Helmerich and Payne Inc (HP) 2010 Q1 法說會逐字稿

Good day, everyone, and welcome to today's program.

(Operator Instructions).

It is now my pleasure to turn the call over to Mr. Doug Fears. Please go ahead, sir.

Thank you, Shannon, and good morning, everyone. Welcome to Helmerich & Payne's conference call and webcast to discuss the Company's first quarter earnings. With us today are Hans Helmerich, President and CEO, John Lindsay, Executive Vice President, and Juan Pablo Tardio, Director of Investor Relations. As you know, most and 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 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.

Today Helmerich & Payne reported net income of just over $63 million, or $0.59 cents per diluted share from operating revenues of just short of $400 million for its first quarter, ended December 31, 2009. This compares with net income of $145 million, or $1.36 per share from operating revenues of approximately $623 million during last year's first quarter. Included in both quarters, net income are less than $0.01 cent per share of gains from the sale of drilling equipment, and involuntary conversion of long-lived assets. As you might have noticed on the statement of cash flows, our capital spending for the quarter was $64.8 million. We are still budgeting $265 million of capital expenditures for fiscal 2010. At December 31, 2009 our total debt was $485 million, and our debt to total capitalization was 15%. Our investment portfolio, primarily comprised of 8 million shares of Atwood Oceanics and 967,500 shares of Schlumberger currently has a pretax market value of just over $350 million.

On the income statement, you'll notice that General and Administrative expense is up by approximately $7.2 million compared to the previous quarter. Approximately $4.9 million of that increase was due to increased stock option expense, a noncash expense, most of which was a one time adjustment relating to the continuation of stock option investing at retirement from employees who meet certain employment criteria age and length of service with the Company. This new compensation policy was approved by the -- at the December Board of Director's meeting, and the accounting adjustment was applied to all current employees who now meet the requirement, even though still employed. There was also a $1.3 million increase in bonus accrual for the quarter, compared to the fourth quarter of fiscal 2009. We expect the G&A expense to be approximately $17 million to $18 million per quarter for the remainder of the year.

As reported in our press release dated January 12, 2010, the Company expects the recent devaluation in Venezuela to result in a currency exchange loss of approximately $20 million to be recorded in our second fiscal quarter ended March 31, 2010. This devaluation loss estimate is based on the balance of our believer based net monetary asset position in that country at December 31, and our current understanding of how the new, two exchange rate system will work for the oil service activity. This exchange loss is nondeductible, for tax purposes, which results in a negative impact to our effective tax rate for the remainder of the year. In addition, we expect to incur some additional income taxes in Venezuela, for our United States dollar denominated monetary assets, which will also increase our effective rate. There are plenty other complexities involved, but we believe our effective rate could be in the 40% to 41% range for the remainder of for each of the remaining quarters for our fiscal 2010. Successful collection of outstanding receivables could lower this effective tax rate.

After the adjustments corresponding to the recent devaluation of Venezuela, the total invoice amount by the Company that remains due from PDVSA as of January 12, 2010 is valued at approximately $57 million of US dollar equivalent, which includes $46 million in invoices issued since the Company changed its revenue recognition to cash basis for its Venezuela operations. Invoices issued under cash basis revenue recognition include $42 million of potential future revenue, and approximately $4 million of nonrevenue billings. All 11 H&P rigs that formerly worked for PDVSA have completed their contracts, and are currently idle. I will now turn the call over to Hans Helmerich, President and CEO. And after Hans and John have made their comments, we'll open the call to questions. Hans?

Well, we are encouraged by the improvement in our business during the quarter. Clearly, conditions compared to a year ago has substantially changed for the better. Last year the industry suffered through, what I hope will be a 1 in 25 year plus event, involving a credit crisis, and energy price collapse that was challenging for all. Allow me to mention some examples of how the Company coped with these challenges, and then identified some of the challenges we see ahead, as the industry moves through the current recovery. We weathered the storm well. First, we were well served by the land industry's strongest coverage of long-term contracts with over 50% of our US fleet secured going into the downturn. We were also in a good position with a strong balance sheet. After three years of record growth and capital spending, we maintained a debt to total capital of less than 20%. Doug just mentioned that number is now 15%.

We also committed a year ago to complete our entire new build order book, while others cancelled orders, we managed to maintain the continuity of our unique integrated manufacturing effort. We are now positioned to potentially continue to roll off one new rig per month through September 30th of this year. We went to extensive efforts to maintain our organizational and systems strength. As we have said before, the toughest part of last year was forced field reductions that corresponded to reduced activity levels. All the while, we have made every effort to keep our folks. We high-graded positions on active rigs to retain as many skilled positions as possible, placing dislocated employees on 31 new builds during the year was part of that effort. By avoiding the more damaging personnel reductions sustained by our peers, we positioned ourselves to both maintain the highest rated operating performance, and to smoothly transition to crew up as the recovery unfolds. That position is further enhanced by providing customers the industry's youngest and most technologically advanced rig fleet.

Today, we see customers responding to that combination of value, driven by our best-in-class people and iron. The number of new customers, who had previously not used a FlexRig has now risen to over 30. And of course, each of those turned down available competitor rigs at lower day rates, in order to pursue the value proposition and efficiencies offered by the FlexRig. John Lindsay will give you more specifics about how these new customers have helped improve our activity levels. And now with all of our larger FlexRigs, fully engaged how we would expect to see some spot market rate improvements. With 2009 behind us, the challenges going forward will continue to center around energy, supply and demand dynamics and the resulting oil and gas prices. Clearly, this winter's cold weather has made a positive impact on natural gas inventories. But uncertainty remains surrounding longer term demand, and future supply contributions from LNG, resource plays, and now an increasing industry rig count.

