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Northern Oil and Gas (NYSEMKT:NOG)

Q3 2012 Earnings Call

November 08, 2012 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

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

Jean-Baptiste Jouve - RBC Capital Markets, LLC, Research Division

Peter Kissel - Howard Weil Incorporated, Research Division

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

Operator

Good day, and welcome to the Northern Oil and Gas Incorporated Third Quarter 2012 Earnings Release Conference Call. Today's conference is being recorded. At this time, I would like to turn the call over to Mr. Michael Reger. Please go ahead.

Michael L. Reger

Good morning, my name is Michael Reger. I'm the Chairman and Chief Executive Officer of Northern Oil and Gas. Also with me today is Tom Stoelk, our Chief Financial Officer. We're happy to welcome you to the 2012 third quarter earnings call for Northern Oil and Gas.

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 we most recently updated in our Form 10-Q that we 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 this morning.

Third quarter of 2012 was another record quarter for us in terms of production, oil and gas sales, and adjusted EBITDA. Northern Oil third quarter production was up 96% compared to the same period last year. Our total production for the quarter was 1,038,000 barrels of oil equivalent or BOE, and our average daily production for the quarter was approximately 11,300 BOE. During the quarter, we added 149 gross, 10.9 net wells to our production base, as drilling and completion activity remain strong in North Dakota and Montana. Through the first 9 months of 2012, the total number of wells completed and added to our production base was 440 gross or 40.6 net wells. That raised our total producing wells as of the end of the third quarter to 1,104 gross wells or 98.5 net wells. In addition, we have participated in approximately 32.7 net wells that were spud during the first 9 months of 2012, which leads us on track to spud approximately 44 net wells for the year as previously estimated.

We have also continued to grow our acreage position, which is as of September 30, 2012, stands at approximately 184,000 net acres in the Williston basin. During the third quarter of 2012, we acquired leasehold interest covering 3,815 net acres for an average cost of just over $2,000 per acre. We have approximately 114,000 net acres, either developed, held by production, held by operations or permitted in the Williston basin. That represents 62% of our total acreage position. Also 72% of our total North Dakota acreage position was developed, held by production, held by operations or permitted at the end of the third quarter. And we expect very limited acreage expirations throughout the remainder of 2012.

At this point, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss that some financial highlights from the third quarter.

Thomas W. Stoelk

Thanks, Mike. This morning, we reported GAAP net income of $300,000 for the third quarter, however, this included a $13.4 million unrealized non-cash loss on mark-to-market derivative instruments net of tax, and $3 million of severance charges net of tax in connection with the departure of our former President. Excluding these items, we reported adjusted net income of $16.7 million or $0.27 per diluted share. As Mike mentioned, our earnings release includes a reconciliation of the non-GAAP numbers to net income and net income per share.

We continue to see strong cash flow growth in the third quarter. We reported adjusted EBITDA of $63.1 million for the third quarter, that's a 98% year-over-year increase compared to the third quarter of 2011, and is a 19% sequential increase when compared to the second quarter of this year. Adjusted EBITDA growth in the third quarter 2012 was compared to the second quarter 2012, was fueled by increased production levels and higher realized prices per BOE.

During the third quarter of 2012, oil and gas sales including derivative settlements reached $82.4 million, that represents a 97% year-over-year increase compared to the third quarter of 2011, and a $13 million or 19% higher on a sequential quarter-over-quarter basis.

Comparing the third quarter of 2012 versus the third quarter of 2011, oil and gas sales growth was driven by a 96% increase in production. Realized pricing for the third quarter 2012 including a $1.7 million gained from settled derivatives was $79.38 per BOE. That's up just $0.16 from a year ago. Compared to last quarter, realized pricing increased $6.19 per BOE or 8%. In addition to realized hedging gains during the quarter, the sequential quarter improvement of realized pricing was driven by a drop in Bakken crude oil differentials. Comparing the second quarter of 2012 to the third quarter of 2012, the average oil differentials declined by $3.54 and averaged $10.18 per barrel of oil equivalent. We remain highly oil-weighted with 92% of oil production being crude oil during the third quarter.

