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Northern Oil and Gas (NYSEMKT:NOG)

Q4 2013 Earnings Call

February 28, 2014 10:00 am ET

Executives

Michael L. Reger - Co-Founder, Chairman and Chief Executive Officer

Thomas W. Stoelk - Chief Financial Officer and Principal Accounting Officer

Analysts

Scott Hanold - RBC Capital Markets, LLC, Research Division

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

Peter Kissel - Howard Weil Incorporated, Research Division

Jared Lewis - Northland Capital Markets, Research Division

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Operator

Good day, everyone, and welcome to the Northern Oil and Gas, Inc. Fourth Quarter and Year End 2013 Earnings Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Michael Reger. Please go ahead, sir.

Michael L. Reger

Thanks, April. Good morning, ladies and gentlemen. This is Mike. We're happy to welcome you to the 2013 year end earnings call for Northern Oil and Gas. With me today is Tom Stoelk, our Chief Financial Officer, who will discuss our financial highlights from 2013.

Before we begin this morning's call, you should be aware that certain statements made during this call may contain forward-looking statements that are based upon management's expectations, estimates, projections and assumptions and that involve certain risks and uncertainties. We encourage you to review the various risk factors relating to our business, which are available in our annual report on Form 10-K and other reports filed with the SEC.

These forward-looking statements relate to our future plans, objectives, expectations and intentions. Our actual results could differ materially from those contemplated by these statements, partially as a result of the various assumptions relied upon in making such statements.

During this conference call, we will also make references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the applicable GAAP measures can be found in the earnings release that we put out last night.

2013 was another good year for Northern. We increased production by 19%, increased our reserves by 25% and added 531 gross or 40 net wells to production, bringing our total producing well count to 1,758 gross or 146.2 net wells. Including the roughly 250 gross wells that we had drilling or awaiting completion at year end, Northern has now participated in over 2,000 gross wells, representing approximately 20% of all Bakken and Three Forks wells drilled in the Williston Basin since our founding in 2006.

Looking back at 2013, it really was a tale of 2 halves for Northern. The first half saw a rough winter with extended road weight restrictions, resulting in relatively flat production levels, but high completion activity in the spring and summer months brought on a strong rebound in the second half of the year.

In the second half of 2013, North Dakota field production grew by approximately 18% versus the first half of 2013. During that same time period, Northern increased its production by 25% versus the first half of 2013. Also, as North Dakota production growth slowed during the fourth quarter, Northern's quarterly production grew by 7% sequentially to just under 14,000 Boe per day, again, outpacing North Dakota's field production growth. We believe these achievements are a testament to what we consider a high-grade acreage position, with exposure to the premiere operators in the play.

As we start 2014, it appears to be shaping up very similar to 2013, although we have a head start due to a large inventory of current wells in process. While we only added approximately 1 net well to production in January, we spud 4.5 net wells during the month. At the end of January, we were participating in approximately 19 net wells in process compared to approximately 11 net wells at the end of -- at the same time last year.

Considering the extreme cold temperatures so far in January and February, coupled with expected road weight restrictions at spring, it is likely that completion activity will be constrained in the first half of the year. However, we remain very optimistic about 2014 as a whole due to robust activity levels, which will likely result in a similar production ramp in the second half of the year.

With all that factored in, we expect total 2014 production growth of approximately 15% or approximately 5.1 million Boe. On that note, given the completion activity we are seeing in the field at this point in 2014, it is very important that we are conservative about our production growth estimates for the year.

If the 44 net wells that we are estimating to be completed and their associated CapEx come on in a straight-line fashion, we would expect higher production growth in 2014 than 15%. In 2013, we completed 40 net wells, 25 of which came on in the second half, and we increased annual production by 19%. So to be conservative, we are modeling a similar pattern for 2014.

Another thing I'd like to point out, when evaluating Northern's production growth compared to our peers, our growth has been almost exclusively organic. We have not been buyers of large acreage and production package deals, rather, we have built our asset base lease by lease. As the non-operator of record in the Williston Basin/Bakken play, we will continue to be disciplined in our business model and acquisition strategy, seeking only high-quality, non-operated near-term drilling opportunities.

