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Helmerich & Payne Inc. (NYSE:HP)

F2Q09 (Qtr End 31/03/09) Earnings Call

April 30, 2009 11:00 am ET

Executives

Doug Fears - VP and CFO

Hans Helmerich - President and CEO

John Lindsay - EVP

Juan Pablo Tardio - Director of IR

Analysts

Mark Brown - Pritchard Capital

Pierre Conner - Capital One

Waqar Syed - Tristone Capital

Mike Drickamer - Morgan Keegan

Arun Jayaram - Credit Suisse

John Daniel - Simmons & Company

Monroe Helm - CM Energy Partners

Bob Schwerin - Schwerin Boyle Capital Management

Operator

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

Doug Fears

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 Lindsay; and Alan Orr and Juan Pablo Tardio, our 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'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 $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 the last year's second fiscal quarter.

Included in second quarter net income for '09 and '08, were $0.01 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 terminated 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 coped with extended receivables for most of that time. Our longer term experience with PDVSA is that while they often have been slow to pay, they have always paid us the full amount of our billings.

Other than a deserving delay in payments that all oil service companies seem to be experiencing at this time, we have not had any communication from PDVSA that has given us any indication of non-payment, 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 PDVSA, 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 will 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 the 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. 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 reimbursable 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 our 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 to 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 PDVSA, 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 include 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's predicted to generate significant free cash flow, as a result of continued revenue and income from our long-term contracted FlexRigs and a much smaller capital expenditure estimate for that year.

The market value of the company's stockholding in Schlumberger and Atwood today is approximately $230 million pre-tax and $160 million after-tax. Until this month, Atwood Oceanics as been accounted for as equity affiliate because we have held two board seats and were deemed for accounting purposes that have significant influence. We now hold only one board seat.

We have not sold any of our 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. And after Hans and John have made their comments, we will open the call for questions. Hans?

Hans Helmerich

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 the 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 at bottom. We know others have particular bottom to occur sometime during the quarter. And while we hope it does, we believe E&P operators 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 LNG 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 policymakers 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 result 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 termination as Doug mentioned on 35 rigs with long-term contracts could 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. And 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 customers a flexibility to change course, at the same time mitigating the risk of a massive capital commitment. We made in an industry leading effort to satisfy our customers' demand for purpose-filled 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 reflect that their determination to manage spending within their declining cash flows.

It follows that un-contracted 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, 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 terms.

The pace of terminations has noticeably slowed down. When we updated investors a month ago, the number was 31, whereas today the total stands at 35. Even after factoring in this total, approximately 42% and 37% of the segments 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 this downturn both leaner and better positioned to seize opportunities that will come with 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 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 Lindsay to make some comments.

John Lindsay

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 this scenario will continue until operators gain confidence that gas and oil prices to stabilize at economically viable levels.

As a result, we are seeing activity declines in all three operating segments of 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 markets, 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 FlexRigs; 34 of which are early terminated new builds.

We have reached 139.2 active rigs during the first fiscal quarter as compared to 177.4 during the 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. 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 rig in the spot market has declined by approximately 30%. Currently the H&P dayrate average for rigs in the spot market is approximately 27% lower than the H&P dayrate 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 $1,000 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 FlexRigs 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 FlexRig will be among the first to go back to work. We were reasonably successful in signing a contract for our first FlexRig in 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 us to grow our footprint in the Marcellus as operators delineate and develop the play.

At offshore, in our last call we commented on seeing the first signs of softening activity in our offshore platform business that would effect the third quarter. As expected three of the nine rigs have been given 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 could sequentially decline 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 day for the quarter was $10,848 before the adjustment was reduced to a loss of $4,086 per day.

Average international operating activity declined from 26.2 rigs during the first quarter to 22.8 rigs during the second quarter. 11 of the companies international land rigs on 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 ones 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 American 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 is 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 the long-term.

We are also 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 the fleets, stacked FlexRigs should be among the first to go back to work.

I'll turn the call back over to Doug.

