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Executives

Jonathan Samuels - Chief Executive Officer, President and Director

Justin J. Bliffen - Chief Financial Officer

Analysts

Jared Lewis - Northland Capital Markets, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Dan McSpirit - BMO Capital Markets Canada

Dan McSpirit - BMO Capital Markets U.S.

Eli J. Kantor - Iberia Capital Partners, Research Division

Triangle Petroleum (TPLM) Q3 2014 Earnings Call December 10, 2013 10:30 AM ET

Operator

Good morning, and welcome to the Third Quarter of Fiscal Year 2014 Triangle Petroleum Corporation Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Jonathan Samuels, President and CEO. Please go ahead, sir.

Jonathan Samuels

Good morning, everyone, and welcome. We appreciate you taking the time to listen in. My name is Jon Samuels. I'm the President and CEO of Triangle, and I'm joined today by our Chief Financial Officer, Justin Bliffen.

Before we begin, I'd like to point everyone to our forward-looking statements disclosure in our press release, our presentation on our website.

As I think, you can see in our press release, our business is growing across-the-board. Current production is up at our core E&P business and ahead of our expectations, with approximately 7,400 barrels of oil equivalent per day production. We are on track to meet our revised production guidance number of 7,500 to 8,500 BOE a day for the year. As a reminder, we define our exit rate as a 21-day average end of January 31. So about 3 weeks of average production, not a single day.

Sold volumes are up significantly from the same period last year and quarter-over-quarter. We are realizing an increase on our productivity per rig and modifications to our completion design are resulting in wells with better EURs and lower capital expenditures. We continue to see the value of downspacing as tests show better results than we have previously expected. Over 60% of operator producing wells are connected to gas sales.

Our completion techniques are improving, and we have seen some great results this last quarter. We reduced the gel pumped into our wells by 50% by utilizing slick water flushes, which results in less gel damage in the formation and a lower cost. We increased our pump rates to 30 barrels per minute from the previous 24, due to increase our stimulated rock volume. And we are currently working on 2 separate liner tests to increase isolation between perf clusters within individual stages. So a lot of exciting things on the completion side of things over the next couple of months.

We have high capacity utilization on our RockPile Energy Services business, and we see huge runway for growth ahead. RockPile completed 9 triangle wells and continues to grow its third-party business with 19 jobs for the third quarter to healthy backlog. RockPile will bring on its third back spread in the coming months as demand for quality services in the Williston Basin continues to remain high. Wireline services performance is strong and pump services continues to build momentum.

We're continuing to see the strategic value of Caliber Midstream, which currently has over 75 miles of pipe in the ground and has successfully delivered water to 8 triangle fracs. Caliber continues to make significant progress towards the buildout of its system with the gas plan expected to come online in early 2014. Caliber also executed its first third-party contract in October and continues to pursue numerous additional third-party opportunities.

As a management team, we're excited about the quarter and our best progress of our 3 businesses. A reminder of our strategy statement, we're 100% focused on the Bakken. Our objective is to be low cost producer in the Williston Basin. We want to make money for our shareholders regardless of oil prices, we want to be sustainable and profitable over the long term. We feel strongly that our vertically integrated model allows us to execute our strategy. And with that, I'll pass it over to Justin to review our financial results for the quarter.

Justin J. Bliffen

I will walk you the financial results for Q3 fiscal 2014 ending October 31, 2013. As Jon mentioned, Triangle USA, our E&P and core business, grew quarterly sales volumes to 626,000 BOE, 390% growth year-over-year. This represents average daily production over the quarter of approximately 6,800 BOE per day, which is up nearly 60% from the previous quarter.

Triangle USA generated revenue of $55.5 million and adjusted EBITDA of $40.5 million. This is tracking well ahead of our previously stated guidance of $46 million to $50 million of revenue and $32 million to $36 million of EBITDA in Q4 of this fiscal year. Triangle spent approximately $79 million in consolidated operated and nonoperated drilling and completion CapEx during the quarter, which includes nearly $12 million in intercompany eliminations from RockPile and Caliber.

