Select Water Solutions, Inc. (WTTR) Q4 2014 Earnings Report, Transcript and Summary

Greetings, ladies and gentlemen and welcome to the Nuverra Environmental Solutions Fourth Quarter and Full Year 2014 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 Ms. Liz Merritt, Vice President of Investor Relations.

Thank you, operator. Good afternoon and welcome to the Nuverra Environmental Solutions fourth quarter and full year 2014 conference call and webcast. As we turn to Slide 2, I’d like to introduce you to today’s speakers. With me are Mark Johnsrud, Chairman and Chief Executive Officer; and Greg Heinlein, Executive Vice President and Chief Financial Officer. Before they get started, we will quickly cover a couple of items. First, we will 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 trend, 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 projection 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-K for the fiscal year ended December 31, 2014, our current reports on Form 8-K and our fourth quarter and full year press release posted on the Nuverra website. These documents may be obtained from the SEC or by visiting the Investor Relations section of our website. All information provided on this call is as of today, March 16, 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 will turn the call over to Mark Johnsrud, Chairman of the Board and Chief Executive Officer and we will begin with Slide 4.

Thank you Liz and welcome everyone to our call this afternoon. Before we begin our review, I would like to take a moment to introduce Greg Heinlein, our new Chief Financial Officer. Greg hit the ground running when he arrived in January and he has been extremely focused during the past couple of months on the execution of our highest priority initiatives. The first and foremost of which is to close the TFI sale. As Greg will cover in more detail he is also helping manage the business through the current commodity cycle. Now, let’s briefly recap 2014 results on Slide 4 followed by an operational overview and I will turn it over to Greg to cover our financial results in more detail. At the end of the call, I will wrap up with an update of several key initiatives and our views on 2015. Taking a look at our results for the fourth quarter, revenues were $141.8 million 10.4% over the fourth quarter of 2013. This increase reflects good demand for logistics, disposal, fluid recycling and solid services throughout the quarter as customers worked to complete their 2014 budgets. Full year revenue was up 2% to $536.3 million. Fourth quarter adjusted EBITDA from continuing operation was up 9% to $25.4 million over the prior year. Full year adjusted EBITDA was down 6.2% to $95.2 million, primarily due to reduced drilling and completion activities in the Rocky Mountain division. Turning to slide, let’s start with the Rocky Mountain division. In the fourth quarter, we proactively shifted our business mix to more production related activities. These services tend to be route based and provide a more consistent workflow. As an example, year-over-year oil production in December, in North Dakota, increased from 900,000 to 1.2 million barrels per day. This increased activity also means more produced water to manage on a daily basis. Fourth quarter revenue in this division increased 8% year-over-year to $87.8 million. The revenue increase was tied primarily to the growth and produced water logistic services as compared to 2013. Despite the typical seasonal slowdowns from the holidays in the fourth quarter, sequential revenue was flat compared to the third quarter. For the full year, Rocky Mountain revenue increased 10.1% to $334.8 million. All-in-all it was a solid fourth quarter and year for this division and we remain pleased with our leading market position in this basin. In the Northeast division, which includes Marcellus and Utica, fourth quarter revenue was up 30% to $28.2 million, primarily due to increased logistics and recycling activities. Sequentially revenue was up 8.5% from the third quarter and for the full year revenue increased slightly to $95.6 million, compared to $95.1 million in the prior year. During the fourth quarter, customer activities in the Marcellus and Utica remain strong. We saw a nice ramp in business from our largest customer in this area and sequential revenues increases for four of our top five customers in this division. There is no significant weather related interruptions during the fourth quarter, which also contributed to the boost in activities as operators were diligently to complete their 2014 programs. We also were pleased to see the increase in logistics and disposal services for a new customer in the Utica that holds more than 300,000 acres in this region. Looking ahead, we are seeing exploring an opportunity to add more services for this customer. Additionally another customer has announced that will increase its CapEx in the region by an additional 15% this year. We will address microtranslator but our strong customer focus coupled with our recycling and disposal services continue to service well in this region. Turning to the Southern division, quarterly revenues were down 1% to $25.8 million. Full year revenue was down 16.3% to $105.9 million compared to the same period of 2013. Sequentially, we saw a 1.8% decrease in revenue for this division compared to the third quarter. Revenue decreases were largely driven by a decline in logistics and disposal activities in the Eagle Ford as well as continued decline in activities in the MidCon operations. Because of the basin economics of the Mississippian region, we made the decision to close our MidCon operations effective immediately and redeploy some of the assets to the Eagle Ford and northeast regions. In our East Texas region, which includes the Haynesville and TMS, we a slight increase in revenues in the fourth quarter over the prior year. One of our key assets in this region is our 60 mile integrated pipeline and disposal well network that we can handle a capacity of approximately 85,000 barrels per day. We have recently taken actions to improve the economics of this pipeline, including additional volumes from an existing customer. Given its strategic location, we plan to continue to improve the pipeline operation results over the next couple of years. This core infrastructure asset provides a great example of what we intent to replicate in the Rocky Mountain region with our McKenzie County pipeline system, more on that later. In the Eagle Ford, we experienced a decline in logistics and salt water disposal revenue in the fourth quarter, primarily because one of our disposal wells was down from maintenance. This decline was partially offset by increases in water transfer work as well as additional work in solids management for one of our large customers in this basin. Our largest customer announced that it will focus all of its drilling and completion activities in 2015 in the Eagle Ford and Williston Basins. Additionally, another top five customers will spend the largest percent of its 2015 CapEx budget in the Eagle Ford. The economics of this basin are very strong even in the current market, which will provide some stability for 2015 work flows. Let’s move on to Slide 6. While we delivered strong operating results in 2014, its clear 2015 will be a challenging year for the industry and for Nuverra. The rapid decline of crud oil prices and rig counts has resulted in significant cuts to operators 2015 CapEx budgets, primarily in exploration, drilling and completion of phases. One of our advantages during this time like these include the strength of our customer relationship, our geographic locations, mainly the specific acreage within each basin for our customers, our focus and the quality and scope of services that we provide. Out top customers are among the largest E&P operators in the world. And while the majority will scale back over all drilling and completion activities, none of them have announced plans to shut in producing well. These customers have the resources to taking long-term view on production activity, which helps to insulate that portion of our business tied to produce water. More than 40% of our 2014 revenue was tied to the production phase of oil and gas wells. This volume mix provides a stickiness not all of our peers have. In 2015, we expect that percentage of relatively stable produced water volumes to grow to approximately 50% of our revenue with the balance continued to be generated from ongoing drilling and completion activities. We will do this by focusing on the key needs of our customers in the busiest areas such as McKenzie County, North Dakota, while streamlining operations in the less economic basins to maximize asset utilization. Moving out of the MidCon region and redeploying those assets and other basins is just one example of where we are narrowing our focus to core basins. As you see on Slide 7, our locations also provide efficient operating platform. In the Bakken, for example, Nuverra operations are concentrated in the heart of McKenzie County. We have strategically positioned our logistic services in a grid like model, roughly every 40 miles to 60 miles from our customers’ location to support their day-to-day operations with a rapid turnaround times. We are their first call. In 2015, we expect 80% of the Bakken drilling to happen in McKenzie County with 90 to 100 rigs working in the tier one acreage. We expect to see fairly steady workflows due to our concentrated presence in these high return areas, offset somewhat by pricing concessions. To absorb the pricing pressures, we will be working hard to manage our cost structure. In keeping with my earlier comments, we believe our business is highly scalable and we have identified various levers that we can pull in order to protect our market share and manage our cost through the duration of this cycle. We have taken proactive steps to minimize capital expenditures, manage the business within operating cash flows, maintain flexible if and when condition shift. I will now turn the call over to Greg, so he can give you more details on the financials and our initiatives to support 2015 plan then I’ll come back to wrap up our call.

