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Northern Oil and Gas (NYSEMKT:NOG)

Q3 2013 Earnings Call

November 08, 2013 10:00 am ET

Executives

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

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

Analysts

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

Peter Kissel - Howard Weil Incorporated, Research Division

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

Jared Lewis - Northland Capital Markets, Research Division

Marshall Carver

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

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Operator

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

Michael L. Reger

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

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 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, which are available in 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 these non-GAAP financial measures to the applicable GAAP measures can be found in the earnings release that we issued last night.

As we mentioned in our earnings release last night, Northern's third quarter 2013 production was 1.2 million barrels of oil equivalent or 13,049 barrels of oil equivalent per day, a 20% sequential increase over the second quarter. We added 147 gross, 12.1 net wells to production in the third quarter, bringing our total producing well count to 1,585 gross, 133.5 net wells as of September 30. The level of drilling activity in the basin was strong throughout the third quarter, primarily driven by favorable weather and pad drilling efficiencies. Our backlog of wells, either drilling or awaiting completion, expanded to 260 gross, 18.8 net wells as of September 30.

Robust activity levels continued into the fourth quarter as we added 65 gross, 4.6 net wells to production during the month of October. We spud another 60 gross, 3.3 net wells during the month as well, leaving our drilling and awaiting completion list at 255 gross, 17.4 net wells in process as of October 31. The October completion activity gives us a really nice start to the fourth quarter and hopefully a strong finish to the year.

Due to the sequential production growth and well productivity we experienced during the third quarter and our strong start to the fourth quarter, we are raising our assumptions to an estimated 37 to 39 net well additions for the year and estimated 2013 total production of 4.4 million to 4.5 million barrels of oil equivalent. If weather cooperates and completion activity remains robust in November and December, we could be at the higher end of that range.

Acreage acquisitions picked up slightly in the quarter as we acquired almost 7,400 net acres at an average cost of just under $1,500 per acre. This brings our current acreage position to approximately 187,000 net acres in the core of play at the end of the third quarter. We will continue to be disciplined in our acreage acquisition strategy, seeking only high-quality, non-operated, near-term drilling opportunities.

As mentioned in our press release last night, on October (sic) [August] 16, Northern began repurchasing shares under our existing share buyback authorization. During the third quarter, we purchased just over 2 million shares at an average cost of $12.82 per share. This represented just over 3% of the company's stock. The decision to buy back shares was initiated for a couple of reasons: First, Northern's liquidity position has never been stronger. The borrowing base under our '13 bank revolving credit facility was increased to $450 million during the third quarter. Capital expenditures have been more predictable and per well cost have been trending down. Aside from McKenzie County, where the wells are a bit more expensive due to depth and completion designs, most of the well cost we are seeing are closer to $8.5 million or less. Also, we have mitigated future's cash flow volatility by increasing our oil hedges to maintain a strong liquidity position.

In addition, the market's valuation of Northern versus the value of our asset base had become, in our opinion, dislocated. Our board, the rest of the management team and I have concluded, after careful consideration, that it was the appropriate time to act. At approximately $13 per share, it was cheaper to buy our own high-grade acreage position, current production, reserves and future drilling inventory than it was to buy most of the deals we are seeing in the marketplace.

Overall, the third quarter was very exciting for Northern as activity levels improved as compared to the first half of the year and our sequential production growth resumed. We are encouraged by the level of activity in October and the inventory of wells that should come on before year end. We are in a great position to continue to execute our business plan into 2014 and beyond. We will continue to seek high-quality acreage opportunities, develop our extensive drilling inventory, expand our liquidity position and explore additional ways to maximize shareholder value.

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

Thomas W. Stoelk

Thanks, Mike. We reported GAAP net income of $1.7 million, or $0.03 per diluted share, for the third quarter of 2013. Excluding the effects of noncash loss on derivative instruments, we reported adjusted net income of $20 million, or $0.32 per diluted share. Adjusted EBITDA for the third quarter was $74.6 million, bringing total adjusted EBITDA for the first 9 months of 2013 to $196.3 million, which is a 22% increase compared to the first 9 months of 2012.

