Helmerich & Payne, Inc. (HP) Q2 2015 Earnings Report, Transcript and Summary

Good day everyone and welcome to today’s program. At this time, all participants are in a listen-only mode. Later you will have the opportunity to ask questions during the question-and-answer session. [Operator Instructions] Please note, this call maybe recorded. I will be standing-by, if you should need any assistance. It is now pleasure to turn the conference over to Mr. Juan Pablo Tardio.

Thank you, and welcome everyone, to Helmerich & Payne’s conference call and webcast corresponding to the second quarter of fiscal 2015 The speakers’ today will be John Lindsay, President and CEO, and me, Juan Pablo Tardio, Vice President and CFO. Also with us today is Dave Hardie, Manager of Investor Relations. As usual, and as defined by the U.S. Securities Litigation Reform Act of 1995, all forward-looking statements made during this call are based on current expectations and assumptions that are subject to risks and uncertainties as discussed in the Company’s annual report on Form 10-K, and quarterly reports on Form 10-Q. The Company’s actual results may differ materially from those indicated or implied by such forward-looking statements. We will also be making reference to certain non-GAAP financial measures, such as segment operating income and operating statistics. You may find the GAAP reconciliation comments and calculations on the last page of today’s press release. I will now turn the call over to John Lindsay.

Thank you, Juan Pablo, and good morning, everyone. Thank you for joining us on the call this morning. The results corresponding to our second fiscal quarter were stronger than expected during this very turbulent time. Low oil prices continue to depress demand levels for drilling services during the transition into our third fiscal quarter. Even with oil prices rebounding from the lows reached earlier this year, our customers have continued to release rigs, albeit at a slower pace. Although there appears to be some stabilization in the oil macro outlook, there is still uncertainty in the market, and our customers remain cautious. The industry rig count decline has been more swift and severe than we expected at the time of our last earnings call in late January, and we reviewed at that time as being more bearish than most. While we don’t believe we have reached the absolute bottom yet, we do believe there are indications that the trough is nearing. Several industry analysts have predicted a trough count ranging from 850 rigs to 750 rigs in the U.S. land market, and we believe that is a reasonable fairway given today’s oil price environment, and the discussions we have had with customers. We have commented that rig count reductions have been indiscriminate, and that trend continues. Yet even in an environment where customers are releasing rigs based upon their liquidity, as well as economic considerations, in many cases regardless of a rig’s performance, we estimate that approximately 40% of the sidelined rigs are mechanical rigs, and that approximately 31% are SCR rigs, while AC drive rigs make up approximately 29%. Despite the reductions in our activity, there may be another sign that the market is establishing a bottom. We have recently contracted a handful of FlexRigs in the spot market to customers who are trading up, high-grading rigs in their drilling programs. Horizontal well complexity and factory-type drilling requirements in the ongoing U.S. energy revolution have changed the game for drilling contractors and other service providers. As a result, fewer mechanical and SCR rigs will be required in the future, especially in the rig categories below 2,000 horsepower drawworks rating. This morning we announced the decommissioning of our first and second generation FlexRigs. These 17 SCR powered rigs built in 1998 and 2001 were a very important strategic move in the Company’s history. The belief was that our customers would be willing to pay a higher day rate for a safer and more efficient rig, and the success of that strategy led to H&P’s investment in AC drive FlexRigs, and I will talk more about that in a moment. Even though the Flex 1 and Flex 2 rigs were a dramatic improvement over the legacy rig fleet, it has become evident SCR power isn’t the preferred technology for today’s more complex well design. What customers want is AC drive technology. Now back to designing and building the first AC drive FlexRig, where we began with a clean sheet of paper and safety-by-design rig structures, and powered the design with AC drive technology. The value proposition to our customers was compelling, and the market finally embraced our efforts. We recognized a long time ago that eventually other contractors would build AC rigs to compete with H&P. We often get the question, are you concerned about your peers’ new AC drive rigs? We answer that by saying, our strategy has remained focused, build the best rigs, employ the best people, and create support systems and processes that continue to deliver the FlexRigs value proposition to our customers. The future holds many opportunities for H&P. The FlexRig 3, FlexRig 4, and FlexRig 5 make up approximately 37% of the AC drive market share in the U.S. today, and FlexRigs have an opportunity to take market share internationally as well. Before turning the call back to Juan Pablo, let me mention a key element of our Company culture. Our focus on continuous improvement and building a learning organization is a key advantage in both the highs and lows of the energy cycle. I am proud of what our people accomplished in 2014 for our customers, where we drilled over 71 million feet of wellbore, and operated over 325 rigs at the peak of activity in October of last year. In addition to setting records for footage and rig activity, our people continue to work on innovative technology solutions, safety systems, cost control systems, and processes that position the Company to be better prepared today than ever before. And certainly, better than we were in the 2009 downturn. The organization’s response to this very severe reduction in rig count has been significant. Our field operations to date have idled over 150 rigs, taking care to preserve the rig and equipment integrity, so we are ready to respond when the market improves. I believe our experienced leadership team provides us with an advantage to manage through the current downturn, even more efficiently and effectively than during previous cycles. Let me close by saying, equally important to the tactical side of our business is our continued strategic focus on organizational effectiveness during these difficult times. We will continue to invest in systems and processes which will allow us to efficiently scale operations to meet changing industry conditions, and be prepared with our significant AC fleet capability to respond quickly to future demand levels. We believe this makes H&P the best-positioned drilling contractor in the industry today. Now, I’ll turn the call to Juan Pablo, and he will give you more details on the second fiscal quarter, and the outlook for our next quarter. Juan Pablo?

