Danielle (Hunter) Foley - Associate General Counsel, C&J Energy Services Inc. Joshua E.

Comstock - Founder, Chairman & Chief Executive Officer Donald Jeffrey Gawick - Chief Operating Officer Randy McMullen - President & Chief Financial Officer

John Matthew Daniel - Simmons & Company International Waqar M. Syed - Goldman Sachs & Co.

Byron K. Pope - Tudor, Pickering, Holt & Co.

Securities, Inc. Alexander Nuta - Evercore ISI Bradley P.

Handler - Jefferies LLC Ken Sill - Seaport Global Securities LLC Sean C. Meakim - JPMorgan Securities LLC B.

Chase Mulvehill - SunTrust Robinson Humphrey, Inc.

Thank you, operator. Good morning, everyone, and welcome to the C&J Energy Services conference call to discuss our results for the second quarter of 2015.

We appreciate your participation. Before we get started, I'd like to direct your attention to the forward-looking statements disclaimer contained in the news release that we put out yesterday afternoon.

A copy of the release is available on the company's website at www.cjenergy.com. In summary, the cautionary notes states that information provided in the news release and on this conference call that speak to the company's expectations or predictions of the future are considered forward-looking statements intended to be covered by the Safe Harbor provision under the federal securities laws.

Such forward-looking statements are subject to risks and uncertainties, some of which are beyond our control, which could cause our actual results to differ materially from those expressed in or implied by these statements. We refer you to C&J's disclosures regarding risk factors and forward-looking statements in our filings with the SEC for a discussion of the known material factors that could cause our actual results to differ materially from those indicated or implied by such forward-looking statements.

Please note that the company undertakes no obligation to publicly update or revise any forward-looking statements, and as such, these statements speak only as of the date they were made. As a reminder, today's call is being webcast live and a replay will be available on C&J's website.

Please note that the information relayed on this call speaks only as of today, August 6, 2015. So any time-sensitive information may no longer be accurate at the time of replay.

During this call, we will discuss GAAP and non-GAAP measures, and we will discuss results on a reported and pro forma basis. Reported results were prepared in accordance with GAAP.

Pro forma results were prepared in accordance with SEC's Regulation S-X rules under Article 11, and reflect certain adjustments and exclusions described in our second quarter release. These pro forma results were provided for comparative purposes, assuming the March 24 merger transaction of the completion and production services business of Nabors Industries occurred on January 1, 2014.

We encourage you to read our second quarter news release as it contains important information as on our reported and pro forma results, including reconciliations of non-GAAP financial measures to the most directly comparable GAAP financial measures. With that, I'd like to turn the call over to Josh Comstock, Founder, CEO and Chairman of C&J Energy Services.

Thank you, Danielle. Good morning, everyone.

Thank you for joining us to discuss our results for the second quarter 2015. With me today are Randy McMullen, our President and Chief Financial Officer; and Don Gawick, our Chief Operating Officer.

Today's call will deviate a bit from our usual format. First, I will briefly recap our certain quarter performance with commentary regarding the overall market environment and our response to those conditions.

I will also provide an update on the success of our integration efforts following the March closing of the Nabors transaction, and conclude with the recent acquisition of a newly vertically-integrated business. Following my comments, Don will speak in greater detail on our operating results, including our ongoing operating strategy and contributions from our research and technology initiatives.

Randy will then discuss the second quarter financial results of our new reporting segments, Completion Services, Well Support Services and Other Services in more detail. I will conclude today's prepared remarks with a discussion of our outlook for the remainder of the year, before we open the call for your questions.

The second quarter was our first full quarter as a combined company, following the closing of the transaction with Nabors' completion and production services business on March 24. I'm proud to report that, from an operational perspective, we were operating as an integrated company on day one and we have accomplished an enormous amount in the short time since the transaction closed, which I will discuss in more detail momentarily.

The second quarter was another extremely challenging one for the North American oilfield service industry due to the sustained weakness in commodity prices at levels that caused reductions in drilling, completion and production activities. Second quarter adjusted net loss of $53.8 million or a loss of $0.46 per diluted share represented a 24% decline compared to the first quarter on a pro forma adjusted basis, while revenue decreased 33% to $511.2 million in the second quarter compared to the first quarter on a pro forma basis, and adjusted EBITDA decreased 45% sequentially on a pro forma basis to $20.3 million.

These results were driven by a significant reduction in customer activity levels, coupled with further pricing erosion from increased competition as the rig count fell and operators reduced their spending. As I mentioned on the first quarter earnings call, March was the most difficult month of the first quarter and we experienced decline in utilization and pricing towards the latter part of the month, after a relatively stable January and February.

And then, in April, utilization dropped severely from this March low, accompanied by persistent pricing pressure, and both utilization and pricing for all of our services remained depressed throughout the quarter. Critically, while revenue decreased this quarter, through aggressive management of costs and resources, coupled with synergy savings from our integration efforts, we expanded gross margins by 230 basis points on a sequential pro forma basis.

Also, several of our research and technology initiatives helped to drive inter-company savings and efficiencies. The relative strengthening of our results demonstrates our resiliency in the face of an industry-wide issue and proves that our strategy for managing our business, while integrating our companies, is working.

Additionally, the operational adjustments were made in the first quarter and continued to make in the second quarter, plus the synergy realizations and inter-company savings from vertical integration enabled us to protect and, in some cases, grow our market share and support utilization in spite of some irrational pricing by competitors willing to cut their prices below break-even levels. We intend to stay the course of our strategy and making adjustments as needed to effectively respond to market conditions.

Now moving to our integration program. We immediately and seamlessly integrated the Nabors' assets into C&J, creating and effectively managing the company's several times Legacy C&J size and with diverse service lines that are in one of the most difficult times for our industry.

We managed our business and executed well, despite the persistently challenging market environment, implementing C&J's operating philosophy and high-efficiency culture across our expanded operations without a loss in service quality or efficiency. We also made significant progress towards integrating our corporate and administrative structures, and we are on track to achieve our goal of total integration by August 31, 2015.

We still have a lot of work to do, but I believe it'll be a remarkable feat to accomplish this complete transformation of our organization in only five months. This is a direct testament to the capabilities and dedication of our employees and management team.

In response to market conditions and also as part of our integration planning strategy, late in the first quarter we began to scale back our operations and adjust our cost structure in line with activity levels. We stacked idle equipment, reduced head count, implemented strict cost control measures and negotiated substantial price reductions through our supply chain.

At the time of closing, we immediately implemented C&J's improved cost structure across the combined business. Bringing Legacy Nabors' supply chain into C&J's provided significantly procurement synergy savings for key consumables, generating over an estimated $15.5 million in cost savings during the second quarter compared to the first quarter on a pro forma basis.

For example, we generated meaningful procurement synergy savings related to proppant, which is a major input cost for our hydraulic fracturing operations. We also generated procurement synergies from reduced sand trucking costs and chemical costs for the expanded Completion Services division on the combined company.

Based on the procurement synergies we realized through the second quarter, we anticipate that our efforts will deliver more than $50 million in savings over the course of 2015 based on current activity levels. And we are focused on maximizing the potential of our increased scale to push for even more procurement savings and reduction in input costs.

We have significant momentum on this front and are making great progress there. We're also focused on streamlining the combined company, generating SG&A savings.

