Helmerich & Payne, Inc. (HP) Q3 2012 Earnings Report, Transcript and Summary

Good day, and welcome to the Third Fiscal Quarter Earnings Conference Call. [Operator Instructions] And please note today's call is being recorded. I would now like to turn the call over to Juan Pablo Tardio, Vice President and CFO of Helmerich & Payne.

Thank you, and welcome, everyone. With us today are Hans Helmerich, Chairman and CEO; and John Lindsay, Executive Vice President and COO. As usual and as defined by the U.S. Private Securities Litigation Reform Act of 1995, all forward-looking statements made during this call are based on current expectations and assumptions that are subject to risks and uncertainties as discussed in the company's annual report on Form 10-K and quarterly reports on Form 10-Q. The company's actual results may differ materially from those indicated or implied by such forward-looking statements. We will also be making reference to certain non-GAAP financial measures such as segment's operating income and operating statistics. You may find the GAAP reconciliation comments and calculations on the last page of today's press release. I will now turn the call over to Hans Helmerich.

Thank you, Juan Pablo. Good morning, everybody. We're pleased to report the company achieved an all-time record level of quarterly income from continuing operations. This is a nice milestone made possible by, literally, thousands of H&P employees who work hard every day to exceed our customers' expectations. We have discussed on a number of these calls the impressive rotation from dry gas direct drilling to oil and NGL directed targets. There's been a steady 3-year upward march in oil directed drilling that had been more than enough to offset a slowly deteriorating dry gas drilling rig count. Then, a couple things happened earlier this year. Natural gas prices plunged beneath $2 per mcf and the gas directed rig count dropped by over 1/3, reaching a 13-year low. Next, the oil rig count received a jolt at the time of our last call. WTI prices were over $105, but by the end of the quarter, the oil prices had fallen to $77 and changed. While both oil and gas prices have recovered some lately, the $100 question focuses on what happens next, particularly to the future price of oil. Certainly, that answers entangled with macroeconomic headlines of the euro crisis, the ongoing Middle East turmoil and the sense for a slowing world economy, but the volatility and uncertainty is weighing on the minds of our customers and impacting their spending in the field. I think the right question to ask at the onset of what appears to be a somewhat softening cycle is how deep and will the pain go and how long will it last. While our sense is that the duration and the depth of this slowdown will be on the milder side, I can't think of a time in the company's history that we've been better positioned for the uncertainty ahead. In addition to our quality fleet profile and strong balance sheet, we've never had a more robust term contract coverage. Today, 157 FlexRigs or about 2/3 of our active fleet are under long-term contracts in the U.S. land market. Moreover, we already have in place today an average of 136 FlexRigs under term contract during fiscal 2013 and still an average of 95 FlexRigs under term contracts during fiscal 2014. These rigs are expected to generate average daily rig margins that are higher than the average reported in the segment during this third fiscal quarter. In addition, today, we have 13 rigs under term contracts internationally, as well as 2 platform rigs. Most of these 15 rigs are already contracted through fiscal 2014. Turning to our new build effort. We continue to make deliveries on time and on budget, including 11 new FlexRigs since our last webcast. We have 25 rigs that remain under construction that will roll off at a pace of 4 per month. As we mentioned on the last call, the ongoing rig rotation in the oil patch represents a kind of competition for new build orders as customers have taken a wait-and-see approach in terms of what rigs may become available. The added volatility and uncertainty we are discussing today has further quieted conversations at least at this point, and this is not a big surprise. Our experience reminds us that this also can turn around very quickly. In the meantime, our ongoing construction effort buys us some time. We suspect that the entire land industry is dialing back on new builds, resulting in around 150 AC drive rig deliveries for 2012. It's too early to predict 2013 except to say that the number of industry deliveries will be significantly less. Our own expectations after our last scheduled delivery in February 2013 are for things to start slowing but find traction as the year progresses. Our integrated effort affords us an important flexibility that should serve us well. Before turning the call back to Juan Pablo, you may have seen where we repurchased 1.75 million shares of stock during the last quarter at an average price of $44.40 per share. We believe the implied market value of the fleet at those levels makes it an attractive option. As we go forward, our preference would be to focus on building iron and what we believe is an ongoing replacement cycle. At the same time, we'll try to find the right balance in managing our expectation for future excess cash flow in a manner that maximizes shareholder value by returning funds through dividends and opportunistic share repurchases. At this point, I'll turn the call back to Juan Pablo.