Overall, we continue to see the economics of the basin improving as operators are increasingly focused on full pad development drilling and new completion designs, which should continue to improve productivity in 2014 and beyond.

With that, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss the financial highlights from 2013.

Thomas W. Stoelk

Thanks, Mike. For 2013, we reported GAAP net income of $53.1 million or $0.85 per diluted share. Excluding a net of tax impact of a noncash loss on the mark-to-market of our derivative instruments, we've reported adjusted net income of $66.4 million or $1.06 per diluted share.

For the fourth quarter of 2013, we reported GAAP net income of $17.4 million or $0.28 per diluted share. Excluding a net of tax impact of a noncash gain on the mark-to-market of our derivative instruments for the fourth quarter of 2013, we reported adjusted net income of $13.7 million or $0.22 per diluted share.

During 2013, we continued to see strong cash flow growth. We reported adjusted EBITDA of $268 million for 2013, a 19% increase compared to 2012, and that was driven by our growth in production. In the fourth quarter of 2013, adjusted EBITDA reached $71.7 million as compared to $63.6 million for the same period last year.

In 2013, oil and natural gas sales increased 24% over 2012, driven primarily by a 19% increase in production. In 2013, we produced nearly 4.5 million barrels of oil equivalent and our daily production averaged 12,261 Boe per day. Northern's 2013 average oil differential to the NYMEX WTI benchmark was $8.68 per barrel as compared to $9.79 per barrel in 2012.

In the fourth quarter of 2013, oil and gas sales increased 23% compared to the fourth quarter of 2012 that was driven by a 28% increase year-over-year. Daily production levels in the fourth quarter averaged 13,946 Boe per day.

Our fourth quarter oil sales were impacted by an oil differential that reached $14.98 per barrel. That compares to a $2.70 -- $2.17 per barrel amount in the fourth quarter of 2012. Based on the discussions we've had with our operating partners and other information that we have received, oil differentials have dropped into the single digits into 2014, and we currently expect the yearly range to range somewhere between $8 and $10 per barrel.

As a result of the oil price derivative activities, Northern incurred a net cash loss of $12.2 million in 2013 compared to a loss of $400,000 in 2012. As a result of forward oil price changes, our noncash mark-to-market derivative gains and losses resulted in a noncash loss of $21.3 million in 2013 as compared to a noncash gain of $15.1 million in 2012.

Production expenses were $41.9 million in 2013 compared to $32.4 million in 2012. The aggregate increase production expenses was primarily due to a 38% increase in the total number of operated or -- net wells, as well as higher production levels.

On a per-unit basis, the average production expenses per Boe increased from $8.61 in 2012 to $9.35 in 2013. The year-over-year increase on a; per-unit basis, primarily due to costs associated with water hauling and disposal expenses and higher workover costs. Production expenses per Boe decreased from $9.85 in the fourth quarter of 2012 to $8.85 per Boe in the first quarter -- or fourth quarter of 2013. The decrease cost on a per-unit basis, primarily due to increased production from lower cost areas in the fourth quarter of 2013 as compared to last year's fourth quarter.

We pay production taxes based on the amount of oil and gas sales. Production taxes totaled $35 million in 2013, that compares to $28.5 million in 2012. Our average production tax rates as a percentage of oil and gas sales averaged 9.5% in 2013, which was essentially flat with the 9.6% rate we experienced in 2012. Production taxes as a percentage of oil and gas sales were 9.7% in the fourth quarter of 2013 as compared to 9.5% in the fourth quarter of 2012.

General and administrative expenses were $16.6 million for 2013, which compares to a $22.6 million amount for 2012. The decrease between years was primarily due to a $5.5 million severance charge in connection with the departures of the company's former President and former Chief Operating Officer in 2012 and a $1.3 million reduction in salary and benefits, which was partially offset by increases in other administrative costs.

General and administrative expense was $4.5 million in the fourth quarter of 2013. That compares to $4.1 million for the fourth quarter of 2012. The fourth quarter of 2013 increased over the fourth quarter of 2012, primarily due to some increased insurance costs, as well as higher professional service expenses.

