Liz Merritt - VP, IR Mark Johnsrud - Chairman & CEO Greg Heinlein - EVP & CFO.

Brian Butler - Stifel Sean Hannon - Needham & Company Joe Giordano - Cowen Gerry Sweeney - Roth Capital Partners Scott Levine - Imperial Capital Scott Graham - Jefferies.

Welcome to the Nuverra Environmental Solutions First Quarter 2015 Conference Call. [Operator Instructions]. It is now my pleasure to introduce your host, Liz Merritt, Vice President, Investor Relations. Thank you. You may begin..

Thank you, Operator. Good morning and welcome to Nuverra Environmental Solutions first quarter 2015 conference call and webcast. As we turn to slide 2, I would like to introduce 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 the 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 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-Q for the three months ended March 31, 2015, our form 10-K for the fiscal year ended December 31, 2014, our current report is on form 8-K and our press releases 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, May 11, 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 would like to turn the call over to Mark Johnsrud, Chairman of the Board and Chief Executive Officer..

Thank you, Liz and welcome, everyone, to our call. I will start today with a brief recap of our first quarter performance, then Greg will follow with a detailed discussion of our financial results and I will wrap up with some final comments on our views for the balance of the year.

Let's start on slide 4, where I will set the stage for a broader macro trends affecting the marketplace. First, overall drilling and completion activities have declined substantially in the U.S. Land rig count has dropped by more than 50% since the 2014 peak, to 868 rigs on May 1.

Oil rich basins, such as the Bakken, Eagle Ford and Permian have been hit the hardest as price of oil continued to decline through the quarter and operators slowed their drilling and completion activities. Gas rich basins, such as the Marcellus, Utica and Haynesville, have also lost rig count, but not to the magnitude of the oil rich basins.

We would note that the change in the rig count from the 2014 peak in our key basin is down 55% in the Bakken, 41% in the Haynesville, 40% in the Eagle Ford, 13% in the Marcellus and 36% in the Utica. For when bottom will come, that is impossible for us to predict.

As you can see, on the bottom chart on slide 4, that on average, V-shaped bottoms in oil take two months to form. While we can't predict future oil prices, this chart shows that the current price trend compared to the last three cycles would suggest the bottom may have already occurred.

On slide 5, we show that despite industry headwinds in the first quarter, revenues were $119 million, compared to $128 million in 2014. Relative to many of our peers, a 7% year-over-year decline is commendable and speaks to our flexibility to quickly respond to customers' needs.

As we discussed in our last call, we anticipated revenue would be down as a result of lower drilling and completion activities and to a lesser extent, targeted pricing concessions being sought by our customers. Our early actions, to proactively redirect our Business towards production activities, began in October and helped to soften the decline.

First quarter adjusted EBITDA from continuing operations was essentially flat at $18.7 million, compared to $18.9 million in the first quarter of 2014. Despite the decline in revenue, adjusted EBITDA margin improved 90 basis points year over year.

This is a good indicator of our proactive management of our Business and the effectiveness of our cost savings initiatives. I am pleased to say that we generated $30.6 million in free cash flow in the first quarter.

The early impact of the cost-saving measures we introduced in Q1 yielded a 10.7% savings in total operating expenses in the first quarter, compared to the prior year. We're taking measured additional actions in the second quarter that will provide additional savings with no degradation of operational strength or service quality.

As we discussed last quarter, we're committed to being highly disciplined in our spending and expect to continue to operate within cash flow throughout 2015. On slide 6, we will begin our divisional review. Let's start with the Rocky Mountain division, where rig count in the Bakken has dropped more than 55% from a year ago, to around 85.

The backlog of uncompleted wells is in excess of 900 and continues to increase. Customers continue to look for pricing relief. We saw a 15.3% decline in revenue, to $69.4 million compared to $81.9 million in 2014.

The result was driven entirely by lower drilling and completion activities which reduced the demand for rental equipment and water logistics services. Even on the reduced revenue, we held adjusted EBITDA margins steady in the Bakken at 26.4%, compared to 26.5% for the same period last year.

A key differentiator for Nuverra is our ability to bundle and provide full-service solutions which helps decommoditize the pricing environment, to a certain extent. Our proactive move towards production activities in our grid-based service model is very much to our advantage.

