Helmerich and Payne Inc (HP) 2010 Q2 法說會逐字稿

Good day, everyone, and welcome to today's second-quarter earnings conference call. At this time all participants are in a listen-only one. Later you will have the opportunity to ask questions during our question-and-answer session. (Operator instructions). Please note this call will be recorded. I will be standing by, should you need any assistance. It is now my pleasure to turn the call over to Mr. Doug Fears, Executive Vice President and CFO. Please go ahead.

Thank you, Natasha, and good morning, everyone. Welcome to Helmerich & Payne's conference call and webcast to discuss our second-quarter earnings. With us today are Hans Helmerich, President and CEO; Executive Vice President, John Lindsay; and Juan Pablo Tardio, Director of Investor Relations and soon to be CFO. Also joining us today is Mike Drickamer, H&P's new Director of Investor Relations, and we welcome Mike to the call.

As most of you know, much of the information provided today involves risks and uncertainties that could significantly impact expected results and that are discussed in our most recent 10-K. We'll be making references to non-GAAP financial measures such as segment operating income and operating specifics. You'll find those reconciliations and calculations on the last page of today's press release.

This morning we announced net income of $0.43 per share for our second quarter ended March 31, compared with net income of $0.98 per share during last year's second quarter and $0.59 during this year's first quarter. Included in our second-quarter fiscal results is $0.18 per share from a currency exchange loss in Venezuela.

During the second quarter capital spending totaled approximately $78 million. As we revised our estimate in March we expect our total capital spending to be $330 million for the year. During the quarter total debt decreased by $45 million to $440 million, and thereby decreasing our debt to total cap ratio of 13.6%.

G&A expenses of $20.8 million were flat sequentially but did exceed our estimate of $17 million to $18 million that we had talked about in our last conference call due to higher than expected accruals for compensation expenses. For the remainder of fiscal 2010 we expect G&A expenses to be in that $19 million to $20 million range.

On the other hand, the tax rate of 38% during the quarter was lower than our expected 40% to 41%, primarily because assumptions regarding tax obligations corresponding to the devaluation in Venezuela and some other tax-related estimates proved to be too conservative. And as a result, we now expect tax rates to be in the 37% to 38% for the remaining two quarters of this fiscal year.

The pre-tax value of the Company's investment portfolio is approximately $380 million or about $250 million after-tax. And as you all know, 90% of that value is in Atwood and Schlumberger shares.

On a personal note and as we have previously announced, tomorrow I'm retiring after 24 years at H&P, the last 22 of which were as CFO, and I feel so fortunate to have served such a great company and with people who are not only competent professionals but who constantly strive to do the right thing, who are great people. I believe that much of the success that we've had here is due to the culture that Walt and Hans Helmerich have established over the 60 years plus that those two gentlemen have led the Company, and I'm grateful for their leadership and example.

For the first 17 years of my time as CFO, I was the investor relations contact for the company. Since 2005, Juan Pablo Tardio has taken that role to a new and higher level, and I believe he'll do the same as the new CFO for H&P.

I consider one of the most enjoyable things about my job was the opportunity to work with you, the research analysts, the portfolio managers, shareholders and bankers, some of whom are on this call. I want you to know that I truly enjoy that aspect of my job and found it a pleasure to work with you and to know you through the years. I will miss and have missed our interactions and I want to wish each one of you the very best. And tomorrow I'll give my farewell speech to my H&P colleagues and have much more to say about them at the time. But just let me say now how proud I am of them and proud to have been a part of their team and appreciate all they have done to make this such a great Company.

I would now like to turn it over to Hans Helmerich, President and CEO. And after Hans and John have made their comments, we'll open up the call for questions.

Thanks, Doug, for those nice remarks. I was going to say something at the end of my comments, but let me just respond now and say on behalf of the whole Company, we want to really express our appreciation for your 24 years of service. Doug, as many of you know, is highly respected inside and outside of the Company. In fact, he was just honored recently as the top CFO in our group by Institutional Investor magazine, which was a nice recognition.