We continue to expect to see some choppiness ahead. If natural gas prices find a trading range, between $4.00 and $7.00, we will benefit as customers are more discriminating and value driven for longer stretch of time. rig counts may, in fact not reach either the previous highs, or hopefully the lows of the recent past. And while fewer overall rigs will likely be needed, the trend toward more complex and challenging wells will favor the most efficient providers that are able to offer customers a safe, consistent, and measurable value proposition. That goal is what we continue to focus on. And our people's success in delivering on this effort should continue to serve our shareholders well. In closing, I'm pleased to note, that with all the challenges we faced last year, our people delivered the best safety performance we have had in our 90 year history. It is an accomplishment we are very proud of. And with that, I would like to turn the call over to John for his comments.

Thank you, Hans, and good morning. We are experienced continued improvement in the overall H&P rig count. Spot market price is strengthening, some customers are beginning to ask for term contracts on FlexRigs, signaling confidence for future activity. New customers continue to high grade their fleets with FlexRigs, especially in the unconventional resource plays. So overall we are pleased with the fir first quarter results, and the outlook for the second quarter, and the following comments will outline our three operating segments. In our US land segment, 148 existing US land rigs are contracted today, as compared to the 127 rigs reported during our last conference call in November of 2009. Included in the contracted rigs are three completed new builds that are generating revenue, however, no revenue days, before their initial field deployment.

Activity in the spot market continues to improve, as 45 of the 148 contracted rigs are currently operating in the spot market, including 42 FlexRigs. The remaining 103 active rigs, including 79 new build FlexRigs under their original contract, are under long-term commitments. 62 of our land rigs remain idle in the United States, including 29 FlexRigs, and 33 mobile or conventional rigs. The number of active rigs during the first fiscal quarter averaged 122.4, as compared to 107.6 during the previous quarter. This does not include approximately six new build rigs under term contracts that generated revenue during the first quarter, and about eight in the previous quarter, due to customer requested delivery delays. And again, no revenue days. As expected, revenue related to early terminations and customer requested new build delivery delays in the US land segment totaled approximately $16 million during the first fiscal quarter.

We have been pleased to see several of the rigs that were experiencing delivery delays become active sooner than expected, reducing our estimates for this type of revenue in the future. We currently estimate this type of revenue to total approximately $19 million during the remaining three quarters of fiscal 2010, about 50% of that should be expected during the second fiscal quarter. In US land, the Company expects an average of approximately 102 rigs to remain under term contracts during the second fiscal quarter of 2010, 97 during the third fiscal quarter, and 87 during the fourth fiscal quarter of 2010. The average revenue per day for H&P rigs under term contracts is expected to remain in the mid 20s. Spot pricing is beginning to improve and selected unconventional plays for our large FlexRigs, which is expected to drive a slight quarter-to-quarter improvement in H&P's average day rate for rigs in the spot market. We expect to experience a 15% to 20% quarter-to-quarter increase in revenues days or average activity,y as we transition to the second fiscal quarter.

The combination of flat term contract revenue and a steep increase in the number of active rigs in the spot market may cause the average rig margin per day for the segment to slightly decline, when excluding the impact of early termination and delay revenues. The activity improvements have been mostly by our larger FlexRigs, Flex ones, twos and threes. And as of today, all of those rigs are fully contracted, with most of the demand come from the Haynesville, the Eagle Ford and Woodford shales. New contracts since our last webcast have allowed us to add eight rigs in the Eagle Ford and six rigs in the Haynesville. A recent analysis of publicly available rig count data leads us to believe we are the most active rig driller in terms of total combined rig count in the eight primary unconventional resource plays in the country, including the Haynesville, Eagle Ford, Barnett, Woodford, Bakken, Piceance, Fayetteville and Marcellus.

We lead activity in the Eagle Ford, Barnett, Woodford, and Piceance. Recently many of our customers have begun to expand or implement for the first time, their pad drilling operations allowing Ha&P to contract many of the FlexRig 4S model rigs. And you may recall that these rigs are designed to drill up to 22 wells on a single location. The increased interest for these rigs has not only been in our traditional areas, such as the Piceance, Pinedale and Barnett, but also in the Marcellus, Bakken and Haynesville shales. We believe multi-well pad drilling will be a long-term trend by operators in the US for environmental reasons, as well as drilling and production efficiencies.

Now to our offshore segment, and in offshore operations, average rig margin per day increased sequentially by $4,257 to $24,936. The average rig margin per day is expected to decline, but remains strong at over $20,000 during the second fiscal quarter. Average activity in the segment during the first fiscal quarter was 85%. Today, seven of the companies's nine offshore platform rigs are active. As we transition from the first to the second fiscal quarter, the number of revenue days for the segment is expected to decline by 5% to 10%. The two idle rigs currently do not have good work prospects for fiscal 2010. A previously mentioned prospect has been delayed by the cut customer. We are now working on three platform rigs owned by customers under management contracts, two in the US, and one in Equatorial Guinea.

In the international segment, the number of active international land rigs is currently at 20, including six in Mexico, five in Argentina, four in Colombia, four in Ecuador, and one in Tunisia. Twelve of the 20 active rigs are under long-term contracts for the duration of fiscal 2010 and beyond. In addition, one new build FlexRig under a long-term contract is still in the US earning delay revenue, while waiting on the customer to determine its first international location. We expect quarterly activity or revenue days for the segment to sequentially increase by about 5%, as we transition from the first to the second fiscal quarter. We experienced a steep quarter quarter increase in operating income, which was primarily a result of the Company's incremental activity in Mexico and Argentina, as well as a very successful short-term project, executed in Africa during the first fiscal quarter of 2010. We expect, however, our average rig margin per day to decline by up to 30%, as we transition from the first to the second fiscal quarter, primarily as a result of completion of the mentioned project in Africa.