To illustrate this point, we have some level of activity on more than 70% of the rigs in the basin, with a combination of solids, fluids and liquid services.

As far as the outlook for the Rocky Mountain division, February marked the second consecutive monthly decline in oil production, to just under 1.2 million barrels a day and the uncompleted well backlog is in excess of 900. To sustain the level of production, operators would need to complete 110 to 120 wells every month.

In contrast, completions dropped to 42 in February from 63 in January and 183 in December. In the context of continued decline in completion activities, we would expect softer second-quarter revenues in this region.

Before I wrap up this division, I would like to provide a brief update on our Bakken water midstream project and Terrafficient solids processing facility.

On the water midstream project, we're presently working very closely with XTL on the engineering specifics for the pipeline system, taking into consideration the trend towards enhanced well completion technologies and high density well spacing. We must be very certain that the engineering system be aligned with customers' projected needs.

When it is all said and done, it is all about meeting the needs of our customers. We must plan for the volumes of our primary contracted customer, as well as the incremental capacity to manage increased volumes over time from customers with adjacent acreage in the basin who want to also benefit from the efficiencies of water midstream services.

Once our engineering is final and to the specifications of our contracted customer, we will complete the selection process for the right partner. We intend to begin construction of Phase 1 of the network this summer, pending no further changes from customers or the macro environment.

Just to reiterate for investors, our water midstream assets include fresh water delivery systems for completion work and maintenance, gathering systems for flow-back and produced water, disposal network and eventually, recycling programs.

On Terrafficient, we're processing solids from multiple wells in the area and expect the facility to be fully commercial and generating incremental revenues in the second half of the year.

With the addressable market for drill cuttings substantially changed from the levels we previously expected, we will revisit our financial assumptions for Terrafficient in the second half of the year. Also, we're pleased that North Dakota bill 1390 passed the legislature and was signed by the Governor on April 16.

The law provides for the severance of legal liability for operators who process their fluids and/or liquids for reuse by permitted and authorized facilities. This action sends a strong message on the state's commitment to reducing, recycling and reuse as a matter of policy and provides risk mitigation option for operators.

We're very excited to provide this valued service to our customers. On slide 7, we recap first quarter results in the Southern division which shows substantial margin improvement in this period. This was despite a decrease in revenue related to the closure of our MidCon locations and lower drilling and completion activities.

Revenue for the first quarter was $22.4 million, compared with $26.9 million in 2014. Of the $4.5 million decrease in revenue year over year, $3.1 million was attributable to the closure of our MidCon locations. Adjusting for this, revenue only declined 6% year over year.

The overall lower revenue was offset somewhat by growth in water transfer services in the Permian basin. In the Eagle Ford, despite the slowdown in completion work, we generated a 14.2% increase in fluids and solids logistics revenue. In the Haynesville, fluid logistics and equipment rentals were down, due to lower activities in this region.

However, year-over-year revenues related to our water midstream assets in this basin increased by 7.8%. In coming quarters, we will take some time for scheduled maintenance on the Haynesville pipeline and disposal well assets which could impact volumes this summer.

The adjusted EBITDA margin for the Southern division increased 460 basis points year over year to 10.3%.

Turning now to slide 8, in the Northeast division, where we serve the Marcellus and Utica regions, we carried solid positive momentum from the fourth quarter into the first quarter, with continued demand for fluid logistics, disposal and recycling services.

We achieved a 42.4% growth in revenue, to $24.3 million and a 590 basis-point increase in adjusted EBITDA margin to $3.8 million, compared to the prior year. The improvements were driven primarily by a higher pace of activities for our largest customer in the region, as well as ramping up activity for new customers in the Utica.

Demand for recycled water, drove 62% more volume through our AWS facility in the first quarter when compared sequentially to the fourth quarter.

The growth in the first quarter was primarily due to new wells starting production, the addition of a new customer and more operators opting to utilize the AWS facility as a means to quickly and efficiently recycle their water.

Our WMGR-123 permit, under Pennsylvania law, provides for the processing, transfer and beneficial use of recycled water to complete wells. This permit, plus the central location of our facility, makes the AWS plant a valuable resource.

I would like to turn the call over to Greg for a detailed discussion of our quarterly results and the process that we have made on our initiatives we outlined last quarter..

