Northern Oil and Gas Inc (NOG) 2012 Q4 法說會逐字稿

Good day, everyone, and welcome to the Northern Oil and Gas fourth quarter and full-year 2012 earnings release conference. Today's call is being recorded. At this time, I would like to turn the conference over to Mr. Michael Reger. Please go ahead, sir.

Thank you, Kim. Good morning, ladies and gentlemen. This is Mike. We're happy to welcome you to the 2012 year-end earnings call for Northern Oil and Gas. Also with me today is Tom Stoelk, our Chief Financial Officer, who will discuss our financial highlights from 2012, and Brandon Elliott, our Executive Vice President of Corporate Development and Strategy, who will discuss the opportunities we are seeing in 2013.

Before we begin this morning's call, you should be aware that certain statements made during the 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 on our annual report on Form 10-K for the fiscal year ended December 31, 2012 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 the non-GAAP financial measures to the applicable GAAP measures can be found in the earnings release that we put out last night.

As I mentioned in the earnings release last night, 2012 was a transformational year for the Williston Basin. Drilling costs abated throughout the year, as oil field services became more plentiful. Wellhead oil price differentials ended the year at some of the best levels we have seen since the play began, and multi-well pad drilling is becoming the norm as opposed to the exception. During this transition, Northern was also able to grow the Company's production in 2012 by 95% over 2011, and grow adjusted EBITDA in 2012 by 101% over 2011, while also improving capital efficiency throughout the year. Also, drilling pace at the end of 2012 was robust, with North Dakota well spuds at an all-time high in December. A combination of this high activity and the operational efficiencies I just highlighted should position Northern for a very exciting 2013.

With that, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss some financial highlights; and then he will turn the call over to Brandon Elliott to discuss value and the 2013 opportunities.

Thanks, Mike. Northern's 2012 production increased 95% compared to 2011. We produced approximately 3.8 million barrels of oil equivalent, or BOE, for the year. Our sequential quarter-over-quarter production on a BOE basis declined 4%, with fourth quarter production averaging approximately 10,900 barrels per day. As we discussed in our operations release on February 11, fourth quarter production was affected by a confluence of events, including weather, lower average working interest in completed wells during the fourth quarter, and a dip in North Dakota's Bakken production during November.

Having said that, 2012 was obviously a record year for Northern in terms of production, net well additions and proved reserves. During the year, we had added 563 gross, 48.3 net wells to production, bringing our total producing wells to 1,227 gross or 106.2 net wells. We reported net GAAP net income of $72.3 million, or $1.15 per diluted share, for 2012. Excluding the net of tax impact of the non-cash gain on derivatives and certain severance expenses, we reported adjusted net income of $66.2 million, $1.05 per diluted share. Our earnings release includes a reconciliation of these non-GAAP numbers to net income and net income per share.

We continue to see strong cash flow growth in 2012. We reported adjusted EBITDA of $225.3 million for 2012, a 101% increase compared to 2011. Adjusted EBITDA growth for the year was fueled by strong production growth and higher realized prices.

Production expenses were $32.4 million in 2012, as compared to $13 million in 2011. The aggregate increased production expenses was primarily due to well additions and the maintenance production on existing properties. On a per-unit basis, the average production expenses per BOE increased from $6.77 per barrel sold in 2011 to $8.61 in 2012. The year-over-year increase in the per-unit basis is primarily due to increased costs associated with water hauling and disposal, and servicing expenses. Production expenses are generally higher during a well's first year of operations, due to higher level of well servicing additions. We had a significant number of well additions during 2012.

We pay production taxes based on realized oil and gas natural gas sales. These costs totalled $28.5 million in 2012, compared to $14.3 million in 2011. Average production tax rates were 9.6% and 9%, in 2012 and 2011, respectively. The 2012 average production rate was slightly higher than the 2011 rate, due to fewer wells that qualify for reduced rates or tax exemptions during 2012.

