Northern Oil and Gas Inc (NOG) 2013 Q4 法說會逐字稿

Good day, everyone, and welcome to the Northern Oil and Gas Incorporated 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.

Thanks, April. Good morning, ladies and gentlemen, this is Mike. We are 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 we have 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 per 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 two 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 premier 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 -- at the same time last year.

Considering the extreme cold temperatures so far in January and February, coupled with expected load weight restrictions this 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 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 in 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.

Thanks, Mike. For 2013, we reported GAAP net income of $53.1 million, or $0.85 per diluted share. Excluding the net of tax impact of a non-cash loss on the mark-to-market of our derivative instruments, we 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 the net of impact of a non-cash 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, and 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 $2.17 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 non-cash mark-to-market derivative gains and losses resulted in a non-cash loss of $21.3 million in 2013. That is compared to a non-cash 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 in production expenses was primarily due to a 38% increase in the total number of net wells, as well as higher production levels.

On a per-unit basis, the average production expenses for Boe increased from $8.61 in 2012 to $9.35 in 2013. The year over year increase on a per-unit basis was primarily due to costs associated with water hauling and disposal expenses and higher workover costs.

Production expenses for Boe decreased from $9.85 in the fourth quarter of 2012 to $8.85 per Boe in the fourth quarter of 2013. The decreased costs 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. That compares to 9.5% in the fourth quarter of 2012.

General and administrative expense was $16.6 million for 2013, which compares to a $22.6 million amount for 2012. The decrease between years is 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 our year-end reserve estimates, which was partially due to higher production expenses and revised 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 a 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 43% of our proved reserve volumes are categorized as proved developed.

Based on 2013's net additions, our reserve replacement ratio was 370%. The PV-10 value of proved reserves at year end reached 1.5 billion with approximately 68%, or over 1 billion of those, of the PV-10 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 this cost are as follows: We spent approximately $389.5 million on drilling and completion capital, which includes capitalized workover expenses; we spent $38.5 million on acreage and other expenditures and the remaining costs totaled approximately $11.1 million.

During the fourth quarter of 2012, total capital expenditures equaled $119.7 million. The fourth 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 to acreage and other expenditures, and the remaining costs 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 an average completed well cost for 2013. Using the public information we provide, the average completed well cost in 2013 amounted to a $8.8 million. I will 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 costs for the wells in process average approximately $8.9 million. If you would eliminate the higher cost McKenzie County wells that weighted average drops to approximately a $8.5 million.

As indicated in 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 the 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 average probably three to four 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 [coat] will occur primarily in the second half of 2014 which is similar to what we experienced in 2013.

We ended the year with our revolving 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 (sic--"2014"). 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 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, an 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 you would please give the Q&A instructions.

(Operator Instructions)

Scott Hanold of RBC Capital Markets.

Yes, thanks, guys. How's it going?

Great, Scott, thanks.

Good. So, a couple 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 [unit] direction on whether or not it's a go-forward project, or you guys are going to look to maybe try something else?

Scott, this is Mike. You might have your notes mixed up there. We don't have any Smackover Brown Dense assets. (laughter) But we will sift through our leaseholds and see if there's anything in there. We are 100% Bakken and Three Forks, Scott.

(laughter) I hope you can appreciate, there's a number of calls going on. So I'm a little --

Yes, no problem.

I apologize. So, obviously, the Bakken was off to a bit of a soft start because of weather, and with that 0.9 net well in January, what does February look like? Is it very similar? Are we basically going to look at the first quarter somewhere around -- maybe as low as three to four net wells completing, with it really ramping up in the middle of the year?

February looks to be a bit better than January. January at one net well was uniquely low. But as we mentioned earlier in our comments, we spud 4.5 net wells, so drilling activity continues to be robust. When drilling on pads, we are able to get these wells drilled with no problem. It's moving water around, and freezing hoses and pipes at the frac sites that's the challenge.

So, February has 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 all sort of back-half loads, but I think that February has been better, and we think it's going to continue to get better, and fingers crossed that road restrictions will be normal this year as opposed to last year. That's our big variable.

Okay. So, it sounds to me like it's certainly much more heightened -- the weather issues are more heightened on the completion side; is that a fair statement?

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.

Okay, so, that kind of squares -- circle to my next question because CapEx seemed a little high relative to completions, but it's because you are drilling then, okay.

