Key Energy Services' (KEG) CEO Richard Alario on Q2 2014 Results - Earnings Call Transcript

Aug. 7.14 | About: Key Energy (KEG)

Key Energy Services (NYSE:KEG)

Q2 2014 Earnings Call

August 07, 2014 11:00 am ET

Executives

West Gotcher -

Richard J. Alario - Chairman of the Board, Chief Executive Officer, President, Chairman of Equity Award Committee and Member of Executive Committee

J. Marshall Dodson - Chief Financial Officer and Senior Vice President

Analysts

Michael W. Urban - Deutsche Bank AG, Research Division

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

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

Blake Allen Hutchinson - Howard Weil Incorporated, Research Division

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

Kurt Hallead - RBC Capital Markets, LLC, Research Division

Michael R. Marino - Stephens Inc., Research Division

Doug Dyer - Heartland Advisors, Inc.

Operator

My name is Mike, and I will be your conference operator today. At this time, I would like to welcome everyone to the Key Energy Services Second Quarter 2014 Earnings Call. [Operator Instructions] I will now turn the call over to West Gotcher, Director of Investor Relations and Corporate Development. You may begin your conference.

West Gotcher

Thank you, Mike, and thank you all for joining Key Energy Services for our Second Quarter 2014 Financial Results Conference Call.

This call includes forward-looking statements. A number of factors could cause actual results to differ materially from the expectations expressed in this call, including risk factors discussed in our 2013 Form 10-K and other reports most recently filed with the SEC, which are available on our website.

This call may also include references to non-GAAP financial measures. Please refer to our website for a reconciliation of any non-GAAP financial measures provided in this call to the comparable GAAP financial measures. For reference, our general investor presentation is available on Key's website at keyenergy.com under the Investor Relations tab.

I'm going to turn the call over to Dick Alario, Key's Chairman, President and CEO, who will provide some introductory comments regarding the second quarter and discuss current trends in our business. Then Marshall Dodson, our CFO, will review our results and provide some guidance commentary.

Now I'll turn the call over to Dick.

Richard J. Alario

Thank you, West. Good morning, everyone. Key generated a consolidated GAAP net loss of $0.34 a share for the second quarter. This result included a $0.19 loss due to impairment of goodwill and other assets related to the company's operations in Russia. It also included a $0.04 loss due to expenses, including severance, primarily in Mexico. And it also included mobilization and make-ready expenses related to rigs moved from Mexico to the U.S. and expenses associated with the previously disclosed Foreign Corrupt Practices Act investigations.

Before I provide an overview of our segments, I'd like to briefly cover the rationale behind my decision to take over the day-to-day responsibilities for Key's U.S. operations. As we moved through the prior few quarters, we saw some traction relative to the actions that we took in 2013 to take advantage of market opportunities. However, we did not get as much improvement as we expected or enough to overcome the normal give and take in our businesses. I stepped into this role to ensure that we have the right front-end processes in place to execute our business plans and that we have the right alignment of people, responsibilities and accountability.

We expect that the net effect of these changes will yield better results on the customer transactional side of our businesses, which will directly impact the bottom line. I'll give you more detail on some of these changes as I discuss the business segments this morning.

So moving to the U.S. segment. Revenue in the second quarter was essentially flat compared to the prior quarter. These results fell below our previously guided range of 4% to 6% improvement, as our legacy production-driven business in California was impacted by further declines in activity, primarily by one of our major customers.

Additionally, and again on the production services side, we did not see the uplift that we had expected from the Permian Basin. On the other hand, rig-hour activity in all of our other regions outside the Permian and California saw better-than-typical seasonal uplift, with sequential improvement of 15% in some markets, which was enough to moderately overcome the declines in our largest markets.

Further, the U.S. segment experienced relatively high decremental margins due to a series of activity disruptions in our Coiled Tubing Services business, which left us with a fully baked cost structure in the face of lost revenue, and I'll explain more on that in a minute.

Before we leave production services, I want to take a moment to address the lag between the growth in market demand for these services as compared to what we've seen in the completion-driven demand.

Clearly, from a market perspective, the production side of our business has not seen the same demand improvement that the drilling and completion sides of the industry have seen recently. This is especially evident in the legacy production markets, where activity remains solid, but meaningful improvement over the last few quarters has not materialized in a way consistent with broader indicators.

While we continue to hear positive commentary from our customers, we believe that this lag has been due to a few key factors, beginning with customer investment decisions. As operators of all sizes decide where to direct their capital in a rapidly changing U.S. oil and gas footprint, there has been a decidedly consistent trend toward a higher number of increasingly complex horizontal completions.