DD&A was $124.4 million in 2013 compared to $98.9 million in 2012. The aggregate increase in DD&A expense for 2013 compared to 2012 was driven by an increase in production and higher depletion rates. Depletion expense, the largest component of DD&A, averaged $27.62 per Boe in 2013 compared to $26.18 per Boe in 2012.

Depletion rates rose to $30.02 per Boe in the fourth quarter based on year end reserve estimates, which was partially due to higher production expenses and revised reversed -- reserve estimates in certain of our areas of operation. The provision for income taxes was $31.8 million in 2013 compared to $43 million in 2012. The effective tax rate in 2013 was 37.4%, essentially flat with the 37.3% from a year ago.

Our total proved reserves at December 31, 2013, as estimated by Ryder Scott, were approximately 84.2 million Boe that represents a 25% increase in proved reserve volumes from our 2012 year end. Approximately 90% of our proved reserves are oil and 42% of our proved reserve volume for categorized as proved developed. Based on 2013's net additions, our reserve replacement ratio was 370%. The PV10% value of proved reserves at year end reached $1.5 billion, with approximately 68%, over 1 billion of those, of the PV10% value attributable to our proved developed properties.

As of December 31, 2013, we controlled approximately 187,000 net acres targeting the Williston, Bakken and Three Forks. Approximately 63% of that total acreage position and approximately 73% of our North Dakota acreage position was developed, held by production or held by operations.

During 2013, total capital expenditures equaled $439.1 million. A general breakdown of costs were as follows: We spent approximately $389.5 million on drilling at completion capital, which includes capitalized workover expenses. We spent $38.5 million on acreage and other expenditures, and the remaining cost totaled approximately $11.1 million.

During the fourth quarter of 2012, total capital expenditures equaled to $119.7 million. The fourth quarter, quarter breakdown of the capital spending is as follows: Drilling and completion expenditures, including capitalized workovers, were approximately $109.5 million; $6.1 million related acreage and other expenditures; and the remaining cost totaled approximately $4.5 million.

Given the large number of wells in process and the varying percentage completion of these wells, between periods, it's difficult to compute on average completed well cost for 2013 using public information we provide. The average completed well cost in 2013 amounted to $8.8 million. But we'll point out that this average well cost includes a slightly higher mix of McKenzie wells during the year. As of December 31, 2013, our weighted average AFE cost for the wells in process averaged approximately $8.9 million. If you would eliminate the higher cost McKenzie County wells, that weighted average drops to approximately $8.5 million.

As indicated our press release last night, Northern expects 2014 total capital expenditures to range between $430 million and $440 million. The 2014 budget anticipates the company will participate in the drilling and completion of 44 net wells and expects the average well cost to be approximately $8.8 million per net well. Additionally, we are currently estimating $12 million in capitalized workover expenses and $30 million to $40 million of spending on acreage and other expenditures.

Keep in mind that our actual CapEx spending will be impacted by the change in the number of wells that we have in process at period end. We ended 2013 with approximately 15.2 net wells on our drilling and completion list. Based on our estimate that we will add approximately 44 net wells during the year, Northern estimates that 2014 production goal will be approximately 15%.

As Mike referenced in his earlier comments, we believe that weather will significantly impact the timing of well completions and production activities during the first quarter and depending on the length of the road restrictions, could have a second quarter impact as well. We expect the newer well completion technologies will continue to improve well productivity, but weather issues will slow the drilling and completion activity during the first half of 2014.

As noted in our press release, the company had just under one net well completed when historically, we averaged probably 3 to 4 net wells per month. Once the weather warms up, we expect the pace should pick up quickly, with our high backlog of wells awaiting completion. Our annual production growth forecast attempts to reflect the impact of these delays. As a result, we believe that sequential production [indiscernible] will occur primarily in the second half of 2014, which is similar to what we experienced in 2013.

We ended the year with our evolving credit facility having $75 million drawn on the $450 million borrowing base. And combined with cash flow from operations, we expect to have ample liquidity to develop our asset base in 2004. We continue to layer hedges in opportunistically as the market warrants to increase the predictability of our cash flow and help maintain a strong financial position.