Our efforts have included reductions in management, head count, and eliminating duplicative field locations and personnel that resulted from the Nabors transaction, as well as reducing the number of crews and stacking equipment in the regions where the market was hit the hardest. We've also analyzed our geographic footprint, reducing duplicative locations and negotiating new leases to ensure that the field is operating as cleanly and efficiently as possible.

Finally, in May of 2015, we acquired and integrated business that designs, manufactures and installs electrical submersible pumps systems and accessories, primarily for artificial lift applications. This business is currently being managed through our Research and Technology division, and its results from the date of acquisition are included in our Other Services segment.

In addition to offering a wide variety of products that support artificial lift installations, we are also developing a line of electric submersible pump systems that are optimized for the small casing sizes, typical of long horitzontal wells. We believe that this artificial lift business has significant growth potential both in the U.S.

and abroad. Additionally, we believe that this new product offering has the potential to provide a competitive advantage in our Well Services division, and we continue to invest in this product.

I'll now turn the call over to Don to provide more detail on our operating results and strategies.

Thank you, Josh, and good morning to everyone joining us on today's call. As Josh mentioned, we ended the second quarter with notably lower utilization and pricing levels, and continued to experience an extremely competitive market environment as our customers responded to the impact of reduced commodity prices.

Summarizing our operating strategy, we have continued to take defensive measures to maximize utilization as much as possible, including working with our customers on pricing and working with our supply chain to adjust cost to the current market. Extensive cost control measures, proactive cost-cutting initiatives and significant synergy realizations from our accelerated integration program strengthened our ability to weather the current headwinds.

We've also maintained a strategic presence in each of our operating areas to protect market share, concentrating resources in markets where activity is strongest and stacking equipment where it does not make economic or strategic sense. Importantly, we have maintained a long-term perspective and stay true to our value-driven philosophy, focusing on the quality and efficiency of our service execution and aligning with customers who recognize the cost savings that C&J provides through efficiency gains.

Let's look at our individual operating segments. The performance of our Completion Services was significantly impacted by the lower activity levels and widespread pricing pressure characterizing the current market.

With a lack of available work driven by the rig count decline, the growing inventory of uncompleted wells and the resulting equipment overcapacity fighting for the work that is available, we are experiencing an extremely competitive environment. Our hydraulic fracturing operations felt the most intense competition, and we have encountered varying degrees of non-sustainable pricing by competitors who are willing to work at a loss to maintain utilization.

The increasing effects of reductions in input costs that we obtained earlier in the year facilitated our ability to work with our customers on pricing, as operators focused on reducing their spending with falling commodity prices. Additionally, the actions we took to improve our cost structure and streamline our business were further advanced by synergy savings and consolidation opportunities from the rapid implementation of our integration program.

Our expanded Completion Services line also benefited from the growing effects of cost savings attributable to our Research and Technology initiatives, which I will discuss more in a moment. We have a strong platform to further improve our cost structure, increase completion efficiencies, enhance our service capabilities and add value to our customers, which provides us with a unique ability to defend and capture market share across all of our service lines.

In our Well Support Services division, reduced activity levels by customers drove a decrease in utilization levels, coupled with pricing declines as a result of the increased competition. Even in this highly competitive environment, we were able to minimize the impact on utilization levels through most of the quarter and uphold market share by working with our customers on pricing.

In addition to managing our business line with market conditions, we focused on restructuring the organization to maximize utilization, lower costs and optimize operational efficiencies, including through organizational upgrades and right-sizing of resources. We will continue to monitor the market to ensure that our assets are strategically positioned and to pursue operational improvements of this division to ensure that each service line is performing at the highest level both in this environment and when the market recovers.

Over the past few years, we have emphasized the importance of our strategic initiatives, including vertical integration and technology advancement through our Research and Technology division. Our R&D division is now generating monthly cost savings for our greatly expanded Completion Services operation, which is essential to our overall strategy of proactively managing our costs to maximize our returns and provide a competitive advantage, particularly in this environment as customers look for innovative means for extracting oil and gas in the most economic and efficient way possible.

Our R&D division is expected to drive an estimated $15 million in cost savings over the course of 2015, based on current activity levels, by providing in-house developed products to our operations, which in turn will enable us to more effectively work with our customers on pricing. For example, over the second half of 2014, we developed the technology and manufacturing capabilities to produce the perforating guns and related logging and downhole tools used in our wireline operations.

We are now able to manufacture and deliver these products at a price that is 35% to 40% below current market prices, generating close to $1 million in cost savings to our wireline operations during the second quarter alone. And we are just getting started.

The cost savings are expected to continue to increase as we ramp our production to fully satisfy our operational needs. Additionally, we know that the savings we are able to offer our wireline customers because of these products played a key role in protecting market share and retaining a substantial amount of work with several customers.

We're also seeing results from a number of other strategic initiatives aimed at increasing the quality and breadth of our service offerings, while capturing cost savings. We have improved and enhanced the efficiency of our hydraulic fracturing operations through in-house manufacturing of fluid ends, which generated over $1 million in cost savings during the second quarter, in addition to the benefits received from the use of new technology impacting the entire frac spread and extending the fluid end life.

By designing and manufacturing these products in-house, we drive significant cost savings compared to what is similar and often lower quality products cost in the market today, as was the case with the Legacy Nabors operation. Additionally, sourcing many of the chemicals and fluids used in our hydraulic fracturing operations through our vertically-integrated specialty chemicals business has enabled us to improve our chemicals offering, while generating significant cost savings.

With that, I will turn the call over to Randy.

Thanks, Don, and good morning everyone. This morning I will provide additional details on our financial results from the first quarter.

During our comparative discussions, please keep in mind that with the closing of the Nabors transaction on March 24, our results for the first quarter of 2015 included the C&P business for the eight-day period following the closing through the quarter-end. Importantly, for comparative purposes, in our earnings release we presented first quarter 2015 financial results on a pro forma basis, assuming that the Nabors transaction took place on January 1, 2014.

Also as a reminder, given the structure of our new combined company we are now operating in, we will report results by three reportable segments instead of by service lines, as previously done. We generated overall company revenue of $511.2 million for the second quarter of 2015, with an adjusted net loss of $53.8 million, or a loss of $0.46 per diluted share, after excluding a $0.05 per diluted share after-tax charge related to transaction cost, severance costs of $0.01 per share, customer settlement/bad debt write-off charges of $0.02 per share and an inventory write-down of $0.02 per share.

Adjusted EBITDA for the second quarter of 2015 was $20.3 million, with an adjusted EBITDA margin of 4%. These results compare to first quarter 2015 results on a pro forma basis of adjusted net loss of $43.4 million, or a loss of $0.37 per share, after excluding a $0.10 per share after-tax charge related to severance and other out-of-period costs on revenue of $766.6 million and adjusted EBITDA of $36.7 million.

Our second quarter results were negatively impacted by decreased utilization and pricing levels across our operations resulting from significant reduction in U.S. drilling and completion activity, as the rig count declined and operators reacted to the continued weakness in commodity prices.

Our proactive approach to cost, resource and supply chain management, the acceleration of our integration program and the growing effect of our research and technology initiatives helped mitigate the impact of market conditions on our margins. In our Completion Services segment, we generated revenue of $332.5 million with adjusted EBITDA of $24.5 million for the second quarter, compared to revenue of $546.7 million and adjusted EBITDA of $31.9 million for the first quarter of 2015 on a pro forma basis.

