Nabors Industries Ltd (NBR) 2009 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third-quarter 2009 Superior Well Services, Inc. earnings conference call. My name is Shamika, and I will be your coordinator for today. At this time all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (OPERATOR INSTRUCTIONS).

I would now like to turn the presentation over to your host for today's call, Mr. Dave Wallace, Chief Executive Officer. Please proceed, sir.

Thanks, Shamika. Good morning, everyone, and welcome to the Superior Well Services third-quarter 2009 conference call. Joining me today is Tom Stoelk, our Chief Financial Officer. I would like to remind all those participating on the call today that a replay of our conference call will be available to listen to through November 11th at 888-286-8010. The conference ID for the replay is 574 797 56. The webcast will be archived for replay on the Company's website for 15 days.

Before I begin with comments on our operating performance, I would like to make the following disclaimer regarding our call today. Except for historical information, statements made in this presentation including those relating to acquisition or expansion opportunities, future earnings, cash flow and capital expenditures, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Act of 1934.

All statements other than statements of historical fact included in this presentation that address activities, events or developments that Superior expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by Superior based on management's experience and perception of historical trends, current conditions, expected future developments and other factors that are believed appropriate in the circumstances.

Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond Superior's control which may cause Superior's actual results to differ materially from those implied or expressed by the forward-looking statements. These risks are detailed in Superior's Securities & Exchange Commission filing. The Company undertakes no obligation to publicly update or review any forward-looking statements.

Our call agenda is as follows. I will first provide an overview of our operations and then turn the call over to Tom who will review our financial results. After Tom's review, I will provide some closing remarks and open up the call to Q&A.

While US drilling activity declined rapidly in the first six months of 2009, we have seen a slow and steady improvement in the US land rig count from the June lows. Also there has been a consistent shift during the year in the percentage of horizontal rigs versus the percentage of vertical rigs, and the percentage of rigs drilling for oil versus the percentage of rigs drilling for natural gas. The increasing percentage of horizontal rigs plays into our strength, with our presence in all of the active US horizontal shale plays where operators are drilling longer horizontals with increasing number of frac stages. In addition, our broad geographic footprint allows us to benefit from the increased oil drilling activity.

We are pleased to have returned to positive adjusted EBITDA for the third quarter. Adjusted EBITDA improved sequentially by $10.4 million from the prior quarter to $3.2 million off of essentially flat revenues of $90.8 million. This improvement was due to the effect of our headcount reductions and realized labor, material and repair savings. We continue to closely monitor our activity levels by service center, adjust our costs, and reposition employees and equipment to take advantage of areas with higher activity levels within our broad geographic footprint.

As a percentage of gross revenue, sales discounts increased marginally by 2.1% in the third quarter of 2009, as compared to the previous quarter. While discounts increased, our customers appear to be shifting their focus from trying to get the lowest price to focusing on who can deliver the best service quality. We continue to believe that Superior provides one of the highest levels of service quality across our industry. As many customers choose us based on our service quality, reliability, and safety record, we continue to maintain our equipment to traditional high standards and develop unique technologies and processes for enhancing returns and reducing risk for our broad and diverse customer base.

We still have the leading expertise on our team, which our customers and investors have come to rely upon in both up and down cycles. This expertise was recently recognized when World Oil Magazine named Superior as the winner of the best drilling, completion and production fluids award for our WFR-3B slick water system at the Eighth Annual World Oil Awards.

Our WFR-3B slick water system is a liquid environmentally-responsible non-damaging friction reducer designed specifically for application in shale formations and is utilized in our exclusive gamma frac slick water system. This patented friction reducer lowers pumping pressure requirements, permitting a reduction in necessary well site hydraulic horsepower, and allows the use of saline water in previously used fracture fluid, reducing the demand on local resources of freshwater and reducing the environmental burden of fracture water disposal.

In addition, Superior's ICP-1000 iron control agent received the finalist award in the health safety environment/sustainable development category at the World Oil Awards. This iron control agent has a positive and significant effect on eventual natural gas and oil production by providing iron control at low levels of chemical loading without harming friction reduction properties.

As we've discussed in the past, we see the pressure pumping market rebalancing over time. Some of our larger competitors have commented on moving 10% to 15% of their horsepower internationally. Older, less efficient and less reliable horsepower is not well-suited for today's deeper depth, higher pressures and longer stages, and is being used up more quickly than newer mission-specific horsepower.

Equipment is also being moved out of basins and stacked. The combined effect of these trends is that pressure pumping capacity in North America could decline significantly, which would go a long way towards improving the supply and demand fundamentals in this market.