Thanks Mark and good afternoon everyone. Let’s turn to Slide 8. Revenues from continuing operations for the fourth quarter were $141.8 million, a 10.4% increase over 2013 and 1.6% sequentially compared to the third quarter. Full year revenue was up 2% to $536.3 million. As Mark mentioned, these increases reflected higher levels of logistics, disposal, fluid recycling and solids services for the year. When we look at fourth quarter versus third quarter activities, the metric support our strong fourth quarter performance. On the logistics side, revenue per vehicle was up 4% for all regions combined. Disposal volumes at the water recycling plant in the Northeast was up 19.5% and salt-water disposal volumes were up 35% in the Northeast division, reflecting the significant increase in logistics and recycling services. Our Haynesville pipeline generated nearly 40,000 barrels per day in the fourth quarter. Total salt-water disposal volumes in all basins were up approximately 20% for the year, which speaks to the production mix, Mark talked about earlier. As part of our year-end review of the balance sheet and given the effective recent declines in energy prices, the company made the decision to take a pre-tax, non-cash impairment charge of $315.7 million. $112.4 million of this impairment was against intangible assets, which will eliminate the majority of amortization going forward. The remaining write-down of $203.3 million was to goodwill. We firmly believe these actions reflect today’s market realities distorted or not by the unknown future for our overall industry. We will refer to financial numbers adjusted for these special items going forward. Adjusted operating income was $3.4 million, compared to an adjusted operating income of $3.9 million in the fourth quarter of 2013. This difference was due primarily to lower overall drilling and completion activities. Adjusted loss from continuing operations for the quarter was $9.6 million, or a loss of $0.35 per share, compared to a loss of $9.7 million, or a loss of $0.39 per share in the prior year. Adjusted EBITDA from continuing operations i.e., excluding TFI in the fourth quarter was $25.4 million, up 9% from $23.3 million in the same period last year. Fourth quarter margins were down year-over-year. On a sequential comparison, adjusted EBITDA was down 9.4% from $28 million in the third quarter. For the full-year adjusted EBITDA was down 6.2% to $95.2 million, or 17.9% of revenue. These decreases were primarily due to the decline in drilling and completion activities we spoke about a moment ago. Turning now to Slide 9, we ended the year with cash and cash equivalents of $13.4 million, up from $8.8 million at the close of 2013. Cash flows from continuing operations were $17.4 million for the full-year. Working capital resulted in a use of cash of $30 million in 2014 and is the target of one of our major financial initiatives in 2015, which we will speak to in just a moment. At December 31, total liquidity was approximately $39.3 million, which included $13.4 million of cash and $25.90 million of availability under our $245 million ABL credit facility. As of March 13, we have approximately $25 million cash on hand and an outstanding balance of $176.5 million under our credit facility, excluding letters of credit. Our total liquidity is now $52.2 million. Net cash capital expenditures for 2014 were $45.5 million and were primarily related to the construction of our solids processing facility in the Bakken along with limited fleet upgrades in select locations. We will be disciplined in our CapEx spend for 2015. We expect CapEx to be in the range of $10 million to $15 million this year, which will consists mainly of maintenance CapEx. Approximately 55% of that will be earmarked for enhancing our water disposal capabilities, targeted fleet refresh programs on a cash-like basis and completing the second unit at our Bakken solids treatment facility. I want to reemphasize that we will be very disciplined with CapEx this year focusing on return on capital deployed across all basins. As Mark mentioned, we expect 2015 to be a challenging year lead more by reductions in drilling and completion activities rather than broad declines in logistics volumes. Our presence in key low cost proven oil and gas basins will help to soften the impact that lower commodity prices will have on drilling and completion activities. Additionally, new customer business will provide some support in certain areas on a year-over year basis. In response to this environment, we have proactively implemented streamlining initiatives that we expect to reduce total operating costs by 7 to 10 percentage points excluding depreciation. These cost saving initiatives will include 20% to 25% lower fuel spend and bulk fuel buying, 7 to 10 yard closures in our Southern Division, the sale in reduction of over 100 vehicles representing approximately 10% of our total fleet and 4% to 5% reduction in our workforce, which began in March. In total, we expect cost savings to approximate $20 million to $25 million in 2015. Before I turn the call back over to Mark for closing comments, let me review some of our key financial initiatives and outlook for 2015 on Slide 10. As I said earlier, we had a $30 million use of working capital in 2014. We have great tier one customers. We need to improve our internal ticketing and invoicing processes and we’re going to do that. We will also work with our customers to improve their payment processes. As the year progresses, each day in working capitals worth $1.5 million and our employees are focused squarely on this. We will minimize CapEx to as necessary levels. We scrubbed our CapEx plans and feel confident that given the environment we can reduce net CapEx spending to $10 million to $15 million this year. Last year, nearly 75% of our net CapEx spend was on our new solids processing facility. We are proactively reducing operating cost and exiting uneconomic basins and expect to track each workflow throughout the year. We remain focused on achieving 7 to 10 percentage point reduction in operating expenses excluding depreciation. We are also addressing SG&A costs in all regions. We expect the total headcount reductions to be between 4% to 5% by the end of the second quarter, while we regret having to take these actions, it’s crucial that we do so. We are modeling interest expense to be slightly less than in 2014 based on the planned pay down of our credit facilities from the TFI sale proceeds. We anticipate depreciation and amortization expense to be in the range of $70 million to $75 million, down approximately $14 million, as a result of the year end write down. Our effective income tax rate will remain 0% due to the valuation allowance on deferred tax assets. We will also be a minimal cash tax payer in 2015 due to the Federal and state net operating loss carry forwards. Lastly, our actions to streamline operations will result in first half one-time cost of approximately $2 million. All actions combined should result in annual cost savings of at least $20 million to $25 million excluding depreciation and amortization for 2015. With that I’ll turn the call back over to Mark for closing comments and then we will open the lines for questions.