Doug Fears

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

Question-and-Answer Session

Operator

(Operator Instructions) We'll take our first question from the side of Mark Brown of Pritchard Capital.

Mark Brown - Pritchard Capital

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

Doug Fears

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 switchover 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.

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. At the end of the day, as a 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.

Mark Brown - Pritchard Capital

Okay. Further rings in that country, do you have any insurance on them? What are your plans potentially to move them somewhere else, or any resale value on those rigs?

Doug Fears

First of all, we cannot comment on the insurance issues. We 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.

Operator

Our next question will come from the side of Pierre Conner of Capital One.

Pierre Conner - Capital One

First, John, a color on guidance on a number of items, I wanted to try to push a little bit more on the costs; the daily operating cost side on the clean basis, absent, standby etcetera. 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 could go?

John Lindsay

Pierre you said it, there is a lot of moving parts. When you are stacking rigs, you've got stack costs, you've got the personnel side, so I tried to address it.

In my comments, there are some efforts, I believe on our 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've got these other moving parts and pieces related to stacking rigs.

That's the challenging part. We are hopeful that we are going to be able and be successful to get the costs per day down. We did have a reduction in our labor costs. I think we talked about that in our last call. That was effective going back to our previous September 30 wages. That obviously had an effect in this quarter.

It's really hard to say. What I can tell you that we've got a lot of effort going on. We've 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.

Pierre Conner - Capital One

Going back to the tax question, I understand the mechanics there, but as you idle additional rigs in Venezuela, and then 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.

Doug Fears

The 40.8 is an estimate for the remainder of the year and for the entire year when you mix it altogether, 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.

The answer is yes. As you stack rigs and have less activity, generated non-book revenue and then for US tax purposes, for US GAAP purposes, you are better off. So you are correct. It should come down.

Pierre Conner - Capital One

Going to the CapEx question, free cash flow 2010, a significant improvement in free cash, so that maybe the way to ask is, what is the maintenance CapEx on the fleet? And absolutely it varied on how much is active, but this kind of level, how low could that CapEx be?

Juan Pablo Tardio

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

Pierre Conner - Capital One

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

Juan Pablo Tardio

Just the minimum.

Pierre Conner - Capital One

One last one back to John, are you the most active US land driller yet? How close?

John Lindsay

Seems like a small consolation.

Pierre Conner - Capital One

You sort of gained and your mentioned the Marcellus getting the contract there, but what do you think about your position at Haynesville and some of the higher horsepower equipment? What do you think Helmerich & Payne needs to do to grow some share there or are you comfortable with where you are?

John Lindsay

We 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 is out there. The good news is that lot of the new builds we are delivering now are in fact going to the Haynesville. The timing on that is good. So, we are going to continue to capture some market share there.

Once we continue to kind of say this over the past several months is once operators do get into that mode of high-grading and putting rigs back to work, the Flex3 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, in a lot of cases, we are moving the rig twice as fast as as they are.

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 down. 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 Flex3s that are available. Think about, if we've not had Flex3s available on the open market, well in a very long time.

Pierre Conner - Capital One

Actually one more for Doug, and it just had to be on. At one point your expectation for the early termination revenues in the quarter was in the $90 million range and I guess came in at $81 million. And was there fewer cancellations? Is there silver lining in that or just the timing of the payments?

Juan Pablo Tardio

This is Juan Pablo. It was combination of things; basically we invoiced over $100 million related to early terminations during the quarter. But we are moving the revenue to future quarters, some of that.

Pierre Conner - Capital One

So just shifting, right. Okay. Thanks, gentlemen.

Operator

And our next question will come from the side of Waqar Syed of Tristone Capital.

Waqar Syed - Tristone Capital

Good morning. Just on this rig that's going to Marcellus, the new contract. Is it FlexRigs 4s or the 4m?

John Lindsay

It's a Flex3.

Waqar Syed - Tristone Capital

It is a Flex3, it's a bigger rig, okay. And what kind of contract, is it a term contract or short-term contract?