This trend has contributed to significant cash flows for customers, and the impetus to drill even more wells of this nature continues as operators refine the completion process, which continues to yield even higher production rates. Thus, CapEx has taken precedent over OpEx, as the incentive to add wells to the inventory has outweighed well interventions focused on repair and maintenance.

At some point, as shown by prior cycles, this CapEx versus OpEx competition will move back into balance, at which point we believe production services will more broadly enjoy the momentum that has propelled new completions in the U.S. And we saw this in many of our regional U.S. markets in this quarter.

We also believe the shift toward well maintenance spending will have strong economic upside for our customers when they broadly begin to focus on intervening existing horizontal wells because of the heightened service intensity that they require as compared to vertical wells.

Given this backdrop, I want to provide a framework for how we're approaching our businesses today. As it pertains to our Rig Services, we're ensuring that our incentives and our personnel are aligned with the actions we want and that the barriers to execution are removed. Adjusting the focus of our lines of business to broaden our customer base and serve a larger portion of the market is integral to our strategy, and we continue to make progress on that front. We also continue to battle in the legacy markets, as our second quarter averaged 395 rigs compared to an average of 402 in the first quarter, but our average rig hours per workday was up 130 basis points, as we continue to see more 24-hour completion work for our larger rigs.

As it pertains to Fluid Management Services, the restructuring process that we began last year continues. We've installed a new management team, which is bringing a fresh commercial approach to this business. We've studied how we can best compete and deploy our capital given the assets and footprint we currently have and are driving the business to compete where we have the most advantages in this evolving and challenging market. With our suite of assets, this is typically in markets at the frontier stage of their development or, at the opposite extreme, markets that have been producing for decades, focusing in both on places where it makes less sense for our customers to pay the price to install infrastructure that takes the place of our mobile asset base of vacuum trucks and frac tanks.

As I mentioned in my opening remarks, activity disruptions in our Coiled Tubing Services business contributed to high decremental margins in our U.S. segment in Q2. Given broader market conditions, our average utilization in the low 40s during the second quarter was disappointing. We exited the first quarter with a tailwind. Then we began the second quarter with some customer scheduling issues that were overcome in May and early June. However, we then experienced some events that prohibited our units from generating revenue to offset their cost structure and were made more costly by third-party equipment rentals needed to maintain our position with our customers.

The impact of even one large unit going out of service in this service line can have a disproportionately outsized effect on margins, given their relative economic contribution. We continue to improve our exposure in the Permian Basin in this business, and we believe that the Permian provides the best opportunity to increase overall utilization within our 2-inch unit class.

In July, we've seen a recovery in this business as last quarter's activity disruptions move past us. Ultimately, we need to broaden our customer base to improve our utilization and generate consistent results, and we're adding commercially experienced business leaders to the Coiled Tubing Services business unit to achieve this.

In our Fishing and Rental Services business, our revenue decline in the second quarter was the result of further challenges in our frac stack and well testing services. These services require a similar set of remedies such as those that we recently made in our Fluids business. And with the changes we're implementing, we expect to make this a successful business. I recently placed incremental commercial managers within this line of business to allow our current leaders to address the problems that have plagued this service line for the past year. And I also recently separated our legacy Fishing and Rental Service group from its former reporting structure, and it now reports directly to me. I'm confident that this streamlined reporting arrangement and a renewed focus on growth will yield meaningful benefits for this service line.

So to summarize my U.S. comments, I've provided color on some of the changes I'm implementing across the organization. One of our main goals is to bring a stronger, commercially-focused structure and functionality to our businesses so that we're able to take advantage of the market opportunities available to Key. I believe these changes will allow our company to be more responsive to customer demand and, given our strong safety and operational record, be more able to deliver value to our customers and, ultimately, our shareholders.

Turning now to International. Although we experienced a higher-than-expected revenue decline of 19%, we were able to improve our results at the cash flow line. In Mexico, we continue to monitor our asset base to allow for optionality on the Mexican oil and gas market while maintaining positive cash flow. We remain encouraged that the Mexican legislature continues to progress through the energy reform process. And additionally, we do have some tender opportunities that we're currently pursuing in the country, although none at the levels of activity that the industry there experienced previously. As we look at this market, we do see some indicators of growing need for our services, and we believe that we've maintained our business to benefit from a return in demand in Mexico.

The balance of our International segment performed roughly in line with our expectations. All regions posted positive operating income improvement sequentially, with the exception of our Middle East business, which was just shy of flat.

