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Basic Energy Services, Inc (NYSE:BAS)

Q2 2013 Earnings Call

July 26, 2013 9:00 am ET

Executives

Jack Lascar - President and Managing Partner

Kenneth V. Huseman - Chief Executive Officer, President and Director

Thomas Monroe Patterson - Chief Operating Officer and Senior Vice President

Alan Krenek - Chief Financial Officer, Senior Vice President of Finance, Treasurer and Secretary

Analysts

Jeffrey Spittel

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

James M. Rollyson - Raymond James & Associates, Inc., Research Division

Brian Uhlmer - Global Hunter Securities, LLC, Research Division

Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Michael W. Urban - Deutsche Bank AG, Research Division

Michael Cerasoli - Goldman Sachs Group Inc., Research Division

Daniel J. Burke - Johnson Rice & Company, L.L.C., Research Division

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Travis Z. Bartlett - Simmons & Company International, Research Division

John R. Keller - Stephens Inc., Research Division

Operator

Good day, ladies and gentlemen, thank you for standing by. Welcome to the Basic Energy Services Second Quarter Earnings Conference Call. [Operator Instructions] This conference is being recorded today, Friday, July 26, 2013.

I would now like to turn the conference over to Jack Lascar. Please go ahead, sir.

Jack Lascar

Thank you, Damian, and good morning, everyone. Welcome to Basic Energy Services 2013 Second Quarter Earnings Conference Call. We appreciate your joining us today. Before I turn the call over to management, I have a few items to go over. If you would like to listen to a replay of today's call, it's available via webcast by going to the Investor Relations section of the company's website at www.basicenergyservices or by telephonic replay until August 9, 2013. That information was provided in yesterday's earnings release. The information reported on this call is only as of today, July 26, 2013. Therefore, you are advised that time-sensitive information may no longer be accurate as of the time of the replay. Before we begin, let me remind you that certain statements made by management during this call may constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management's current expectations and include known and unknown risks and uncertainties and other factors, many of which the company is not able to predict or control, that may cause the company's actual results or performance to materially differ from any future results or performance expressed or implied by those statements. These risks and uncertainties include the risk factors disclosed by the company in its registration statement on Form 10-K for the year-ended December 31, 2012, and subsequent 10-Qs filed with the SEC.

Further, please refer to these statements regarding forward-looking statements incorporated in our press release from yesterday. Please note that the contents of this conference call are covered by this statement.

At this point, I will turn the call over to Ken Huseman, President and Chief Executive Officer.

Kenneth V. Huseman

Thanks, Jack, and welcome to those dialing in and those on the webcast this morning. Roe Patterson, our Chief Operating Officer; and Alan Krenek, our Chief Financial Officer are joining me on the call. The format for this morning will be slightly different than what we've followed over the last several years. Since Roe will lead these calls once I retire, I'll ask him to provide the operational overview and an update of our current activity levels and pricing environment. Alan will then discuss our financial results in more detail, and I will come back and provide you with our outlook for the remainder of 2013.

Generally, we are pleased with the operating results given current market conditions. Our 7% sequential increase in revenue and 20% increase in EBITDA, I believe, confirms the strength of our organization and market position. I'd like to commend our management team for those achievements in a very competitive environment. Our positive performance was overshadowed by the reserve we established for the expected settlement of a claim dating back to 2008.

We elected to settle this case following remediation effort rather than prolonging the process and spending additional cost, resources and time on the matter. While we can't discuss the specific details of the settlement, we can say that it relates more to inadequate post-action management of the case on our part rather than to the action itself. We've taken the necessary steps to prevent such missteps in the future and the settlement should not be extrapolated beyond this specific incident. With that, I'll turn the call over to Roe.

Thomas Monroe Patterson

Thanks, Ken, and thanks to everyone joining us on today's call. As we discussed in our first quarter call, our customers began to increase their activity in the latter part of the first quarter, and that increase gradually continued in most markets throughout the second quarter. Some heavy but seasonal rain and snowstorms did affect activity in our northern Rocky Mountain market and the Mid Continent region. Generally, activity improved as a result of increased daylight hours. While we were pleased with the ramp in activity, the much-anticipated rig count increase in oil-driven markets, that many companies have forecasted, has really yet to materialize in any kind of significance. We anticipate a flattish count for the remainder of the third quarter as many of our customers have suggested their spending will be flat or even slightly down from current levels for the remainder of the year. Now let's review each of our reporting segments. Completion and Remedial Services, our largest segment, experienced a 12% increase in revenue quarter-over-quarter. Strong demand for our pumping and rental and fishing tool services made this segment our best performing segment in the quarter. Despite higher discounts in our Permian stimulation services and overall coiled tubing markets, margins in this segment rose from 33% to 35% driven by higher utilization and our efforts to reduce cost. Looking forward, pricing will remain very competitive in this segment as excess capacity remains an issue. However, we have essentially full calendars in the third quarter, which may portend price stability, if not some pricing power, between now and the end of the year. That remains to be seen as current activity levels and rig count would suggest revenue and margin for this segment will remain flat in the near-term.