For 2014, we currently have approximately 10,300 barrels of oil per day swapped out at an average price of $90.46 and approximately 650 barrels of oil per day using costless collars having an average floor price of $90, average ceiling price of $99.05 per barrel. In 2015, we have hedged approximately 7,800 barrels of oil per day at an average swap price of $89.02.

At this time, we want to turn the call over to the operator. April, if would please give the Q&A instructions?

Question-and-Answer Session

Operator

[Operator Instructions] And we'll first hear from Scott Hanold of RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So a couple of questions. First, looking at the Smackover Brown Dense. Certainly, it's been a bit of an exploration project for the last couple of years. At a high level, when do you all think you're going to get some [indiscernible] direction on whether or not the go-forward project, or you guys are going to look to maybe try something else?

Michael L. Reger

Scott, this is Mike. I -- you might have your notes mixed up there. We don't have any Smackover Brown Dense assets. But we'll step through our leaseholds and see if there's anything in there. We're 100% Bakken and Three Forks, Scott.

Scott Hanold - RBC Capital Markets, LLC, Research Division

I hope you could appreciate there's a number of calls going on, so I'm a little...

Michael L. Reger

Yes, no problem.

Scott Hanold - RBC Capital Markets, LLC, Research Division

I -- apologies. So obviously, the Bakken was off to a bit soft start because of weather. And with that 0.9 net well January, I mean, what does February look like? Is it very similar? Are we basically to look at the first quarter, somewhere around -- maybe the lows like 3 to 4 net wells completing with -- really ramping up in sort of the middle of the year?

Michael L. Reger

The February looks to be a bit better than January. The January at 1 net well was uniquely low. But as you -- as we mentioned earlier on our comments, we spud 4.5 net wells, so drilling activity continues to be robust. When drilling on pads, we're able to get these wells drilled and with no problem. It's moving water around and freezing hoses and pipes at the frac sites, that's the challenge. So February's been a little bit better, although if you look at your weather, it's going to be 25 below again tonight. It's been pretty tricky out there. But similar to last year, if you remember, I think in July, we added more net wells than the entire second quarter. It just -- it all sort of back half loads. But I think that February's been better, and we think it's going to continue to get better. And that we're just fingers crossed that road restrictions will be normal last year as opposed to last year. That's our big variable.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And so it sounds to me like it certainly much more heightened the weather which is more heightened on the completion side. Is that a fair statement?

Michael L. Reger

Yes. Drilling doesn't seem to be affected. If you annualize our January spuds, that's about 54 net wells, and we're estimating 44 net wells for the year.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. So that kind of squares the circle on the next question, because CapEx seemed a little high relative to completion just because of your drilling net, okay? And then, when -- of those 18.8 net wells, how many of those -- I mean, are a lot of those on multi-well pads where some of them will be grouped on together? Like a couple of quarters ago, you had a bunch on the peninsula on pads. And when those came on, we saw flush production and ramped real rapidly. Are we going to see the this similar phenomena again this year?

Michael L. Reger

I think the -- based on what we saw towards the end of the year, we're look at -- probably 75% to 80% of the wells we're currently drilling are on some of the larger pads. Slawson specifically, which you referenced from last year, they've had 3 rigs operating on the peninsula on 4 to 6 well pads for the last year or so. So we did catch a nice win from that in the third quarter of 2013, as Slawson turned on a bunch of those pads. And we have a similar, even a larger backlog of pads waiting to complete on the peninsula literally as we sit right now. So we expect that to be a nice tailwind going into the year as well. The only factor, again, is just weather-related completion delays and road weight restrictions, which seem to affect the second quarter of 2013. So we're just watching that again really closely. Road restrictions in 2013, which typically come off anywhere between late May and the middle of June or middle of -- excuse me, middle of May to the middle of June, they were extended to July 8 of last year, and so that was unique. So we're just fingers crossed that the road weight restrictions are more normalized this year. And that's going to -- we think that's going to improve our current completion modeling and our current estimates for annual production growth.

