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Triangle Petroleum Corporation (NYSEMKT:TPLM)

Q3 2012 Earnings Conference Call

December 10, 2012 10:30 AM ET

Executives

Jonathan Ryan Samuels – President and Chief Executive Officer

Joseph B. Feiten - Chief Financial Officer, Principal Accounting Officer

Susie Kuntz – Controller

Justin Bliffen – Head of Corporate Finance

Michael Grijalva – Vice President of Capital Markets

Analysts

Will Green – Stephens Inc.

David Snow – Energy Equities

Jason Wangler – Wunderlich Securities

Ron Mills – Johnson Rice & Company

Jack Aydin – KeyBanc Capital Markets

Jared Lewis – Northland Securities

Blaise Angelico – Howard Weil, Inc.

Dan McSpirit – BMO Capital Markets

David Peterson – Shareholder

Adam Fackler – KLR Group

Operator

Good day, ladies and gentlemen, and welcome to the Q3 2013 Triangle Petroleum Corporation earnings conference call. My name is LeeAnn and I will be your operator for today. At this time all participants are in listen-only mode and we will conduct a question-and-answer session towards the end of the conference. (Operator Instructions) As a reminder, this call is being recorded for replay purposes. I would now like to turn the call over to Jonathan Samuels, President and CEO. Please go ahead.

Jonathan Samuels

Thank you and good morning everyone. Welcome to the Triangle Petroleum fiscal 2013 third quarter conference call. My name is Jonathan Samuels and I’m joined today by Joseph Feiten and Susie Kuntz from our accounting team and by Justin Bliffen and Michael Grijalva from our finance team.

Today we’d like to cover a number of topics. We’d first like to review the quarter, the operational and financial results for the period ended October 31 2012 which is the first profitable quarter in our company’s history. Second, we’d like to cover some highlights and low lights from current operations which will include some thoughts on overall trends in the Bakken. Third, we’d like to talk about strategic goals on a go-forward basis, particularly as it relates to our vision for Triangle’s low cost Bakken operator differentiated by vertical integration. Fourth, we would like to take questions and answers from those of you listening in on the call.

During the three month period ended October 31 2012, Triangle generated a total of EBITDA of $6.8 million on total revenues of $23.1 million. We produced an average of approximately 1,400 barrels of oil equivalent per day in the quarter, representing about 20% sequential growth quarter over quarter and ahead of our production guidance given to the street. We exited the quarter producing a little over 2,000 barrels a day, which again is about 500 barrels a day ahead of the high point of our previously issued production guidance.

Triangle’s balance sheet remains in great shape. We exited the quarter with approximately 445 million in cash, which does not include our share of cash in Caliber midstream and we had an undrawn E&P credit facility, $52 million which we expect to continue to grow as reserves come online.

At the end of the quarter we also established a total hedge position of approximately 1.4 million total barrels, which has downside protection as we move forward through these uncertain economic times.

Regarding the highlights and lowlights and overall operations which is where we want to spend most of our time, there’s a lot to talk about and interesting period in the Bakken and Triangle’s development. Starting with the lowlights mostly so we can finish on the positives which we’re obviously more excited about and this quarter definitely saw production lower than we thought. I want to explain really the key driver of that is well downtime and one of the things we’re experiencing as we move forward is multi-well pads drive operational and cost efficiencies in the drilling and completion side of bringing wells online. It also results in higher downtime in the early days of a well’s life. And to simply explain that, we have two or three wells on a pad like we do on our Larson pad in McKenzie County, whenever you conduct any sort of operation on one of those wells, whether you’re flow back testing and you want to shut in, whether you’re drilling out plugs, safety pretty much depends that you shut in all wells on that pattern.

So while that does not impact total EUR or the total production that well will have in the first 90 days when it is online, it does affect the current period and you see that reflected in these production numbers. Obviously with an average of 1400 barrels a day in the exit rate, you can see what happens when all these wells are turned online. But it did have a negative impact in the quarter.

Secondly is really on the cost side. A simple way to put it is the trend is positive, going the right direction, meaning costs are coming down, but they do remain high in McKenzie county. This is the deepest part and the hardest part of the basin and that remains a core focus area for us as we move forward.

Third, G&A and LOE, both higher as a percentage of revenue that what we’d like to see. This is a problem that largely solves itself with revenue growth over time. We have to staff up with a certain number of people both in our corporate headquarters in the field to conduct these operations and start our vertical integrated model and the people come before revenue. But you did see that in this quarter and the margin expansion is something we’d like to focus on next year.

The last lowlight from the quarter was our experience with gas lift as a form of artificial lift. It’s a pretty involved topic, but the simple way to put it is given the reservoir characteristics in McKenzie County and given the infrastructure in the area, rod pump remains a better choice for us and that’s what we’re going to be doing on a go-forward basis as well as converting some of our wells that are currently on gas lift to rod pump. We see that again as something that solves itself in Q4 and we see our total productive capacity today as meeting or exceeding our guidance as laid out for year-end.

