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Northern Oil and Gas (NYSEMKT:NOG)

Q2 2014 Earnings Call

August 08, 2014 11:00 am ET

Executives

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

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

Brandon R. Elliott - Executive Vice President of Corporate Development and Strategy

Analysts

Scott Hanold - RBC Capital Markets, LLC, Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

Peter Kissel - Howard Weil Incorporated, Research Division

Phillips Johnston - Capital One Securities, Inc., Research Division

Blaise Matthew Angelico - Iberia Capital Partners, Research Division

Marshall Carver

Operator

Good day, and welcome to the Northern Oil and Gas Second Quarter 2014 Earnings Conference Call. Today's conference is being recorded.

At this time, I'd like to turn the conference over to Mr. Michael Reger. Please go ahead, sir.

Michael L. Reger

Thanks, Aaron. Good morning, everyone. This is Mike. We're happy to welcome you to our 2014 second quarter earnings call for Northern Oil and Gas. With me today is Tom Stoelk, our Chief Financial Officer, who will discuss some of our financial highlights from the second quarter.

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 on 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 while we are -- which are available in our annual report on Form 10-K for the year ended December 31, 2013, 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, including adjusted net income and adjusted EBITDA. Reconciliations of these non-GAAP financial measures to the applicable GAAP measures can be found in the earnings release that we issued last night.

Now that we have the disclosures out of the way, I'll start by saying, by all accounts, the second quarter was a great quarter for Northern. Conditions in the field were better-than-expected, and well productivity continued to improve. We talked last quarter about the breakdown of our wells in process by county, so it should be no surprise that of the wells brought online during the second quarter, over 90% of them were in the core counties of Mountrail, McKenzie, Williams and Dunn. We expect that trend to continue, given that our wells in process at the end of the quarter continue to be dominated by those same 4 core counties, which account for 91% of the current wells in process at the end of the quarter.

Second quarter production was up 17% over the first quarter of 2014, and up 41% year-over-year to approximately 15,400 barrels of oil equivalent per day. We placed into production 14.4 net wells, which brings our total producing well count to 2,037 gross, or 165.2 net wells.

Activity on our acreage remains very robust, as we spud an additional 190 gross or 13.4 net wells during the quarter. If you include the wells in process at the end of the second quarter, Northern has now participated in a total of 2,335 gross wells, which is approximately 20% of the Bakken and Three Forks wells drilled since 2006.

As we begin the third quarter, July got us off to a very solid start. We completed 4 net wells and spud another 4 point net wells, increasing our wells in-process list further to 313 gross or 23.9 net wells as of July 31.

Based on our strong second quarter results and the quality and size of the in-process well list, we are raising our 2014 production guidance to an increase of 20% to 25% over 2013 levels.

Let me take a moment to talk about capital allocation as well. Every day, we take a hard look at our capital allocation opportunities, whether it's new acreage, well proposals and AFEs or repurchasing our own stock. Over the past year, we have taken a more disciplined approach to our capital allocation decisions and we believe this is showing in our most recent results. For example, we are pleased to be able to raise our 2014 production guidance without changing our expectations for the year's net well additions, which we still expect to be approximately 44 net wells added. We continue to participate in some of the best projects in the basin and we will continue to evaluate opportunities and allocate our capital to the highest rates of return while avoiding projects that do not meet our strict internal thresholds.

We remain committed to our effective and efficient business model, and we will continue to look for ways to grow the asset base and further improve capital efficiency and returns.

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

Thomas W. Stoelk

Thanks, Mike. For the second quarter, we reported a net loss on a GAAP basis of $4.4 million, or a loss of $0.07 per diluted share. The loss was due to a noncash loss on the mark-to-market of our derivative instruments. Our adjusted net income, which excludes the net of tax impact of that noncash mark-to-market loss, was $17.3 million or $0.29 per diluted share. Our adjusted EBITDA for the second quarter totaled $81.4 million, which was up 40% as compared to the same period last year and up 24% on a sequential quarterly basis.