I would like to note that the majority of Superior's fleet has been built in the 2005 to 2008 time period. We continue to hear commentary on the growing inventory of drilled but not completed wells in the US. While it is difficult to predict when these wells will be completed, it should provide an additional demand driver for our technical pumping and fluid logistic services.

Now let's turn the focus to our five operational regions. Our Appalachian service centers support the Marcellus, Huron and other shale plays. Revenues of $31.8 million in the Appalachian region were up 13% sequentially as Marcellus activity expanded across the region. We are currently running three stimulation crews in the Marcellus, which includes the utilization of crews from our Mid-Continent region.

We have the capability to move more of our resources into the Marcellus as the land and the pricing for our services warrants doing so. Our customers continue to ship their CapEx dollars away from drilling shallow wells to drilling wells in the prolific Marcellus shale play.

Our Marcellus shale technical sales team continues to make progress with new customers, as confirmed by the increased diversity of our customer base and the increase in our Marcellus job count. Our solution focused Marcellus shale technical sales team has specific industry experience in the play, and has helped our customers maximize recoveries and ensure that they are getting the highest rates of return on their investment.

To address our customers' environmental and safety concerns, we are currently offering spill containment rentals. We are also aggressively marketing our World Oil award-winning WFR-3B systems utilized in our exclusive gamma frac slick water system that reuses 25% to 50% of our customers' flowback water to all of our shale customers, including those in the Marcellus where fluid disposal is a significant regulatory and cost issue.

We are a leading provider of nitrogen services in Southern Appalachia where nitrogen-based stimulation treatments and water-sensitive shales is the treatment of choice. We recently completed a Huron shale stimulation in Southern Appalachia where we pumped 244,000 standard cubic feet per minute of straight nitrogen with our equipment. We think this could be an industry record.

We are also utilizing a fracture identification logging tool in a dry air-drilled hole, which gives us a distinct advantage over our competition who can only utilize their tools in a fluid-filled hole which increases the potential for well damage.

Competition continues to increase in this area as competitors move equipment and crews into Appalachia in an attempt to pick up market share in the Marcellus. Our strength in cementing work combined with our consistently-demonstrated high job performance and our reputation for excellent frac service quality helps us maintain our first mover advantage and strong competitive position in our backyard. We also remain the conventional leader in Appalachia.

Revenues in the Southeast region of $16.6 million were up 37% sequentially, with increased stimulation in cementing activity in our Cottondale and Bossier City service centers. We remain focused on [not paying] to work, and improving our economics in this region.

Our Haynesville technical sales team continues to demonstrate our proficiency in performing high-quality completions and high-pressure, high-temperature downhole environments like those found in the Haynesville. Similar to the Marcellus team, our Haynesville team has specific industry experience in the shale. They continue to provide innovative solutions that translate to better well performance and the preservation of economic returns for our customers.

For example, they are introducing their gamma frac slick water system developed in the Marcellus to our Haynesville customers, and are developing alternative profits for the Haynesville market that offered improved high-temperature stability and better crush strength at lower cost than traditional profits. We remain focused on providing high-tech cementing and stimulation solutions to existing and new customers that are required in this high-pressure, high-temperature play.

Revenues from the Southwest region of $17.6 million were down 35% sequentially. The revenue decline was driven by lower activity levels in the Barnett. Barnett activity was impacted by soft utilization in pricing, and the number of wells drilled but not completed continues to grow. The Permian rig count continues to improve with high oil prices. We have increased our oily presence over the last two years with a focus on the Permian market.

We continue to adjust our cost structure in the Southwest by reducing locations and product lines to better match our profitable workload. We see customers in this region trying to lock in high-service quality, which is an indication that utilization and pricing may be firming.

Revenues in the Mid-Continent region of $18.6 million were down 11% sequentially. Similar to the Southwest region, the Mid-Continent region also saw drilling activity levels fall dramatically in the first half of the year, and has been challenged by utilization and pricing weakness. We have aggressively decreased our presence in this basin across all product lines and are also utilizing crews from this region in the Marcellus and other basins.

As a result of these actions, we have started to see price and utilization improvement with the remaining crews. We are keeping one crew active in the Fayetteville.

We continue to maintain our position as one of the premier providers of technical pumping services for deep high-pressure wells in Western Oklahoma.

Revenues from the Rocky Mountain region of $6.1 million were up 169% sequentially. Our activity levels bottomed in the Rockies in May, and we have seen improvements in activity levels as we continued to deliver excellent service quality. We have started moving equipment from the Southwest region to the Rockies to handle this expanded workload.