General and administrative expenses was $22.6 million for 2012, compared to $13.6 million in 2011. The increase in general and administrative expenses when compared to 2011 was primarily due to a $5.5 million severance charge in connection with the departure of our Company's former President and the Chief Operating Officer, as well as higher personnel costs that we've incurred as we continue to invest in our technical operational staff to support our growth.

Completion depreciation and amortization accretion was $98.9 million in 2012, compared to $41.2 million in 2011. The increase in aggregate DD&A expense for 2012 compared to 2011 was driven by a 95% increase in production and higher depletion rates. Depletion expense, which is the largest component of DD&A, averaged $26.18 per BOE in 2012. That compares to $21.20 per BOE in 2011. Depletion rates rose in 2012 due to increased future development cost and production expense estimates. Based on our year-end reserve engineering, our fourth quarter depletion rates declined by $0.27 per BOE, to $26.66.

The provision for income taxes was $43 million in 2012, compared to $26.8 million in 2011. The effective tax rate in 2012 was 37.3%, compared to an effective tax rate of 39.8% in 2011. The decrease in our 2012 effective tax rate compared to 2011 was really due to lower state tax rates.

During 2012, Northern's acquisition development expenditures included approximate $485 million of drilling, completion and capitalized work over expenses, $8.5 million of capitalized internal costs, and $5.9 million of capitalized interest. Our drilling and completion expenditures were heavily weighted to the first half of 2012, as operators continued to work through the backlog of wells awaiting completion at the end of 2011. Also in 2012, approximately $37 million was extended on acreage acquisitions and other acreage-related costs located in the Williston Basin. During the fourth quarter of 2012, capital expenditure spending totaled $85.9 million, with approximately $4 million of that amount related to acreage acquisitions. As of December 31, 2012 Northern controlled approximately 179,131 net acres targeting the Williston Basin, Bakken and Three Forks formations. In 2012, Northern acquired leasehold interests aggregating approximately 17,590 net mineral acres in its chief prospect areas at an average acreage cost of $1,788 per net acre, and earned an additional 6,450 net acres through farm-in arrangements. In the fourth quarter of 2012, Northern acquired leasehold interests covering an aggregate of approximately 3,404 net mineral acres in its chief prospect areas, at an average cost of approximately $1,082 per net acre.

As of December 31, 2012, approximately 64% of Northern's total acreage position and approximately 72% of Northern's North Dakota acreage position was developed, held by production, held by operations, or permitted. In 2012, we spud approximately 42.8 net wells, which brought our full-year net wells added to production to 48.3. Our total proved reserves at December 31, 2012, as estimated by Ryder Scott, was approximately 67.6 million BOE, which represents a 44% increase as compared to 46.8 million BOE at December 31, 2011. Approximately 45% of our total proved reserves at December 31, 2012 are categorized as proved developed. The PV value of our proved reserves in 2012 reached $1.3 billion, and approximately $835 million of that PV10 was improved developed properties.

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. Currently, we have hedged approximately 9 million barrels of oil per day in 2013. Approximately two-thirds of the 2013 hedges are in the form of costless collars with an average floor price of $90.08 and an average ceiling price of $104.07 per barrel. The 2013 crude oil swaps averaged $92.16 per barrel. In 2014, we have approximately 6,800 barrels of oil hedged per day. The majority of the 2014 hedges are crude oil swaps, with an average price of $91.73 per barrel. Just under 10% of our 2014 hedges are in costless collars, with an average floor price of $90.00 and a ceiling price of $99.05. We also have approximately 180,000 barrels hedged in 2015, at an average price of $90.50 per barrel.

At this point, I'd like to turn the call over to Brandon Elliott to discuss 2013 opportunities.

Thanks, Tom. As Mike mentioned in his opening remarks, the Williston Basin was in transition in 2012. And with that transition, we experienced some challenges. The push to hold acreage by production and the constrained availability of oil field services in the second half of 2011 and the first half of 2012 caused some bumps in the road. But as we look to 2013, some of these challenges represent opportunities.