During the second quarter, our total production volumes were approximately 1.4 million BOE, or average 15,396 BOE per day, which was up 41% as compared to the same period last year. On a sequential quarterly basis, production volumes increased 17%. The strength of the overall financial results in this quarter was clearly driven by our increased production levels. One factor that certainly made a big difference in this quarter's production was the fact that nearly half of the completed well additions that occurred during the quarter occurred during that first month. During the second quarter, we added 14.4 net wells to production, with 6.7 of those occurring in April, which, in turn, provided a strong start to the quarter.

Oil and gas sales reached $121.2 million during the second quarter, which was a 52% increase as compared to the same period a year ago. Our average oil price differential to NYMEX WTI benchmark was $12.25 per barrel in the second quarter of 2014, as compared to $5.32 per barrel in the second quarter of 2013, and $13.42 per barrel last quarter. Our realized price per barrel of oil equivalent after reflecting our settled derivative transactions was $78.45 per BOE in the second quarter of 2014. That realized price was 4% higher than last quarter, and 2% lower when compared to the second quarter of last year.

As a result of oil price derivative activities, Northern incurred a net cash settlement loss of $11.2 million in the second quarter of 2014, compared to a loss of $499,000 in the second quarter of 2013. As a result of forward oil price changes, our mark-to-market derivative gains and losses resulted in a noncash loss of $35.3 million in the second quarter of 2014, compared to a noncash gain of $17 million in the second quarter of 2013.

Production expenses increased $1.4 million during the second quarter of 2014 as compared to last quarter, and reached $13 million. On a per-unit basis, the average production expense decreased by $0.46 per BOE from the first quarter to $9.30. We are currently estimating that production expenses on a per-unit basis will range between $9 and $9.50 per BOE during the second half of 2014.

We paid production taxes based on the amount of oil and gas natural sales before the impact of settled derivatives. Production taxes totaled $12.2 million in the second quarter of 2014, or approximately 10.1% as a percentage of oil and gas sales, which was the same percentage experienced last quarter and compares to 9.5% in the second quarter of 2013.

The company's production tax rate has trended slightly higher due to the decrease weighting of oil revenues on wells, receiving tax exceptions for a certain period of time. Upon expiration of these production tax exemptions in North Dakota, that rate will increase to a standard 11.5% statutory rate. As the mix in our production base changes, we expect our average production tax rate as a percentage of oil and gas sales will continue to trend higher throughout 2014, likely averaging in the mid-10% range during the remainder of the year.

General and administrative expenses was $4 million for the second quarter of 2014, which was essentially flat when compared to last quarter and the second quarter of last year. On a per-unit basis, our general and administrative expenses per BOE was $2.84 per BOE in the second quarter of 2014, which was $0.50 lower than last quarter and $1.11 lower than the second quarter of 2013.

Depletion, depreciation and amortization was $42.2 million in the second quarter of 2014, or $30.13 per BOE, which compares to $26 million in the second quarter of 2013, or $26.79 on a BOE basis. The depletion rate per BOE of $30.02 was determined based on our year end reserve report, and we expect that to remain at that level until we update our reserves, likely not until the fourth quarter of this year.

During the second quarter of 2014, our capital expenditures total $155.6 million. The breakdown is as follows: Approximately $137.3 million of drilling and completion capital, which includes capitalized workover expense; $16.5 million on acreage and other acquisition activities in the Williston Basin; and $1.8 million of capitalized interest and other capitalized costs.

Our first half drilling and completion capital expenditures include approximately $59 million of spending attributable to the increase in the number of our wells in process. We ended the quarter with 23.5 net wells in process, which is an 8.3 net well increase from the number of wells in process at the end of the year.