Thank you, Hans. Our record result during the third fiscal quarter were primarily attributable to our U.S. Land segment, where we experienced continued improvements in average pricing and activity levels along with better-than-expected daily rig expenses. At this point, however, and given the mentioned uncertainty around current market conditions, we are not expecting additional growth in income from continuing operations during the fourth fiscal quarter. Our capital expenditures estimate for fiscal 2012 remains at approximately $1.1 billion, and total depreciation for the year is expected to be slightly under our prior estimate of $380 million. Our general and administrative expense estimate for the year remains at $110 million, and our interest expense estimate, which is net of capitalized interest, remains at $10 million during fiscal 2012. Our income tax rate for continuing operations for the first 9 months of the fiscal year and for the third fiscal quarter were at 36.2% and 35.1%, respectively. We expect the tax rate for the fourth fiscal quarter to be between 36% and 37%. The slightly lower effective rate for the third fiscal quarter was due to an increased level of operations in states with lower tax rates and an increase in a tax benefit due to revised annual income estimates. I will now turn the call over to John Lindsay, and after John's comments, we will open the call for questions.

Thank you, Juan Pablo, and good morning, everyone. I will highlight the third fiscal 2012 results for our 3 operating segments, U.S. land, Offshore and International Land, as well as the outlook for our fourth fiscal quarter of '12. Beginning with our U.S. Land segment, third fiscal quarter results where revenue days increased 2.5% to 21,977 days, representing 241 average active rigs in the third quarter as the U.S. Land segment took delivery of 11 of the 13 new build FlexRigs completed during the quarter. The other 2 FlexRigs were mobilized to the Middle East, and I will update further in the International segment. In U.S. Land, an average of 160 rigs were under term contracts, an average of 81 rigs were in the spot market. Average rig revenue per day increased by $471 from the second to the third quarter to $28,096 a day. Early termination revenue accounted for approximately $140 a day, and average rig revenue per day for rigs working on term contract during the third fiscal quarter was approximately 6% higher than the average rig revenue per day for rigs working in the spot market. Average rig expense per day decreased $489 sequentially to $13,337 per day after experiencing higher-than-expected daily cost levels during the first part of the quarter even in the midst of an ongoing cost management efforts. We were pleased to see favorable results during the latter portion of the quarter. There were no significant onetime adjustments in our U.S. operating cost. Average rig margin per day increased by $960 sequentially to $14,759 a day. As a result, U.S. Land operating income increased 12% to $236 million. As of today, the company's U.S. Land segment leads the industry in active rigs with 241 contracted rigs and 38 idle rigs. The 241 contracted rigs include 157 under term contracts and 84 operating in the spot market. Of the 84 rigs in the spot market, 82 are FlexRigs. Only 2 of the 84 rigs in the spot market are drilling wells targeting dry gas. Also, we estimate 15 of the 157 rigs under term contracts are drilling wells targeting dry gas, but none of these 15 rigs roll off of their term contracts during the remainder of this fourth fiscal quarter. Our fourth quarter U.S. Land activity outlook begins with the scheduled construction and delivery of 4 new FlexRigs per month. Overall activity outlook is dependent upon the direction of oil and gas prices and their impact on the drilling market. The number of revenue days for our U.S. Land segment may increase or decrease by a few percentage points during the fourth quarter as compared to the third fiscal quarter. We would expect a slight increase in quarter-to-quarter average activity and revenue days if the drilling market stabilizes, but would expect a 1% to 2% decline if the market continues to deteriorate. In response to softening oil prices, several of our customers have taken an even more disciplined approach to their budgets and are using this opportunity to trim their active rig counts. In some cases, operators are high grading their existing fleet of SCR and mechanical rigs, providing an opportunity for AC drive FlexRigs to gain market share. However, as a consequence of this high-grading trend, we stacked several SCR rigs, which include Flex 1 and Flex 2 rigs. With regard to that rigs working on term contracts, we expect to have at least 162 rigs working on term contracts in the fourth fiscal quarter of '12 and 153 rigs working on term contracts for the first quarter of fiscal '13 and an average of 131 rigs working on term for