Our Well Servicing segment showed a 6% sequential increase in revenue as utilization rose to 74% on improved daylight hours. We have shown 2 sequential quarterly increases of 2% in our average rig rate. Pricing overall remained flat, but a steady flow of 24-hour work in our land and barge fleet and a full calendar of more comprehensive plugging and abandonment activity drove the increase in these average rig rates. Margins in this segment rose 200 basis points to 28% due in part to lower unemployment taxes and higher utilization. Near-term, we expect revenue and margins to be flat until industry utilization stabilizes above the 75% range. Our Fluid Services segment saw an increase in revenue of about 2% in the second quarter. The increase was mainly due to investments we've made in expanding our Water Solutions services, where we received full quarter contribution from the Atlas Equipment and Petro Water acquisitions.

Segment margin declined slightly by 70 basis points to 30.7%. This segment remains highly competitive as competitors continue to migrate to busy oil markets. We've seen significant discounting of frac tanks and other ancillary services within this segment, which holds that margin to low 30% range. We expect attrition among some of the smaller players in this segment in the near-term. That, along with some possible increase in drilling activity or stronger gas-oriented business, could consume capacity overhang in this segment over the next 6 months and allow margins to move up.

Our drilling segment revenue was flat with that of the first quarter at $14 million. Rates in this segment were also flat with the first quarter as we experienced revenue of $16,500 per drilling day.

Utilization was down slightly from prior quarter of 79% to 77% in the second quarter. This decrease was due to some of our customers transitioning their drilling dollars to deeper horizontal drilling programs in the Permian Basin. In addition, a few of the oil-driven vertical drilling programs have been reduced due to regulations restricting the flaring of associated natural gas. We stacked one of our 3,000-horsepower super singles in response to this decrease in demand for mid-depth vertical drilling rigs. However, our shallower mechanical rigs and our larger horsepower electric rigs had maintained stable rates and utilization. Margins in this segment fell from 35% to 30% on lower utilization and some major repair remains on our work fleet. Now I'll turn the call over to Alan for more review of the financial results for the quarter.

Alan Krenek

Thanks, Roe. This morning, I'll provide additional details on our second quarter income statement as well as discussing balance sheet, cash flow items including capital expenditures, then I'll turn the call back over to Ken, who will speak to our near-term outlook. As usual, when making comparisons, my comments will focus on sequential changes. As already mentioned, our total revenue increased 7% sequentially in the second quarter, with the largest increase being generated by our Completion and Remedial Services segment. 58% of revenue in that segment in the second quarter was from our pumping services, 23% by rental tools, 11% by coiled tubing, 6% by snubbing services and the remainder by other services.

In our Well Servicing segment, our Taylor Rig manufacturing operation had revenue of $2.6 million and segment profit of $502,000 compared to a revenue $3.7 million and segment profit of $516,000 in the first quarter.

Permian Basin continues to be our largest market, generating 44% of our total revenue for the 6 months ended June 30. Our G&A in the second quarter, excluding the $8 million pretax impact of a legal settlement, was $41 million, 13% of revenue, slightly lower than $42 million or 14% of revenue for the first quarter. We expect that G&A expense will be approximately $40 million in the third quarter. Additionally, through our recent cost savings initiatives, we would expect G&A to be $39 million for the fourth quarter. Depreciation and amortization expense increased to $52 million in the second quarter, up from $50 million in the second -- first quarter due to our recent CapEx and acquisitions. We expect that depreciation and amortization for the third quarter will be approximately $53 million. Net interest expense was $17 million in both the first and second quarter of this year and we expect the quarterly net interest expense to be $17 million going forward.

Our second quarter effective tax benefit rate was 18%, down from 46% in the previous quarter. We are required to true-up our tax rate on a quarterly basis through our expectations of income or loss before taxes for the full year. Given our current view, we've revised our expectations downward from our projections earlier this year, resulting in a lower effective tax rate for 2013.

We had an effective tax benefit rate of 18% in the second quarter in order to get to a 32% effective tax benefit rate for the 6 months ended June 30. Our net loss for the second quarter was $6 million or $0.15 a share for both basic and diluted shares, excluding the $7 million after-tax legal settlement. Weighted average shares outstanding were $40.3 million. We have not repurchased any shares this year and have $20 million remaining under our approved share repurchase plan.

