Helmerich & Payne, Inc.
Q1 2015 Earnings Call Transcript

Published: 29 Jan 2015

[Operator:]

Good day, ladies and gentlemen, and welcome to today's program. [Operator Instructions] Today's conference is being recorded. And it is now my pleasure to turn the call over to Mr. Juan Pablo Tardio. Please go ahead, sir.

[Juan Pablo Tardio:]

Thank you, and welcome everyone to Helmerich & Payne's Conference Call and Webcast corresponding to the First Quarter of Fiscal 2015. The speakers today will be John Lindsay, President and CEO; and me, Juan Pablo Tardio, Vice President and CFO. As usual, and as defined by the U.S. Private 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. 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.

[John W. Lindsay:]

Thank you, Juan Pablo, and good morning, everyone. We achieved record levels of revenue and operating income during 4 consecutive years as well as record revenue and operating income for the first fiscal quarter of 2015. However, the strong quarter is overshadowed by a rapidly deteriorating energy market. When the oil markets -- with oil markets oversupplied, sluggish demand forecasts, prices at 6-year lows and without confidence that we've reached a pricing floor, great uncertainty exists for our customers. If triple-digit oil prices were unsustainably high, what isn't clear is how far the pendulum may now be swinging to price oil at unsustainable levels on the low side. As a result, drilling activity and spot pricing has significantly declined in the U.S. Many industry analysts have predicted a 500- to 900-rig count reduction in U.S. land. And since the peak of activity at the end of October 2014, recent rig counts already appear to be down by 300 to 500 rigs. This wide range depends on the rig count source and how inclusive it is of smaller rigs. So far, however, the burden of the rig count reductions appear to have been shouldered by our competitors' legacy rig fleet. By using third-party rig counts, we estimate that approximately 58% of the sideline rigs are mechanical rigs and that approximately 27% are SCR rigs, while AC drive rigs make up approximately 15%. We expect the downturn may also reduce the number of planned new builds for 2015. The industry will most likely deliver 100 to 120 new AC drive rigs throughout the year with an expectation that all of these rigs would be sponsored with term contracts. This total would be a much lower number and cadence than originally estimated in 2014. Looking at past downcycles, the rig replacement cycle usually accelerates. This can be seen most recently during the peak and troughs since 2008 and 2009 in the U.S. land market. The legacy rig fleet, made up of mechanical and SCR rigs, reached a lower-peak rig count in each successive cycle. As an example, using third-party data, we estimate that the peak count for mechanical rigs was approximately 1,000 rigs in 2008, approximately 800 rigs in 2012 and approximately 600 rigs in 2014. Today, we estimate that the mechanical rig count is below 400 rigs, actually lower than the SCR rig count for the first time. Historically, rig count reductions at this stage of the cycle tend to be indiscriminate. And this downturn is no different. Spot market rigs are the first to go, and even top-performing AC drive rigs have been released. However, once the trough rig count is reached, rig quality, safety and performance are all evaluated to make decisions when putting rigs back to work. Customers have a choice. And H&P is focused on strong field performance, where our people are determined to win the confidence of the customer every day, and that provides us an important advantage. The rig count reduction thus far has been more swift than many expected. We reported earlier this month that the number of idle FlexRigs was increasing and spot market pricing was down approximately 10%, and we expected additional softness in the market going forward. The outlook for pricing and activity continue to be lower, and we don't see the outlook improving during fiscal 2015. I heard someone say recently, "The job of correcting markets when they're oversupplied is to find a price that destroys the oversupply." And in this case, the process that is required to destroy the oversupply is for E&P companies including our customers, to side light -- sideline hundreds of drilling rigs in the U.S. including H&P rigs. Our field employee count is directly proportional to our rig count. Unfortunately, that means we have begun the process of making significant reductions to our workforce as we idle many of our rigs. Based on what we know today, it is possible that we will have approximately 2,000 or more field positions eliminated by the foreseeable rig reductions. This is, without question, the worst part of the downturn. Nevertheless, we still believe H&P is the best-positioned drilling contractor. Fortunately, we still have 31 new builds to deliver, all sponsored with 3-year term contracts, a backlog of $4.6 billion to start the calendar year and term contract coverage of an average of approximately 160 rigs for the remainder of fiscal 2015. Before I turn the call back to Juan Pablo, as I think about the outlook, our experience has taught us that in the face of a very negative market like we see today and a growing perception and panic of weaker-forever prices, the market does work, and eventually, all fundamentals improve. Now Juan Pablo will give you more details on the first fiscal quarter and our outlook for the next quarter.