the remainder of fiscal '13. Excluding costs that are passed on to customers, we're going to expect revenue per day for our rigs on term contracts to increase by approximately $150 a day on average in the fourth quarter of '12 and by approximately $400 per day in average for fiscal 2013. Both of these increases are as compared to the third fiscal quarter average. Excluding the impact of early termination fees, we expect average rig revenue per day in the fourth quarter to remain roughly flat due to spot market pricing softening and term pricing continuing to increase. At this point, we expect early termination fees to be in the $7 million range during the fourth fiscal quarter. We expect average rig expense per day for the U.S. Land fleet to be in a range of $13,500 to $13,800 per day. This range of expense levels take in to account seasonality and market conditions, as described earlier. Our FlexRig new build program continues to lead the industry in delivering advanced technology AC drive rigs on time and on budget, including the 3 new builds announced on May 21. 25 FlexRigs remain under construction are currently being completed at the rate of approximately 4 FlexRigs per month through the end of the calendar year '12 and 4 rigs are scheduled to deliver in 2013. Since January of 2006, H&P has built a total of 221 AC drive new build FlexRigs3s, 4s and Flex 5s. Our rig construction, safety and operational expertise have allowed us to capture over 40% of the industry AC drive market share in the U.S. The industry AC drive market share has doubled since the 2008 peak rig count to 30% market share today. SCR and mechanical rigs have lost market share during this replacement cycle and the long-term metrics point to that trend continuing. Now a review of our Offshore segment, third -- for the third fiscal quarter, where Offshore operating income decreased approximately $2.1 million to $7.7 million. And the outlook for our Offshore segment as of today, the Offshore segment has 7 rigs active and 2 rigs stacked, although one of the stacked rigs is expected to mobilize in the fourth fiscal quarter. In the fourth quarter, we expect Offshore revenue days to increase by 10% to 15% and margin per day to increase by 15% to 20%, as one recently mobilized rig goes to a full operating rate in August and an additional rig begins mobilizing in August as well. The International Land segment, the results from the second fiscal quarter to the third fiscal quarter increased by approximately $7.2 million. The primary factors driving the increase were activity and margins, revenue days increase 5% to 1,852 days, average rig margin per day increased $2,820 to $7,704 per day. Included in this average, rig margin per day is approximately $800 per day of net positive one-off retroactive adjustments. Now, the outlook for the International segment as of July 27. The company's International Land fleet has 29 total rigs, 23 are working and additional 3 rigs are under contract, with activity ranging from waiting on location to rigging up and 3 conventional 3,000-horsepower rigs are stacked in Argentina. Of the contracted rigs, 7 are in Colombia, 6 in Argentina, 5 in Ecuador, 4 in Bahrain and 2 in both Abu Dhabi and Tunisia. The mobilization of the 2 FlexRig3s from our new build facility in Houston to Abu Dhabi is on schedule. The first rig has spud its first well and the second rig should spud mid-August. In the fourth quarter of fiscal 2012, we expect International Land revenue days to increase by 5% to 10% and average daily margin to be down 10% to 15%, primarily due to the absence of the positive one-offs in the previous quarter. In closing, and as we think about the current uncertainty in the industry, our efforts will continue to be directed toward delivering compelling performance for our customers and shareholders. Our people, processes and FlexRig technology create a competitive advantage for the company. The shift to drilling more complex unconventional resource plays that require the drilling at horizontal and directional wells only magnifies our competitive advantage. There is indisputable evidence that a large percentage of the old conventional rigs and lower-end technology product offerings are being displaced by new technology AC drive rigs. This replacement cycle provides additional market share capture for H&P and especially in a soft commodity price environment. And now, I'll turn the call back to Juan Pablo.

Thank you, John. And now, Tasha, we will open the call for questions, please.

[Operator Instructions] We'll take our first question from Luke Lemoine from Capital One South.

I guess, Juan Pablo, I'm trying to maybe reconcile some of the U.S. Land margin guidance that was given at the end of June. It's supposed to be flat and had a very nice increase of about $1,000. Was that mainly just maintenance deferral in the fiscal 4Q since the OpEx is kind of bouncing back to fiscal 2Q levels?