On a personal note, I've enjoyed working closely together all these years and appreciate the leadership skills and personal integrity that you've provided in your role here. Thanks for your contribution to the Company. You will be missed. And if you find yourself missing these calls, we'll be able to make room at the table for you. But I think the heavy lifting is going to shift to Juan Pablo and Mike.

So with that, let me turn to my comments. Since our last webcast, the Baker Hughes land rig count has increased by 12% or over 150 rigs, while natural gas prices during that time have actually fallen by 25%. Energy cycles typically don't follow that pattern. Usually, lower declining product inventories stimulate higher pricing, which then leads to higher activity levels. But these are not normal times, and the building inventory levels and the uncertainty associated with future natural gas prices will likely keep things volatile going forward in the near-term.

Our guess is the volatility will be somewhat range-bound by several factors. The mild spring has contributed to record natural gas inventory builds, and investors' concerns over the softness in natural gas pricing. This morning's build of 83 BCF will only add to their concerns. Many analysts are calling for this year's faster than expected domestic rig count climb to not only top out but give back somewhere between 100 and 200 rigs.

We are not seeing a pullback from our customers as high-performing rigs remain in short supply. But we would not be surprised to see the overall industry count soften during the second half of the year. At the same time, several factors such as strong oil prices, customers drilling to hold valuable leases and hedges in place have locked in higher prices, should all act as a downward buffer to the rig count.

In regards to attractive oil prices, the current shift from gas to oil drilling has driven the growth in oil-related activity to increase by 180%, which has outpaced the natural gas-related activity improvement of 40% since the bottom last year in June of 2009.

Beyond just a general increase in the oil-related drilling activity, we are seeing this oil drilling become more complex across the industry. Directional or horizontal wells now account for almost 50% of total oil-related activity, up from 40% a year ago. At H&P our exposure to this category, classified as complex oil wells, is even greater with nearly 70% of our drilling rigs that are drilling for oil are in fact drilling either directional or horizontal wells.

We expect our exposure to oil to continue to grow. Since our last call we have extended contracts on six FlexRigs already in the Bakken and signed contracts to send an incremental six FlexRigs, including two previously announced new builds, to this market. We expect that by the beginning of the fiscal fourth quarter 2010 we will have 16 rigs active in the Bakken shale.

So if oil-directed drilling in liquids-rich gas focus helps to limit the downward pressure on the rig count, the same limitation can be argued on the other end of the cycle for the possibility of upward increases. A repeat of factors that converged to fuel the up-cycle from 2002 to 2008 seem to be a remote possibility at this point. That cycle saw oil prices more than triple, and the rig count increased threefold, all to be followed by crashing energy prices and a rig count that fell by more than 50% during the most recent down-cycle. We described this on our last call as a one in 25-year event.

True or not, a case can be made that a significant period of time where the energy cycle is better behaved or range-bound will ensue. The implications of this for the land drilling industry would be profound and would offer us, we believe, potential market share opportunities. Not long ago, the drilling industry primarily paid attention to fleet size instead of asset quality. Large fleets were cobbled together from very old rigs of every make and model during the down-cycle, and as the up-cycle took hold, those assets provided operating leverage in an improving environment.

As E&P spending increased, the customer bid up day rigs for even these commodity rigs that emerged from the weeds. Several factors have shifted to impact this model. Our introduction of the high-efficiency rig class, the FlexRig, forever changed the perception that a rig is a rig. Differentiated performance and efficiency gains created a value proposition that was reflected in a range of pricing and day rates among different rig types. And now, increasingly, the customer began leveraging the expanded capabilities of these rigs into more complex and challenging drilling requirements, hastening the obsolescence or unsuitability of underperforming assets.

Today those efforts are yielding results. The most obvious in terms of robust gas supply visibility that may reduce the volatility or the highs and lows in future cycles. Within this potentially more limited range, customers will remain focused on performance and drilling efficiency as the means to maximize value. The steady march towards more complex and challenging wells will further encourage customers to be more discriminating.