Activity in the Bakken oil shale play in North Dakota has improved. We are continuing to expand our presence in the active oil areas, while many customers -- excuse me, many competitors have exited the region.

I will now turn the call over to Tom for a review of our financial results.

Thanks, Dave. As Dave mentioned, revenues were $90.8 million for the third quarter of 2009. That was a 0.3% sequential increase. Revenues from our technical pumping services, which include stimulation, cementing and nitrogen, accounted for 86%, or $77.9 million of total revenues. Downhole surveying services, completion services and fluid logistics were responsible for 6%, 4% and 4% of revenues respectively.

While total revenues were essentially flat on a sequential basis, revenues by operating region changed with increases in the Appalachian, Southeast and Rocky Mount regions, which were partially offset by declines in the Southwest and Mid-Continent regions.

On a companywide basis, discounts increased 2.1% sequentially compared to the June 2009 quarter. With the exception of the Mid-Continent region, all other operating regions experienced hires sales discounts for the third quarter of 2009, as compared to the previous quarter.

Cost of revenue decreased 7% or $7.2 million for the third quarter of 2009, compared to the previous quarter. As a percentage of net revenue, cost of revenue decreased by 8.2% to 105.2% for the third quarter of 2009 from 113.4% for the previous quarter, due primarily to savings in labor, materials, repairs and other expenses as a percentage of net revenue. And these were partially offset by the higher sales discounts.

Labor expense as a percentage of net revenues decreased to 22.3% in the third quarter of 2009, which compares to 27.6% in the previous quarter because of higher utilization, reduced levels of personnel, lower benefit costs and furloughs. Material costs as a percentage of net revenues decreased to 39.8% in the third quarter of 2009. That is down from 40.9% in the previous quarter due to realized material cost savings.

SG&A expenses decreased 18.1% or $2.5 million for the third quarter of 2009, compared to the previous quarter. As a percentage of net revenue, SG&A percentages decreased by 2.8% to 12.6% for the third quarter of 2009. That is down from 15.4% for the previous quarter, and that was primarily due to lower labor and other expenses.

Labor decreased 23.7% or $2 million in the third quarter of 2009, as compared to the previous quarter, due to reduced levels of personnel, lower benefit costs and furloughs. Additionally, property taxes, insurance costs and office expenses decreased approximately $100,000 each in the third quarter of 2009, as compared to the second quarter of 2009.

In the third quarter of 2009, we recorded a non-cash charge totaling approximately $300,000 for the impairment of intangible assets associated with a service center ceasing operations. Additionally, as a result of the modification of our credit agreement and in accordance with the FASB topic on modifications and extinguishment of debt, Superior increased its interest expense in the third quarter by approximately $0.5 million for the writedown or writeoff of deferred financing costs.

Adjusted EBITDA increased $10.4 million in the third quarter of 2009 compared to the second quarter of 2009 to $3.2 million, due to previously discussed cost reduction and savings initiatives.

Turning to the balance sheet for a moment. On a sequential basis, working capital decreased $9.6 million from $95.4 million at June 30, 2009, to $85.8 million at September 30, 2009. Accounts receivable increased 3% sequentially at $68.1 million, and our inventory levels remain relatively flat sequentially.

Total long-term debt at the end of September was approximately $227.3 million, with $146 million outstanding on our amended $175 million syndicated credit facility, leaving us with approximately $22 million of availability after adjusting for the letters of credit that are outstanding.

Our credit facility matures in March 2013, and we are currently in compliance with all of our debt covenants. As documented in our credit facility amendment, we agreed to raise $50 million on or before December 31, 2009, through asset sales, the issuance of equity or a combination of both, the proceeds of which are going to be used to pay down amounts outstanding on a credit facility.

We continue to evaluate our asset sale options in the capital markets with a focus on reducing leverage in the Company and maintaining our financial flexibility. For the third quarter of 2009, we made capital expenditures of approximately $5.8 million. We plan to continue to focus on minimizing our discretionary spending, limiting our capital expenditures, and managing working capital to maximize liquidity.

At this point, I am going to turn the call back over to Dave for some additional comments.

Thanks, Tom. We built Superior Well Services into the fifth-largest pressure pumper in the US, and even in this downturn we are actively working to improve our competitive position. We believe that our strength of reliable equipment, high-service quality and technical expertise in the key unconventional shale plays combined to help reduce risk and maximize returns for our customers, as we consistently deliver results based on demonstrated performance and sound technical expertise.

Our management team is experienced and has successfully weathered several down cycles in the course of our careers. Although we have made the difficult decisions required to improve profitability, we are not sacrificing service quality or innovation.