The average completed well cost for the 19 net wells placed into production during the first half of 2014 was approximately $9.5 million per well. The newer completion technologies using plug and perf and some accretive profit usage have slightly increased our well cost estimates, but perhaps more importantly, these methodologies appear to be increasing production levels. As a result of the well cost increases, we are raising our drilling and completion to capital expenditure guidance by approximately 5%.

Turning to liquidity. As of June 30, 2014, we had $198 million drawn on a revolving credit facility, which has a borrowing base of $500 million, leaving us with $302 million of borrowing availability under the revolver, with approximately $14.3 million in cash at quarter end. This company had available liquidity of approximately $316.3 million.

Including our senior notes, our total indebtedness at the end of the second quarter was approximately $707 million, and the ratio of our long-term debt to trailing 4 quarters adjusted EBITDA was 2.4x. We believe we have more than enough liquidity to handle our current backlog oils and process, and we expect our cash flows to continue to grow and keep us in a strong financial position.

We continued to layer in hedges opportunistically as the market warrants from increase of predictability of our cash flow and help maintain a strong financial position. For the remainder of 2014, we currently have hedged approximately 10,500 barrels of oil per day using swaps at an average price of just under $90 per barrel, and approximately 650 barrels of oil per day using costless collars having an average floor of $90 and an average ceiling price of $99.05 per barrel.

In 2015, we have hedged approximately 10,850 barrels of oil per day at an average swap price of approximately $89.43. For the first half of 2016, we have hedged approximately 5,000 barrels a day at an average swap price of approximately $90 per barrel.

At this time, we're going to turn the call over to the operator for Q&A. Aaron, if you could please issue the instructions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll go first to Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

I had a couple of questions. First one maybe for Mike, and then a follow-up for Tom. First, on production guidance, Mike. It looks like if you all stand still from where you were in the second quarter, you can get pretty well into your full-year guidance at this point. Is that a little bit of conservatism? Is there going to be some -- a little bit of ebb and flow in the 3Q and the 4Q? I know it can be tough to gauge quarterly production, but if you can give us a little color on that, that would be great.

Michael L. Reger

Yes, I think the way we're looking at this is that we're very comfortable at 20%, but we look forward into the second half of the year. We are factoring the potential of a rough fourth quarter from a weather standpoint, so we just want to be conservative there. If we continue to have a -- the same momentum we saw coming out of the second quarter carried through to the end of the year, we'll likely be at the high end of that range or better. So we're just -- we're going to be conservative at this point just because we don't know what the weather is going to look like in the fourth quarter, but we feel pretty good about the year as it's shaking out.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. So you guys can't predict weather yet? All right. Got it. No, I mean, that's good. I mean, that makes sense. It looks like things are going pretty well. In the second one, on the CapEx increase of about 5%, and Tom, I think this has been discussed in a variety of ways on different calls. But when you look at the first half spending for the drilling and completion and sort of that full year guidance that you had set out in addition to the 5%, it looks like there's a little bit of -- it looks like it could be running a little bit higher. Can you square the circle for that for us?

Thomas W. Stoelk

Sure. As I mentioned in my earlier remarks, our capital spending included an increase of approximately $59 million that was attributable to the investments made in the wells in processes as of June 30. That increase in the number of wells was driving the overall increase in our capital spending. And I'm going to walk you through some computations that I hope it will clarify. The bottom line is that our in-process inventory had stayed at the same levels at year end. Our CapEx spending would've been $59 million lower or approximately 213, which would have put us right at the midpoint of our beginning of the year guidance. We finished the second quarter with 23.5 net wells that we're drilling and awaiting completion, which is an increase of 8.3 net wells from the beginning of the year. Not only did the number of net wells in process inventory increased, Scott, but also the percentage of completion on those wells increased from year end to June 30. At December 31, we had 15.2 net wells that were approximately 40% complete. So we ended 2013 with a net investment in our in-process inventory of approximately 6.1 net wells. And I derived that number by multiplying the 15.2 net wells that were in process times the percentage completion amount of 40% to arrive at 6.1. At June 30, the number of net wells that were in process were 23.5, and as far the percentage complete, they were approximately 53% complete as of that date. So we ended the quarter with a net investment at the end of June of approximately 12.5 net wells, which is derived by taking the 23.5 net wells times the 53% estimated completion percentage. Now if you take the net investment in our in-process inventory at the end of June, which was 12.5, and you subtract the 6.1 net wells that we had kind of coming in at the first of the year, you're going to arrive or derive the increase in our investment in the wells that we're drilling or awaiting completion that occurred during the year. And that net increase is about 6.4 net wells. Now the weighted average cost of our in-process inventory at June 30 was approximately $9.2 million per net well. So if you multiply the $9.2 million times the 6.4 net well increase that occurred during 2014, you're going to arrive at that $59 million estimate. If our in-process inventory had stayed exactly the same as the year end levels and the percentage completion was the same, as I'd mentioned, we would have spent $59 million less and, our CapEx would have been kind of in the midpoint of our beginning of the year guidance, if that helps.