The third quarter of 2012, we had an unrealized non-cash loss from derivative instruments of $22.3 million. That compares to 27.1 unrealized non-cash gain in the third quarter of 2011, and a $49.8 million unrealized non-cash gain in the second quarter of 2012. Total production expenses per barrel of oil equivalent were $8.42 in the third quarter of 2012, as compared to $7.40 in the third quarter of 2011, and $70.70 in the second quarter of 2012. On a per unit basis, production expenses were higher in the third quarter of 2012 compared to both the third quarter of '11 and the second quarter of 2012, primarily due to a rise in production enhancing workover activities, as well as higher saltwater disposal expenses.

Total production taxes per BOE were $7.80 in the third quarter of 2012, as compared to $8.07 in the third quarter of 2011, and $7.03 in the second quarter of 2012. As a percentage of oil and gas sales, production taxes were 10% during the third quarter of 2012, as compared to 9.8% in the third quarter of last year, and 9.5% during the second quarter of 2012. The third quarter of 2012's average production tax rate was slightly higher from the third quarter of 2011 and the second quarter of 2012 due to greater levels of production that didn't qualify for reduced rates or tax exemptions during 2012. Some of these tax exemptions are temporary or for a certain period of time or until we reach a volumetric threshold, at which point they return to North Dakota's standard 11.5% rate.

General and administrative expenses were $9.5 million for the third quarter of 2012, which was up from $4.1 million in the third quarter of 2011, and $4.4 million from last quarter. Vast majority of the year-over-year increase is due to a $4.9 million severance charge in connection with the departure of our former President, of which $4.3 million is in the form of noncash share-based compensation expense. Generally accepted accounting principles required us to recognize the entire cost of the separation agreement during the third quarter of 2012. The remaining portion of the year-over-year increase is primarily a result of increased staffing throughout the company to support our growth.

Our depletion expense per BOE during the third quarter of 2012 was $26.93, that's the same rate as it was last quarter, but an increase over the 2011 third quarter rate of $20.34 per BOE. The year-over-year increase in depletion expense per BOE is due to an increase in our future development and operating cost estimates, as well as an increase in the depletable base as additional unproved properties are proved up and become subject to depletion.

Interest expense, net of capitalized interest, was $5.2 million for the third quarter of 2012, which compares to $200,000 in the third quarter of 2011. The increase in interest expense is due to higher level of borrowings in 2012, including $300 million of 8% senior notes we issued in May of 2012. During the third quarter, we expanded our borrowing base under our revolving credit facility to $350 million, of which $68 million was outstanding at quarter end. That left $282 million of borrowing capacity under this facility, together with an additional $8.2 million of cash on hand at the end of the second quarter and this should provide us with the necessary liquidity to fund our planned capital expenditures.

The ratio of our trailing 4 quarters EBITDA over our total debt was 1.95 -- 1.9x at September 30, 2012. During the third quarter of 2012, we spent approximately $119 million on oil and gas expenditures. Approximately $109 million of these related to drilling and completion expenditures. We continue to layer in hedges opportunistically as the market warrants to increase the predictability of our cash flow and help maintain a strong financial position. For the fourth quarter of 2012, we currently have hedged 563,000 barrels under swap agreements at a weighted average price of $93.66, and approximately 384,000 additional barrels under costless collars with an average floor of $91.20, and average ceiling price of $105.93 per barrel.

For 2013, we currently have hedged 960,000 barrels under swap agreements at a weighted average price of $91.86, and approximately $2.2 million additional barrels under cost of collars with an average 2003 (sic) [ 2013 ] floor price of $90.01 per barrel and an average 2013 ceiling price and $104.17 per barrel. For 2013, we've hedged approximately 1.7 million barrels under swap agreements at a weighted average price of $91.92 per barrel, and approximately 240,000 additional barrels using costless collars with an average 2014 floor price of $90 per barrel and an average 2014 ceiling price of $99.05 per barrel. We'll continue to look for opportunities to increase those hedging levels, but we feel we've established some attractive base levels at this point.