Thank you, John. The Company reported $150 million in net income, $227 million in operating income, and $883 million in revenues during the second quarter of fiscal 2015. Given the steep downturn that the industry is experiencing, these quarterly levels were down significantly as compared to the prior quarter, and are expected to continue to decline during the third fiscal quarter. Following are some comments on each of our drilling segments. Our U.S. land drilling operations delivered approximately $225 million in segment operating income during the second fiscal quarter. As expected, the number of quarterly revenue days significantly declined, resulting in an average of approximately 231 active rigs during the second fiscal quarter, representing a 24% decline in revenue days as compared to the first fiscal quarter. On average, approximately 158 of these rigs were under term contracts, and approximately 73 rigs worked in the spot market. Excluding the impact of early termination revenues, the average rig revenue per day decreased by 3.6% to $27,575, and the average rig expense per day increased by 2.7% to $13,395, resulting in an average rig margin per day of $14,190. During the quarter, the segment generated approximately $71 million in revenues corresponding to long-term contract early terminations. Given existing notifications for early terminations, we expect to generate over $75 million during the third fiscal quarter and over $30 million after that in early termination revenues. Since November of last year, we have received termination notices for a total of 44 rigs under long-term contracts in the segment. Total early termination revenues related to these 44 contracts are now estimated at approximately $204 million, approximately $90 million of which corresponds to cash flow previously expected to be generated through normal operations during fiscal 2015, $65 million during fiscal 2016, and $49 million after that. As of today, the 336 available rigs in the U.S. land segment include approximately 165 AC drive FlexRigs generating revenue, and 171 idle rigs, including 163 idle AC drive FlexRigs. Included in the 165 rigs generating revenue are 138 rigs under term contracts, and 27 rigs in the spot market. The 165 rigs generating revenue include rigs that are on stand-by type day rates, and some new build deliveries that have been delayed in exchange for compensation from customers. Looking ahead to the third quarter of fiscal 2015, we expect revenue days to decrease by about 32% quarter-to-quarter. And given the current trend, we could have approximately 150 rigs or less generating revenue days by the end of the quarter. Excluding the impact of revenues corresponding to early terminated long-term contracts, we expect our average rig revenue per day to decline to roughly $27,000. The average rig expense per day is expected at roughly $13,600. Subject to additional early terminations, and excluding rigs that we have received early termination notifications for, this segment already has term contract commitments in place for an average of approximately 130 rigs during the third fiscal quarter, an average of about 117 rigs during the fourth fiscal quarter, and an average of about 107 rigs and 79 rigs during fiscal 2016 and fiscal 2017, respectively. The average rig margin per day level for these rigs that are already under term contract is expected to remain strong and roughly flat during the next several quarters, as some rigs roll off and new builds are deployed. The pricing for rigs in the spot market declined by approximately 15% from the first to the second quarter of fiscal 2015, and it’s expected to continue to decline during the third fiscal quarter. Spot pricing today is about 23% lower, as compared to spot pricing at the peak last November. Let me now transition to our offshore segment. Segment operating income declined to approximately $19 million from $21 million during the prior quarter. Total revenue days decreased by about 2%, as one rig was demobilized and became idle during the second fiscal quarter. The average rig margin per day declined by about 10% to $18,671 during the second fiscal quarter, as one rig that continues to generate revenue days while stacked on the customer’s platform had a significant day rate and margin reduction. Eight of the Company’s nine offshore platform rigs continue to generate revenue days by the end of the second fiscal quarter. As we look at the third quarter of fiscal 2015, we expect revenue days to decline by about 10%, as one of the eight rigs generating revenue completes its current project, is demobilized, and becomes idle during the quarter. We also expect the average rig margin per day to decline to approximately $12,000 during the quarter. The expected average rig margin decline is mostly attributable to three rigs that are generating revenue days during the third