Moving on to the balance sheet. On June 30, we had a cash balance of $96 million, up from $81 million on March 31 and down $135 million at year-end -- at 2012 year-end. This decrease from year-end's mainly due to the acquisitions we completed in the first quarter as well as the capital expenditures we made during the first half of this year. Total liquidity, including availability under our revolver, was $324 million. There were no amounts drawn on our revolver at June 30. Our DSO at the end of the second quarter was 64, down from 68 at March 31. The decrease in DSO was attributable to our continued focus on credit and collections. Our top 10 customers for the last 12 months ended June 30 represented 36% of total revenue, with no customer over 8%. We ended the second quarter with $887 million of debt, consisting of $300 million of recently issued senior notes that are due in 2022, $476 million of senior notes that are due in 2019 and $111 million of capital leases. Our total debt to adjusted EBITDA for the second quarter-end was 3.8x. With our debt-to-EBITDA ratio being close to the maximum permitted by our revolver, we already started discussions with our bank group to get relief for that covenant. Our interest coverage ratio was 3.7x at June 30, well above the minimum required by our revolver. During the first 6 months of 2013, we generated $66 million of cash from operating activities. We used $79 million in investing activities, including $78 million for cash, capital expenditures and $16 million for acquisitions, and we used $26 million for financing activities. During the second quarter, total capital expenditures were $50 million, including $16 million for expansion projects, $28 million for sustaining and replacement projects and $6 million for other. Expansion capital spending included $7 million for the Fluid Services segment, $7 million for the Completion and Remedial segment and $2 million for Well Servicing. At this point, I'll turn the call back over to Ken.

Kenneth V. Huseman

Thanks, Alan. As you've read in our press release and heard in our prepared remarks, the market continues to be challenging with too many service providers chasing available demand. We think this imbalance will continue through the remainder of 2013. The drilling rig count has likely reached its peak for the year as several active E&Ps indicate plans for scaled-back activity even in oil-oriented markets like the Permian Basin. And with continuing weak gas prices, gas activity has failed to materialize to any significant level. So we're projecting flat sequential revenue for the third quarter followed by the usual seasonal drop-off in activity in the fourth quarter, as shorter workdays, holidays and winter weather come into play. Most of the deterioration in rates has probably occurred since current rates generate cash losses at low utilization levels, which will tend to push higher cost competitors to the sidelines. That attrition combined with a modest increase in activity over the next 6 months, may actually provide opportunities for rate improvement in our better markets. Along with revenue rates, margins have likely bottomed. While we will match wage increases to prevent poaching of our qualified personnel, we'll be very aggressive in scaling our operations and controlling cost. Overall, we continue to retain our exposure to as many of our markets as possible with market-based pricing and aggressive cost controls. Our management team has done a great job of holding onto that in some markets, increasing our market position while protecting our pricing and margins. We've reduced our capital spending program by $20 million and expect to spend less than $165 million now compared to our improved capital budget of $185 million. That spending can, however, be ramped up quickly as market conditions warrant or special opportunities arise. Acquisitions continue to interest us as we steadily review a series of deals. We have seen no compelling opportunities recently due to fairly rich expectations on the part of sellers. In summary, we're looking forward to an improving market in 2014. Operator, let's open the call to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from the line of Jeff Spittel with Clarkson Capital Markets.

Jeffrey Spittel

Maybe if we could touch on -- in the Permian specifically, you talked about even in the oily markets, you're not necessarily seeing that spending appetite tick up. With your conversations with customers, what do you think is the primary factor there? Is it a matter of drilling efficiencies and needing not as many rigs? Is it infrastructure constraints? Is it kind of the transition to a more horizontal work? What do you think is the hang-up on their part?

Kenneth V. Huseman

It's a combination of factors. And I think I'll let Roe address that question.

Thomas Monroe Patterson

I agree. It's the combination of things we're hearing from the field. Obviously, the takeaway capacity is an issue in some other parts of the Permian with some specific customers there unable to flare their associated gas that's slowing some things down. There's a good systematic approach to their activity. They're not jumping off and really firing anything up. They're happy with the workload that they have, the engineering staff that they have and they're trying not to get ahead of their own cash flow. And that's the sense we get from them. They -- I don't think anybody's out there drilling on a $105 a barrel. They're out there trying to be careful with their money. That's the approach we feel like they're taking.

Kenneth V. Huseman

I think also the Cline Shale probably has not developed to the extent it was projected and some people expected. We've seen competitors actually move into the eastern part of that market in anticipation of that. That activity is not developed and so that just means more competition migrating even further west into the main part of the Permian Basin. So it's a combination of not quite as healthy of activity levels compounded by even more competition than was there last year.