Our plan to endure this downcycle and emerge as a strong competitor remain the same. Aggressively cut costs at all levels of the organization to align our cost structure with the reality of the current market environment; provide the highest levels of service quality and results to our diverse base of strong customers, and acquire new customers on the basis of competitively-priced high-quality service.

Maintain our disciplined approach to managing liquidity and cash flow; strengthen our presence in the markets where we have a clear competitive advantage and high-tech completions, and in the plays with the most durable economics; prioritize capital investments to maintain the performance of our relatively new fleet, ensuring high levels of service quality, safety and reliability.

Continue to innovate and build on our technological advantages and maintain and strengthen our technical sales teams. Last year, we established three basin-specific shale play technical sales teams to position us as the market leader for high-tech and super high-tech work in the most profitable US resource plays.

These teams have been very successful in pushing our high-tech technical fluids expertise into the horizontal shale plays, building relationships with new customers, maintaining relationships with existing customers and securing works in plays, offering long-term potential for activity and growth.

By working together, these teams are all instrumental in deploying our technologies, techniques and best practices across all of our regions and customers. As a result, we believe Superior Well Services is well positioned for an improving market.

Our crews have built a quality reputation one job at a time, and I would like to thank all of our employees for the hard work, continued dedication and professionalism during this challenging year. I would again like to mention that our primary focus is to return to profitability and generate positive cash flow.

Ours is a cyclical business, and we will continue to make adjustments to position our people and assets with an eye towards making the most of the eventual recovery. This concludes our prepared remarks.

I will now to the call over to Shamika to help coordinate our question-and-answer session.

(OPERATOR INSTRUCTIONS). Stephen Gengaro, Jefferies.

Thanks. Good morning, gentlemen. I guess a couple of things. The first thing I would start with is can you give us a sense for sort of the progression throughout the quarter? I mean, so I am trying to get a sense for the way your regions performed in the third quarter versus the second quarter, should that directionally continue in the fourth quarter?

We have made a lot of cost adjusting reductions, especially started getting aggressive late first quarter through the second quarter, continuing some through the third quarter. So a lot of the adjustments that we have made have been due to our cost-reduction efforts.

The other thing that we have done is we have basically taken the approach of backing off from some of the jobs that we were pricing at below cost. So we have changed our pricing structure there, and by doing that we have downsized our position in some of the softer markets and shifted resources to maybe some of the more growing or active markets, which would be the oily areas or certain of the gas markets.

So at this point, we see that trend continuing. But we are seeing some firming up in some of the areas that were earlier softer, which would be Mid-Con and Southwest areas. We are starting to see those firm up a little bit, too. So it may change how we position our assets looking into the future.

And along those lines, we have heard -- I've actually heard different, but I have heard that pricing in the higher-end areas has become a bit more competitive just because you have had so much equipment move to those markets.

As you look at your regions, are you willing to give us a sense for what is most profitable and what is least profitable right now, and how you might think that evolves going forward?

I think we could talk about -- and again, I think we did kind of in our script where we moved resources from, which would -- when you look at the beginning of the year, we were heavily weighted to Oklahoma, the Barnett, Southwest area. We have basically downsized our position in those areas and shifted resources to the eastern markets, which rig count has expanded there. Also some of the oilier basins which would be in a Permian. Even the Rockies area have rebounded with the oil prices. So I think you can kind of base it on where we shifted resources to is maybe where we see some of the better markets.

Okay, that's helpful. And then just a final question I would ask you is any -- and maybe if I just looked at it from an operating income level, any chance you will hazard a guess on when you think that is breakeven?

Still got a few more steps to go. We continue to make good progress. We can see cost side has -- we made a lot of progress there. One thing that has lagged is when our customer pricing was dropping very rapidly, our supplier side trailed at this time period.

Now we are at the point that we see customer pricing has flattened, and we still can see additional improvement on the supplier side. So we are making the right steps, and I can't give you a date when it starts to turn.

Okay, that's helpful. Thank you.

Jeff Tillery, Tudor Pickering & Co.

Hi, good morning. As you look out at the fourth quarter, obviously with the covenants in place you need a little bit of EBITDA improvement in order to hit that target. Do you think that sequential improvement in the fourth quarter comes more from a full-quarter benefit of the cost savings you achieved in the third quarter or some top-line growth?

I think it's probably a combination of both, Jeff. One is you should see continued improvement because we continued our cost reduction efforts through the quarter. One of the things -- and we will be filing our Form 10-Q a little bit later this morning. You will notice in there that we had some service center closures, and David kind of referenced it in a different to general way during his comments where he talked about these poorer performing service centers that were leaking a lot of negative op income.