RockPile Energy Services, our wholly-owned pressure pumping subsidiary, generated standalone revenue of $66 million, adjusted EBITDA of $13 million. This is also tracking well ahead of previously stated business segment standalone guidance of $58 million to $64 million in revenue, and $12 million to $15 million in EBITDA for Q4 for RockPile.

In October, RockPile completed its acquisition of Team Well Service Incorporated, an operator of 3 well service rigs in North Dakota in exchange for approximately $9 million.

Caliber Midstream Partners, our 30% owned joint venture, generated $1.2 million in revenue and $600,000 in adjusted EBITDA, that to our 30% interest.

On a consolidated basis, after elimination of intercompany profits related to Caliber's services to Triangle USA, we did not recognize income or loss from our equity investment for the 3- and 9-month period ending October 31, 2013. As I've stated before, standalone business segment reporting offers a clear snapshot of discrete business performance and provides a measure against previously stated standalone guidance. Allocation and elimination detail can be found in Note 3 of our consolidated financials. If the respective business segment performance continue at this pace for the remainder of the fiscal year ending January 31, we expect to meet and likely exceed all of our previously released fiscal year 2014 standalone guidance without any increase in our CapEx budget.

On a consolidated basis, our basic earnings per share was $0.22 for Q3 fiscal '14. When adjusted for noncash and nonrecurring items, which includes the mark-to-market derivative gain of $2.1 million, we earned adjusted net income per basic share of $0.19. It is important to note on a consolidated basis RockPile and Caliber has saved Triangle nearly $30 million in well cost year-to-date.

We tapped multiple sources of capital over the past quarter, primarily to fund resold [ph] acquisitions in our expanded E&P drilling program. Sources included public and private equity of approximately $180 million as well as $110 million quarterly increase in our Triangle USA reserve base credit facility. By quarter end, we had over $100 million in cash and $130 million in revolving -- in revolver availability, that's between RockPile and Triangle USA.

The next Triangle USA revolver determination will be in January 2014. Excluding the NGP note, which is convertible into shares of common stock at $8 per share, we have approximately $170 million in debt. Leverage metrics improved over the period to 1.1x total debt to annualize adjusted EBITDA from 1.2x in Q2 fiscal '14, excluding the NGP note. We continue to use zero cost collars and now swaps to provide more certainty around price realizations. As of the quarter end, we had 4,300 barrels hedged for the balance of fiscal year 2014 with a volume weighted average forward of approximately 88-30 and a ceiling of 103-50. For fiscal 2015, we had approximately 3,300 barrels a day hedged with volume weighted average floors of approximately $85 and ceilings of $100.

Overall, the 3 business segments continue to outperform, and cash generated by each will allow us to reinvest in growth without sacrificing our disciplined approach to our balance sheet. In January, we anticipate releasing our fiscal year 2015 budget and guidance figures to provide insight into next year's plans. With that, I'll hand it back over to Jon.

Jonathan Samuels

We'll open up for questions in a minute. As a management team, we continue to be excited about the growth we see and continue to see in the future. As a reminder, we're focused on building value over the long-term and really look at our business, what it's going to be like 12 months from now, 18 months from now? And as we go through our budgeting process and planning process for next year, which is not quite done yet, all 3 businesses can double in that 12- to 18-month time period, and that's what we're focused on achieving. That's how we think we create value. So a lot of exciting things going on. The Williston Basin remains a top place to operate, it's temperature is something like to negative 20 degrees right now. That makes life on the ground tough, but we're committed. We show up to work everyday, and we have a great team that does the same thing. So we're excited about the future and we appreciate taking time to listen in.

With that, we can turn it over back to the operator for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question will come from Jared Lewis of Northland Securities.

Jared Lewis - Northland Capital Markets, Research Division

I was worried just on RockPile, just looking at Q2 to Q3, you just kind of look at on a standalone margin basis. The percentage went down. Can you just give a little detail on maybe pricing environment or what you're seeing that might encounter for that?