In the third quarter of 2013, oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 33% compared to the third quarter of 2012, and that was driven by a 16% increase in production and a 15% increase from realized pricing, excluding the impact of settled derivatives. Our average realized price, including all cash derivative settlements during the third quarter of 2013, was $82.58 per Boe, that was roughly 4% higher than the $79.38 per Boe realized in third quarter 2012. The higher average realized price in the third quarter of 2013 as compared to the same period of 2012 was driven by higher average oil prices, offset by the effect of losses on settled derivatives. Oil differential during the third quarter of 2013 was $9.04 per barrel as compared to $10.18 per barrel in the third quarter of 2012.

During the third quarter of 2013, we had a noncash mark-to-market derivative loss of approximately $29.4 million, that compares to a $22.3 million loss in the third quarter of 2012. The noncash loss relates to oil volumes hedged in future periods at prices less than the forward futures market on September 30, 2013.

Production expenses were $11.5 million in the third quarter of 2013, that compares to $8.7 million in the third quarter of 2012. On a per unit basis, production expenses increased to $9.56 per Boe in the third quarter of 2013 compared to $8.42 per Boe in the third quarter of 2012. The year-over-year increase in 2013 was really driven by higher water hauling and disposal costs and work over expenses.

Our production taxes totaled $9.9 million in the third quarter of 2013, that compares to $8.1 million in the third quarter of 2012. As a percentage of oil and gas revenues, production taxes were down slightly to 9.3% in the third quarter of 2013.

General and administrative expense was $4.2 million for the third quarter of 2013, that compared to $9.5 million for the third quarter of 2012. On a per unit basis, general and administrative costs during the third quarter of 2013 were $3.47 per Boe. Excluding the $4.9 million severance charge from last year, our G&A expenses dropped 9% in the third quarter of 2013 compared to the same period in 2012. So we've been able to contain our overhead cost while continuing to grow our business.

Depletion, depreciation and amortization accretion was $32.1 million in the third quarter of 2013. That compares to a $28.1 million in the third quarter of 2012. Depletion expense, which is the largest component of our DD&A, averaged $26.66 per Boe in the third quarter of 2013 compared to $26.93 in the third quarter of 2012. The provision for income taxes was $1 million in the third quarter of 2013 compared to $213,000 in the third quarter of 2012. Effective tax rate during the third quarter was 37.6%, the year-over-year decrease in our effective tax rate reflects a decrease in the corporate income tax rate in North Dakota.

During the third quarter of 2013, capital spending totaled approximately $117.5 million, which puts our 9-month capital spend at $319.5 million. Our total capital expending for the first 9 months is broken down as follows: Drilling and completion costs, including capitalized work over expenses, was $280 million. We spent $22.6 million on acreage and related activities and another $16.9 million on other capital expenditures. As we mentioned in the earnings release during the third quarter of 2013, we placed 147 gross, 12.1 net wells into production, which brings our year-to-date producing well additions as of September 30 to 358 gross, 27.3 net wells. If we hit the top end of the completed well range Mike mentioned earlier, we will have added approximately 9 -- 39 net producing wells by the end of the year. Assuming our drilling and completion costs per net well is $9 million, which is the weighted average AFE costs for our wells in process at September 30, we'd incur a total of approximately $351 million of drilling and completion costs related to the producing well additions in 2013.

Please keep in mind that our actual CapEx spending will be impacted by the expenditure levels on our backlog of wells in process at the end of the year. We entered 2013 with a backlog of approximately 12.4 net wells in process, which has increased to 18.8 net wells at September 30.

At September 30, 2013, we'd incurred approximately $64 million of drilling and completion costs related to our in-process wells at that date. Given our slight pickup in acreage acquisitions during that third quarter, our full year acreage CapEx will probably be closer to $30 million, and I'd estimate that other capitalized expenditures will remain unchanged at our previous estimate of $30 million.

As Mike mentioned, in conjunction with the comments about share repurchases, we increased our hedge position in order to protect our liquidity, increase the predictability of our cash flow and to help maintain a strong financial position. Currently, we have hedged approximately 11,200 barrels of oil per day in the fourth quarter of 2013. Approximately 52% of the fourth quarter hedging is done with costless collars with an average floor price of $90 per barrel and an average ceiling price of $104 per barrel.

In 2014, we have hedged approximately 10,900 barrels of oil per day, the majority of our 2014 hedges are crude oil swaps at an average price of $90.46 per barrel. In 2015, we have hedged approximately 7,400 barrels of oil per day. The majority of our 2015 hedges are crude oil swaps at an average price of $89.03 per barrel.