We have taken some action to basically close those, so you will see improvement just from the standpoint that those are gone. In addition, we will continue -- Dave referenced in his comments about rightsizing some of the locations. We referenced some of the regions that had revenue declines were Mid-Continent and Southwest, and we've continued to focus our cost-reduction efforts there. But I think it will be a combination of both. Appalachia has good activity in the Marcellus. We saw some good activity in Southeast, and so I think it is both.

We are expecting the rig account to maintain steady performance through the end of the year, and based on that we anticipate a combination of both, as Tom said.

Great. One other cost question. On SG&A, is the third-quarter level a sustainable level for you guys going forward? Obviously, I would expect that to tick back up with revenue improving, but just generally in a flattish revenue environment, is that SG&A level sustainable?

You know, I think it is. I don't think there was really anything unusual. The biggest, when you listen to my comments, the biggest change, we had a $2.5 million sequential quarter reduction. About $2 million of that is labor, and I think that is sustainable.

And really the reduction -- the other reductions came really from a combination of property taxes, office expenses and insurance. No reason at this point not to believe that those aren't really sustainable either, so the answer is yes.

Then, Dave, just a question on your capacity. With CapEx levels sub $6 million kind of over the next year or so and where the activity is occurring today being pretty harsh on equipment, do you think that we actually see your capacity erode over the next year, or is $6 million a quarter enough for you guys to keep the capacity flat?

When you look at the CapEx for this quarter, about half of that was still new equipment ordered in 2008. If you look at the run rate on our maintenance CapEx -- and it is a lot -- it is well below the $6 million. So we should be in good shape as far as maintaining the newer fleet that we have on an ongoing basis.

So at this point, we still feel pretty good about keeping the fleet intact and be ready for increased activity.

Great. And my last question is just on the Barnett. You mentioned that specifically, seeing a lot of drills are not completed being an impact to demand in the third quarter. Have you seen any evidence of those previously drilled wells; are you seeing the customer come back and start to price out completion activity for those wells, or is that not yet occurring?

We are starting to see some signs of a little uptick in the Barnett, and it could be a combination of increased rig count and also starting to catch up on the backlog. I think the gas price has kind of popped up to a point that there is interest in trying to start completion on some of those. So we see the Barnett showing a little uptick.

Thank you very much.

Victor Marchon, RBC Capital Markets.

Thank you. First question I had was just on pricing. Dave, I believe you had said it in response to a question earlier. It's just regarding the pricing environment today. Has that remained flat or is there anything else left on downward pressure there?

We see most of the downward pressure is pretty well gone. I mean there is going to see me some spot situations where people may be trying to get a little market position and may put some pressure. But as a general rule, we can see that pricing has flattened out and we can start to see some signs going the other way that -- again, all the service providers have made some major steps as far as downsizing, really shrinking operations, repositioning into some of their stronger markets.

With that, with the rig count going up, we are seeing that basically our customers now are focused more on we want a good service quality crew that we can depend on. We are not going to beat you up for price anymore. You can have a little bit of improvement. So we are starting to see some signs that it is going the other way.

And just as it relates to how the pricing is going to flow through your P&L over the next couple quarters, the sales discounts increases have moderated over the last number of quarters. Is there another quarter or two of just a lag effect where you will see some of that in the fourth quarter or possibly the first quarter as well, or do the sales discount increases basically flatten out as well?

We see the discount number kind of flattening, and again part of that is going to be product mix. Because we are heavy stimulation and it is going to vary by, again, kind of by basin. But as a general rule, discounts by basin has kind of flattened. Now it is just a matter of the mix of the combination.

And looking out a little bit further possibly, I just wanted to see if you guys can sort of guesstimate as to what to think the rig count, you know, would need to get to before you see some sustained or material pricing power back into the industry as a whole, given the equipment that is being taken out of the market and the other equipment that is being moved internationally.

Do you guys have a sense as to when the supply/demand balance will get to the point at which you will start seeing significant pricing power back?

We've got 1250, 1300 rigs, somewhere in that area. But again, as the market continues to rebalance -- and again, we can't emphasize enough about with the horizontal activity going on, all the different stages, how it has really gotten very stimulation intensive.

So there could be a lot of capacity absorbed on a smaller rig count number just based on the increase in horizontal wells going on. But if we see 1200 to 1300 rigs, continue to see the rebalancing of equipment, the heavy push toward more horizontal, more stages, it could occur quicker than that.

And last one if I may, just a comment that you made on the customers locking up equipment, was that specific to a region or is that more of a general comment? I missed that, I apologize.