Thank you, Greg. Turning now to Slide 11, I would like to leave you with updates on several key strategic initiatives. First, let me provide you with an update on the progress we have made towards closing the sale of TFI to Clean Harbors and start by saying both companies are ready to close the sale immediately when we get the final clearance on the Hart-Scott-Rodino review. We expect this may take a few more weeks to receive, and once we do we will move very quickly to close. As we have previously said, Clean Harbors and its safety clean division are an excellent fit for TFI and its employees. We want to command the TFI team for their continued dedication through this process and for ensuring our customers continue to receive the highest quality services. This transaction will also provide Nuverra with significant financial flexibility as we apply those net proceeds to the outstanding balance on our ABL credit facility. Next, we have implemented a fleet update program that we will fully support our customers’ needs, enable us to upgrade selected fleet while reducing the number of overall vehicles and minimize the use of cash. In the Bakken, for example, we will implement a cash like fleet trade in program this quarter with very limited additional investment given the relative age of the fleet. We have nearly completed the commissioning process for our advanced solids treatment facility in the Bakken, which we have named Terafficent. We are now working with customers to drive volumes through the facility. We’ve also had positive news from the North Dakota Legislature with unanimous passage earlier this month of House Bill 1390. The Bill has moved to The Senate for consideration and if passed the legislation would provide for the severance of liability for operators of solid and fluid wastes that’s treated and recycled in state-licensed facilities. With this legislation, we see tremendous opportunity to advance our overall recycling and reuse activities in North Dakota. As for our pipeline project in the Bakken, there is new legislation moving through the North Dakota House and Senate, it’s specific to regulations of leak detection systems for gathering lines, which we would include in our plan the McKenzie County pipeline system. Having visibility to this legislation provides us with the opportunity to design our system in a matter that we’ll comply with the States pending regulations. Currently, we have early phases rights-of-way acquisitions and process and remain on track to begin construction of the first phase of this project this summer. Additionally, we have a lot of interest from multiple financial sources that want to partner and fund this project. We are very close to selecting new partner and we will benefit from the access to their lower cost of capital. This first project and in addition to our existing pipeline, our solids processing facility and a robust portfolio of future project positions us to develop a strong platform for an integrated midstream assets in the future. It’s important that we choose the right partner and we have been very deliberate in this process. Turning to Slide 12, 2014 was a solid operating year for Nuverra. We have achieved steady revenue growth and expanded our organic with the introduction of Terafficent and water transfer services in the Bakken and Eagle Ford and solids management in West Texas. Given the current market conditions, our customers’ drilling and completion activities are influencing our business. Our advantage lies in the strength of our customer relations, our geographic locations and the quality and reliable services that we provide. We are proactively shifted our business mix to focus on long-term production related activities in response to decline in drilling and completion activities. This will represent approximately 50% of our 2015 revenues and while the other 50% will remain focused on drilling and completion activities. We have the ability to modify our business mix as the environment requires. We have taken the necessary actions outlined today to streamline our business for new market realities. Our plan enables us to operate the business from a more solid position by reducing overall cash cost by $20 million to $25 million. During this downturn, we are going to take this opportunity to focus on all of the parts of our business that we can manage. I’m confident that we have the right people, technology and strategies in place to operate throughout the cycle and emerge a stronger company. Before we open the lines for questions, I would like to thank all of our employees for helping us to remain competitive through this period and deliver top tier services to our customers’ everyday. We look forward to executing on our 2015 plan. Operator, we will now open the lines to take questions.