Jonathan Samuels

Yes, actually, the numbers don't really tell the truth, because we had a number of new business lines starting up. We brought on our second frac spread. We brought on wireline. There's a bunch of business segments that are expanding, and you have to staff up ahead of that. You need to train people. You need to get equipment tested and online. So what you see in Q3 is a lot of overhead costs that we can't allocate to any well, so they end up in our income statement; they didn't generate revenue, and that's just pure build for the future. So I certainly understand where the question is coming from but the numbers actually hide what is a very positive trend in that business. Pricing is stable to up in some cases with some other customers. And overall, they're doing well.

Jared Lewis - Northland Capital Markets, Research Division

So going forward, you'd see kind of back to that Q2 kind of mid-20 type level?

Jonathan Samuels

I mean, it's kind of going to be one step back two steps forward, over and over again, because we have our third frac spread on order. That's going to come online in the first 3 or 4 months of next year. So you're going to have startup costs related to that. So I mean, I think, as you'd see with any high-growth business, you're going to see cost due to headcount and other ahead of the revenue coming. So I think you'll continue to see improvement in that business overall. And you have to be mindful that Q4 -- our Q4 is the months of November, December and January, which are very, very tough operating months in North Dakota. And when it gets cold enough, you take your guys out of the field, you're still paying them while they're sitting inside somewhere warm before they work again. So we don't want to sit here today and say Q4 immediately goes back to that. But I think if you project forward and compare year-over-year with next year's Q2 look like, we would expect to see better than the past one, if that makes sense. So just want to caution people against -- there is seasonality in the business. And if you don't take that into account, sometimes it cannot look great.

Jared Lewis - Northland Capital Markets, Research Division

Okay, that's helpful. And I guess on a follow-up, that was kind of reflected in the increase in the G&A from Q2 to Q3, going from 7 to 10.5 or thereabouts?

Jonathan Samuels

Yes, I mean that's again built for these other business lines and equipment. And its -- this quarter, to be honest, from our perspective is a little bit noisy because costs are higher than what you would see. I mean, if we were running this business for profitability of this quarter, it would be a very different outcome, but we're building the infrastructure and the people to where we think it's going to be next year, which is double where it is now.

Operator

Our next question will come from Mike Kelly of Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Jon, I know you got a pretty small sample size right now of your latest wells here, with these tweak completion approaches. But just hoping we could dive into that a little bit further here, because your latest 4 to 5 wells with 60- to 90-day rates are significantly higher than what you have posted previously. And just wanted to get your sense on how repeatable is this? And what this ultimately means for kind of an incremental uptick to EURs and just ultimate rates of return?

Jonathan Samuels

Yes, Mike. We're increasing the efficiency of our completions, and you could define that really as the barrels you get out of the ground per dollar spent, so you can drop cost, get the same, recover more, spend more. That's ultimately what drive returns and that's what we think about it. And the general trend is very, very positive, so I guess you're -- minding the NDIC and good on you for pulling that out. I mean, you're right, our wells are getting a lot better. We don't stop to talk about it, because we don't think we're done. One of the big things we're trying right now is a cemented liner and we're literally flowing back, and have been for 7 days on that first test, which doesn't put us in a position of wanting to talk about the results. We can tell you directionally that our well performance is getting much better than it was a year ago, then it was 6 months ago, and we're spending less. So I'm really attacking both sides. And as we learn more about our part of the basin -- we're in a unique area where completion designs that people are using in other parts of the basin, be it slick water [ph], be it 24/40 [ph] white sand, that's not optimal for our area. The benefit we're going to get out of our area is we think our downspacing potential is much, much higher than a lot other places. So we're going to get a lot of wells in middle Bakken and a lot of wells in the Three Forks, and the wells are getting better. So in terms of actual EURs, that's a tough one because you want to get some production data and you want to see what the tail looks like, and then ultimately, you need your third-party engineer to come in and agree with you. The trend is definitely very, very positive.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Great. That's helpful. And then just switch gears a little bit, just was hoping to get just kind of a step-back and take a look at Caliber, and I think your September press release there, it talked about really First Reserve upping the commitment to it. And putting out some pretty exciting expansion details there too. So just we've got the EBITDA guidance for what that business looks like this year, but just if you could frame it to what Caliber could really look like a couple years out where you've gotten a 50,000-barrel pipeline fully up and running, processing plants out, what does this look like in terms of its EBITDA potential? And maybe just help with the timing of that too.