[Juan Pablo Tardio:]

Thank you, John. The company reported a quarterly record level of $332 million in operating income during the first quarter of fiscal 2015. We also reported record revenue levels of well over $1 billion for the quarter. Although we are now expecting drilling activity to significantly decline, the number of revenue days during the first fiscal quarter also represented a record level. Following are some comments on each of our drilling segments. Our U.S. land drilling operations delivered approximately $295 million in segment operating income during the first fiscal quarter, excluding the impact of early termination of long-term contracts. The number of revenue days increased by 2% from the prior quarter, resulting in an average of over 297 active rigs during the first fiscal quarter. Approximately 179 of these rigs were active under term contracts, and approximately 118 rigs were active in the spot market. Excluding the impact of early termination revenues, the average rig revenue per day increased by 1.6% to $28,603. And the average rig expense per day decreased by less than 1% to $13,046, resulting in an average rig margin per day of $15,557. During the quarter, we generated approximately $23 million in revenues corresponding to long-term contract early terminations. Given existing notifications, we may generate over $60 million during the second fiscal quarter from additional early terminations corresponding to long-term contracts. Since our last conference call in November, we have received termination notices for a total of approximately 22 rigs under long-term contracts in the segment, 7 of which were estimated to have under 90 days of remaining contract duration and 7 of which have contract durations that extend beyond September 30, 2015, which is the end of our fiscal year. As of today, the 340 available rigs in the U.S. land segment include 243 active rigs and 97 idle rigs. All except 1 of our active rigs are AC drive FlexRigs. Of the 97 idle rigs, 73 are AC drive FlexRigs, and the remaining 24 idle rigs are SCR rigs. Included in the 243 rigs that are active today are 162 rigs under term contracts and 81 rigs in the spot market. Looking ahead at the second quarter of fiscal 2015, we expect revenue days to decrease by roughly 25% quarter-to-quarter. And given the current trend, we could have less than 200 rigs active by the end of the quarter. Excluding the impact of revenues corresponding to early-terminated long-term contracts, we expect our average rig revenue to decline to levels between $27,000 and $27,500 per day. The average rig expense per day level is expected to increase to roughly $13,350 as we deal with some volatilities and significant changes in activity levels. Subject to additional early terminations, and excluding rigs that we have received early termination notifications for, we have term contract commitments in place for an average of approximately 160 rigs during the second quarter and an average of about 137 rigs during the second half of fiscal 2015. The average quarterly pricing level for these rigs that are already under term contracts is expected to remain roughly flat during the first -- excuse me, during the fiscal year as some rigs roll off and new builds are deployed. The quarterly average pricing for rigs in the spot market slightly increased from the fourth quarter of fiscal 2014 to the first quarter of fiscal 2015 but is expected to significantly decline during the second fiscal quarter. Spot pricing today is over 10% lower as compared to pricing for rigs now working under term contracts, whic of course, were negotiated over the last few years. Let me now transition to our offshore operations. Segment operating income increased to approximately $21 million from $15 million during the prior quarter. Total quarterly days increased by about 10%, and the average rig margin per day declined to $20,732. All 9 of the company's platform rigs were active by the end of the first quarter. As we look at the second quarter of 2015 -- of fiscal 2015, we expect revenue days to remain relatively flat, along with a decline in the average rig margin per day to approximately $19,500. Given current market conditions and some expected platform-to-platform rig mobilizations, we would not be surprised to see activity levels and average daily margins decline during the rest of the fiscal year. Management contracts on platform rigs continue to favorably contribute to our offshore segment operating income. Their contribution during the first fiscal quarter including some favorable retroactive pricing adjustments was approximately $8 million. But this is expected to decline to approximately $6 million during the second fiscal quarter. Moving on to our international land operations. Segment operating income increased to approximately $12 million during the quarter. The average rig margin per day increased to $10,770. And quarterly revenue days remained flat at an equivalent of about 23 active rigs. As of today, our international land segment has 20 active rigs including 9 in Argentina, 5 in Colombia, 2 in Bahrain, 2 in the UAE and 1 each in Ecuador and Mozambique. 14 rigs are idle including 5 in Ecuador, 4 in Argentina, 2 in Colombia, 2 in Tonisia -- Tunisia, pardon me, and 1 in Bahrain. An additional 6 rigs already assigned to this segment are in various stages of transition from the U.S. to Argentina. For the second fiscal quarter, we expect international land quarterly revenue days to decline by about 10% to 15%. We also expect the average rig margin per day to decline by about 25% to 30% as compared to the first fiscal quarter, excluding any impact from early contract terminations. We received early termination notification for a rig with a long-term contract that is now idle and expect approximately $8 million in early termination revenues from that contract. We also have ongoing discussions with a customer regarding the possibility of an additional rig contract early termination. The daily margin weakness in this segment is primarily due to several rigs in transition and others becoming idle. The first 4 rigs related to our 10-rig YPF project have commenced operations in Argentina. We now expect to see roughly 700 revenue days from this project during the third fiscal quarter and to hopefully be at full activity during the fourth fiscal quarter. The project's daily margins, that is the project's daily rig margins and contribution to the bottom line, are also expected to improve as this long-term project is fully deployed during the fiscal year and transitional expenses are behind us. Let me now comment on corporate-level details. Given lower levels of expected activity during fiscal 2015 and a partial deferral of new FlexRig construction spending to fiscal 2016, we now estimate capital expenditures to be approximately $1.3 billion during fiscal 2015. We are reducing the construction cadence to 2 FlexRigs per month beginning in June through the end of the calendar year, allowing us to have new build continuity as we go through this downturn while, at the same time, not impacting the corresponding value of our backlog. Roughly 70% of the CapEx estimate for fiscal 2015 corresponds to our new build program, less than 20% to maintenance CapEx and the remainder to other projects. The portion corresponding to our 2015 new build program also includes most of the major components in dollar value required for the 6 FlexRigs under term contracts that are now scheduled to be completed during early fiscal 2016. Although we still expect to generate cash from operating activities during fiscal 2015 in excess of the $1.1 billion generated during fiscal 2014, we may need to externally fund a portion of our capital expenditures during the fiscal year. With a debt-to-cap ratio today of approximately 2%, our balance sheet is in great shape to enable the funding of our continued organic growth under the sponsorship of attractive long-term contracts with customers. Including the long-term contracts for the 40 new FlexRigs scheduled to be delivered during fiscal 2015 and the 6 additional ones now scheduled for fiscal 2016, we already have secured term contracts for an average of approximately 160 rigs across our drilling segment during the last 3 quarters of fiscal 2015, an average of almost 130 rigs during fiscal 2016 and an average of approximately 100 rigs during fiscal 2017. About 90% of those rigs correspond to our U.S. land segment and provide the company with the benefit of an average pricing level that is expected to generate great margin per day averages that are higher than the $15,557 per day average corresponding to our most recent quarter. 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 changes in market conditions, our backlog decreased from approximately $5.0 billion as of September 30, 2014, to approximately $4.6 billion as of December 31, 2014. The value of our backlog is expected to continue to decline during the second fiscal quarter, as we earned a corresponding income during the quarter through operations or through early contract terminations. We still expect our total annual depreciation expense to be slightly over $600 million during fiscal 2015 and our general and administrative expenses to be slightly over $140 million. The recent tax law change in bonus depreciation allowances resulted in a first fiscal quarter 2015 adjustment given a reduction of our 2014 cash taxes. This also increased our deferred taxes by approximately $100 million. This accelerated depreciation of property and equipment for cash tax purposes will favorably impact the company's liquidity during this fiscal year. We expect the effective rate for the remaining 3 quarters of fiscal 2015 to be between 35% and 36%. We repurchased approximately 810,000 shares during late November and early December of 2014 at slightly under $60 million. We did not repurchase additional shares after that time frame given the significant change in market conditions. We have a 5-year $300 million revolving credit facility that matures in May 2017. We're currently using -- pardon me, we are currently only using it for letters of credit and have over $250 million available to borrow under that facility. As it relates to our investment portfolio, the holdings remain unchanged as compared to the prior quarter. These holdings were recently valued at close to $150 million with an after-tax value of over $90 million. With that, let me turn the call back to John.