Thank you. [Operator Instructions] Our first question comes from the line of Michael Hoffman with Stifel Nicolaus. Please proceed with your question.

Hi, Mark. Thank you for taking my question. So, I think you all alluded to this at the beginning of the presentation, Greg, you made a comment about the working capital and what’s driving 2014. How much of that do you think you can recover in 2015 in the context of reducing that $30 million that you use in 2014?

Yes, there is a fair amount of – hi, Michael, good afternoon by the way.

Good afternoon.

There is a fair amount of that that we’ll be able to recover this year will – happen at once, but the team is focused on going after all of that in 2015.

Okay. And then I mean when you think about it in the context of who the customers are and there is – my recollection is somewhere between 5 and 10 customers account for 60% to 70% of the company. Is that bulk of that $30 million tied up with that groups of these are bigger wells finance and this is a function of – and along to pay you faster?

Not always, it’s not that easy of a blanket statement. It depends on the location. It depends on the customer. We’ve been fortune up to pickup some fairly recent new customers. Some of our longstanding customers have been very solid payers and part of it is just our team’s ability to focus on turning invoices and billing out as quickly as possible.

Okay. And then, Mark, the outlook that you provided and I guess the limits don’t being able to have too much visibility on the direction of a business other than maybe some of the mix what you’re going to do about cost. But when you talked about the production level I think 40% in 2014, how would you characterize the run rate exiting 2014 given your efforts in the fourth quarter particularly in the second half most importantly in the fourth quarter to shift the mix anyway. If I just take [indiscernible] by 40% that’s $215 million, but actually had a higher rate of performance on the 215?