Jonathan Samuels

Yes, I mean, you look at this year's guidance, you look at next year's guidance, and Caliber is the only business line that we put out guidance for next year. There's no third-party revenue in any of those numbers. And infrastructure is the name of the game particularly in the winter months in the Williston Basin. So I mean, we take the view that, that over time, Caliber will achieve similar results to what RockPile has achieved. And it took RockPile, if you guys remember, when we were on this call last year, that they were just starting to get some traction with third parties. And then you fast-forward to this quarter, and they're doing twice as many jobs for other people as they are for us -- not quite that, but directionally, you know what I mean. So the key for Caliber and the third-party business is getting their system online and running, because if you are a third-party customer, why do you want to commit to a system that isn't online yet? It's a long-winded preamble to answering your question, which is we think there's a lot of upside to the Caliber numbers now. How do you quantify that? We don't know what other people in the basin are going to do. We can tell you that if we achieve just half capacity utilization of the existing systems that's already been built, EBITDA on a [indiscernible] basis goes over $100 million, and that is not a big stretch to get there. And you would still have spare capacity in the pipeline. So the earning power of this, of the Caliber business -- of the Caliber system, is quite large, but we have to go out and execute. We have to get the plan online and the pipe in the ground, and Caliber has to go through what RockPile has successfully done, which is that they are a reliable third-party service provider to other operators in the business, and that's not just something that only serves only Triangle, which is not the case for either business. But there's only one way to prove that, and that's you got to go out and do it. And we're excited. I mean, Caliber I think is the most, what's the right way to frame it? It's still early in the development. It's hard to put a value on it, but it has the most upside of any piece of our portfolio relative to current expectations, you could say. So it's something that we're getting a lot of interest in. If you guys follow the infrastructure, and then NLP markets, there's really been 3 transactions in the Williston Basin, that's Bare Tracker, Arrow and Saddle Butte all getting acquired at quite generous multiples relative to what we're used to in E&P. If we get 6x or 7x next year's EBITDA, we're pretty happy. These are businesses that trade at 15x, 20x and then you pay a growth premium, some of these transactions are 20x, 30x that quarter. So the upside in Caliber is huge and we're a 30% owner of that. And you got to keep in mind that we have a warrant package, a Triangle, that can make us up to 50% owners of that business over time. So it is exciting,

Operator

Our next question will come from Ron Mills of Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Jon, I might just ask one little question on the wells, just a little bit more, I mean, a detailed question. But your 30-day, 60-day and 90-day rates on your most recent 9 wells you've completed during the quarter are 40% to 50-plus percent higher than your prior 29 wells. How does that compare with the kind of -- I guess, trying to compare how you forecast or what EURs you're using for court forecast standpoint versus that kind of performance, because the important thing is it's even holding up over the 60- and 90-day rates. I'm assuming that's partly what's driving the well performance and the production beat you had during the quarter and the exit rate. Those changes, do you know which of those changes were probably more impactful for those rates?

Justin J. Bliffen

Yes. So Ron, good question. Absolutely, Jon alluded to in his previous question, wells are getting better. The engineers are doing what engineers do, figure out ways to do it faster, better, increase reservoir optimization, and also at cheaper well cost. Now we are putting this data on our webpage, 30-, 60- 90-day numbers for every well completed. Is very transparent and that is updated quarterly on our webpage. To your question, yes, we are increasing the model. I think in the past, we have always met and beat our guidance that we put out there, and that's because we strive for accuracy with a touch of conservatism. Just like as differentials or crude oil price change, and we have to tweak our model. As our EURs are going up, we are considering tweaking the model higher. I can say guidance has been out there and it's probably on the lower EUR well than what we will be putting into the model for next year.

Jonathan Samuels

Yes, I mean one of the biggest things is you're going to get EURs and you also have down time. And one of the big drivers of productivity, we've talked before about the trade-off in terms of when you drill the downspacing well -- sooner is better. So one of the downsides to that is when you go reoccupy a pad, you're producing well or wells are going to be shut in, and that's a tough thing for us to model. So we're trying to balance out our financial guidance, our production. We're trying to do the best thing for the reservoir long term. Safety, [indiscernible], has to come first and so we're probably more conservative than we need to be in terms of shutting in wells, but that's the right thing to do because we are actually going to post an Analyst Day next summer and have you guys all up in the field, I think in the July, and you can see it. But when you have 2 or 3 wells producing and a drilling rig on that location, there's a lot going on, so...