[John W. Lindsay:]

Thank you, Juan Pablo. And I'll close with a few comments regarding H&P's advantages and our outlook going forward before opening the call to questions. H&P has an experienced management team and seasoned field operations personnel that know how to manage through a downturn. The experience gained in the company's 95 years will continue to serve us well. And speaking of long-term service, I would like to acknowledge Steve Mackey on this call and his nearly 30 years with the company. Steve is retiring soon from his role as EVP, General Counsel and Chief Administrative Officer at the company. Steve worked closely with Hans for over 25 years, and I've been fortunate to work with Steve since 2006. He has contributed in many ways to the success of H&P. Steve, thank you for your many years of service, for your contributions, for your leadership, and every one at the company wishes you the best. In addition to great people, we have a strong balance sheet with ample liquidity and access to capital. We have a large term contract backlog supported by a very strong customer base. Finally, we have the largest and most modern fleet of AC drive rigs in the industry. We believe our strategy has positioned the company to be competitive through the cycles. Whether we are faced with a downturn, like we are today, or in an improving market environment, we are well positioned to take advantage of opportunities ahead. And now we will open the call for questions.

[Operator:]

[Operator Instructions] And we'll go first to the side of Jeff Spittel with Clarkston Capital.

[Jeffrey Spittel:]

Maybe if we could start off with a little bit of perspective on what's going on in the different basins, and if you could add a little bit of incremental color about where things have gotten the ugliest so far and maybe where things are holding up a little bit better.

