Nuverra Environmental Solutions, Inc.
Q3 2015 Earnings Call Transcript

Published: 5 Nov 2015

[Operator:]

Greetings and welcome to the Nuverra Environmental Solutions Third Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host Liz Merritt, Vice President of Investor Relations for Nuverra Environmental Solutions. Ms. Merritt, you may begin.

[Liz Merritt:]

Thank you, operator, good morning and welcome to Nuverra Environmental Solutions third quarter 2015 conference call and webcast. As we turn to Slide 2, I’d like to introduce today’s speakers. With me are Mark Johnsrud, Chairman of the Board and Chief Executive Officer; and Greg Heinlein, Executive Vice President and Chief Financial Officer. Before we get started, we’ll quickly cover a couple of items. First, we’ll be using slides to accompany today’s call. These slides are accessible on the Investor Relations page of our website at www.nuverra.com, where you will also find a link to a replay of today’s call about an hour after we conclude. Moving to Slide 3, today’s presentation will contain forward-looking statements about our expected financial and operational performance. This includes revenue trends, the expected performance of our businesses, and our strategies, services, cost controls and related matters. These statements involve a number of risks and uncertainties that could cause actual results to differ materially from our projections and include a variety of factors, some of which are beyond our control. Potential risk factors that could cause these differences are described in our SEC filings, including our Form 10-Q for the three and nine months ended September 30, 2015, our Form 10-K for the fiscal year ended December 31, 2014, our current reports on Form 8-K and our press releases posted on the Nuverra website. These documents maybe obtained from the SEC or by visiting the Investor Relations section of our website. All information provided on this call is as of today, November 5, 2015, and Nuverra undertakes no duty to update or revise this information based on new information, subsequent events or otherwise. Today’s discussion will also include certain non-GAAP financial measures, including adjusted EBITDA. Reconciliations of our non-GAAP measures to the most closely related GAAP results can be found in our press release. With that, I’ll turn the call over to Mark Johnsrud, Chairman of the Board and Chief Executive Officer.

[Mark Johnsrud:]

Thank you, Liz, and welcome everyone to our call. Starting on Slide 4, industry headwinds continue to put significant pressure on results. In the phase of this, we have done a solid job of operating our business efficiently, meeting our customers’ service and safety needs, and continuing to aggressively implement cost and expense reductions. These efforts have contributed to $85.5 million reduction in total costs and expenses, excluding special items on a year-to-date basis and have generated year-to-date free cash flow of $51.4 million. We are also taking steps to pursue strategies that will strengthen the business going forward, seeking opportunities to organically grow market share and making selective investments in key midstream initiatives, so that we are positioned for stronger returns. We will continue to execute on these goals by prudently managing the expenses, implementing programs that support greater operating efficiencies, continuing to grow our customer relationships, and being disciplined in our capital spending. In addition, one of the goals of our midstream expansion strategy is to reduce exposure to commodity price fluctuations over the long-term. We are pleased to advance the strategy with the carve-out of our pipeline subsidiary and our bank facility amendment that we announced this morning. Revenue from continuing operations for the third quarter was $76.5 million, down 17% sequentially from the second quarter, and 45% from the third quarter of 2014. This sequential year-over-year declines are driven primarily by reductions in customer drilling and completion activities and by pricing pressure across all basins. In the Rocky Mountain Division, third quarter revenue was $41.3 million, down 53% when compared with the third quarter of 2014, due to lower levels of water logistics, solids management and equipment rental services. In the Northeast Division, the third quarter revenue was $19.8 million, down 23% when compared with the third quarter of 2014. The decrease was primarily due to lower revenue of water logistics and salt water disposal services, offset in part by increases in revenue from water recycling services. Our AWS water recycling facility continues to be a key asset in the Marcellus, Utica region, where volumes up 20% year-over-year. It is noteworthy that water recycling continues to be a focus in this region that salt water disposal capacity tends to be limited. In the Southern Division, third quarter revenue decreased by 42% to $15.4 million from the third quarter of 2014. The decrease was primarily due to lower revenue across all service lines. This revenue decrease was offset partially by increases in revenue from water midstream, logistics, and disposal services in the Haynesville. As the advent of pad drilling becomes more frequent in the Haynesville, we believe volumes in our pipeline system will increase. With that, I’ll turn the call over to Greg to cover our results in more detail.