Held by production percentages are approaching levels where the worry over acreage exploration is declining for many operators. With that, the basin is beginning the transition back to the core and a more developmental drilling approach. As Mike mentioned, multi-well pad drilling has become the norm, as we enter 2013. This, combined with much greater availability of oil field services and substantially improved infrastructure, should help drive costs down. We have already begun to see this, as the AFE cost overruns we experienced in the first half of 2012 have abated. As we indicated in our press release, we expect drilling and completion costs to average between $8.4 million and $8.8 million per well for the year, with the costs likely approaching $8 million per well by year-end.

Spud to sales times have also been in decline and are now at approximately 90 days for the basin. As a result, we expect our capital budgeting predictability to improve. Assuming we spud approximately 44 net wells during the year, and the costs and capital budgets we have laid out to you today, we initiated 2013 production guidance in a range between 4.7 million and 5 million barrels BOE, which would reflect growth of approximately 25% to 33%. As of December 31, 2012, Northern was participating in 157 gross, or 12.4 net, wells that were either drilling or in the completion process. The average AFE drilling and completion costs on these wells was approximately $8.4 million.

Given our liquidity position, Northern should benefit greatly from the increase in drilling activity we saw at the end of 2012. Based on our January drilling and completions list, that activity looks to be continuing into 2013. In addition our largest operator has three rigs operating on the Peninsula in southern Montrail County, and expects to continue infill drilling through the remainder of 2013. This area has been one of Northern's main drivers of production growth in the past, and the return to the Peninsula will contribute to our growth profile in 2013. We expect the benefits from pad drilling both in production and in costs that I have laid out to be a trend throughout the year; and hence, we expect the benefits to become more visible in the back half of 2013.

So clearly, 2013 is another growth year for Northern. We plan to deliver this growth while maintaining a strong liquidity profile, with production that is adequately hedged in the $90 range. We will continue to exercise capital discipline through our strategic capital efficiency effort. However, the number of wells we non consent will likely decline when compared with the second half of 2012, given the completion costs and AFE's we are currently e experiencing. With this, we expect to continue to execute and fund our growth plans in 2013 through cash flow and borrowings on our revolving credit facility. Said plainly, we do not plan to use new equity as a way to fund the growth we are projecting.

Let me say a few things about valuation. On an enterprise value to 2013 EBITDA estimates, we believe we look relatively cheap versus our pure play peers, with our valuation standing, as of last night's close, at 4.4 times, almost a full point discount to our peers. On a PV10 basis, our equity value is approximately equal to the current PV10 value of our proved developed reserves only. Also, there was a comparable asset sale in 2012 on a large non-op package in the Williston Basin, that if you applied some of the rumored valuation parameters of that deal, it would value Northern at 50% more than our enterprise value today.

With our business plan and growth projections, we believe 2013 is setting up to be an exciting year for Northern. We remain in a very active, oil-rich basin where costs are declining and profitability is on the rise. We enter 2013 with a very strong liquidity position. We look forward to seeing many of you on the road over the next several weeks during the upcoming conference season, and we look forward to sharing our value proposition with you at that time.

At this time, we will turn the call over to the operator for Q&A. Kim, if you could please give the instructions for the Q&A process and open the call for Q&A, that would be great.

Thank you.

(Operator Instructions)

Ryan Oatman, SunTrust.

With shares trading near that PV10 value, can you talk about the assumptions you used to create that estimate, whether they be well costs, EURs, number of wells per year, et cetera?

Hello, Ryan. This is Brandon. A couple of numbers that are in there -- I think 1,214 PDPs as of the end of the year, with 488,000 average EURs. And basically, the average well numbers that we gave you, 44 net wells for the year.