[John W. Lindsay:]

Jeff, this is John. I'll give a little bit of an overview. It's similar to what we talked about earlier this month. I would say the areas that we've seen most of the weakness, if you think about it in terms -- not necessarily of just raw rig releases, but if you think about it in terms of percentage of rigs released in the basin that we're working in, we've -- the rigs, we have a small footprint, 11 or 12 rigs, out in California. That's been hit pretty hard, where about 80% of the fleet has been released there. The Niobrara has had over 50%; Marcellus is around 50%; Woodbine, 60%; Bakken is 40% -- a little over 40%. So the -- for us, I think, a positive is our distribution of rigs in basins like the Permian and the Eagle Ford. Both of those basins are our largest. Now we obviously have had several rigs released in each of those basins. But to give perspective, the Eagle Ford is down 25%, 28%, something like that; and the Permian is over 30%. So while we have had rigs released in those basins, it seems like those tend to be a little stronger in terms of the economics going forward.

[Jeffrey Spittel:]

I appreciate that. And you referenced -- eventually, this is going to create a market share opportunity. And it sounds like, obviously, with those sorts of numbers, people are letting rigs go, as you mentioned, indiscriminately at this point. From a timing standpoint, do you think that opportunity to capture market share comes to fruition a little bit more in fiscal '16 given that we're probably still relatively early innings in the rig count decline?

[John W. Lindsay:]

Well, I think just by the nature of our contract coverage and the quality of our fleet, even though the releases are indiscriminate, as I said in my comments, what we've seen thus far, if we're looking at the data correctly, is in the 300 to 500 rigs that I mentioned. Again, it's a pretty wide range. But that's what the third-party rig services -- or rig count services, best we can glean out of that. You still have a large percentage of that, 57%, 58%, are mechanical, and 27% are SCR. So yes, we are impacted. I think -- and again, it's not anything you're in a position to brag about at all. But I mean, we're still in a situation where I think we're picking up a little incremental market share as the -- as this falling-knife situation is going on. So I do think, to answer your question, I have no idea what the outlook is in terms of when we reach bottom. Are oil prices -- have we reached that level now? I don't think there's a great certainty in the market that we've gotten there. But if we are, that -- our experience is, is that when you get to that point where customers can put together budgets that they can count on and they can get a rig count forecast going forward, then I think that's when we have an opportunity as customers begin to high grade their fleet. I think that would be the opportunity that we would then be able to take advantage of.

[Operator:]

And we'll go next to the side of Jim Wicklund with Crédit Suisse.

[James Knowlton Wicklund:]

Look, 15,000-plus daily margin. We're hearing from all the service companies that they're being asked to cut prices by anywhere from 15% to 25%. And then everybody is pushing down the supply chain as much as they can. I guess my first question is, how much on a spot leading edge rate is that 15,000 at risk? Will companies come and say, "We'll let you have a $2,000 a day margin," or they will cut you by percentages? Or how does the mechanics actually work of you trying to stay working and them trying to get the price down?

[John W. Lindsay:]

Well Jim, again, as usual, that's a great question. And we are -- again, our experience at this stage, in most cases, rigs that are in the spot market, what we've seen up to this point is a reduction a little over 10%. We have used the '09 downturn as a benchmark because it's really the closest in terms of this dramatic reduction in rig count. It's the most recent example that we have to draw upon. And what we saw then, Jim, was around a 30% reduction on FlexRigs. And so we went from similar pricing levels, $27,000 a day, $27,000, $28,000 to high teens. And we're not there today. I was going to say we're in the low 20s, but obviously, the longer this goes on, that has the potential to see that in the spot market.

[James Knowlton Wicklund:]

Okay. Guys, I'm looking at your expenses. How much can you push down on your supply chain? You mentioned that your $13,500 (sic) [ $13,350 ] average daily cost is going to go up a little bit. Is there any potential with the operator paying for fuel? And the way things are structured, is there any potential for you guys to push down on your supply chain in any meaningful way?

[John W. Lindsay:]

Well, I think in any case where -- if the downturn is long enough, then you begin to get some response back through the supply chain. Our expenses were actually lower in the first quarter than what we had originally estimated. As you probably saw, we're guiding towards higher expenses now as a result of the transition that we're seeing with rigs going to the sideline. That's a...

[James Knowlton Wicklund:]

It's hard to stay ahead of it. I know.

[John W. Lindsay:]

It's hard to stay ahead of it. But I think, over time, there's the potential to see that. But again, the other thing to think about on our cost structure is 2/3 of our expenses are labor costs. And so you have a -- somewhat of a small percentage of your total cost that is variable that you can work on. And again, I think we're better positioned as a company today as far as a lot of the processes, and you've probably heard us talk about some of the things that we've been successful in doing with our supply chain. So I think we're better positioned from that perspective. But to answer your question, I think, over time, we'll be able to get some improvement in our cost. But for right now, it's hard to see much past the next quarter.