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Can you explain a little bit about how the process of the simultaneous operations? And that was a pretty big impact on this quarter alone, but how that helps soften that or smooth that impact out going forward?

Jonathan Samuels

Yes. I mean, if you drill 3 wells, frac them, and those are producing, 9 months later, you'd expect each of those wells to be doing some 200 or 300 barrels a day apiece, that's a gross number. So I mean if you put a drilling rig back on that location, I would say over the next 3 to 6 months, you should expect 30 to 60 days of downtime that those wells aren't producing, and that adds up. So the sign-off does have a benefit of smoothing out, and that was -- we talked about it last quarter, about our remote fracs and how that allowed us to continue producing while we completed down spacing wells, and I think our team has done a great job of improving that. You saw in this quarter, we put it in the press release, something like 500 or 600 barrels were produced in the quarter because of us tweaking the design. But a lot of this is new to us, and it's new to everyone else. When you talk about the other operators out there that are doing this, we've haven't been doing it that long as an industry in the Williston Basin. So there's still learning to be done and we're kind of cautious about it.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And you've mentioned a couple of times the down spacing. What are you testing now in terms of the way you're laying out these pads in terms of potential spacing, whether it be via Bakken and/or up at Three Forks and/or thoughts on the lower benches?

Jonathan Samuels

Yes, I mean, our -- we continue to test 600-foot spacing for the middle Bakken and have seen no communication. We recently tested the Three Forks and frac-ed 2 wells that were offset on the same spacing and saw no communication. So we don't have production results from those Three Forks tests. But from a spacing standpoint, we saw no communication. Regarding the lower Three Forks, I think you got a remember in our area, we talked about the lower Bakken dolomite, and we see that as a productive zone and we see the upper Three Forks as a productive zone. I don't think you're going to get lower than Three Forks in our area, but you still have the same number of opportunities because if you can put 6 to 8 wells in the lower Bakken dolomite and however many wells in the upper Three Forks, that's kind of achieving the same thing, you have 3 targets, the middle Bakken, lower Bakken dolomite. Upper Three Forks, other operators -- other areas in the basin, they're going to have middle Bakken, upper Three Forks, lower Three Forks. So a lot of this goes to how much rock sits between the lower shale, which is a prolific source and other factors about where you are. So we say in our operations meetings, as each month that goes by, our inventory increases, even though we're drilling wells, and the reason we say that is because each month that goes by, we get a new data point and new test, we realize we have a lot more wells to drill than we thought a month ago or 2 months ago. And the increase in that number is a larger number than the number of wells we drilled the past month. So it continues to be on trend with what you're hearing from pretty much everyone in the basin consistently now, which is they're going to get a lot of wells in the 12-80 when you go out 10, 20 years.

Operator

Our next question will come from Dan McSpirit of BMO Capital Markets.

Dan McSpirit - BMO Capital Markets Canada

What is the cost of a frac spread today versus, say, when you first got into the business?

Jonathan Samuels

Maybe 7% to 10% less. I'm shying a little bit away from dollar terms, because it's cheaper to bring on your third spread, than it is the first one where you need everything.

Dan McSpirit - BMO Capital Markets Canada

Right, right.

Jonathan Samuels

So I'm thinking in terms of like the marginal cost of the spread, which were different and everyone having priced out everything. And that includes your infrastructure, your building, your -- we have a parts van that goes around and services everything. And when you get a third spread, you don't need another one of those.

Dan McSpirit - BMO Capital Markets Canada

Got it, understand. And then as a follow-up, can you sketch for us the market size and the opportunity for workover activity in the basin? I ask maybe in an effort to better define the maturity of the basin and what that could mean for recovery methods other than primary, if that makes sense?