I think we're probably starting to see that probably more in the Western areas at this point, and again mainly because there has been a lot of rebalancing in those areas. There was a lot of capacity. There has been a lot of capacity moved or shut down, and some of the oily areas have seen pretty significant rig count jumps. So -- and expect to see even more rig count jumps based on budgets for 2010. So I would say those areas is where we have seen the biggest improvement.

Great. Thank you very much.

Waqar Syed, Macquarie Capital.

Good morning, gentlemen. Just wanted to check with you on the sequential progression. You know, from what you know about October, are you seeing better EBITDA? And if you think about maybe estimating putting that EBITDA for October, for the whole quarter, where would you be versus what your $5 million requirement, EBITDA requirement is from the lenders?

We saw EBITDA progression in the third quarter, and it improved monthly and got its strongest in September. As we look at October, we see it continue. The thing that may disrupt that progression a little bit as you are going into November which has a holiday, and you have got December which has a holiday.

But from our standpoint as far as kind of our frac boards and our activity levels, October and November look pretty strong at this point. And we are still gathering some information, I think on December, to be honest with you.

Yes, I think Tom has got a good point, that there is always a holiday factor that, again, you never know how that is going to play out as far as E&P guys want to get aggressive, spend as much as they can before the end of the year, or they are basically in a position to say we are not going to fight our way through the holidays. We may slow down for a couple of weeks and then start up again first quarter.

So I think we still lack a little bit of visibility on how the holiday factor, seasonality factor is going to play out, but the overall theme is rig count is up. E&P guys overall feel a little more bullish on increasing their activity. It is just a matter of maybe some of the timing.

I think we are clearly at this point comfortable with making the EBITDA hurdle, and that is a combination of reductions we have put in place and then kind of our continuing cost-reduction efforts, just as kind of a follow-up to that.

Now, in the last one month or so we have seen a big pick-up in the Haynesville and the Marcellus, maybe 20 rigs plus there and in the Marcellus as well. Those rigs or wells are probably still being drilled, and the pressure pumping and completion work is going to start probably in the next 30, 35 days. And that can have some impact on the demand side, given how pressure pumping intensive these plays are.

Are you getting calls about locking up equipment for that upcoming work in the next month or two?

We are definitely seeing activity in both those areas get busier, and scheduling is getting stretched out a little more in those areas. So the answer is yes.

It'll be interesting in the Marcellus to -- this will be the first active year that they go through with the winter environment to see if the other support infrastructure can keep up with the cold-weather environment or if it delays some projects.

And how about in North Dakota in the Bakken area, would that slow down during the winter months?

Last year it did, and again, lacking a little visibility at this point. They had extremely cold winter last year. They continued to drill during that time period, but they elected not to stimulate. And the combination of the cold weather, and also oil prices were fairly soft during that time period.

Looking at it right now, I think with oil prices up, they will continue to stay active as long as -- and then just work their way through the harsh environment.

And then in Marcellus, there have been some issues in terms of environmental issues, basically relating to some of your competition. Do you have any comments on that how that could affect the legislative regulatory environment in the basin?

It is still a -- when you look at the Central and Eastern Pennsylvania area, the expansion of the activity is still relatively new to really the general population in that area. So there's a lot of concerns that they may have, just because they are not familiar with the industry.

We feel very comfortable about our position in that area because we have worked in some other states where we had to work under the Fresh Drinking Water Act requirements, and Safe Drinking Water Act requirements where we had to pre-certify our fluids, that they were non-toxic and compatible in that environment. So we feel like we maybe have a leg up on some of our competition, that we have already gone through that learning curve.

Well, thank you very much. That is all I have.

Joe Agular, Johnson Rice.

Thank you. I wanted to maybe return to a comment that you made earlier regarding how you were closing service centers where you were actually pricing jobs below cost and losing money. And just maybe get you to, if you could, expand a little bit on maybe what kind of impact that might have had in the third quarter.

Had a little bit in third quarter. We will see a little bit more in fourth quarter. Basically, again, some of the markets we looked at can we centralize, still cover the work from a more centralized location and eliminate some of the SG&A costs, some of the extra duplication costs?

And that is kind of the part that we are looking at. So we have continued to kind of right-size some of our regions just to better match the profitable workload in those areas. So saw a little bit of impact as we downsized in the third, and again, there will be a little bit of impact in the fourth quarter as well.

Very little in the third, Joe.

Well, I guess what I was asking, were those areas still a drag? Were they still a negative operating income number in the third quarter?

Yes, they were.

But in the fourth, that should swing into at least a zero, but maybe -- I guess depending on how you account for it, at least it is maybe even a positive.