[James Knowlton Wicklund:]

Okay. Guys, last one if I could. You mentioned that your debt-to-cap is only 2%, but you're probably going to access the Capital Markets to give you a little bit of cushion. And I guess you guys had tried kind of a soft raise of $1 billion. Do you have an idea of how much you'd like to have or need coming into this downturn?

[John W. Lindsay:]

Well, Jim, I didn't realize we were out looking for $1 billion.

[James Knowlton Wicklund:]

It's funny how rumors get first started in the downturns, isn't it?

[John W. Lindsay:]

Yes. Yes, it is. Well, let's set the record straight. We're not out looking for $1 billion. Yes, I'm going to turn the response over to Juan Pablo.

[Juan Pablo Tardio:]

Thank you, John. We don't have a number to share with you now. But as John just mentioned, we would expect our debt-to-cap ratio to remain very low, perhaps between 2% and 10%, but nothing as you've described.

[Operator:]

And we'll go next to the side of Byron Pope with Tudor, Pickering, Holt.

[Byron K. Pope:]

Juan Pablo, I appreciate all the color on the fleet and how to think about revenue per day. I think I heard at some point -- there were a lot of numbers. I think I heard at some point you say spot pricing today is roughly 10% lower than your term-contracted rigs. And I'm just curious as to -- if you could give the order of magnitude of what it was in the recently completed December quarter as a frame of reference.

[Juan Pablo Tardio:]

It was very close. So spot and term were very close, maybe 1 or 2 percentage point differences, so we've seen a 10% drop in spot. As John mentioned, that market, the spot market, appears to be softening as we speak. And we'll have to see how far that goes.

[Byron K. Pope:]

Okay. And then with regard to the 31 new builds still in the queue, I would guess that the lines here of those are still skewed toward the Permian. But I was wondering if you could provide a little color on the regional disposition of those. And to the extent that you have your customers want to push out those deliveries further out on the horizon, I'm assuming you'll get some sort of daily compensation for those delays. Is that fair?

[John W. Lindsay:]

Juan Pablo's looking at the distribution on the new build. Byron, this is John. I'll touch on the -- yes, typically, Byron, when we are pushing the contracts out, it's a win-win situation for us and the customer. And of course, we're H&P shareholders, and we're trying to do things that are cash flow neutral. And again, I think, from our perspective, I feel like what we've been able to do thus far in working with our customers has made a lot of sense.

[Juan Pablo Tardio:]

To your comment, if I may add to that, about 15 of the 31 are expected to go to the Permian; I think another 10 to the Woodford; and then other places like the Eagle Ford and the Woodbine.

[Operator:]

And we'll go next to Kurt Hallead with RBC Capital Markets.

[Kurt Hallead:]

So John, you took some time there to walk through the dynamics on how, each cycle through, we've seen fewer and fewer mechanical rigs operating and now that you have, I guess, more AC rigs than mechanical rigs. I know we're still in the very early stages of trying to manage through this downturn. But when we come out the other side, what risk or opportunity do you see with your current rig fleet? And some of your FlexRigs will be pushing on 10-plus years old. So what kind of risk is there for some of your idle rigs, potentially, in this next cycle run to have a little bit more challenge going back to work?

[John W. Lindsay:]

Well, Kurt, I think you've probably heard us talk before that while the first FlexRig3s that we've built in 2002 to 2004, those rigs, we've continually high graded and upgraded with the latest and the greatest, whatever that may be. And if you compare the rig -- those particular rigs and the day rates that they were able to command through the cycles and most recently in the most recent peak, the spot market pricing that those rigs achieved, it was very similar if not the same as what we had on rigs that, in the spot market, that had rolled off of their term contract that may have only been 3 or 5 years old. So while I -- again, it's a good question. I think, as I look at us and our overall fleet profile, one of the big advantages we have is this fleet continuity and uniformity and the size of the fleet and our ability to utilize standard processes for driving better drilling performance, rig move performance, safety performance. And I think all of those are advantages that will serve us well as we -- in the future as we come out of this downturn and customers begin to look at expanding their fleets and high grading their rig fleets. It's hard to say what the legacy rig count will do over the next 3 to 6 months, but what we can see is a pretty clear trend as we go through these cycles.

[Kurt Hallead:]

John, then maybe as a follow-up, you guys indicated 160 rigs on term contract for this upcoming quarter and then 130, I think, on average for the remainder of your fiscal year. Again, just trying to think the process through. Given what's going on with spot rates and, obviously, lack of demand for putting rigs to work, what kind of percentage of -- what kind of appetite would there be for the E&P companies necessarily to feel like they have to put your rigs that are going to roll off back on term when there's so much availability in the marketplace?