And then, of those 18.8 net wells, are a lot of those on multi-well pads where some of them will be grouped on together? I know like a couple of quarters ago you had a bunch on the peninsula on pads, and when those came on we saw a flush production and a ramp real rapidly. Are we going to see a similar phenomena again this year?

I think, based on what we saw towards the end of the year, we are looking at probably 75% to 80% of the wells we are currently drilling are on some of the larger pads. Slawson, specifically, which you referenced, from last year -- they've had three rigs operating on the peninsula on four- to six-well pads for the last year or so. We did catch a nice wind from that in the third quarter of 2013, as Slawson turned on a bunch of those pads. And we have a similar, or even a larger, backlog of pads waiting to complete on the peninsula, literally as we sit right now. 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 seemed 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, excuse me, middle of May to the middle of June -- they were extended to July 8 of last year. That was unique.

We are -- fingers crossed that road weight restrictions are more normalized this year. And that's going -- we think that's going to improve our current completion modeling and our current estimates for annual production growth.

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

The good news is: There isn't a lot of snow out there. But 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 some normal weather, and we are looking at the 30-day AccuWeather -- it's going to be 30 to 40 degrees or 30 to 50 degrees in about a week from now for the next month or so. So, we think that if it very slowly comes up like normal, that is going to really help things. But the fact that there isn't a lot of snow, that's a big positive for us, as we, again, have our fingers crossed for road restrictions being lifted earlier in the Spring than later.

Okay, that's some good color; I appreciate it. Thanks.

Thanks, Scott.

Ryan Oatman, SunTrust.

Hi, good morning.

Good morning, Ryan.

[Jim], did I hear you correctly: The differential should be $8 to $10 or less in 2014, [you think]?

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

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?

It depends on the mix of the wells, but I think that we are 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.

Okay. Very good.

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

I'll make some comments, and then 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 and being able to use the efficiencies out of there to drop those well costs closer to $8 million is also something that affects the comparability, I think, of the two data points you are trying to do.

Yes, and one thing I want to add, too, to that is: As you look at our weighting, 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 -- and this ties into Tom's answer, which is: about 30% of the net wells in process as of the end of January were 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; it's 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 to provide a little color for you.

That's very helpful.

Do you see operators moving more, obviously, towards pad drilling, and do you think that that bears some impact on maybe 1Q being a little bit weaker, but you see the ramp back half of the year? Or do you really see more weather as kind of the culprit here?

It's really just completions that are tricky when you are moving water around and just trying to get wells fracked with freezing hoses. They basically just shut in if it's 20 below. There is no sense trying to move fluids around.

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 were a one-rig operator and we were sitting on a four- to six-well pad, it would definitely create a pretty lumpy scenario for us from a production standpoint.

But weather aside, we are going to be both drilling and completing pads every week. There isn't going to be a real lumpy nature to it.

I think the main issue for us is going to be weather and just the severe cold that has really hampered completion activities. And then as we get into the Spring when you are trying to move sand and water around, when you have got road restrictions, it makes it more expensive, and it makes it harder from a just-in-time standpoint at the well head to get these wells completed. That's the way we're looking at it, but, again, with 250 gross, 19 net wells in process, that is somewhat of a smoothing effect as it relates to pad drilling, and pad drilling is generally a good thing.

Right. That's a good point.

One final one for me. We've talked in the past about a lot of the technological innovations going on in the Bakken right now. I was just curious if you had any color or any anecdotes for us on that front, where you are seeing potential productivity gains in the basin? And I'll step back in queue. Thanks.

Thanks a lot, Ryan. That's a good question to end on because it's what we are 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 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 from an infill drilling standpoint -- I think that's probably going to impact Northern in the long run more than anything.

Really exciting to see EOG, Whiting, and others begin to adopt this across the board -- this new completion design. And we are getting a direct benefit, specifically, from EOG in real time. Thanks a lot, Ryan.

Thanks, Mike.

Jason Wangler of Wunderlich Securities

Good morning, guys. Just curious: With the share repurchase program, the $2 million -- was that all done in the fourth quarter, or did that spill into the first quarter, as well?

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 are watching that very carefully, and if we see a good opportunity to continue buying, we will, as that authorization is still in place.

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

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

That's helpful. I appreciate it.

Thanks, Jason.

Steve Berman of Canaccord.