Among the various service providers, pricing and margins will reflect the current range of asset quality in the marketplace. Our FlexRig activities -- our FlexRig activity levels are now approaching the mid-90% range, while utilization for older industry legacy assets languish in the 40% range. All of this is to say, the advantage on the service side will continue to shift from sheer size to performance in the field, driven by a combination of people and iron, and that is where we plan on continuing our efforts.

So with those comments, John, I'll turn the call over to you.

Thank you, Hans, and good morning. We are pleased with the improvement in the business. Even with the uncertainty of natural gas prices, operators are directing more dollars towards oil and liquid-rich plays, and FlexRigs are in high demand for both. New and existing customers are high-grading their fleets with FlexRigs as they pursue more difficult wells, employing horizontal and directional drilling to deliver better and more cost-effective reservoir performance in shales and other unconventional plays.

The following comments will describe the performance and outlook for our three operating segments, and we'll start with US land. As of today, 160 existing US land rigs are contracted as compared to the 148 rigs reported during our last conference call in January. Included in the contracted rigs are five completed new builds that are not generating revenue days but that are earning revenue before their initial field deployment.

Activity in the spot market continues to improve as 51 of the 160 contracted rigs are currently operating in the spot market, including 48 FlexRigs. The remaining 109 active rigs, including 77 new build FlexRigs under their original contract, are under long-term commitments. 53 of our land rigs remain idle in the US, including 19 FlexRigs and 34 mobile or conventional rigs. All of these idle FlexRigs are FlexRigs 4's, which target shallower wells. Six of the 19 are already contracted and expected to commence operations in the third quarter. The number of average active rigs during the second quarter increased to 145.7 from 122.4 rigs during the previous quarter. This does not include an average of approximately four new build rigs under term contracts that generated revenue but not revenue days during the second fiscal quarter, due to customer-requested delivery delays.

Spot pricing continues to gradually improve, especially for larger FlexRigs in unconventional plays, which should drive modest improvement in H&P's average rig revenue per day for rigs in the spot market to the high teens. The average revenue per day for H&P rigs already under term contracts is now expected to remain in the mid-20s during the remainder of the fiscal year. This average is expected to increase by about $1000 per day, an average, during fiscal 2011 and by an additional $600 per day, in average, during fiscal 2012.

Considering only existing contractual commitments, the Company now expects an average of approximately 107 rigs to remain under term contracts during the third fiscal quarter and 105 rigs during the fourth fiscal quarter. The corresponding annual averages for fiscal 2010, 2011 and fiscal 2012 are 102, 75 and 42 rigs, respectively.

Improving activity is expected to increase the number of US land revenue days by 5% to 10% quarter to quarter. Excluding the impact of early termination revenues and customer-requested delays, average rig revenue per day in the third fiscal quarter is expected to be flat to slightly down sequentially. Early termination and delayed revenues for the remainder of fiscal 2010 are now expected to be approximately $14 million, above previous expectations of approximately $10 million, due to one incremental contract termination on a conventional rig and extended contract delays on two new builds.

Revenues from early terminations and customer-requested new build delays are expected to be $8 million in the third fiscal quarter and $6 million in the fourth fiscal quarter. When comparing the second fiscal quarter of 2010 to the first quarter and excluding the favorable impact of compensation related to early terminations and customer-requested new build delivery delays for US land, average rig revenue per day for the second fiscal quarter decreased by $138 to $22,586. Average rig expense per day for the second quarter increased by $1016 to $12,089, and average rig margin per day for the quarter decreased by $1154 to $10,497.

A large percentage of the increased expense per day from the first to the second fiscal quarter was a result of reactivating 18 rigs from stacked status during the second fiscal quarter and 12 rigs toward the end of the first quarter. The costs were comprised of maintenance and supply costs, training and labor cost. A strategic part of the H&P brand is using best practices for cost control, but an equally important part is making sure that the rig is mechanically sound and the rig leadership and crews have undergone training as we endeavor to deliver value to our customer. The balancing act between cost controls and delivering customer satisfaction can result in somewhat higher cost during times of increasing our rig count, but we believe that, long-term, this also delivers value to our shareholders.