Okay. Very good. That's helpful. And then, we also recently saw the announcement of the first-ever acquisition of a public C Corp by an upstream MLC or LLP. In the past, you guys have kicked around the idea of converting into an MLP structure. Can you refresh us on the prior rationale there for and against conversion, the pros and the cons there? Then follow-up question. With shares where they are, is that idea now back on the table?

With respect to the valuation, currently -- and Ryan, this is Mike -- and the question about MLPs. As we announced last August, we've shelved any possibility of an MLP for now, until our production profile matures and becomes more appropriate for that structure, as we continue to analyze all options to increase shareholder value, though.

Okay. Appreciate it. And moving on to 2013 guidance here, what sort of average Bakken well assumptions are you looking at, or are you looking at specific locations versus last year, with activity looking like it's trending towards some of these higher productivity areas, whether they be South of Elm Cooley or the Peninsula or Tarpon, is this -- does guidance reflect that potential for productivity to improve, or does it more look at how the 2012 well results trended?

One thing that's going to be different about 2013 that was different than 2012 is that the rigs are now present again in southern Montrail County, which is where Northern has generated a lot of its production growth over the last few years. That acreage, over the course of 2011, became, for the most part, held by production. And just in late 2012, we started to see the Slawson and EGO rigs return to southern Montrail. Specifically, Slawson has three rigs drilling on the Peninsula right now, where Northern has a fairly significant working interest. So I would say, generally speaking, the mix of wells that are going to be developed in 2013 will be better, on the whole, than the wells developed in 2012, as the rigs start moving back into the core for more development and infill drilling.

Great. I appreciate it. That's it for me, guys. Thank you.

Scott Hanold, RBC Capital.

Just to follow-up on that question on 2013 guidance, obviously it does look pretty good coming in close to 30%. And outside of Slawson in the Peninsula, what is your confidence level, what are you seeing from some of your other operating partners, as they move to development? How do you get a confidence, as a non-operator, over the next couple years in what they're going to do and how that translates into growth for Northern?

Scott, this is Mike. Thanks for the question. The way that we look at it is, from a development standpoint, based on the rig count, based on the activity we saw at the end of 2012 and in the beginning of 2013, we've always got a fair degree of confidence over development, when the wells would be spud. Where it's been a challenge for us in the past is when the wells would be completed. We didn't necessarily know when the production would come on, and we didn't know when the completion costs would flow through our joint interest bill cycles. But because the spud to sales cycle has compressed to approximately 90 days, generally speaking, we now know that once the development program begins, we generally know when the production's going to be coming on and when the joint interest bills will flow through our cycle.

So the way we look at it, we expect 44 to be a conservative number, from a net wells spud this year; and we expect that to be generally straight line. We do expect some additional benefits from pad drilling to maybe weight heavier towards the back half of 2013, from a production standpoint. But from a general development standpoint, we're confident with the 44 net wells and we're confident with the development plan and the areas where they're being developed.

As I mentioned in the previous question -- in a previous question, the rigs are currently present in southern Montrail. That's going to be a wind at our back this year. A lot of the drilling in the core of the play is now pad drilling, as opposed to out on the edges or the periphery, for hold by production type drilling. We also have seen some activity in McKenzie County that's very exciting for us. We happen to have 17.4% working interest in Whiting's Tarpon wells that they've brought on here recently, that are in the 5,000 BOE range for an IP. So that's been exciting for us.

We also happen to have about -- a little over 7% working interest in the Conoco Corral Creek unit, which is the 30,000-acre spacing unit in Dunn County, which is some of our highest EURs overall in the entire play. And Conoco currently has three rigs drilling in that area. So that's going to be active for us. And then in addition to the other activity that's standard for Northern throughout the core, as I'm just basically highlighting only a handful of the rigs that we're exposed to, I think the play as a whole is actively developing the core, and then we're also very actively developing the Big Sky AMI in Richland County with Slawson, targeting the upper shale.