Scott Hanold - RBC Capital Markets, LLC, Research Division

And so a lot of that road restrictions effectively is going to relate to how much snow is in the ground, right? And I know it's been really cold out there, but obviously, being on the ground, are there more -- can you kind of give us a sense of -- from a snowpack perspective this year versus last year, how does it look right now?

Michael L. Reger

Yes. The good news is there isn't a lot of snow out there. We -- but we -- because of the cold temperatures, we think the frost level is a little bit deeper. So because there isn't a lot of snow, you don't have the water table issues. And then if we get to normal weather, and we're looking at the 30-day AccuWeather, it's going to be 30 to 40 degrees or 30 degrees to 50 degrees in about a week from now for the next month or so. So we think that if it -- very slowly -- and comes up like normal, that's going to really help things. But the fact that there isn't a lot of snow, that's going to -- that's a big positive for us as we kind of again have our fingers crossed for road restrictions being lifted earlier in the spring than later.

Operator

Next, we'll hear from Ryan Oatman, SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Jim, did I hear you correctly, the differential should be $8 to $10 or less in 2014, you're saying?

Thomas W. Stoelk

Yes. I mean, that's our expectation right now, and that's just based on discussions that we've had with operators. We've had some of our January receipts in, but I think that will range between $8 and $10.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay, okay. So that is down significantly from the $15, I guess, we saw in 4Q and the $10 average for the year, okay, so that's helpful. And it does look like operating expense ticked lower quarter-over-quarter to less than $9 a barrel from about $10.50 in 2Q, $9.50 in 3Q. What's a good go-forward number for us to use there?

Thomas W. Stoelk

It's depends on the mix of the wells. But I think that we're comfortable with the $9 kind of flat, maybe possibly tick a little bit lower than that. It will depend on the mix of the wells, but somewhere around $8.80 to $9 is probably a pretty good range.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay, very good. One final one for me. It looks like the budget in the AFES are coming in at about $9 million, whereas some peers are guiding more in kind of that $8 -- $8 million range. Can you help us kind of reconcile that difference? Is it kind of differences in counties, is it differences in them having their own frac crews, if they can kind of net those costs? Just trying to kind of understand the difference between those 2 averages that we see.

Thomas W. Stoelk

I think I'll make some comments and let Mike tag on if you'd like. But I think that a lot of it has to do with really the mix of wells. The wells in McKenzie for us, and I referenced it in the script, it was $8.9 million as of the end of December kind of average AFE cost. If you excluded the McKenzie mix out of it, it's more $8.4 million. I think your point about some of the operators having their own stimulation crews are being able to use the efficiencies out of there to drop those well costs closer to $8 million is also something that is -- affects the comparability, I think, of the 2 data points you're trying to do.

Michael L. Reger

And one thing I want to add to, to that is as you look at our waiting over the last few years, specifically 2012, we had a lot of Richland County activity, with Slawson, we had some Divide County activity that we had farmed into. But if you look at the last half of 2013 and then our current D&C list by county just ties in to Tom's answer, which is up 30% of the net wells in process as of the end of January. We're in McKenzie County, and McKenzie County is a lot deeper, as you know, and those well costs are a bit higher. But more importantly, 92% of the wells in process are weighted in McKenzie, Mountrail, Dunn and Williams. 30% in Mountrail, 30% in McKenzie and the balance in Dunn and Williams. So that's a really important factor as it's going to relate to everything. Well productivity is going to improve -- again, well productivity is going to improve. Lease operating expenses. As our lower lease operating expenses and water hauling and water charges are in some of the better counties. So just provide a little color for you.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

That's very helpful. Do you see operators moving more obviously towards pad drilling? And do you think that, that kind of bears some impact on maybe 1Q being a little bit weaker, but you see they ramp back half of the year, or do you really see more weather is kind of the culprit here?