Our utilization levels were significantly lower in the second quarter and pricing concessions early in the quarter were necessary across our service lines to support utilization and protect market share. The Completion Services segment was the most affected by the difficult market conditions, specifically our hydraulic fracturing business.

In addition, our fracturing operations were also negatively impacted by certain highly active customers electing to provide their own sand or chemicals. A positive during the quarter was our ability to increase both gross margin and EBITDA margin sequentially for this segment, despite the significant decrease in revenue quarter-over-quarter.

The rapid success of the Nabors integration and our sharp focus on cost management allowed for this improvement. Moving into the third quarter, our Completion Services division is expected to remain challenged by the difficult market conditions, but we remain focused on managing the business through these difficult times while maintaining a long-term perspective.

Our Well Support Services are new to C&J from the Nabors transaction. Second quarter 2015 revenue from this division was $153.1 million with adjusted EBITDA of $22.2 million, compared to first quarter revenue of $188.2 million with adjusted EBITDA of $23.2 million on a pro forma basis.

Compared to first quarter results, U.S. rig hours declined by approximately 12% to 133,000, while Canadian rig hours declined by approximately 39% to 14,900.

U.S. truck hours declined by approximately 10% to 570,000.

As we entered the second quarter, our Well Support Services segment experienced a decline in activity in pricing pressure, as a result of the sustained weakness in commodity prices, although the rate of decline has not been as severe as that experienced in our Completion Services segment. We supported utilization and protected market share through pricing concessions, while repositioning resources in line with current market conditions and customer demand.

Similar to the Completion segment, we also increased both gross margin and EBITDA margin for this segment, despite a 19% decrease in revenue quarter-over-quarter. Immediately following the March 2015 acquisition of this business, we focused on restructuring and right-sizing the organization through management changes and adjustments in head count, facilities and asset base, driving sequential improvement in margins.

As we move into the third quarter, market conditions remain depressed for our Well Services segment. As with our Completion Services segment, our approach is focused on maximizing the utilization and extensive cost management.

Our Other Services segment contributed $25.6 million of revenue with negative adjusted EBITDA of $26.3 million, compared to pro forma first quarter 2015 revenue of $31.7 million with negative adjusted EBITDA of $18.5 million. As a reminder, this segment includes our smaller service lines and divisions, including Legacy C&J's directional drilling services, Cementing Services from the Nabors transaction, and our Research and Technology division.

Several of our vertically-integrated businesses are also included in this segment, including our equipment manufacturing and repair, specialty chemicals business, data acquisition and control instruments provider, and our recently acquired artificial lift applications provider. Corporate overhead and the inter-segment eliminations are also comprised in this Other Services segment, which among other things at this time offsets the inter-company cost savings and other contributions from the included service lines and Research and Technology division.

Our SG&A expense for the second quarter of 2015 was $55.5 million, comprising approximately 11% of revenue, excluding transaction and severance costs. On a pro forma basis, and exclusive of transaction and severance costs, first quarter SG&A was $62.2 million, representing approximately 8% of revenue.

The sequential decrease in SG&A is primarily due to cost-cutting measures undertaken throughout the first half of the year, in line with reduced customer demand as well as the rapid implementation of our integration program, which delivered consolidation and restructuring opportunities. Since the fourth quarter of 2014, on a pro forma adjusted basis, SG&A expense is down approximately 25%, primarily due to reduction in head count as well as tightening of spending over the trailing nine-month period.

Currently, we expect quarterly SG&A to remain relatively flat over the second half of 2015. We incurred $4.3 million in research and development expense for the second quarter of 2015, essentially flat with $4.1 million in the first quarter of 2015.

And we currently expect quarterly R&D expense to decrease slightly over the second half of 2015. As Don explained, the strategic investments in our research and technology capabilities are now delivering monthly cost savings, which we expect will increase over the coming quarters.

We remain committed to investing in technologies that will lower our cost base for key inputs and improve our operational capabilities and efficiencies, enabling us to continue to widen the gap between us and our peers. We are confident that these efforts will help us manage through this down cycle and position C&J to be able to accelerate out of the downturn when the market recovers.

In summary, the improvement in margin for our Completions and Well Services segments were driven by significant advances in cost management. Since the fourth quarter of 2014, we have implemented aggressive cost control measures that have resulted in significant direct cost reductions.

Specifically, our proppant, trucking and acid costs have declined by as much as 35%, 50% and 65% respectively from the fourth quarter of 2014 compared to the second quarter of 2015, due to our centralized supply chain and cost reduction efforts. Also, direct labor costs have decreased by proximally 27%, in line with head count reductions.

In addition to reductions in direct costs, we have also implemented tighter management of SG&A spend, resulting in additional savings. Going forward, we will continue to find way to cut costs and better align our cost structure for these challenging times, while still finding ways to better serve our growing customer base.

Depreciation and amortization expense totaled $81.5 million in the second order, compared to $78.3 million in the first quarter of 2015 on a pro forma adjusted basis. Going forward, we would expect D&A expense to increase slightly over the second half of 2015.

Moving to our balance sheet. At the end of the second quarter, we had a cash balance of approximately $12.3 million, with $94 million drawn on our revolving credit facility which has a borrowing base of $600 million.

We feel that our liquidity position exiting the quarter of approximately $500 million provides the company with ample liquidity to better navigate through these challenging market conditions. The company has approximately $1.06 billion outstanding under a two-tranche Term Loan B facility, which has an all-in blended book interest rate of approximately 8.25%.

We had approximately $36.5 million in capital lease obligations at quarter end. Focusing on the cash flow statement.

We generated $55.5 million of cash flow from operations during the second quarter by substantially reducing inventory levels and improving DSO, specifically for the C&P business as we managed it down to a level more closely aligned with Legacy C&J. During the quarter, capital expenditures declined by approximately 25% to $68.7 million, compared to $92 million in the first quarter of 2015 on a pro forma adjusted basis.

The majority of our capital expenditures during the first half of the year consisted of construction cost for previously ordered equipment as well as maintenance and other activities to extend our useful lives. In response to current market conditions, we have significantly reduced our 2015 capital expenditure plan and we currently expect to spend approximately $50 million to $60 million over the second half of 2015.

Our effective tax rate was a benefit of 34.5% for the second quarter, compared to a benefit of 13.8% for the first quarter. The effective tax rate was a benefit of 29.1% for the six-month period ending June 30, 2015, which we believe reflects a normalized rate for the remainder of 2015.

We anticipate no cash tax exposure in 2015 and further expect that NOLs generated this year will significantly drive down our cash tax exposure in future periods. Lastly, our primary objective is to maintain the company's strong liquidity position and focus on paying down debt by cutting operating expenses, reducing capital expenditures, and improving working capital management.

Since the closing of the Nabors transaction, we have worked hard to reduce inventory levels and bring the DSO from Nabors' C&P business down to a level that is more closely in line with Legacy C&J. Going forward, we will continue to focus on financial discipline by cutting costs and taking advantage of post-acquisition synergies, which should continue to enhance our liquidity position in the coming quarters.

I will now turn the call back to Josh for closing remarks.

Thanks, Randy. In closing, I think it's appropriate to provide a little more color on the current macro environment as we see it and the effect we believe that it could have on our third quarter results and perhaps on the second half of 2015.