[Greg Heinlein:]

Thanks, Mark, and good morning everyone. On Slide 5, revenue from continuing operations for the third quarter was $76.5 million, a 17.2% decline sequentially from the second quarter, and the 45.2% decline when compared with $139.6 million in the third quarter of 2014. As Mark discussed, the decreases were due primarily to overall declines in customers’ drilling and completion activities, and pricing pressure across all regions. Non-rental revenue declines were primarily related to a lower overall demand for water logistics and solids management services. Rental revenue continue to be impacted, down about 68% in the third quarter of 2015 when compared with the third quarter of 2014, which correlates with the overall year-over-year percentage decrease in Bakken rig count of 67%. As a reminder, the vast majority of our rental fleet is designed for using drilling and completion work. As we announced this morning, we took a non-cash charge during the third quarter to write-off remaining goodwill of $104.7 million. This resulted from our annual impairment testing process, which we conduct as of September 30 each year. During the third quarter, our total costs and expenses excluding special items decreased by 34.9% or $46.6 million, which partly offset declines in margins. This contributed to year-to-date reductions in total costs and expenses excluding special items of $85.5 million or 22% decline compared to 2014. Third quarter cost reductions included approximately $17 million and lower payroll expenses. Year-to-date, we have reduced our headcount by 31%, $8 million in fuel savings, which is a factor of both lower volumes and efficiencies including fleet deployment optimization and bulk fuel purchasing programs, $5 million in the lower depreciation and amortization expense, and the balance due to reductions in direct operating expenses related to lower overall activities. For full year, $85.5 million reductions consisted approximately $31 million and lower payroll expenses, $20 million in lower fuel costs, $11 million in lower depreciation and amortization expense, with the remainder driven by reductions in all other direct operating expenses. As revenues continue to decline, we continue to reduce our cost structure as necessary and now expect total year reductions to approximately $125 million. On an adjusted basis, excluding special items, net loss from continuing operations for the third quarter was $22.5 million or a loss of $0.81 per diluted share compared with a net loss of $6.3 million, or a loss of $0.24 per diluted share, for the same period in 2014. For the year-to-date period, adjusted net loss from continuing operations was $52.3 million, or a loss of $1.89 per diluted share, compared with a loss of $29.3 million, or a loss of $1.14 per diluted share for the same period in 2014. Adjusted EBITDA from continuing operations for the third quarter was $6.3 million with a margin of 8.2%. This compares with adjusted EBITDA from continuing operations of $28 million and a margin of 20.1% in the third quarter of 2014. Year-to-date, adjusted EBITDA from continuing operations was $37.3 million, a 12.9% margin, compared with $69.8 million and a margin of 17.7% for the same 2014 period. Turning now to Slide 6, we will start with a review of the Rocky Mountain Division where the decline in customer drilling and completion activities as well as pricing pressures continue to impact the demand for water logistics, solids management and rental services, which drove both lower revenue and margins. Third quarter revenue was $41.3 million, down 52.8% compared with the third quarter of 2014. On a year-to-date basis, revenue was $158.3 million, a decrease of 35.9% compared with the same period in 2014. Third quarter adjusted EBITDA for the Rocky Mountain Division was $8.4 million, a 20.4% margin compared with $27.4 million and 31.3% margin in the third quarter of 2014. On a year-to-date basis, adjusted EBITDA for the Rocky Mountain division was $37.6 million, a margin of 23.7% compared with adjusted EBITDA of $72.2 million and a margin of 29.2% in 2014. In the Northeast Division, third quarter revenue was $19.8 million, a decline of 23% compared with $25.8 million in the third quarter of 2014. Year-to-date revenue was $74.5 million an increase of 10.6% compared with $67.4 million in 2014. Northeast results for the third quarter primarily reflected lower water logistics and salt water disposal activities, as a result of an overall reduction in activities among several key customers in the region as well as pricing pressures. As Mark mentioned, we continue to see increased volumes at AWS water recycling facility. Year-to-date revenue increases relate primarily to market share gains in the first half of the year