Well, John, may wish to add something to this, but it was mostly driven by a very nice decline in operating expenses per day, which resulted from the latter part of the quarter reflecting very favorable numbers. We had seen relatively high numbers during the first part of the quarter and we thought it was prudent to guide accordingly, but the results of later were very favorable. John, would you like to add anything?

Luke, I might add, if you look at, and we've talked about this before, look at the several quarters, don't just look at the last quarter or the last couple of quarters. But if you look at it over a 4-, 6-quarter run rate, you'll see a range of expenses. And last quarter, we were on the high end of that range, and this quarter, we were on the low end of that range. And so just a lot of variables, lot of moving parts quarter-to-quarter, and the field operation and everybody in general, just, they've continued to work the costs side really hard. And as Juan Pablo said, the second half of the quarter, things came together for us.

Okay. And then Juan Pablo, I guess, I'm sorry if I missed this, but what was the after-tax value of the equity portfolio?

As of recent weeks or days, it was $281 million approximately.

We'll take our next question from Robin Shoemaker with Citigroup.

I wanted to ask, John, you mentioned you have some early termination fees in the current quarter and how many long-term contracts have you -- do customers want to buy out at this point? And are there any of the rigs currently under construction for customers where there is an indication that they would like to buy that out?

Rob, and I'll start with the last. We don't have any, what I would consider, real long-term contracts and we don't have any that are getting ready to deliver that we've had any customers even hint at being interested in and exiting those rigs. They have plans for those rigs, and in a lot of cases, as I have mentioned before, the plan is to high grade the rig fleet when those rigs are delivered. As far as the other rigs, and it's really very similar in the third quarter going into the fourth quarter, you're looking at a relatively small number of rigs, and typically, the rigs have very -- I think last quarter it was 45 days on average and I don't know what the average days are left on for fourth quarter thus far, but they're reaching the end of their term. And so if you think about what our customers are doing in general is, they're looking at their rig fleets and then they're trying to figure out what rigs make the most sense. They have other rigs that are on term contracts as well, and so a lot of times it just happens to be that because of the budget discipline that I described, you just kind of be the one that's left without a contract and they end up early terminating it. So it's a relatively small number of days left on the term contract in these cases. It isn't like what we saw in '08 and '09, where we saw multiyear term contracts being early terminated and there was no work to be done. That's not the case here. There's work to be done, it's just in a different budget cycle. They're just looking at trimming budgets.

Yes. That was really what I was getting to and a few other land drilling contractors have mentioned some early terminations, but it doesn't seem to be anything on the scale of what we saw in 2008 and '09. So I guess my other question then just has to do with the rigs that are -- you have, I think, 157 FlexRigs on term, something like 113 on some kind of spot or related pricing contract is, what kind of -- from let's say beginning of the year, late last year, what kind of percentage decline has occurred in the spot pricing of rigs and maybe it varies by basin, but some kind of general indicator if you can?

What timeframe, Rob?

Wherever -- I mean, before this land rig count started to come down a bit, so maybe toward the end of last year or...

Spot pricing in general for us has been increasing during the course of the year until just recently. We've seen some softness and we talked about that even, I think, in the last call. We said that we saw some softness, but we really hadn't seen spot pricing impacted. But we are starting to see some softness in spot market pricing now, and we would expect again in the current commodity price environment we would continue to expect to see a little bit of softness.

But not, I guess, to the point where you would consider stacking a rig as opposed to working it at some kind of a low spot rate?

Well, I would say, in most cases, the rigs that we're stacking, first of all, we've stacked SCR rigs, we have stacked some AC drive rigs and they're kind of in a transitional period. I think most of those AC rigs will go back to work, but I think in a lot of cases, it's just the work is not there. It's really not a function of pricing. I do see that we have some competitors that are, I think, pricing very aggressively in some cases and in some basins. But I think, in general, in our case, we've been able to hold our spot pricing pretty firm.

We'll take our next question from Joe Hill with Tudor, Pickering. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I noticed your non-rig operating costs in U.S. Land were pretty high this quarter. Usually, they run around $2,500 to $3,000 a day, but it looks like you hit $4,000 a day. Is there any reason for the discrepancy here?