Jeffrey Spittel

Sure, makes sense. And then you referenced rich expectations in terms of potential deals that are out there. Are there any particular service lines or maybe there's a little more distress, or there's equipment sitting on the showroom floor where the expectations appear as if they might start becoming a little bit more reasonable?

Kenneth V. Huseman

We've seen some fabricators offer some equipments, new equipment, at not discount prices, not so cheap that we can't stand it and act on it. But I think all the sellers are sort of putting their best face on it and holding out for deals that we don't consider viable.

Operator

Our next question is from the line of Neal Dingmann with SunTrust Robinson Humphrey.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Say, Ken, for you and Roe, I'm just wondering within the Completion Remedial Services, obviously, look like they actually trended pretty good considering all things for second quarter. And I'm wondering within that, the coiled tubing and snubbing, just wondering, in those 2 particular, are you still seeing solid demand there or is there still a little bit of pressure because of capacity? Or just wondering if you could go through sort of the frac versus snubbing versus coiled tubing. Just wondering how they look as far as margins, given the capacity for all -- each of those 3 areas?

Kenneth V. Huseman

Okay. I think we've been able to keep our calendar full but not at -- not about some discounting. And I'll let Roe fill in the blanks on that.

Thomas Monroe Patterson

Where we operate those lines of business, activity's just been very steady. But it's not ramping up, it has been flat. And we have seen some competitors creep into those markets. As they've come in, we've had to increase discounts to make sure that we keep our market share.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. Okay. And then, it's -- Roe, does that stay true also with the -- when you -- are you including snubbing on that as well?

Thomas Monroe Patterson

Somewhat. And snubbing is probably not as intense in snubbing as it's been in the stimulation in the coiled side, but it's just a matter of time. Whenever that competition tends to migrate around, they're going to follow the work.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then lastly, my -- just last question, just on Well Servicing. Ken, your thought on as far as is there a need right now to bring some more rigs out there? I'm just wondering what the -- your thought on adding more rigs at this time?

Kenneth V. Huseman

We have some available equipment. So far, recently, we really redeployed some assets, internally grow than activate more. Some of these markets activity ebbs and flows and so we'll move some equipment around. So we've actually addressed additional opportunities in the Permian in that way. But I think the industry has plenty of equipment, just as we have plenty of equipment, it may need to relocated, but overall, the industry is in pretty good shape.

Operator

Our next question is from the line of Jim Rollyson with Raymond James.

James M. Rollyson - Raymond James & Associates, Inc., Research Division

Ken or Roe, maybe a little color on Fluid Services. Your margins have kind of been hanging around this low 30% level, high 20% over the last 3 quarters. All we seem to hear about is the challenges and overcapacity on the tank side. Just maybe a little color on ability to hold margins in that business going forward and maybe just some color on the SWD business, how that's tracking along.

Kenneth V. Huseman

I think the range of services, the comprehensive capability that we have, has helped us maintain those margins. The single line provider, those guys that just have tanks or just have trucks, are applying the pressure to this business overall, and that's what I meant by those guys. We'll see some attrition take its toll. So it just takes a while and a shorter period than our other segments for that segment to rightsize itself. But it -- we're in that process now. And I'll let Roe talk about the regional differences.

Thomas Monroe Patterson

Well it's tough in every single market, but these spot guys that are out there competing for their hourly work. And the by-barrel work from market-to-market without SWDs are the ones that are the quickest to lower their rates. So we focus on improving our SWD position and feel like that gives us the competitive leverage to squeeze those guys out when it gets really lean. And I think that footprint of SWD has been what's helped us hold our margin.

James M. Rollyson - Raymond James & Associates, Inc., Research Division

And that -- do you think that margin level continues?

Thomas Monroe Patterson

I think it's going to be tough. I think if this competition doesn't start to -- we don't start to see the attrition that I've talked about in my comments, it will be tough. It's going to be hard because those guys -- every asset they own rolls and they're going to move it to where the work is. And to their last breath, they're going to discount to try to hold themselves above water.

James M. Rollyson - Raymond James & Associates, Inc., Research Division

Yes, make sense. On the contract drilling side, costs were up a fair amount sequentially. And I think you mentioned, Roe, just maintenance and repairs and, maybe to some extent, utilization. Maybe a little thoughts on how that cost line trends going forward for the next couple of quarters at least?

Thomas Monroe Patterson

I think this quarter, we just had some catch-up work to do on some maintenance, and I think it will be relatively flat. I don't see it creeping up anymore. This was just some things that we have to do from time to time to these rigs to keep them in service. They've been highly utilized and, from time to time, you have to have a little downtime and do that maintenance work. And it's -- sometimes, it creeps up when it gets a little bit expensive. But I see it -- trending out, I think it will be flat.