Right. I think there will be some fixed costs with respect to those closures with rentals and some lease obligations, but you are right, the majority of those costs that drag is going to be gone.

Okay. I mean you mentioned that you're comfortable with sort of achieving your new target for your facility for EBITDA, which I think is $5 million.

Correct.

Right. Now to get to that number, could you get there with just sort of those cost changes or is that -- is it going to require some help from your just regular business?

I think when we were looking -- I had mentioned in a previous question here where we saw sequential improvement in EBITDA. And if we continue to kind of see what we generated in the back half of the third quarter as well as these cost reductions on top of it. And we continue, Joe, to take a look as Dave referenced to right-sizing some operations and things like that.

We finished the quarter with just a little over 1300 employees, and we continue to look at locations that are underutilized and continue to make some adjustments. So I think a combination of those continued adjustments, the closures and kind of the realization of all the reductions that we have made, that kind of puts us in a position to be able to make that statement.

Tom, what kind of expenses are you incurring right now from moving equipment?

We are expensing the actual mobilization, which would be fuel, manpower, to do all that. So really, we are expensing all that cost at this point.

I mean, is there any way you could quantify it? Was it a material number in the third quarter?

When you think about, again, if you moved just one truck from West to East, it might be 1200 miles at $1.50 a mile. Then you multiply that by a fleet for a stimulation crew of 30 trucks, you know, it can start adding up pretty significantly. So, you know, I am not sure we have a good number for that.

I don't at this point, Joe, on that.

Sure. Okay, one last question if I could. And I know you all highlight frequently the newness of your fleet overall relative to the industry, and I know that you all have outlined the potential for some retirements of older equipment in the industry, some capacity reduction from maybe even movement of assets internationally and so forth.

I was just wondering if you could maybe give us your updated thoughts on if you are yet noticing any effect from reduced capacity in the field at all? I know it is kind of hard to measure other people's equipment sitting in their yards, but if you had any thoughts on that, I would appreciate it. Thank you.

I thing the thing we are seeing is there has been a combination of stacking out equipment, downsizing personnel and it's kind of a multifactor, people moving out of certain regions, closing locations and leaving equipment stacked there. So we see a lot of things happening that is kind of rebalancing.

The other thing we're starting to see is when you start to see the customers wanting to lock in, it says that supply and demand is kind of getting pretty close in some of these areas. And it could be just there may be equipment; they may be talking about competitors could say, well, operating on an extra crew, but the customer is saying they don't want to go through the service quality issues that can come with them expanding out that extra crew.

So I think we are seeing it on the pricing side. I think we are seeing it on the -- you're starting to see a little bit more turned-down work where stuff can't get scheduled. You may get a second call, the opportunity to pick up some additional utilization. And I think all that kind of goes back to the rebalancing not only of the equipment part being moved around, stacked out, placed in the weeds, but you're also seeing the effects of downsized personnel from all these companies also.

Dave, if I could one more. Would you mind commenting on the progress you are making on potentially selling some assets?

You know, we continue to look at a number of options with respect to that, and I mean assets is a pretty broad term. A couple of things that we continue to look at is just the sale of what you would think of as our property plant equipment type assets. But when you look at our balance sheet you have got -- we have the ability to monetize an income tax receivable that we have out there.

We had generated operating losses in the current year which we can carry back, and so we have talked to some parties that are willing to monetize that and to give us some different options and things like that.

So it is really not really one group of assets. It is just a number of things, and we continue to -- we continue to take a look at that and kind of consider our options as we focus on the market.

What is the value of that NOL or the book value?

The receivable I am talking about is a little over $20 million. It is like $20.3 million, I think, Joe. It is pretty close, $20.3 million, $20.4 million.

Okay, thanks. I will jump off. Thanks.

Mike Mazar, BMO Capital Markets.

Hey, good morning guys. I am just curious, in practice if you were to trip one of these quarterly EBITDA covenants, what are really the consequences of that?

Well, what we would -- if we thought we were going to trip it, I mean from a practical standpoint is you would see us go to our bank group and either try to amend the agreement or try to obtain waivers. The consequences if we went into default is we have some intercreditor agreements, and we wouldn't want to do that, is what the short answer would be. Because we have sitting behind the credit facility some second-lien notes, and we would bring that kind of in the scheme of it.

So to answer your question is if conceptually you weren't going to make it, you knew you weren't going to make it and it was prior to year-end, you would be having a dialogue with your bank group trying to obtain waivers or further amend the agreement from a practical standpoint. You wouldn't want to go in default, is what the short answer would be.

Okay, thanks. That's all I had.