On to some highlights from the quarter, we continue to be very excited about the geology and the reservoir quality of our area of operations, which includes the Three Forks. Our target formations are deeper and hotter here than just about anywhere else in the basin, which does mean costs are higher, but we also think we’re ultimately going to get a lot more wells per 1280 than other folks are going to get in other parts of the basin. That means ultimate recoveries from our acreage will be higher on a percentage basis than other counties, again really just because you can drill more wells for 1280 than you can in other places. We continue to study our downspacing and what the appropriate well spacing is, but as of today with well spaced just as little as 600 feet apart, we see no communication between these well bores which is very encouraging for us as we both move horizontally across the 1280, meaning more Bakken wells in the unit and as you move vertically, meaning Bakken Three Forks and other benches of the Three Forks as well.

Secondly, we’re very excited about what we’re seeing out of RockPile this quarter really demonstrates what the vertical integrated model can do to our business and however you think about it, when you adjust for capital invested in RockPile, their contribution makes a meaningful impact on our F&D cost as an EMP operator. We’ve done a great job operationally and you can see this quarter the positive impact they have on our financial savings.

Third, we are well positioned operationally to meet our year-end production guidance which you can find on page 18 of our corporate presentation on our website. As a quick reminder, our guidance established at the beginning of this year was an exit rate in January between 2600 and 3200 barrels of oil proven per day and we are on track to meet or exceed that target.

Fourth, we’re very excited about the formation at Caliber midstream and our partnership with First Reserve. We’d like to take a minute to reiterate that we view the Bakken primarily as a cost play. Everyone knows there’s a well there. How much does it cost to get it out is really the question and we see vertical integration as the path to being a low cost producer in the basin. What it also means is that Triangle shareholders get growth in three different fully funded engines setting the stage for years of growth and revenue and cash flow on a per-share basis. It also makes our current two-rig program self funded far sooner than would otherwise be possible.

Fifth, and perhaps most importantly, the turnaround of Triangle is complete and the startup nature of our operations is a thing largely of the past as of today December 10. We have the people, the platform, the capital, the inventory to drive meaningful growth in years to come and what that means as a management team we can focus on costs, we can focus on margins, we can focus on making this as profitable a business as possible which really just wasn’t something that we were able to focus on this year when you’re trying to drill and complete our first well, get your integrated service business up and running, get your midstream entity fully funded. All those goals have been accomplished which really set the stage next year for margin expansion.

This is a good segue into our strategic goals for next year. One, we’d like to continue to drive production growth while attacking costs. Our budget released today of $190 million includes development capital for our two rig program next year and we want to be as efficient as possible every dollar we spend. Second, as I just mentioned, margin expansion. We’re happy this quarter with our revenues and we’re happy with our total EBITDA relative tax periods, but we know we can do better and we’d like to see margin expand by focusing on G&A and LOE as a percent of revenue or improving the basis depending on how you want to look at it.

Third, we want to continue to maintain the integrity of our balance sheet and to that end we have board approval to drop one of our two rigs in the spring if macro or fiscal cliff issues warrant it. The revised budget will be $130 million. So we really want to drive the message home that liquidity management and balance sheet integrity are very important to us and we’ll respond to macro conditions as they evolve.

Fourth, we want to keep an eye on our station prospect in Montana. This is part of our portfolio that gets very little attention, very little value accredited to it. But we’re monitoring activity in the area as I’m sure a lot of you are as well and there are some big boys out there sniffing around. You’ve got Apache, Southwestern, Whitting, Samson Resources all drilling wells, leasing acres and it’s going to be something to keep an eye on next year.

Definitely we want to continue to derisk Three Forks in our area and in the same vein flesh out exactly what wall spacing should look like in our current area of operations. We continue to believe there’s a lot more recoverable oil out of this play than people give it credit for, but we need to weld out the support science that it remains early in the life of the play.

That concludes our prepared and I’d like to turn it back to the operator for questions.

Question-and-Answer Session

Operator

(Operator instructions). Your first question is from Will Green of Stephens. Please go ahead.

Will Green – Stephens Inc.

Good morning, guys. I wonder if we could start on the borrowing base. You guys, I think, have another redetermination or meeting in January. Can you talk about how many of the current wells that you have operated are in the $52.5 million base currently? And do you think that -- I am fuzzy on how this works; you guys probably know a little bit better than I do. But could you see performance revisions higher to that $52.5 million? And then how many wells would we be adding to that? Just trying to get a sense for how significant of a change that $52.5 million borrowing base we could see?

Jonathan Samuels

Yeah, happy to address that. It’s an important part of our liquidity. So the $52 million borrowing base, that redetermination was done in early October and just doing off of production numbers, I think we probably had about I’m going to guess nine or 10 wells operated, producing in there and then several of those wells would have been pretty early on in their life and the bank does risk sort of flash production or early – when a well has only been online two weeks they don’t give it a ton of credit. Wait and make sure that curve sells out where you want it to. So by January we would expect to have between 14 and 16 wells online. You’ve got to factor in the nonop portfolio which is a fairly stable component of it. But we do expect the facility to grow. I don’t have a number we want to give, but the credit facility continues to outpace whatever we have in terms of the capital needs that is definitely what our internal model says.