At September 30, 2013, our revolving credit facility had $45 million drawn on a $450 million borrowing base. With strong third quarter growth, our net debt-to-adjusted EBITDA was 2x on a trailing 12-month basis and 1.8x if you annualized the third quarter. While we have ample liquidity under our revolver to fund our development or our future development, we also remain focused on maintaining a strong balance sheet.

At this time, I will turn the call over for Q&A to Rishel. If you would please give the instructions for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll first hear from Scott Hanold with RBC.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So Mike, you had mentioned that you all are looking at other opportunities to advance -- or enhance shareholder value outside -- I'm assuming that means outside of the share buyback. So I kind of embedded 2 questions. First, what would those other opportunities entail? Can you give us some color on that? And the second question is on the stock buyback. What is your view at this point? Was that a onetime sort of a transaction you did or could we see this happen again?

Michael L. Reger

Yes, thanks, Scott. As far as the stock buyback goes, obviously, we won't be mentioning our specific plans ahead of time and we'll report any of the stock buybacks at the end of the quarter. But having said that, as you know, we make decisions on a daily basis, on well proposals and acreage acquisition opportunities. So our capital allocation decisions are somewhat fluid. The first part of your question was additional ways to maximize shareholder value. And I think we'll continue as the management team and the board will continue to analyze other opportunities, royalty trust or MP [ph], additional stock buybacks, et cetera. So we'll continue to analyze those opportunities, potentially, strategic asset sales. However, our leverage is relatively low compared to our peers at under 2x debt-to-EBITDA. So we're not in any need to make any asset sales. But we're always reviewing those opportunities and all of the options we have.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. That's some good color. And then my second question would be on the acreage acquisitions. You made a pretty nice chunk of acquisitions this quarter. Can you give us a little color on what changed this quarter to really ramp that up and where that stuff was at? And also I guess over the last couple of years, we've seen some larger operators sell some non-op interest and recently, another one has indicated that they're looking to sell some Mountrail non-operated interest. And just remind us at this point, what's your appetite for some of these bigger deals?

Michael L. Reger

I think the strength of our balance sheet and our liquidity position gives us the ability to weigh these new deals we're seeing. The new one this week with Oasis divesting their Mountrail non-op, that's a very interesting opportunity. We're going to run that one out, just like we run all of these opportunities, through our acquisition teams. And we -- but we really do stay focused on what we do best at Northern, and the niche that -- and the -- really the business model that we invented, which is acquiring and being the clearinghouse for acquiring these non-operated strategic interests that are about to be drilled. So from an organic standpoint, we continue to be very active on the ground. We have, over time, acquired a few packages that were larger. We're looking at a few packages that are a bit larger. We'll continue to look at opportunities that are big, like the Oasis package, which is similar to the EOG package from about 1.5 years ago. But really, where we picked up the acreage in the third quarter, to answer your question, is just basically across the board in the -- throughout North Dakota, spread across the counties where we have really strong presence already. We've added additional acreage in Mountrail, McKenzie, Dunn, Richland County, et cetera. So we'll continue to just pick away at the core acreage that we continue to seek [ph], especially as it relates to the near-term drilling opportunities.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, and if I could follow up with that real quickly on sort of the pickup in sort of your core bread-and-butter acquisition. Is something changing in the basin right now? Early on, obviously, you got in there early and you were able to be very successful. Then it slowed down a little bit. But is there something, another cycle occurring in the Williston at this point where maybe there is some more small or non-op stuff coming available for you all?

Michael L. Reger

There are -- there is a lot of activity right now that we're seeing from an acreage standpoint that's interesting to us. One thing that might be creating this is that with pad drilling, you start to see well proposals go out, not just for one well, but for -- in some cases, 4 or 8 wells. And that may create liquidity issues for others, or CapEx issues for others, where Northern, given the strength of our balance sheet and our liquidity position, we may have the opportunity to acquire that interest from some of the smaller folks in the basin. So we do start -- we have started to see more deals, and we believe the main catalyst is from pad drilling.

Operator

And next, I'll move to Jason Wangler with Wunderlich Securities.

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

Just curious on the hedging, obviously, jumping it up. Is that about to the limit of your credit facility or is there any more room there?

Thomas W. Stoelk

There's some more room. Effectively, most of that room would be out in the 2 15, 2 16 area.

