Helmerich and Payne Inc (HP) 2009 Q2 法說會逐字稿

Welcome to today's program. It is now my pleasure to turn today's program over to Doug Fears, Vice President and CFO of Helmerich and Payne. Please go ahead, sir.

Thank you, Katie, and good morning, everyone. Welcome to Helmerich & Payne's conference call and webcast to discuss the Company's second quarter earnings. With us today are Hans Helmerich, President and CEO; Executive Vice President, John Lindsey and Alan Orr, and Juan Pablo Tardio, Director of Investor Relations. As you know, much of the information provided today involves risk and uncertainties that could significantly impact expected results and that are discussed in our most recent 10-K. We will also be making references to certain non-GAAP financial measures such as segment operating income and operating statistics. You may find GAAP reconciliation comments and calculations on the last page of today's press release.

Today, Helmerich & Payne reported net income of $103.7 million or $0.98 per diluted share from operating revenues of just over $520 million for its second quarter fiscal quarter ended March 31, 2009. This compares with net income of slightly over $102 million or $0.96 per diluted share from operating revenues of over $473 million during last year's second fiscal quarter. Included in second quarter net income for 2009 and 2008 were $0.0 1 and $0.04 respectively of after tax gains from the sale of portfolio securities and drilling equipment. Also included in this year's second quarter income is approximately $0.47 per share after tax from the early termination of contracts relating to new build FlexRigs. As mentioned in the press release, total pre-tax early termination revenue for the second quarter totaled approximately $81 million. Hans and John will have more to say about these early terminating contracts in a few moments.

This morning we released specific information regarding our accounts receivable position in Venezuela, which I'll discuss in just a moment. First of all, let me provide some comments to put this issue in perspective. For fiscal year ended September 30, 2008, our Venezuela operations represented 8.2% of total operating revenue, less than 3% of our long-lived assets and less than 5% of our rig fleet. We have worked for over 50 years in Venezuela and have helped with extended receivables for most of that time. Our longer term experience with (inaudible) is that while they often have been slow to pay, they have always paid us the full amount of our billings.

Other than observing the delay in payments that all oil service companies seem to be experiencing at this time, we have not had any communication from (inaudible) that has given us any indication of nonpayment, nor have we received any indication that only a partial payment should be expected. We simply do not have enough information to convince us that our remaining receivable balances are not probable of collection. Those facts and circumstances, along with the recent collection of approximately $8 million from (inaudible) resulted in our decision not to take any reserve against our receivable balance but not to record revenue as of the beginning of the second fiscal quarter ending March 31. Our decision not to record second quarter revenue was primarily due to the uncertainty of the timing of the collections. Of course, we were to record revenue if and when the cash is collected.

Not recognizing revenue in our Venezuela operations had a negative pre-tax impact of approximately $35.6 million for this second fiscal quarter in the revenue section, and was the reason we recorded an operating loss of $15.3 million in our international land rig (inaudible). The after tax per share impact was approximately $0.31 per share for the second quarter.

As mentioned in today's press release, the total invoiced amount in Venezuela that remains unpaid as of and through today is approximately $116 million. That is made up of approximately $50 million of unrecognized revenue and other billings such as unreimbursable taxes that are not revenue items and approximately $66 million of book accounts receivable balances remaining for Venezuela operations. Recall now that the March quarter for international operations runs from December 1 to February 28, one month ahead of our domestic accounting months. So the last month we booked revenue in Venezuela for accounting purposes was November 2008.

Concerning taxes, the fact that we did not recognize revenue in Venezuela moved our corporate effective tax rate up sharply to 45.6% for the second quarter. Our estimated effective rate for the remainder of the year is 40.8%. The reason for the increase is that Venezuela taxes are computed based on accrual revenue recognition regardless of the Company's decision to go cash basis revenue recognition for US accounting purposes. So while revenue was not recorded for GAAP purposes in the US, we booked taxes for GAAP purposes as if they had been recorded.

Operationally, in Venezuela we now have seven rigs that have either been stacked or are in the process of rigging down and being stacked and four rigs that continue to work with completion of their respective wells anticipated within the next four months. In the meantime, we intend to continue our communications with (inaudible) and hope that we can work something out to amicably resolve these issues.

As of the end of the quarter on March 31 the Company had total debt of $560 million our ratio of 18.3% debt to total cap. At that time we had $126 million of cash on hand and available borrowing capacity from our bank credit facility of $120 million. Our internal earnings in cash flow projections which includes significant benefits from bonus tax depreciation show us to have adequate liquidity given our current capital structure. We continue to estimate 2009 capital expenditures to be $850 million.

Beginning in early 2010 the Company is predict generate significant pre cash flow as a result of continued revenue and income from our long-term contract at FlexRigs and a much smaller capital expenditure estimate for this year. The market value of the Company's stockholdings at Schlumberger and Atwood today is approximately $230 million pre-tax and $160 million after tax.