Joe, this is Juan Pablo. I'm not sure that there's a discrepancy there. It just -- we just happen to see additional costs that actually are at the operator's expense, our customer's expense, but we just happen to pay for them and are reimbursed for those. And so that can include items related to transportation and the other equipment rentals, et cetera. We're just seeing more of that, but there's no discrepancies. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Got you. Okay. And then, if we look at the 4 rigs that got early terminated in the quarter, how many are associated with the $7 million in Q4?

The total number of rigs? Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Yes.

Joe, there is none of those associated with the $7 million. The $7 million refer to the fourth quarter. I think what you're referring to is what impacted our third fiscal quarter. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Correct. So are we talking about termination payments continuing from the 4? Or are we talking about incremental terminations?

Incremental terminations. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. So we had 4 rigs terminate in Q3 and then we're going to have incremental rigs terminate in Q4 and I wanted to know the number.

It's another 4 or 5 included in that number. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And if we think about the terminated rigs as a group, can we ascribe any particular geographic location to these?

Kind of been across. Kind of been across the board, Joe. That really hasn't been just focused in one area. Again, I think, just consider the number of customers that we work for and the number of rigs that they have working and they look up at a budget and say, well, we're going to have to trim this back. I mean, I didn't mention this in my comments, but part of what's driving this is obviously the commodity prices, but we're also drilling wells much faster than anticipated. So that, obviously, increases your spend during the course of the year. So there's some positive there too, and that we're delivering wells more efficiently and cheaper, but we're just drilling a lot more than anticipated. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: John, are you having trouble taking those rigs that have terminated and turning them and losing to spot market? Are these the ones you're stalking or are these going back to work?

Yes, we've been very successful in putting AC drive rigs back to work, particularly Flex 3s. And as I have said in the comments, we've seen opportunities to high grade. A lot of customers have used this as an opportunity to get rid of underperforming rigs, mechanical and SCR rigs. And so it's been a great opportunity for us. Obviously, we do have some AC rigs that are stacked, and we'll continue to have some at least for the next -- at least what we see the next 30 to 60 days. Again, this is an attractive market for us. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And one last question for me. John, how do you assess demand? Do you keep track of the total number of bids you guys have outstanding or RFPs or something like that? And can you give us some color on how much that's fallen off in the last quarter?

I don't really have a -- I don't have any specific metrics that I can speak to, but there's no doubt that the bid -- the bid activity is down. What's going on is, it's high grading. There's an occasional bid here and there, but it's kind of this transitional rigs getting released and our marketing guys going after great job and finding opportunities and putting rigs to work. Obviously, on the new build side, there's not a lot of bid activity. We did have one here recently, I guess, in the last couple days for 2013. But I mean, in general, a new bid activity, as you can imagine, is very low right now.

[Operator Instructions] We'll take our next question from Kurt Hallead with RBC Capital Markets.

Just a general question here. As you guys are mapping out the rest of the year and doing the best that you can to kind of gauge some of the sensitivities [indiscernible] and so forth, what do you think prospect is that from this point through the end of the year that the E&P industry essentially just continues to, if you will due to high grading, just lack a sense of urgency, kind of ride out the rest of the year so that there isn't really much in the way of, I think, demand and that the softness continues. If I put that into context of the fact that there's been a significant bounce, obviously, in oil prices back around the $90 level, the strip price for natural gas is well north of $3, I just want to get a read from you guys as whether or not you think the E&P industry will start to get a little bit more optimistic before year end or this will continue to wade out this year and maybe kind of build up their cash and hit the ground running come the first quarter '13, what's your take on that?

Kurt, this is Hans. I think you hit on the most important element in your question in terms of oil prices and what level they're perceived to be at so going forward. So I think, psychologically, when we saw oil prices, WTI get under $80, it caused quite a bit of pause. And I think, certainly, people are looking at the last part of their 2012 budgets, but I don't think it might be as bad as you suggest just in terms of, hey, let's just kind of store up and wait until '13. I think people are trying to wade through the uncertainties, watching oil prices closely. One of the things we do here from customers is they don't want to over correct on the downside where they try to spool up too much. And like I said, over correcting that regard, so I think it's going to be oil price driven but not quite as bad as people might think.