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

Got it, yes, and I should have specified I was thinking '14 because it looks like some pretty nice numbers there. And then just, obviously, with the 7,400 you picked up last quarter in your comment there on the pad drilling, as far as seeing that, do you think we're in the early stages of that still or do you think that a lot of it is kind of being picked up? And do you see maybe, without asking too much about '14, do you see a land budget that's still going to be able to let you really start keep acquiring acreage in the core?

Michael L. Reger

Yes, I think we're just starting to get going here with pad drilling. I think a majority of -- the units that we're participating in are on pads with at least 2 wells, but in most cases, 4. I think -- I really think we're just getting going here with this particular opportunity we're seeing from an acreage acquisition standpoint.

Operator

And next, we'll move to start Peter Kissel with Howard Weil.

Peter Kissel - Howard Weil Incorporated, Research Division

Mike, you alluded to this a little bit in your prepared remarks, but just looking at your fourth quarter assumptions, it looks fairly conservative, particularly that you're coming out of the gates so strong with 4.6 net wells in October. And I just was wondering if you wouldn't mind clarifying to make sure that it has nothing to do with timing of completions in November, December. It's much more just a function of playing it conservative with the risk of some potential early winter weather?

Michael L. Reger

Yes, Pete, thanks. The big issue for us is, as a non-op, is we really -- we get to take a really hard look at our existing end process list, and that's really strong right now at close to 18 net wells. I think right around 255 gross wells, that are actively drilling or completing or awaiting completion. So we have a pretty good bead on what's happening. And as you know, what happens in the first month of the quarter is more beneficial than what happens in the last month of any given quarter. So we're really encouraged by the fact that October was strong. It really does come down to weather. If completions continue to be strong in November and December, we think we're going to be at the higher end of those ranges that we mentioned. And it's not an effect of just being conservative. We just truly don't know what the weather is going to be like in late November and December, but fingers crossed, that it's favorable, because it's been pretty good so far.

Peter Kissel - Howard Weil Incorporated, Research Division

Got you, Mike. I may be taking a bit of a step further here. Looking at the first half of 2014 or so, how should we look at, outside of weather, of course, but how should we look at the smoothness of the growth trajectory? Is there any sort of quarter you see coming up in the first 2 quarters or so that has more pad drilling or less pad drilling that may create more lumpiness in the mix or is it a little too early to tell?

Michael L. Reger

It's too early to tell. But I would say that given the pad drilling phenomenon, that's actually a benefit to Northern, because with roughly 250, 260 gross wells that are actively drilling or completing or awaiting completion, that's somewhat of a smoothing effect for us. We're not sitting on 1 pad waiting for production to come on at some point in the future. We're completing big pads today, we were completing big pads last week and we will again next week. So it's kind of a smoothing effect for us just given the sheer number of wells that we're participating in. But really, again, the key is if we have favorable weather conditions in the first quarter, it'll be a lot more smooth than it was in 2013, where our operating partners and Northern, both said, "Hey, we thought the first half would be flat." And then we thought we'd ramp into the second half. And it looks like all of our partners now that they've reported third quarter, and Northern as well, that all happened kind of as expected. So we're just fingers crossed for favorable weather because that's the big issue in the Williston is just kind of getting the equipment moved around.

Operator

And we'll move on to Ryan Oatman with SunTrust.

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

We've seen some operators really focused on driving down costs while it seems like others are taking a different approach and they're adding a little bit to the cost to try some new completions to improve productivity. I was just wondering if you could speak in broad strokes as to where you see costs moving across the basin. Do you see guys more focused on kind of driving down the cost or more focused on improving the potential productivity?

Michael L. Reger

Well, I think you get the best of both worlds here. You start to see cost continue to come down across the board. In addition, as a lot of you have seen over the last few months, new completion techniques really have been utilized to improve the recovery of the oil in place. And we don't necessarily see that as a broad cost increase issue. We think that cost are going to continue to come down, really because it isn't a completion -- it isn't a major completion redesign, it's just a technique change. So we're excited to see the cost continue to come down. And we think that their cost will come down and the completions will be more effective as we go here -- with the additional sand. You're referring to the bigger completions where we're -- where they're adding more sand with cemented liners and plug-and-perfed and we're starting to see some really amazing results from that. We've seen a lot come out of EOG especially. They've been the most vocal about it and they were one of the first to utilize this new technique, if you will. And so we were in a lot of those new wells. So we got to see them real-time and it is really exciting for us. So -- but we continue to see costs come down basically across the board and with every operator.