with the addition of new customers. Third quarter adjusted EBITDA in the Northeast was $2.6 million and a margin of 13.1% compared with $4.1 million and the margin of 15.8% for the same period in 2014. Year-to-date adjusted EBITDA was $11.1 million and a margin of 14.8% when compared to adjusted EBITDA of $7.6 million, and a margin of 11.2% in the first nine months of 2014. The 360 basis point margin improvement in this division was due primarily to market share gains in the first half of the year in addition to positive impact of cost reduction activities. In the Southern division, third quarter revenue was $15.4 million, a 41.5% decrease when compared with the third quarter of 2014. Year-to-date revenue was $55.2 million, a decline of 31.1% compared with $80.1 million in 2014. Revenue decreases for the quarter and year-to-date periods related primarily to overall declines in customer drilling and completion activities with a more prominent impact in the Eagle Ford region. These declines were offset somewhat by third quarter increases in water logistics, salt water disposal and water midstream services in our Haynesville region. Both basins were impacted by continued pricing pressure. Third quarter adjusted EBITDA for the Southern Division was $740,000, a margin of 4.8%, compared with $2.3 million and a margin of 8.7% in the third quarter of 2014. Year-to-date adjusted EBITDA was $5 million, and a margin of 9%, compared with $6.2 million and a margin of 7.7% in 2014. The year-to-date margin improvement of 130 basis points was due primarily to the impact of lower overall costs and expenses. Moving to Slide 7, net cash provided by operating activities from continuing operations for the third quarter was $13.3 million compared with $16.8 million for the third quarter of 2014. For the year-to-date period, net cash provided by operating activities from continuing operations was $55.6 million compared with $12.9 million for the same period in 2014. Free cash flow for the three and nine month periods were $16.4 million and $51.4 million respectively. This compares with free cash flow of $3.2 million for the third quarter of 2014, and a use of cash of $20.8 million for the year-to-date period in 2014. The year-to-date increase in cash flow was primarily due to our focus on improving collections and collection cycle times, the effectiveness of our disciplined capital spending and our diligence around cost management. In the third quarter, asset sales outpace capital spending by $3.1 million. For the nine months, net cash CapEx was $4.2 million, which included $12.3 million in asset sales. Our full-year net cash CapEx guidance will now be in the range of $6 million to $8 million. We are sometimes asked if we are under spending on CapEx. The answer is we have been very creative and proactive in managing our fleet resources by sometimes selling, sometimes moving, and even trading assets in order to minimize cash expenditures by optimizing the life and utilization of our assets. As we’ve also announced today, we amended our credit facility effective November 2, following a periodic redetermination of our borrowing base. We elected to reduce the sizes of our facility from $195 million to $125 million in order to match the facility to the value of our borrowing base. As of the date of the amendment availability under the facility net of required reserves was less than $5 million and we had cash on hand of nearly $32 million. Importantly, as part of the amendment, we reached agreement with our lenders to release our Nuverra Rocky Mountain pipeline subsidiary from all obligations under the facility. The amendment also releases our equity interest in the subsidiary and established a permitted basket of up to $5 million in additional aggregate investments. Concurrently, we designated Nuverra Rocky Mountain Pipeline as an unrestricted subsidiary under the indenture for our senior notes to 2018. This carve out provides a path for the advancement and eventual financing of our long-term water midstream growth strategy. Adjusting our liquidity, availability under the ABL Facility has declined significantly in this past redetermination period due to additional declines in machinery and equipment appraised values. Added to that while all of our long-lived assets are secured by our lenders, only half provide borrowing availability. We believe it is important at this juncture to better match our long-lived assets with more certain borrowing capacity than our current ABL Facility provides. Thus we are evaluating new financing structures that may complement or replace our existing ABL Facility as permitted under our indenture. With that, I’ll turn the call back over to Mark for our final commentary and then we’ll open the line for questions.