fiscal quarter, but that are now expected to be idled on the corresponding customer offshore platforms, with new day rates and margins that are significantly lower as compared to regular operating day rates and margins. A total of seven of the Company’s nine offshore platform rigs are now expected to be generating revenue days at the end of the third fiscal quarter. Management contracts on platform rigs continue to favorably contribute to our offshore segment operating income. Their contribution during the second fiscal quarter was approximately $8 million, and is expected to decline to approximately $6 million during the third fiscal quarter. Moving on to our international land operations. Segment operating income decreased to approximately $6 million during the quarter. Excluding the impact of $373 per day corresponding to early contract termination revenues, the average rig margin per day slightly decreased to $10,524. As expected, quarterly revenue days decreased by about 11% to an equivalent of slightly over 20 active rigs. As of today, our international land segment has 21 active rigs, including 12 in Argentina, 4 in Columbia, 2 in the UAE, 2 in Ecuador, and 1 in Bahrain. 17 rigs are idle, including 3 that are under contract, but no longer active. These 17 rigs include 5 in Argentina, 4 in Ecuador, 4 in Columbia, 2 in Bahrain, and 2 in Tunisia. An additional two rigs are mobilizing to field locations in Argentina. For the third fiscal quarter, we expect international land quarterly revenue days to be flat, potentially increasing up to 5%. We expect the average rig margin per day to decline by about 15% to 20% as compared to the second fiscal quarter, excluding any impact from early contract terminations. We expect to generate early termination revenues in this segment of approximately $9 million during the third fiscal quarter, and another $9 million during the fourth fiscal quarter corresponding to two rigs that are under contract but no longer active. The expected daily margin decline in this segment is primarily due to rigs that are in transition and others becoming idle. We expect to see all 10 of the YPF project rigs generating revenue days during the fourth fiscal quarter. Let me now comment on corporate level details. Our liquidity position is very strong. We recently issued 10 year unsecured notes for $500 million with 4.65% coupons, and a 4.723% yield. Our capital expenditures estimate for fiscal 2015 remains at approximately $1.3 billion, about 70% of which corresponds to the funding of our continued organic growth under the sponsorship of attractive long-term contracts with customers. Our fiscal 2015 construction cadence plan remains unchanged, but we are reducing our fiscal 2016 cadence to one FlexRigs per month beginning in October through March, which allows us to have greater new build continuity as we go through this downturn, while at the same time not impacting the corresponding value of our backlog. Including the long-term contracts for the 40 new FlexRigs scheduled to be delivered during all of fiscal 2015, and the additional 6 rigs scheduled for fiscal 2016, we have secured term contracts for an average of approximately 148 rigs across our three drilling segments during the third fiscal quarter and approximately 134 rigs during the fourth quarter of fiscal 2015. In addition, an average of about 121 rigs is already under contract during fiscal 2016, and an average of approximately 93 rigs during fiscal 2017. The term contract coverage just mentioned excludes long-term contracts for which we have received early contract termination notifications. Given that these early terminations allow us to remain whole in terms of our expected cash flow from the corresponding operations, their impact on both our earnings and liquidity should be favorable, as this accelerates the expected payback on our investments. Given the trend in market conditions, our backlog decreased from approximately $4.6 billion as of December 31, 2014, to approximately $3.9 billion as of March 31, 2015. The value of our backlog is expected to continue to decline during the third fiscal quarter, as we earn related income through operations or through early contract terminations. We expect our total annual depreciation expense to be approximately $600 million during fiscal 2015, and our general and administrative expenses to be approximately $140 million. Interest expense after capitalized interest is expected to be approximately $15 million for fiscal 2015, and the effective tax rate for the remaining two quarters of 2015 is expected to be between 34% and 35%. Our deferred income tax liability as of March 31, 2015, was approximately $1.32 billion. At this point, we expect this liability to remain in the range of $1.3 billion and $1.4 billion through at least the end of fiscal 2017. With that, let me turn the call back to John.