Thanks, Mark and good morning, everyone. On slide 9, revenues from continuing operations for the first quarter were $119.1 million, a 7% decrease over the first quarter of 2014 and a 16% sequential decline when compared with the fourth quarter. Typically, our fourth quarter is our strongest quarter from a seasonal perspective.

The decrease was primarily driven by the overall decline in drilling and completion activities and secondarily by the impact of price reductions negotiated with certain customers. Depending on the location and the types of services, pricing concessions average from 7% to 10% in the first quarter.

We feel we got in front of some of those concessions with proactive cost reductions which I will speak about shortly. Pretax income for continuing operations was $248,000 in the first quarter, compared to a pretax operating loss of $5.1 million in the first quarter of 2014.

We attribute this $5.3 million improvement to the early impact of our 2015 cost management initiatives, fuel savings and lower overall amortization expense, all of which drove lower total operating expenses when compared with the same period in 2014.

Net loss from continuing operations for the first quarter was $12 million or a loss of $0.44 per share, compared with a loss of $11.9 million or $0.48 per share, in the first quarter of 2014. Adjusted for special items, net loss was $0.41 per share.

During the first quarter, we booked pretax restructuring and exit expense of $700,000, primarily related to our previously announced exit from the MidCon region and other facility closures in the Southern division.

We expect to have additional restructuring and exit expenses in the second quarter as we complete our 2015 initiatives, driving further cost savings throughout the year. Adjusted EBITDA from continuing operations for the first quarter was down 1% or $200,000, to $18.7 million, compared with $18.9 million in the first quarter of 2014.

Adjusted EBITDA margin improved 90 basis points to 15.7%, compared with 14.8% for the year-ago period. As Mark mentioned, this points to the early effectiveness of our cost saving initiatives, helping to offset pricing pressures.

You will note that in today's announcement, we have provided additional financial metrics for each of our divisions in an effort to give more visibility to basin-level performance. When we look at division level adjusted EBITDA on a year-over-year basis, margins for the Northeast division improved 590 basis points, to 13.8%.

For the Southern division, the improvement was 460 basis points, to 10.3% and for the Rocky Mountain division; margins were essentially flat at 26.4%. Let's turn to slide 10.

Net cash provided by operating activities from continuing operations through March 31 was $34.8 million, compared with a negative $373,000 a year ago, with the increase primarily due to improvements in collections and lower CapEx spend. DSO improved by 6 days to 65 in the first quarter, compared with 71 days at the close of 2014.

I'm going to pause a free moment and commend every Nuverra employee who helped to drive improved invoicing and collections cycle times this quarter. It really does come down to good people doing the right things and working together. Moving on, we're very pleased to close the sale of TFI to Clean Harbors on April 11, for a sale price of $85 million.

We applied the net proceeds of $74.6 million to reduce outstanding debt on our ABL credit facility. In conjunction, we amended our credit facility to release the TFI collateral and reduce the borrowing base to $195 million accordingly. The interest rate and fees remain unchanged.

As of April 17, total liquidity was $77.3 million, consisting of $55.4 million of net availability under the credit facility and $21.9 million cash on hand. Turning now to slide 11, in the first quarter we implemented multiple initiatives to align our cost with activity levels.

During our last call, we projected these efforts would result in annualized cost savings of $20 million to $25 million, with the majority of those savings in the first half of the year. We now estimate full-year savings will be in the range of $30 million to $35 million.

In the first quarter, we achieved a $14.2 million or 10.7%, reduction in total operating expenses when compared with the first quarter of 2014.

These savings include $3 million in payroll and related expenses which includes our exit from the MidCon region, an 8% overall reduction in headcount, $5.6 million in fuel expense savings and $3.6 million in lower amortization expense.

Net cash capital expenditures from continuing operations in the first quarter were $4.2 million, net of $2 million of asset sales. The majority of the net spend related to the Terrafficient facility and transportation related equipment in Rocky Mountain division.

We will continue to maintain a very disciplined approach to capital spending and reiterate our range of $10 million to $15 million in total net cash CapEx for 2015, subject to how we fund our North Dakota midstream project prior to selecting a strategic partner.

As I mentioned on the previous slide, we closed the sale of TFI in mid-April and applied 100% of net proceeds to reduce the outstanding balance on our ABL credit facility. This has helped improve our liquidity dramatically.