Until this month, Atwood Oceanics has been accounted for as an equity affiliate because we have held two Board seats and were deemed for accounting purposes to have significant influence. We now hold only one Board seat. We have not sold any of Atwood position recently, so our ownership remains at 12.5%. Therefore, effective April 1, we will account for Atwood at fair value as we do our Schlumberger holding and we will no longer record our portion of Atwood's income on our income statement. I will now like to turn the call over to Hans Helmerich, President and CEO. After Hans and John have made their comments, we will open the call for questions. Hans.

Thanks, Doug. Good morning, everyone. At the time of our last conference call, the industry was well into a precipitous down turn. We said then things could get worse before they got better. Today we will be discussing the falling knife effect still occurring in the domestic rig business and considering if the knife is still falling, is the fall at least slowing down? Well, there is simply not enough clarity from our conversations with customers to call a bottom. We know others have predicted a bottom to occur some time during the quarter. And while we hope it does, we believe E&P operators are still are waiting to see how commodity prices behave in the near term. Their concerns are many. Let me discuss some now.

What level of L&G shipments will land in the US? Will demand destruction, the worst level seen in over 35 years, begin to flatten and improve? How will natural gas prices, already down 40% since the first of the year, respond to growing inventory levels and increasing potential of unconventional gas supplies? Will policy makers in Washington, D.C. view this new domestic supply potential as a Godsend or will they pursue punitive tax changes such as eliminating intangible drilling costs? And, finally, when will rig count reductions meaningfully impact production numbers?

These uncertainties have resulted in the worst cyclical downturn since the early 80s as the industry rig count has fallen by more than half in response to spending reductions. We have been surprised by the impact on our own activity levels. We have received early terminations, as Doug mentioned on 35 rigs with long-term contracts, that have been active since 2006 or 2007 and experienced a very quick decline in our spot market fleet. Today, slightly more than 50% of our US rigs are active. Because our results this quarter were significantly impacted by these early termination payments, let me just make a few comments regarding them.

First, our intent is to provide the clarity that allows you to get your arms around the numbers related to our ongoing business separate from the early term payments. At the same time, we want to remind everyone that these monies we would have earned, in fact we would have preferred to earn out in the field because it would have allowed us to keep our people intact and fully engaged. As it happened, these payments accomplished what they were intended to, provide the customer the flexibility to change course, at the same time mitigating the risk of a massive capital commitment. We made an industry leading effort to satisfy our customers's demand for purpose-built high efficiency rigs.

Some have asked why would we continue to build rigs at the same time we have rigs being idle? Well, simply put, when we sold an available slot in our production effort, we were fully committed to fabrication costs and equipment kit orders at that time. To their credit, our customers have honored their obligations and we have benefited to some extent from the hedge, if you will, against the hard reality our industry is experiencing now. In fact, we entered this downturn with the most contractual coverage in our Company's history and we believe we had the best position in that regard in the land drilling industry. Customers have told us their decision to terminate was not based on performance or rig preference, but reflected their determination to manage spending within their declining cash flows. It follows that uncontracted rigs are usually the first to go. Then, rigs under term contracts are considered as a trade-off between the costs of cancellation and the total well costs of keeping that rig active.

For example, if the rig expense represents approximately 30% of the oil and well costs, then the costs of cancellation is measured against the potential of the overall savings of reducing the well count. Also, rigs with relatively less remaining term are less expensive to cancel. So, on average, our terminated rigs had completed over 70% of their corresponding term. The pace of terminations has noticeably slowed down. When we updated investors a month ago, the number was 31 where as today the total stands at 35. Even after factoring in this total, approximately 42% and 37% of the segment's potential revenue days corresponding to the second half of fiscal 2009 and all of 2010 respectively are already contracted at attractive day rates.

We are confident that our Company will emerge from this downturn both leaner and better positions to seize the opportunities that will come with the inevitable resurgence of our industry not only in the United States, but in international markets as well. Our fleet, comprises nearly one-half of the advanced technology rigs in the United States and, more importantly, we have an organization and an infrastructure to effectively support and operate these rigs. We continue to believe that technology, efficiency and value will return to the forefront of our customers' demands during the next up cycle. With that, I'm going to ask John Lindsey to make some comments.

Good morning. Our activity levels today reflect best in class performing spot market and term contract rigs being stacked during 2009. This trend has slowed, but we believe the scenario will continue until operators gain confidence gas and oil prices to stabilize economically viable levels. As a result, we are staying activity decline in all three operating segments as US land, offshore, and international and the following comments will analyze each of these segments.