[Mark Johnsrud:]

Thanks, Greg. I will wrap up now with an update of our XTO pipeline project and emphasize that we are highly committed to the long-term water midstream strategy. Customer activity levels including XTOs have changed significantly since this contract was signed last year. This has impacted economics of this pipeline with major shifts in volumes and production assumptions. These volume assumptions were developed on the basin at 180 drilling rigs, oil was $100, and forecasts were for increased volumes. That environment has shifted dramatically. So we are having discussions with our customer about what that means for the project. The good news is that we continue to work very closely with XTO to determine the most appropriate timeline for this project, recognizing that we have already obtained the majority of the rights of way. Our customers can have confidence in our ability to perform based on our engineering design, success in execution and world-class pipeline relationships. We are in a position to construct the pipeline when it makes sense for all parts. We continue to take a cautious approach along with XTO, and believe this is a pretty good strategy. As for our thoughts on the fourth quarter, we believe current headwinds will linger compelling customers to take a conservative approach and operate inside their cash flow. We have limited visibility into CapEx budgets for 2016 as such we must continue to run our business efficiently, reduce costs and expenses and expand market share as competitors exit the basins with the ultimate goal to retain the flexibility to grow in a disciplined manner as activity levels recover. This concludes our prepared remarks. Let’s open the line now for your questions.

[Operator:]

Thank you. At this time, we’ll be conducting a question-and-answer session. [Operator Instructions] Our first question today is coming from Michael Hoffman from Stifel. Please proceed with your question.

[Michael Hoffman:]

Hi, Mark and Greg, thanks very much for taking my questions. Can we talk a little bit about the dynamics of your commentary around the revenue declines? When you say price, is that screwing mostly about the rates you are able to charge for logistics and not so much what is happening at the actual disposal assets and may be that’s very basins [indiscernible] so may be the Bakken might be down because of excess capacity, but disposal prices like if the saltwater disposal wells in the South and the Northeast are holding up. I just like to understand that difference there.

[Mark Johnsrud:]

Hi, first of all, good morning Michael. I think that’s a good question, but there is also a little bit of sales mix that you have to look at. And let’s kind of may be break that up by region. What we’re seeing in the Northeast, there has really been a little more fluctuation towards water reuse. What we anticipate as we get into the back half of the year and into next year, is that our disposal volumes will increase as what we’re anticipating as companies kind of slowdown their drilling and completion activities in the South. In Texas, we really haven’t seen rates change a lot, but when we go to the Bakken, we’ve seen our blended rate change somewhat because on average flow back water, you’ll get probably close to $1.5 a barrel and you probably are in that $0.65 range for production water. And its completions have really declined and also your weighted average of water on a per barrel basis changes. And so that’s how that mix somewhat changes. With regards to our logistics, there’s just been a pressure on all aspects to reduce costs, and so some areas we’ve seen more pressure than others. And hopefully that answers your question.

[Michael Hoffman:]

Okay. So to summarize, disposal – absolute disposal prices and – whether its drilling and completion water versus produced water are holding up, but logistics pricing are under pressure.

[Mark Johnsrud:]

I’d say yes, that’s correct.

[Michael Hoffman:]

That’s okay. Which I think important that disposal part of the business isn’t suffering price pressure; it’s the more commodity aspect of the business, logistic side. Okay, then in the context of your ability to sort of ongoing service the cash out flows, I mean the two major items are your cash interest expense and ongoing capital spending. How do you just think about what those – that cash interests about $38 million if I recollect correctly if I exclude the amortization in it in the $12 million a quarter? How do you think about what the capital spending is for going forward? Is that [indiscernible] fall in that sort of $10 million to $15 million range and we’re looking at something in the $50 million to $55 million as what we need for cash?

[Greg Heinlein:]

Hi, Michael. It’s Greg. Good morning.

[Michael Hoffman:]

Good morning. Hi, Greg.