We're pleased with the progress we made in the first quarter to manage cost, generate efficiencies, improve liquidity and continue to run the business effectively. As Mark pointed out, the rig count continues to decline into the second quarter. Most of our customers and industry peers are calling for a more challenging second quarter than the first.

Until rig counts start increasing again, we will continue to be impacted. Given all of that, we have taken out cost in the first quarter to position us for a weaker second quarter. We expect the full impact of lower rig count and price concessions to affect Q2 revenues in the mid to upper teens, sequentially, over Q1.

We're striving to achieve margins similar to first quarter levels by prudently managing our operating expenses, working with vendors to lower our cost of services and smartly managing activities in all of our basins. Finally, there are just a few other modeling items worth noting. Annual interest expense should be lower than 2014.

Depreciation and amortization will be in the range of $70 million to $75 million and our effective income tax rate will remain near 0%, due to our federal and state net operating loss carry forwards. With that, I will turn the call back to Mark for closing remarks. Then we will open up the lines to take your questions..

Thanks, Greg. Concluding with slide 12, our team did an excellent job in the first quarter, executing on our 2015 streamlining initiatives, generating $34.8 million in cash flow from continuing operations and $30.6 million in free cash flow which has improved our liquidity position considerably.

As we assess the balance of the year, we continue to operate in a very challenging environment. As Greg mentioned, we expect to see continued volume and pricing pressures on second-quarter results. U.S. drilling activity has experienced unprecedented declines, with nearly 1,000 U.S.

land rigs stacked and the backlog of drilled, but uncompleted, wells growing by the day. When customers decide to start completing wells again, we will be prepared to support increased levels of activity.

Until then, it is critical that we remain highly focused on managing elements within our control, streamlining and scaling our Business to market realities and operating efficiently within cash flow.

We must not lose sight of the competitive advantages we afford our business mix and our ability to leverage Long term opportunities of the production phase of the well's lifecycle. As we discussed last quarter, we're proactively redirecting our business mix in the response to our customers' needs to focus on Long term production activities.

We believe we can achieve 50% of total revenue tied to production activities in 2015, with much of that shift being driven by a higher activities in the Northeast and the Rocky Mountain divisions.

Our operating locations are strategically positioned, particularly in the Rocky Mountain and Northeast divisions, where we have significant resources to serve the areas of the basins where our customers already operate. Long term that we know that our move to more midstream assets will be beneficial to our customers and to Nuverra.

That is why we're working diligently to make sure that we have the right strategic partner as we build out that part of our Business. All in all, we remain confident that we have the right team, technologies, innovations to operate effectively through this cycle and emerge as a stronger company. Everything we do, we put the customer first.

Our thanks in particular goes to our employees, who are working to ensure the success of our 2015 initiatives, that we remain competitive through this down cycle and that we will always deliver the highest quality services and safety to our customers. This concludes our prepared remarks and we will ask the operator to open the line for questions..

[Operator Instructions]. Thank you. Our first question is coming from the line of Brian Butler with Stifel. Please proceed with your question. .

First one, just on the working capital. You had huge savings or a good generation of working capital on a positive in the first quarter.

How does that play out to the rest of 2015? Does any of that did given back or should we expect ending the year with a positive working capital contribution, at or above the level you saw in the first quarter?.

I would say generally, we have accomplished quite a bit in the first quarter. Individual quarters going forward, you might have ebbs and flows, but if you looked at where we finished the year, we had over $30 million of AR as of yearend 2014 that was tied up increased in working capital. We were able to get a lot of that back.

As the year progresses, a lot will depend on completion activity and whether customers start to ramp up a lot of the unfracked wells. Generally, I think we have made major achievements.

I don't know whether that is 70%, 80%, but we've accomplished a lot in the first quarter and a lot will depend on whether we see revenue growth in the back half of the year..

Okay.

Assuming we don't see increase in activity, though, you would expect to hold onto the majority of that working capital gain?.

Yes..

If revenues increased, that is going to be a good thing and putting that working capital would be more of a positive than a negative, but I just wanted to [indiscernible] assume where we're at..

Assuming where we're at, I think we've accomplished a good deal of it. There may be some more upside, not as significant as the first quarter. But conditions could change..

Okay.