There is a – first of all good afternoon.

Hi, Greg.

I guess I’d like to say probably a couple of different pieces. One of them is, is that as we look in certain basins and specifically the Northeast, where we move production water through our AWS treatment facility that ultimately goes in its frac, used for one of our customers in either the Marcellus or Utica. We’ve kind of considered that more on managing on the production water side versus using that as completion water. So that number is not exactly science, there is a little bit of movement in that. The second part is that as we’ve seen the slowdown start coming, we’ve been consciously moving to more and more production activity because of where our operations are, relationship with customers and just more activity in that in the whole production water piece of it. So, we’ve been consciously working since October and trying to increase that number and that’s something that’s continuing to go on and I think it will continue to go on, because as production has – overall production has continue to increase or at least start to flatten out, there is – we’re finding more and more activity that some companies are just not as competitive, they’re not as geographically positioned as we are to manage on a day-to-day basis.

Okay, so if I ask a question in a different way, do you expect that 215 to grow in 2015?

Yes.

Okay.

You wouldn’t – I think what we’re saying is that it’s going to be come at least half of our business and I would say in 2015 our production water will increase 50% to 60%.

Okay.

Michael, this is Greg. I guess another way to think about it is going from greater than 40% as we’ve outlined in the slide to approximately 50% in 2015 is 6% on total revenue. So you’re going to have some things going up in 2015. You’re going to have some things going down in this environment from a revenue standpoint. And generally that 6% is going to be achieved over the course of the full-year.

Yes, I mean there is two ways to look at that. The 215 flat just multiplied by two and get to the revenue number or the 215 grows and then I adjust accordingly for what I think has been...

Yes.

Understand. Mark, I just want to make sure I understood your statement [indiscernible] did you say you thought volume – water volume in 2015 would be up 50% on the production line?

No, no I think that our percentage that production water would grow from 40% to between 50% and 60% of our total revenue.

Well, okay. I just want to make sure if I misunderstand that. On the Terrafficient business, the HB 1390, that’s more function of liquids not solids right. The Terrafficient is independent [ph] on HB 1390 being passed?

No, it’s not but what it does look at is separating the risk for both fluids and also for solids.

Okay, but this is a much bigger deal to the liquids side in terms of the issue about bulk storage and things like that and unbundling is that liability back down to the individual well is a bigger deal around liquids right. I mean it’s not your relevant but it’s a much bigger deal right?

I think that’s correct, it’s a much larger impact on the industry, but I would contest that this becomes a very large factor to considering all the wells that have been drilled, but then also the wells that will be drilled in the future especially with multi-well pads that we think this is an extremely positive change in the state regulations.

So when we look at this, our conclusion is that I’d say I think basically are adjusting – several liabilities to be more like hazardous world where it goes back to the operator – as operator cannot back to a specific point of origination. So that the operator still always on the hook – it doesn’t get in the way promoting recycling and reuse and reduced. Is that fair observation?

That’s a true observation.

Okay. And then your comment on the presentation on the rig count specifically the 90 to 100 in the Bakken how would I reflect that 90 to 100 versus what’s been happening in 2014 in those counties you refer to?

The rig count kind of peaked out at around 180, so I would say this will reduce the rig count in half. The other factor that I think you want to look at in addition to rig count is the number of uncompleted wells as of the end of January increased to 825. So there is becoming a very large on frac inventory of wells that we would anticipate will be fracs probably starting somewhere in the next month or two but definitely by June and the reason for that is there some tax incentives are coming to place, starting June 1, that probably make just a little bit more appealing for the operators.

Okay. And given the year 60% of fluids market that’s a big deal that they are going to try and work that inventory down, plus maintenance a pace even its where at the 100 rigs down from 180. Right, and that’s probably that’s one way to improve that?

Yes, I think a lot of this has to do a little bit also with the come to the individual company, their balance sheet and also with the price of oil.

Right.

We’ve seen there has been some companies Michael have talked about that they are going to significantly reduce their completion activities until prices become stronger.

Got it…

So we don’t really have this good visibility into that we’re talking with customers everyday. But I think there is still some strategy that’s being implemented at this point that there kind of maybe changes day-to-day or week-to-week based on commodity trends and prices.

Okay. And then last question from me. Greg, what do you think cash interest expense will be in 2015, approximate?

Yes. I remember Michel. We don’t give guidance, so I’ll try and give a range. Generally speaking, it will be slightly less than 2014, simply because of the use of the TFI proceeds at some point we will reduce our need to borrow under the revolvers much. So you can take LIBOR plus three and back off for TFI proceeds and kind of three quarters of the year just that.