Michael L. Reger

It's just -- it's really just completions that are tricky. When you're moving water around and just trying to get wells frac-ed with freezing hoses and they basically just shut in if it's 20 below. There's no sense trying to move fluids around. But I think the real answer is, pad drilling is not necessarily going to be a big culprit for us. As far as lumpy net well adds, it's typically going to be weather. With approximately 250 gross wells currently drilling or completing or in various stages of completion, Northern, as I've always said, has somewhat of a smoothing effect. If we are a 1-rig operator and we were sitting on a 4- to 6-well pad, it would definitely create pretty lumpy scenario for us from production standpoint. But weather aside, we're going to be both drilling and competing pads every week. There isn't going to be a real lumpy nature to it. So I think the main issue for us is going to be weather. And just the severe cold that's really hampered completion activities. And then as we get into the spring, when you're trying to move sand and water around when you've got road restrictions, it makes it more expensive and it makes it harder from a just-in-time standpoint at the wellhead to get these wells completed. So that's the way we're looking at it. But again, with 250 gross, 19 net wells in process, that's somewhat of a smoothing affect as it relates to pad drilling and pad drilling is generally a good thing.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Right, that's a good point. One final one for me, we talked in the past about a lot of the technological innovations going on in the Bakken right now. Was just curious if you had any sort of color or any kind of anecdotes for us on that front where you're seeing potential productivity gains in the basin? And I'll sit back with you.

Michael L. Reger

Yes. Yes, thanks a lot, Ryan. I think the -- that's a good question to end on because it's what we're watching really closely here, and it's really exciting. I think, specifically EOG, who we have a lot of exposure to. In Mountrail County, we're starting to see these the new completion designs add to our EURs. I think more than anything, that innovation, with more sand and coupled with -- it appears to be more density. And from an infill drilling standpoint, I think that's probably going to impact Northern in the long run more than anything. So really exciting to see EOG, Whiting and others begin to adopt this across the board, this new completion design. And we're getting a direct benefit, specifically from EOG right kind of real time. So thanks a lot, Ryan.

Operator

Next, we'll hear from Jason Wangler of Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Just curious with the share repurchase program, the $2 million, was that all done in the fourth quarter or did that spill in the first quarter as well?

Michael L. Reger

The share repurchase program we announced in November was all completed in the third quarter and then we continue to be very opportunistic. We still have an authorization from the board to continue buying stock, so we're watching that very carefully. And if we see a good opportunity to continue buying, we will as that authorization is still in place.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Sure. And then obviously, the reserves moved up pretty nicely. Just curious when the next redetermination is on your line and what you're expecting there.

Thomas W. Stoelk

Yes. We have an April 1 redetermination, so we have a bank meeting next week. So probably right around the first or second week of April you'll see us announce where we're at with respect to that.

Operator

Next, we'll hear from Steve Berman of Canaccord.

Stephen F. Berman - Canaccord Genuity, Research Division

Mike, what is the -- what does the pipeline look like right now for M&A or acquiring in non-op acreage up there?

Michael L. Reger

We just came off of NAPE in Houston a couple of weeks ago, and one thing we're finding as an opportunity for Northern is that we're seeing a lot of folks in the field who we have typically acquired non-operated interest from in the past. They're starting to receive 4 well proposals in the same envelope. If somebody receives 10% in the past, it received 10% working interest AFE and decided whether or not to sell that to Northern or not. Now, they're getting 4%, 10%-ers because of the pad drilling proposals they're getting from the operators. So we're starting to see more activity as our balance sheet allows us to take the opportunities that we want and the opportunities that we like. So we continue to see acreage opportunities, and that's pretty brisk right now. At certain in times in the past, we felt that it had slowed down and then it would speed back up. But right now, just given the pace of activity, I mean, there's 194 rigs drilling in North Dakota alone as of last night. And with, we think, somewhere around 75% to 80% of those rigs drilling on 4- to 6-well pads, we think that our opportunity to acquire non-op interest is brisk, especially over the course of '14. The -- we've seen some of the bigger deals that we've looked at. We looked at the Oasis deal and other non-op package deals. We do bid on those deals, but we typically -- it seems like the MLPs are picking off the larger marketed package deals. So we continue to do what we do best, which is to, on a lease-by-lease basis, we just continue to be the clearinghouse for non-operated orphaned minority interest in the field, and we've always done that really well and we're going to continue to execute that strategy kind of going into our eighth year here.