As oil recently approached and briefly broke through the $60 mark, we began to see optimism in our customers, resulting in talks about increased activity along with potential rig additions for the second half of this year and into next year. That optimism quickly turned to pessimism and frankly, in some cases, disbelief as oil took another turn downward and fell below the $50 mark.

Many industry professionals within our customer base do not believe the current supply/demand fundamentals support this low level of oil price. Those of us who see and experience data real-time understand that the current production declines are more prevalent than the market realizes.

We also believe that OPEC supply is not able to materially increase production at a rapid pace and global demand increases substantially over the summer months. Historically, these facts were supporting increase in oil price, but that is not and is not occurring.

So, as many of us recognize that today's oil price is not being driven by fundamentals, as we see them, but perhaps more of a market sentiment that causes and has caused a certain amount of angst across the industry. Fortunately, we have not seen additional material activity level declines in drilling.

However, we are experiencing what I would describe as a general reluctancy to increase activity in the near-term. Additionally, in another positive sign is that customers seem to be monitoring the market and adjusting their operating plans on a day-to-day basis and not making long-term decisions based on current oil price.

We constantly hear that given the current oil service pricing, $55 WTI is now the threshold for customers to begin to reevaluate increases in activity levels. With that said, as it relates to Q3, we expect activity levels to be flat to slightly down.

We currently anticipate the majority of our service lines will be flat, with some of the smaller ones possibly even slightly up as they further develop new business. However, our hydraulic fracturing operations could potentially be down as much as 15% to 25% from a revenue perspective.

This would translate to an estimated 5% to 10% decline on total consolidated revenue from the Q2 levels. It is important to note, however, that hydraulic fracturing is currently our lowest margin service line.

So revenue can decline without having a material impact on earnings. Also, the potential revenue declines within this service line are not only activity and pricing driven, but some of the declines in the third quarter are due to new customer wins who may work four to five fleets of high utilization levels electing to supply their own sand and, in some cases, chemicals.

As a reminder, sand and chemicals are typically anywhere between 40% and 60% of the job revenue. In summary, the second half of 2015 will likely remain challenging for the oilfield services industry and we intend to keep focusing on our operations, reducing costs where necessary and making adjustments as the market dictates.

We're confident in our management strategy and believe that the increased scale, capabilities, resources, geographic footprint and customer base of our combined company puts us in a strong position both for the current environment as well as for our long-term success. I believe that the hallmark of a good business is how you manage through challenging times, and I'm particularly proud of our team and how they have approached the downturn with an eye toward cutting costs and positioning the business for long-term.

While the market remains tough, we also believe we have been successful in adapting to a rapidly changing situation as far as the size of our workforce is concerned. Adjustments will continue to be made as the market evolves, but our main priorities are to drive revenue by maximizing utilization, improving margins through cost controls and growing market share.

In closing, I want to thank all of our employees at C&J, both the Legacy C&J and former Nabors folks, who have seamlessly come together as one team. Their collective efforts have resulted in a strong position where C&J finds itself in today and I am proud of their contributions and commitment.

I have complete confidence that we are successfully managing the business in these near-term challenges, while keeping an eye on our long term position. The market will adversely turn upward and I'm confident that when it does, we will be positioned to immediately capitalize on the opportunities created by increased demand for our services.

With that, operator, we're going to open the call to questions.

Thank you. Thanks for putting me in.

Randy, first question for you. It would seem that a bank amendment might be needed later this year.

Can you update us on what steps, if any, you've taken with regards to the matter and, just if possible, characterize any discussions you might have had thus far?

Sure. Yeah.

We've begun a dialogue with our bank group and are obviously working to get in front of any covenant issue. We expect to come to a resolution that obviously gives us the flexibility to operate the company in normal course and to do so for a significant amount of time.

We hope and expect to have a conclusion to this process by September and we'll provide more details at that time.

Yeah. And John, I would just say it's important to point out that most of the banks, especially in our revolving bank group, have been involved with C&J, some as far back as 2007.

We have a great relationship with those banks. In fact, during this transaction, as many will remember, we had specific terms that were written before the final oil and those terms were going to be pretty tough on the banks.

And we worked with them on their behalf to change the debt structure in a way that caused them to lose less money and work for us. And so we fully expect to remind them of that favor and we expect that they're going to return the favor.

And so, at this point, we're not concerned at all about any potential relief that we may need.

Okay. Thank you.

Josh, one for you. There is a debate regarding the efficiencies benefit of quintuplex versus triplex pumps.

First, do you believe there is a material difference between the two types of pumps? And second, as you look at the performance of your fleet, have you experienced any weaknesses or shortfalls with your triplex units versus others?

Well, I will start with the quintuplex and the triplex and just what you get out of the quintuplex versus the triplex, right? So, when you look at them on paper and you look at pump rates, you've got to say, okay, let's look at 15K rate of equipment.

So, in that on the quintuplex, you can get a 4-inch plunger size to get 15K-rated. On a triplex, you get 4.5-inch plunger size to get 15K-rated.

So, at those two sizes, if you look at – at low pressure, say 5,000 pounds, you're going to get 12 barrels a mint on a quint and roughly 10 barrels a minute on a triplex. At 10,000 pounds, it's 9.5 barrels on a quint and 8.5 barrels on a triplex.

And at 15,000 PSI, it's 4 barrels on a quint and 6 barrels on a triplex. Most of our work is done at – pumped at 8,000 to 10,000 PSI.

And so the additional items you get out of the quint is the quint and on the configuration of a trailer becomes heavier than 80,000 pounds, which causes you to have to permit reloads, moving it around between locations, and that's a substantial additional cost which is required to run the quints. In addition to that, when you're servicing a quintuplex between stages, you have 70% more time servicing them because you have five holes instead of three, and 70% more cost because you have five holes instead of three.

But we get down to the nuts and bolts of it, right, I mean, it's more expensive. I mean, to buy quints, $25,000 to $250,000 and a complete pump, fluid ends is probably $120,000 in stainless steel versus $180,000 on a triplex and in normal market $80,000 on a stainless steel fluid in for a triplex.

And so there's substantial cost differences, weight constrictions, and service costs that are higher with the quintuplex.

Okay.

That said, some may say that you get a higher rate. The problem is the higher rate comes at lower pressures and we're not doing low pressure work.

We are doing – when I say we – I'm talking about the industry is doing the majority of their pumping between 8000 pounds and 10,000 pounds. So, when we look at a job and a job calls in, we say, okay, we want to run our – we put extra equipment on location as does everyone.

Folks call that standby equipment, but we don't actually have that equipment sitting there being idle. What we want to do is we want to run all the equipment on location and have it running at about a 65% load.

And so, when you run at a 65% load, quintuplex or a triplex, you take horsepower, you say you got 2,500 horsepower engines, which is the biggest we can all get, you get 2,250 brake horsepower to the pump. 65% of that's 1,500 horsepower.

At that horsepower, you can get six barrels a minute, at 10,000 PSI, whether or not you're running quint or tri, because you're limited by the engine. So, if you take a job and say, all right, we're going to have 85 barrels a minute at 10,000 PSI, you use six barrels a minute with 65% load model.

If you do that, you're talking call it 14 pumps. Historically, a rule of thumb for all of us has just been five barrels a minute, and so you would take 17 pumps out there.