Will Green – Stephens Inc.

Great, I appreciate the color there. Then, you touched on this some in the prepared remarks, but on the LOE side it looks like it came in at about $11.50 or so per barrel total company. Sounds like the operated properties are actually a little bit higher than that currently. As we think about this going forward, obviously you guys are bringing on more operated production. Is the current operated of $14.50, is that a good portrayal, or should we think about some projects that are coming along infrastructure-wise that lower that going forward?

Jonathan Samuels

What it really is more than anything is there’s a certain number of people in the field that we’re hiring and things that we’re doing to support not a 1400 barrel a day number, but a 2,000 or 3,000, 4,000 barrel a day number on a go-forward basis. So when you bring on a field employee whether you produce one barrel or 10,000 barrels in that quarter, you’re going to pay this cost. So really what we want to see is relatively flat total LOE spend, at least on the personnel side and then that’s coming on increasing volumes which drives down the per unit expense. But again, we’re staffing up not for 1,400 barrels a day but for our exit rate and beyond and there’s just a front end loading nature to that.

That’s point one. Part two is within our LOE are substantial costs that will both come down when Caliber is online and then those costs also become Caliber revenues and cash flows. So you’re going to see some of that come in in Q1 of next year with water pipes up and then when our central facility is up in the middle of next year with gas being processed, crude oil being stabilized you may see higher volumes and less lease operating expenses.

Will Green – Stephens Inc.

I appreciate the color. So with all that said, it sounds like employee count is kind of now at a decent level to where you can really manage the business effectively. So are we kind of peaking in terms of operated LOE per barrel? I am not trying to pigeonhole you. I just want to make sure that we are modeling this right so you don't -- we are not surprised on this end on that.

Jonathan Samuels

Yeah. The initial answer I want to give back is yes, directionally on a per-unit basis you are going down. That will make any Bakken operator heading into winter kind of nervous there because if you end up in a month with horrible weather and you’re shut in and you’re still spending a lot of those LOE dollars and the production goes down. So if you were to judge us on a 12 month basis, yeah, we’d be very comfortable saying per unit level is definitely going down. Any given month, particularly in the winter time it can get tough. So just would encourage people to keep that in mind.

Will Green – Stephens Inc.

So it would be fair to say that LOE on an operated basis is peaking currently per unit basis?

Jonathan Samuels

On an annualized basis that would be fair to say.

Will Green – Stephens Inc.

Great. I appreciate all the color, guys. Thanks.

Operator

Your next question comes from David Snow of Energy Equities.

David Snow – Energy Equities

Yeah. Hi. I had calculated the oil and gas operating expenses as almost $21 a barrel. Am I doing something wrong there?

Jonathan Samuels

One second while we look at our sheet here. Yeah, I think that number, David, includes production taxes.

David Snow – Energy Equities

Oh okay, I see. Okay. So I am not sure -- I also saw your implied wellhead price of $81.72. It was $71.72 in the previous quarter. Is that due to better pricing in the basin or some of your infrastructure activities?

Jonathan Samuels

That’s really due to the basin-wide differential. We think our infrastructure will improve next year but it really hasn’t had an impact yet. So that’s just the Clearbrook Bakken price relative to WGI going from a negative to for a period of positive number it was stabilizing.

David Snow – Energy Equities

Okay. And then I am wondering, your land budget is down quite a lot next year. Have you got pretty much most of what you want, or are you seeing prices too high or where do you…?

Jonathan Samuels

It’s really more driven by macro concerns and liquidity concerns and not wanting to need outside capital to fund our program. There is more land in our area and in the Bakken that we like that could be bought at prices that we like. But with today’s share price, not something we want to do at the expense of dilution.

David Snow – Energy Equities

Okay. Is there any chance you’ll go up to a three-rig program next year if things are okay in Washington and in the oil market?

Jonathan Samuels

That’s – we like that world you just portrayed. We unfortunately have spent most of our time in the past couple of months worried about the downside scenario what happens. So we haven’t given a lot of careful thought to that. That problem I guess our business sort of takes care of itself from the upside case. So no, we haven’t really given a lot of thought to increasing our rig count next year at this time.

David Snow – Energy Equities

Could you handle that with the infrastructure and build out of fracking and everything going on at the same time?

Jonathan Samuels

Yeah. We have the people, we have the inventory and our business model will work better at a higher rig count, but again that will be the expense of ultimate shares outstanding and we’re more interested on reserve production cash flow on a per share basis.

David Snow – Energy Equities

Okay. And is there any chance that you will increase the frac stages? I know the Brigham papers had always said that more fracs are better and they had gotten up to 36 and 42. You seem to be modeling on a 31 basis. What is your thought there?

Jonathan Samuels

Yeah. There are some interesting technologies Weatherford is working on, some technology that would – they’re calling it more than a 100 stages. It’s really not more than 100 stages as on an apples to apples basis. But we’re pretty happy with our spacing in terms of in the horizontal portion of our well bore, the distance between each points that we’re pumping in the reservoir right now is pretty good. You can increase stages, but doesn’t benefit you on a per-unit basis remains open. So we’ll of course respond to any developments out there and if we thought there was a better way to do it we’d definitely do it that way. We’re not married to the way we’re doing it. We haven’t really seen anything in the last couple of months that would change our view in terms of completion design.