In our US land segment, as of today, 104 of 205 existing US land rigs are active. Only 17 of the 104 active rigs are currently operating in the spot market, including 14 FlexRigs. The remaining 87 active rigs, including 80 new builds are under term contracts. Of the 80 new builds that remain under term contracts, 71 are operating, 7 are on reduced standby rates and 2 are in transition to their first location. The 101 rigs that are idle include 34 mobile and conventional rigs and 67 flex rigs, 34 of which are early terminated new builds.

We averaged 139.2 active rigs during the first fiscal quarter as compared to 177.4 during the previous previous quarter. On average,53.6 rigs were idle during the second fiscal quarter as compared to 10.1 idle rigs during the previous quarter. The total income related to early contract terminations now includes about $100 million already incurred during the first two quarters of this fiscal year and the $75 million estimated to be incurred going forward. The Company estimates that almost 60%, or approximately $100 million, of this total was originally expected to be incurred during fiscal 2009 regardless of early terminations.

Excluding the impact of early terminations for the second fiscal quarter, average rig revenue per day decreased by $1,060 to $24,876, average rig margin per day decreased by $808 to $12,898 and average rig expenses per day decreased by $252 to $11,978. We continue to focus efforts in the field as well as the back office on cost discipline. From a concerted effort with our supply chain management group to stacking rigs properly, utilizing best practices with our maintenance group and managing our personnel in efficient ways, we are hopeful to be able to control our costs.

Looking at rates, since the peak last fall average spot pricing for H&P rigs in the spot market has declined by approximately 30%. Currently, the H&P day rate average for rigs in the spot market is approximately 27% lower than at H&P day rate average for rigs under term contracts. The average revenue per day for rigs under term contract is expected to slightly decline but remain in the mid 20s. Standby and reduced rates are expected to unfavorably impact the average by approximately $1000 a day as compared to the prior quarter.

Opportunities to put rigs back to work for our existing customer base in the spot market have been nonexistent as they continue to shed rigs. New opportunities have been few, but we have been successful in contracting flex rigs in the spot market to a half dozen brand new FlexRig customers since the last earnings call. We believe that when the market further improves and existing customers and new customers begin to actively look for rigs to high grade their fleets, H&P FlexRigs will be among the first to go back to work.

We were recently successful in signing the contract for our first FlexRig in the Marcellus Shale in Pennsylvania. This contract was also with a new customer. As we have in other unconventional plays, we believe our rig technology, the best personnel, safety performance and drilling efficiencies will allow us to grow our foot present in the Marcellus as operators delineate and develop a play.

Offshore in our last call we commented on seeing the first signs of softening activity in our offshore platform business that would affect the third quarter and, as expected, three of the nine rigs have been given a release notification. One is currently demobilizing from location, the second will begin demobilization soon and the third is expected to be released by the end of the quarter. In addition, four of the six remaining active rigs are expected to be operating at reduced standby or move rates during portions of the third quarter. Consequently, the average daily rig margin for the third fiscal quarter sequentially declined by over 30% quarter to quarter.

In our international segment, operating statistics provided in our earnings release were significantly impacted by the Company's decision not to record $35.6 million in revenue from Venezuela during the quarter. This decision impacted this segments average rig revenue per day by $16,760 from potentially $40,157 to $23,397. In parallel, the segments average rig margin per date for the quarter was $10,848 before the adjustment was reduced to a loss of $40,086 per day.

Average international operating activity declined from 26.2 rigs during the first quarter to 22.8 rigs during the second quarter. Eleven of the company's international land rigs are now idle, including five in Venezuela, four in Argentina, one in Colombia and, more recently, one in Tunisia. The idle rig in Tunisia was under a term contract and is expected to continue to generate monthly income through the end of the fiscal year. Four additional rigs are expected to become idle during the current quarter, all of which are in Venezuela and two of which are currently in the process of rigging down. Thus, we would not be surprised to experience a 25% to 30% quarter to quarter decline in average activity days as we transition into the third fiscal quarter.

Today, four of the seven previously announced new FlexRigs with long-term contracts are operating and delivering remarkable field performance in Colombia and Argentina. Two of the remaining three are scheduled to begin operations during the third fiscal quarter in Argentina, and the last one may be directed to a different international destination. Going into the third fiscal quarter, reported average margins per day may sequentially improve, but still remain negative given additional expected unrecorded revenue during the quarter in Venezuela.

One of the bright spots in our Latin America operation is the performance of the first FlexRigs working today in Colombia and Argentina. The rigs have set most if not all of the existing field records in a short time in operation and in some areas have already reduced full cycle well times by as much as 50% compared to the competition. We are hopeful this performance will lead to expansion when commodity prices stabilize.