And on the pricing pressure you talked about from your major clients in the first quarter, how has that translated into the second quarter? What is the trend? Is that accelerated? Has it leveled off, now that oil has seem to have found some level of consistency?.

I would say generally, pricing has stabilized for the moment. I think a lot of what we will see in the second quarter and what we have kind of referred to in our guidance was late first quarter activity that will flow into the second quarter. But here we're, May 11.

It is too early to call the second quarter totally, but it feels like things have stabilized for the most part..

When you think about that pricing pressure that you have seen from an overall competitive environment, have you been able to take share? Or has everyone just held onto their share at just a lower price?.

And I guess the way I look at it is first that customers, what we saw was more from a customer was pushing down on price early in the quarter. Later in the quarter, there was probably some competitive amongst other vendors that are working for people. And then we have some areas that some of the smaller groups have just really declined.

They are not nearly as aggressive. What I think we're finding are in a lot of places is that the competition is -- we just have to make sure that we can get the work done. It kind of varies a little bit, basin by basin..

A last one, I'll get back in the queue.

On the Haynesville maintenance that you talked about, you give any magnitude on maybe impact on EBITDA or where that kind of can fall out for next quarter?.

I don't think, at this point, we don't really know what the impact could be or how much downtime that potentially could be. But we know that we have some scheduled maintenance that we're going to do, both on the disposal wells and then also just in the pipeline itself..

Okay. But it will have some level of impact on EBITDA, is the right way to think of it..

Yes. The question is whether it is done completely in the second quarter or whether it falls into the third quarter. We have substantial assets between salt water disposal wells and the pipeline and what we collectively call our midstream assets there.

But at this point, we're not saying how much of an impact it will have yet in the second quarter or third quarter..

Thank you. Our next question is coming from the line of Sean Hannon with Needham & Company. Please proceed with your question..

The first question here, wanted to follow-up on some of the pricing questions earlier. I appreciate that there is some stabilization now. It sounded like the majority of the pressure probably came from your Rocky Mountain region or, specifically, the Bakken.

Just want to see if I could confirm that or get any additional color on how you saw price pressures on a regional basis. Thanks..

I guess the way I would look at this, it kind of comes in two different pieces. One of them is, like with our rental equipment in the Bakken, where the drilling and completion activity was down by over 50% and even in the completion was down on a percentage basis more than 50%, that was just -- there is more of a switch.

There just wasn't that activity. On the production side, I think that we were pretty comfortable with that 10% to 15% decline in price. As we look at other basins, everything kind of fits into that same category, based on the drilling. If there is no activity, there is no work..

Okay. And then within the Rocky Mountain there, is there a sense that we could perhaps get for the rough run rate these days of how your landfill is operating and thermal desorption? Any color there would certainly be helpful, since these have been kind of incremental add-on activities..

Yes. The landfill continues to generate volumes, tonnage into the landfill. Generally, I would say that less drilling activity is going to drive less cuttings into the landfill..

Sure..

And then the TDU facility, that is still being developed and finalized. We're working in tweaking things. Expectations are that will be commercial in the back half of the year..

Okay. And then, in terms of the cost savings that you talked about, I think that fuel cost was a very big part of that.

Was this a result of the actions that you specifically took, versus simply getting the benefit of having just lower fuel cost? What perhaps am I'm missing there, based on some proactive measures you can take?.

We have been very proactive. Drivers being smarter, guys mapping out dispatch, smarter routes. Buying in bulk, as opposed to retail. Clamping down on the use of retail cards when guys are purchasing to make sure it is just fuel and not other things. So we have been very proactive.

There is a benefit, obviously, from just the overall diesel fuel prices, but I think this team has been very proactive..

And then last question and I will jump back in the queue. It is a two-part one. The comment, Mark, I think that you had made in answering another question, the concern around revenue growth in the back end of the year, I think it is obvious that would be challenging versus 2014.

But is there an opportunity to grow the second half of the year, versus the first half of this calendar 2015, based on what you know in front of you? And then Part B to that, I'm not aware of or whether you're willing to discuss, if there are any other large customers out there that would be incremental that your working with, similar to what you recently were driving here in the Northeast.

Thanks..

First of all, talked about the Bakken and that there are 900 to 1,000 uncompleted wells that have been drilled. That is a lot of work in consideration for what percentage that we were taking care of in prior years. So as companies start to frac wells, we really see that, that will help our revenue.