A couple questions, as a follow-up to your comments there. The first is, in the project area with Whiting, the Tarpon area, where you've had some pretty prolific wells, what does the inventory there feel like? Is there a handful of wells left that's going to be drilled this year? Because certainly, that's potentially pretty significant for you guys.

Scott, we have about 23,000 net acres in McKenzie County, fairly close to the river. If you look at the map that shows our acreage, whether you look on our website or in press releases or investor presentations, you can see that most of our acreage is tucked nicely into Northern McKenzie and southern Williams, fairly close to the river, of course, as opposed to Northern Williams or southern McKenzie. So if you look at our acreage in McKenzie County, it's tucked nicely up into the river. And that Tarpon prospect is generally in the central -- east central or northeast central portion of McKenzie County. So we've got a lot of inventory in the area, not just with Whiting, but with Conoco, Continental and others. So it's a very exciting area for us, and we've got a lot of inventory, especially from an infill standpoint, going forward.

Okay. Very good. And one last follow-up. You mentioned Big Sky. I know in the past, you've talked about this prospect opportunity. A number of wells, it looks like, have been drilled there over the last year or so. At this point in time, do you have any color or sense in terms of what that opportunity looks like at this time, and if there is going to be increased development there with you and your partner?

Thanks, Scott. Let me lay out Big Sky here simply, without getting into too much detail. Slawson and Northern have drilled approximately 20 wells in the Big Sky area, in our Big Sky area of mutual interest in Richland County. It's on that southwestern edge of the Elm Cooley field in Richland, over in Montana. Northern has a 24% working interest in the area of mutual interest, with Slawson having the balance. We control -- Northern controls approximately 20,000 net acres in that particular area.

The program is slightly different than our typical Bakken and Three Forks development drilling. We're targeting the upper shale on that southwest edge of the Elm Cooley field, where the middle member is no longer present. We are drilling short laterals in 640-acre spacing units. And as I mentioned earlier, we've drilled about 20 of these wells. So on these short laterals, 5,000-foot laterals, we're using 20 stages sliding sleeves with white sand. We're currently drilling these wells for under $5 million a piece, and the EURs on most of the recent wells are in the 350,000 to 400,000 range. So this puts Big Sky as probably one of our highest EURs -- highest IRR areas. Slawson intends to drill about four wells per unit, until the project is complete. This is not a huge deal for us, but it will be among many of the drivers of production and value in 2013, similar to the movement of the rigs into the core over in North Dakota. So it's an exciting play for us, with Slawson.

Okay. And I apologize, I'm a little bit slow here. But what was the well cost and that EUR range that you provided?

We're currently drilling these wells for under $5 million a piece. And the EUR range of the wells that we've been drilling, with the most recent recipe for drilling and completion, are in the 350,000 to 400,000 range.

Okay.

And one thing to note, not to get into too much additional detail, but Slawson has also recently drilled two dual lateral wells, where from a single vertical, it has two laterals running along the lease line, either North and South and then East and West, or vice versa, where he's completing one -- he'll complete one -- Slawson will complete one lateral, flow it back, shut it in and isolate it, complete the other lateral, flow it back and then commingle the production. Slawson just completed the first well under this program, and the well costs are approximately $8 million. So roughly $4 million per lateral. So Slawson continues to innovate, not just from a drilling and completion standpoint, but they're also innovating from a cost efficiency standpoint. So it's an exciting play for us, albeit not gigantic for us. It's just another value driver for 2013.

Okay. That's great. Thanks a lot, Mike.

Peter Kissel, Howard Weil.

Maybe just one, initially, on differentials. Clearly, they've been favorable. And just trying to get a sense for where you think they're going to go going forward. And if you could give any sort of color in terms of what your breakout is from rail to pipe to truck, just for our modeling purposes, that would be helpful.