Okay, great. Thanks.

Thanks.

Thank you.

Thank you. Our next question comes from the line of Joseph Giordano with Cowen and Company. Please proceed with your question.

Hi guys, this is Christine for Joe. Thanks for taking my question. Good afternoon. I guess I’ll start by asking, when you talk about the mix shift mostly moving from 40% to 50% or 60%. Is this mix shift mostly having to do with the big declines in completion?

That is correct. So, if you kind of look at it, and I’ll use North Dakota as an example, a year in December 2013, 2014 that we’ve the – the state was producing approximately 900,000 barrels a day and as of the end of 2014 we were producing approximately right at 1.2 million barrels a day. So there was a lot more production and consequently there is a lot more production water that needs to be managed. And so as we started to see the trends change, we wanted to make sure that we were, because of our network we want to make sure that we were managing as much route based service business as we could until we see the trend would start to change to increase to more drilling and completion activities. We’re not that we were walking away from any work, what we’re doing as we’re taking our people and our locations and we’re shifting into something that looks a lot sticker at this current time.

Okay, that make sense, thank you. And talking about your liquidity here and I think you mention you just have like over $52 million in liquidity. How long that this sustain operation at this rate?

Well, we’ve been holding on. This is Greg, Christine. We’ve been holding quite well managing the cash, month by month we’ve been building cash throughout the year. So [indiscernible] 2015 is very early, but we’re focused on lighter CapEx than we have in the past. We’ve announced the cost in streamline activities. And so we are going to manage totally the cash flow positive for the year. So we will play as the year progresses but that’s entire.

All right, great, thanks. Do you think margin in 2015 can be higher than they were in 2014?

No, not in this environment.

Okay, fair enough. Thanks. And just maybe a last one, how do you see in terms of balance sheet, how do you intent to fix it with the amount of debt that is from the balance sheet?

That’s the big question I’m answering with a smile on my face that’s the big question. I don’t know, fix it is the right phrase that implies something is broken, but clearly we’ve got fair amount of debt and fortunately we don’t have M&A maturities, so we’ll address that over time with the right kind of strategy.

Fair enough, thank you guys. I Appreciate that.

Thank you. Our next question comes from the line of Evan Templeton with Jefferies and Company. Please proceed with your question.

Hi, thanks. I am just also wondering if you can just trying to drill down also just on liquidity. Can you comment, what you’ve anticipate the net proceeds from the sale today what we can expect that the possible paydown on the ABL.

Yes, hey Evan this Greg. The sell price announced was $85 million, there is a 5% pullback for 18 months. So you got to adjust for that, it’s basically just a standalone there is fees and other expenses and then there is a working capital adjustment that just prior to closing will be factored in based on where the working capital invest. So we’ve sort of been advising people generally speaking right out of the gate, somewhere between the $70 million to $75 million range of net proceeds.

Right. And then just on that front, have you had discussions with the banks about what to look for in terms of total size for the ABL? Do you see that coming down? And I – because I think there is some sort of future in there regarding an appraisal I’m wondering if one have been done recently or if that was possible in the works?

Yes, good question. So the facility has several times a year the ability for the lenders to do appraisals and value equipment values. And so they will do that I think if it is two to three times a year. We’ve had good discussion with our lenders. They have been very supportive. We’ve taken them through our expectations for how the year unfolds. I can’t say right now whether the facility size would come down or not, but if you think about our machinery and equipment funds that facility along with our receivables. Generally speaking, it would not surprise me if the overall borrowing base comes down as the year progresses, but nothing formal in place today.

Okay, great. And do you have any timetables in terms of when you look to conclude those discussions or would just be in conjunction with the closing of the transaction?

My hunch is it’s going to be sometime around the closing of TFI. Our lenders, we’ve had great discussions with them. And at some point my hunches will have a facility side that reflects the use of the TFI proceeds and then adequate availability to get through this down cycle over the next year or two.

Great, thanks a lot. I appreciate it.

Thank you.

Thank you.

Thank you. Our next question comes from the line of Scott Levine with Imperial Capital. Please proceed with your question.

Hi, good afternoon guys.

Hi, Scott.

Hi, Scott.

So we’re most the way here to the first quarter. I know it’s not your custom to provide financial guidance, but maybe looking for a little bit more color on what you’ve seen so far since the environment has changed. I mean any additional qualitative insights into either pricing concessions or whether things slowed in accordance to your expectations for regional detail that will be helpful.