John Lindsay

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

Waqar Syed - Tristone Capital

And then your rig in Tunisia, I believe you have agreement for operator to be demobilization, is this correct?

John Lindsay

Yes. I believe we have that in the contract.

Waqar Syed - Tristone Capital

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

Hans Helmerich

I really think, we'll put the rig to work. This is a very recent event, I think we'll put the rig to work and really don't have any intention to send the rig back to the US. There are other areas that have a lot of interest that are much closer, but I think we'll put the rig back to work in North Africa.

Waqar Syed - Tristone Capital

In 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 you people?

Doug Fears

We'll just have to play that by year. Probabilities would be high that we would see reductions on all fronts on those cost, but still a lots 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.

Waqar Syed - Tristone Capital

But can the OpEx go down to zero or it may not go down to zero?

Doug Fears

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

Waqar Syed - Tristone Capital

The daily operating cost, will that go down to zero or will there still be something even if all rigs are stacked.

Doug Fears

Yeah there will be something there, radically reduce the course, but it will be significantly lower.

Waqar Syed - Tristone Capital

And then for the CapEx for 2010, you mentioned maintenance type and the minimum could be $100 million. If I put it another way, on a per-rig-day basis, is it like $800, $900 per-rig-day?

Doug Fears

You are talking about capital expenditures?

Waqar Syed - Tristone Capital

Just the maintenance CapEx.

Doug Fears

But we are talking about a capitalized amount. Not a field expense.

Waqar Syed - Tristone Capital

The capitalized amount, that is correct.

Doug Fears

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

Hans Helmerich

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

Waqar Syed - Tristone Capital

Thank you very much.

Operator

Our next question will come from the side of Mike Drickamer, from Morgan Keegan.

Mike Drickamer - Morgan Keegan

Good morning, guys. Asking the CapEx question one more time. I apologize, if I missed this but of the $850 million for 2009, how much is it related to new build?

Hans Helmerich

About two-thirds of that, Mike.

Mike Drickamer - Morgan Keegan

And then on the Flex3, you are setting up to Marcellus, any modifications required to that rig to get it into that market and able to meet the various needs of that market?

John Lindsay

No, Mike. This is John. It is a pretty much standard Flex3 package. There is obviously a lot of discussion about the infrastructure and road infrastructure and challenges there. We have been up there, we have made a lot of trips. Sure, there is some areas that have that but there is a lot of other areas that 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 and a lot of elevation changes and those types of things that we have been successful with Felx3s. That question that was asked earlier, I think maybe it was Waqar, about the rig type. I do think there is opportunity for the Flex4s in the Marcellus as well as the Flex4m. I think we have a nice offering of rig types for that play, because it is a very, very large area and a lot of different conditions.

Mike Drickamer - Morgan Keegan

John, I agree that when E&P companies go back to work, your rigs will probably one of the first one to be picked up, therefore your rig has to be a leading indicator here. But the question I have is if you go back to the previous couple downturn, I know there is a different time back then, but I don't remember that you guys got very much of a premium for your rigs. Do you think, we'll see that again this time or will you be able to maintain the premium for your rigs?

John Lindsay

Again it is all relative but we were getting a premium at that time. And what I recall was anywhere from $2000 to $3000 a day. Of course, we just test all the rigs that we were, we had the Flex1 and the Flex2 and we were building the Flex3s. And the 3s 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.

Hans Helmerich

I think, Mike, there is going to be a transition period in any market move, and you’re going to have lots of our 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 [farewell] going forward with the type of rig profile that you’re 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. 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 the 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.

Operator

We'll take our next question from the side of Arun Jayaram from Credit Suisse.

Arun Jayaram - Credit Suisse

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

John Lindsay

You’ve got the 17.5. That's correct, and that's the average. As you can imagine, putting the 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 capability rigs in our fleet are in the lower teens and the higher capability rigs are in the higher teens, up to 20,000 a day. So, it’s a range and it is based on capability.