The part is, we don't know when that is going to start. We're starting to feel like companies are looking at that now, but we don't know exactly when that will start. That could be in the 1st of June. It could be the 1st of July. It could be the 1st of August.

I think it is a combination of oil prices and also to make sure that they have enough gas gathering capacity in the region that the wells are drilled and completed, because the state regulations are being adopted and being adhered to very closely. So it creates another limitation on some of the operators.

Another area that I think we're going to see some increased activity is in the Utica. We have a couple customers there that have drilled wells and they have not completed them also. It appears that they are getting the infrastructure in place so they can complete the wells and get those online and start producing revenue on a timely basis.

So in two areas that are very important to us, we just aren't sure of the timing when that activity is going to occur. There is a lot of pent-up work that will happen in the future. Just don't know the timing..

Okay.

So it sounds like second half could be stronger than the first half, timing dependent?.

That is what we're focused on, but it is hard to tell at this point exactly when that gets started..

The next question is coming from the line of Joe Giordano with Cowen. Please proceed with your question..

I wanted to touch on the cost savings again. Obviously, the number on the magnitude of the savings was impressive. Maybe you could walk us through your decision-making process on how you weigh cost decisions today versus having the necessary capacity to ramp up quickly when the opportunity arises..

We don't take these lightly. The first priority is making sure we can serve our customers and so that was key. Holding safety up, strong safety culture, was extremely key. Everything that our guys did looked at cost, basin by basin. We made, hopefully, smart choices.

Closing the MidCon, we talked about closing the MidCon in our fourth-quarter call in March. We had a substantial savings take out on that. That will flow through the rest of the year. Fuel, we have talked about previously, good fuel savings, number of proactive measures by our guys.

The write off of the amortization from year end is just over $3.5 million. So a number of actions taken, right down to fuel cards and travel and entertainment cards. We focus on people. We focus on processes. The team did a fantastic job of prioritizing.

The beauty of an environment like this is you take a fresh look at your cost structure and your service levels at customers and your profitability by customer and our teams got behind that hugely..

So the 900 wells that you guys have been mentioning in the Bakken, if something were to happen where that was to really start being worked down in June, for example and that's not maybe likely, but if it was to happen, would you be scrambling to get enough assets in place or are you there and ready to take advantage of that when it does come?.

The thing that we have done is, is even from a workforce standpoint, while we have reduced our total headcount 8%, in some areas, instead of working somebody 12 hours a day, maybe they are getting 8 hours, maybe they're getting 10 hours.

And so we're trying to make sure that we have some capacity within our existing system where we can kind of scale up. I think that we have a fair amount of capacity at this point by just utilizing people that are -- not going to say totally underutilized, but if we cut everything so deep right now, then you wouldn't be able to flex back up.

So if we flex people down a little bit in the hours they are getting, we're able to flex back up as we get busier..

On the 2Q revenue guidance, in terms of the mid- to high-teens decline, would you call out anything specific, basin by basin, that would be worse or better than that in any meaningful sense?.

I think the main thing we have is just what we've talked about, is both on the drilling, as the declines have come in on the rig count, we will feel the full quarter effect of that. Also, historically, 2Q has been when companies have started to ramp up their completion activities. And right now, we're just uncertain as to when that gets started.

But we know the total number of wells that will ultimately be fracked. We're just not sure what the timing is going to be..

One last one from me, in terms of you mentioned 50% goal of production activities versus completion for the full year. I assume that -- hopefully that is getting a little bit more on the production side toward the end of the year, if things are bottoming here.

Where would you put you guys -- where would you peg yourself right now versus that full-year goal?.

We moved in the right direction from the fourth quarter. Moved at a percentage point or two in that direction..

Thank you. The next question is coming from the line of Gerry Sweeney with Roth Capital. Please proceed with your question..

As we're working through all of this pricing pressure, revenue pressure, what have you, what is going to happen to the smaller players? Are you seeing some of the smaller guys maybe shut down, go out of business? Does this create some kind of opportunity when revenue does starts to trend back up?.

I think that this does create a lot of pressure. And I think that there are certain companies that are even larger, that are looking at this space and they're saying that the returns are not here. They are not wanting to put as much focus on this.