At this point, I'd like to turn the call back to Mike, to discuss some recent trends in the Williston Basin.

Michael L. Reger

Thanks, Tom. We're seeing some nice trends in the field today. As a number of our operating partners have mentioned, drilling and completion costs are expected to trend lower throughout the fourth quarter and into 2013, primarily due to service availability and increased efficiencies. These improvements have shortened spud to sales times as well. Also due to additional infrastructure in the Williston basin, takeaway capacity remains very healthy right now and the differential have tightened since earlier in the year. All of this bodes extremely well for a non-operated business model. Infill drilling and down-spacing activity on our leasehold position has been increasing. And so far, the results have been promising. In recent press releases and conference calls, many of our operating partners have stated their intentions to dedicate a significant portion of their rigs to multi-well pad drilling and begin a robust infill development program.

At this point, I'd like to turn the call back to the operator to begin the question-and-answer session and provide more color on our quarter.

Question-and-Answer Session

Operator

[Operator Instructions] We'll take our first question from Ryan Oatman with SunTrust.

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

Given the financial strength and flexibility you guys have, what are your thoughts on taking your working interest higher than that typical 5% to 10% in areas?

Michael L. Reger

Well, I think, it just -- it comes down to the mix of the operator base that we're targeting. We've been in that -- for the last 5 years or so, we've been in about the 6% to 12% range for average working interest. At given times, it moves throughout that range. We expect that our percentage to increase here, as we move to the end of this year and into 2013, primarily due to the fact that Slawson Exploration specifically is going to move 2 rigs back into the southern Montrail peninsula, we call it, or loop, or Windsor area, depending on what you want to call it. And then at the beginning of 2013, he's going to move a third rig into there. That's where our working interest is significantly higher, where we're looking at wells -- or looking at average working interest in the 20% range. That will increase our percentage going to 2013, which is really exciting for us, that's the beginning of the infill and down-spacing for Slawson in that southern Montrail County loop area. As we continue to buy additional working interest, they come in various forms obviously, but we just target specific areas, specific acreage, specific drilling partners and it may come in the neighborhood of 5%, it may come in the neighborhood over 20%, but we just -- we buy the attractive acreage as we see it. And we don't make any specific decisions relative to size.

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

Okay, that's helpful. And I mean, it sounds like working interest will kind of increase next year, especially in more efficient areas. I mean, do you see the chance for sort of a corporate-wide efficiency to increase next year and then just thoughts on activity levels as well? Looks like it's been pretty steady at around 10 or 11 net wells per quarter, based on this working interest, all these moving parts, do you see that number moving higher as well?

Michael L. Reger

Thanks for that question. That's what we expect in 2013 for basically the field to remain the same from a rig count standpoint, maybe a slight increase in rig count. However the rigs, as you know, are getting more efficient and the drilling times or number of days that takes to drill a well is just decreasing across all of our operator base. And so I think next year, with all things remaining equal, with a similar number of rigs, we expect to drill 4 net wells and if you think that we're going to drill a similar number of wells, 44 net wells or maybe let's say a 10% increase potentially next year as efficiencies increase, with the same number of rigs, we also expect to see a subsequent decline in overall drilling and completion cost by at least 10%. So we think it's going to -- we think activities going to remain very predictable as we go. One other thing, if you'll indulge me, that I'll highlight here, is that a number of net wells that Northern is adding is no longer lumpy. Our drilling and completion list or if we spud roughly 150 gross, 10 to 12 net each quarter. We're going to be completing a similar number of growth in net wells. So as we go forward, 2013 is going to be far more predictable from a cash flow and CapEx standpoint than 2012, because the spud to sales times have now compressed to less than 90 days. So it's more of a predictable turnover on a quarter-by-quarter basis. So the activity we think will remain the same, we think efficiencies may actually increase our net wells throughout 2013, given the same number of rigs and all things remain equal. But efficiencies and costs are also going to be on our side as well. So thanks for that question.

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

Very helpful. And then just one more if I may. 2013 guidance, when do you guys plan to communicate that?