Thank you, Juan Pablo. Before opening the call to questions, I want to reiterate a few key points. As we manage through the current decline in activity, our fleet size provides us with a distinct advantage. With the largest AC drive fleet available in the industry today, the Company has unprecedented leverage to significantly increase activity levels during a future industry recovery and ongoing replacement cycle. In addition to our fleet advantage, H&P has over 1,600 rig years of AC drive experience. This experience provides a foundation to deliver superior value to our customers by providing innovative solutions, and safer, more productive operations. We expect these efforts, along with the Company’s demonstrated capital discipline, to continue to result in pricing, margin, and return on investment premiums that allow us to create value for our shareholders. Now, we will open the call for questions.

[Operator Instructions] We’ll take our first question from Kurt Hallead of RBC Capital Markets. Your line is open.

Hi, good morning.

Good morning.

Good morning, Kurt.

So if I heard you correctly, you mentioned that you are decommissioning 17 of your earlier edition Flex 1 and Flex 2 rigs. Let’s say, the market kind of flattens out through the second half of the year, how do you assess your remaining kind of old vintage assets?

Well, Kurt, this is John. The Flex 1s and 2s – and I think you recognize this – what I am getting ready to say, but the Flex 1s and 2s were SCR rigs. They were also rigs that we didn’t design the structures on the rig. They were bought through kind of the traditional sourcing in the marketplace. Those rigs haven’t worked, really the last couple of years. We have had some different opportunities potentially sell those rigs. But really, the Flex 3s, 4s and 5s, the Flex 3s that we built in 2002 to 2004, if you recall the first 32 we built, those rigs have continued to work, they’re both spot and term. They have been in a situation where they have typically commanded the same type of revenues and margins that we have seen with our newer Flex 3s. Some have skid systems and some don’t. It’s kind of a mixed bag. But I feel real good about where we are, in terms of drilling with those rigs going forward. We do have – I just want to remind you too – we do have eight 3,000 horsepower SCR rigs, one of which we worked at the end of last year on a deep project, a deep gas project in Louisiana. We will continue to have those rigs. We have 2,000 and 3,000 horsepower SCR rigs working in South America. And then, of course, we have our first 3,000 horsepower AC rig also working in South America, working in Columbia. So I feel good about where we are. I think those rigs that – we’ve continued to upgrade those rigs over time, in just about every way possible. They continue to deliver great value for customers, and I feel good about where we are with those rigs.

Great. And how do you – a lot of questions on many fronts here about, hey, we have got a lot – a first time where we are going through a cycle downturn with significant excess capacity in Tier 1 rigs. What is it going to look like coming out the other side, the prospect of those rigs maybe not finding work? How do you assess coming out of the other side of the cycle recovery, and given the excess capacity in Tier 1 land rigs, how would you expect pricing to behave in this cycle, versus maybe what you experienced back in 2012, 2013?

Well, clearly, today is a different market than what we saw in 2012 and 2013. Today is, obviously, a lot more similar to the downturn at the end of 2008, and going into 2009, and first part of 2010. Of course, as you said, I think we had 15% of the active fleet at the peak in 2008 that was AC drive. So it is going to be a different environment. It’s hard to say exactly where pricing will be. I think our expectation would be, in the spot market similar to what we saw in 2009, where it would be in a high teens range. The rigs that we are going to be competing against, yes, there will be some head-to-head competition with AC on AC. But you still have a significant number of SCR and mechanical rigs that are out working today, drilling unconventional resource plays that really aren’t designed to adequately address the challenges, and deliver the type of cycle times that an AC rig can deliver.

Hey, that’s great. Thank you, John.

All right. Thanks, Kurt.

We’ll take our next question from Angie Sedita of UBS.

Thanks. Good morning, guys.

Good morning.

Good morning.

So, John, just going further into the outlook for 2016, and obviously what we’re seeing today, if you think about a modest recovery in 2016, how easy or challenging do you think it will be to get these rig crews back? Is it a bottleneck? Or do you think that you won’t have a problem bringing them back on?

Well, Angie, I think we have done a – this isn't the first significant downturn we have been through. I just mentioned the 2008, 2009 downturn, and we responded coming out of that very well. I think our peak rig count in 2008 was about 185, and we got down to a little over 100 rigs. Of course, this time we're – we got close to 300 rigs working in the US, and we are down to 160. Our experience is that the rigs go back to work. We have a lot of experienced, skilled personnel on the rigs that are working in a lot of cases lower positions. So those guys are always eager to move up into that next role, that next slot, and I personally don't think it's going to be a challenge. The other advantage that we have in our business, of course, is that when you compare the earnings that a guy can have working a year in a oil field, compared to building houses or other types of competitive jobs, there is really not a great comparison. And so, I think people are typically eager to come back. And I think with H&P specifically, we have created a lot of job opportunities and upward mobility, and our guys have seen that through the cycles. We have grown more quickly than our peers, and when we have that kind of growth, we promote from within, and those guys have opportunities to move up in the organization. That's a long-winded answer to your question. But I don't think we are going to have a challenge, personally.

Thanks. That’s very helpful. And then, Juan Pablo, this is probably question for you, and I’ve had the question asked to me. So given the current market environment, how much of a focus does the dividend, the commitment to the dividend going forward? Obviously, you have more liquidity. You just did the debt offering. So just share some comments there, and your thoughts going forward?