And then we're also seeing some of the smaller players that are -- just don't have the bandwidth to be able to manage it. Also and I am going to pick on -- I'm going to look at the Bakken, is with our grid-base network that we have there, we're just kind of logistically positioned to take care of the day-to-day activity.

Also, as there is drilling and completion activities, as that returns, we're still kind of geographically in an excellent position. We also have that same type of network in the Marcellus and Utica. I think in the Haynesville, we're also kind of in the right spots to make sure that we're efficient.

And then the Eagle Ford is so spread out that we're in good positions, but our business there is just a little smaller..

Okay. All this talk about the frac log, the 4,000 uncompleted wells across the U.S., I was under the impression, in the Bakken specifically, there were some types of rules and regulations that you had a year to complete that well as far as drilling..

That was kind of an early comment that was made. But because of the new regulations that have come out around the gas capture percentage, there is kind of a different way that it is going to be looked at and viewed..

Okay.

I mean, there was some talk about just an acceleration and completions around June just because of that backlog, but as it stands right now, you don't see that coming to fruition?.

I think that it depends on the area that the wells are in. Because if they cannot end up with -- because right after the well's been fracked and it goes through that initial production phase, there is a lot more gas that comes on for the first 90 days, 180 days and it all fits into the gas-capture percentage.

If they do not have the infrastructure in place or if they can't put enough gas into the pipeline, then they're going to have to restrict the volume of the wells. I think that some of those regions are just not enough infrastructure in the ground to allow them to frac and complete wells. In some areas, I think that it is more related on price..

Okay. And then switching gears a little bit over to, we will say, maintenance CapEx. I know CapEx was pretty low in the quarter [Technical Difficulty], most of them focused in on the TDU.S. That's up there in the Bakken. As we go forward, obviously you have a lot of trucks running down the road, there is a lot of depreciation with those assets.

What would be, as Nuverra stands today, sort of the maintenance CapEx? You have TFI off the books and as you locate your assets, what would be a normalized maintenance CapEx?.

We said in our fourth quarter call that a normal environment, we probably would have $20 million to $25 million of annual CapEx. This year we're expecting $10 million to $15 million, subject to our pipeline and midstream asset activities.

Generally, we would expect $20 million to $25 million and that is somewhere between 50% and 60% of that is maintenance CapEx and the rest being growth CapEx..

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

I was hoping for a little bit more color on the cost saves in the guidance. I think, Greg, you'd indicated that you thought EBITDA margins in 2Q could be comparable to Q1, despite the sequential declines in revenue. That would imply, on some quick math, roughly half the detrimental margin that you reported in the first quarter sequentially.

I'm guessing some of this is incremental cost savings realization. Maybe a little bit more color on those cost savings, the timing you expect it to roll in and where the upside to your prior target is coming from..

As you know, we upsized the cost savings for the year by about $10 million, from $20 million to $25 million to about $30 million to $35 million. A lot of the actions we took began in March, so we didn't get the full benefit of those cost savings in the first quarter. They will flow through into the second quarter.

And so while we will expect revenue declines in the second quarter sequentially from the first quarter, we're striving, the team is striving, to offset those declines with cost savings that should approximate margins that we saw in the first quarter..

Can you give us a sense on how that breaks out between caught OpEx and SG&A? Are you looking to get realization of that full $30 million to $35 million in the P&L this year? Is it a run rate you're looking at by the end of the year?.

We will see the full impact of that this year, P&L. It is almost balanced. SG&A will be a little bit impacted by the second-quarter events, versus the first quarter. The direct cost gross margins will probably be more impacted in the second quarter, as a result of this achievement of additional savings..

And then, just turning to the footprint geographically, you talked about exiting the MidCon. I think last couple quarters you're doing that. It sounds like the Northeast is doing really well for you.

Do you have any additional thoughts with regard to your footprint? Are there markets you might consider getting out of? Are you conceivably looking to get into additional markets, take advantage of opportunities here? Just trying to assess your mindset with regard to the regional footprint generally..

Mark and I and the team are constantly assessing every basin. For the benefit of our employees out there and customers, we think we have achieved the right balance in all of our basins. I think our efforts are now focused on the pipeline and driving our midstream asset portfolio improvements.