I'll now turn the call over to Marshall.

J. Marshall Dodson

Thanks, Dick. Our consolidated revenues for the quarter were $350.6 million, down 2% from the first quarter. U.S. revenues were $324.5 million, essentially flat compared to the first quarter, while International revenues declined 19% to $26.1 million.

Our consolidated bottom line GAAP EPS was a loss of $0.34 for the second quarter. These results include a $29 million pretax loss due to a goodwill and other assets impairment related to the company's operations in Russia; a $1 million severance pretax expense, primarily in Mexico; mobilization and make-ready pretax expenses of $1.8 million related to rigs moved from Mexico to the U.S.; and pretax expenses of $5.4 million associated with the previously disclosed Foreign Corrupt Practices Act investigations. Excluding the Russia impairment, these pretax expenses totaled $8.2 million or $0.04 of our quarterly loss.

U.S. operating income margins came in at 7%, down 360 basis points from the prior quarter and approximately 600 basis points below the low end of our previous expectations. A disappointing quarter with Coiled Tubing Services and frac stack and well testing services were responsible for just under 2/3 of the decline quarter-on-quarter and about 1/2 of the decline against our expectations. The remainder of the operating income margin decline was driven primarily by Rig Services and, to a lesser degree, Fluids.

Challenges with frac stacks and well testing, which comprised about 20% of our Fishing and Rental revenues, continue to weigh on our U.S. margins. Getting the frac stack and well testing services to at least a breakeven level would add about $0.10 of annualized earnings from our Q2 run rate.

Outside of the U.S., where we ended the quarter with 61 rigs deployed, we averaged 24 rigs working in the second quarter and experienced a 19% decline in revenues, largely due to Mexico, where we averaged 1 working rig for the quarter and generated approximately $2 million in revenue in the second quarter.

Our consolidated International segment operating income margin includes a $29 million goodwill and other assets impairment related to our Russian operations. Excluding the impairment charge, our International operating income margins, which were burdened by a similar amount of severances compared to the prior quarter, improved $2 million sequentially.

While International operating income did not improve as much as expected, we did achieve our cash flow objectives for the quarter. While we saw improvements in operating income from Colombia, Russia and Ecuador, our operations in Mexico and the Middle East were about flat sequentially.

Our International DD&A on a per rig basis has increased to about $125,000 a quarter, as our rig moves to date have primarily just been the rig, not inclusive of ancillary equipment. We believe that we have positioned the International segment in such a way that we can maintain positive cash flow while we continue to endure the current effects of the energy reform process in Mexico.

To date, 19 rigs from Mexico have returned to the U.S., slightly behind our previously guided expectations of about 24 rigs by the end of the second quarter. Of the 19 in the U.S., 9 rigs have been deployed to the field. The remaining rigs continue to progress through the requisite maintenance procedures to prepare them for the field. We anticipate that we should stay on this rate and expect these rigs to go to work by the fourth quarter.

Additionally, we expect to incur about $1.5 million or so of costs on this process in the third quarter. As we deploy the rigs already in the U.S. and free up capacity to move additional repatriated rigs through our quality assurance processes, we will evaluate the opportunities in Mexico and in the U.S. and the relative costs, with our objective being to have the remaining other [ph] rigs working in 2015, whether in the U.S. or Mexico.

G&A expense for the second quarter was $58 million or 16.5% of revenues. Substantially the entire sequential increase in G&A was due to the approximately $5 million in fees associated with the previously disclosed FCPA investigations. We expect to continue to incur fees until the investigation is over.

Depreciation and amortization expense was $52 million for the quarter. Interest expense was $13 million. Cash flow from operations was $107 million. Capital expenditures for the quarter were $41 million.

We continue to make progress on our stated goal of paying down outstanding borrowings on our $550 million senior secured credit facility. During the quarter, we collected $15 million from PEMEX, and we paid down $45 million off this facility, bringing total outstanding borrowings to $40 million. We ended the quarter with a net debt to total capitalization ratio of 36.5%.

During the first quarter, we realized a lower-than-expected tax benefit of $9.5 million, based on our pretax loss of $61.7 million, which implies an effective quarterly tax rate of 15.5% due to the exclusion of the goodwill and other asset impairment from our tax basis. For the remainder and full year of 2014, we expect our effective tax rate to average in the low 30s.