Sure, Angie. We've said in the past, that every time that the Company looks at the possibility of increasing dividends as we have, of course, over the last few years especially, the sustainability of that dollar per share amount is a very important consideration. We look at different scenarios and stress cases to determine whether or not we feel comfortable with the sustainability of those new levels, and we certainly do feel comfortable and continue to feel comfortable that we will be in good position to continue to pay those dividends for the foreseeable future. Potentially, hopefully, as the industry and market recovers, we might have a situation where we once again increase it. Of course, there may be situations in the mid to long-term that are unexpected, that may be extreme, that may represent a structural change in the business that we might have to look at, and determine whether at that point there may be a change. But as far as we can see, we are very comfortable with the sustainability and our commitment to the dividends.

Great. Thanks. Very helpful. I will turn it over.

Our next question comes from Robin Shoemaker of KeyBanc Capital Markets. Your line is open.

Thank you. John, I wanted to go back to one of your earlier statements about, you said recently you have put some AC drive rigs in the spot market that have replaced older rigs. So the kind of high-grading process that you were predicting has – seems to be starting to happen. So I wonder if you could talk about the rate that – of the rig that you are replacing, are you getting a higher rate? And is the value proposition still there in this kind of market environment on newly signed contracts?

Yes, Robin. The rigs that we have replaced are, in some cases, legacy rigs. In other cases, I think they were – in one of the cases, it was kind of a lower-end performing AC rig, and the day rates that we received – I know in the legacy rig case, it was a higher rate. I am assuming it was on the other rig as well. They were high teen type rates, kind of what we've talked about. The value proposition is clearly there. I mean, you have seen our value proposition slide that we have shown for years, where we're saving 10%, 15%, 20% on a well. We have a higher day rate, and we are able to save the customer money, as well as deliver more wells in a given year by working that rig. So our belief continues to be that there will be a replacement cycle, the replacement cycle will continue. However, again, I've stated too, it's just a handful of rigs. Unfortunately, we still have more rigs becoming idle than rigs we are putting back in the market. But at least it is an encouraging sign that we hadn't seen in a couple of months anyway.

Yes. Right. So one of your latest presentations shows the AC drive market share at about 51%. So as we get to the bottom of the market, will it still be around that percentage? It still leaves a large number of rigs to be displaced ultimately by the Tier 1 rigs. So do you see that, this very early signs that you have noted, are there more people interested – you’re talking to more people interested in doing that, as we get to the bottom of the market, and perhaps stabilize somewhere at that level?

That would be our expectation, Robin. I think the AC drive market share today in the current active fleet is approximately 54%. So it's up slightly from what you quoted, from the previous presentation. I think it will probably continue to increase. And then, what you'll see over time, of course, is that as older – because there are some older rigs, legacy rigs, and then underperforming rigs that are on term contract, that as they roll off there is a possibility that those rigs could be high-graded. So that would be our expectation. That's what we saw in 2009 and 2010. Our customers, operators in general, are looking for an opportunity. The other advantage to this type of a market is the ability to attract new customers. In 2009 and 2010, we were able to attract a lot of new customers to H&P, because they didn't have to sign a three-year term contract. They didn't have to wait in line. They were able to grab an available FlexRig, and put it to work, and test drive it and see how it worked out. Another data point is in the horizontal and directional market, AC rigs have approximately 59% market share. So again, you can just see that there is another large percentage of rigs that are mechanical and SCR rigs that are drilling horizontal and directional, that are drilling some pretty challenging, complex wells. So that offers a great upside for us.

Yes. Right. Okay. Thank you, John.

Thank you.

Our next question comes from Dave Wilson of Howard Weil.

Good morning, gentlemen. Thanks for taking my questions. Kind of want to stick with this – the thought of the value proposition, and looking a little longer-term. But John, is there a scenario where maybe some less competitive rigs stick around, because operators choose them? Because on price, for example, if those rigs are going for $12,000 a day, and an AC type rig is going for $18,000 to $20,000 a day, is that $6,000 gap there in the day rate, is that enough to sway an operator to stick with a less competitive rig? Do you have a sense of that?

Well, Dave, our experience would tell us that if the operator is sticking with that lower tier rig, they are giving up some value. Because, and again, we have heard this from many customers – or pardon me – many competitors over the years, that as they began to get the picture that they needed a more advanced rig to compete in the marketplace, oftentimes they would say – and these were leaders within their organizations – would say we can't charge a rate low enough, that is compelling for an operator to pick that rig up because of the value proposition. So we believe that it's clear and that it's there. It doesn't mean that we're implying that there won't ever be – or there won't be mechanical and SCR rigs working in the future. I think that there will be, but I do think it's going to be a fewer number. We talked about it on our last call. You can go back and review the notes. I am not going to try to recap it. But with each successive peak and trough, with each successive cycle, you see fewer and fewer mechanical and SCR rigs dating back to 2005, and that trend will continue. One of the components, in addition to customers that's important – and I didn't touch on this earlier when Angie asked the question about people – and that is, the new rigs, AC drive FlexRigs are so much better to work on. They are safer. They are more environmentally conducive to working on. It's just an easier work environment, and so, and that has a real attraction to people. So you are going to get the best people that are going to be working on the newer rigs, which puts a lot of pressure again on rigs that were designed in the 1970s – 1960s, 1970s, and 1980s.