As we look to the third fiscal quarter, we expect that costs should remain flat or slightly lower as we continue to bring rigs out of stack and add rigs to the active fleet. As previously announced, three new FlexRigs with multi-year terms contracts in the Bakken and Haynesville are expected to be completed by the end of the fiscal year. Depending upon whether or not we choose to proceed with the completion of the five previously announced potential new builds, we could deliver these rigs at a rate of approximately one rig per month, lasting into the first fiscal quarter of 2011.

Now, talking about our offshore operations, as expected, the average offshore rig margin per day decreased sequentially from the first to the second fiscal quarter. The sequential decrease was due in part to higher than expected revenues in the first fiscal quarter related to compensation by a customer for improvements on a rig. Average rig margins per day are expected to decrease by 10% to 15% as one of our rigs is expected to be subject to a lower day rate during a rig move taking place during the quarter. Average utilization during the second fiscal quarter was 81%, down sequentially from 85% in the first fiscal quarter.

Today, seven of the Company's nine offshore platform rigs are active. One of the two idle rigs had a prospect for work beginning in the fourth fiscal quarter of 2010.

Third-quarter utilization is expected to slightly decrease from 81% experienced in the second quarter. We are now working on three platform rigs owned by customers under management contracts, including two in the US and one in Equatorial Guinea.

In the International segment, activity days grew 4.5% sequentially to 1766 in the second fiscal quarter, essentially in line with our estimates of 5% growth. However, margins were stronger than expected with per-day margins improving almost $500 to $11,038, exceeding our expectation for the quarter. The better-than-expected margins were due to collections in Venezuela and a retroactive day rate adjustment in Argentina. We currently have four FlexRigs earning reduced standby rates in Argentina due to a strike. Unless further payments are received from Venezuela, average daily rig margins for the International segment are expected to decrease by close to 20% in the third fiscal quarter.

All 11 rigs in Venezuela remain idle; and, while we will continue to pursue future drilling opportunities in Venezuela for these 11 conventional rigs, we do not expect to return to work in Venezuela until additional progress is made on pending receivable collections and on conversion of local currency to US dollars.

Today we have 21 active rigs internationally, including 12 contracted under long-term commitments. The active rigs by country are six in Mexico, five in Argentina, four in Columbia, four in Ecuador and two in Tunisia. During the third fiscal quarter activity days are expected to increase slightly, over 5%, as one additional FlexRig three is working in Tunisia.

As mentioned in previous webcasts, one new build FlexRig under a long-term contract for international work is still in the US earning delay revenue. This rig is now expected to be deployed and become active in Bahrain during the first fiscal quarter of 2011. This is the first FlexRig contract for the Middle East, and we are excited about the opportunity.

In summary, with $4 natural gas and $80-plus oil prices, E&P companies are announcing plans to reduce dry gas directed capital spending to fund increased levels of oil directed and liquids rich capital spending, especially in areas like the Bakken and Eagle Ford shales.

Our recent activity would suggest that if capital is redeployed to more oily and liquids-rich areas, H&P would benefit because of the FlexRig's ability to drill more complex wells, whether gas or oil. We have doubled our Bakken exposure to 16 rigs and added five additional rigs to the Eagle Ford, which should also total 16 rigs during the third quarter. We've been able to continue to grow the fleet in pure natural gas plays as well, and since the last call we've added seven rigs to the Marcellus for a total of 11 rigs and five rigs in the Haynesville for a total of 27 rigs.

Finally, we talk a lot about the quality of our rigs, but I would also like to reinforce the importance of a strong field organization. In addition to the drilling demands placed upon the rigs to drill more complex wells, quality personnel continue to be a strategically important advantage for H&P, and we believe we have the best people in the business. We have grown our fleet since 2002 by designing and building new, advanced technology AC-drive rigs, and it wouldn't have been possible without the commitment by our people to organizational excellence and executing on the value proposition to our customers.