So there's multiple ways you can skin the cat as far as what's needed. But what ultimately ends up happening is you need as much from a triplex as many pumps out there with a triplex configuration as you do with a quintuplex.

So you don't save anything. And then in fact, if you took an 85-barrel-a-minute job at 10,000 PSI, it's rate times pressure to determine what horsepower's needed.

It's rate times pressure divided by 40.8. You end up with about 21,000 horsepower required to actually pump the job.

A lot of customers say we want 50% back up, so now you're at 32,000 horsepower, so that's 16 pumps. So, anyway, you look at it, skin the cat, you fall between 14 and 17 pumps on location and then so multiply that times how many holes you have and pumps.

If you can do a job with 14 tries versus 14 quints, 14 tries, you got 42 pods that you're servicing versus 70 on quints and a $300 to $500 of pod depending what parts you're replacing, plus 70% more time to do it, plus the additional cost of the quint, plus the additional weight. It makes absolutely no sense in our operations to have quintuplexes.

And in fact, our first fleet – two fleets we have, we did have – I believe it was 12 quintuplexes, and that was at a time in the market when you could get whatever you could get, and that's all we could get. And as soon as we could change them, we changed them.

The only thing that really – an advantage for is extremely low-pressure work or doing pumpdown type work, and we use them for that, pumping down plugs and doing some injection rig. So, that's our opinions on quint versus triplex.

You can talk to plenty of others, but that's the operational nuts and bolts and how the math works and that's where it all shakes out.

Okay. Thank you.

I'll jump back in the queue for modeling follow ups. Thanks, again.

All right. Thank you.

Thank you very much. Josh, you were pretty clear about the revenue guidance.

Could you talk about the margin side, how that could develop? Or some guidance – you broadly described how the costs were coming off.

But for modeling purposes, you could guide us on the margins or how to think about costs for third and fourth quarters?

Waqar, it's Randy. I'll take the question.

As mentioned throughout the scripts, we're continuing to push cost reductions and expect to see some sequential decrease in Q3 from Q2, although it won't be near as significant to what we saw Q2 over Q1. But as we think about the margins, and again consistent with the general revenue guidance that was given, we expect a lot of consistency with what I would call the non-frac service lines, meaning we're generally expecting revenue to be very consistent 3Q over Q2 and in the margin performance as well.

For the fracturing business, as mentioned, we're expecting some revenue declines there based on where we sit in the quarter and the near-term outlook we have. A lot of the degradation that we would see in margins we're hoping to make up for with additional cost savings.

So margins for that service line will be slightly down, but not as significant given the cost improvements. But again, as mentioned, that's currently our lowest margin service line.

So its overall impact on the total gross margin is less than what it's historically been.

Yeah. And I would just add to that.

On the hydraulic fracturing side, we obviously gave a range of decline. We also pointed out that sand and chemicals could be a significant part of that decline, not necessarily all activity or all price, although that will have an impact.

But I can tell you that it changes daily around here around the forecast, and there is potential that we could have better months than we are expecting. And it's just – it's so fluent right now, we don't want to overshoot and under-deliver.

We want to be as upfront as how we're looking at it today. But as Randy said, from a margin perspective, we should have a minimal impact.

Okay. Now, as you look back into Q2, on exit rate versus as you entered the second quarter, how did the market change for you or your profitability kind of change over the course of the quarter?

Well, margins, I'll let Randy speak to it. But I can just say that revenues throughout the quarter, you'd have one month lower, then the next month higher, then the next month lower.

So revenues were pretty fluent again with frac. Especially when pricing – oil prices started to fall, you saw some guys pause and then get back to work.

But we had months where we had lower revenue yet higher margins. And so I would say there's been added pressure towards the end of the quarter.

That pressure has come from pricing and utilization. That said, at the end of the second quarter was where we had made the most gains on input costs and we've not yet had a full quarter of those input cost reductions.

Okay. And we're hearing about bundling of services becoming a big theme on pressure pumping and trying to gain market share and you alluded to that as well.

Could you maybe explain that with owning wireline and coiled tubing and pressure pumping, if going forward it would allow you to gain some market share and are you aggressively pursuing that strategy?

Well, I can tell you that we are seeing more and more on our daily operating reports around frac, which show whose coil is on location and whose wireline is on location. The majority of the new win work that we have and actually the majority of our historic work, we now have our wireline on location with the frac and, in a lot of cases, our coil.

But, more importantly, around bundling is – historically people have thought around bundling as offering one service at a significant discount to get another. What we've tried to do around bundling and have been successful doing is to offer those services together with the understanding that when we run our wireline, this happens to be the most efficient wireline business (48:08) our wireline business in the U.S., absolutely no doubt, compared with our fracturing – or combined with our fracturing fleets, which also happen to be the most efficient in the U.S.

And we're working over 90% of our fleets 24x7 and still doing that with 19 fleets a day, for the most part, working. And so when we look at that, we know that we can get more stages with our wireline.

We sell that to our customers. The same with our coil.

Our coil has been extremely efficient and it has held up better than, I would argue, anyone else's coil tubing in the market and continues to hold up. And in fact, it's gaining back a little bit of revenue with the recent guys' parking equipment.

So, that said, we don't – we sell it all as a package now. Customers, they are more welcome to that than historically they have been, because – the other thing is if you have a problem with one of those services, you got all three services there, the customer's not having to eat the downtime, you are because you're providing one of the services that had a problem.

And so you take that, it's an extreme advantage, but what's really becoming more of an advantage is the fact that with the well servicing, with the fluid servicing and then with our partnership with Nabors, we have a unique position in the U.S. that I would argue no one else has where we have access to drilling rigs; we have the fluid service handling; we have the frac tanks; we have directional drilling downhole tools; we have all the completion tools that are needed; and then now on the production side of things, we have those services as well.

And so recently, we've been able to pull a Nabors rig – and working with Nabors, pull one of their rigs that were parked, convinced a customer to use all of the services combined and get that customer to go ahead and start drilling. And we won an eight-well package, and that was a customer that was not going to drill those eight wells in the near future.

And we were able to bundle all of those services with Nabors. And as a C&J customer, we used the Nabors rig and combined all of our services, and we're doing everything.

We've already completed the first well and they're on the second well and it's working great. And so I think there's more of that that can be done and had.

And it's definitely a effort that we're making from a cost perspective and I think it's an effort that Nabors is making, and we're going to continue to do that so that we can offer a differentiated package that even what a Schlumberger or Halliburton can offer within the U.S.

Great. Thank you very much.

Good morning, guys. Just trying to calibrate where we are and, Josh, I think I heard you say in your response to one of the callers' questions that you might be around 19 fleets working a day.

Basically my question is today versus maybe the end of Q1 or end of last year, can you frame for us the percentage of your frac fleets that were stacked? Just trying to get a feel for the revenue generating capacity that you've got deployed today.

Hey, Byron. It's Randy.

Yeah. I mean, as we mentioned on the last call, we've stacked approximately 500,000-horsepower.

That number hasn't changed since our last call, giving us deployed horsepower account of approximately 750,000-horsepower. The stacked horsepower is what we're dividing into both cold stack and warm stack.

And as we said last quarter, about 200,000 is cold stack where the remaining portion is warm stack.

Yeah. And then just from a fleet perspective, on the 19 fleets working, that's actually working on jobs daily.