Got you. Thanks for clearing that up. I will turn the call back over.

Okay. Thank you.

Our next question is from Scott Gruber of Citigroup.

Good morning.

Good morning.

Good morning.

I would like to get your opinion on the macro outlook here over the next 6, 12 months, starting to look beyond the trough which appears to be nearing. We have heard from some other industry participants this morning, general unwillingness to call an inflection point, at least in the second half of the year. But as I think about it, and I take your 800 or so trough number of rigs working in the U.S. which seems reasonable, it’s a peak to trough drop of about 60%. This actually appears on par, if not in excess of the drop in E&P cash flow. More importantly, the E&Ps haven’t adjusted their activity levels to the improvement in spending power that has come through the system. I realize this takes time, but why doesn’t this happen in the second half of the year? Should we expect – do you expect a decent rebound in activity before year end, call it, 100 plus rigs, once we’ve cleared what I assume is a modest backlog of uncompleted wells? Just thinking through the impact of this improvement in spending power, and certainly the capital markets are open to the E&Ps. So just interested in your outlook on the rebound potential before year end?

Well, Scott, this is John. Thank goodness, I don't get paid to make predictions on oil and gas prices. But our sense is, like we talked about in our opening comments, our sense is, it feels like we are finding a floor. As you know, there are so many variables involved and things that are unexpected that could happen, which is why I think again, we continue to see our customers being cautious. But you're right. We said – we talked about it on our last call, that markets work and eventually they work, and oil prices have a tendency to overshoot on the high side and the low side. There is a lot of forces working out there that could potentially contribute to exactly what you said. And so, I think your reasoning is right on target. It's just a very difficult situation to try to call it. I think there are a lot of people out there now, that seem to be leaning more towards the second half of the year, and the first part of 2016, and starting to see some improvement. And so, I think that's a reasonable assumption. But I sure don't want to try to call it.

We’ll just have to wait and see. And just thinking about the future of the domestic drilling industry, I think we can all agree that AC drive rigs drilling horizontal wells will certainly dominate the marketplace, but only a small subset of drilling companies can really execute this type of activity efficiently. Is there any thought to going out and purchasing an AC rig competitor at this point, consolidate the industry, before you really squeeze out the conventional activity, and potentially face roadblocks in terms of market concentration issues?

Scott, we've talked about that, thought about it a lot over time, and you've heard us talk about one of the key advantages that we have as a Company is our fleet uniformity, and standardization of practices and supply chain, training, those types of things. I think, at least for H&P, it would be somewhat dilutive for us to acquire a competitor. Again, we've thought through it, whether it's a small competitor or large. In any event, it ends up having a dilutive effect. We would prefer to continue to grow the Company organically. We see some real synergies associated with having the fleet that we have, and that's part of what we're speaking to, as we talk about processes and systems as we move forward. So but does to make sense from an industry perspective? I think it does. I think there is probably some logical combinations out there. I don't know who it would be, but I am sure there is some logical opportunities.

Our next question comes from Brad Handler of Jefferies. Your line is open.

Thanks. Good morning, guys.

Good morning.

A couple different kinds of questions from me, I guess. The first is, maybe I missed it, and I just want to be clear. Is it your sense – you talk about how spot pricing has fallen. You have mentioned high teens, and you are placing some rigs there. Is it your sense – I know you are not calling the trough per se in activity, but is it your sense perhaps rates on the spot market have troughed? Or do you expect to go – the potential to go below the high teens in terms of placing AC rigs?

Brad, I think we – you heard us – you probably heard us comment before. We talked about it on the last call, that there really isn't – there hasn't been a spot market per se. We are starting to see a little bit of a spot market develop now. I mean, obviously, it's going to come down to competitors deciding at what level they are going to price rigs at. I think for us right now, we are down – like Juan Pablo said, we are down, 23% spot pricing. To remind you, in 2009, spot pricing was down approximately 30% from the peak. So we've kind of thought that 30% was a reasonable type of an estimate. I am not – I don't think we can call a bottom on spot market pricing at this stage of the game, because I think we are still really early in on developing the spot market. However, I will say, I think an interesting point keep in mind, is that while we have 30% market share of the AC, our next three largest peers have approximately 38%. So 75% is – of market share of AC, is by four contractors, and then there is approximately 20 that make up the next, the other 25%. So it's a relatively small group of competitors out there. And so, you would think there would be some pricing discipline. I know I have heard some of our larger peers talk about that, and being willing to defend a certain level of pricing. So that would be our expectation going forward. But it's– I don't think we are in a position where we can call the trough on spot market pricing.