Okay. So in that context, once again, it appears that they're going to eventually just kind of glide into year end, reassess their portfolios and their opportunities try to get, as you mentioned, high grade the rigs where they can and then take a look at what the strip pricing, the outlook is coming November, December, then probably hit the ground running. I don't want to put words in your mouth, but I think that's kind of what you maybe -- hopefully what you maybe alluded to.

Yes, I think you said it better than I did, so yes.

I think the other -- the third question I had was in relation to your operating cost management process because, once again, as to the first question on the call, the guidance points for the fiscal third quarter were indicating down and margins were much better and deposit is much better. What is it that you're doing that we would expect -- can we expect another reduced operating expense performance? And what do you guys focus on internally, I think, is really the question? So what's driving this reduction in operating expense?

Well, I mean, it's a fair question. And like what Juan Pablo said, when we saw the very early indications in the first part of the quarter, they were at similar levels to the prior quarter and slightly elevated from that. And we knew we had a focus on cost reduction in the field that had not gained much traction at that point. So we elected to let you guys know what we saw in terms of the visibility we had at the time. The last 6 weeks of the quarter, we did get some traction and things improved. And so there's a little bit of we'll do more of that and that's our intention, but we've also tried to make clear for the last couple of calls that the volatility and the rig rotation, it can drive some higher cost for us and it's not so easy to predict. And so if we have more rig rotation than we might have anticipated, like we mentioned before, you're going to have some issues on crew retention, you're going to take advantage to spend some money on a rig that's been working all out and it's going to drive some expenses. But clearly, we're being more focused and disciplined on that now and we would expect those efforts to continue to pay dividends. So the ranges that we gave going forward, again, I think John put it in the proper context, you look over a number of quarters and there are 240-plus rigs running out there and there are lots of moving parts, but I think we are gaining traction on improving on MNS and purchasing and cost management. And so we think that, that will be a benefit, but we also know that there's still some rotation and uncertainty. And so it's just we're doing our best to give you guys the best feel of what the go forward looks like, but that's the best we can do.

[Operator Instructions] We'll take our next question from Michael LaMotte with Guggenheim Securities.

I guess, can you address the willingness to re-up on term, what the appetite looks like for 3 year, 1 year kinds of work or is everything essentially rolling over into spot and was spot holding up relative to contract?

Yes. I think things were rolling into spot at this stage of the game unless they're just special situations.

We have in a few cases, Michael, we've got 6-month term. Obviously, you don't see anyone going in for 2 or 3 year, but there are some. Some of our customers that as rigs are rolling off or as they're contracting rigs that have gotten released, then they're looking at 6-month term contracts but nothing major.

Okay. And given where gas and NGL prices are, are any of your customers talking about moving the rigs from the Eagle Ford to the Permian?

We have seen some of that over the course of the summer we've also seen some of that moving out of Oklahoma, moving into the Eagle Ford or moving into the Permian. Those were heavily influenced by NGLs.

Okay. Hans or Juan Pablo, how much of the buyback is left? How much dry powders are left in the program?

We have authorization for 4 million shares, and typically, what happens is that gets renewed with board meeting cycle. We've got board meeting in early September, so that's been our historic experience.

Okay. So $4 million is what's left outstanding or $4 million was the program we should back out this quarter's purchases.

Yes, back out this quarter's purchases from the $4 million.

Okay. And I guess the last question for me is probably is for Juan Pablo. If we look at the pace of new construction slowing down into 2013, how does that impact your cash tax rate?

There are many moving variables, so I'd hate to give you any particular guidance there. We do expect to continue to benefit from accelerated depreciation for tax purposes, for cash tax purposes. But I couldn't give you a specific answer at this point. It will vary depending on many moving variables.

Okay. But the 2 big pieces are accelerated depreciation and the capitalized interest, right?

Well, the capitalized -- the latter is -- excuse me, the former is really what drives it, not the latter.

We'll take our next question from Tom Curran with Wells Fargo.