We typically have 21 fleets that are 2 of them in transit moving to cover jobs and cover the schedule or to rotate in and out on a daily basis. And when we originally closed the transaction, we had essentially on a combined basis about 29 total fleets.

So...

Okay.

So, that's where we are from a fleet perspective. Compared to the first quarter, I think we've idled one fleet since we were working probably 20 on a daily basis, with 22 rotated at the end of the first quarter and since then we've probably idled another – I'll let Don....

Yeah. We – Throughout the second quarter, we actually laid down two fleets.

So, that was the differential from the end of Q1 to the end of Q2.

Okay. And then, I realize that there is going to be job mix issues from quarter-to-quarter.

But even accounting for situations where the customer might decide to write-down proppants and chemicals, I'm assuming that the percentage of work that you guys are doing on that 24-hour operations is still fairly high, I'm assuming. Is that fair?

Yeah. I mean, over 90% of what we're doing is 24/7.

All of our fleets, they're working with 24/7 capability. I'd say over 90% – just to give some vigor in there, it's probably higher than that.

I think out of 19 fleets, we have 1 fleet that's working daylights and the rest of them are all working 24/7.

Okay.

Yeah. It tends to be some shallow vertical work in the Northeast that we'll just see.

It's a small amount of horsepower required on location as well. So it's really a fleet that gets used not on a continual basis.

It covers a number of small jobs that we do see in the Northeast.

Okay. And then the last question I have.

Don, in hearing you describe that the benefits of research and technology reminds me of the Technology Day you guys had back in March. And so I don't expect you guys to offer up specific numbers, but reasonable to think that your transport number of stages done per day continues to trend in the right direction?

I'm sorry. Could you – I didn't catch what you said there.

Well, I was just thinking about your Technology Day. And when you talked about the extension of getting more stages up per day because of some of the investments you're making in research and technology, hearing you described them earlier in the call.

There's no reason I think that that trend continues to head in the right direction. In terms of the technology investments, you guys are bearing fruit in terms of the number of stages you get up per day.

Yeah. In terms of the number of stages, I mean we continue to see – that's driven largely by the mix of work as well that we're in.

But we do continue to see a continued push to multi-well stages and big pads, et cetera. That alone is very efficient.

The things we're seeing in terms of improved efficiency as well are coming from things like longer fluid end life and improvements that we're making in terms of some of the designs. So, with the better maintenance and better performance of our equipment out there, we've got our own gun systems that we feel is the best design in the marketplace.

We've got a number of other enhancements that we're bringing online and we're currently field-testing to help with the whole pumpdown perforating process. We do expect to continue to see the efficiencies improve out on location.

All right. Thanks, guys.

That's helpful. Appreciate it.

Hey. This is Alex Nuta on for James.

Thank you for taking my question. Josh, you mentioned that several active customers are providing their own sand and chemicals in certain wells.

Could you speak as to the impact that had to 2Q revenues and margins, and kind of how you see that playing out through the rest of the year and why you don't think it's necessarily a trend?

Yeah. Well, let me start with why it's not a trend.

One of our historic customers that we've been – they've been a customer for us since, well, contract has been in 2011. They were customer of ours before that.

And they've been a long-term customer. They have moved in West Texas to all of their – providing all of their chemicals and sand.

That happened in the second quarter. They've been trying to get there, but that's – they will continue to do that.

We've actually had two new customers that we've won. One of them is working two fleets now in the Eagle Ford and a fleet in the Permian.

They're providing their own sand. And then we have another new win, another new customer, but a new win on the frac side, which is the customer that's probably the most famous E&P company for providing their own sand and chemicals in the industry, that have been doing it since 2010.

And we're working for them in Niobrara, in the DJ and up in the Bakken. And the Niobrara well is pumping as much as 20 million pounds of sand in a well to provide an all growing sand and all growing chemicals.

So three out of our entire – three customers out of our entire customer base is doing it. One has historically always done it.

That's a new win. One has been working towards that for three years now and has finally gotten there.

And then the other doesn't want to do it, but signed into a contract for sand with volume commitments that they got to get worked through. And we're working with them to help them with that, before they can let us start providing the sand.

And so those are new wins. So, from a revenue impact, I mean, sand and chemicals, you just want to say it's 50% of a job ticket.

I mean, these customers are 24/7 customers that have back-to-back jobs, full utilization for a month and will be full utilization for a month going forward. And so if you say, all right, that's five fleets, five or six fleets, I mean that's a 30-year fleet.

So, just pick a number, just say – and this is all for an example. These are not actual numbers.

So, if you say you made $300 million of revenue in frac and a third of that is now going to be customer supplied sand and chemicals, and your 50% of that third – actually now you've taken $300 million of revenue and turned it to $250 million of revenue. The margin impact is probably nil because there's not a lot of margin on pass-throughs.

That said, there's not a lot – historically, we would have told you, you would have a positive margin impact because services are higher-margin and sand and chemicals, then the consumables. Today, in this pricing environment, that is definitely not the case.

I mean, you'd make very little margin on anything with regard to pressure pumping. And so it's a revenue hit.

So, if you look at it from a $300 million number then go into that $250 million, that's 16% revenue – should be as much as 16% of revenue hit across the quarter, if you did it for the whole quarter, and it'll have minimal margin impact either way.

Okay. Thank you.

And then $35 million in additional procurement savings and additional G&A savings from 2H, obviously frac revenue, you guys said margins will keep declining. But for the broader company, can those cost savings kind of offset the decline in frac margins to keep company-wide margins flat?

Yeah. I mean, I think Randy got it earlier – had the question earlier and we guided to – we expect our cost in terms of synergies to offset most, if not all of that.

Again frac, although it's a big part from a revenue perspective, it's the lowest margin by a lot. It's lowest margin business that we're currently in.

And so it'll have very little impact on overall margins and we think the cost controls and the synergies that we're getting now that are broader size and reduction in SG&A and procurement cost savings will offset that.

Okay. And then, one final one for me, and just following up on John's final question regarding the covenant release.

Do you have any idea what the anticipated cost might look like for that release?

No, we're not speculating on that at this time.

Okay. Thank you.

Thanks for letting me on after the hour. Can you give us a little additional information on, I guess, wireline utilization or number of stacked units as well as (1:02:19)?

Yeah. I can tell you that the vast majority of our wireline units are still operating on a day-to-day basis.

We do have a small number that are stacked. It's mostly a lot of the older units that came as part of the acquisition.

They tend to be – they were focused on specific parts of the market that are not currently very active. But, overall, wireline has held up very well relative to the other product lines.

The utilization is certainly down, but not anything to the extent we've seen in some of the other areas. Pricing has been a very significant impact, however.

And, again, that's across all of the different services at this point. Coil as well, we've got the vast majority of our coil units running.

We're seeing a lot more utilization of the smaller coil sizes now. So we've got units that are ready to go with anything from 1.25 inches up to 2.375 inches, and we're able to basically cover a wide range of jobs because of that.

We do have a number of units that are stacked, and, again, came with the Nabors acquisition. We didn't have any particular need to fire them up at that time.

But the vast majority of both coil and wireline units are currently working and staying relatively well utilized.

Yeah. It's interesting to point out on the – well, both of these service lines.

On the wireline side, we've done just a phenomenal job keeping equipment utilized and busy and revenues up, even with the pricing declines, and margins up. So those guys have just – they've managed that business well.