Our capital expenditures for the quarter were $41 million and $69 million for the first 6 months of 2014. We have not been on a run rate to spend the full $198 million of capital we had planned. However, there are opportunities we expect to take advantage of. Given these new opportunities, we believe that we may end the year closer to the $198 million that our run rate would suggest.

This concludes our prepared remarks. Operator, we'll now open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question is from Mike Urban with Deutsche Bank.

Michael W. Urban - Deutsche Bank AG, Research Division

So I wanted to try and understand some of the issues in the coiled tubing business and the frac stack and well test business. Is this a demand issue that's out there, and the equipment and the people aren't positioned in the right place, which I'd be surprised by in the current market? Or are there execution issues out there where we're just kind of not making the right connections here and not capturing those commercial opportunities, hence putting more, as you say, commercial managers in place? I'm just trying to see if this is, again, a market issue or something that you guys can more readily fix internally.

Richard J. Alario

Yes, thanks for the question, Mike. It's Dick. It's different for each one of those. I'll cover both. In coiled tubing, it was a pattern of, early in the quarter, some customer scheduling changes that caused us to lose some utilization in markets where we're busy and have multiple customers. We, as I said, we recovered from that in the second month and started June very strong. However, then we had some, as I called it, events. What we're talking mostly about are vehicle accidents that occurred with major pieces of equipment, 2 and 3/8 unit, in route to jobs. That was the majority of it. We also had a couple of other equipment-related issues. So look, the overarching issue, as I said in my prepared script, is we require a broader customer base so that, when scheduling disruptions take place among our bigger customers, that we have an ability to recover from that. And that's what the purpose -- that's one of the purposes of the installation of these commercial leaders within the lines of business, in order to put a strong focus on understanding these markets and making sure, as you alluded to, that we have assets and crews in the right places to be able to capitalize on multiple opportunities so that, when you're faced with a call-out business, there is a need to have an underpinning of backup orders to offset orders that are part of the schedule and don't come through. Turning to frac stack and well testing, this is a case of us moving out of a market that fell apart on us not long after we made the acquisition, the Edge acquisition. That's the Haynesville. We got very strong very quickly in the next market that we targeted, which was the Eagle Ford. But then Custer and all his men road into that market as well, and we began to have to battle, as everybody else is there. And frankly, we didn't hold on to customers and crews as well as we had in previous quarters. So again, the notion that having a much stronger transactional presence on the front end, a broader customer base and some ability to bundle that service with some other things that we're doing will drive the improvement. Again, with a team of people within the line of business, not separate in sales but within the line of business, to ensure that the right conversations are being held with customers, that the company is positioned in this service line. Because frankly, in both these service lines, we're very good operationally. We know what we're doing. We can deliver a valuable service. And we need to just broaden the customer base and bring -- and turn more opportunities into revenue.

Michael W. Urban - Deutsche Bank AG, Research Division

Okay, that's helpful. And then in the well service business and the ultimate shift from CapEx to OpEx, are there any indicators that might be out there? Either that this might be happening, or is there something you'd look for to tell you it's happening? Or is it just one of those things that we'll know it when we see it?

Richard J. Alario

I think the 2 things that tell us it's in process are: One, the fact that outside of these 2 markets that we talked about, we had material improvement in hours in our rig business and, obviously, associated revenue. So customer mix and various other things can happen. And then we had this one large customer who impacted activity and utilization in both California and Permian. So that's the first thing. I think that what's encouraging is that we saw fairly material improvement in our ability to increase utilization and put more rigs to work and fluids services outside those 2 markets. I think the second thing is, as we've talked about before, we really like the fact that, as these oil horizontal wells and oily basins continue to age, we are seeing early signs of operators focusing on recompletions, workovers and various other methods of continuing to keep these really high-value assets up and running. And we think that's going to be a big driver of that shift over time.

Operator

Question is from Marshall Adkins with Raymond James.

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

You've given us a lot of good detail. I won't ask you a tough one, but you're probably up to it. When is the bottom here? I mean, are we -- I know you're going through a lot of changes and whatnot, but do you have -- can you give us any sense as to when we expect this thing to stabilize and start improving?

Richard J. Alario

I'm glad you asked. I expect stabilization and some improvement in the third quarter.

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

Perfect. A little more color on the Permian. I guess that was the bigger surprise to me because -- and you gave us good detail on the shift in spending to completions and away from workovers. But help me just grasp a little better structurally what's going on? Aren't they still using like coiled tubing units to help complete some of those wells? Is there any, outside of the frac stack stuff, equipment and stuff of yours that they're using in the actual initial completion that I thought probably would have been there?