David Snow – Energy Equities

The Weatherford technology, can you give us a little color on that?

Jonathan Samuels

Boy, that’s a Weatherford question. It’s not something that we’ve used. We had a meeting with them last week and presented it. That was really kind of the first time that I’ve heard about it so I won’t mention it as a directional trend for horizontal shale development. But certainly not an expert and also their technology so better that they speak about it.

David Snow – Energy Equities

And then just last, when are you likely to do some additional ideas about downspacing? Is this an ongoing thing? Are you likely to go to a more dense spacing next year?

Jonathan Samuels

Yeah. I think this is a process that never ends. You continually get better and each part of the basin is going to have a different code that needs to be unlocked. So we definitely are going to be trying out some different spacing and see what happens. But I think this is a process that never ends. You’re just continually trying to get better in terms of extracting oil in the reservoir.

David Snow – Energy Equities

You’re talking about McKenzie being such a hot area, but most of your wells were in Williams. Is that just timing and we’ll be moving more towards McKenzie as we go forward?

Jonathan Samuels

The majority of our well count is in McKenzie County. I think on our press release two wells were mislabeled as being in Williams County, but I think of our 14 wells currently in operation, 10 of them are in McKenzie and the balance are in Williams.

David Snow – Energy Equities

Okay, great. Thank you very much.

Operator

Your next question comes from Jason Wangler from Wunderlich. Please go ahead.

Jason Wangler – Wunderlich Securities

Morning guys. Just curious, you talked a little bit on Montana and obviously we are seeing more and more kind of movement over in that area. In the budget that you guys have set aside is there anything included to go over to Montana, or is it still kind of the wait and see until, let them spend the money and then you guys will move over there when you guys get more comfortable?

Jonathan Samuels

It’s the latter part. We have limited capital for our two rig program. We know we have great wells to drill in McKenzie County. It feeds into our GP Caliber system. RockPile is already there. Field is already there. So we have not been budgeting for Montana. At this point next year obviously industry activity could change that. But we have plenty of lease time left. We have no need to drill. Some active producers out there who are a lot more motivated to add liquids to their portfolio. So we’d rather remain absent, see what they do and then deploy capital when the risk profile changes.

Jason Wangler – Wunderlich Securities

Sure, that makes sense. Then just with RockPile, you mentioned obviously getting all your wells completed and you did a third-party well. Going forward are you seeing some more interest in using RockPile from third parties as now you’ve kind of proven that it’s a viable frac company and they are doing a pretty good job out there?

Jonathan Samuels

Yeah. They’re doing well. Obviously no third party – no one wants to be the first company to use them. So kind of a more rollout of approach versus storming the gate if you will. But they did a great job for the customer they pump for. I believe that job was done about 18 hours faster than any other service provider had done. For this customer and this is a top gen producer by rig count, we’re under a non-disclosure agreement so don’t want to talk about the name, but we believe they’re pretty happy with the performance and as you head into winter and you build backlog again, we are hopeful for increased third party work for RockPile on a go-forward basis.

Jason Wangler – Wunderlich Securities

That is helpful. I’ll turn it back. Thank you.

Operator

Your next question comes from Ron Mills of Johnson Rice. Please go ahead.

Ron Mills – Johnson Rice & Company

Morning, Jon. Question on -- you mentioned the Three Forks and testing. How many of the 14 wells you have operations on, how many have been drilled to the Three Forks so far? And also what are your plans of your planned two-rig program next year? You also mentioned the multiple benches that Continental has done. Do you have any core data or information to provide any pre-drill data on multiple benches where you’re located?

Jonathan Samuels

Yeah. Just taking the second part first, we do have core data and there is a fully saturated Three Forks all the way through. Really our biggest question internally has not been is there oil in the reservoir, but can you actually execute operationally, putting that many wells in the Three Forks, meaning is there a frac there between the third bench and the second bench. Our thinking has previously leaned us towards yeah, you could land a lateral on either bench and it would be successful, but if you have a lateral in the second bench that doesn’t mean you could go put one in the third bench if that makes sense and that’s really due to the as you know fracs want to go up. So rather than fracking the rock immediately around the well bore, we tend to want to go to the well uphole or in the formation.

So we know there’s a well there really which changed our views on we have one pad right now with three wells on it, that is our Larson pad. That well or that pad also has our only Three Forks well. So your first question how many Three Forks wells in the current portfolio is only one and that is largely two inch. You can see in the production numbers it doesn’t look like a great well on that table, but referring back to the earlier comments in the prepared remarks, that well is shut in for a lot of hours during those initial periods. And so those numbers they don’t really reflect the productive capacity of the well. You can see what the pressure will look like and that is the formation we like. So really the next step for us is to go drill Three Forks well on a 1280 that doesn’t have any other wells in it. So you can get an isolated test the Three Forks and then you also don’t have the pad interference problems that we’ve experienced in the Larson 2H. Though Larson 2H was a great test for us.