And we are, in our opinion, by far, probably the busiest and most utilized wireline company in the U.S. when it comes to cased-hole wireline and plug-and-perforate setting.

On the coil side, at a time when most people are laying off and we're having cuts as well, but within our coil segment, we actually have been hiring recently because we've had more demand for coil. We have seen large competitors shut coil down – one that's being bought right now, one that was historically red and white, and one of the larger ones has not been very active in it.

And so, that's helped. And then we've seen a lot of these smaller players in coil essentially go through the same thing that some of the smaller frac players have gone through, and so they've shut down.

And that's helped. I mean, that is a core business for us, always has been.

And at times, it struggles, but it's really doing fairly well compared to the market right now.

Got it. That's very helpful color.

Maybe just the natural follow-on, Don, I think you alluded to pricing. But could you give us some perspective on pricing declines in wireline coil, and maybe that's relative to frac, that's helpful as well, but some percentage changes?

Hey, Brad. It's Randy.

Just to give you a sense, maybe staying away from the pricing but more on the revenue declines quarter-over-quarter.

Okay.

I've generally mentioned the declines earlier, but more specifically on wireline, revenue was down 19% and coil was down 37%. And obviously, frac was down greater than that.

That gives you a sense of how much success we've had on the wireline side of growing our share, despite pricing reductions that are in excess of that sequential decline.

Right. And those are – Randy, thank you for that.

Just to clarify, those are pro forma for full quarter of combined company?

That is correct.

Okay. Great.

All right. Very helpful.

Thanks, guys. I'll turn it back.

Well, thanks, guys. Coming by some price letting me in here.

We know things are bad right now and you guys seem to be doing a great job on the integration. One of the things out there is this suicide pricing that's going on in your peers.

How long do you think – if you got 50% excess capacity and you're working without doing your maintenance to keep stuff working, how long – or I guess so let's assume they're working 50% of their fleet. How long before they kind of run out of excess capacity and have to start asking for more money to keep what they've got working?

Yeah. I mean, obviously it depends on the utilization levels.

I will tell you that, just to give you some of our own intel, from a market perspective, if you took a snapshot of the market in late 2013, I think John Daniel has actually put out a report and has the numbers, but you could say, it ranges anywhere from 20 million to 25 million of horsepower. I think the number was essentially 23.8 million is where most of the folks thought it was at peak levels, and over 40 and some will say over 45 fracturing companies.

I can tell you that, as of today, within the U.S., we think that the active fracturing company number is more like 14, with several of those about to not be around anymore one way or another either through transaction, or through bankruptcy, or through parking equipment and auctioning it, which we've seen a lot of auctioned equipment lately. All you have to do is go to Ritchie Brothers to see that.

That said, we also believe that there's probably 10 million to 11 million active horsepower working on a daily basis now in the market and that's the size of the market with probably another 4 million that's ready to go. All it needs is stack.

And the rest from that 24 million peak, that 14 million number or 15 million number has been cannibalized, auctioned, sold for parts, you name it. But, yeah, if folks aren't doing – I mean, that's something no way you can utilize this equipment and not maintain it.

And we are – as Randy said, we have about 500,000 horsepower parked, that's 750,000 working. We work 24/7 a day.

Our maintenance CapEx is pretty consistent and has been and has to be in order to work the equipment. And if you don't maintain it, the equipment's not going to last and you will be in a situation rapidly where you don't have anything that can go out and catch a job.

Yeah. That's fair.

And I guess the question is what's rapidly? Is that something that happens over one, two three, four quarters?

Well, I mean, to put it this way, you obviously pump 200 hours a month. Your fluid ends, you're lucky to get 200 to 400 hours.

So, that's a couple of months when the fluid ends off. If you're cannibalizing off of other equipment, you have 50% parked, right?

So you get one free fluid end, so that gets you four months. Now you're buying fluid ends.

Transmissions last about a year in this business. Engines last a couple years.

Power aims last about a year. A lot of this equipment is five years old and it's been working really hard.

And so rapidly could be within the next three to six months. It just depends on the potential – it depends on the utilization of each company and it depends on the condition of the equipment currently of that company.

And I think that those of us, and I'm proud to say their names, the companies such as Cudd, us, Superior, Universal, Halliburton, Schlumberger, these are guys that are working and are maintaining equipment. Others are not.

And the ones that are priced the lowest or they are not working at all are the ones that aren't maintaining it. But if they're not working, they're not having attrition either.

So, I mean, the gist of your question, I think, is to try to figure out how much horsepower can bounce back and snap back and what the market is going to look like six months from now. I mean, assuming we get the covenant relief we expect, another three months to six months of this market, although it's a ton of pressure on all of us, would not necessarily be a bad thing because I think it would weed out 100% of the weak.

We've already gotten most of them.

All right. Thanks for the detailed answer and I'll stop there.

Thank you, Ken.

Hey. Thanks for taking my call, guys.

Just wanted to kind of continue with that same line of thinking. At the moment, things are pretty short-term focused for you guys as well as for your customers.

But how do you think about the decision to remain on spot versus contracts, if activity stabilizes for a few quarters here and you start to look for the potential for recovery? Can you give us some sense of how that could progress and how your thinking would go?

Yeah. I mean, at these levels, we're not interested in contracting up unless we can contract a whole line of services and do that with escalators in pricing based off the commodity price or activity or some type of market escalator within service pricing.

I think our customers – there's not an interest today in signing contracts. They prefer to work in the spot.

However, as soon as we see oil price move upward, and do so for any timeframe to give customers confidence that activity's going to increase, customers are going to be pushing to lock up contracts at these low rates. And so -

Right.

...it's not sustainable to do it. And most customers, to be fair to customers that are still round, it's a lot different than it's been in the past, especially when in 2013 we had pressure pumping market that was oversupplied, that went from making 45% margins to 10% margins, where customers just hammered us.

Customers, they're feeling the same pain we are, and so it's a group effort and it's amongst all services. And I will say, from an industry perspective, as long as I've been around that this is the first time I've seen everyone work towards the same goal.

And, I think, Tony Petrello said on his call yesterday that at the end of the day we all have to figure out how to make money at $55 oil, and if we can do that, the rest will take care of itself. And so through all of our R&D efforts, through all of our cost reductions, through the efficiency gains we have, through the vertical integration, through the product lines, through the service lines we have, through our access the drilling, we're doing all we can to reduce cost for the customer, so that customers can work and they have to work, given production declines at these levels.

And so we're going to work to continue to improve margins. And from a contacting basis, we're just going to wait and see where things go.

We're not aggressively interested in contracting today. Just like drilling rigs.

I mean what you're hearing on drilling rigs is three-month to six-month contracts versus three-year to five-year contracts that they previously got.

Right. No, that makes sense.

And so then, if you think about – if we're in call it – if we bounce on the bottom here for a few quarters and there was kind of two outcomes, one in which we see an over-supplied market, in which equipment comes unstacked as activity maybe gets a little bit better. Maybe there'd be a kind of a cap on pricing at some normalized level.

Or the other outcome would be there's so much attrition that the reality is there won't be enough equipment to come off the fence and, therefore, you could see a more accelerated recovery in pricing that we saw in the last kind of 2012 and 2013 cycle, which would – and some of you are kind of on the latter side of that?

I'm definitely on the latter side. And I'll just tell you why, because returns from 2010 through the 2013 cycle, returns with this type of equipment were exuberant, they were outrageously high.