Hans or John, as the largest landlord in the Eagle Ford, I think you are in a unique position to best understand and proper insight into that market. So 2 questions there. First, on the demand side, about how much of that demand at this point do you estimate is NGLs driven, and what would seem to be the price thresholds below which you would expect to see a significant cut to activity? And then on the supply side, how far along are we with the influx of Tier 1 rigs from both the dry gas markets that have been in down trend for some time now, as well as possibly the northeast where the Marcellus has been overwhelming the Utica

Tom, this is John. I think on the Tier 1, from our perspective, most of the move from dry gas to oil and liquids rich, I would say most of that transition has taken place for us. We don't have much exposure to dry gas today, and most of that has already taken place and a lot of those rigs moved to the Eagle Ford and to the Permian, a few into Oklahoma. We have had a couple of rigs move out of the Marcellus into the Utica, but we never had a large footprint in the Marcellus to start with. So does that answer your question on...

We'll, I actually meant at the industry level, so looking at the Eagle Ford market as a whole, what is your sense of how many more Tier 1 rigs we might see enter from competitors, particularly out of the northeast where rig releases in the Marcellus had been occurring at a pace of 3:1 with regards to additions in the Utica.

Well, it's a natural place to source going from Marcellus to Utica. I don't really have a feel for it. I think it's going to be demand based on what the Utica is needing. I mean, the Utica seems to be moving a little slower than what I had anticipated, and so that's a kind of a tough one, but that's where you're logically going to get the rigs sourced from is from the Marcellus to go to the Utica. But I don't have a real feel for it. As far as you had mentioned, sourcing into the Eagle Ford, again, I think that's relatively small at this stage based on the rig count. I think there's some high grading going on as well in the Eagle Ford. We've seen quite a few examples where we've high graded competitor rigs when we've had Flex 3s or Flex 4s come available.

Okay. And have you gotten any read on the demand side when it comes to the NGL directed activity as to significant price levels for your customers?

We haven't seen that much. I think most of our rigs are -- a greater percentage of the production is oil in the Eagle Ford, and so we don't have as much exposure to NGLs. I do recall some time during the summer earlier in the year that we moved a few rigs out of the Eagle Ford that were in NGLs to the Permian, but I don't really have a feel for overall in the industry. I just really have a feel for what we have.

Okay. And then I'll just conclude with U.S. wide. How much additional Tier 1 capacity seems likely to come into the market between now and year end that's not in the hands of the big 4? And have you been recently seeing any of those rigs entering without contracts?

Well, I think we know, Tom, that our new builds are going in without contracts. And as we look at AC drive rigs, I think we gave a number out of 150 in 2012. You're asking now kind of outside the big 4 and are there some private guidance. Our sense is that's pretty de minimis and maybe it's 20 or less and how many of those are really AC drive rigs versus some refurbished effort is hard to know. So that number may even trend further downward as the rest of the year plays out and maybe those rigs move to the right and find deliveries in 2013.

Okay. So an already relatively small number that could get even smaller as you might have cancellations or deferrals?

Yes. I think that's right. And then, I think, it sets up for a very modest number of new builds at least in the first part of 2013 just because of this present climate.

We'll take our next question from Michael Fomuk with Wolverine Asset Management.

I understand it's a different business, contract durations. They're a little bit shorter or a lot shorter and smaller, but I just wondered if you could tell me if you're watching the sea drill proposal with more than a passing interest?

Well, hey, look, a little attention to offshore peers, but you're talking about their MLP?

Yes.

No, not really. I mean, I think that they're a unique player in that space and I don't know if it translates, at least to this point, it's the land side.

Is there a point clearly when there's an up-cycle again where you could foresee visiting something like that?

I think we're pretty open minded, but we expect for there to be an up-cycle, and I think we've got a pretty good approach in model for attacking that. So that would be our intent at least at this point.

We'll take our next question from Brad Lundy with Ivory Capital.

Just on a quick follow-up on the buybacks. Did you guys repurchase any shares following the quarter end?

Well, no, we have that blackout period that we abided by, so we've been out of the market.

Okay. So it's fair to say there's still 2.25 million shares left on the authorization?

Correct.

Okay. And then the context of the board meeting in early September, is this just a normal meeting or is there a more in-depth evaluation of the capital structure at that point?

No. It's really an ongoing conversation we have with our board and they're engaged in these issues and so there's nothing special about it.

And it appears we have no further questions at this time.

All right. Well, thank you very much everybody, and have a good day.

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