Stephen F. Berman - Canaccord Genuity, Research Division

Are you participating in any of the downspace testing going on up in the Williston and -- or the lower Three Forks benches? I just like to get your thoughts on those innovations going on up there.

Michael L. Reger

Yes, we are. We're watching that as closely as anything, because what it does more than anything is it adds to our long-term inventory of drilling in the Williston. We participated in the first well that was testing the lower benches of the Three Forks. The Continental Charlotte well, we have working interest in that well, so that was really fun to monitor real time. And then Continental, as you know, has released those results. They released those results in 2013, and they were really exciting. We participated in quite a few now as the operators continue to delineate the lower benches of the Three Forks. I think the general thought is that they are productive throughout the field. I think that the argument would be whether benches 2, 3 and 4 or all 3 lower benches are separate distinct reservoirs. So this is a really high-class problem as we begin to debate the productivity of each individual zone. But I think what we can assume here at this point is that we definitely have additional oil to harvest over the coming, really, the coming decades. So it's really exciting to watch it. The productivity seems good. I think we just -- we're monitoring to see how they communicate with each other.

Stephen F. Berman - Canaccord Genuity, Research Division

Great. Last one for me. What's the remaining authorization on your stock repurchase plan?

Michael L. Reger

I think the -- what we're limited by, more than anything, I should say, is the restricted payments bucket within -- in our bond covenants, in our credit facility covenants. And that restricted payments bucket is -- and it grows every quarter by adjusted net income, but somewhere in the neighborhood of $70 million to $80 million is what we currently have in our restricted payments bucket. And the board and management are going to be, over time, opportunistic about how we deploy that capital.

Operator

Peter Kissel, Howard Weil.

Peter Kissel - Howard Weil Incorporated, Research Division

A couple of quick questions. Mike, thanks for giving us the county breakdown of the wells in process. But I was wondering, is that a fair breakdown to use for the remainder of the year? Or is there any particular shift to other counties? Or even within that group, any particular shift later on this year based on what your permanent flow looks like?

Michael L. Reger

Thanks, Pete. I think the -- that percentage, we've been between 90% and 92% between those 4 core counties for the past year or so. And that won't change throughout 2014, in our estimate. I think the -- as you know well, throughout 2012 and then maybe tailing into the very beginning of 2013, we were adding a lot of inventory from Divide County, which we had farmed into, which -- that generally affected our LOEs and affected our overall productivity per well. But as that percentage -- as we stopped farming into those opportunities in 2011 and 2012, we started to -- that mix of our asset base. And if you look at our asset base, that's generally going to be where it's going to be. So for the past year, it's been the same and we expected to be the same throughout 2014.

Peter Kissel - Howard Weil Incorporated, Research Division

Got you, okay. And then one other that's not really NOG-specific, but I was wondering if you care to comment on the rail situation up in the Bakken, obviously, have exposure as a non-operator. So all the different takeaway options, and just curious to what you think could happen if anything to the rails?

Michael L. Reger

Yes, I think the -- I think it all looks pretty good. And as we start to get more clarity on some of the regulatory issues that we're seeing around crude by rail, I think everything looks pretty good. I think one thing we saw last week was that the DOT is going to start requiring testing of crude as it leaves the field. Well, what's interesting is that every rail terminal has to test anyway based on package group for the buyer before it leaves the terminal. So that's all a generally good thing. One thing that is important to us is what it means for differentials. As we talk to our operating partners and as we talk to some of the rail terminals that we're familiar with, January was in the single digits when it came to wellhead pricing, which is an improvement for Northern, an improvement for the field as it relates to November and December. And then what we're hearing is that February might be even better in the $4 to $5 range at the wellhead. So that's good for us. There's plenty of takeaways, as you know, there's over $1 million barrels of rail take away and almost 600,000 barrels of pipeline take away to get about 1 million total barrels out of the field. So rail is playing a big part. There's a lot of markets to take that oil, which is important for our partners and us. So differentials are really important in Northern and as you watch those come down, we've got oil at $103 and differentials that might be in the $4 to $5 range, that's going to be -- that's going to bode pretty well for us as we go through 2014 just hopefully, it stays nice and tight.

Operator

Next, we'll hear from Jared Lewis of Northland Securities.