Michael L. Reger

We're currently in the process of preparing our 2013 capital spending budget. Since it hasn't been presented or approved by our Board, we don't have anything to share really at this time. Once that is completed, then you'll see us going to come out with some guidance. It probably is -- we haven't formalized it so it's a little tough to kind of give you a date but it will be after the first year, I would think.

Operator

We'll take our next question from JB Jouve with RBC Capital Markets.

Jean-Baptiste Jouve - RBC Capital Markets, LLC, Research Division

I had a follow-up about the previous question. And in particular, with regards to pad drilling you mentioned earlier, and I guess this pattern goes hand-in-hand with the quantity of acreage that is now HBP. What kind of impact do you see from that pad drilling to your next activity? Does it affect your ability to seek your interest in new wells or does it do anything at all?

Michael L. Reger

What it will do is it could potentially, because of that particular efficiency, and not having to move rigs around the field, we actually think that could be an increase from a net wells standpoint but we also think that we'll have a corresponding and more potent cost efficiency benefit to Northern. We think that, that could if they're drilling a Bakken and Three Forks well in the same unit where we have the same obvious corresponding working interest, that could increase our efficiency and it could increase the number of net wells but we think that if we do add more net wells in 2013 than we do -- than we have here in 2012, then we think the corresponding efficiency and cost benefit is going to be better. The one thing that would potentially have an impact, that I would say very minimal, is that when multi- well pads are utilized, they will likely drill all 2, 3, 4 or more wells on that pad before they frac all the wells at the same time as well. So because of the number of net wells that we have, that won't necessarily create lumpy production where it all comes on at one-time. But the first, second and third well on a 4-well pad would clearly be awaiting frac while the fourth well is being drilled. And once they're all drilled, then we'll frac all those wells. But the smoothing effect of the sheer number of growth in net wells that we are participating in, we don't see that as presenting any lumpiness, if you will, for our production base.

Jean-Baptiste Jouve - RBC Capital Markets, LLC, Research Division

Okay. And then another one if I may. What are you currently seeing in the basin regarding interest structure and in particular gas infrastructure?

Michael L. Reger

We think that in the areas that we're participating in and if you're familiar with our asset base, we are heavily weighted to the Nesson Anticline and east of the Nesson Anticline. So we've been benefiting from infrastructure that's been being developed since 2006, and even earlier than that. Our field as a whole, there's new areas that are being developed by some operators but most of our acreage, as you know, is in fairly tight to the core of the play. And so we're benefiting from maybe infrastructure that's further along in the process. Gas is being hooked up. Our wells, for the most part, that's not a big issue for us. From time to time, we will have a certain percentage of our gas being flared but that percentage for us is, we think, good and will continue to increase just like all of our operating partners have indicated as well. I'll add some other color since you mentioned infrastructure. Water gathering, water disposal, that's really going to be the big driver of cost reductions going forward because water has been -- water disposal has been an issue for the entire basin. So we think that the increase in infrastructure there is important. Currently, the rails, take a crew by rail takeaway, my understanding is well over 50% of the takeaway in the field right now. That bodes very well for differential. So takeaway remains healthy. So that kind of infrastructure has been very beneficial to play as a whole. And in particular, those types of -- that additional infrastructure bodes very well for our non-operated model.

Operator

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

Peter Kissel - Howard Weil Incorporated, Research Division

I was wondering if you could please comment on some of the management changes that have occurred over the last few weeks. I mean, are we looking at more a change in strategy or cost-saving measure or really just anything you care to mention on that would certainly be helpful?

Michael L. Reger

Sure, Thanks, Pete. We've covered a lot of this in the different press releases, but I'll just give you some color here right from me. As you know, Ryan Gilbertson co-founded Northern with me. Ryan and I has been essentially paid as co-CEOs since inception, with identical salaries, identical bonuses, et cetera. Ryan's primary strengths were the capital markets. And as you also know, most of our capital markets activities are now behind us as we get closer to cash flow positive. The Board and the management team, and Ryan for that matter, determined that Northern no longer needed to pay 2 CEOs. We feel great about our current team and these decisions position the company for a very profitable 2013. Given our expected production ramp and the associated hedge profile that goes along with that. So this has been more of a streamlining effort than anything.

