEx spend based on activity levels and oil prices (multiple speakers) at our discretion.

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 the operative word here is discipline. I think 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 threshold, we will non-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?

You know, it's started to pick up a little bit, and I am trying to figure out the best way to say this. But we have seen a pickup in deal activity, but what we are starting to see that is 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 the very, very core of the play picking away at acreage opportunities. So we are starting to see more and more opportunities in those better areas, and so we think that there is a lot of work to do here in 2016 in that very core area.

Appreciate it. Thanks for the time.

Peter Kissel, Howard Weil.

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, first of all, I'll just say the overarching theme is we have 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 is 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. 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 DUC portfolio, or of the portfolio of drilled uncompleted wells, we have it basically mapped out by operator when those wells are expected to be completed, and then any new 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 is something we work really hard at and we are 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 nonoperated 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?

You know, we have 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, where some of the larger operating partners we have are looking to potentially sell some of their nonop DUCs to us.

So we are seeing -- it is across the board, Pete, and it is a really interesting environment, but we are being as opportunistic as possible. As you can probably imagine in this environment, we 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 will take this opportunity to use the word discipline again. We have always looked at our CapEx as a returns base exercise.

As you know, you have known me personally for 10 years, Pete, I have never had an opinion on oil prices in 10 years. I have only ever had an opinion on returns.

If we elect to participate in a substantial number of wells, it is 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 is 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 in wells that we participate in -- that we are participating in and at the current strip, we are more than happy to lock in those returns. All we care about is returns.

Great, thanks, Mike. I appreciate the answers.

Neal Dingmann, SunTrust.

Mike, just one (inaudible) 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 look 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?

Well, I will give you one somewhat simple answer. If you model any one of our well proposals that we receive in our engineering -- our ARIES engineering software, essentially if a well meets our rate of return threshold, then it is effectively going to be liquidity positive.

So the way we look at it is if anything in this current oil price environment -- if any well in this current oil price environment meets or exceeds our economic thresholds, it is 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 a certain production profile.

If oil prices stay low and rig counts continue to drop, our CapEx spend will drop. It is just a function of activity levels in the basin. That's the beauty of our business model. And our ability to manage our CapEx is, 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 (inaudible) or 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?

I will just lay it out. What we look at is -- we -- on a basic -- assuming a well that is being drilled is going to be completed in relatively short order and we haven't received any confirmation from our operating partners that the well is going to be drilled and then the completion will be materially delayed, we would run essentially a two-year strip starting in six months from well proposal, and that is a good hand wave on 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 a 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, buddy.

Phillips Johnston, Capital One.

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 the averages on the PUDs were in the low 600s, and that was probably up about 30% from the average that was booked in 2014 and that is just really due to the -- there is a reduction in the 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 overcompletions in there, so you have a smaller increase year over year with respect to that.

Okay.

You have got a base that has got a lot of overcompletions 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 (technical difficulty)

Well, it is really hard to -- and really don't want to speculate any kind of capital decisions, but I think first and foremost what we will do is in the spring borrowing base redetermination go in, and as I referenced in the call, I think we will have a 20% to 30% probably reduction somewhere there. In connection to that, we have already had discussions with our banks about changing the covenants to get to something that we would be more comfortable with should lower prices not recover. And that's probably our first line of attack with respect to it and then see where it plays out from there.

Okay.

But we have a number of levers that we can pull with respect to it.

Okay, sounds good. Thank you.

Steve Berman, Canaccord Genuity.

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.

(laughter). We got some oil moving by, sorry about that.

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

And then looking at where oil prices are now, and literally in the last week we have 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 that 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 a 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 (multiple speakers)

No, that is all in.

All in?

Yes, that is 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. Obviously, the depletion will be based on reserves that we calculate at the end of March, which is going to be a factor of price, so that's still moving around.

But at this point, I would 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.

Ryan Oatman, Cowen and Company.

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 recompletions.

We have seen a lot of that. We saw that really start to take hold as completions -- new completions designs started showing the positive results. So, any time we receive a supplemental AFE for a recompletion, it is usually a very substantial rate of return on that additional spend.

And it is capital, right, mostly?

Yes.

Okay, and can you speak to how that has trended over time here? Is that just more talk here or have you actually seen more AFEs coming in here recently?

We have seen a lot from Marathon over the last, call it, year. Marathon actively developed the Bailey Field in Dunn County, which are some of the best rocks in North Dakota. And we saw a lot of recompletions on these older completions where we had some substantial working interest in some good areas.

We have seen it from Hess. We have seen it from a handful of other operators that a lot of these wells, if you remember when we started drilling in 2007/2008, some of them were even open hole, no frac, and so -- or 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 it from Marathon in 2015. It ebbs and flows, but there are 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 is going to be more heavily back-end loaded, somewhere like 30/70 maybe first half, second half, somewhere in there, Ryan, if that helps.

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

John Aschenbeck, Seaport Global.

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?

Down 15, probably. I think what's going to happen with our production if we come -- as we come into the year on a 10-well scenario and we initially forecast 15% that you're going to see it be more back-end loaded. So what that means is in the first half, you're going to see the heavier decline, and then in the second half I think you're actually going to see it 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 it and as those wells come on, it is pretty flat in the second half. So I don't know if that helps.

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

(Operator Instructions). Adam Leight, RBC Capital Markets.

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, 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 to answer the first question, it is all over the board, to be honest with you. I'm not trying to dodge your question, Adam. But you have seen some companies actually take an increase in the price of 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 aren't, to be honest with you, expecting to trade grid for some covenant relief. You have got a lot of people struggling in the industry and we have been real standup with respect to our performance and our discipline and the moves that we have made with commitment reduction. So, I am not necessarily anticipating a really difficult time with respect to that.

What was the second (multiple speakers)

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

Okay. Part of it was just a viewpoint on liquidity versus repositioning the balance sheet for (multiple speakers)

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

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

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 and 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 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 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.