Kenneth V. Huseman

For the small fleet, those relatively small numbers can move that margin.

James M. Rollyson - Raymond James & Associates, Inc., Research Division

Absolutely. And Ken, the last thing, just you were talking about competition in the Permian. A lot of guys moved out -- equipment out maybe in advance of the ramp-up in the Cline. What does it sound like when you talk to customers about when that particular play might start to see some pickup in activity? And when it does, do you think there's already adequate capacity out there for that? Or just kind of how you think about that over the next few quarters.

Kenneth V. Huseman

Yes, the -- I think that's a good example of why you don't chase a drilling program if you're in the service businesses that we're in. There's just so much capacity in some of this other markets, adjacent markets, like the Barnett Shale still, and some of those guys repositioned in anticipation of that. It just doesn't look like that as a blanket play that a lot of people assumed. There's -- it probably will develop but it's going to take a little longer. And we don't know -- we're not privy to what everybody is actually seeing there. But the lack of a rapid increase in drilling activity tells me that it may be not what was originally projected. But other than that, that's all we know.

Operator

Our next question is from the line of Brian Uhlmer with Global Hunter Securities.

Brian Uhlmer - Global Hunter Securities, LLC, Research Division

I have a couple of quick and easy ones. First one, I wanted to discuss what's your commentary on the vertical drilling, cash shutting off due to the lack of bid on rigs and flares coming out? Do you see these guys dropping midstream small compression on site and tie them into lines like those are transitory issue and they're just -- they'll do that? Or do you think that the economics has been hampered that this is kind of a permanent effect?

Kenneth V. Huseman

That's an E&P question probably. But -- and it's customer-specific and even location-specific. Eastern New Mexico is probably a bigger factor in that regard than West Texas and it's just been something that's developed fairly recently. There's a lot of gas being flared in West Texas and I think we might have hit the limit of what's going to be allowed to -- what's going to be allowed to be flared. Would you add anything that I missed on that?

Thomas Monroe Patterson

No, I think you're dead on. I think that it's customer-specific. They are allotted a certain amount of flaring capacity and what we've seen is some of our larger operators run into or bump their levels. And that's a fluid thing, it moves around. Those flare mounts move around as their production moves around. So that dictates how much money they can spend at the bit.

Kenneth V. Huseman

There are a lot of pipes being put in the ground and how long this will take, I can't really answer that. That's an E&P-specific question.

Brian Uhlmer - Global Hunter Securities, LLC, Research Division

My second one is -- I'm trying to figure out, I guess with the volume of wells that we've added, especially in oilier basins, obviously, the well designs are getting a little more complex and possibly a little bit better with control systems where you go and pump -- or a pump breaks out a little bit later. But yes, with your increase in the revenue and utilization in well servicing and the well counts increasing, how come that you're not, I guess, a little more bullish on that market? I get the capacity argument, but just kind of explain your thoughts there may be as we go through Q -- the back half of the year and then into '14?

Kenneth V. Huseman

We kind of have to run through an equation. There are about 1 million wells in the U.S., and 3,000 well service rigs have addressed those needs throughout my career. We're adding about 30,000 new wells a year and it just doesn't move the meter each month on well servicing demand. Particularly, with gas being out of the market right now, that gas -- those gas rigs are underutilized and can be relocated and have been relocated into the oilier markets. We've done that ourselves. So we haven't outpaced the demand or the available fleet, I should say, with the increased well count just yet. I mean, we're adding 30,000 wells a year on top of 1 million. It takes a while to move that meter. Now every well that's completed, particularly, these horizontal wells, they're more complex and probably, more serviced but it's too soon to feel the effect of that. We're doing the completions on those wells but, again, completions take a couple of rig days. There are rigs at or around the country. So I think that you have to consider the total well count versus available rigs and put that in perspective.

Brian Uhlmer - Global Hunter Securities, LLC, Research Division

Okay. That's very helpful, Ken. You say that as we -- the longer protracted inches with the gas regions, you just keep getting more and more equipment as guys finally kind of throw in the towel.

Kenneth V. Huseman

Right. Now the -- looking beyond kind of the other side of the valley that we're in, as gas activity picks up -- and it will, we just don't know when -- there will be, in our view, a shortage of capable equipment to address that. So there will be kind of an deflection point, the hockey stick up, or movement in rates as gas activity or gas prices move up. And they'll have move to $6, but a solid $4, with expectations for that, I think will really kick off that gas work-over activity, and that's why we're keeping our position to the extent we can, in as many markets as possible.

Operator

Our next question is from the line of Jeff Tillery with Tudor, Pickering, Holt & Co.

Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

On the -- just the M&A market, can you just give us some color. I mean as your peers, I mean, I would think, come to the same realization as you guys are or just kind of the activity is where it is for right now, are you seeing that changed their mindset around valuation at all? And is the list of things you guys are looking at growing as that plays out?

Kenneth V. Huseman

Well, the flow -- the inflow of deals is probably as full now or as busy now as we have seen, and pretty much across the spectrum of the services that we're involved in. There aren't very many there that's compelling we feel we need to move. And the valuations are still pretty rich if we look at full cycle-type economics. So at this point, at least in the valuations, the expectations we've seen, we're better off adding equipment one at a time, so to speak, in those markets where we have that demand rather than making acquisitions that's pretty lumpy in terms of capacity.

Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

That makes sense. And how does the balance sheet play into it? I mean you guys have plenty of liquidity, but are you trying to make sure to stay below that 4x debt-to-EBITDA?

Kenneth V. Huseman

Sure. And we have adequate liquidity but not unlimited. So we're also being careful not to jump at the first semi-attractive deal that comes along. So we are going to hold our fire and make sure that it is something that will really will move the meter when we use our available liquidity.

Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then if you think about CapEx going forward, obviously, you guys can increase that pretty rapidly. But if I take the other side of it and just say activity is going tread water here for the next 12 months, what does the CapEx profile look like for you guys?

Kenneth V. Huseman

Over the next 12 months, I think, historically, we spent 8% to 10% of revenue throughout the cycle for sustaining CapEx. And as I've said earlier, we're going to maintain our capability, so it would be in that neighborhood. And then will -- it's not going to fluctuate from that but, over the course, it'll probably average that. Now we still have markets, pockets of great activity. We have requests virtually every week from some of our areas justifying, in a very attractive fashion, additional equipment. So we are providing some growth CapEx in those better markets, in those better segments.

Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And so, putting it kind of another way, is it kind of -- DD&A rate right now is around $210 million a year, if you spend about 60% of that at kind of the current revenue run rate, do you think the revenue capacity stays constant to you guys?

Kenneth V. Huseman

Yes, I'd say so.

Operator

Our next question is from the line of Mike Urban with Deutsche Bank.

Michael W. Urban - Deutsche Bank AG, Research Division

Ken or Roe, I just wanted to get a little clarity on the near-term outlook, you talked about it being pretty flat sequentially. But in Q2, I think it's safe to say that your exit rate almost had to have been higher than the average just given where you're coming from, some of the weather issues, plus, as you go forward in Q3, partly in the usual way as aspects of positive seasonality and things like that. So to be flat quarter-on-quarter, that actually implies that your declining at the leading edge or expecting to decline? So where -- what markets are you seeing that? Or is it just conservatism, just given the backdrop that you've talked about?

Kenneth V. Huseman

Well, several factors. We are allowing for some price degradation. I think Roe and I both mentioned the competitive pressures we're seeing. The third quarter is generally pretty favorable in terms of weather and available daylight, but more holiday impact with both Fourth of July and Labor Day impacting, particularly, our Well Servicing and, to a lesser extent, our other businesses. And then, of course, there is some conservatism built in because we've seen, just recently, in the last couple of weeks, announcements on the part of these E&Ps that they're actually scaling back some activity. So that rolled up together generates this outlook that we put together. And this is outlook based on what our local guys are seeing and hearing from their customers, adjusted for what we think pricing may do in that sort of thing.

Michael W. Urban - Deutsche Bank AG, Research Division

Right. So you're not necessarily seeing anybody actively rolling back activity as it stands today, it's just those factors that you talked about?

Kenneth V. Huseman

Yes. Well, some of the customers have announced their plans to scale their drilling activity back in the Permian. But as Roe said, we have full calendars for completion-related activity and that will drag along our Fluids business, and Well Servicing is busy in those oily markets for sure. But to put up a big increase over the second quarter, we're just required that we kind of perform to perfection, and it's hard to have every market -- and there's always some surprises out there with customers moving budgets around or whatever. So I think it's a combination of all those factors.

Michael W. Urban - Deutsche Bank AG, Research Division

Understood. Hopefully things will turn around here. Actually some of these E&P announcements have been positive on the CapEx front. I think they've been going through earnings here. So hopefully, we'll see more of that.

Kenneth V. Huseman

We may change our outlook next week.

Michael W. Urban - Deutsche Bank AG, Research Division

That's to be considered given what's been -- the way things have been playing out.

Operator

Our next question is from the line of Michael Cerasoli with Goldman Sachs.