In closing, we believe H&P is well positioned for the long-term both in the US and international markets with over 80% of our total fleet consisting of FlexRigs. Short-term there remains much uncertainty with natural gas prices and it's hard to predict when activity will improve. We do expect customers to continue to drill unconventional wells with demanding well profiles that require the best technology rigs to drill and that gives H&P an advantage in the short and long-term. We are encouraged by our ability to attract new customers to FlexRig performance in the H&P brand. When the markets do stabilize and operators begin to high grade their fleets, stacked FlexRigs should be among the first to go back to work. I'll turn the call back over to Doug.

Thanks, John. We'd now like to open the call to questions.

(Operator instructions). Our first question from the Mark Brown of Pritchard Capital. Please go ahead. Your line is open.

Hi. Can you clarify the point on the tax? What is driving up your effective tax rate related to how you account for revenues in Venezuela?

Yes. This is Doug. In Venezuela, regardless of what you do on your US books, you are required to book revenues if you are billing them. You are going to do it on an accrual basis. You cannot just arbitrarily switch over to a cash basis and, therefore, report negative income or lower income for tax purposes in Venezuela. They are going to make you pay taxes on accrued revenue. So, with that in mind, even though for accounting purposes here in the US, we are not recording revenue, there is still a tax liability that's accruing in Venezuela which we then must book for US purposes. So at the end of the day, at the US analyst, you don't have the income but you have got to pay the taxes. So that is what drove up the effective rate.

Okay. For the rigs in that country, do you have any insurance on them? Or if, what are your plans potentially to move them somewhere else? Or any resale value on those rigs?

First of all, we cannot comment on the insurance issues. Can't do that. At this particular time, we are stacking rigs but have no plans to move at this time. We are still in hopes of working that situation out in Venezuela.

Okay. All right. Thank you very much.

Thank you.

Our next question will come from the line of Pierre Conner with Capital One. Please go ahead. Your line is open.

Good morning, everybody. First, John of color guidance on a number of items, I wanted to try to push a little bit more on the costs, the daily operating costs side on the clean basis absent standby. Can you, how much can you work those costs down? Are they going to be fairly sticky? Give us some sequential perspective of where the daily operating cost on US land can go.

Well, Pierre, you said it. There is a lot of moving parts. When you are stacking rigs you have stack costs. You have got the personnel side, so I tried to address it in the -- in my comments. There are some efforts, I believe, on the supply chain side that are helping us. As you would expect, pricing is coming down on certain maintenance and supply items. That's helpful but at the same time you have got these other moving parts and pieces related to stacking rigs. And so that's the challenging part. We are hopeful that we are going to be able to and be successful to get the cost per day down. We did have a reduction in our labor costs, if you recall, we talked about that in our last, I think we talk about that in our last call. That was effective going back to our previous September 30 wages.

Right.

So that you know that obviously had an effect in this quarter. So it's really hard to say. What I can tell saw that we have got a lot of effort going on. We have got a lot of both in the back office as well as the guys on the rig and focusing on that. So, again, we are hopeful that we can, at minimum, keep it flat and hopefully drive it down some.

A couple of other things. Going to this go back to the tax question and I understand mechanics there. But as you idle additional rigs in Venezuela and don't record any revenues, cash or otherwise, should the tax rate then in the out quarters begin to fall in the fourth quarter or going into next year? I mean you said for the remainder of the year.

Right. No, good question. Of course the 40.8 is an estimate for the remainder of the year and for the entire year when you mix it all together. But you are correct. I guess another way to say that is, the less revenue that is generated but not booked will be -- means a better effective tax rate. So as the answer is yes, as you stack rigs and have less activity, generated non-book revenue for US tax purposes for US GAAP purposes you are better off. So you are correct. It should come down in 2010.

Okay. Going to the CapEx question free cash flow 2010, significant improvement in free cash flow, so maybe the way to ask is what is a maintenance CapEx on the fleet and obviously it varies on how much is active. This kind of level how low could that CapEx be?

Hi. This is Juan Pablo. We could go as low as $100 million or so.

You don't have a budget for 2010 yet but is that kind of directionally where you are headed or you are just going to have to minimum?

Just the minimum.

Okay and then, one last back to John. I'm not sure you are watching every day, but are you the most active US land driller yet? How close?

Oh, gosh. Seems like a small consolation. It really does.

It is awful close. You sort of gained and you mentioned the Marcellus contract there, but what do you think about your position in Haynesville and some of the higher horsepower equipment. What do you think H&P needs to do to grow some share there or are you comfortable with where you are?

Well, we have had a late start into the Haynesville. When the play really started taking off, all of our rigs were committed and our new build schedule was out there. The good news is a lot of the new builds we are delivering now are, in fact, going to the Haynesville. The timing on that is good. We are going to continue to capture some market share there.