[Greg Heinlein:]

Yes. In regards to CapEx, we’ve done a good job this year as we said in our prepared remarks of thinking creatively. We had excess assets in the MidCon. We moved – those were possible to use those in some of our other basins. We sold excess assets throughout the year. And so where we started guidance this year of net cash CapEx of $10 million to $15 million, we’re now saying that’s going to be $6 million to $8 million with asset sales complementing that. And it’s probably the same kind of range for next year. It’s going to be single digits augmented by either asset sales, small asset sales like we’ve been doing. In regards to the interest payment, it’s semi-annual in nature. It’s roughly almost $20 million every six months. And there is a lot of time between now and the next payment and we’ve got a lot of options at our disposal. And we touched briefly in our prepared remarks about whether we’ve got the right type of credit facility in place today given our long-lived assets that aren’t really providing availability under our current facility. So we’ve got options and we’ve got time and that’s what we’re going to focus out over the next couple of quarters.

[Michael Hoffman:]

Right, but – so it is like 19 in change, so it’s about 38 in total, is that right throughout the period?

[Greg Heinlein:]

Yes, for the nine and seven, eight nodes, that’s correct.

[Michael Hoffman:]

Yes, right, okay. And then – and you have the cash on the balance sheet as well and you should be at least neutral if not modestly cash flow positive under as I look forward. So certainly the next six months, I shouldn’t be worrying about that payment.

[Greg Heinlein:]

Yes. If you look at our third quarter, we generated $14 million of cash flow when we didn’t have the interest payments. So we’ve shown the ability to continue to generate good cash flow from working capital some of these asset sales disciplined capital spending, so plenty of levers, yes.

[Michael Hoffman:]

And even without the asset sales, there were $7 million, so if you can hold that pace that – so there is a operating cash as well not just the benefit of asset sales that’s my point.

[Greg Heinlein:]

Great, I appreciate that.

[Mark Johnsrud:]

That’s correct.

[Michael Hoffman:]

Okay, and – are you pretty much worked through the working capital gains – great success in the first half, some in the second – or in the third quarter, but is that not pretty much done that what we can – you can get there?

[Greg Heinlein:]

No, I think with 60 days DSO, I would never say we’re done and satisfied. We’ve done a lot this year and that continue to pay that each quarter, but our team continues to presently impress and surprise us. So we’re going to keep working that avenue as long as we can.

[Michael Hoffman:]

All right. And then in the – I think if I read this correctly, you’ve repositioned some of your G&A out of in the field versus last year or two the corporate number. And it’s about $5.5 million, roughly $5.2 million to $5.5 million. What’s the opportunity to reduce that $20 million, $22 million of corporate based G&A?

[Greg Heinlein:]

There is an opportunity there. I think Mark and I continue to look at it. There are various things that we have at our disposal and we’ll have to evaluate those as the – at this cycle, as you said in your commentary, remains lower to longer.

[Michael Hoffman:]

Yes, yes. And then I just thought I have clarity on the document on the pipeline in XPO. Until the world gets a little better, there’s more clarity, there is no urgency at this juncture is what I’m basically reading through. But the good news is you’ve unencumbered it out of Wells Fargo ABL. So you now have the most flexibility, when you do get to that point you’re making decision about how to fund it if it should happen…

[Mark Johnsrud:]

I think that’s a good way of looking at it. We just needed to have the flexibility so that it was not encumbered or wasn’t dictated by our credit facility or indenture.

[Operator:]

Thank you. Our next question today is coming from Joe Giordano from Cowen and Company. Please proceed with your question.

[Joe Giordano:]

Hi guys, good morning.

[Greg Heinlein:]

Hi, Joe.

[Joe Giordano:]

Why would you peg your split in the Bakken from – revenue from completion versus revenue from producing?

[Greg Heinlein:]

I would say the drilling and completion today is 35%, 40% and 35% probably from a revenue standpoint and the balance of it produced water and disposal.

[Joe Giordano:]

Okay. And so that kind of gets…

[Greg Heinlein:]

I’m trying to saying that is – is that you’re trying to add the landfill in and it's kind of – that has a little bit of both components in it.