Thanks, Pete. This is Mike. I would say, the first quarter, we're probably seeing some of the similar levels we saw in the fourth quarter of 2012. I think just from a conservative standpoint, I would use the 5 to 7 range throughout 2013, which is consistent with what our operators are telling us. But generally speaking, with the addition of significant rail assets in the Williston, that's going to be one of the big drivers of tight differentials in 2013.

Okay. And then maybe one follow-up, a little bit more broad-based, following on one of the prior analyst's questions, regarding the MLP. Just looking at our model, we have Northern generating free cash flow mid-2014-ish. And just curious to see how you think about that, in context of the structure of Northern. You mentioned MLPs, and that you're always looking at alternatives to maximize value. But what about dividends, repurchases or even at that point, once it's a free cash flow entity that's still growing pretty fast, is that a time to be looking at an exit strategy? And does the buyer become a little bit different and more interested at that point, do you think?

Well, thanks for that question. And as you know, we take our duty to maximize shareholder value very seriously, and we're continually evaluating all options to increase shareholder value. As to any specific strategy, whether it's an MLP or an outright sale, like most public companies, we basically have a no comment policy. With respect to MLP, again, we announced in August last year that we've shelved the MLP for now, until the production profile matures. The production profile may be appropriate for an MLP towards the end of 2013 into '14. But at this time, that's still on the shelf.

Got you. Okay. Thanks, Mike. And maybe just one last question for Tom here. When you're looking at 2013 costs, how should we think about your different operating cost lines? In particular, LOE was a bit higher in the fourth of '12, due to some work over and water disposal expenses. But looking through the year, now that you have a pretty good line of sight, how should we be looking at that versus fourth quarter '12?

I think, echoing on Mike's comments, I think the first quarter differentials are fairly similar to what we're seeing in 4Q, differentials, I think, 5 to 7. I think our LOEs are going to range in the $8.00 to $9.00 range. As I mentioned in the script, you typically have higher LOEs during the first year of a well's operation. We've added a significant number of new wells during 2012. That will continue. I think our expectation is you'll see LOEs trend down as our production base matures. But I'd probably peg it in the $8.00 to $9.00 level. Production taxes, we were about 9.6% at the end of the fourth quarter; 9.6% to 9.8% would probably not be a bad range. And income tax rate, slightly lower -- slightly higher, rather -- than our year-end rate. We'll be an alternate taxpayer next year, so probably 38% to 39% on a rate, probably 0.5%, 1% being kind of current, the rest of it still being deferred.

Great. Thanks for taking my questions, guys.

Jason Wangler, Wunderlich Securities.

Just a couple of quick ones. One, on the CapEx budget, do you see the rig count moving higher throughout the year and maybe that CapEx budget ramping as that happens, or do you see it more being consistent throughout the year?

This is Mike. Thanks for the question. We really are modeling a stable rig count here. I think the rig count, as of last night, was about 185. We think that the rig count is essentially been high graded over the last year, given two pretty important data points. One clear data point is that the rig count is actually down about 15% from its all-time high of about 215. However, in December, the gross well spuds were at an all-time record. So we believe that the rigs that are in the basin now, roughly at185 rigs that are in the basin now, are pad drilling rigs that can walk or slide from well to well on a pad.

So that's -- I think that's what our model is assuming, which is just a stable rig count and development profile. And I think the CapEx budgets and the drilling plan in 2013 have been set with our partners. So we've always had a fairly decent view towards spuds, and we think that our 44 net wells spud is going to be accurate, and we believe that it's 8.4 to 8.8 is a reasonable range to assume at this time. Although, given the efficiencies of pad drilling and other costs, given the further availability of services, we think that we could exit 2013 closer to 8.

That's helpful. And the only other question I had was as far as the credit facility, when is the next redetermination coming up?

April 1.

April 1? Perfect. Thank you. I'll turn it back.

Chad Mabry, KLR Group.