Yes, I would say kind of what we’ve seen so far is kind of in our logistics business pricing has been down probably in the 10% range, an area that is probably impacted as more as it has been in our rental business because as some of the number of drilling rigs has declined that’s impacted. We would anticipate that would be somewhere in the 25% to 50% ballpark. We think that’s probably a pretty good range based on what we’re seeing area by area. The Bakken, there is just less drilling and completion activity today. The Northeast are logistics recycling and disposal well business seems to be moving along very nicely out there at this point. We were able to pick up a new customer in the Utica and another large customer actually increasing their drilling activity in the Utica this year. So for being a relatively new basin, we’re quite excited about that area. In the South, in the Haynesville and Eagle Ford area, we’ve had to do some streamlining activities. But overall in the Haynesville, our activity remains, I would say, relatively flat year-over-year. And I think we’re – I would say that you know it’s a smaller business, but our Eagle Ford business remains steady versus kind of Q4 of last year. I’d say kind of overall we’re going to be very prudent this year kind of just with our capital and with our spending. And it’s our anticipation that we just have to go through this down cycle and be as prudent as we can.

Understood, thanks. And may be just a follow-up, regarding the margin, I guess I already asked you Mark, how instructive with the experience you had with power fuels maybe during the last down cycle I know Nuverra's been an evolving story over the last few years. But just kind of – how instructive if you look at prior down cycles in the way the business is performed and looking at the – what we maybe looking at this year and if you could provide more color regarding experience there specifically with the Bakken asset that we can determine how best to set margin assumptions here at this point?

I think that our margin assumption is really kind of have to be taken a look at both sides, one of them is, we know that our revenue number price per unit is going to go down, but correspondingly we’re going to both from a headcount standpoint, from a margin standpoint, and our cost standpoint, we’re going to make sure that we’re driving our cost down, we know fuel prices are down. And then we’ll have certain activities that we just may not do, if we don’t see the margin profile is adequate in this period. So, there is a lot of levers that we can pull and because we’ve been through these downturns before, I think that gives us a little bit of an upper hand because we know and we’ve been able to successfully manage those in the past. None of this is easy for employees or for customers, but I think the experience should helps us so that when we talk to both our employees, but also our customers, we have a better sense of what we need to do to be successful during this downturn.

Got it, thank you. And maybe one last point I think you’d mentioned, Greg, expectations that you would be cash flow positive does, is that free cash flow or operating cash flow?

It’s probably operating cash flow at this point in time. What we’ll have limited investments, cash flow from investments remains to be same how the year unfolds, but certainly cash from operations we’ve got some opportunities to improve that.

Got it, thanks good luck.

Thank you.

Thank you.

Thank you. Our next question comes from the line of Spencer Joyce with Hilliard Lyons. Please proceed with your questions.

Good afternoon guys. Thanks for taking my call.

Hi, Spencer.

Good afternoon.

Just a couple of quick ones from me and I know it’s getting a little late here for some folks. I wanted to go back to the CapEx for this year and if I understand correctly most of the $10 million to $15 million will be maintenance CapEx, which is also similar to the amount of maintenance CapEx that we saw in 2014. And my question would be what would be ideal level of maintenance CapEx be for you guys under I will call it some more – or just sneeze your operating circumstances I feel like I’ve heard some significantly larger former maintenance CapEx numbers, they need to develop the past is that fair?

Yes, hi, Spencer its Greg. I think it depends on where you’re at in the cycle. So when oil is in the 90 to 110 range and you’re – you can’t keep up with work I think there is a general mindset that you can afford more CapEx. And so maintenance – I will call it maintenance CapEx, but you’re refreshing your trucks, you are increasing your truck fleet size, et cetera. I think in this environment, maintenance CapEx takes on a different perspective. One, we are reducing our fleet size. We’re getting rid of older vehicles and swapping them out on a two for one kind of equivalent in some cases of three per one equivalent. And so you don’t need for [indiscernible] a year or two. You don’t need as much heavy investment in CapEx. And so I think in this environment, what we’ve modeled, what Mark and I’ve looked at is as you know really modest investments in CapEx and that $10 million to $15 million range I think longer term is assuming normalized oil prices in the 70-ish range for instance and you’re kind of still growing with your customers. You’re probably looking at in the $20 million to $25 million sort of mid range for maintenance CapEx just to keep your fleet fresh.

Okay. So if we were to think about it over a cycle per se this $10 million to $15 million we’re seeing currently might be towards the low end and then even in maybe just short of a real boom time we might be thinking in 20 to 25 what kind of the…

I think that’s generally right. You may have some years where you’re investing more and you may have some years you’re investing less, but 20 to 25 for the size roughly. Again getting on the MidCon region, reducing our exposure in TMS and right sizing our fleet in a couple of basins puts less pressure on your need for CapEx in the imminent future.