Jared Lewis - Northland Capital Markets, Research Division

Just curious, given the completion side of the business is getting the biggest impact with the weather, and once we do see weather improve and road restrictions, what you can anticipate, how the completion crews will work through that inventory if -- may we see something like we've seen in a couple of years ago where it becomes a premium on completion crews and well cost actually start creeping up? Just kind of curious on your thoughts.

Michael L. Reger

Yes, that didn't seem to be an issue for us in 2013. I think we're -- the nice side about -- the nice part about 2014 is we have pretty decent hindsight to a similar situation and pattern in 2013. It was very efficiently and -- it was very efficiently -- the backlog that we had growing in the first half of 2013 was very efficiently completed throughout the year. Again, we just -- we're hopeful that it doesn't stack up like it did in 2013. And if we get a little more straight line on the approximate 44 net wells that we expect to complete this year, it's going to dramatically improve our estimates for total production. So I don't think that's going to affect cost because it didn't in 2013. So that's probably a fair answer based on what we saw last year.

Operator

Next, we'll hear from Adam Leight of RBC Capital Markets.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Just a couple left for me, too. On the wells that you have on your list currently, [indiscernible] -- could you give us a sense of your operator concentration?

Michael L. Reger

Yes. I think the concentration that we've seen in the past is going to be fairly similar. It's -- if you look at our top 5, it's going to be Slawson has Continental, EOG and Statoil. I mean, that's been our -- they've been our top 5 for a long time. Slawson is going to be big for us from the weighted average standpoint just because they have the 3 rigs actively developing, the peninsula in Southern Mountrail County and that's where we have some of our highest working interest wells. We also have a nice chunk of the Conoco Corral Creek unit in McKenzie County. They have 4 wells actively drilling in that area right now and on pads, and that's pretty meaningful to us because those are some of our higher EUR wells and some of the best wells in the basin. So we're seeing that Slawson -- and then we're starting to see Continental -- or excuse me, Conoco creep up as we add more and more wells from the Corral Creek unit, the big unit just south of the peninsula, just south of the river. So really good mix so far.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Great. And then on the working interest, what's the variance in your working interest, the current well was about 7.5% average?

Michael L. Reger

Yes. I think throughout the field, we're going to see -- over time, we're going to see that 7% to -- call it 7% to 9%. It just depends on where the operators are at any given time and what opportunities we're seeing for new acquisitions. But you can count on Northern being pretty -- to be conservative, 7% to 8% over the long haul. And that'll vary between -- that'll vary over the -- quarter-by-quarter, but that's a very safe average going forward. And again, in -- Southern Mountrail County with Slawson where we're seeing some of our better wells and some of our lower drilling cost, that just happens to be some of higher working interest units.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Okay. And then lastly, you talked a little bit about water costs. Are you seeing from your operators any change in quantities being taken out by truck on the disposal side versus removing [indiscernible]

Michael L. Reger

No. I think the -- what we've seen, especially over the last year, maybe 1.5 years is that water disposal has become more of an efficient issue for us. It's -- where we were getting -- where we were seeing a lot of cost increase over the last, call it, 2 years was primarily up in the northern part of the play, kind of Divide County, Burke County, Northern Williams, that's where the water disposal costs were the highest. I think infrastructure has really started to improve up there. Generally, as you saw more of the mature parts of the play in Mountrail County, in McKenzie County, there's a lot of water disposal wells and water disposal infrastructure. And so there, we've seen lower costs. We started to see our LOE drop here this quarter. We think that might continue to drop based on additional water disposal infrastructure. But if you took the counties, take Burke and Divide out of the picture, our LOE would probably go down materially. So as we reduce our exposure to those areas, LOE is likely to go down.

Operator

And that does conclude the question-and-answer session. Mr. Reger, do you have any closing comments?

Michael L. Reger

No, April. Thanks for your participation in this call, everybody, and your interest in Northern. April will give you the replay information and we look forward to talking to you over the next few months during conference season, and we forward to sharing our results with you next quarter. Have a great day, everyone.

Operator

And that does conclude today's conference. Thank you, all, for your participation.

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