Once we continue to, kind of say this over the past several months, once operators do get into that mode of high grading and going putting rigs back to work, I mean the flex three is the perfect fit for the Haynesville. It not only has the horsepower and obviously AC drive and all the features and advantages we have, but the rig also moves very quickly. And when you compare the FlexRig move times to the competitor move times, in a lot of cases we are moving the rig twice as fast as they are. Well today, I don't know what the average Haynesville well takes. I have seen 45, I have seen 55. I really don't know for sure what it is. But make no mistake, we'll get those days now. When those days get into the 30s and the high 20s, then the rig move time is even that much more important. So I really think that, again, as this market moves and people start to gain some confidence when there is a reason to have confidence, then we'll have an opportunity to put some rigs to work because we have the flex threes that are available. Think about it, we have not had flex threes available on the open market, well, in a very long time.

Actually one more, Doug. At one point your expectation for the early termination revenues in the quarter was in the $90 million range and it came in at $81 million. Were there fewer cancellations, is there a silver lining in that or just the timing of the payments?

Conner, this is Juan Pablo. It is a combination of -- sorry, Pierre, it was a combination of things. Basically we invoiced $100 million related to early terminations during the quarter but we are moving the revenue to future quarters, some of it.

Okay. Great. Okay. Thanks, gentlemen.

Thank you.

Our next question will come from the site of Waqar Syed of Tristone Capital. Please go ahead. Your line is open.

Good morning. This rig that is going to Marcellus, the new contract, is it a FlexRig 4S or 4M?

It is a flex 3.

Oh it is a flex 3. It's a bigger rig? And then what kind of contract? Is it a term contract, short-term contract?

Waqar, I wish I could tell you more but based on the contract we have and the agreements we have in place, we are really not in position to talk about it. Can't really talk about the customer or the contract. But I mean it's, from our perspective, it's an attractive contract. And I think gives us a lot of opportunities in Marcellus.

Then your rig in Tunisia, I believe you have an agreement for the operator to pay you demobilization, is that correct?

Yes. I believe we have that in the contract.

So, would you be moving the rig back by the end of the year? Or are you just going to wait and see what happens?

I really think we'll put the rig to work. I mean, this is a very recent event, so yes, I think we'll put the rig to work and really don't have any intention to send the rig back to the US. I mean, there is other areas that have a lot of interest that are much closer. And, but I think we'll put the rig back to work in north Africa.

Okay. Then on Venezuela, once all your rigs in Venezuela are stacked, would you see any benefit on the G&A side and what would still be bid on the OpEx line for the (inaudible)?

We'll just have to play that by ear. I mean, yes, the probabilities would be high that we would see reductions on all fronts on those costs. But we have got to be -- still a lot of uncertainty how that's going to unfold. So I hate to be too bold about stating how much or when that's going to happen.

Right. But can the OpEx go down to zero? Or it doesn't -- it may not go down to zero?

I'm sorry, Waqar, can what go to zero?

The operating costs, the daily operating costs will that go down to zero or will there be something even if all rigs are stacked?

Yes, there will be something there. Erratically reduced, of course but it will be significantly lower.

Okay. Then for the CapEx for 2010, you mentioned [maintenance] type and the minimum could be $100 million. Could you -- if I put it another way. On a per rig day basis is it $800 to $900 per rig day?

You are talking about capital expenditures?

Just the maintenance CapEx.

Okay. But we are talking about a capitalized amount, not a field expense.

The capitalized amount, that is correct, yes.

So we are still talking what $25 million a quarter roughly on a maintenance CapEx?

Right. We don't look at that on a per rig unless you want to take the average and divide it by the after rigs that are expected for 2010. We don't look at it that way but the total amount of maintenance CapEx for 2010 might be close to $100 million.

Okay. Thank you very much.

Thanks.

Thank you. Our next question will come from the site of Mike Drickamer with Morgan Keegan.

Asking the CapEx question one more time. I apologize if I missed this but of the $850 million for 2009, how much is related in new builds?

About two-thirds of that, Mike.

Okay. And then on the flex three you are setting up to Marcellus, any modifications required to that rig to get it in to that market and able to meet the various needs of that market?

No, Mike. This is John. There is really, it is pretty much the standard flex three package. I mean, there is obviously a lot of discussion about the infrastructure and road infrastructure and challenges there. And, I mean, we have been up there we have made a lot of trips. Sure there are some areas that have that but there is a lot of other areas we work whether it be in the Rockies or whether it be in southeastern Oklahoma or just various places that have very narrow roads. A lot of switch backs, a lot of elevation changes and those types of things that we have been successful with flex threes. That question that was asked earlier, I think maybe it was Waqar, about the rig type. I do think there is opportunities for the flex four S in the Marcellus as well as the flex 4M. I think we have a nice offering of rig types for that play. As you know, it is a very, very large area and a lot of different conditions.