That’s what gives us more confidence in not being able to move vertically to the reservoir because we really saw no communication in the Bakken part of the Three Forks completion and that’s important. We haven’t hit the boundary yet so we don’t know where it is. But we do know based on our current spacing we’re encouraged and next year we have specifically laid it out. You can kind of make a game time decision on whether you want to get Bakken or Three Forks well. There’s no permitting difference. You just land your lateral a little bit lower. So I would say definitely I’d like to see us drill these two wells in the Three Forks, but that’s going to be driven as a team decision here and we’re also going to want to response to data from the first well and then the second well and if those work great, drill more. If the Bakken wells work better you might drill less. Directionally positive and I think you know how we have approached this. We’ve tried to tiptoe in the risk as slowly as possible and so far we’re liking what we see.

Ron Mills – Johnson Rice & Company

Okay. As it relates to the spacing, you had talked about being in the deeper part of the basin and you think you may even have tighter spacing than what people may think. Are you thinking it can be tighter than -- or you may be able to get more than even four wells per 1280 or are you thinking still four Bakken and Three Forks? Or where are you moving on the potential spacing?

Jonathan Samuels

We’re more comfortable talking about the Bakken as we have more tests there and we have been drilling our down space Bakken wells based on four wells per 1280 and I’ve seen no communication between those wells. So on a go-forward basis we are going to decrease the number of feet between the Bakken laterals. Going from 600 to 500 feet would imply five Bakken wells per 1280. We’re not five Bakken wells in 1280. We’re not aware of anyone else that actually does. So it remains theoretical. But on a pad when we put four wells, you’re developing half of the 12 ESF as if you could do the same thing on the other half.

Ron Mills – Johnson Rice & Company

Right. Okay. Will you start that in your fiscal 2014, testing the five wells per?

Jonathan Samuels

We will not drill five wells in a 1280 next year, but we will be…

Ron Mills – Johnson Rice & Company

Test the space?

Jonathan Samuels

Putting Bakken laterals on a spacing.

Ron Mills – Johnson Rice & Company

Okay. And then could you provide just a little bit more color on the gas lift versus the rod pump, and provide some sort of order of magnitude in terms of efficiency or relative improvement with rod pump versus gas lift and what the trade-offs are?

Jonathan Samuels

Yeah. Overall our experience with gas which is when it’s working and when it’s online is much better. There’s two things you need for gas lift to work. You need a steady supply of gas which is obvious I guess and then you also need a minimum bottom hole pressure for it to work. And the two things we’re seeing is when you don’t have a network and as a reminder, Caliber is building gas line right now but that’s not connected yet. You are dependent on gas from other wells in that pad for your gas lift. So if you have Larson 3H supplying gas for gas lift on the Larson 1H, when the 3H goes down the 1H goes down too. That wouldn’t necessarily be the case with rod pump. So it’s really a network effect and on the gas side we want to wait till we have a network to buyback that gas for all of these, but also what we’re seeing is really reflected in the downspacing. This is where the deep type reservoir and the period of time in which gas lift works your IP well has certain bottom hole pressure and then there’s a pressure decline and when it crosses a critical threshold and the specific numbers aren’t important, the theme is more important.

When you cross that threshold basically gas lift ceases to work and you have to switch to rod pump. So we were always planning to make that switch at some point in time. It’s just happening sooner than what we thought and part of the reason for that are the same reasons we think the downspacing is harder. You don’t have the metrics permeability that you have in partial and partial obviously that drives per well performance. But they’re going to be able to drill a lot less wells per unit over there. So that’s sort of fanatically what’s going on with gas lift as we move to rod pump. The magnitude of the impact it was material. I would say that our productive days and productive hours, this is not an actual production number and please don’t take it that way, could have been (inaudible) higher.

Ron Mills – Johnson Rice & Company

Okay.

Jonathan Samuels

Basically as we sat down last week planning this and we looked across our operated wells. You have all of them on rock pump producing on the same day it would basically be at our year-end guidance.

Ron Mills – Johnson Rice & Company

Got you.

Jonathan Samuels

Or you can see what the production was. So and every operator is going to deal with downtime and exit rate or production in a quarter is going to be reflective of that. You’re not going to be 100%. No one is, but we would like to be better than our peers. We’d like to be better than where we were and this is a transition that takes four weeks.

Ron Mills – Johnson Rice & Company

Okay. Then one last one on RockPile, the operating margin was a bit higher than what we were expecting and I would assume that the move here in the fourth quarter to be on full 24 hour operations that that financial impact can even grow relative to third-quarter. When did you switch to 24 hour operations? And then one corollary is the six wells that you announced in the release, when did those wells come online?

Jonathan Samuels

Sure. On the first part of RockPile, I think they did their first 24 hour job in October. But I’m not 100% sure about that. It might have been September, but it was in the last couple of months. The thing about these margins, that’s corollary number and RockPile today has 76 employees and there is a not insubstantial year-end compensation that comes for the management team and the operational team if they hit their targets. So keep that mind as you look at margins and we certainly would not guide you towards margins expanding. The other thing about 24 hours is if you stay busy it results in your margins improving. If you’re not busy it hurts you because you have to have more crews to work for 24 hour rotation than you do in 12 hour rotation. Until they get more third party work, it’s actually more profitable to be 12 hours than 24. You go to 24 you also get through your work a lot faster which goes without saying. So regarding RockPile margins, Q4 may look slightly down. The costs are also coming down on the pumping side and that will eventually flow through of these costs and on the commodities on all fronts.