Operator

We'll go next to Steve Berman with Canaccord.

Stephen F. Berman - Canaccord Genuity, Research Division

Mike, your second quarter production beat the Street by about 1,500 BOE a day. I was wondering if you could just give us a general idea. I mean, how much of that was from better conditions out there versus your operators drilling bigger and better wells? Just a general idea there.

Michael L. Reger

So I think, generally, over the last year, we started to see a material improvement in the quality of wells being drilled across the basin. You also should factor in for Northern just a percentage of wells that we're adding to completion that are in the 4 core counties, which continues to improve as we go on. As I mentioned in my remarks that over 90% of the wells that are currently in process are in those 4 core counties, with the current awaiting, especially to Mountrail County. So you're going to see some bigger wells up in -- of the more net wells that we've added. Of the additional net wells we're adding, we're seeing some of the stronger wells come on. But I think one of the biggest factors in the second quarter was just that we really did have a -- have really good momentum from a completion standpoint. So we were able to add 14.4 net wells during the quarter. And the second quarter can be challenging. And in 2014 here, the second quarter was not challenging. So we have great momentum going into the second half of the year, and July got off to a great start. And the quality of the wells in process and the age of the wells on the drilling and completion list or the in-process list, as Tom just mentioned in his answer to Scott, was that, that age is advancing. So it looks like we're going to have a really good completion momentum in the third quarter as well. So that just gives you a little color. We saw a little bit of everything. But I think the #1 key to watch for Northern, and our -- and the winner for us going into the second half is the number of net wells in those 4 core counties and the completion momentum of that DNC list. So we're excited.

Stephen F. Berman - Canaccord Genuity, Research Division

Okay. My other question, Mike, is there's some new rules in North Dakota. I'm particularly thinking about the gas flaring rules sort of gone into effect. Now just your general thoughts there as -- how you view your operators and your -- and with a whole bunch of companies up there, how they're handling this and -- going forward here?

Michael L. Reger

Sure. We've taken a really hard look at what we're going to be participating in here going forward. I think one of the advantages that we have is just given the sheer volume or the sheer number of wells that we have that are participating in those 4 core counties is going to be really important for us, and is really important for us, especially because the majority of the infrastructure is in the 4 core counties. So the wells that we're going to be adding and the wells that we have added of recent that have real strong plush productions, they're all going to be tied in to that gas-gathering infrastructure. So we don't see any material effect going forward.

Operator

We'll take our next question from Peter Kissel with Howard Weil.

Peter Kissel - Howard Weil Incorporated, Research Division

I guess just one right off the bat, looking at the outlook, which I know you've touched on a little bit here. But looking in the third and fourth quarters, is there any particular period that you see where there could be some lumpiness to the completions? Or I guess, maybe a better way of asking it is, is there any higher-working interest pads or wells that you're exposed to coming up over the next few months that could skew production higher or lower by quarter?