In summary, we believe the FlexRig offering, and the organizational competency to efficiently operate advanced technology rigs positions H&P for long-term growth. Drilling is becoming more challenging today, as 50% of all wells drilled in the US are horizontal, compared to approximately 30% at the peak in 2008. And today, over 85% of active FlexRigs are on horizontal and directional wells. Not only are operators drilling more horizontal wells today, but they are also lengthening the laterals to provide more exposure to the reservoir. That puts even greater pressure on the conventional rigs, or lesser capable rigs in general, and highlights the limitations on the legacy fleet capabilities. Remember in 2008, approximately 70% of the available fleet was mechanical. Finally, we believe our proven track record of delivering reduced well cycle times, and consistently delivering best value wells is a major reason that H&P has been able to add 30 new FlexRig customers during the down cycle, and increase our rig count in the unconventional resource plays. Then I'll turn the call back to Doug.

Thank you, John. We'll now open the call to questions.

(Operator instructions)

We'll take our first question from the line of Waqar Syed from Macquarie Capital, please go ahead.

Congratulations on a good quarter. My question relates to international activity, international demand. Are you seeing any demand for your rigs? International markets, other than the where you operate currently? And then specifically to Iraq, do you see any opportunities, or do you have any interest in going into that region?

Well, we are seeing, in terms of international interest and conversations, Waqar, those are still ongoing. As you know, the rig count pulled back about 15% during the last year. So we saw that slow down, as we mentioned in our business, too. You mentioned Iraq, and we are reading and seeing the potential ramp up in activity there. And that would be an area that we would be interested in seeing what opportunities exist. So, as we think about international markets, we would still be interested in expanding the footprint in Mexico, and then our other current areas. We would like to think we'll have opportunities to be in the Middle East or North Africa. I have said before to you and others, that's a slow, unfolding effort in process, and it's at times, frustratingly so. But, yes, I think that's kind of our current thoughts on that. John, do you have anything to add to that?

Well, Waqar, as you know we have been working on a lot of international projects, and the growth has been relatively slow, much slower than we ever dreamed based on the performance. But there are some opportunities in the Middle East, I would have thought that they would have happened by now. I do think there is some possibility that some of those could happen by the end of this fiscal year. But again, I would have thought that they would have already happened. There is some additional growth opportunities in our current operating areas as well. So I think, overall, what we are encouraged by is the value proposition that the FlexRig provides is being understood more every year. And with that, I think it offers us an opportunity. Now, on the other hand, keep in mind, obviously the larger FlexRigs now are at 100% utilization. We don't have that available, FlexRig on the ground, just waiting to go. So that causes a little bit of a challenge. But new builds are obviously an opportunity as well.

Sure. But you do have some FlexRig 4's available. Do you have -- do you see opportunities for those type of rigs international markets? Number one, and number two, could you provide us with some split amongst your idle Flex 4s, what is the mix between the mobile kind and the skid type?

We do have opportunities on Flex4Ms, or Flex4s in general, but specifically on the Flex4M, there is an opportunity, another opportunity in South America that we think will present itself over the next couple of quarters. But again that's, we don't know for sure. We are not in contract negotiations or anything at that stage. But I do think there's opportunities. On the Flex4S, I had mentioned that we have seen some pickup in activity there. And I want to say just ballpark, we had about 20 Flex4S, available, and if all these contracts come through we think will, we'll end up with around 14 or so available, based on what we know today. The Flex4Ms, I don't remember the exact number that we have available, but there are some opportunities in West Texas for those. And that's really, pretty much it. There is not much availability past that.

Okay. And you mentioned that you are going to be building one per month through September. Just could you remind me how many of those are incremental to what your original plan was for construction of rigs?

Waqar, we have a cadence that takes us through April that will complete our new order book, contracted order book. And then, when we talked about one per month through September, we have announced a corresponding increase in December of our CapEx program to accommodate and position us to have a continuation of the one rig per month, as I mentioned, through September 30. So, as we go forward, and anticipate the market to continue to improve, that's something that we have to position ourselves now for. Obviously, if we would see a big pull back, or disappointment, we could do what we have always said we would do, which is put that equipment into a capital spare category. And as you remember, as we did our new builds over the last couple, three years, we purposely didn't have capital spares. And we knew that at the end of the program, we were going to have to to have some of those available. So I think it's a positive that we have that type of flexibility, to either keep on task with one rig per month, or we could pull back and again, resort to those being capital spares.

Okay. And these new builds, they are going to be FlexRig 3 types, is that right?

That's correct.

And what do you think is going to be kind of an approximate cost for these rigs?

Oh, I'm going to go back to earlier comments where we said our overall new build program had an average cost of $16 million, and I think we have seen some savings. But in fact, they are not dramatic savings available out there, even with the pull back everyone experienced over the last year. So there is some incremental savings. So maybe we have an average that is a little bit better than that. As you know, that average included both Flex4 models and Flex3 models.

Okay. Great. That is all I have. And Doug, thank you for your service to H&P, and to the industry, and in general. I understand you are retiring, so we miss you on the calls, and talking to you. Thanks.

Well Waqar Syed, thank you for those comments. You have to put up with me for one more call, though. We are having -- our next quarter's earnings release call is on April 29th, and then my retirement date is April 30. But appreciate those comments. And I'll probably have something to say then, but thanks very much.

Thanks Waqar Syed. I told Doug this morning, he had not just one more round, but two more rounds. But thanks for saying that.

Thank you.

Next to the line of Joe Hill with Tudor Pickering. Please go ahead.

Good morning, guys.

Good morning.

Doug, I just wanted to explore the tax issue a little bit. In Venezuela, I guess the SENIAT is imposing some type of asset tax on you?