Shawn Boyd, Westcliff Capital Management.

Just want to ask on the contracting activity that you're seeing today, we talked about customers wanting to lock up higher-quality crews and equipment a little bit more. Can you use the actual number of wells completed or quoted jobs; is that -- can you quantify that?

Is that increasing now versus a quarter ago, two quarters ago, or is there another metric we can talk about just to give us a little bit more color about what is happening here in terms of the duration of what they are trying to book?

I think that the number of quotes is maybe increasing some. Probably the biggest thing we are seeing is just we can see utilization continuing to tweak up. So, again, utilization probably hit a low mid second quarter, has continued to tweak up in the third quarter. We can say that it looks like it is, again, barring any seasonality, looks like fourth quarter utilization is going to continue to tweak up.

So I think that is the biggest barometer for us that we can see a difference. And we constantly look at it as far as, you know, looking at one basin versus the other; do we want to shift resources. We have basically been making that decision that from the Mid-Con Southwest areas, we have been shifting resources to other basins.

Now we are kind of getting to the point that we are looking at pricing potential, profitability improvement, one basin versus the other, and we may shift -- continue to shift resources.

Got it. And that is a perfect segue, Dave. In terms of profitability, can you give us you know maybe not numbers but even just directionally on how much the profitability is differing right now by region? We have seen some pretty significant upticks here in your quarter. So really, actually, I don't even want to focus on the Q3 numbers. But just in terms of the activity that you are out there bidding on today, how is the profitability of say Appalachia versus Southwest versus Mid-Con, etc.?

Well, our toughest areas that we have talked about, again, have been Mid-Con, Southwest. When you look at the rig count drops in those areas, you were looking at 70% rig count drops in those areas, and there was a lot of capacity in there. So the capacity got extremely aggressive just trying to keep utilization up, which basically meant that we were catching work at a loss.

We basically decided that we were going to quit doing that, that we could -- with our broad footprint, we could shift resources. That is why you see the increases in Southeast, Appalachia, also the Rockies. We talked about the revenue increases there. And that is basically saying that we are shifting resources from softer markets to better markets.

Yes, it is really following the revenues a lot, Shawn. I mean when you see our comments in the script about the three regions that had revenue increases, those are the three that are doing quite a bit better, and the other two are still challenged by discounting and just lower activity levels.

Got it. Very good. Thank you so much.

Jack Aydin, KeyBanc.

Hi guys. I apologize if you answered this question. Utilization, can you give us what was in the mid-second quarter, what was in the third, and what you think could be in the fourth quarter?

Kind of our rough for second quarter would have been probably sub 40%. I mean it got pretty soft when you look at May with kind of our -- what we call our trough. And then we saw a little bit of improvement going forward after that.

And again, I am going to basin on overall stimulation activity.

Okay.

When you look at probably third quarter, we probably started getting up in the mid-to low 40s as far as utilization for our stim crews. And part of that can be a little bit deceiving because, again, on these horizontal wells there is a lot of stages. They can be out there for a long period of time.

The other part to that is when you are not really challenged, as far as trying to stretch your capacity, you will run extra units on those crews just to try to reduce your maintenance costs. But as activities continue to increase, we expect utilization to improve.

Then it gets to the point that to try to stretch out that extra crew, that basically you reduce a few horsepower units per crew and build another crew at that point. So as rig count continues to grow, we continue to see our utilization growing.

So again, we could see another 5% to 10% expected maybe in fourth quarter, barring any seasonality, based on just the outlook that we see today.

Dave, what would take -- what kind of utilization you would need to be in the black, in terms of earning point of view?

We are thinking 50% to 60%; 50%, 55% would probably get us there. And again, part of that utilization as we mentioned earlier is just a little bit deceiving because you may be running extra units per well per job right now. So utilization could look a little busier than it actually is. And then, again, once you get busier, why you start stretching those crews a little bit more.

Thanks. We were at the [DUC] conference. We heard a lot about your recycling treatment of water in Appalachia. Are you getting a lot of inquiries about that one?

We definitely are. I mean, water is a big issue in Appalachia. One, because look at Pennsylvania, you don't have disposal wells. So they have got to truck the water a long way. They have got to work through local municipalities as far as finding a way to treat discharge of water. So the work that our group has done where we can reuse a higher percentage, that is a major cost saving to our customers. So it is having a lot of traction for us at this point.

Thanks, Dave.

There are no further questions in the queue at this time. I would like to turn the call back over to management for closing remarks.

Thanks, Shamika. I appreciate everybody being on the call today, and we look forward to talking to you at the end of the fourth quarter. Thank you.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.