Michael L. Reger

I think it's going to be fairly smooth here. If you look at the numbers we've put out for July 31, we can -- we had a strong completion list in July. We completed 4 net wells and then spud another 4.4 in July. Just the sheer number of wells, gross number of wells, I think it was 300 -- or 313 gross wells were in process at the end of July. It looks like, given the age of that DNC list, as Tom was mentioning again, it looks like they should all come on pretty ratably, which is -- which gives us a lot of confidence when it comes to our new guidance. So any quarter can be lumpy. Severe weather can affect the logistics in the field in any one month. But usually, the third quarter is our best quarter from a weather standpoint every year. And then the fourth quarter can be good as well. So it looks like it's going to be fairly smooth throughout the rest of the year.

Peter Kissel - Howard Weil Incorporated, Research Division

Okay. And I guess my next question is more for Tom. But when you think about debt levels, you're known to have plenty of liquidity in the form of borrowing base availability, so no issues there. But I'm just curious to see if there's any particular level of debt or coverage ratio that you look at that, that it kind of dictates your comfort level?

Thomas W. Stoelk

Well, I think, speaking personally, I'm comfortable with our debt levels now. I think that, for us, because our -- because we kind of continue to grow that I'd like to see our debt to trailing 4 quarters EBITDA not peak into the 3x very far, 3.1, 3.2 might be -- I'd start to get a little bit concerned with respect to it. Not overly concerned, but I'd be concerned. But that's probably a metric I'd look at quite a bit with respect to that. So -- and I think we're actually in really good shape with respect to the availability and kind of the growth in the reserve base. And as Mike mentioned in our [indiscernible], we're pretty excited about what we're seeing, kind of happening in the field, kind of where our drilling opportunities are for the second half of this year. And when you add on to it, the impact of some of the newer completion methodologies that are being adopted in the field. So we're in pretty good shape, I think.

Operator

[Operator Instructions] And we'll go next to Phillips Johnston with Capital One.

Phillips Johnston - Capital One Securities, Inc., Research Division

Just to clarify on the CapEx accounting. If we back off the $59 million of accruals off the $270 million that you reported for CapEx for the first half of the year, it's roughly $210 million. Is that the actual amount of cash that you spend on CapEx in the first half of the year?

Thomas W. Stoelk

No. You have to -- it includes accruals. So effectively our cash spend is a different amount than that. We had an accrual for drilling and completing wells at the end of December. We'll have -- we have a related accrual kind of at the end of June. It's just -- we estimate the percentage complete on the wells based on when it was spud and then based on the drilling reports and kind of the status of the well, making certain cost estimates for items that are incurred in our view, but we haven't been billed by the operators at that point in time. You really can't draw cash to -- in that number and relate them.

Phillips Johnston - Capital One Securities, Inc., Research Division

Okay. So I mean, is there an actual estimate of what you spent on cash in the first half of the year?

Thomas W. Stoelk

Yes, I don't have that in front of me. My guess is that, that would be about $40 million or $50 million lower, but I'd have to put a pencil to it.

Phillips Johnston - Capital One Securities, Inc., Research Division

Okay. And then just on the 5% increase in CapEx, does that assume that well costs continue to run at about $9.5 million? Or does it assume that they continue to sort of creep higher on a weighted average basis?

Thomas W. Stoelk

It assumes that they intend to kind of creep higher. Our kind of in-process list will kind of move around a little bit. At the end of June, it was an average well cost of $9.2 million. At the end of July, it had actually dropped into the $9 million level. So it -- we tried to use our crystal ball a little bit and kind of forecast where that development activity is going to be and the timing of those completions, but I think for the year, it'll probably average about $9.3 million, somewhere in that range.

Operator

We'll go next to Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Just a follow-up on the acreage you all picked up. It was a pretty big chunk, almost 7,000 net this quarter. Could you give a little color on that? Was is it 1 or 2 big chunks? Or was it just you're picking up a few hundred here, a few hundred there? It just seems like a pretty side to the dish. And if you can give us some color on the location? Was that kind of all core acquisitions for the most part?