Ron Mills – Johnson Rice & Company

And then the timing of the well hookups? I am just curious, the 2,000 barrel a day exit of October versus where you may be here in early December. Trying to get a sense as to where you are currently versus the end of the quarter. I just don't know when the last batch of six wells came online.

Jonathan Samuels

Yeah. Today we’re not terribly different from that exit rate and that’s really again we are on location making exchanges to our artificial lift design and installing rod pumps and we are downspacing and fracking some wells. So we are – the only guidance we give in this year to the Street is our exit rate production guidance. That’s really the only one. That 2600 or 2000 barrel a day number and that has been our key focus. People in here are referring to the super bowl league. But we’re doing everything we can for that and we had our first storm in North Dakota a couple of weeks ago and kind of shakes everyone up, reminds people winter is coming and things can go bad in January. So as we sit here nearly in the middle of December there’s a lot of work going on right now. So we’re sure we don’t have to do the last 10 days of the month in January. So we don’t really feel today’s production which is not terribly different than the exit rate is a good measure of the productive capacity of this company going into winter.

Ron Mills – Johnson Rice & Company

Okay, great. Thanks, Jon.

Operator

Your next question comes from the line of Jack Aydin from KeyBanc. Please go ahead.

Jack Aydin – KeyBanc Capital Markets

Hi guys. Most of the questions were answered, but let me ask you this way. What is the threshold price for you to drop one rig? Because you mentioned that you could be nervous and you might drop one rig and you reduce CapEx level. What is that threshold?

Jonathan Samuels

There’s kind of two components to that decision and I’ll talk about both. The simple answer is what you saw crude oil drop below $70 WTI number for some period of time, 10 trading days, 15 trading numbers, that would really just make us nervous because of access to capital. Our stock, along with presumably every other E&P company, would be down substantially and that’s the time to preserve cash for other opportunities. Another driver to that is in our vertically integrated model. Our economics change based on our working interest in a well. So obviously the higher working interest, the more CapEx per well we’re responsible for and the less RockPile revenue and cash flow we get to book. So one is a component of oil price. The other is a component of what other people in the basin are doing. I think a simple way to put it, you see a – handle on oil, us and a lot of other folks are going to get nervous and that’s when you’d see us potentially drop that rig.

Jack Aydin – KeyBanc Capital Markets

Jonathan, on DD&A, the absolute DD&A was about almost $4 million for the quarter. What percentage of that was the E&P and what percent was RockPile and others?

Jonathan Samuels

Give me just one second to look at that number please Jack.

Jack Aydin – KeyBanc Capital Markets

Sure, no problem. While looking at it, let me ask this question. On Montana --

Jonathan Samuels

Before you go, I’ll forget the number if you ask the second question.

Jack Aydin – KeyBanc Capital Markets

Okay, I will wait.

Jonathan Samuels

On page 11 of our 10-Q it breaks it out and it was about 3.3 million for the E&P side and the balance was RockPile.

Jack Aydin – KeyBanc Capital Markets

Okay. Regarding Montana, I know your cost is low. Would you entertain monetizing that portion of that going forward in order to do -- supplement your CapEx or cash flow in a way?

Jonathan Samuels

I think the more – if you were going to talk about a monetization it would be more of a partial monetization to fund development in Montana. So it’s something that we like and we think has a lot of upside and obviously if Montana works, it really changes the total operating inventory. Up front our goal has always been to increase total operating inventory because we think that drives the strategic value of the business. You could potentially see us do and I can say the consensus internally is bringing a partner to help us develop that so that we can effectively expand our CapEx without having to put the burden for paying for it on our shareholders. But do I see us going to Montana next year? That’s’ not something that we’ve considered.

Jack Aydin – KeyBanc Capital Markets

Thank you very much.

Operator

Your next question comes from Jared Lewis from Northland Securities. Please go ahead.

Jared Lewis – Northland Securities

Morning, guys. A lot of questions have been asked, so just curious looking at the wells and the proppant. Half of them were 100% ceramic, the other one is 25%. Obviously that would be a big difference on the cost; just kind of what you see going forward.

Jonathan Samuels

Yeah. McKenzie County is going to be 100% ceramic play for us, particularly in our state wells and Williams County, we did use a blend and are very happy with those well results there. So I think we’re going to continue to just use a blend in Williams County and 100% ceramic in McKenzie which is deeper and hotter.

Jared Lewis – Northland Securities

Okay, thanks. And on Caliber, just curious; you mentioned you were laying out the pipe. How is that going between the gas, dealing with the water, oil? Are you focusing on one versus the other? Just a little more color on that.