Arun Jayaram - Credit Suisse

Historically, if my thinking is correct, the FlexRigs have generally garnered, would you think those are accurate about $4000 to $5000 premiums to your conventional rates. Is that fair?

John Lindsay

Approximately, so. Yes.

Arun Jayaram - Credit Suisse

I’m just wondering as utilization has come down, are the FlexRig still maintaining this type of premium? Just trying to say that the FlexRigs are holding this kind of pricing advantage as utilization has come down.

John Lindsay

We are maintaining a pricing premium. But as Hans said earlier, 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 dramatically different environment. I do think that people recognize. Some operators that have not had the opportunity to use the 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. A lot of that depends on the plays, it depends on you know, is it a 15 or 20 day well. It’s just a lot of different variables.

Arun Jayaram - Credit Suisse

Last question regards Venezuela. Hans, is the collectability issues that you are citing, is this more of PDVSA and not having the means or is this more of a function of them trying to negotiate getting or paying a portion of the receivables out there to try to get lower dayrates on work that’s performed.

Hans Helmerich

I think it’s the first issue. I think they have like the whole industry has, I think in particular they’ve had difficulty transitioning from the high prices we saw last July to where we are today. And, I think the other point is we’ve been in discussions with other oilfield service players down there and our situation is very similar to that.

So, from just stepping back and looking at it, it's an industry group that PDVSA 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 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.

Operator

Your next question is from the side of John Daniel of Simmons & Company.

John Daniel - Simmons & Company

For the new goals that are being delayed, can you tell us how you are being compensated on that?

Hans Helmerich

In dollars.

John Daniel - Simmons & Company

Is it a function of lower dayrate extended term? Just trying to better understand it.

Hans Helmerich

The answer, John, is we really can't. We have as I think people know, 16 rigs remaining, we’ve got manufacturing that will extend through this calendar year. As we have said to you and other folks to follow us, our mission is to keep this on a net present value neutral basis. 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.

John Daniel - Simmons & Company

On other thing, just on the spot rates versus the term rates, is there a material difference in the cost per day? I don't know if you answered it earlier in the call and I apologize, if you did.

Hans Helmerich

No there is not.

Operator

Follow-up question from Pierre Conner of Capital One.

Pierre Conner - Capital One

For John, relative customer behavior in the Barnett and you might shed light on the perspective of uncompleted wells; it would seem that equipment is well-suited to batch drilling and [wading]. What do you know about that? Are the FlexRigs suitable to come back in the completion mode? Would they be picked up things replace by potentially a service rig?

John Lindsay

Pierre, I'm not aware in a large way, of wells being drilled in the Barnett, and not completed. I'm not saying that they are not. I just don't recall hearing that. I am aware that there's some of that, that's going on in the [peeon], but I'm not necessarily aware of it in the Barnett.

I think what does the Flex4s, would offer in the Barnett in that case, if there were, is that the rig could come in and complete the well and then drilling other series of wells on pad. 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, he'll have a well or two on it. And then the Flex4s would come in, and then drill additional wells, whether it be two or three or in peeons 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 wellheads and those types of things. 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.

Pierre Conner - Capital One

Well, it actually is helpful. I guess mechanic supply on these pads and the peeons, so 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 and FlexRigs that I think you noted John equal to couple. Were those replacements of older rigs or were they enticed by the customer seen better spot rates? It was an economics and they started up again or because of the availability did they replace the competitor's rig?

John Lindsay

I think we put eight rigs, eight FlexRigs to work. Most of them are Flex3s. 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.

We see that trend; we see it as a potential growing trend. That's a great opportunity for us because 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. So, we have actually grown the customer base in terms of the number of operators. Fortunately, the rig counts are not at 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.

Pierre Conner - Capital One

Both of those are very helpful. Thanks, John.

Operator

(Operator Instructions) We'll take our next question from the side of Monroe Helm of CM Energy Partners.