Michael L. Reger

Yes, for the most part, it was some of the -- our typical wheelhouse-type activity where we were taking up smaller, call it, 80- to 200-acre transactions subject to well proposals, where we're buying AFEs. As you know, that's the power of our franchise is that we really do see a majority of the activity in the field, and we get to analyze a lot of these well proposals, and we picked up a lot of them in the second quarter. So it wasn't a big lumpy -- I don't think there was a single big lumpy transaction in there. It was all just a bunch of the -- our typical 100-acre-type stuff.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Yes, I mean, that's a pretty impressive increase. And do you sense that with -- and I know you've talked about it with operators moving back into the core, that some of the smaller-acreage holders or working interest holders, I should say, are, I guess for lack of a better term, getting run over a little bit by big AFEs. They can't handle so you can step in there. Is that what's happening, or is there something else?

Michael L. Reger

That's exactly -- and I've mentioned that on several of the previous calls. So if you take a typical well proposal that someone might receive that may or may not be able to participate in that well, if they have 10% interest in a $9 million well that -- they're going to get a cash call for $900,000. The current state of development in the Williston is that every pad is going to have approximately 4 wells on it. So instead of that land man or lease broker, whomever it might be, receiving a well proposal and a cash call for $900,000, there'll be 4 well proposals and cash calls in that same FedEx envelope, so they're going to get a bill for $3.6 million in that particular example. So we're seeing a lot of activity just because the pace of development in the field has been increasing. You could see that from some of our spud numbers from the first half. So we're seeing a lot of edge there. We're -- just given the size of our balance sheet, we're able to stand in there and continue to make a market for those types of opportunities.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, great. And one other question, too, and taking a look at the wells that have recently been completed and the stuff that's in your in-process or in your inventory right now, I mean, do you all have a sense on how much of that is actually using new completion designs? Is that something you all have some visibility on, or is it just really tough to know?

Michael L. Reger

We're starting to get more and more visibility on it. I would say that no one operator has moved exclusively to that. We're seeing different areas identified as new test areas for the new slick water and increased proppant completions. So I guess I'll take the opportunity to say this. Every one of our operators is trying it. And so that's the most exciting part about what we're seeing. And every one of our operators, when they've tried it, have found that it's been an improvement to our general returns and general EURs. The other thing that's interesting that I figure that we might get in one of the questions was the lower benches at the Three Forks activity. If you'll indulge me, I'll take your question and run with it here. One of the other things we're seeing that's really interesting is the lower benches of the Three Forks in and around southern Mountrail. We saw some really nice Whiting wells, really nice Oasis wells, and then Slawson drilled a handful of Lower Bench tests in -- on the Peninsula and southern Mountrail County. And that's very material to us because we don't -- we hadn't really accounted for a lot of Lower Bench reserves. So this is starting to delineate really nicely, and that's probably the most exciting thing that I am watching as we progress into the second half of the year. Because these wells, some of these wells -- there's an Oasis well in Mountrail County that's amazing. Slawson's Lower Bench wells are, in several cases, better than the first bench Three Forks. So we're particularly encouraged about the delineation of the lower benches. So I kind of figured out that I'd get that in the Q&A. So thanks for the follow-up question, Scott.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Yes, no worries. That's good color. And I think you all -- as we -- in your roughly 1,300 remaining well inventory, net well inventory, you assume, what, 10 wells per 12 to 18? And is that like 5 in the Bakken, 5, Three Forks? And so that lower benches are going to kind of add to that number?

Michael L. Reger

I think that's the way we're going to model it generally. However, each area is different. We're seeing some operators talking about 7 to 9 in the Middle Bakken, 4 to 7 in the first bench or the upper Three Forks. And then, I think they're generally -- some of our operating partners, you can see from some of their slide decks, they're estimating 3 to 5 in the lower benches. But the way we're going to model it now is 5 in the Bakken, 5 in the Three Forks. That's a conservative way to look at it from an inventory standpoint.