Richard J. Alario

Yes, again, good questions, Marshall. First of all, in general, when we talk about the Permian, I want to speak just for a minute about our legacy business there. You shouldn't read into our comments and our results that there's been any loss of market share among our larger customers out there. I've checked our sources carefully, and I'm told that it is being driven by just a mix of customer mix -- of course, we had this large customer that turned down activity levels in the quarter. We had a combination of, let's say, some customer mix, and we had some other customers that had schedule changes. This in no way -- my point of all that is -- and by the way, we've added some customers in that marketplace. They're just not large ones at this point. So our strategy to broaden our customer base, as I said in my prepared remarks, is working to some degree. And my point of all that is this in no way -- this performance doesn't change our outlook on the strength of the Permian Basin. When it comes to completions, yes, there is growing demand for coiled tubing and related services with respect to the horizontals that are being installed in that marketplace. It's fairly new frontier. Fairly new, not the newest, but it's a fairly new frontier. And whenever you have that, customers attempt to try different completion methods. And the one thing that's fairly consistent is that the longer-lateral completions are not so coiled tubing-driven because customers want to be able to rely on the ability of using jointed pipe in a rig to get out to the toe of the lateral. So when you hear of customers drilling 8,000-, 9,000- to 10,000-foot laterals in that and other markets, some will choose to use a rig, some will choose to use a coil. We have a huge presence in the rig business there. And as I said, we're receiving the benefit of 24-hour work doing completions in that market with our rigs. We're a fairly new player in that market with coiled tubing, although we've now got our footprint up to a size where we will begin to get some incremental ability to service more customers and kind of underpin the business there with both coil and frac stack with a broader customer base. So it's one of the things that we're addressing with these management changes by sort of injecting more commercial talent and experience into the lines of business. This is exactly the kind of market opportunity when I say we're doing things to avail ourselves of opportunities. I mean, coiled tubing and frac stack and well testing in the Permian fall right down our fairway. What we need is more customers so that we don't have the schedule interruptions that we've had to deal with. But again, remember that for both those services, we're fairly new as an entrant and a serious player in the Permian Basin.

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

So let me just summarize what I think I heard. And we've been hearing this from a lot of your competition, too. Legacy business, kind of stagnant, slow, not really any major share changes there. The other parts, the growth areas of the business, are evolving, but it's kind of coming along slowly. And that's where you're focusing your efforts going forward. Is that fair?

Richard J. Alario

It is. I would -- only I would not use the word slow. The Permian Basin, even in the legacy business, is healthy and...

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

So stable, I guess, I should say. It's not really surging like the frac business, for example.

Richard J. Alario

That's fair.

Operator

Question is from Neal Dingmann with SunTrust.

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

Say, Dick, a quick question just on the well services. Your thoughts in California, the upside there and how stable you see that market.

Richard J. Alario

Well, we think, at the current levels, it's fairly stable. Our customer there is indicating, at a minimum, sort of flat activity for the rest of the year. We have -- there are not a lot of customers in that marketplace. There's a limited amount of customers. The others that we're doing business out there either have flat to slightly upside plans for the year, and in one case, we have a customer that we've actually deployed a couple of the rigs that were laid down in the second quarter, too. So I would say that we expect stable activity levels in terms of what the market offers. I would also tell you this is one of the markets where we're infusing our management team with more commercial experience. And therefore, we expect to be able to improve once we get that in place and are able to assess where the better market opportunities are.

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

And then just one follow-up. Over on the Fishing and Rental Services, your thoughts for adding additional services or how you sort of see the growth in that playing out for the remainder of the year.

Richard J. Alario

In the legacy Fishing and Rental business, we have identified a number of growth opportunities, and we've begun to shift some capital from what we had originally forecasted in our 2014 capital budget as maintenance. We've actually been shifting some over to the legacy Fishing and Rental business. I'm not sure I'm ready to talk about additional services, but I am ready to talk about the notion that -- for certain products that we market in that business, I'll give you just a little bit of insight: premium drill pipe, higher in blowout preventers, reverse units, things like that. We've seen pockets of demand, particularly in some of the newer emerging shaley oil plays. And our people have done a good job at being able to mobilize equipment and crews into those areas. So the demand improvement that we're seeing and the opportunity in terms of capital deployment really turns on the existing businesses that we're in just being able to deploy more capital to those service lines that are in higher demand.

Operator

Next question is from Blake Hutchinson with Howard Weil.