[Joe Giordano:]

And when you say 35% to 40% what do you consider in the landfill out of?

[Greg Heinlein:]

It’s probably in the drilling and completion.

[Joe Giordano:]

Okay. So I kind of get to my next question is, kind of the correlation that you might expect between spending levels that your customers this year versus next year and the direct impact to your business. So obviously, really large declines in E&P spending this year pretty strong correlation to your business, but would it be fair to say that if E&P overall spending was to decline in the incremental, call it, 20% next year that the sensitivity to your business would be far less given where we are?

[Greg Heinlein:]

Yes, Mark and I are both thinking through that question because we’ve looked at it in a number of different ways. I guess one way to think about it is while E&P spending will be down by more forecasters, a certain percent again next year, a lot of that is in the front-end of exploration spending. You’re seeing some production spending, but a lot of that exploration spending is going to shell pulled on the Arctic et cetera, et cetera. So that overall spending doesn’t necessarily correlate with us, but nonetheless, it’s about rig count. It’s about trucking hours and how active they’re going to be. And then you have this backlog of uncompleted wells yet that could come back on with oil prices tend to quite always higher. So as fast as this decline happened, it could recover back as well. So we’re trying to be nimble and if it isn’t over for longer, we’d prepared for that.

[Mark Johnsrud:]

I think there’s one more component, it’s really important too, and that is that we’re starting to see certain smaller and even larger companies that are exiting the basins – certain basins. And so from a competitor standpoint in certain areas we’re very strong dominant players. And as others leave, it creates the opportunity for us to go and take market share, and that’s all organic growth.

[Joe Giordano:]

Yes, that’s fair. As far as the asset sales, what should we be thinking in – on a go forward basis how much capacity do you have to continue to do things like that? And how do you weigh asset sales versus ABL availability and along those lines, you hinted that options there. What are you able to say in terms of what types of options are allowed under the indentures?

[Mark Johnsrud:]

Yes, Joe, generally we don’t give a lot of guidance, so we’re being very cautious given the macro environment. But generally, net cash CapEx is probably going to be in a similar level and I don’t know whether that will be overall CapEx spending or whether that will be augmented by asset sales. So I’m reluctant to give any kind of asset sale guidance because then that implies what you are going to spend from a gross CapEx. So net cash CapEx if we’re guiding this year $6 million to $8 million probably going to be in that similar single-digit range and I don’t know how it’s composed between asset sales and gross CapEx.

[Joe Giordano:]

Do you have a – how much – is there just a lot of capacity to your assets sales if necessary and how should we think of that relative to your availability and borrowing availability? Because I guess you have cash now, I guess the worry becomes, does the availability under the revolver or under the ABL move below the current and on outstanding if asset sales continue or something like that?

[Greg Heinlein:]

Yes, so our bank facility and our indenture allows for ongoing assets sales and usually the proceeds of those assets sales can be reinvested into the business through CapEx or within a year’s timeframe we typically have to offer to reduce your commitments. And so, we’ve been reducing our commitments under our facility this year whether it’s TFI asset sale or other asset proceeds. So you have that flexibility to use those proceeds within a year within your business, so not really worried about assets sales impacting availability under the facilities at all. And then likewise, our bond covenants allow for a senior secured $150 million type facility. And as you can tell ours has been reduced overtime from starting at $245 million to $125 million in commitments in this last amendment. So we will look at new structures as we kind of said in our prepared remarks to increase our availability under a potentially new facility more considering all those options.

[Joe Giordano:]

Thanks guys.

[Greg Heinlein:]

Thanks Joe.

[Operator:]

Thank you. Our next question today is coming from Eric Stine from Craig-Hallum. Please proceed with question.

[Aaron Spychalla:]

Hi, Mark. Hi, Greg, this is Aaron Spychalla for Eric. Thanks for taking the questions.

[Mark Johnsrud:]

Hi Aaron.

[Greg Heinlein:]

Good morning.