[John W. Lindsay:]

Well, rigs that are rolling off of term contract, as we've seen in the past, some of those rigs continue to work in a spot-market environment. We're going to be competitive in the spot market. Obviously, our value proposition is valuable through the cycles, and so we're going to be competitive. And there'll be some hand-to-hand warfare in the trenches, I'm sure. But I think we're well positioned to get in there and battle it out and keep rigs working in the spot market. Again, at this stage of the market, it's hard to determine what level of rig activity we're ultimately going to go to. Like I said, we're in this 300 to 500 range now, and many expect it to be closer to 900. So with that in mind, I would say we're going to continue to see rigs in the spot market released. And potentially, again, depending on the rig and it working for a particular customer, in some cases, rigs will roll off of term, and then they'll roll into the spot market and they'll continue to work. The question is what's the rate in the spot market.

[Juan Pablo Tardio:]

And if I may add a little bit more granularity to the numbers, I think we said about 137 in the U.S. land segment working the second half of the fiscal year. On the third quarter, the average would be closer to 145. On the fourth quarter, it'd be closer to 130.

[Operator:]

And we'll go next to the side of Scott Gruber with Citigroup.

[Scott Gruber:]

Juan Pablo, can you help us think about how the deferred tax liability comes due as the new build program winds down?

[Juan Pablo Tardio:]

Well, I'll give it a shot, Scott. It depends on many moving variables. But certainly, the retroactive application of the allowance for 2014 is very helpful for fiscal 2015 liquidity. As I mentioned, we expect an additional $100 million coming in from that source during the fiscal year. As we go into 2016, 2017, it all depends on what happens to CapEx spending during those years. I think what your question might imply, which is, I think, fair, is let's assume that in 2016, CapEx levels are much lower, perhaps closer to maintenance CapEx as compared to fiscal 2015. If that were to happen, then yes, we would see a reversal. But the reversal would be very slight. I -- we have a $1.3 billion liability related to deferred income taxes. That would probably come down by maybe between $10 million and $30 million during 2016. And then in 2017, it might be another amount that might be a little larger than that if CapEx continues to be very low. But if CapEx increases at some point, then we would once again probably start to defer additional income taxes. Did I address your question, Scott?

[Scott Gruber:]

Well, you did, and you answered my follow-up even before I could ask it, so you're definitely thinking ahead. And so maybe if we can switch gears then. I was a bit surprised with the guidance on the international front just in terms of activity in 1Q. Can you talk about -- 1Q calendar. Can you talk about the outlook for the rest of the year on international side of the business?

[Juan Pablo Tardio:]

Sure. We've had a few rigs become idle, some of those in Ecuador, Bahrain. We've seen Argentina also decline in terms of activity. The bright light, of course, is related to the YPF project, where we have 10 FlexRigs under 5-year contracts each that are in the process of being deployed. And so that will improve activity levels or at least, hopefully, more than offset any other declines that are market-driven from other countries and even from Argentina rigs that may become idle given market conditions. But -- so it's going to be a balancing act. We're pleased with the level of margins that we expect from our contracted rigs including those in Argentina. We have other contracts in other countries. It really is a combination of several things. But it's tough to see activity start to decline in general and also margins become softer. As I mentioned, what we do expect after the transition that we see that is ongoing, that is rigs becoming idle, rigs moving to Argentina, country to country, et cetera, we hope to see some improvement in daily margins by the end of the year. But again, it'll depend on market conditions in a significant way.

[Scott Gruber:]

But do you think it's reasonable to assume that you still have some active rig count growth over the course of the year with growth in Argentina more than offsetting potential declines elsewhere? Or is it more reasonable to assume a flattish environment from here?

[John W. Lindsay:]

I'd hate to speculate on that, Scott. I think it's reasonable to assume the flat to up. But it -- again, it'll depend on market conditions.

[Operator:]

And we'll go next to the side of Brad Handler with Jefferies.

[Brad Handler:]

Maybe just a couple clarification questions because I'm not quite sure. I think, John, you were helpful in giving us percentage declines in basins in an earlier question. Those are for the industry, right?

[John W. Lindsay:]

No. Those are our experience up to this point.

[Brad Handler:]

Your experience, okay. So for example, the Marcellus, your experience was down 50%.

[John W. Lindsay:]

Yes. And then again -- and so using that, Marcellus is a -- for H&P is a very small basin. That's the reason why I summarized it in -- on percentages, but I also said, well, really, our big exposure, the big basins with Eagle Ford and Permian and Bakken. We're really strong in the Eagle Ford and in the Permian.

[Brad Handler:]

Understand. Okay. And then maybe another way to ask Scott -- or I get it, Scott's issue, and it wasn't quite as clear for me as I want it to be. You -- Juan Pablo, you gave us the contracts for average '15, '16, '17. Can you just give us U.S. lower 48 contracted values for those years, please?