Blake Allen Hutchinson - Howard Weil Incorporated, Research Division

First of all, Dick, I just wanted to give you a chance. I think you addressed it in the release and the commentary, but something that there's enough conjecture around that I wanted to make perfectly clear. As we have the ongoing FCPA issues, you're not, in any way, precluded from bidding in any country to any customer while that is -- while that's ongoing?

Richard J. Alario

Not at this point, Blake. We're mindful of that as a concern. But -- and I don't want to speculate about the possible impact. But at this point, no decisions around that have been made.

Blake Allen Hutchinson - Howard Weil Incorporated, Research Division

Okay. And then, Marshall, some of your commentary around the quarterly progression, with 2/3 of the decline contained within the coiled tubing business and that improving in July. As we look to 3Q, I mean, can we start thinking about U.S. margins as perhaps getting back to double digits and maybe approaching 1Q levels? Or is that too much of a leap to take right now as we kind of just hope for business to stabilize?

J. Marshall Dodson

Yes, I think right now, we're focused on, as Dick's talked about, all the changes we're going to make in these businesses. But as the changes happen and as we progress, yes, double digits. And getting some of these businesses back on track, you should be in the mid to high teens at some point when everything is humming. So this is not a quick thing. As Dick said, we expect -- he expects to see some changes now, and that progression will happen over the next couple of quarters.

Blake Allen Hutchinson - Howard Weil Incorporated, Research Division

So I guess it's fair to say, not calling anything near term, but you guys -- your assessment would be that the margin offered by your suite of businesses is still -- is similar to what you had midyear last year or something like that?

J. Marshall Dodson

Yes.

Blake Allen Hutchinson - Howard Weil Incorporated, Research Division

Okay. And then just quick check of the numbers, Marshall. You said you had 61 rigs deployed internationally and 24 working?

J. Marshall Dodson

Correct.

Blake Allen Hutchinson - Howard Weil Incorporated, Research Division

Okay. And the difference there times your depreciation is still -- per rig is still a reasonable goal to tighten the loss to in the International overall?

J. Marshall Dodson

Yes, we're focused on -- as I've said, the biggest drag today on our International businesses is the excess equipment in Mexico and the cost structure we have there. And we're going to be evaluating that as we move through the year as we watch the energy reform unfold. And our goal is to have those rigs working in 1 of the 2 markets next year or so. As that happens, obviously, the earnings will progress along that way as the excess costs come out.

Operator

The next question is from Jeff Tillery with Tudor, Pickering, Holt.

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

Dick, as I think about what all you laid out in terms of the changes you've made and as well as factoring in some of the execution issues in Q2, if I -- I'm just trying to think about the timeline with which to think about progress being shown. And coiled tubing, I would think, shows the most immediate impact, if nothing else because some of the one-off things that happened in the quarter don't recur. Well servicing is kind of a medium-term impact, as shown in the broadening customer base. And do I think about the frac stack changes as being kind of the most long term from which to think about measuring you guys by?

Richard J. Alario

Jeff, I think that's fair. Certainly, given the transient nature of this coiled tubing issues, we should be able to recover from those more quickly. As I said, when I made the comment that I expect to see results improve in the third quarter, I'm thinking Fluid Management kind of right behind Coiled Tubing. And then, as you say, rigs and frac stack and well testing sort of behind that. By the way, I also have a strong view of our legacy Fishing and Rental business, maybe not this quarter but certainly as the year progresses and we receive some of the new equipment that we've been ordering and things like that.

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

Okay. That's helpful. And then for the Rig Services business in the Permian, if we were to exclude the large customer where activity was reduced, were the hours up sequentially in the second quarter?

Richard J. Alario

Up slightly, yes.

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

And then I just want to make sure I have kind of the moving parts that likely don't recur in the third quarter correct. So it seems like less kind of mobilization and make-ready expense sequentially. The coiled tubing kind of costs incurred from replacement equipment shouldn't recur. Anything else to think about in terms of moving parts that are unlikely to repeat in the third quarter? Or I guess another way is just -- trying to figure out what the right Q2 baseline is from which to measure the operational improvement.

J. Marshall Dodson

I think severance is one that we're not expecting to repeat. Although as we watch things happen in Mexico, that could happen there, but it will be about the same magnitude, if it were to happen.

Richard J. Alario

Yes, just to put another point on that, Jeff. Probably less cost associated with actual moving of rigs from Mexico, but that will probably be offset by more costs associated with QA. The quality process is getting those rigs ready to go out and work in the U.S. market. So just a little bit of yin and yang there, but just to give you some more fabric behind it.