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

And you do see that the productivity gains that some of these operators are talking about between these new wells with the new designs and the offsets?

Michael L. Reger

Yes, it's really strong, especially with EOG, they've started to talk about some of their results that we've participated in. So EURs appear to be moving up with this new design. And with EURs so goes IRR, so we're really encouraged.

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

Right, absolutely. And then kind of a tactical question, there was -- you touched on a little bit earlier regarding hedging in the backwardation of the curve. How do you think about being opportunistic with your hedging and how do you balance between say, a swap and a collar, what are your thoughts on hedging strategy?

Michael L. Reger

Well, it just really depends on the -- on what the market looks like. There's been some backwardation over the last few months. The curves flattened materially as you've seen, which would kind of put collars more in play. But really, $90 is an important level for us. We've been fortunate to put on a pretty significant hedge book through the end of 2015 at $90 a barrel or approximately $90. The fourth quarter is particularly exciting. We've got -- a majority of our hedges have $90 floors with $104 ceilings. So that's going to be positive for the remainder of the year. But we'll continue to add to '15 hedges, $90 is a really good level for us. And we've been able to -- and fortunate to be able to put on a very big book there at $90.

Operator

And we'll move on to Jared Lewis with Northland Securities.

Jared Lewis - Northland Capital Markets, Research Division

Just back to the acreage. You added 7,400 just on the held by production, and North Dakota has been kind of holding steady around that 70%. Can you just talk about that a little bit on just why that really hasn’t moved that much?

Michael L. Reger

Yes, it's really just kind of a wash. We had about I think just -- it's right around 3,000 acres expired during the quarter and we added about 7,400 acres. So it was a really strong quarter for us from an acreage acquisition standpoint. The new acreage we acquired, that will all, for the most part, be held by production in, we think, the fairly near term. So that number should start moving up. The big driver of our held by production percentage will be, as we start to increase activity in Richland County, where, really, if you take Richland County out of the equation, we have a pretty substantial HBP position. But we have a fairly substantial area of mutual interest in that Big Sky play we have with Slawson. We've got 1 rig running over there right now, and they'll continue to bounce around and hold acreage. And hold the stuff that we really want to hold. And we think our percentage should start moving up here pretty materially.

Jared Lewis - Northland Capital Markets, Research Division

Great. And just kind of a follow-up on that. Given, I assume, the stuff that's expiring is kind of away from the core and the stuff you're adding is tighter, has that changed the overall working interest at all?

Michael L. Reger

It really hasn't changed the working interest at all. Primarily, the expirations we're seeing are in Richland County. This is acreage we bought alongside Slawson at very favorable cost. And so our primary expirations in the third quarter and the fourth quarter are from Richland County in that area. So Slawson is going to drill the stuff that is going to have the highest IRR first. And it's a pretty big slug of acreage. We've got about 25,000 acres over there, south of Elm Coulee. And they're -- Slawson is getting to the best stuff. The expiration pressure is in Richland County, where over in North Dakota is -- we're getting after that, the activity is really brisk.

Jared Lewis - Northland Capital Markets, Research Division

And one more quick one, if you don't mind. Are you seeing just with the pad drilling, a lengthening from when you get AFE until when you start seeing cash flowing or just -- what are you seeing with that kind of aspect of pad drilling?

Michael L. Reger

Well, I think the key is just, when you spud a well, and it's the first well on a 4-well pad, the first well, obviously, is going to have a longer drill-to-complete cycle time, but the last well will be a lot tighter. So we think that the -- we think that our average is going to be fairly stable at kind of 90 to 120 days. If you take weather out, it's going to be at the lower end of that range. If you factor weather in, it's going to be at the higher end of that range. So -- but generally speaking, it's spud to spud, so drilling time to total depth, that's decreasing, which is positive. And then spud to sales overall will decrease when the weather is better and widen out a little bit towards the 120 range when weather is less favorable during the winter months. So -- but generally, it's a positive.

Operator

And next, we'll move to Marshall Carver with Heikkinen Energy Advisors.

Marshall Carver

Couple of questions. One on the expense guidance. Do you have any -- it looks like 3Q came in fairly predictably. Any tweaks on from 3Q to 4Q that we should think about?