Doug, I wanted to mention also we're going to miss you, and for the last time I will turn the call back to Doug.

Thank you, John, I appreciate that very much. Well, we are now ready to open the call to questions.

(Operator instructions) Pierre Conner, Capital One South.

First, welcome to Mike. Look forward to working with you. And, Doug, thank you for everything in the past and all the best wishes.

Thanks, Pierre, I've enjoyed working with you over the years.

John, I know we'll cover a lot of territory here, but the first one that pops in my head is Mexico. We've seen some change in activity levels from various integrated service providers and well service companies. So give us your current expectations in terms of remaining activity, continuity of the six and what we might be looking out for in that area.

As you know, we have six FlexRigs in northern Mexico, and all six are on term contracts. There has been quite a bit of slowdown. We haven't seen it impact us. We don't really foresee it impacting our six rigs and their activity. There is some possibility that we could be shifted around to different areas within Mexico, but right now with six rigs we're doing a great job in the area and I think our customer intends to keep the rigs where they are, at least for the time being.

As far as you know, your customers' contract doesn't come up against an expiration date in the next quarter or two?

Not to my knowledge, no. From what I understand, I know we've got two-year terms, and to my knowledge they have a commitment to continue to drill.

In a specific region here, then, domestically, what is H&P's activity in the Barnett of recent, and what do you see there?

We've added a couple of rigs back to work in the Barnett. Specifically, I haven't heard anything that would lead me to believe that there would be a lot of growth or that before that, there would be a pullback. I do think that just in general, not necessarily just with H&P rigs, but I think in general there could be a situation where some of the more pure play natural gas areas, you might see some rigs migrating to places like the Eagle Ford Shale. But again, we haven't seen that as of yet. And of course, there is some oil exposure in the Barnett that, at least from my perspective, I think is beginning to gain a little bit more traction. And that could impact H&P positively there as well.

But to be clear, you haven't yet put any rigs to work on any of the Barnett oil at this point? You're just in discussion?

No; I do believe we have one that is in the Barnett oil that's fairly -- it's a new customer for us, and I think it gives us some upward potential.

Robin Shoemaker, Citi.

You talked about the increase in average cost per rig having to do with reactivation. If we just look at the pure overall, excluding the rig activation costs, is there any upward pressure on rig operating costs that would come from wage increases and other things that are more generic? And would those continue?

As of yet, we have not seen any increases. If you are referencing just general labor, wage increases, no; we have not seen that. I don't expect that in the foreseeable future, but it's always a possibility. But that really -- that didn't have any -- the wages didn't have any bearing on this, on the costs in the second quarter.

So it was almost entirely the factoring in of rig reactivation costs in the quarter? Okay, could you give a little more detail on of the 16 of the 19 I'll Flex 4's that are going back to work, where those are going back to work and are they principally in the Rockies/Piceance, where -- the kind of formations they are designed for? Or, in other words, going back to work where they were previously? Is that right?

That's a good question, and I may not have said it clearly on the call. It was actually six out of the 19. The 19 that are currently stacked, six of those currently have contracts. But they are not included in the active fleet.

In general, what we've seen are those rigs going to work in the Marcellus. So, in other words, they're leaving either the Rockies either from Colorado or from Wyoming, going to the Marcellus, in some cases going to the Bakken. We have also had some rigs reactivated in Colorado, in the Piceance, that have gone back to work. And so that's a positive sign for us.

We've also had some Flex 4's that are going to work in West Texas in some of the oil plays.

Okay, so it's six rigs going back to work. And are they going back to work under a spot type contracts or on more of a term basis?

It's a mixture. We've got both. I don't recall what -- I was going to say I think the mix is more towards term, but I'm not certain about that. But it is a mix. I think there's a few in there that are well-to-well contracts.

Dan Boyd, Goldman Sachs.

I'm sorry if I missed this, but I just wanted to follow up on the cost and the reactivation portion of that. Excluding that cost, what would have been the trend in daily OpEx? And should we expect, two quarters from now, for that to just completely drop out of the mix?