Okay. And then, John, I agree that companies go back to work your rigs will probably be one of the first one's picked up. I think, therefore, your rig count would be a leading indicator here. The question I have is if you go back to previous cyclical downturn, I know it is a different time back then but I don't remember that you guys got very much of a premium for your rigs. You think they'll say that again this time will you be able to maintain a premium for your rigs?

Well, and again it is all relative. We were getting a premium at that time and what I recall was anywhere from $2000 to $3,000 a day. Of course we just had all the rigs we had the flex 1 and flex 2. We were building the flex 3's. The 3's were coming out at $11,000 a day. I think the spot market pricing for a rig was probably $6500 to $7500. So I think we were successful then. I think we'll be successful today.

I think, Mike, there is going to be a transition period in any market move and you are going to have lots of idle rigs and guys that are willing to be very, very aggressive on their pricing. I think most of the pressure will be exerted on the legacy rigs and that's where, as you point out, I think we fare well going forward with the type of rig profile that you are very familiar with. So, I think it will take some time but there are so many differences between today and prior periods. We really didn't have as an industry a segmented fleet the way we have today with the availability of the type of rigs we have. As John has mentioned, for the first time ever, those FlexRigs are available to a wide range of customers. And notwithstanding some of the tone of this call, I mean we are very busy today getting in front of new customers and potential folks that are interested in having a chance to use a FlexRig. So I think as we transition out of this down turn there will be a sloppy period of time. But I think at the end, the performance and the efficiency will be valued and will be awarded a premium in the market.

Great. Thanks guys. That is all from me.

We'll take the next question from the site of Arun Jayaram from Credit Suisse. Please go ahead. Your line is open.

Good morning, guys.

Good morning.

John you mentioned the spot market, if I understand your comments were about 30% below what you are getting in terms of your term contracts to suggest something in the 17.5 range. Is that correct characterization of what you said? Are you saying the rigs operate under spot or at 30% below? Just trying to understand where the current leading edge or spot kind of rates that you are signing where that range is today?

You have got the 17.5. That's correct and that's the average. But, as you can imagine, putting rigs to work in the spot markets, which I'm sure you recognize this as a very, very small number of opportunities. But the rigs that we put to work are in a range, and overall, that that's about what they average of those that we have put to work. But there is a range, depending on the capability of the rigs. Obviously the lesser capable rigs in our fleet are in the lower teens and the higher capability rigs are in the higher teens up to $20000 a day. It is a range and it is based on capability.

That is very helpful by the way. JT, historically, if my thinking is correct, the FlexRigs have generally garnered would you think this is accurate, about $4000 or $5000 premiums to your conventional rigs, is that fair?

Approximately so, yes.

Something in that range. I was just wondering as utilization has come down, are the FlexRigs still maintaining this type of premium? Just trying to understand if the FlexRigs are holding this kind of pricing advantage as utilization has come down.

We are maintaining a pricing premium. But as Hans said earlier, I mean, we don't have very many opportunities. There is a premium there but it's very difficult to compare it to what was going on a year ago and in 2002 or 2003, I mean it's just, it's a dramatically different environment. But I do think that people recognize and people, some operators that have not had the opportunity to use a FlexRig today have an opportunity and they see the value proposition. So they are going to pay the premium to what they would pay for a conventional rig or some other competitor rig. The question is what is the premium and it's all over the board.

Okay.

A lot of that depends on the play, it depends on is it a 15 or 20 day well. Just a lot of different variables.

That's helpful. Last question regards Venezuela. Hans, is the collectability issues that you are citing, is this more of not having the means or is this more of a function of them trying to negotiate getting or paying a portion of the receivables to try to get lower day rates on work that is performed.

I think it is the first issue. I think they have had, like the whole industry has, I think in particular they have had difficulty transitioning from the high prices we saw last July to where we are today. And I think the other point is we have been in discussions with other oil field service players down there and our situation is very similar to that. So just stepping back and looking at it, it's a industry group that [Petavasa] needs to continue to team with and work with and we think that because of that, it's in everyone's mutual interest to work through this time. It's just been a difficult period and frustrating but at the same time we would anticipate we work through it and have a chance to get back to work.

Okay. Thanks again, guys.

Thank you.

Next question from John Daniel of Simmons & Co. Please go ahead. Your line is open.

Morning, guys. Hopefully you can answer this, but for the new builds that are being delayed, can you tell us how you are being compensated on that?

In dollars?

Well, I mean is it a function of lower day rate, extended term? Just trying to better understand it.

And the answer, John, is we really can't. We have, as I think people know, 16 rigs remaining. We have got manufacturing that will extend through this calendar year and as we have said to you and other folks that follow this, our mission is to keep this on a net present value neutral basis and we continue to do that. At the same time, we are cooperating and working with customers. So to give you any more granularity, I think wouldn't be appropriate.