It attracted PE money. It attracted outsiders who've never been in the business.

Same within the sand companies, you see guys that have never been in the business before that are in the sand business today that are scratching their head, kicking their self in the rear saying, what am I doing in this business. They haven't been through it.

They don't know how to deal with it. And so you're going to see – there's a lot of guys that have been burned, that have lost money that are not going to have an appetite to jump back into a business that they don't really understand.

They just jumped in because the paybacks were, at times, less than a year to a-year-and-a-half. And anyone with capital could jump in the business.

And so I believe that with a normalized margin, that's a barrier to entry that will control the growth of the market.

That's very fair. Thanks for taking my call.

Thanks.

All right. Thank you.

Hey. Thanks for letting me in.

I've got kind of few questions. I guess, the first one, how should we be thinking about Other Services EBITDA in the second half ?

Chase, it's Randy. With our SG&A forecast remaining flat and not expecting any material changes in the revenue generation of our Other Service lines, I think it'll be generally consistent with what we've produced in the second quarter.

Okay. Awesome.

And the second half CapEx run rate of $50 million to $60 million, is that a good run rate for 2016 CapEx?

Obviously, it would depend on market conditions and activity levels. If we were to continue to see a similar environment that we're in now, I think it'll be slightly below that range.

Probably in more the $45-ish million to $50 million range on an annual basis. Oh, I'm sorry.

I'm sorry.

On a semi-annual basis.

On a semi-annual basis.

$100 million a year.

Right. Okay.

Mainly maintenance. Mainly maintenance.

Okay. And then last one.

Is there any opportunities our there for non-core asset sales, maybe associated with the NCPS assets you acquired? And then, maybe your comfort level of where you'd like liquidity to be and maybe some non-core – I mean, non-traditional options there as to kind of holding liquidity?

Well, you tell me what's non-core, right, that came out of NCPS. The only thing that's non-core that came out of NCPS is the production services business, which happens to be, from a margin perspective, probably one of the best performing businesses and the most stable business that we have today and is spitting off cash flow.

And so that well servicing business, we are making changes within that business that we think will improve margins and help revenue in that business. We think we can make significant improvements there and are in the middle of those.

And today you can't get the value that we think we can create and unlock in there. Again, much like what Tony Petrello said on his call yesterday, I mean this deal was done to unlock and create value.

That's what C&J management is doing. That's what we're going to do with the Well Services.

We have plenty of liquidity. Obviously, I understand the concerns around the balance sheet.

We're going to address them. We're in those discussions with the banks now and we think we'll be just fine.

That said, if we ever get to that point, we'll evaluate our options and decide which area that at the time has been non-core and has the least growth potential, and look for an asset. So, but today, it does not make – that makes absolutely no sense to sell assets below what they're worth.

And there's no appetite for anyone with any of these assets to pay more than – to pay a fair price. So...

Right.

That's where we are. I mean I know folks would love to hear me say, well, we're going to sell off a product line to reduce debt on the balance sheet, but we're going to do other things to address the debt on the balance sheet as necessary, which is seeking release, dealing with our bank.

And we're going to grow these businesses and we're going to be set to take off when the market picks up and it will pick up. And so, that's where we're at as far as asset sales, currently.

Okay. Awesome.

Thanks for the color. I'll turn it back over.

And you got to start and finish, John.

Well, I think I'm going to ask you the dumb question of the day. But the follow-up on coil, excuse me, when wells get re-fracked, do you have similar opportunities for drill-outs as of the new well completions and what type of utilization opportunities for coil might exist as the re-frac market picks up?

In the re-frac market? So...

Yeah.

So, and let's address new wells first. At our new wells, we're drilling out coil tubing plugs or composite-rich plug and washing out the wells.

I know there's been a lot of talk about dissolvable plugs, it's just that; it's talk. You still have to – I mean, there's other things left in the wellbore besides the plug.

mainly sand. And so you still have to make a cleanup trip with coiled tubing.

And so dissolvable plugs, other than being dissolvable, aren't going to do anything or have any negative effect on coil as we see it. And in fact, I mean this was an idea that was around in 2001.

And it'll work, but it's not going to change the dynamics around wireline or coil. In the refrac market, what will happen with coil is you will coil more for cement squeezes, more for fracking down tool, like we used to fracking down the back side of the coil and reversing up through the coil.

And so re-fracking, to the extent that it starts to happen – it's not taken off yet. But to the extent it starts to happen, coil will be used quite a bit.

I'd tell you where we're really starting to see some uptick is, as Don said, the smaller diameter coil and it's what we would call a re-stimulation work, not re-fracturing work, but it's acidizing, nitrogen, artificial lift type stuff, and you're starting to see more and more of that. And the same will hold true for workover and then any re-fracking that's done that's not just bull headed then down the tree, will be done either through a coil unit or a workover rig.

Okay. All right.

One more. With 19 fleets working, I would assume that you can procure your sand cost at a better price than what your E&P customer can do, assuming that customer doesn't own its own mine.

If that assumption is correct, why is your customer still looking to buy sand directly? And just your further thought on sand prices going into the second half of year.

Right. So the one customer that we're talking about, owns his own mine, his own railcars, all of it, which we're all aware of who they are.

They've been the best at it since Eagle Ford in 2010. And so there's nothing they're going to do to change.

The recent new win that we had, we can buy cheaper. We showed them that we can provide it to them cheaper.

Their only issue is that they signed a contract prior to seeing the data from us. This is a win that we took from another company.

And prior to seeing our pricing for sand and trucking, they locked into a sand contract and they had volume commitments that they have to take volumes. I think their preference would be for us to do it and we're working towards a solution where we can address their volumes where we could do it – I mean, a great example is with us in trucking, we tell our trucking companies in this environment absolutely no to merge.

If you're going to work for us, we're not paying for the merge. We get that from the majority of our customers – I mean, the majority of our trucking companies.

This particular customer had a situation in the Eagle Ford where they had a well control issue. They had a bunch of trucks of sand that they had ordered.

The trucks sat there and they had what was described to me by them, hundreds of thousands of dollars in the merge time (1:25:22). Well, that's cost that they would not have had with C&J, and they recognize that.

The other customer that's doing it has been pushing this ever since 2011. They want to model EOG.

They're another one that begins with a vowel in the alphabet and they want to follow that model. So there's nothing we can do there, but we can buy cheaper than them.

We're pumping more volume. With our size now, I think we pump more volume than any one customer.

Yeah.

Okay. Last one because we're running really late here.

Hey, Randy, is there any chance that you would have handy the revenue per hour or rate per hour numbers on the Well Service rigs for both U.S. and Canada?

He's grabbing it right now, John.

You asked the revenue – the rig rate, John, is that what you're asking for?

I'll take whatever you can give me, but rate probably would be ideal for everyone.

Well, we gave you – yeah, we gave you the hours worked.

Right.

So, that would give you a rig rate on Q2 of $514 versus $556. And that's in the US.

Okay.

The truck rate in the U.S. was $103 in Q2 versus $106 in Q1.

I don't have the Canada rig rate in front of me.

Okay. Thank you very much for your time today.

All right. Thanks, John.

All right, we appreciate everyone joining us. Obviously, we went long.

We wanted to get everyone's questions in. We're going to continue to stay focused on integration, focused on market share and look forward to talking to you all at the end of Q3.