Quick question on non-consents. You previously mentioned that you went non-consent on about 30 wells in Q3, Q4. Curious if you could specify which areas or maybe operators that you went non-consent? And then also if you could comment on the terms of your leases there. Will you have the option to participate in future development on those units?

Thanks for that question. Non-consents are fairly simple, in that if we don't agree with the economics of the current well being drilled in the unit, we can elect to not participate in that well. And then after the operator recovers approximately 300% of their drilling costs, we back in for our portion of -- our interest in that well.

And then to answer your last question first, if another well is proposed in that same unit, say, 90 days or six months or a year later, Northern has the same right to participate heads up in that additional well. So there isn't penalty, other than we just forgo the economics of the first 300% of drilling costs. So it's really simple.

We did elect to non-consent about 29 wells in the second half of 2012. The primary reason was just because of higher drilling costs. And our goal was -- the management and Board's goal was essentially to high grade capital deployment and improve capital efficiency, because we didn't know what well costs were going to end up doing. But they actually ended up stabilizing and then starting to drop. And just to give you an idea, to answer your first question, it really was across-the-board, from a county standpoint and an acreage -- and an operator standpoint. There was no one area that stood out. And it wasn't a material amount of wells. It was 29 gross, 1.9 net, in every county, really every county we're developing in.

One thing I'll note is as well costs have come down, we have non-consented less wells. And just to give you a probably a metric that you might be interested in, in the first two months of 2013, Northern has only non-consented five wells with about a total of about 12% working interest. So very minimal, just because the well costs have come down. And some of the first wells that we were non-consenting were in the $11 million range, with expected overruns of 10% to 15%. Even though they're in good areas, from a geologic standpoint, we just couldn't pencil them to a 15% pre-tax IRR. So we decided to non-consent those wells, from a capital efficiency standpoint. Subsequently, the wells that I'm specifically referring to, in the same area in the same units, are being proposed with the high 8's or low 9's, and those wells do pass our tests. So we're now participating with those same operators and units that are adjacent, and in some cases, the same unit.

So the non-consent issue will likely be a non-issue going forward, but we had to focus on capital efficiency at the end of 2012, as drilling costs at the end of 2011 and the first half of 2012 had escalated and overruns were fairly rampant. Now, just to echo something that Tom said, costs have come down, generally, across-the-board and across every operator. And overruns are now -- there really aren't any overruns now, generally speaking. It's fairly accurate, from an AFE standpoint, in the usual plus or minus 5% range. So we're able to very predictably estimate costs. So we're pretty happy with the position. But we expect non-consent in 2013 to be very limited.

Understood. Very helpful. Just a quick follow-up then on the acreage. Looking at your 2013 acreage budget, do you expect this to essentially offset any expirations this year?

Could you repeat that question? I'm sorry.

Of course. Just shifting gears to acreage, looking at your 2013 budget, should that -- should we look at that as essentially offsetting any expirations you have on the leasehold side this year?

That would be a fair assessment, yes.

Okay. Thanks, guys.

(Operator Instructions)

Jared Lewis, Northland Securities.

Just a couple quick questions. When you look at 2013, can you give us an idea of what your average working interest that you're looking at is?

Yes. We exited 2012 with 157 gross, about 12.4 to 12.5 net, which is about 8%, which is consistent with our historical average. I think our average working interest on our roughly 1,250 PDP wells, and roughly 157 or so on our PDNP, are kind of averaging in that 8% to 8.5% range. So that's our historical average, and we expect that to be fairly consistent going through 2013. So I think when it all comes out in the wash, we're still expecting the 44 net wells spud in 2013. So with a consistent historical average, working interest of about 8%.

Okay. Great. And just more of a general question on the LOE expenses in the water and the disposal, what are you seeing as far as infrastructure build and do you see that coming down through '13?