[Juan Pablo Tardio:]

Yes. Let me start with -- let me come back to fiscal '15. But on fiscal '16, I have 100 -- approximately 115 rigs; and approximately -- excuse me, 85 rigs for fiscal '17. Going back to fiscal '15, let me give you quarterly numbers for the remaining 3 quarters. For the second fiscal quarter, it would be approximately 161 rigs. For the third fiscal quarter, it would be 145. And for the fourth fiscal quarter, it would be approximately 130.

[Brad Handler:]

Great. All right. I really appreciate that clarity too. If I could squeeze in one more, please, a question about the early terminations. I guess maybe it's a little bit of a looser question. But in some of the prior downturns, have you experienced as much early terminations as you -- on some sort of relative basis as you are experiencing thus far this -- in the last 2 or 3 months?

[John W. Lindsay:]

Yes, Brad, we -- in 2009 and 2010, we -- I believe it was over 35.

[Juan Pablo Tardio:]

Yes, between 35 and 40 early terminations in fiscal 2009, I believe.

[Brad Handler:]

So if I rough [ph] the math now, it looks like you're already there. Given the $60 million in early termination in 2Q, I'm sure it'll push you over the 40 number. And of course, you're on a -- that's on a [indiscernible] and a ledger count.

[John W. Lindsay:]

I'm sorry. No, Brad. We were around the low 20s in total.

[Juan Pablo Tardio:]

So I think you were hearing us talk about dollars, perhaps, when we were talking about total rigs early terminated. So let me go ahead and try to clarify that, if I may. For what we've seen so far since our last conference call, since the steep downturn here, we've seen a total of 22 early terminations in the U.S. And we've already reported for the first fiscal quarter that we have approximately $23 million in revenues corresponding to that. In the second fiscal quarter, of course, we'll have to determine, but we estimate that the early termination revenues would be over $60 million. So the $23 million plus the $60-plus million corresponding to those 22 early terminations. Now let me go back to 2008, 2009. In 2009, I believe that we had between 35 and 40 rigs early terminated in the U.S. during that entire year. And the corresponding revenue from that -- and the number that I'll give you, it does include fiscal 2010, I believe, but it was over $200 million. I think it was close to $210 million.

[Brad Handler:]

Got it. Yes, you're right. I had -- I heard the 22. I thought it didn't cover the second quarter terminations. I didn't realize that, that was encompassing all the rigs, so I got it, so great.

[Operator:]

And we'll go next to Michael LaMotte with Guggenheim.

[Michael K. LaMotte:]

Most of my questions have been answered. But John, if I could follow up on just the headcount reduction. In particular, I know that you all have always had a very robust human resources program. Can you talk about what this means from a recruiting standpoint and what you're doing on the front end? And also, how do you protect the loss of intellectual capital with these reductions?

[John W. Lindsay:]

Well, Michael, I'm not going to go into a lot of detail on the process and what we do. What I can say is we've been successful through the cycles in maintaining our skilled personnel, our most experienced people. Again, like my comments said, you've got positions that get eliminated as these rigs get -- go idle. But we do -- we have a very good HR effort. We have very good people and good systems that enable us to hang on to our best people. And that's ultimately what our goal will be going through this downturn, is hanging on to our best folks.

[Michael K. LaMotte:]

And coming out of the downturn, as you start to put rigs back to work and go to hiring again, generally, what's been your experience, say, coming out of the trough of '09 in terms of the productivity hit associated with having to train people as you're bringing them on and adding rigs? And what's that -- I can see what it's done to your cash cost, but is that something that we should be mindful of as well?

[John W. Lindsay:]

Well, I think our experience would be, coming out of the downturn, the productivity is very, very good. It's very strong. And as you can imagine, at peak rig counts, when the industry is scrambling and trying to attract as many people into the industry as possible, that a lot of times that has some negative impact on performance. But our -- I think our track record has been really good because of the -- our ability to work more rigs through the cycles. I think it's been communicated pretty strongly through the field operation. And as we begin to put rigs back to work, we generally have a lot of folks that are interested in going to work for H&P. So that's been our experience. I can't say it's what that will be in the future, but it sure feels that way. Again, I think we've got a lot of things on our side here, obviously, the rigs, the uniformity, the fleet. The safety record that we have overall as a company, I think, over time, has been very good.

[Operator:]

And we'll go next to John Daniel with Simmons & Company.

[John M. Daniel:]

John, have you guys allowed any of your customers at this point to sublease rigs?

[John W. Lindsay:]

John, that is something that, through various parts of the cycles, we've -- there is a provision in the contract that customers are able to do that, and they have some -- have had some assignments. There may be a couple that are ongoing right now. I think, at this stage of the market, there's not -- as you can imagine, there's not a lot of people looking for rigs. But there are a few examples of that. And like I said, through the cycles, we'll see our customers do that.