Dan, when you look at the overall costs that we reported, if you look at the last eight quarters, that $12,000 cost falls in a band, a little on the higher end of the band, but nevertheless in that cost range. We are continuing to put rigs back to work; but, as mentioned on the call, we would like to expect that our costs would be flat to slightly down for the next quarter. It's kind of hard to say on the quarter after that because, as was asked earlier about labor and those kinds of things, there's a possibility that you could always have labor increases in the future. But we would expect that we would see the costs down slightly -- at least we're hoping -- in this next quarter.

I'd like to better understand the day rates that your rigs that are in the spot market that are working, the progression of those rates and your exposure to rising day rates in some of the better rigs, the FlexRigs 3's. So can you help me with the progression of what you've seen over the past couple of quarters and what you expect over the next couple quarters, or at least the next quarter?

Well, as we said on the call, in average we're looking at high teens, which would -- some of the larger -- like the Flex 3's, as an example, are going to be higher than that. And then some of the smaller rigs are going to be less than that. I think, just in general, we've seen a nice progression over the last couple of quarters of $1000, $1500 per quarter.

In that average rate of the mix of all the rigs; right?

Yes.

And, based on where you are today and where pricing is today, should we expect that trend to continue, or does that start to level out?

I think that's pretty difficult to predict at this stage. Again, as Hans had mentioned, a lot of people are talking about a pullback. If there's a pullback, there's always that possibility that the spot market pricing flattens out. Again, we have rigs that we see that are in very high demand, so in some respects it's hard to believe that they would reduce. But I think to believe that we would continue to be able to increase at this stage, I think, is too early to call.

Let me ask another way. Assuming spot prices don't change but things reprice, would there be a natural increase sequentially or not at all?

I think -- and we've talked about this before -- you are seeing this bifurcation where you've got scarcity in your higher end, higher performing rigs. And so our availability is very tight there. And as rigs reprice, to your question, I think they enjoy that improved spot market pricing we are talking about. Like John says, I think it's too early to see what the overall rig count impact is going to be. We think the brunt of that is going to be borne by the mechanical rigs and the lower end SCR rigs that are operating in regions that we're gaining market share in and would expect to continue to take market share.

So it's a pretty dynamic situation. And as you know -- you know, if you get a real big pullback, it's going to have some impact, less than historically, but some impact in our pricing scenarios. But we're sure not seeing evidence of that now.

(Operator instructions) Mike Breard, Hodges Capital.

Last quarter you mentioned some new rig orders. Are you still having talks with various operators that are interested in acquiring brand-new rigs from you?

We do have conversations ongoing in that regard, and so it's hard to know how those developed. But we've been pleased to see, at this time in the cycle, to be able to put three of those rigs that you mentioned under long-term contract as new builds. And the answer to your question is yes, we are still in dialog with additional customers.

Okay. And then, next, the Chinese government seems to be investing quite a bit of money in Venezuela. Are you seeing any more likelihood now that possibly you would start getting some more money back from Venezuela?

Well, we hope so. We would sure welcome that, and I think they have expressed an interest to do some drilling. And I think they have that need, and we'd like to engage in that activity. I think I know our position in terms of we really need to see some progress on our receivables.

So I think what you're seeing in the press should be somewhat encouraging, and it's part of an overall theme that Venezuela needs to continue to turn to the right in order to deliver the production that they're trying to deliver. So hopefully, that flows into seeing some improvement in our situation.

One of your competitors had mentioned that they were offered some incentives to come back to work in Venezuela. I think that was not PDVSA, but some other company?

We saw that, as well. Yes, we'd like to have some of that. Yes.

Okay. Just one comment more, on Doug. It's been nice working with you. I'm looking forward to working with Mike Drickamer. Thanks for your service.

Thank you; it's been a pleasure to know you and to work with you, too, sir.

It appears we have no more questions at this time.

Thank you all for joining us today. Our next conference call is scheduled for July 29. Thank you for joining us this morning, and have a good day.

This concludes today's conference. You may now disconnect, and have a good day.