Okay. Appreciate that. The related follow-up, and I guess it is really is an extension of the same kind of question is – I don’t admittedly know how much of that there is, but we are hearing some conversations around E&Ps subcontracting rigs, that they are not using. And so, I guess, to your comment at least for the near-term, as it relates to a relatively limited number of suppliers, perhaps it’s a bit of a bigger number than that? Is that something you are seeing as well? Do you have any perspective on that for us, and is it creating some additional potential pressure on rates?

We have seen this through the cycles. I remember back in 2009, 2010, I think there was some. We saw it again, I think, in 2012 and 2013. But at least from my sense, it's not a large number. I think there may be a few that we have had recently. But it's less than a handful. It's just not a large number. So I don't have a feel for industry-wide. But my sense would be, that it wouldn't be that large.

Not impacting the market that much?

Right. And particularly, as the – if the market were to improve and oil prices were to improve, and budgets were able to expand, I think you would probably see less of that.

Right. Right. Very good. Okay. Thank you. I’ll turn it back.

Thanks, Brad.

Our next question comes from Chase Mulvehill of SunTrust.

Hey, thanks for squeezing me in. I guess, one question. On the rigs that went back to work, what type of rigs were these, and you may have said it, and I may have missed it, and I apologize.

I think they were Flex3s and Flex5s. I guess it was – we had Flex3s, Flex4s and Flex5s combination.

Okay. Which class rig do you have the most availability for?

FlexRig 3s.

3s?

Yes. We have what is our number close to 200 overall got available, but overall. So that would be our largest.

Okay. All right. And then, of the stand by rigs, are you seeing any customers put these back to work yet, or at least inquire about putting these back to work?

Can you repeat the question? I’m sorry.

Yes, on the stand-by – well, do you have stand-by rigs? Do you have any rigs on stand-by right now?

Scott, this is Juan Pablo. We, as we mentioned, we have some of the active rigs, or rigs that are generating revenue, are not actually operating. They are under stand-by type rates. Yes, we do have a few of those.

Okay. So I guess, my question would be, are you seeing customers put these back to work, or at least ask you about, hey, putting these back to work in the next few months?

I don't think right now, we have heard any. I think what we – I think you are going to have to see a stronger oil price environment more than likely. I can't speak to all of the details of it. But right now, I don't think that there is any that we are having those conversations with.

Okay. All right. That’s all I have. Thank you.

All right Chase, thanks.

I’m sorry, Chase, thanks.

Our next question comes from Thomas Curran of FBR Capital Markets.

Good morning, guys.

Good morning.

Hey, John. Last time, I attempted to back into it sticking with the FlexRig 3 fleet. I estimated that about 32% of the FlexRig 3 fleet was equipped with skidding systems. Could you speak to where that percentage stands now? And then are you continuing to outfit those rigs with skidding systems throughout the downturn whether they’re currently active or not?

I'll start with the second part of your question first, while we're looking the information up. We are. We have continued to deliver – first of all, new builds with skid systems, as well as we are adding skid systems to Flex 3s that are working in the field today. I think – you said 37%. I was thinking it was 40% to 45%. So we're gaining on it.

Okay. That would actually be consistent with the progress...

Right.

I imagine you would have made since I last looked at it. Is there a percentage that you are planning not to outfit, and if so, is it because there is some that you’ve already marked for potential deployment internationally?

Well, we've actually had Flex 3s deploy internationally with skid systems. And so, we have Flex 3s working internationally, both with and without skid systems. It's really – I would say, it's a demand pull basis, not all customers are doing pad drilling. And so, it's just going to be a function of – as customers transition from single well pads, or and going into a more multi-well pad layout, then that's when we add the skid system to the rig, and those customers want to keep the rig, and they want to keep the folks together, and they get the skid system to go along with it.

Okay. And then turning – when it comes to the AC drive rig market – turning to the 28 smaller contractors that control about 18%, are you seeing any of those drillers bidding rigs at day rates, where they are clearly now operating at a loss? Have you seen any signs or heard anecdotes about any having gone out of business or potentially being on the verge of having to file?

I haven’t on either case. I think I’ve heard some mid to – I guess mid-to-high teens type numbers that have been lower than what I’ve talked about, but I haven’t heard of anybody bidding AC rigs at cost breakeven or anything like that, and I’m not aware of anyone that’s particularly in trouble, in financial trouble.

Okay. Thanks. I’ll turn it back.

Okay. Thank you.

Our next question comes from Walt Chancellor of Macquarie. Your line is open.

Good morning.

Good morning.