Jonathan Samuels

Yes, I think you had a couple questions in this, so I'll try and answer it. And if I don't go all of it, let me know and I'll give it another crack. But I mean, for the workover business, one of the reasons we love that is that it's tied to well count in the basin versus rig count. So today, I don't know, you got 8,000, 10,000 producing wells in North Dakota, more in Montana. And based on the current rig count each year, industries going to add about 2,000 wells to that, and well count will be the driver of workover business. So in the downside scenario, where the drilling rigs go away, repeat your '08 or '09 for example, workover rigs remain busy, so that's sort of a steady state on business for us. It's a $9 million acquisition. It's not huge relative to the market capitalization of the Triangle in the aggregate, but it is a building block to add to. And I think you starting to ask another question about secondary recovery and the like. Did I hear that right or...

Dan McSpirit - BMO Capital Markets U.S.

It's right. Correct.

Jonathan Samuels

Would you mind repeating that piece of your question, please?

Dan McSpirit - BMO Capital Markets Canada

Yes. I was just -- I had asked a question about the workover activity, just in an effort to kind of better define in what stage the industry is in developing the Bakken and Three Forks and the basin. And maybe what that could mean in the out periods for recovery methods other than primary, secondary or other?

Jonathan Samuels

Yes, I mean -- this is my opinion. Justin might have a different one. Our Chairman Peter Hill will have a different one and other companies will have a different ones, but I think we're in the second or third inning in compared to a baseball game, which is very, very early. I mean, the vast majority of the 12-Es [ph] in the Williston Basin have 0, 1 or 2 wells in it, relative to the data points you hear. So just like you see the revivals in places like the Permian, the Bakken is only 6 or 7 years old. And with the completion designs that Brigham [ph] really pioneered a couple of years ago, we're only 3 or 4 years into it. So it's dangerous to bet against technology and to try to put a cap on it, but our internal view is this going to be much more over time, although there are going to be bumps in the road. People are going to try things that won't work, try something else that will work. Things that work, you got to then work on the per unit cost and make economic sense, and that will be the trend over time. But our kind of view is E&P is a great technology leader. It's one of the big bright spots of the energy economy in the United States. And it's kind of on a Moore's Law turf -- up, it's getting better. When you start to hear some stuff about other operators, and we don't talk about their businesses, about people trying CO2 floods and waterfloods and other things. And we leave it to those companies to talk about their business, they're part of the basin, but the Union started to touch on secondary.

Operator

Our next question will come from Ron Mills of Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Just a follow-up on something else you mentioned, Jon. In terms of November through January and the weather, the recent weather, has there been any impact on any of the operations at this point? Or I'm assuming that Caliber helps offset some of the weather that's come in there so far?

Jonathan Samuels

I think Caliber is going to help offset some production operations, and we have a lot more storage at our central battery, and so you have more swing. But our crude oil still touches the truck at some point in its value chain, but I don't care what you tell someone when it's negative 20 outside, it's tougher to do anything. So yes, I got to think it's slower up there and we also want people to be safe. And you got to slowdown, you got to drive slower, everything slows down. So I don't think that changes our financial guidance for the quarter or the year end or gives us any concern about hitting our exit rate, far from it, but that's life in the Williston Basin. It's one of the reasons the opportunity exists in our business model.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Right. And then can you remind us in terms of the marketing of your crude, what are your current price realizations relative to WTI given the Clearbrook price points widened out now? How much do you sell via pipeline, via rail and how are yours currently -- how is your crude currently priced with your WTI? Because most people there are achieving high realizations than what Clearbrook would suggest. Just trying to get a better sense of Triangle...

Justin J. Bliffen

Right now, it's moving towards around a $14 differential off of WTI. So it has widened out. We've seen this before, the dip is noisy and volatile. What I can say is as Caliber continues to build out its network and its system, the dynamics will shift over the coming year. As you can imagine, when you have a number of wells that are over a large, 200 square mile footprint, feeding volumes to one truck-loading delivery point, we have some negotiating leverage in dealing with some of the trucking companies. So that works to our advantage now. And then of course in the future, Caliber will be building takeaway up to -- interstate takeaway up in Alexander and beyond. So moving those hydrocarbons down the critical part of the hydrocarbon highway, which is that gathering and transportation up in the Bakken, isn't expensive and piece of it which Caliber will start to control. But right now, $14 dip is what we're experiencing.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And is that -- some of those benefits factored into either Jon or Justin, you talked about potentially generating $100-plus million of EBITDA in Caliber in terms of the build-out of that system?