Operator

And we'll take our next question from Marshall Carver with Capital One South Coast.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

A couple of questions. On the -- so it looks like you've spent about $110 million on drilling and completions in the quarter. If I take that, divide that by the 11 wells completed and spud, it works out to about $10 million a well. You talked about well cost dropping, should that really impact the fourth quarter? It doesn't look like it hit the third quarter yet. So if you could you help me with the direction on well costs for 4Q and your thoughts around the full year budget slight outspend in the third quarter?

Thomas W. Stoelk

One thing I wouldn't do is I wouldn't divide our current quarter spend by the number of wells that we put into production because part of that spend is related to the wells that are awaiting completion and at the end of the quarter, we had little over 10 wells that were kind of awaiting completion so that's kind of an apples to oranges sort of comparison. And it's going to skew your statistics and they're not really going to be representative of kind of what we're seeing. Kind of the current costs are starting to come down. They've been slight so far. As a non-operator, we're 60 to 90 days kind of behind in the billing cycle from our operators. Effectively, at the end of the third quarter, we had about $8.7 million average well cost for the wells that our estimates for the wells that were kind of awaiting completion. That's down just slightly. It's down about $100,000. We're starting to see a lot of estimates on our current levels of activity kind of filter in, and those are more in the neighborhood of the 5% to 10% reductions. We're hearing a lot of our operating partners continue to talk 10% or in excess of 10%, and we're starting to see that kind of bleed in, if you will. Our capital budget remains the same at $387 million for drilling costs for 2012 spuds, and about $50 million for acreage. Through September 30, we've incurred approximately $225 million of that $387 million of drilling costs related to the wells that we spud in 2012. We think we've got about $162 million to go. But when I say that, one of the things you need to kind of keep in mind is even -- we may spud wells in December, we won't receive or pay for those expenditures, so there will be a little bit of lap over into 2000 -- or into the next year rather, if you will. So I think the spending level for the fourth quarter, similar, maybe slightly higher. It's going to depend on the pace of activity, holiday shutdowns, possibly a little bit of weather and such. But I wouldn't look for necessarily a really big bump in our fourth quarter CapEx is kind of my view on it.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay. And a question on more and more of your acreage is getting held by production and you probably have a -- with such a good survey of -- participating in so many wells in the Bakken, would you -- it seems like in the past, you've elected to participate in every well that gets AFE-ed to you, do you plan to change that going forward and being more focused on just what you consider the better areas to be or what are your thoughts on that, and would that happen next year, would that happen in 2014 or would that never happen?

Michael L. Reger

Well, I think the -- this is Mike, I think the question or the answer to your question is we'll elect to any well that pencils out. And when we look at buying acreage, we run the math on the well essentially when we acquire the acreage, it's not a -- this is no longer an exploratory business, if you will, this is predominantly just developments and most of our acreage is exploratory. We would consider non-consenting a well if the well costs are abnormally high for a particular operator relative to a particular area. However, we usually make the decision to participate in these wells when we buy the acreage. So as you well know, the acreage that we have as well would delineate within the high-quality productive area of the field, unless there's some unusual costs issue related to a particular well we intend to participate.

Thomas W. Stoelk

Just maybe a couple additive comments to that. One of your questions, I've understood it was whether we're non-consenting on wells and actually we're already in the process of doing that. We perform kind of an internal rate of return analysis with respect to the well proposals that kind of come in. Look at the areas, look at the offsetting production as part of our analysis. Over the last 2 quarters, a rough estimate is probably 10 gross wells that were proposed to us, we non-consented on probably about 1 net -- I mean, generally. So that already happens, if I understood the question right.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Yes, okay. And just one last question. So that $119 million spent in the third quarter, that's got to be what shows up in the 10-Q as the cash flow from investing?

Thomas W. Stoelk

Yes. It's going to show up as the net change between gross oil and gas properties in the 10-Q, which you can reconcile to your cash flow statement. That's correct.

Operator

[Operator Instructions] We'll take our next question from Curtis Trimble with Global Hunter Securities.