I think the big push in 2012, which you're seeing from most of our operators, as their conference calls have all happened here in the last 48 to 72 hours, we're seeing a big push for infrastructure development, specifically water gathering and water disposal. I think probably one of the biggest pushes in 2012 and into 2013 will be further cutting the costs on water disposal in every area. Some areas are better than others. Some areas have more water than others, and infrastructures continue to ramp there. So that will be the big push here in 2013, because that's the biggest driver of our lease operating expense increases over the last year.

Excellent. That's all I have. Thank you.

Curtis Trimble, Global Hunter.

Was hoping to gain a little bit of insight into difficulties, challenges, opportunities on forecasting production as more wells go into a batch completion phase. Obviously, costs coming down aid you a great deal in the pad drilling, but how about line of sight into completion dates, initial production, et cetera?

Thanks for that question. That's going to be one of the benefits of 2013, is that the wells are going to be drilled more efficiently, they're going to be, we believe, a lot cheaper as they're all drilled through, primarily on pads. We do, just from a conservative standpoint, expect the benefits from that to hit mainly in the second half of 2013. Because we currently see approximately two-thirds of the wells we're currently drilling as part of a pad drilling program, so that's going to be very beneficial to us. However, just from a conservative standpoint, we'll just say the weighting of our production growth in 2013 will probably be heavily weighted towards the back end of 2013. So it's fairly simple math. If you're drilling four gross wells on one pad, you're going to get those wells drilled more efficiently, but they're likely going to be batch completed all at the same time.

The one thing I will note that is a little unique to Northern is that given the sheer number of wells that we're currently participating in, there isn't a scenario where we have certain dates where the production will come on or where we'll have lumpy production, given the fact that at the end of 2012, in December, we were drilling or completing 12.4 net, 157 gross. Northern is always pad drilling wells. We're always batch completing wells and bringing new pads on. So there isn't a scenario where we have certain production coming on at certain months throughout the year. We're going to be constantly completing pads. And so we think we have a certain smoothing effect, for lack of a better way to explain that. But generally speaking, the pad drilling that has increased over the last few quarters will likely benefit us, for the most part, in the back half of '13.

Good deal. And dialing down a little bit on the non-consent wells, you mentioned an $11 million figure for those. Would your assumption or theory be that a lot of those wells are science wells, they're testing deeper ventures in the Three Forks, coordinated with co-development of the middle Bakken, et cetera? Would it be fair to characterize that you are basically getting a free look at the science that other folks are conducting on those wells? I don't think we had any science projects in 2012, to speak of. I think, just generally speaking, not only were the costs escalating throughout the end of 2011 and the early part of 2012, but what we were seeing, just given the sheer delay in completion, was we were seeing overruns on those AFE's. So AFE's that were coming in the 10, 11, 12 range were all tending to overrun. So we were very careful with our CapEx deployment to those higher cost wells. So these wells were in good areas. They were with good operators. But well costs have come down materially over the last two or three quarters. So we expect this to be fairly limited. So there wasn't anything particularly unique.

I think you've seen public data from some of the larger operators in the play who are consistently drilling wells in the 10.5 to 12 range in the Williston, are now in the 8.5 to 10 range. I think that's been a consistent theme of some of the operators who are drilling some of the higher cost wells. Some of our operators in 2012 that had the highest cost wells probably deserved most improved for 2012, for bringing the well costs down. So just to maybe finalize our thought on non-consent, we think they'll be limited, if hardly any, in 2013, just because of the decrease in well costs. Good deal. I appreciate it. You all have a good weekend.

Thanks. You, too.

And that does conclude our question-and-answer session today. Speakers, I'll turn the conference back to you for any additional or closing remarks.

This is Mike. Thank you for your participation in this call this morning and your interest in our Company. Kim will give you the replay information, and we look forward to seeing you during conference season and sharing our results with you next quarter. Have a great weekend. Thank you.

And that does conclude our conference for today. If you would like to rehear this conference, the replay information starts today at 12 noon and ends on March 15 at 11.00 PM. The phone number is 888-203-1112, or 719-457-0820. Thank you so much for your participation.