Phillips Johnston - Capital One Securities, Inc., Research Division

Understood. And if I could just tack on a little bit to my question. Slawson is a big operator of yours. Have they done slick waters? And remind me, do they do plug and perf, or do they do sliding sleeves?

Michael L. Reger

Up until recently, they had been primarily in the 36- to 40-stage sliding sleeve from a completion design. The results have been good obviously because it's some of the better rocks in the Williston there and southern Mountrail County. We have tried several wells with the increase proppant and the increased -- or the new completion designs. We have seen the results of those. There's one particular set of data that I've seen where it appeared that the 30-day rate was approximately 30% higher than the other wells that were sliding sleeve around it. So I think what we need to do now, and I'm sure what Slawson is doing at this point is breaking out the calculator, trying to determine returns versus additional cost. So -- or EURs versus additional cost. But it appears that it -- that the additional cost is going to be well worth it. So we're really encouraged by the new data.

Scott Hanold - RBC Capital Markets, LLC, Research Division

And that's just plug and perf. That's not even using slickwater, is that right?

Michael L. Reger

No, they're using the big fracs, where they're tripling the amount of sand they're putting in the wellbore.

Operator

And then we'll go next to Blaise Angelico with Iberia Capital Partners.

Blaise Matthew Angelico - Iberia Capital Partners, Research Division

Just had a quick follow-up here regarding the Bakken and Three Forks. If you look at your wells in process, can you give us a better idea of the number or percentage of which wells are Bakken versus Three Forks and also lower Three Forks?

Michael L. Reger

I would say a vast majority are Bakken. I would say -- just to handwave it, I would say 70% to 80% are Middle Bakken and the balance being Three Forks. At any given time, we're seeing a couple of dozen wells that are testing the lower benches. So it's pretty exciting. But over -- if you look at a total DNC list for us, at the end of July, it was over 300 wells. So we get to see a lot of data, but I would say 70% to 80%, probably closer to 80% is Middle Bakken.

Operator

We'll go next to Marshall Carver with Heikkinen Energy Advisors.

Marshall Carver

I had one question. The Lower Bench Three Forks sets that are -- that you said were so successful in and around your announced rail acreage, how many acres do you have in that sweet spot there?

Michael L. Reger

So I think if you look at our total Mountrail County position, it's approximately 30,000 acres last I checked. And I would say it's probably half in the South and half in the North. So I would say that southern Mountrail County right in the core there is at least 1,500 acres, just to handwave it.

Brandon R. Elliott

And Marshall, this is Brandon. I just wanted to clarify one more thing because I saw your note this morning on the percentage of the CapEx. And so to kind of carry on a little bit with Tom's math, just for your note, that if you look at those first-half completions of about 19 wells, with the map Tom gave you, that we've paid for basically an additional 6.4 net wells, that gets you to about 25.4 wells that we've paid for, which is ironically about 58% of our expected 44 net wells for the year. If you look at the drilling and capital budget that we laid out, net spend of $240 million, which includes some workover costs in there of $1 million a month, that gets you to about $234 million of DNC capital. If you take the slight increase we had in the DNC capital budget, that $234 million of the $410 million DNC budget total for the year is about 57%. So again, to kind of reemphasize Tom's math earlier, we're exactly kind of on-pace with the amount of capital we've spent year-to-date, as well as the number of wells that we've paid for year-to-date. So I hope that helps.

And Aaron, I think with that, we'll cut it off. Mike?

Michael L. Reger

Thanks, everybody. Thanks for your interest in Northern. Aaron will give you the replay information. We look forward to talking with you all next quarter.

Operator

This does conclude today's conference. We thank you for your participation.

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Source: Northern Oil and Gas' (NOG) CEO Michael Reger on Q2 2014 Results - Earnings Call Transcript

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