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

Just wanted to kind of stress your database here a little bit and see if I can an idea of the incremental level of detail that you guys collect. Can you tell me the number as a percentage of AFEs that are infill drilling that you received over the last 6 weeks, month, and/or the number that maybe are looking at down-spacing and/or looking at testing deeper benches of the Three Forks, et cetera?

Michael L. Reger

Thanks for that question. In taking a look at that data, our entire -- from our entire PDP well base essentially, less than 20% of the wells, net wells that we have in our PDP base are infill wells or down-spaced wells, second wells in each unit. And our current -- going forward, that number is going to be obviously increasing. And as we get into 2013, we expect the number of net wells that we add to be under 50% from an infill standpoint because the field is still in the process of holding acreage. And as we begin to -- as we fully develop our acreage position and as our held by production acreage percentage gets closer and closer to 100%, the wells that will be drilled will be obviously closer -- will be closer and closer to 100% infill. And what's important to note there is that over the past 6 or 7 years in the Bakken, specifically in North Dakota, as the wells have been drilled, the decisions have been made not just on economics but have also been made for the purpose of holding acreage, and holding blocks of acreage. But going forward, and really starting now as we'll start to get, in 2013, as we'll start to get closer and closer to 100% held by production and the number of net wells that we add which are infill wells will cross above 50% and so on. The decisions to drill these wells will be made purely on economic -- on an economic basis. And in addition to that, the design in the Bakken, as you know, from all of the operating partners that we participate with, that the optimal design appears to be pad drilling and so the efficiencies and speed at which we develop this acreage from an infill standpoint will increase and the economics will increase. And it will further magnify the returns that we're seeing in this premier oil resource play. So that kind of breaks down the data as we have it in front of us. But it's pretty simple math, when we're 100% held by production, it's going to be 100% infill drilling on our acreage position. And so our inventory there is substantial. We believe we've only developed about 10% of our total net wells if you include infill drilling and just assume 3 wells to the Bakken, and 3 wells to the Three Forks. So we have a lot of inventory and as we get here closer to 100% held by production, it's going to be all just burning through that inventory of infill drilling. And those decisions, as I mentioned earlier, will be made primarily on economic basis.

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

Sure. And taking that one level lower, can you sort of soft circle a number in terms of cost savings are you're seeing recent AFEs for pad drilling, for infill vis-a-vis, others, wells that are simply looking to HBP?

Michael L. Reger

Sure. I think we get our data essentially real-time from our operating partners, the same way that the market gets their data from the different operators in the Bakken. Several of our operators have mentioned, 20% to 30% decreases in total drilling and completion costs. Northern, we have a particularly good set of data in that when we load a new well proposal or AFE into our system, when it becomes permitted and we receive the well proposal and the AFE, and then as it gets -- once it's spud, it moves into our -- we call it our drilling and completion list, which is wells drilling, completing or awaiting completion. We know the AFE costs, the AFE estimate on the bottom right-hand corner of that AFE, we load that into our system. So we can always take a snapshot of roughly 150 wells that we're participating at any time. And that number has been decreasing. Currently, as it sits, it's at $8.7 million for every well that we have in our list of the roughly 150 or so that we're drilling. That's down from about a month and a half ago, which was $8.8 million. We expect that to go down further. I think the easy answer to your infill drilling standpoint is it varies throughout the operator set -- our operator set. Pad drilling, based on what our operators are telling us and what we're seeing, saves somewhere in the neighborhood of, on a per well basis, the per gross well basis, it saves anywhere from 300,000 to 500,000. We think that efficiency will continue to show itself as we start to develop the field from more of an infill standpoint once we get all this acreage held by production here over the next 18, 24 months. And as it gets more and more efficient, then these -- and the wells decisions are based on economics, this number is going to go down, we believe.

Operator

And that concludes today's Q&A session. I'll turn it back to our speakers for any closing remarks.

Michael L. Reger

Thank you, all, for your interest in Northern Oil and Gas. We look forward to a very successful fourth quarter and 2013. Thanks a lot. Have a good day.

Operator

That concludes today's conference call. We appreciate your participation.

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