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

We just came off of [Nathan] in Houston a couple weeks ago, and one thing we are finding as an opportunity for Northern is that we are seeing a lot of folks in the field who we have typically acquired non-operated interest from in the past -- they are starting to receive four well proposals in the same envelope. If somebody receives 10% in the past, they received 10% working interest AFE, and decided whether or not to sell that to Northern or not. Now they are getting four 10%-ers because of the pad drilling proposals they are getting from the operators. So, we are 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 times in the past, we've felt that it had slowed down, and then it would speed back up. But right now, just given the pace of activity -- 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 four- to six-well pads, we think that our opportunity to acquire non-op interest is brisk, especially over the course of 2014.

We have seen some of the bigger deals that we have 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 interests in the field. We have always done that really well, and we are going to continue to execute that strategy going into our eighth year here.

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

Yes, we are. We are 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 have 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 the argument would be whether benches two, three, and four, or all three lower benches are separate and 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 decade.

It was really exciting to watch it. The productivity seems good. I think we just -- we are monitoring to see how they communicate with each other.

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

I think what we are limited by, more than anything, I should say, is the restricted payments bucket within 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.

Great. Thanks, Mike.

Thank you.

Peter Kissel, Howard Weil.

Yes, hi, guys. Good morning. A couple 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 permit flow looks like?

Thanks, Pete. I think that percentage -- we have been between 90% and 92% between those four core counties for the past year or so, and that won't change throughout 2014, in our estimate. I think, 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 -- it 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 expect it to be the same throughout 2014.

Got you. Okay, thanks.

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

I think it all looks pretty good, and as we start to get more clarity on some of the regulatory issues that we are 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 the 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 generally a 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 are familiar with, January was in the single digits when it came to well-head pricing, which is an improvement for Northern -- an improvement for the field as it relates to November and December.

And then, what we are hearing is that February might be even better, in the $4 to $5 range at the well head. That's good for us. There's plenty of takeaway; as you know, there's over 1 million barrels of rail takeaway, and there is almost 600,000 barrels of pipeline takeaway 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. Differentials are really important to Northern, and as we watch those come down, and we've got oil at $103 and differentials that might be in the $4 to $5 range, that's going to bode pretty well for us as we go through 2014. Just hopefully it stays nice and tight.

Great, thanks, Mike. Much appreciated.

Thank you.

Jared Lewis of Northland Securities.

Good morning, guys.

Good morning.

I was 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 anticipate -- how the completion crews will work through that inventory? If maybe you see something like we've seen a couple years ago where it becomes a premium on completion crews, and well costs actually start creeping up? Just curious on your thoughts?

That didn't seem to be an issue for us in 2013. I think we're -- the nice part about 2014 is we have pretty decent hindsight to a similar situation and pattern in 2013. 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 are 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.

Okay. Perfect. Most of my other questions were answered, so I appreciate that. Thanks.

Thanks a lot.

Adam Leight of RBC Capital Markets.

Hi, good morning

Hi, Adam.

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

Yes. I think the concentration that we have seen in the past is going to be fairly similar. If you look at our top five, it's going to be: Slawson, Hess, Continental, EOG and Statoil; they have been our top five for a long time. Slawson is going to be big for us from a weighted average standpoint just because they have the three 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 four wells actively drilling in that area right now 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. We are seeing that Slawson, and then we are 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.

That's great, thanks. And then on the working interest -- what's the variance in your working interest for the current well list about 7.5% average?

Yes, I think throughout the field we are going to see -- over time, we're going to see that, call it, 7% to 9%. It just depends on where the operators are at any given time, and what opportunities we are seeing for new acquisitions.

But you can count on Northern being pretty -- to be conservative, 7% to 8% over the long haul. And that will vary quarter by quarter, but that's a very safe average going forward. And, again, in southern Mountrail County with Slawson where we are seeing some of our better wells and some of our lower drilling costs, that just happens to be some of our higher working interest units.

Okay. Thanks.

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 moving them -- ? (multiple speakers)

I think what we have seen, especially over the last year, maybe year and a half, is that water disposal has become more of an efficient issue for us. Where we were getting -- where we were seeing a lot of cost increase over the last, call it, two 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 the mature parts of the play, in Mountrail County and McKenzie County, there's a lot of water disposal wells and water disposal infrastructure, and so 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.

That's great. I won't ask the follow-up on the Smackover.

(laughter) Great. Adam, thanks.

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

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 look forward to sharing our results with you next quarter. Have a great day, everyone.

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