Jonathan Samuels

Yeah. All the pipe is going to be in the ground. There’s two components to Caliber being completely done. That’s the pipeline network tying into the wellhead and then that’s the essential processing facility and the central processing is going to have a crude stabilization unit of 10 million a day gas processing unit and that’s going to be online next summer. So the gas pipe is going to be in the ground before the gas processing is online, which basically means the gas pipe is going to wait for the processing plant. So we do expect to have the majority of our phase one water line completed by January which obviously makes us happy to be able to pipe versus drop water in the winter time. But maybe simple way to think about it, that you’re four year 50% done with the Caliber build out in January and you’re really waiting for that central facility before it makes a meaningful impact.

Jared Lewis – Northland Securities

Very good. Thank you.

Operator

Your next question comes from Blaise Angelico from Howard Weil. Please go ahead.

Blaise Angelico – Howard Weil, Inc.

Hey good morning guys. Just one quick question. Can you guys talk a little bit about what you’re seeing in some of the earlier wells you’ve completed just in terms of how they’ve performed over a longer time horizon?

Jonathan Samuels

Decline curves kind of where you’re questioning?

Blaise Angelico – Howard Weil, Inc.

Yeah. Like your 30, 60, 90 day type rates.

Jonathan Samuels

Yeah. We actually posted the 30, 60, 90 day rates on our website. Its’ going up today. I don’t think it’s online yet. We work weekends. Our website posting company just doesn’t. But we are pretty happy with them and we were concerned going in to the operating program. So our 90 day numbers are exceeding our expectations. Our expectations were perhaps conservative compared to some others. But we’re definitely happy with what we’re seeing.

Blaise Angelico – Howard Weil, Inc.

Perfect. Great. Thanks guys.

Operator

Your next question is from Dan McSpirit from BMO Capital Markets. Please go ahead.

Dan McSpirit – BMO Capital Markets

Thank you folks. Good morning. Following up on that last question, what do you estimate or model for the first year decline rate?

Jonathan Samuels

In what sort of metric, the percentage or…?

Dan McSpirit – BMO Capital Markets

Percentage, yes.

Jonathan Samuels

To be honest, we really just don’t think about it that way because the flush numbers are so somewhat meaningless. So like measuring what it’s doing at the end of the year as a percentage isn’t really how we think about it. Let me think of a constructive way to answer this question is we are seeing these wells stabilize at a couple 100 barrels a day with artificial lift and depending on how we IP the well and how it’s being completed, sand versus ceramic, we’re seeing these wells stay online pretty strong. Remember we don’t have a single operated well that’s even a year old. So for us I think we’ll be in a better position to comment on that on our year-end call in April when you would have a couple of wells that are 11 months old. I don’t know if that actually answered or helped your question in a way, but…

Dan McSpirit – BMO Capital Markets

No, I understand. Yeah, I understand that the sample set is small and the production history is limited on those wells that you have operated. At what point in the well's life do you observe that stabilized rate of a couple hundred barrels a day?

Jonathan Samuels

We have some wells that have been online for four, five, six months and they’re just kind of chugging along and the bottom hole pressure looks good. We see that at our state well. We see that in our Freddie James well and others. So it’s a small sample set, but we are liking what we’re seeing.

Dan McSpirit – BMO Capital Markets

Okay. And Jon, in your prepared remarks and speaking about RockPile, you spoke to F&D costs. Can you give us a sense in your analysis of the benefits of the vertically integrated model, what F&D costs may be on a BOE basis would be with and without the benefit of RockPile?

Jonathan Samuels

How we sort of allocate it internally is we have – we charge ourselves for the capital put and the RockPile and we have a $20 million investment in RockPile. We use a 20% cost of capital number. So you get approximately $4 million a year of capital costs. So anything that we are above $4 million internally and not that this matters externally, but just when we’re talking about how we think about it, we would talk about from our total capital spend. So you look at RockPile this quarter, we don’t consolidate Triangle share of working interest. So if you look at the footnotes and the financial statements you’ll see what RockPile did as an entire company and we would charge ourselves for a piece of that capital and we have adopted and we’re sort of in like 10% to 15% rebate if you will on CapEx. Now that’s based on certain working interest. If your working interest goes up the rebate as a percentage goes down.

Dan McSpirit – BMO Capital Markets

Okay, got it and with respect…

Jonathan Samuels

Same way if you had $20 F&D cost, that would knock off $2, $2.50 a barrel for RockPile which we think is very meaningful.

Dan McSpirit – BMO Capital Markets

Right, got it. Turning to Station Prospect, lease terms there. Can you remind us of what those are?

Jonathan Samuels

About three and a half years.

Dan McSpirit – BMO Capital Markets

Okay. Is that three and a half years remaining?

Jonathan Samuels

Remaining.

Dan McSpirit – BMO Capital Markets

Okay, all right. And then your average royalty on these operated wells?

Jonathan Samuels

80% of NRI.

Dan McSpirit – BMO Capital Markets

Your NRI?

Jonathan Samuels

That would be very painful royalty. 80% royalty burden.

Dan McSpirit – BMO Capital Markets

88% you said NRI?

Jonathan Samuels

80%.

Dan McSpirit – BMO Capital Markets

Okay. Thanks.