No, sir. That is not what's driving this. And I can tell you, it is very, very complex. And I'm happy to give you, to a certain degree, the detail over the phone. But, as we mentioned here, in my remarks, the, it really results from the non-deductibility of the devaluation loss. And then some taxation that occurs if you have invoices that are paid in a US dollar base. So you get caught going both ways. And we are not the only ones. Other companies that are down there that get paid in some fees, and some dollars are faced with the same thing.

So what you are telling me is you are actually getting taxed on a US dollar invoice, not a US dollar payment?

That is correct. And what it is, it is a deferred tax. You don't really pay the tax until they pay you. But it is a financial tax hit, because those dollar based invoices got revalued during the devaluation.

Okay. So, no cash impact?

No, sir. That is correct.

Okay. Show I guess the question then becomes, guys, I know you have got a lot of rigs down there, 11. And they are not working, and you've got the assets in country, and you have got invoices that aren't being paid, and at least optically, you are accruing taxes for these invoices. At what point do you just say you know what, let's try and take this equipment somewhere else, and put it to work, and actually make some money with it as opposed to dealing with tax issues like this?

Well, yes, I mean, you are identifying an area where we've had a lot of hand wringing and frustration. And so it is something we have put a disproportionate amount of time and energy in. And when you think that it is less than 5% of our top line. As you have heard us talk about before, those tend to be larger rigs that happen to be very suitable to that market. And in better market climates, we bid those into other international markets, and over a period of years, it reduced our exposure down to 11 rigs in Venezuela. You know, I think what we are trying to do is position ourselves where we can go back to work.

There is going to be, notwithstanding, the turmoil down there today, there is going to be an oil patch down there and opportunities to participate in it. And so, it's hard to have just a lot of forward visibility on it. And we are going to wait and play out how this happens. In a longer-term, might those rigs find another home? Yes, we'd be very open to that happening. We are also very open to being paid, and going back to work there. So it is just, we are at a time where that's about all we know about it.

Okay. You guys have four rigs working in Colombia today, I believe?

Correct.

What are the prospects for putting another couple of rigs to work there?

Joe, there are some prospects, both on the shallow rig market, as well as the deep rig market. There is a possibility something could happen in 2010. But as I had mentioned earlier, it is kind of hard to say for sure. But we've got some great performance going on down there. A lot of people are taking note of that, so that obviously improves our chances.

Okay. And John, just to circle back to Argentina for a second, I think you got five rigs there, and a few more in country, I believe. Can you put more rigs to work in Argentina to work over the near term?

I think of those that are stacked there, is some likelihood we could put one of those rigs back to work. I'm not certain it would impact this fiscal year or not. There is some possibility. But again, those are the rigs that are stacked are large land rigs. They are good rigs, but there is not a whole lot of market there.

Alright. That does it for me. Thanks, guys.

Thanks, Joe.

We'll go next to the line of Pierre Conner with Capital One Southcoast. Please go ahead.

Good morning, gentlemen.

Hi, Pierre.

Hey, John, let me just verify on the total active FlexRig count, 42 in the spot, and 79 on the new builds under term, is that the total FlexRig active? I justify want to differentiate between you said the 79 there, the new build FlexRigs under, is that under their initial long-term contracts, or that is the total?

Yes, the 79 reference are FlexRigs under their original contract. Go ahead.

Pierre, this is Juan Pablo. I believe that we have 98 FlexRigs under term.

Got it. Yes, that is what I was looking for. So, you mentioned that leads me to the next part of it. John, there has been inquiries now from customers to go to term. Or Hans, what is your interest level in that? And does that set you up for continuing on for new build construction, if you are able to term out some of your current spot equipment?

Well, we are, of course, interested in all those conversations. And like John mentioned, we have those ongoing now. And I think as we look going forward, you have heard me say that I don't know what the market will bear, if you will, in terms of future term contracts. We are at a point in the recovery, where that's early to call. But we do like the notion of having a portfolio approach with the fleet, where we are interested in maintaining a high level of contractual coverage. And you are right, I think that would encourage us, as we see the opportunity in the future of new builds, managing those parts that would allow us to consider some new builds.

What is your take then, you all are in a great position, given that you kind of got out there first, with the new builds. But obviously this is pretty clear to everybody that's where the activity is. And that's fit for purpose, or however you want to call it. You know, what is your sense of your competitors's ability to bring new construction to market? That is a difficult one.

Well, I mentioned, Pierre, my comments, we are kind of hoping that we don't see this big ramp up and return to the frothiness we had in the spring of 2008, where it encourages all comers, if you will, to look hard at new builds. I don't think that's what is going to be served up going forward. I think we're going to be in a natural gas trading range, as I mentioned, between kind of this $4.00 and $7.00. I think that it's going to be very competitive. We have a great position with our integrated manufacturing effort, and the resultant lower cost structure. And I think too, just the highest satisfaction amongst customers of what our new builds have done and how they perform. So I think you are right, that puts us in a great position. We are not -- and we are the price leaders -- we are not at an obvious new build economic level now in terms of where day rates are. So those have to improve. And I think our peers are going to have to consider doing the outsourcing of potential new builds, that they have done in the recent past. So all of that makes us like our position.

Okay.

But it's kind of all the visibility we have on it.

No, I appreciate your perspective. Couple for John on some specifics. Interesting follow through on your prior thought that you would see some interest in the 4Ss for pad work, could you allude to where those might, I guess there are about half a dozen of them, it sounds like you might be bidding. Where would we be beginning geographically to see that type of opportunity?

Here, we've seen it in the Marcellus, additional possibilities in the Barnett, recently even in the Haynesville, and discussions in the Bakkens as well. And again, I think it kind of goes back to this general trend of more wells on a pad, less surface disturbance, fewer rig moves, requiring trucks to move from well to well. Obviously all those things have a lot of advantages in urban areas, in areas that you know, have challenges, as it relates to the topography.. So I think we are going to see more of that pad trend, toward that type of drilling.