Okay that's fine. On the spot rigs versus the term rigs is there a material difference in the cost per day for you guys on those. I don't know if you answered it earlier in the call and I apologize if you did.

No there is not.

Okay. Thank you.

We'll take our next question from the site of -- actually, it looks like a follow-up question from Pierre Conner of Capital One. Please go ahead. Your line is open.

Thanks for letting met back through. Hopefully most have gotten their main ones out. For John relative customer behavior in the Barnett and what you might shed light on this perspective of uncompleted wells, it would seem equipment is well-suited to badge drilling and then waiting. What do you know about that? And are the FlexRigs suitable to come back in completion mode or would they be picked and replaced by a service rig?

Pierre, I'm not aware in a large way, of wells being drilled in the Barnett and not completed. I'm not saying they are not, I just don't recall hearing that. I am aware that there's some of that's gone on in the Peance, but I'm not necessarily aware of it in the Barnett. What I think the flex 4S would offer in the Barnett in that case, if there were, is that the rig could come in and complete the well and then drill another series of wells on a pad. That's as we have seen how this development process has gone, in a lot of cases, an operator will have a well or will have a location and he'll have a well or two on it and then the flex 4S would come in and then drill additional wells, whether it be two or three or in the Peance it could be an additional 10 or 15. So I think the rig is well suited for that, because it has the ability to get over the top of the well heads and those types of things. So I do think that it's applicable. I'm sorry I can't really answer the question on the uncompleted wells, because I really haven't heard that.

Well, it actually is helpful. It's the same, I guess, mechanics apply on these pads in the Peance. That is what I was looking for. And then the other follow-up was the character of the rigs that you put back to work off of spot, the FlexRigs I think you noted, John, a couple. Were those replacements of older rigs or were they enticed by a customer seen better spot rates, or was it economics and they started up again or because of availability did they replace the competitors's rig?

We have about I think we put eight rigs, eight FlexRigs to work. Most of them are flex 3's. They are all smaller customers. They are all new customers. And to my knowledge in each case it was a replacement of a competitor's rig that was not performing at the levels that they would have liked to have seen.

Okay.

And so, again, I think it we see that trend, we see it as a potential growing trend. And that's a great opportunity for us. If you look at our customer base today, we have been able to find a lot of new customers. I think at the peak we had about 29 FlexRig customers and today I think we have 35 FlexRig customers. We have actually grown the customer base in terms of the number of operators. Unfortunately, the rig counts aren't where we'd like to see it but the number is going in the right direction in terms of customers. Again, I think that's a positive trend for us.

Great. Both of those things are helpful. Thanks, John.

(Operator Instructions) We'll take our next question from the site of [Monroe Helm] of CM Energy Partners. Please go ahead, your line is open.

Thanks for your candid answers as usual. On these FlexRigs going back to work as you mentioned, would you characterize that within that average you talked about before going to work in the high teens or 20 kind of a thousand dollar a day kind of range?

Monroe, this is John. They are in a range that range that I have mentioned where you are talking the lower teens up to the high teens to right at 20.

Okay. So that entire range not just the top end of the range?

Because, again, you look at a FlexRig 1 or Flex 2, Flex 1 that maybe doesn't have a top drive, doesn't have the same capability as a Flex 3 so, again, it is kind of back to that rig capability question and what kind of performance are you able to deliver in the field?

Okay. A question for Hans since you said at one point in time this is the biggest downturn in rig activity since we have seen in the early 80s, do you think that a lot of rigs that were operating at the peak here not too many months ago will never go to work again? How would you view in the next up cycle what's going to happen to a lot of these rigs that working before? Were they all going to be competitive or do you think a lot of them will be just laid down in the weeds permanently?

Yes. It is a good question, Monroe. It is trying to describe what the new normal will look like once we get off this deteriorating environment. But I think you and I talked about in 2007 when 400 industry rigs went down, we said at that time we thought a lot of those would struggle to go back to work and, in fact, probably half went back to work at the peak. I have got to think the pressure only intensifies on legacy equipment going forward. It's hard to know what the new normal is in terms of do we ever get back to a 2000 rig count? Maybe some day but I would suspect not for a long time. And, again, the customer has had enough time with high efficiency rigs and their performance to have that be their strong preference. And if their 350-plus maybe 400 of those types of rigs, I think they get the first chance to return to work. And I do think, we are really getting at a point where the obsolescence factor sets in, in somewhat of a tough way going forward. So yes. I think the answer is yes. I think a lot of pressure gets exerted on those legacy rigs.

Okay. Thanks again for your comments.

Thank you.

We'll take out next question from the site [Blake Ludless] of [Breeden] Capital. Please go ahead, your line is open.

Hi. Thanks. My main question has been answered. I do have a quick followup. With regards to Venezuela, if you were getting paid as expected based on the rigs going down in current revenues, what would be total receivable and billings be versus the 116 today?