Operator

Question is from Kurt Hallead with RBC.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

I just want to get -- provided some really good color so far. Maybe a little additional on the dynamic. With the increased activity overall in the U.S. marketplace, and whether it's well activity or drilling activity and subsequent service-related activities, when you think about how -- and when -- if we were going to lay out our own game plan of how we think activity improvement goes for the rest of this year and maybe into next year, how do you think we should take Key's revenue growth vis-à-vis activity growth, plus or minus in terms of basis points?

Richard J. Alario

Well, listen, Kurt, as you saw, we didn't guide on that. So I'm loath to try to balance those 2 out. But let me see if I can give you a couple of things that will help you qualitatively. The growth in rig hours -- and that's what we focused on, by the way, outside of California and the Permian, was mainly driven by legacy production service demand. Now we did have improvement in 24-hour -- large rig 24-hour completions, but I would -- my sense is, I think, about the numbers -- for example, Mid-Continent was one of our best growth areas sequentially, and Mid-Continent was mostly driven in the rig business by legacy stuff. I mean, as I said, we're not -- I don't -- we're not going to put any revenue breakdown out there. But certainly, for those completion markets that are strong, Bakken, Eagle Ford and some of the smaller, more frontier shaling markets, we expect to be able -- as we get better at the transactional end, we expect to pick up more activity, which is the obvious revenue driver there. At this point, that's really all the color that I want to put out there. I think the bottom line to stress is that we are very encouraged by the fact that we were able to deploy more rigs, get more rig hours and do better at our Fluids Management business on the legacy side in more than 2 or 3 of these markets, so some 5 or 6 of them. So very encouraging, especially compared to what you've heard out there in the market otherwise.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

All right, great. Appreciate that info. Now the follow-up question I would have for you relates to the cost benefit assessments that you guys go through with respect to the International markets, right? And I don't know, when we get a look at it over an extended period of time, how the return dynamics match up versus what you can just get by maybe focused -- and being focused in North America. Is it really worth the hassle, the management time, the cost, the disruptions, the questions on conference calls? Any incremental thoughts on the International dynamic and really how you look at the cost benefit.

Richard J. Alario

Great question, thank you. Let's go back and remember that the rationale behind Key moving outside the U.S. was to have markets where we'd have less volatility. That certainly hasn't worked out for various reasons. And to have markets where we can deploy excess equipment from the U.S. That has worked out. Every rig that we have -- almost every rig that we have outside the U.S. was either one that was refurbished and sent from our existing fleet or a new build. So the point is, we haven't met all of our goals, but frankly, if you look at returns -- and this is primarily driven by the fact that every foreign market is 24-hour, 7-day a week market as compared to a lot of the U.S., which is daylight only. And we haven't looked at this in the last quarter or 2, but up until the last quarter or 2, our average returns on investment outside the U.S. had been about what they were inside the U.S. So from the standpoint of risk versus reward, cost versus benefit, it's been fairly level. And if we were -- if we had been able to get more critical mass in a couple of our International markets, I actually think you'd see the swing -- the pendulum swing more toward the benefit side. So with regard to strategy, we certainly often think about and talk about at the board level and at the management level what the benefits are of staying involved in the International marketplace versus deploying more of our capital in the U.S. The good news is, we have the balance sheet to be able to take care -- to address capital opportunities in the U.S. without having to make go, no go decisions about International. So the -- if you look at track record and look at future opportunities, we'll always be asking those questions. And at this point, I'm not prepared to talk a whole lot about anymore of it. But obviously, we certainly understand the opportunity presented by the U.S. marketplace and the, I guess, more reliable revenue opportunity that this market offers us today.

Operator

The next question is from Michael Marino with Stephens.

Michael R. Marino - Stephens Inc., Research Division

Dick and Marshall, I guess I'm just trying to figure out, and maybe you can help me with this, how much of kind of the underperformance in the U.S. is market-related and how much is operational-based? So I mean, taking into account market dynamics, I guess, where do you think your U.S. margins should be, if you were operating at an acceptable level?

Richard J. Alario

I'll let Mark -- Marshall talk about the -- what we can say about margins. Let me just start with -- as I said, you should not think of our performance or our comments as reflecting a view that the opportunities in the U.S. marketplace have gotten any worse. So that tells you that the issues that we face are mainly internal. Now again, there are certain dynamics that happen within discrete markets about things like customer scheduling and changes in customer spending habits. But those -- everybody deals with those, and it's my expectation that we have a strong enough business presence to be able to digest those and deal with them and not have negative results. So I would start with that. It's mostly to do with improvement opportunities within Key's ability to turn customer needs into revenue. I don't know if you want to comment any further than you had on margins?