Michael Cerasoli - Goldman Sachs Group Inc., Research Division

You actually just partially addressed this question, but I'll come back to it because we have seen some indications that E&Ps are talking about them, now there's pick up in the spending, still early in that earnings season, so it's -- hopefully, what the others say. But also some anecdotal evidence that operators might be willing to pay a little bit more for certain inputs like Profin. This could be a sign that operators have a little but more capital to work with. I guess another way to ask questions that have been asked on the call already is just how far out is the visibility today for you versus prior periods? When you think about your calendar, how far into the future are we thinking? Do you have a good sense of what, say, August looks like at this point or how is that comparable to where you were previously?

Kenneth V. Huseman

Well, yes. We have good visibility in terms -- in those projects that gets scheduled like frac work and that sort of thing. What we see, though, in reality is some of those projects get pushed for -- because there's just a lack of urgency that we saw 1 year ago. But it's not unusual to see a frac delayed for various reasons, whereas 1 year ago, they would have come hell or high water, get that frac scheduled or performed, so that's part of it. But that's the extent of our visibility. Our Well Servicing business is essentially a call-out business and they don't have formal work agreements. But typically with oil prices where they are in those oilier markets, we're pretty busy. And then, Roe, you can comment on the calendar issue as well.

Thomas Monroe Patterson

Well, we hear what our customers say publicly, the ones that do announce their public activity levels, but we are forced to follow the field. And what we're hearing from the field will -- is how we orchestrate our calendar. And so as we line up this work, we can tell that our customers have a pace that they're comfortable with. As I mentioned earlier, they're not going to get ahead of themselves. They got cash flow they want to live within, they talk about that, so -- and the other thing that decreases that sense of urgency is the availability of equipment. When they have plenty of competitors out there, they're not worried about missing the frac date because they know if this frac company can't be there, there's another one ready to fill the shoes and step in. So that will drive down that -- the fact that there are so much available equipment drives down that sense of urgency. So I think that's why you see this pace, which is slow and steady, and people willing to push off things if they have to. If they don't have enough water to frac with, they'll wait. They're not going to rush it and bring in a bunch of trucks of water. They'll wait for their frac tanks and ponds to fill up. And if that requires another 20 days or 30 days, that's what they'll do. So that's what's driving activity. As far as -- far out -- as far as we can see in the future, I'd say, 60- to 90-day windows at the field level is a pretty long window.

Michael Cerasoli - Goldman Sachs Group Inc., Research Division

That's very helpful. I guess, another way, you had previously spoke on your earlier releases about a large pumping job, I think it was, that moved out in the second quarter. Is this back in the 3Q numbers or has it been -- is it further postponed?

Kenneth V. Huseman

No, it's just 3Q. But it -- we have a limited number of frac base that we could bill, so it's not going to be additive to what our full calendar would have generated anyway.

Operator

Our next question is from the line of Daniel Burke with Johnson Rice & Company.

Daniel J. Burke - Johnson Rice & Company, L.L.C., Research Division

Maybe just a question, I guess it would be focused most directly at the Fluids business. In terms of what you all have observed in the Permian over the last year and the transition of drilling programs there from vertical to horizontal, has the pace of that transition occurred at a rate you all expected? Have the outcomes of that transition been what you envisioned? I'm just trying to understand how you think about the market as it transitions.

Kenneth V. Huseman

No, I think the transition hasn't surprised us. It's been pretty deliberate and was well telegraphed by the customers with their drilling programs, permits they file and all that. So the overall demand has probably actually increased with that transition as those wells -- those horizontal wells have more stages. They're a little bit further away from the core part of the region, which actually has increased the amount of trucking required to move the same amount of fluid. So I think that the other side of it has been the amount of competition that newsworthy activity attracts. I think 2 years ago, maybe 2.5 years ago, there were a half a dozen stimulation companies in the Permian Basin, and I think now there is close to 30. So just everybody that had any equipment elsewhere in the country discovered the Permian Basin. And that's true, to some extent, probably not to the same extent, throughout our service line. So it's more of a capacity on the server side than any kind of disappointment on the demand side.

Daniel J. Burke - Johnson Rice & Company, L.L.C., Research Division

Okay. That's helpful. And then maybe a much more specific question. But the press release did mention a positive contribution from the water solutions businesses. As your expectations for your sort of full year activity levels have declined, is that business still on track to make sort of the contribution that you all expected by the time we get to kind of Q4 2014?

Thomas Monroe Patterson

I think that we're probably still on that same pace. I will say that, that business is competitive as well. We've seen a lot of entrants into that water reclamation and water recycling business. So as that happens, it drives rates down. So -- but I think we're probably on pace with where we originally announced.

Kenneth V. Huseman

That subsegment is probably -- has the lowest barrier to entry for the first -- for entrants into that market. Now they won't be very large, but the number can be significant. It will sort out over time as we provide a broader range of capability. But I think the increment's going to be what we expected.