I'm not sure. Blake, this is Doug. I'm not sure I understand your question, sir.

In other words, Venezuela is approximately 116 today and if they were current on all of their payments, what would that number be?

I'll take a shot at that and it will be wrong. But I think I hear the essence of your question. First of all, sort of a normal is for them, is in the kind of a four-month billing, four months in billings kind of cycle. But if they really got caught up, there might still be $30 million, $20 million somewhere in there.

Okay, that's very helpful. That is what I was looking for.

We'll take our next question from the site of [Bob Schwarin] of [Schwarin Boil] Capital Management. Please go ahead your line is open.

Thanks. You mentioned that while your pre-payments keep you pretty much present value neutral that you would obviously rather keep the crews and the rigs working. What are you doing with the crews, in particular? And when and if things start picking up are you going to be back in the same problem of trying to retrain crews all over again?

Bob this is John. It goes back to the discussion earlier on costs and one of the challenges and of course we have had lots, unfortunately, lots of experience with this over the, you know the last ten years, in having to bump people back. But effectively you bump people back in position. You keep your most senior, your most experienced people. Typically the employees that are laid off are the people the newest in the less experienced the floor-hand level if you will. Obviously, you do get to a point where you could start cutting into the bone, that is what we are trying to prevent and that is part of the cost driver in a market like this is, again, you want to hang on to your best people. We have been successful in doing this in the past. I think the folks have been around H&P a long time have seen it and they appreciate the effort that we are able to keep people busy, so that's what we are doing is we are continuing keep people busy but they are having to work back in a position. In some cases they may be get bumped back to a rig hand for some period of time.

I guess the only thing I would add to that, Bob, is we have had a little bit of relief with the new builds that we have rolled off because prior to a downturn we would have gone out and recruited and trained folks. We have used that as a buffer for our established people and I think the other thing I would say is no one has matched the level of rollout that we achieved. And then also, the amount of training and the ability to bring people in to an organization and get them up to where they are hitting on all eight cylinders, so I think we do that better than anybody and that will serve as well in an improving environment. But you are hitting on something that we think a lot about, the very toughest thing about this downturn for us are the people that have been impacted. We think our organizational strength is our leading asset. So it's something that we come to work with every morning on trying to work through and manage and it hasn't been easy but, again, we are putting a lot of effort into it.

You actually keep people on the payroll who aren't even working at all just who have them in reserve?

Like John mentioned, our first efforts are rotating guys through. So we'll have crews that are made up of primarily rig managers and drillers and for a period of time, 90 days or so, we keep those buys at their prior pay level. So there is a certain holding and those will be the people that mentor and teach new guys when we get to that stage. It's a balance. Unfortunately, we can't afford just to inventory guys. That's the balance we face.

Bob, one other thing that may help you as well is to think about, in general, I think H&P we have less turnover than most. But in a given year, when activity is at a normal level, we'll have annualized turnover rate at that entry level position of anywhere from 70% to 80% annualized turnover. So, again, what we are doing is as you are bumping people back then you are eliminating, essentially you are eliminating that turnover and that need to hire people. We also have maintenance teams in place. I mean, again, when you are stacking rigs, you have got to have people to make sure you are maintaining your assets in a proper way. That was my point earlier when we talk about a lot of moving parts on this cost piece.

Thank you very much.

It appears as though we have one last question and it's a follow-up Arun Jayaram from Credit Suisse. Please go ahead. Your line is open.

Real quick one, guys. You mentioned that you are changing the accounting on the Atwood stake. Can you give us a little bit of your thoughts on reducing you go from two to one Board seat? And does a change in accounting perhaps suggest that you may consider monetizing this investment at some point over the next foreseeable future? Does the accounting change relate to that?

No, it doesn't directly relate to it, Arun. As you might remember, George [Dodson] and I have been on that Board for a long time. So when George retired, he's now fully independent or whatever the term is. So that's what relates to now just the one Board seat. And we have said before our Atwood holding we look at it as something that we eventually will monetize. Then we have sold the main shares of Atwood a couple of years ago. I wish, like a lot of things, I would have picked the high this time around and we would have looked at monetizing some more of that. But that's something that will be an ongoing consideration in terms of eventually transferring those assets into our own operating assets.

Okay. That's helpful. But it's not like this change can be more driven by George's retirement?

Yes, I think that's right.

Thanks, guys.

This concludes today's question and answer portion. I'd now like to turn it back over to Doug Fears for any closing comments.

Thank you, Katie. Our next earnings conference call is scheduled for July 30 and we'd like to thank you all for joining us today. We look forward to communicating with you at at that time. Have a good day.

This concludes today's teleconference. You may disconnect at any time. Have a great day.