John, I agree, the sign that you’re seeing some churn, and some customers trading up is a positive sign. But I guess, the early termination revenue that you all announced incrementally, that seems like a pretty large number, and I was just hoping you could put that in context for us. Any details around timing or basins, things of that nature to help put that in context for us? And also, how that’s sort of shaping your view on the market right now?

Well, I was surprised, I think on the last call, we have 31...

Mid-March.

Mid March, okay. So mid March, we had 31 early terminations, and I think I even commented on the last call that we were surprised with the ones that we had received. At the same time, as we began to kind of think about it a little bit, you contrast with the number of early terminations that we had in had 2008 and 2009, we had close to 40. At that time we had, like I said earlier, a working rig fleet of about 185. This time, we are closer to 300, and we are at 44. So it doesn't feel like it's really out of balance. The early terminations in general have been less than a year left on the term contract. So on a percentage basis, it's – I don't think it's out of touch. I think it really just gets down to the bottom. At the end of the day, we have got customers that just have more rigs on term than they can handle with their budgets, and the lowest cost alternative for them is to early terminate the rig. And really, if you think about it, it's a fairly low cost option to get out from underneath that forward spend, and I think that's how a lot of the customers have looked at it. They have access to the best rigs, and then when they get into that situation, they just early terminate the rigs. So I don't – I am not overly concerned by it. I am surprised, however, that it has gotten to that level. As I start thinking about it, contrasting it, it's a lower percentage than what we saw. I think it's less than 15%, and back in 2009 and 2010, it was over 20% of our fleet.

Great. That’s a very helpful answer. I see we’re up against the hour, so I’ll turn it back. Thanks.

Okay. Thanks a lot. We may have time for one more question. If there’s anybody with a question.

Very good. Our final question will come from John Daniel of Simmons and Company.

Hi, guys. Thanks for getting me in.

Good morning, John.

Good morning. Just a couple here. I know you don’t typically give financial guidance beyond the current quarter, but I am going to try and see if I can get you to work with me on this one. As we try and dial in the contract expirations and the comments on lower spot pricing, I mean, it’s reasonable that we are going to see cash margins decline in fiscal Q3 and Q4. But do you think the magnitude will near what we are seeing here in fiscal Q2, or do you think it accelerates?

John, this is Juan Pablo. I'd hate to speculate on that. What I can tell you is that, is we are very pleased that we have the strength in terms of backlog, and at rigs under term contract that we have, not only for this year, but for the coming years. That provides a very strong foundation, allows us to have a very strong liquidity, and a strong foundation for earnings as well. As I mentioned during my comments, we will be accelerating some of those earnings and cash flows through these early terminations. But at the end of the day, it's hard to provide a clear path in terms of bottom line, excluding early terminations, because we just don't know how much or how many more of those we might receive in the future. Sorry, I can't answer the question, but those are some comments around it.

Okay. Well, I am going to try to – let me go this way. If you guys – I think you mentioned a contract backlog numbers. I didn’t catch the exact numbers, but it sounded like they were lower, than where they were the last time you updated it. I guess, is any of the decline, if I heard that correctly, is any of that decline country related to term contracts perhaps being amended to work with the customers? And if so, just how broad based might that be?

Well, the backlog of decline from $4.6 billion at the end of last year at December 31 to $3.9 billion as of March 31, 2015, and there were several moving parts that impacted that. Of course, we had some rigs that continued to work as expected, and generate part of that related revenue during the quarter. That is one moving piece. Another piece are early contract terminations that, of course, speed up part of the backlog. And then, there are some delays, in terms of rigs moving to the right, in terms of our completion and delivery of those rigs. There are some negotiations with customers, where we believe we have reached win-win type scenarios, where we might exchange day rates on particular rigs with other rigs, remaining whole in terms of our backlog, or extending contract durations, et cetera. Overall, we are very pleased with our ability to sustain the strength of the backlog as expected.

Okay. Fair enough. Let me throw a last one here. How would you characterize the pressure from customers today, versus January, February, in terms of a desire to come to you, and have you work with them on contract renegotiations? Has it subsided at all?

Well, John, obviously it's a much different market today and, of course, a lot of the issues were resolved back in January. Some were resolved in a win-win situation, and others were resolved in the way of an early termination. But there continues to be conversations, and we are going to stay close to our customers, and continue to work with them as best as we can, and again, try to seek win-win solutions. And I think we have been able to do that thus far.

Okay. I didn’t know if perhaps the recent small rally in crude has helped alleviate any of the tension at all? That’s the nature of the question.

Yes. I think there is no doubt. I mean $5 increase in oil prices, there’s a lot of good for all of us, doesn’t it, so.

Yes. All right, guys. Thank you for your time.

All right. Thank you.

Thank you, everybody and have a good day. Good bye.