So we've got plenty of opportunities up in the Bakken to grow our pipeline project around the core customer with XTO and we're focused hugely on that. And then where we can, we're looking at other midstream projects with customers that have similar objectives..

[Operator Instructions]. Our next question is coming from the line of Scott Graham with Jefferies. Please proceed with your question..

I guess I first want to say, I think you guys did a great job this quarter. You really did. I mean, the margins were really impressive that you guys were able to get ahead of things like that. I was wondering if, at the risk of kind of pushing the envelope here, you guys have been extremely forthcoming also with the data you're providing.

Can you give us what the backlog of wells completed but -- drilled but not yet completed in the other two regions?.

What we see so far, Scott, is a total in the U.S. of 4,000. The Bakken is 900 to 1,000. I am just kind of anticipating, kind of on a percentage basis, there is some in the Haynesville. There is going to be some in the MidCon region.

But Marcellus, Utica, I don't think anybody is necessarily coming out with what that is, but I think without question, we're seeing a lot in the Eagle Ford and Permian. For example, EOG, they talked in their call about they have 350 wells that are uncompleted. That would be Bakken, Eagle Ford and Permian.

I would like to give you a little more color, but I just don't have anything better than that..

I want to ask a pricing question a little bit differently than the way it has been asked.

How much of your business, in total, has there been an ask down on pricing?.

That is kind of a customer and basin-by-basin type discussion. For example, in the Marcellus, we have had a longer-term contract with a large customer there that has kind of semiannual agreement, so it is much longer in nature. In the Haynesville, our pipeline contracts were for 7 to 10 years, so that is not changing.

I think as we start to kind of pare that back, part of the pricing, then, will be around our rental equipment, completion activities which is just, by definition, off dramatically. And then, the rest of it, our production related activities, I think we have tried to say that 10% to 15%, overall.

It really varies by basin, how we have looked at and how I would answer that question, Scott..

Right, because you can understand, it sounds to me like it hasn't impacted a ton, because if I am looking at the year-over-year revenue, the decline would suggest -- I mean, obviously we have volume and price and mix, the three of which equal sales, right? So it seems to me that the pricing did not impact a lot of the business in the first quarter.

Let me ask this question this way.

Would you say that your 10.7% reduction in costs, that had to well exceed what the pricing was, right?.

Yes, that is right. A lot of -- to complement Mark's answer, a lot of customers -- there were a lot of discussions during the quarter with customers. And in some cases, customers simply returned rental equipment, right? It wasn't about price. It was simply they didn't need it. So you can't answer this with an across-the-board answer.

It is really specific to customers. But generally, there have been ongoing discussions with all customers. As being the new guy on the block, the encouraging message from all of that was, customers want to work with Nuverra. In every basin, customers want to work with our teams. And that is a good thing.

Now it is just a question of finding that right balance between price and service and maintaining high safety standards that a lot of our smaller peers can't match. We're never going to get into specific customer stories, but generally, customers want to work with Nuverra and that is a good thing..

I was also wondering and you guys and I, we talked about this following the last conference call, was that this pipeline that you guys are committed to here, I know that you have been looking to get, let's just say, artistic with the way that it will be financed.

Is there anything more you can tell us about that?.

I think at this point, we have had kind of a couple things that have changed since we announced it. Number one, the overall price of crude oil prices obviously dropped. We wanted to make sure that everyone that would be included, primarily XTO, that their drilling plans still fit what we have in place on a longer-term basis.

Another thing that has popped up is the enhanced completion techniques that companies are using by increasing the amount of water and sand. The amount of water may increase four to five times that amount.

As we build this system, we want to make sure we're working in lock step with the customer so that we can solve a longer-term problem and so this fits very well. We have a great relationship with XTO. We're working with these guys hand-in-hand.

The season for starting to build projects is just getting going in the Bakken, so our plan is, this summer, we will get started. We build this ultimately in phases, so there would be -- as the phases get completed, they will get turned on so you don't have to have everything in place, day one.

But I think, as far as getting back with kind of the financing, we will have some information out for everyone relatively shortly..

I will go ahead and turn the floor back over to management for any additional concluding comments..

We want to thank everyone for joining us today and look forward to talking to you all next quarter..

Thank you. Ladies and gentlemen, this does conclude today's teleconference. We thank you for your participation. You may disconnect your lines at this time..