Thomas W. Stoelk

Not really, Marshall. I think that LOE per Boe probably in the $9.50 range, kind of similar to what you saw in Q3 production taxes as a percentage of oil and gas. Probably $9.40, $9.50, somewhere in there. You see our G&A was running about $4.2 million for the quarter on a 9-month basis, we're a little -- we're a tick over $12 million. So probably somewhere around $4.2 million, $4.3 million wouldn't be a bad number there. And you've seen our production guidance that we announced in the earnings release and talked about in the script. But not a whole lot of tweak really I don't think.

Marshall Carver

And did you all do a reserve report along with the bank redetermination? I'm just wondering if you have a feel for -- I know you're drilling in better areas this year. Do you have a feel [indiscernible]?

Michael L. Reger

Yes, Marshall, to answer your question on the reserve report, the majority of our lending is supported by our PDP production. So we get after real hard our PDP reserves on a midyear. But we don't do a whole lot of work around the PUDs because it's just a smaller component of it. So we didn't do a -- we didn't really do a full-blown reserve estimate, to answer your question. We do see some growth, some pretty strong growth, I think, when we come up with our year-end reserves. But to answer your question, we didn't do a full-blown one at mid-year.

Operator

And we'll move on to Adam Leight with RBC Capital Markets.

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

Just a quick one for Tom. Can you help me just check my forecast or estimate on what you're RP capacity is currently?

Thomas W. Stoelk

We didn't hear that, Adam, on what?

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

Your restricted payment capacity?

Thomas W. Stoelk

Oh, I'm sorry. Yes, you came through garbled Adam. Roughly around, I think, $60 million, a little right around that neighborhood.

Operator

And we'll move on to Ravi Kamath with Global Hunter.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Couple of questions. One on the, I think you said the AFE on the work in process was $9 million. You seem like, I recalled, on the last quarter, that it was more like $8.8 million. So just wondering if you could kind of reconcile that and I think you had talked about maybe getting to $8.5 million. Just -- if you could talk about that a little bit please.

Michael L. Reger

Yes, really it's driven by the mix of where those wells are at. And when you take a look at our wells and processes at the end of the quarter of 18.8, about 1/3 of those wells are in McKenzie County, and so that's driving that weighted average up. It's -- McKenzie County wells are roughly around, on average, about $9.9 million on a weighted-average basis. If you excluded McKenzie County wells, it's kind of the rest of that inventory or rather the other 2/3 of the drilling and process wells have a weighted average cost of roughly around $8.5 million. So what you're seeing is a higher mix of wells in process in a really good county being McKenzie, with higher well cost kind of driving that weighted average up.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Understood. Understood. And then with regards to acreage expirations. Can you sort of give us some ballpark number for Q4 of '13, and also if you have the numbers for 2014 and maybe how much of that you expect to actually hold?

Michael L. Reger

Right. I would say that -- this is Mike. I would say that our expirations in the fourth quarter will be similar to the third quarter. So fairly immaterial and I think under 3,000 acres. And hopefully we put up another good quarter from acquisition opportunities that we're seeing in the field.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Okay. And then last one for me. I just wanted to get an update on Richland County activity and just recent results, anything on EUR, well costs, anything you can share on sort of results in Richland County?

Michael L. Reger

Yes, the one thing that we've seen Slawson do over the last year or so is use dual laterals with -- I guess, you would call them dual short laterals. So we -- which has been very encouraging to us. The first test well was called the Archer, where they drill -- they drilled the well in the corner of the section, and then drilled 5,000-foot laterals, 1 north and south, 1 east and west along the section line. And once both wells were -- both laterals were frac-ed and brought online, we were seeing those well costs in the neighborhood of $7.5 million for a dual lateral, and each lateral seemed to be consistent with the production of the single sort of laterals that we were drilling adjacent. So costs have come down. We see EURs across the board up there. But really good internal rates of return on some of these new wells we've been drilling right in the heart of Big Sky.

Operator

And there are no further questions. I would like to turn the call back over to Mr. Reger for any additional or closing remarks.

Michael L. Reger

Great. Thanks, everyone, for your participation in this call. Rishel, will you give the replay information to the group? And we look forward to seeing everybody soon and sharing our results with you from the fourth quarter in the New Year. Have a great day.

Operator

Thank you. And that will conclude today's call. The replay does start November 8 at 1 p.m. Central Time, and runs through November 22 at 1 p.m. Central Time. The dial-in numbers: (719) 457-0820 or (888) 203-1112. Thank you, and you now may disconnect.

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