No limitations of 4S as to drill the deeper Haynesville, or the these long lateral Bakkens without upgrades required, John?

Well, we have the 4S, and I don't know how much we have talked about it in the past. But we have a 4S, what we've called a 4S plus. There is various horsepower, hook load, upgrades, torque requirements. And those are the rigs that would be targeted for the Haynesville or the Bakken.

Got it all right all right. Just two others, number wise, on your guidance of a little bit of decline in the margins, John, sequentially, independent of whatever the activity is, are you including or excluding the cancellation payments in that comment?

That's excluding.

Excluding, got it, early termination. Got it. And then the last one on the numbers too, is this comment about selective market spot increases. Can you, I mean just give us a range, maybe percentage-wise, what kind of increases are you seeing? And I'm assuming that is pure margin, as opposed to passing through some additional costs or something?

Yes, it is a net margin improvement. And you see, we had some cost reduction. And as we alluded to in our comments, our labor rates, we don't have -- we are in a great spot being at the top of the totem pole there, too. So there won't be the give backs, Pierre, that you reference.

Okay.

And then, you know, we are obviously going to not say a whole lot about what we are seeing in spot pricing, except to say that we are the price leader. We are in, I think we have mentioned before, in this 17 plus range. We have had rates nicely above that that have been the most recent spot rates. So I think there are meaningful improvements. But I also don't want to give you the impression that those are 30% type improvements. Because it's going to be slowly earned and gained. From here, it is still a very tough market, and we didn't take the deep did I counts that we saw in the marketplace. So again, our improvements are going to be, I think, incremental, going forward. I'm trying to, as you can tell guard myself. (Laughter)

I'm staying quiet, because the more I'm getting.

Yes, I know. (Laughter)

All right. Gentlemen, thank you very much for the time, and I appreciate it. I'll turn it back.

Pierre, a quick clarification in terms of the Flex rates on term. The 98, do not include the three rigs that are generating revenue, but are delayed. So a total of 101 would be the total number.

Okay. Well, as a follow-up, if those three were to be picked up earlier than you thought, does that just move from early termination payment into revenue generating days? In other words, if they did start to work, then you could just shift that? It is no change in the impact, right? No net incremental revenue for you?

Pierre, I think there is some. But I don't know that it's --

Not meaningful?

Yes, I don't think it's going to show up.

All right. Thanks, gentlemen.

Thank you.

(Operator instructions).

We'll go next to the line of Mike Mazar with BMO Capital Markets. Please go ahead.

Hey, good morning, guys.

Good morning.

Quick question, well two questions, really. One, can you kind of remind us of your contract coverage in Mexico? In terms of what's on spot down there? And anything that's on contract, and when that might reset?

In Mexico?

Yes.

All of our, the six rigs in Mexico are all on term contract.

Okay, and when are those up?

They were initially multi-year contracts. So we've got another, in average, probably what, 18, 20 months left.

Okay. Great. And secondly, just shifting gears, can you give us a bit of an update on where you are at and what progress has been made with the directional business?

Well, that's our TerraVici investment. And I think we might have said on our last call, that we continue to be in a testing mode, and I think we are encouraged that we are getting closer to commercialization. It's been moved to the right, from our original plans, Mike. And part of that is because the testing regimen that we had planned for, and I think had secured, when the down turn occurred, it pushed all that back. And people, of course, were scrambling. So that's made our progress so much slower in that regard. But I think we are, besides that delay, I think we are pretty pleased with where we are right now.

That's great. Thanks, guys.

Thank you.

And we'll take our next question from the line of Matt Beeby with Morgan Keegan. Please go ahead.

Thank you, good morning.

Morning.

In the offshore segment that you talked about, having 20 rigs working now, and 11 more out idle in Venezuela, could you remind us where those eight other idle rigs are?

You are referencing international? You said offshore.

I apologize. Yes. International, I'm sorry.

There is 11 rigs idle in Venezuela, and we've talked about that. There is four in Argentina, and two in Colombia.

And one in Tunisia

The one in Tunisia is working, and one in Tunisia is currently stacked.

Okay, and I think you guys also mentioned you expect margins to be lower by about 30% in that segment. Can you kind of clarify the cost side? And then also the revenue side of that?

Matt, this is Juan Pablo. There is, as usual in the international segment, a lot of moving parts. But what we'll see is probably a decline in both revenue per day and expense per day. And the margin per day will also go down as we said, primarily because of the project in Africa, not impacting the second fiscal quarter as it did favorably impact the first fiscal quarter. So we expect that daily rig margin to go down by up to 30%.

Most of that sounds like it that is probably on the revenue side?

Yes.

Okay. Thank you, guys.

Thank you.

And we'll move next to the line of Robin Shoemaker with Citi. Please go ahead.

Thank you, and good morning. I just was wondering if you could shed a little light on the differential recovery in various shale plays. And particularly with regard to the Barnett, the Piceance, and perhaps a couple other basins, where the recovery has been so slow, even as the major shale plays have rebounded strongly. In terms of your inquiry level, discussions you are having maybe post winter season, do you see a recovery in some of those lagging shale plays?

Yes, and John can comment more. I think we do. I think that we have customers in both of those plays that have lots more locations in front of them, and have plans to engage that work. So, part of that, I think too, has been strengthened by the winter prices that we have seen. So I would expect, your observation is a good one. I would expect to see those basins that might have lagged up to date, would be more engaged as we go through the year.