Monroe Helm - CM Energy Partners

The FlexRigs that going back to work that you just mentioned, would you characterize it, within that average you talked about before going to work in the high-teens or 20, kind of thousand dollars a day range.

John Lindsay

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

Monroe Helm - CM Energy Partners

So they are within that entire range not just the top-end of the range?

John Lindsay

Again you look at a FlexRig1or Flex2, Flex1 that maybe doesn't have a top drive, doesn't have the same capability as the Flex3, so again it's kind of back to that rig capability question and what kind of performance are you able to deliver in the field.

Monroe Helm - CM Energy Partners

And the question for Hans, since you (inaudible) the biggest downturn in rig activity since we have seen in the early 80s, do you think lot of the rigs that were operating at the peak here not too many months ago will never get to work again. How would you view in the next up cycle? What's going to happen to all these rigs working before? Were they all tried to stay and be competitive? Or do you think lot of them will be let down in the [weeks] permanently?

Hans Helmerich

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 '07 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.

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 have sets in, in a somewhat of a tough way going forward. I think the answer is yes, I think a lot of pressure gets exerted on those legacy rigs.

Monroe Helm - CM Energy Partners

Thanks again for your comments.

Operator

We'll take our next question from the side of [Blake Lovelace of Breeden Capital].

Unidentified Analyst

My main question has been answered. I do have a quick follow-up. 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 to be versus the 116 today?

Doug Fears

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

Unidentified Analyst

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

Doug Fears

I'll take a shot at that. 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 of billing cycle. But if they really got caught up, there might still be 30 million, 20 million, somewhere in there.

Unidentified Analyst

That's very helpful. That exactly what I was looking for.

Operator

We'll take our next question from the side of Bob Schwerin of Schwerin Boyle Capital Management.

Bob Schwerin - Schwerin Boyle Capital Management

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

John Lindsay

Bob this is John. It goes back to the discussion earlier on costs and one of the challenges and unfortunately we have lots of experiences with this over 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 experience, and the floor hand level if you will.

Obviously, you do get to a point where you could start cutting into the bone and that's what we are trying to prevent and that is part of the cost driver in a market like this. Again, you want to hang on to our best people. We have been successful in doing this in the past. I think the folks that have been around H&P long time have seen it and they appreciate the efforts that we're 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. They in some cases may be get bumped back to a rig hand for some period of time.

Hans Helmerich

The only thing I would add to that, Bob, is we have had a little bit of relief with the new bills 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 hadn't been easy, but again we are putting a lot of effort into it.

Bob Schwerin - Schwerin Boyle Capital Management

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

Hans Helmerich

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, at 90 days or so, we keep those guys 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 and unfortunately, we can't afford just inventory guys. So that's balance we face.

John Lindsay

Bob, one other thing that may help you as well is to think about in general. I think H&P, we have less turn over than most, but in a given year, when activity is at a normal level, we'll have an 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 essentially you are eliminating that turnover and that need to hire people. We also have maintenance teams in place. Again, when you are stacking rigs, you’ve got to have people to make sure that 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.

Operator

It appears that we have one last question. It’s a follow-up from Arun Jayaram from Credit Suisse.

Arun Jayaram - Credit Suisse

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, forward seed? And does the 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 or?

Hans Helmerich

It doesn't directly relate to it Arun. As you might remember, George Dotson and I have been on that board for a long time. So when George retired, he is now fully independent or whatever the term is. So that's what relates to now just the one.

We’ve said before that our Atwood holding, we look at it as something that we eventually will monetize. Then we’ve sold a million shares of Atwood, I want to say, 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.

Arun Jayaram - Credit Suisse

But it sounds like there is change, and that can be more driven by George's retirement, et cetera.

Hans Helmerich

Yeah. I think that's right.

Operator

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

Doug Fears

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

Operator

This concludes today's teleconference. You may disconnect at any time. Thank you and have a great day.

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Source: Helmerich & Payne F2Q09 (Qtr End 31/03/09) Earnings Call Transcript
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