Operator

Our next question is from the line of Jason Wangler with Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Just curious as far as, maybe within the Permian specifically, what you guys are seeing on the frac side, or how you're seeing horizontal jobs come up? Are you seeing that come up as a percentage, I guess, of jobs done for you guys specifically?

Thomas Monroe Patterson

It's a mix for us. We still have some vertical customers that we're working for, so it's a mix for us. It hasn't really come up or changed in the last few quarters, it's about the same. We're still working for about the same mix of customers.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

And maybe if I could drill down on that. As you see maybe a specific customer switch, did they generally just switch with you and use, I guess, different equipment for instance, or even if it's the same equipment for those jobs just, obviously, you happened to add some? Or do they typically switch providers?

Thomas Monroe Patterson

No. Normally, they switch with you if they like the job that you're doing. The equipment operates and functions the same, whether it's on the vertical stages or horizontal stages.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay. And then just my last...

Kenneth V. Huseman

Let me just add, they have had to add some equipment to augment our capability. But same...

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Sure. And then, by this last one, as far as you said it increased completions activity, is that referring to your -- are you seeing more stages per job or are you just getting more stages off, I guess, for more efficiencies?

Thomas Monroe Patterson

We're seeing some more stages per job as the laterals are longer. And even into some vertical work, they're doing some more stages, so as they pinpoint and better refine the perforations that they're making and the completions that they're making. So yes, it's increased the stage count.

Operator

Our next question is from the line of Travis Bartlett with Simmons & Company.

Travis Z. Bartlett - Simmons & Company International, Research Division

You guys were pretty clear in your prepared remarks about the expectations for flat revenue growth in Q3. But when you -- kind of bigger picture question, when you step back and think about the different geographic areas or product lines, is there anything that sticks our as possibly surprising to the upside or maybe just something you are relatively excited about as we sit today and look into Q3 or second half of the year?

Kenneth V. Huseman

Well, I guess if we could project it, it wouldn't be a surprise. But the -- I don't think we have anything other than what we've included in our remarks. It's just too hard to get that granular and talk about specific areas.

Travis Z. Bartlett - Simmons & Company International, Research Division

Right, okay, I would check. Second one here and final question, it looks like you guys are more disciplined now with your capital spend to the year at $165 million. Is there any change to how you're thinking about the share repurchase program?

Alan Krenek

No. Travis, I think what we've done in the past is probably what we would do in the future, so there's no change to our strategy now on repurchasing shares.

Travis Z. Bartlett - Simmons & Company International, Research Division

Okay. And so still opportunistic around that $10 per share level?

Alan Krenek

That's correct.

Operator

[Operator Instructions] Our next question is from the line of John Keller with Stephens Inc.

John R. Keller - Stephens Inc., Research Division

I think pretty much most everything has been covered. But Ken, I was just trying to understand a little bit about your comment about the rig count probably have peaked for the year. Where -- what basins I guess have you started to see the rig count decline? And what sort of customers are driving that? Are these the bigger operators that run big programs or is it the smaller privates? Just trying to understand where kind of where you expect that decrement to come from.

Kenneth V. Huseman

I think, generally, we would expect it to be flat from this point. I think last week, maybe 1 week before, the rig count was almost identical to what it was at the beginning of the year, with a lot of movement around the country, in various markets, some up and some down. So that kind of is where that comment came from. We don't see anybody indicating they're going to add a bunch of rigs in the short-term enough to offset what we know is -- are going to be laid down.

John R. Keller - Stephens Inc., Research Division

Okay. So basically more a comment about just it's -- we don't expect much growth as opposed to any one big falloff.

Kenneth V. Huseman

Yes, it's a macro sort of comment and then, typically, we see a little bit of attrition as we get toward the end of the year. So it could go the other way, but it's not the way to bet.

John R. Keller - Stephens Inc., Research Division

Fair enough, got it. And then just a quick one for Alan. You alluded to working with some lenders to -- typically some covenants as you get close that. Just could you remind us exactly what the covenant is and how the process of work in terms of working with the lenders on that? And that will be it for me.

Alan Krenek

Yes. In our revolver, the maximum total debt-to-EBITDA ratio is 4x. And so, as I've said we were 3.8x, so we're pretty close to that. So what we'll do is we'll get with our bank group and explain what we'll need and then it's a fairly easy process to get that done at the present time. So we'll get some short-term relief on that and it won't be an issue.

Operator

At this time, I will like to turn the conference back to management for any closing remarks.

Kenneth V. Huseman

Okay. Thanks, operator. Well, thanks for those who called in and we look forward to discussing our third quarter results in October. Thank you.

Operator

Ladies and gentlemen, this concludes the Basic Energy Services Second Quarter Earnings Conference Call. Thank you for your participation. You may now disconnect.

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