Robin, I think part of the situation in the Barnett, with some slower recovery, is because there was a large number of wells that were drilled, but were uncompleted. There was a large inventory of those wells and those wells are now being completed. And I don't know of those, what percentage have been completed now, but I get the impression that it is quite a large number. We are starting to see the activity pick up in the Barnett. And I believe it is somewhat of a similar situation in the Piceance, that there were a lot of wells drilled, uncompleted, in some cases, pipelines weren't even built. So I think that's part of the delay, plus I think the economics, particularly in the Piceance and a lot of the areas aren't as strong strong in some of the shale plays.

I'm sure you heard Haliburton's comments that they thought a lot of the drilled but uncompleted wells, the backlog had been worked off in the fourth quarter, and most of the rest had been in the first quarter?

Yes, I saw that as well. And I had heard that from some other sources as well. So it makes sense, that that's going on.

Great. Let me ask one other broad question. In terms of the international shale plays we are hearing about, including in Canada, and other markets in the eastern hemisphere, how much of a dialogue do you have going with some operators, that perhaps you have not worked with previously, that are planning to test potential of shale plays in that, in those markets, and who might draw on your expertise?

As I think about the people that we are talking with, most of them are current customers, and have been long-term customers. And there are a few that are European companies, that have recently bought into and in some form or fashion, JVs or otherwise in the US. And they are beginning to see the capability of the FlexRigs, which is encouraging. And so, yes, I think from the standpoint of some of these international companies, getting experience in the US with the current shale plays, and then taking that and using that experience internationally makes sense. And it would be a logical extension to think they would do the same thing with the FlexRig.

Okay. So this is, from, in terms of any meaningful opportunity for Helmerich & Payne, is it a couple of years away or perhaps sooner?

I think it is going to be a longer-term. I mean you I have heard about various countries. But I think they are in really early stages of that. And each country is going to have its own laws that dictate the ability to bring in an outside rig, and what is the rig availability and the productivity possibilities. I think it's going to take a little bit of time to point out, that you know what sure, sure we are drilling these wells, but we are not able to get the laterals we need. These wells are taking twice as long as they should, and I think it takes that in order to really drive someone high enough in the food chain, to say we've got to have better technology.

Right.

That's one possible scenario. I do think there are companies that know enough about it, and about the potential to be able to accomplish that early on in the project. That is, of course, what our hope is. Based on what I said earlier about our international experience, I mean, we have had great performance with FlexRigs in every country we've worked in. And yet, it takes a long time to get the technology in the country in a lot of cases.

Right. Thank you.

Thank you.

And our next question will come from the line of Dave WIlson from Howard Weil. Please go ahead.

Good morning, guys. Hans, a quick macro question going back to some of your earlier comments. How concerned are you for the spot market for the second half of the year, such that with the increase in the rig count that we have seen here lately, that we drill ourselves into another over-supplied situation come injection season? And I guess the follow-up to that, on a more micro level. How does that effect your thinking in the 70 or so rigs you have in the spot market, to contract those up on some shorter term, maybe a year or so, even though the pricing might not be as optimal as you would like?

Yes, that is a good question. I think people have been a little befuddled by just the monthly 914 data, and where that goes. And we have had nice draws, and so, part of that has to be sorted out as we go forward. I don't think we'll necessarily find ourselves back in a 1500 plus rig count. Or I think that will take long enough. So it is hard for me to guess what that impact has on some of your questions. You have heard us talk about a bifurcated market. And I think we are seeing that now. And we are seeing the rigs that have the performance and efficiency characteristics be engaged. And we are finding that to be true on our account. I'm assuming it's happening with our peers as well.

So, when you look at the number of AC drive rigs in the marketplace, and the small percentage, that is 14% of the available industry fleet. I still feel pretty good that the customers are going to keep those rigs engaged, that they are going to keep them on task. It's hard to know the big question is, is there pricing contamination that kind of goes through even the lower performing rigs? We are not really seeing that. We really are seeing a distinct bifurcation. And when I say bifurcation, it is not necessarily just a bright line between two halves. I mean, there are some refurbished SCR type rigs that will compete. Having said that, we take market away from those guys. But clearly, the customer is going to leave a lot of pressure and idle capacity on the low end, and is going to keep the high-end of the industry fleet engaged.

So, I mentioned earlier we are very open in talking about longer term contracts. In the past, we have wanted a percentage of the fleet exposed to spot, that was also while we were much more engaged in a robust building effort. So now, that kind of takes on a new look, and will be open to various contracting, based on what the customer's interests are. So I know that is not a lot of clarity. But I think we also see the pressure, now, that we are seeing the high-end fleet engaged, there is going to be some pricing pressure. So we don't want to get too far ahead of ourselves, contracting that, so that's just kind of our thinking around here.

Okay great, thanks. That's it for me.

(Operator instructions)

We'll go now to the line of Angie Sedita with UBS. Please go ahead.

Great. Thank you. Good quarter, guys.

Thanks, Angie.

I know you don't want to give too much specifics on day rates, but just to touch on that a bit, is the competition following you up? And I would assume day rate increases are more in the $1500 range versus the two to three range?

The first part of that, yes. We want them to follow us up. And I think, yes, it's on the lower end of that range. I mean, I think it's kind of incremental, it's an incremental march right now. We are not seeing, which is a good thing. I mean we, like I said, no want to see this huge ramp up.

Considering there is only so many high spec rigs that are designed -- or well-designed for these types of plays, do you think that, if you see the rig count continue to slowly march ahead as we go into February, that you could again be pushing rates early or mid February?

Well, our appetite will be to continue to see rates improve. And so I think what we are going to do, on our spot pricing, is we are in conversations today, Angie. And I think we'll see how those play out. And then kind of watch the market, as we head into the late spring, and see where we are there.