Okay, all right. Switching gears here, from time to time we’ve heard the idea of – or perhaps this is from the buy side but retiring some of your unsecured loans, as opposed to specifically paying down the revolver or the asset class facility. Is that still a potential for this year or do we just not have enough breathing room on the ABL to really think about paying down those bonds?

I think we are just a little too early in the cycle to start using our liquidity to start paying back bonds or in that and I think we’re better off today to make sure because we don’t know the length of the cycle, we want to make sure that or maybe we are not happy exactly where we are with our interest payments, we know what we have when we put our with our ABL facility we know how long we have a nice runway, we have enough liquidity. So I think that’s something that we think is probably the most important as we take a look at our capital structure this year.

Okay, yes that makes a lot of sense there. Last one from me here just want to touch real quickly on the discontinued ops one of the income statement. I know that TFI has been in there for a year or so now. Can you refresh for us what’s been moved to their over the past couple of quarters? I would assume an exit from some of the Southern areas, but can you let us know kind of granularly what’s impacting there now, that may not have been early in 2014?

It’s only TFI, all of the closures that we’ve announced, were first quarter actions and as of the fourth quarter TFI I think that’s in there.

Okay, so the entire $15 million loss on that line is TFI, there in Q4. Some of that write down, is that partially a write down?

Yes, it is. That is correct.

Okay, that’s make sense. Thanks guys.

Thank you, Spencer.

Thank you.

Thank you. Our next question comes from the line of David Epstein with CRT Capital. Please proceed with your question.

Hi, folks. In your CapEx talk and your cash flow talk for the year, I think it’s probably self evident that before any spending on the XTO pipeline. Can you talk a little bit more about what the form of the financial partnership might be? And then also in the past I think, you guys have talked about construction cost of a $125 million to $150 million. And you talked about that might be like three to four times EBITDA. Are those construction cost are realistic? And are those kinds of EBITDA multiples don’t realistic when you think about where you currently have to try to lock in business for the pipeline in this environment.

Hey, David. Good questions. Yes, the CapEx guidance is before any spending on the XTOs pipeline. Mark and I will both tell you we don’t have the cash flow over the balance sheet this year to spend our own cash on the XTO pipeline. So quite frankly, we are trying to find the right partner. And we’ve got a host of projects that we’re - portfolio of projects that we are looking at that we want to pick the right partner not only for this, first phase which was estimated to be $125 million to $140 million. But for subsequent basis up there in the Bakken’s as well and so we just don’t want a partner who can fund this project, we want to partner with deep enough wallet that can fund multiple projects. Having said that, it’s more likely than not, that it’s a partner that we really like and they like us. Chances are good that overtime we may have the right to increase our ownership in it, but we’ll probably not going to start off with the majority ownership in that partnership just because of someone else using their balance sheet. So that $10 million to $15 million of CapEx certainly does not include anything funded from us from XTO. From a multiple standpoint, water pipeline multiples are far and queue between from a comparison standpoint. And we’ve looked at gas and oil pipeline projects and saw their multiples. Clearly, as Nuverra considers moving more and more away from just logistic services to pipelines and other midstream assets, the multiples for those kind of projects go up. They are very healthy multiples. I think, whatever may have been talked about in the past will have to wait and see until we get this thing funded. Announce what that funding looks like and what those multiples look like before we give any further indication on those.

I’m sorry, I thought some of the multiple was I might have misunderstood, the CapEx projections and then how much EBITDA, you thought the business could throw off based on what some of that the anchor tenant was booking business from you. Is that incorrect?

Yes, that’s a good point. I missed that, sorry. I’m not going to give you that kind of guidance six months after the fact when that was announced. Because that was not an $80, $90 oil and so we’re still evaluating with the customer and with what I’d call subsequent customers around that area. What that pricing looks like, what the economics of that deal looks like? And whether holds up four times EBITDA to the ultimate purchases pricing we will have to see as we get further down the road.

Okay. And as far as the option of kicking in $20 million or $30 million cash and having it be a largely project financed type of spending, that’s not realistic.

While, I think we’re going to maintain those options whether we do it upfront in the early construction phase or rather we do it at a later stage when we’ve signed on more customers. There is a number of ways to structure this kind of project financing, some of it is – you’re putting cash upfront, with your partner and you kind of end up with comparable equity ownership. Other ways maybe you wait as the company as the business development arm and the relationship arm with the customer and you wait till a better situation or better environment to put capital in. So we’re looking at all of those, but at this point in time as Mark said, managing liquidity this year is first and foremost and getting that pipeline funded is important for us, but we made sacrifice a little bit of the initial upfront equity ownership for doing that.

Thanks very much. Good luck.

Thank you.

And ladies and gentlemen, I’d now like to turn it back to management for closing comments.

We would like to thank everybody for joining us this afternoon and we look forward to our first quarter call and thank you.