Jonathan Samuels

Caliber has paid out to transfer a molecule from A to B. They don't own commodity price risk, so that's just pure transportation charges. Now that transportation charge that our E&P business or other E&P customers pay, that's getting it a barrel further down the hydrocarbon highway, closer to the interstate takeaway. So if you eliminate a truck, you put oil in a truck, you're going to have shrinkage, you're going to vent to atmosphere, you're going to have accidents, drivers on roads. So I think you're going to see margins improve and Triangle, the E&P side, is going to have a much better marketing clout, we're going to have more barrels in a centralized place in connections to pipeline a lot of optionality as the system gets built out. But the differential -- Caliber is immune to the differential. Caliber doesn't care.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Right. And then lastly, what's are your -- you mentioned cost improvements as well. What are your current wells running from a cost standpoint and where are those down from?

Jonathan Samuels

It depends on what well on a pad you're talking about. The first well is still going to be $11 million something like that. The third and fourth wells can be down to $10 million. And that's because we're building our pads to hold 8 to 12 wells, so their sized that way. We have flow lines for it, all the connections, tanks et cetera. Something like a 10% cost decrease, and that's before any benefit from RockPile, Justin already mentioned, that RockPile has saved us $30 million to date, which is another 10%, 15%. Caliber hasn't even got started yet.

Operator

Our next question will come from Eli Kantor of Iberia capital partners.

Eli J. Kantor - Iberia Capital Partners, Research Division

What pieces of the RockPile business are included in your fourth quarter standalone guidance? And what kind of contribution would you expect from those units or lines that are excluded are yet to come online?

Jonathan Samuels

Yes, we don't have -- we're not prepared to kind of break that out right now. I mean, the second spread's up and running, so that's obviously going to be factored into our Q4 numbers. But to be honest, we'd rather take that question off-line.

Eli J. Kantor - Iberia Capital Partners, Research Division

Okay. And the operated well results table you posted in your website, how many of those wells are targeted in Three Forks? And do you see any difference in productivity between Three Forks wells and offsetting middle Bakken wells?

Jonathan Samuels

Yes, we only have one Three Forks well that has made it into the presentation online, I believe. I've been to try think about what wells are on confidential status and what wells aren't. So we --the one Three Forks well, it wasn't our best completion on it and you're seeing a lower EUR there. We don't think that's necessarily indicative of what you're going to get out of that in the future. I thought that table said whether it's middle Bakken or Three Forks, but I might be mistaken. Yes, that's a good point. We'll update that.

Operator

Our next question will come from Ron Mills of Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Justin, just from a RockPile standpoint, Triangle operated and represented 32%, 33% of the third quarter activity, given your activity levels and with the 2 spreads right now, is that still a pretty good representation of Triangle versus on-off [ph] activity for RockPile? Or how do you foresee that changing going forward?

Jonathan Samuels

Ron, I'll take this. I mean Triangle as a percent of jobs and as a percent of revenue is going to continue to shrink over time. RockPile is long-term target is that Triangle is less than 30% from a revenue basis, and the leading edge months for RockPile, so you take the month of October in Q3, is much, much better than the first month of that quarter, and that's really the second spread getting online and then going to the 24-hour operations. And so the leading edge is much better than the quarter indicates. But make no mistake, the goal of RockPile is to get Triangle down to frankly as low a contribution margin as possible. That what's going to drive the most value for that business in an exit scenario.

Operator

And ladies and gentlemen, that will conclude our question-and-answer session. I would like to turn the conference over to Jonathan Samuels for his closing remarks.

Jonathan Samuels

Thank you, all, for your time. I appreciate you listening in and look forward to visiting with you next quarter. Have a great day.

Operator

Ladies and gentlemen, the conference has now concluded. We thank you for attending today's presentation. You may now disconnect your lines.

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