Okay. And then you said you had some interest in for term on the FlexRigs. And it sounded as if you were speaking in regards to existing FlexRigs. And if that is the case, or it's the new ones. But is it rates, and terms that are acceptable to?

Yes, we are very focused on that and I mean, that will be, of course, a big driver. And I think what we are trying to, and I'm probably not being very clear on it. But I think we have, as we mentioned, over 100 rigs on contract today. We've got, Juan Pablo, what? 34 of those rolling off during 2010? So we have this kind of constant churn and moving part. We'd like to see a portion of those go back into some kind of contractive status. It's nice having the quality of FlexRig, because those fare very well on the spot market. And so, it's just a matter of trying to manage through where those opportunities are.

I will say this, Angie. In contrast to other cycles, we are having more customer interest, in term contracts on their side, than you typically see in an early cycle recovery. And I think that's a good thing. It's always been a little frustrate for us that, that long-term commitments often times weren't made until the latter stage of where the cycle was. So, I think that's a positive thing. And I also think it reflects their being cognizant of their own rig rosters and wanting to have the quality rigs in place and secured. So all of these things, I think, are indicative of some positive signs in the cycle at this stage.

That is certainly very positive and noteworthy. And then the last question is, obviously you are, and others including myself, are little bit uncertain about the gas production profile, and the gas outlook for the back half of 2010. But as far as your customers, do they seem nervous regarding gas production, watching the numbers carefully? Are they confident, kind of what is the tone, particularly in those in unconventional plays on their skittishness in regarding gas or their conviction regarding drilling and continuing their drilling activities?

Well, as you remember, some of the first improvement came on the oil side of the drilling with oil prices being improved. But then we saw a movement back into the field with customers, really prior to some of the improved gas prices we are seeing today. So I've got to think now that those are in place, and some of those folks have hedged up again. I think they saw 2010 as being a time when they were going to re-engage, and put their field operations back to work, and then see what happens. So what we would anticipate is, and we have seen it in the last 12 months, there is flexibility for them to pull back, and to kind of play where -- what the market serves up. And we would expect everybody to be doing that in a thoughtful way, and kind of see where they are in the summer time, and how aggressive they are going to be with their CapEx commitments.

And those could either go up from what's been talked about, or I'm sure they could go down. That's kind of what we were trying to communicate earlier, when we say, we see choppiness ahead. I think it is an interesting up turn in that we are encouraged today, but there is some uncertainties that don't always accompany this early cycle time. Usually you have a little better certainty and overall upbeat mood. And so I think people are going to be careful, and play what is served up to them.

Great. Thank you very much, Hans.

Thanks, Angie.

Next to the line of John Tasdemir with Canaccord Adams. Please go ahead.

Yes. Thanks, guys for squeezing me in. Just a question on, I hate to go back to the contract issues and how those are forming. But I got this sense from listening to you guys that -- and looking activity (inaudible) in the Marcellus and plays like that have just skyrocketed, And I can imagine that a lot of guys want rigs to go to work there. And as you get tapped out of the high performance rigs that are available in the fleet, I'm wondering if these negotiations are getting, I guess, a little more unique in the sense that -- am I stretching to think that there is the potential for guys to say, look, we don't want to necessarily give you a four year contract because we are still feeling out the gas market, but we'd like a rig. Is there a potential that you get kind of a premium day rate for shorter term contracts, than maybe what you see in the past?

Well, I think your instincts are right in that the customer is very aware of the scarcity now of the higher performing rigs. And they also know that, hey, we have had these two book ends. One of the heated market we saw in the spring and summer of 2008, and then the thing totally fall off a cliff in early 2009. But I think they would predict, none of those, two extremes are probably in the offing. So I'm going to go back to work, I'm going to have a certain rig roster. I want that rig roster to be the highest performing, higher end rigs I can secure. And I think they see the trend line would suggest this is a good time to be making those arrangements. The longer they wait, the prices are going to go up from here, not down. And I also think it just plays into conversations we are having as well, where customers realize, and are willing to talk about the potential of new builds, and just what that availability, and what those rates would be. So all those things are dynamic, and kind of happening now. But I think your intuition is right.

So potentially maybe you guys are unique in that you have the ability to do it. But I'm stretching to say you might get a better day rate or margin, on a shorter term contract than maybe what you saw on a three or four year take or pay, that is something you guys might be willing to do?

Well that is why we kind of talked about it as being a portfolio approach. And we have seen over the years, we are not smart enough to pick highs and lows in the cycle. And so we do want to lever off of what you just said. We have the higher performing rigs that are going to be in demand. And so we don't want to necessarily book all of those, just at the first signs of market encouragement. So we will look at it as an allocation kind of portfolio management model. And then just say, well, let's have some dry powder. But at the same time, we've got rigs rolling off of previous contracts and let's find a home for some of those. So I don't want to over dignify with a lot of implied science, but we are trying to be careful in how we manage that going forward.

Okay. Thanks, guys.

And we'll go next to the line of Jim Crandell with Barclays Capital. Please go ahead.

Good morning.

Hi, Jim.

Hi, Jim.

Hans, I was just maybe I'm asking you to do -- maybe explain it a different way which you already answered one question. But have you done, has the Company done any work itself on the levels of rigs, given the current mix necessary to replace production? If production is in fact growing, at the current rate count, given all the LNG that is coming in, I mean what levels of gas prices do you think that we still, that we would see still see increases in the business? For example, if gas prices were four for the next couple years, and the forward curve was five, would activity in the eight basins that you cited for unconventional resources, still rise under that scenario?