J. Marshall Dodson

Let's just say that I think, with the businesses performing at a more reasonable level, mid- to upper-teen margins in the U.S. is not out of reach at all. And it's going to be a matter, as Dick said, getting the right changes and capturing the revenue, both to cover the fixed costs and drive the incremental margins that some of these businesses should deliver.

Michael R. Marino - Stephens Inc., Research Division

So how long do you all think that takes?

Richard J. Alario

Well listen, again, I'm loath to get out over my skis on it, but I've gone on the record saying I expect to see improvement in the third quarter.

J. Marshall Dodson

And as we've talked about, some will take longer than others. And the frac stack and well testing business, I mentioned on the call that if you annualize the losses just to get to breakeven, that's $0.10 a share. So there's work to be had there as we go through and address the front end to capture more revenue in that business.

Operator

The last question is from Doug Dyer with Heartland Advisors.

Doug Dyer - Heartland Advisors, Inc.

Just to drill into this question of CapEx versus OpEx competition a little bit further. Obviously, right now, the higher return for the E&P is to go the route on the CapEx side. How big of a difference do you think there is? Is it something that you calculate? Or do companies give you an idea as to how far that difference is? And then what do you think it will take to bring those numbers back in line so we can start to get more of those dollars?

Richard J. Alario

No, Doug. This is more of our view based on what we see happening out in the marketplace, not so much any insightful -- I mean, look, we have discussions all the time with customers about that, but I think it's more appropriate to say that our view that we expressed in our remarks is more about our general understanding of market dynamics associated with that. I would also add that the reason we have an expectation that things will come back into balance is twofold: one is what we've seen historically; and two -- and you can kind of track that looking at drilling rig count versus workover rig count over the last couple of cycles -- and then number two, at some point, wells age, and that becomes painful for operators who're trying to keep their production levels high because even legacy shallow pumping wells are great sources of cash flow, and the opportunity to deploy a Key workover rig to even a 10-barrel-a-day well that we can go back -- which is -- whose production has stopped for some mechanical reason, is one of the best investment opportunities in terms of pure returns that our customers can make. We know this. This, we talk to them about all the time because we're constantly trying to convince them to do more of that. Another -- by the way, another reason, and you've heard this, that there's a bit of an anchor on that is the oil companies' lack of sufficient manpower to be able to run the legacy workover programs. I mean, one of the reasons that we see disruptions -- one of the most popular reasons that we see disruptions in planned activity is customers will come to us and say, "We have to drop a couple of rigs. We don't have the supervision necessary." And it's just part of this whole industry crisis that everybody faces with the aging of the workforce. So I would say, again, just to make a point, that our comments have to do just with the sort of general spending trends that we witness out there, not so much any particular discrete customer insight.

Doug Dyer - Heartland Advisors, Inc.

All right. It seems like Whiting has had some positive commentary with what they're doing in the Bakken with their OpEx spend. Is there anybody else out there that's kind of discovering this yet, do you think?

Richard J. Alario

Yes. We've commented in the past that we have another project up in the Bakken, as a matter of fact, where our customer has a 100-well program. And we're doing the work to go into -- these are horizontal oil wells. And then I'll give you another example. We just took on some work here in Texas from a customer who's converting some vertical production to horizontal production, where Key is providing the lateral drilling service using our rig and other services. This is right down our fairway. It's what Key does. And the idea on that one is he'll test a well or 2, make sure that the production impact is what he thinks it is, and he's got 20 wells to drill laterals in. So we see incremental anecdotal evidence of more and more of that sort of thing being done in the shale. So on top of the obvious benefit that the customer base will get from continuing to keep maintenance programs active on legacy wells, as we say, the slice of demand that no one has really seen yet broadly is the aging of the oily horizontals. And just the sheer service intensity associated with that's going to be an incremental demand driver in the future.

Operator

Call back over to the presenters.

West Gotcher

Thank you, Mike. This concludes our call. A replay of this call can be accessed on our website at keyenergy.com under the Investor Relations tab. Also under the Investor Relations tab, we will post a schedule of our quarterly rig and truck hours. Thank you for joining us today.

Operator

This concludes today's conference call. You may now disconnect.

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Key Energy Services (NYSE:KEG): Q2 EPS of -$0.34 may not be comparable to consensus of -$0.11. Revenue of $350.6M (-14.8% Y/Y) misses by $8.74M.