[Aaron Spychalla:]

Maybe first on the pricing concessions, can you just kind of talk about whether those accelerated in the 3Q, how you are thinking about those we head into 4Q and 2016? And then maybe just your position relative to the completion?

[Greg Heinlein:]

Right now I think that form a pricing standpoint we went between 2Q and 3Q, we went through quite a bit of pricing concessions. We really haven’t felt probably the concession push in kind of from 3Q to 4Q that we did in prior quarter. Right now, I think, it’s really just in some cases there’s reduced amounts of work and as most companies have been talking about, it’s questionable what companies will do, customers are going to do between Thanks Giving and the end of the year, if they just become very quite during that period of time or not, that’s unclear.

[Aaron Spychalla:]

Okay. Thanks for the color. And then I guess on the cost cuts you mentioned an additional $25 million, how should we be thinking about that between kind of COGS in that OpEx bucket. You guys were at $25 million or so this quarter. I mean how should we be thinking about that going forward?

[Greg Heinlein:]

Yes, it’s predominantly going to be in COGS as the previous question addressed our SG&A, we’re going to continue to look at where we can SG&A and certainly aren’t ignoring that by any means, but predominantly it’s going to be in COGS.

[Aaron Spychalla:]

All right, thanks for taking the questions.

[Mark Johnsrud:]

Thank you.

[Greg Heinlein:]

Thank you, Aaron.

[Operator:]

Thank you. Our next question is a follow-up from Michael Hoffman from Stifel. Please proceed with your questions.

[Michael Hoffman:]

Thank you. They actually were asked. I was going to ask about had the logistics pressure leveled off and we were sort of found a floor there and I gather that’s what’s happened as it feels like it’s leveled off, but your biggest concern is there is an overall level of activity just might be lower too. So no more pricing pressure, but volumes might be down.

[Greg Heinlein:]

That is correct.

[Michael Hoffman:]

Okay.

[Greg Heinlein:]

And I think you kind of take a look at it Michael into the drilling side that appears right now that we’re continuing to lose and reduce some rigs. The completion side, I think we’ve seen some companies say we’re just going to try it out really be very, very disciplined slowdown in between now and year-end. It kind of what we’re hearing and seeing others are saying that after the first of the year, there may be somewhat of a tick-up, but I think it really is going to be depended on oil price.

[Michael Hoffman:]

And Greg, you mentioned the frac log, I mean what’s your sense about capital dollars get diverted from drilling and gets flipped over to completion in order to hold production at some level by an operator because [ph] that’s heavy cash flow right.

[Greg Heinlein:]

Yes, Michael, I think that’s very price dependent. So cheapest inventories in the ground and guys are waiting – exploration folks are waiting for higher prices to start tap in those.

[Michael Hoffman:]

And then just…

[Greg Heinlein:]

It’s really going to be dictated on the individual operators personal or their cash flow of their company do they need to turn it on or can they leave that it inventory for a while.

[Michael Hoffman:]

Right. And do you have – just I realized this just gets in the realm of guessing, but everybody in the brother says they lowered their costs on the E&P side. Have we got to a sense now where we’re living in a 40 to 50 range, if we get 50, 60 that’s enough for it, it really has to be 60.

[Greg Heinlein:]

I don’t know if we really have that visibility.

[Michael Hoffman:]

Okay.

[Greg Heinlein:]

There is a combination of hedges and forwards and all kinds of different pricing structures that make a difference the other one is that if some of the operators have locked into forward contracts with regards to how much they have to produce transportation contracts. So there is a lot of others factors that come into play.

[Michael Hoffman:]

Okay. That’s all for me. Thanks.

[Greg Heinlein:]

Thank you, Michael.

[Operator:]

Thank you. [Operator Instructions] We have reached the end of our question-and-answer session. I’d like to turn the floor back over to management for any further or closing comments.

[Greg Heinlein:]

Thank you everyone for joining us today on our call and we look forward to talking to you on our fourth quarter call.

[Operator:]

Thank you. That does conclude today’s teleconference. You may disconnect your lines at this time and have a wonderful day. We thank you for your participation today.