Yes, that is a great question. We're looking at that. We have done some internal work on it. And you've, I know studied the whole notion of it. What level do each of these plays become economic? And what is sustainable? And with the number of potential wells and acreage what might play out. So, I think we do see where the eight unconventional plays that we have talked about, they are going to have a level of activity absent prices really falling off significantly, and we would expect to be very involved in those. Does that say that you need more high efficiency rigs in a moderate $4 gas price? Clearly, Jim, the rigs are more efficient. The wells are sometimes three, five, ten times more productive. So, that math all suggests that you need fewer rigs. But today, we find ourselves with a scarcity of those same rigs. So, Juan Pablo might want to jump in. And he's done the majority of this work, but I think we are trying to feel our way forward on that.

Jim, I wouldn't have much to add on that. It will certainly depend on the variables that Hans mentioned, and what level of productivity per wells numbers we see going forward. There is a lot of questions about what may happen to productivity in the future. So, a lot of uncertainty.

Jim, I think just to add, and you are familiar with this, and you have heard us talk about it a lot. I think the point is you have I think the point is you have 60% of today's fleet that has been carried year after year, and cycle after cycle. And I think the customer and others are realizing that is not a suitable tool for the work ahead. So they are beginning to focus on what is available? What is suitable? What does the future look like? It is going to put, we believe, real pressure we believe on the lower end of the industry going forward. And it is going to provide opportunity to those folks that have leadership, and have good position for what the future work's going to require, and the type of tool set that is going to ploy.

That is a good answer. And two quick ones, Hans or John. In terms of the day rate you would need on a Flex3, to build the new contract, can you compare that with what you were getting a year ago, when you were getting three-year contracts for the Flex3?

Well, maybe the best way to answer it, and my guys are signaling me to say less than more. But Jim, we were very forthright with here's our business model on the buildout that we did. And we talked about ROIC, and three-year term minimums, and a lot of this. And I think we are at the point in the cycle where we know customers are interested in additional opportunities for new builds. I don't think we are at the place now, where we can engage that, but things are able to move.

But I guess part of what I would tell you is, we are very focused on having acceptable returns over our cost to capital. And we are very focused on being able to exploit the strengths we believe we have in this opportunity. But we are going to say less, at least in this stage, than more. Because what we saw in the past, as it just became such a clear marker for our competitors to try to go compete with us with. So, again, as things develop and go forward, we'll continue to say as much as we can, but probably not give the same type of clarity to what we did in the past.

Okay, and last question. If you took the eight major shale plays, which of those eight plays would you say are the FlexRig4s ideally suited for, which are they well-suited for in certain parts of the play, and where are they not suited for at all?

Well, Jim, the, as you know the Flex4s were designed to capture a shallower depth segment.

Okay.

We targeted Flex3s, and 2s primarily and an 8,000 to 18,000 foot depth range. And in fact, we are taking those rigs to as deep as 20,000 and 21,000 feet today. So the Flex4 was really designed to capture a shallower segment. It was more of a 4,000 or 5,000 or 6000-foot range up to in some cases 14,000. The 4S as I said earlier going to be more suited to the Barnett. It will be able to handle some of the shallower Haynesville wells, because we have a Flex4 doing some of that shallower work, shallower meaning in the 14,000, 15,000-foot depth range. And the Flex3 is really a rig that will, is working in all of those plays, with the exception of the Fayetteville. In fact, we don't have any rigs running in the Fayetteville today.

Would you expect to see, in a healthy market, where you are building new rigs, would you expect to see FlexRig4 utilization get up toward full utilization? Or given the characteristics of the rig, is that is too much to expect?

No, I think it's, I can't speak to the timing, but if you look at it, a large portion of those Flex4Ss were in the Piceance. And as I said before, the Piceance has been one of those slower to start back up. Primarily, I think again there were a lot of excess wells not drilled, not completed. And then on the economic side, some of those rigs are going back to work. and we are looking at some of those rigs being mobilized out of. In fact we already have mobilized some of those rigs out to places like the Marcellus. And I think it is possible we could mobilize those into the Barnett and other areas. It's one of the great things about rigs is they are mobile and we can move them around to where the demand is. No, I would expect those rigs will go back to work. I just can't speak to when. Because again, as this process continues on, depending on what the planned is, you could even see some of those rigs, the Flex4Ss, for example, drilling single well pads in some applications. And then maybe it goes and drills some pad work. There is an application, I think they will eventually go back to work.

Okay that does it for me. Thank you.

Thanks, Jim.

Shannon, we'll probably justify take one more, if there is any that would like to have another question. Certainly. We'll take our last question from the line of John Daniel with Simmons & Co. Please go ahead.

Thanks, guys for getting me in. Just two questions for you. Given that you are seeing the bifurcation in the drilling market, how actively are you pushing the conventional rigs at this point? And should we expect to see more asset sales going forward?

Well, John, again, it's not so much what we are pushing. It's what the customer is demanding and what the customer wants. And clearly, conventional rigs are really not the rig of choice. Now, on the other hand, part of our conventional fleet is 2000 and 3000 horsepower rigs. And when that deep gas market comes back and those conventional plays, then those rigs will go back to work. Those are quality rigs. So I'm not concerned about those. I think it's the rigs that are 1500-horsepower and less, unless it's again, a deep job that is more of a conventional-based application, it's going to be a challenge to put those rigs to work today. But as we have all seen, through the cycles, when activity gets to a high level, and the rig of choice isn't available, and a well has to be drilled, then those rigs will potentially go back to work. But I don't see that happening anytime soon.

Okay. And then just a quick housekeeping. This one's for Doug. Any guidance with respect to depreciation? Looked like it came down quarter-over-quarter.

I'll let Juan Pablo answer that.

John, I think it remains at around $260 million. For the year.

260? Okay. All right. Thanks, guys.

Thank you. Thanks, John. Thank you, and thank you, Shannon. And thanks, everyone, for joining us today. Our second quarter conference call will be April 29th. Thanks for joining us and have a good day.

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