Operator

Your next question is from David Peterson, shareholder.

David Peterson – Shareholder

Good morning gentlemen and lady. This is really a crystal ball type of question as relates to the shelf offering authorized last quarter. I would assume that NGP 15 million share conversion will come out of that?

Jonathan Samuels

I’m not a securities attorney, but I think we would have to file something else for NGP. I’m not 100% sure.

David Peterson – Shareholder

Okay. And can you just share a little bit about if there’s any immediate plans for that to come off the shelf?

Jonathan Samuels

We have no immediate plans. We had almost 130 million and still have 130 million on our previously filed shelf. So that was really more just of a housekeeping item. It’s actually something we’ve gotten a little bit surprise and there’s a lot of questions about. Every public company out there has a shelf.

David Peterson – Shareholder

I know. There’s a lot of people nervous about that and I don’t understand it.

Jonathan Samuels

Well, and more of our driver and we’ve never gone high yield this company and as we kind of learn more about that path, a lot of those are done as product placements. But that was part of it was just let’s get the good housekeeping done. We went through our proxy. We reincorporated in Delaware. We adjusted our share count. There are a number of things that we did at year-end that were just kind of corporate structure platform that gives you the flexibility to do whatever you may want to do. It doesn’t mean you’re going to do anything. We actually thought doing it right on the heels of an NGP investment would be a clip signal that a capital raise was coming while we have just done a deal with NGP.

David Peterson – Shareholder

Okay. Thanks a lot.

Operator

Your next question comes from Ron Mills, Johnson Rice. Please go ahead.

Ron Mills – Johnson Rice & Company

Hey Jon. Just one or a couple last ones just on the operated program. You talked about the ceramic versus the mix. Is there any appreciable cost difference? Looking at your presentation, the average cost for Williams and McKenzie County are about the same. Should those costs start to diverge as Williams is not necessarily in the deepest part and you are using some white sand along with the ceramics? Or what’s driving the well cost?

Jonathan Samuels

Yeah. We’d see those be a little wider. I thought that they were lighter in our presentation. I guess they’re not, though it’s not material. But it does make a difference. The profit alone should be $600,000, $700,000 per well.

Ron Mills – Johnson Rice & Company

And then are you expecting any appreciable difference in EURs between Williams and McKenzie? And can you refresh our memory what your expected type curves suggests from an EUR standpoint?

Jonathan Samuels

Williams may be a little lower and it depends on where you are. In Williams we have some stuff up in 157 and then we have some wells closer to Williston. Our state units in Williams County are amongst the best wells in our portfolio. The Washington wells we have kind of internally modeled the 400 to 450 type EUR and you see those now being a little bit north of 500. You move closer to the river, I think you get more of that 550, 600 range which is in line with how we’re thinking about McKenzie County. So across our portfolio we continue to see our wells as between 500 and 600 on a BOE basis gross.

Ron Mills – Johnson Rice & Company

Okay. And if you look at your operated program for next year, the -- I think it’s $128 million, do you have any ideas in terms of how many wells you might drill? And I know the average working interest will vary depending on what you end up drilling, but is it safe to assume that you will still be somewhere in that plus or minus 50%, 60% average working interest?

Jonathan Samuels

Yeah. I would say it’s more – the range is 45 to 55 percent of working interest on it. We’re going to run two rigs so we will drill 24 wells. I’m sure there’s some wells that we’re drilling in January that will be completed in February or beyond and then the same thing, there’ll be wells drilled in December or January next year that might not be complete till the next fiscal year. So you can expect us to do 23, 24 wells gross and it just depends on our working interest and that’s obviously a subject in non-consent rig rates which is driven by macro and other things. So that’s why you also see it as kind of a $9 million other number in our budget which is sort of – we’re probably going to go over in some and under in another, an element of conservatism.

Ron Mills – Johnson Rice & Company

Great. All right guys, thank you so much.

Operator

Your next question comes from Adam Fackler from KLR Group. Please go ahead

Adam Fackler – KLR Group

Good morning. Jon, now that you have provided fiscal 2014 budget I was hoping you might be able to add a little color on what type of production growth this level of spending could imply for next year?

Jonathan Samuels

We’re working on that. We’re not prepared to talk about that today. Really thinking that’s going to come out in January or February. There’s downspacing tests that need to get done. We’re making this shift from gas lift to rod pump. We still remain really focused on this year’s target which is 2600 to 3200. We’re well positioned for that, but we don’t want to take the teams focus off of this year or next year just yet. So definitely understand where the question comes from and it is an important question, but we still have Q4 to solve and ahead and we’ll be talking about what sort of production levels this budget gets shareholders at the appropriate time in Q1.

Adam Fackler – KLR Group

Fair enough, I appreciate it. The rest of my questions have been answered, so that is it. Thanks.

Operator

And now I’d like to turn the call over to Jonathan for closing remarks.

Jonathan Samuels

I’d like to thank everyone for joining and look forward to talking to everyone during our next call which should be in April with our year-end results. Thank you. Happy holidays.

Operator

Thank you for your participation in today’s conference call. This concludes the presentation. You may now disconnect. Have a good day.

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