[John M. Daniel:]

Okay. I'm just trying to understand the -- if possible, what the delta would be in terms of what they're willing to sublease from a rate versus maybe perhaps your spot rate, if there's much delta between the 2. Do you have any color on that?

[John W. Lindsay:]

I really don't, John. I mean, that's really -- you probably need to ask the -- the operators need to ask our customers that because I really don't have a feel for that.

[John M. Daniel:]

Okay. And then like some of the others on the call, I missed some of the commentary from the prepared remarks. But Juan Pablo, did you comment on or quantify the average cash margin attendant to those contracted rigs in fiscal '16? I thought I heard you say something in a $16,000, but I was writing feverishly and I didn't...

[Juan Pablo Tardio:]

I did. I did mention that on -- the U.S. land rigs that are under term contracts, not only for fiscal '16 but all of them through the next -- including fiscal '15 and then through the next several years, we mentioned that the average expected margin per rig per day would be over the average that we saw for the first fiscal quarter in terms of total cash margins for the quarter. And that was a reference of $15,557, which corresponds to the first fiscal quarter. And so a short way to put that is that we expect even better margins for -- from all of our term contracts going forward.

[John M. Daniel:]

Okay. And I presume there's no willingness on your part to adjust or amend those term contracts for customers?

[John W. Lindsay:]

Well, John, again, we've done our best. This isn't the first one of these cycles we've gone through. We've done our best to create win-win situations. We do our best to stay whole on that. I think it's interesting because when you think about our customers and operators in general, when they release rigs and their rig lines become idle, then they're reducing their future outflows of CapEx. I mean, that's an obvious statement. But you contrast that with us, and when we ink a new contract, when we have a term contract with a customer, that's when our CapEx -- the majority of our CapEx is then. So we've made a commitment. We've made a commitment to our supply chain and to our suppliers. And so again, a lot of our costs are already sunk. And of course, our goal is to get it paid back and get a rate of return on that investment that we've already made.

[John M. Daniel:]

Okay. Fair enough. Just a couple of quick ones for me here. Are any customers at this point having payment issues yet? And does the G&A guidance incorporate any growth from that expense?

[John W. Lindsay:]

Not at this point, John.

[John M. Daniel:]

Okay. And then the last one for me. As the rig count goes lower, do we see cash costs per day go higher as you spread those costs over the lower rig count?

[John W. Lindsay:]

Well, we've seen in past cycles that our expenses went up, but primarily, that was associated with transitional rigs becoming idle and costs associated with idling those rigs and preserving the rigs properly and taxes and things like that. I'm not aware of any additional costs that we've seen as it relates to that. I mean, we're going to -- we'll manage through that, again, depending on how many rigs ultimately become idle.

[Juan Pablo Tardio:]

And John, let me further clarify. What we're referring to potentially going up slightly is the average rig expense per day. If we're -- if we would be referring to the total operating costs, those costs would be coming down significantly in proportion to the decline in activity, of course.

[Operator:]

We'll take our final question from Thomas Curran with FBR Capital Markets.

[Thomas Curran:]

I'll just limit this to one question and can tackle the rest with you next week. Returning to international, Juan Pablo, in your flat to slightly up outlook, could you address 2 topics? The first would be term indications, if any, from YPF of an interest in potentially increasing your working rig count for them beyond just these initial 10 and any interest you'd have in doing that. And then the second would be there are some seemingly resilient bright spots out there onshore internationally. Yes, I guess the most obvious would be Saudi Aramco, the UAE. Are you exploring, at all, moves into those or any other markets that look as if they might be more resilient?

[John W. Lindsay:]

Tom, this is John. As far as Argentina YPF at this stage, we've talked previously about additional rigs. I'm not aware of any ongoing or recent conversations about additional rigs. And as far as just overall international, at least my sense is, right now, I think everybody is sitting back and waiting and watching to see where pricing, where oil pricing is going to go. I don't know of -- and again, we've talked to our marketing folks, business development and operations folks, and there's really not any -- what I would consider any real bright spots on the horizon that I can think of right now. Juan Pablo, is there any areas that you can think of?

[Juan Pablo Tardio:]

No, John.

[Thomas Curran:]

John, just a quick follow-up there. If they were to emerge, though, would you be open in considering other markets in the Middle East or anywhere else?

[John W. Lindsay:]

Sure. Sure. We have -- we continue to look and look for opportunities to grow the business. And again, it obviously is a great opportunity. That was why we were able to take advantage in Argentina, is at the time when we first entered into those contracts, we had 15 rigs available or so in the market. And we were able to take advantage of that. So obviously, we're in a situation where we're looking to -- for opportunities and looking to expand.

[Juan Pablo Tardio:]

Thank you very much, everybody, and have a good day.

[Operator:]

And this does conclude today's program, ladies and gentlemen. We certainly appreciate everyone's participation. You may disconnect at any time. Once again, thank you for joining us.