Good afternoon, ladies and gentlemen, and welcome to the Precision Drilling Corporation's Second Quarter 2012 Results Conference Call and Webcast. I will now like to turn the meeting over to Mr. Carey Ford, Vice President, Finance and Investor Relations. Mr. Ford, please go ahead, sir.

Thanks, Jasmine. Good afternoon, everyone. I'd also like to welcome you to Precision Drilling Corporation's 2012 Second Quarter Earnings Conference Call and Webcast. Participating today on the call with me are Kevin Neveu, our President and Chief Executive Officer; and Rob McNally, our Executive Vice President and Chief Financial Officer. Also present are Gene Stahl, President of Drilling Operations; and Doug Strong, President of Completion and Production Services. Through a news release earlier today, Precision Drilling Corporation reported on the 2012 second quarter results. Please note that the financial figures are in Canadian dollars, unless otherwise indicated. Some of our comments today will refer to financial measures, such as EBITDA and operating earnings. Please see our press release for additional disclosure on these financial measures. Our comments today will also include statements reflecting Precision's views about events and the potential impact on the corporation's business, operations, structure, rig fleet, balance sheet and financial results, which are forward-looking statements. There are risks and uncertainties that could cause actual results to materially differ from those indicated by such forward-looking information and statements. Please see our press release and other regulatory filings for more information on forward-looking statements and these risk factors. Rob McNally will begin the call with a brief discussion of the second quarter and operating results and a financial overview. Kevin Neveu will then provide a brief business operations update and our outlook. Rob, over to you.

Thanks, Carey. Precision had a very solid second quarter, notwithstanding the headwinds from lower oil prices and continued weak gas prices and a wet spring in Canada. We reported revenues of $382 million and net earnings of $18 million, or $0.06 per diluted share. Earnings per share were positively impacted by $0.01 by a foreign exchange gain. Second quarter 2012 EBITDA was $97 million, which is the highest level of EBITDA the company has ever achieved in the seasonally slow second quarter. The improved Q2 results primarily reflect stronger pricing, both in Canada and the U.S., versus the second quarter of 2011. EBITDA margins were 25% this quarter versus 27% in the second quarter of 2011. Margins were impacted by international start-up costs, increased maintenance costs in the U.S. and costs associated with directional drilling in Canada. We did not generate positive EBITDA in our International business in Q2 because of the start-up cost associated with mobilizing 5 additional rigs. But we are optimistic about the outlook for our International business in Q3 and going forward, with 8 rigs currently running. In the U.S., during the second quarter of 2012, drilling revenue improved by over $1,000 per day versus the second quarter of 2011. Year-over-year margins declined by 400 per day, largely driven by a wage increase in late 2011, a higher percentage of rigs working at high cost basins like the Bakken, and higher maintenance costs. Versus the first quarter of 2012, U.S. drilling day rates were essentially flat. In Canada, in the second quarter of 2012, drilling revenues improved by over $2,000 per day year-over-year and margins improved by almost 1,300 per day. Drilling days in Canada were down 5% in the second quarter of 2012 versus 2011 due to an earlier spring breakup and wetter spring than…

Thank you, Rob. Good afternoon. As Rob mentioned, despite headwinds in our core markets and flattening customer demand, Precision delivered the strongest EBITDA cash flow performance in the second quarter in our history, and not surprisingly, our highest revenue following the mid-2000s divestiture of the Technology Services' international drilling rigs. So as we look back in the second quarter, there are some important takeaways that speak to the effectiveness of Precision's growth strategy. Resilience and continued demand for Precision's growing Tier 1 rig fleet was validated during the quarter. And I'll speak more on that in a few moments. Precision's enhanced ability to reduce capital spending in light of an abrupt market change was demonstrated well in 2009's downturn, and again, the first half of this year. And most importantly, the sustainable shifts in Precision's second quarter cash flow versus Precision's historic Q2 cash flow are the direct result of our strategic growth outside Canada. So before I move to our regional performance update, let me speak to these takeaways and help you understand how our growth initiatives are delivering results of Precision. So first of all, regarding the Q2 seasonality in Canada. Operating solely in Canada is a serious challenge for oil service companies. For Precision, our Canadian activity took great plunges, between 60% and 70% for the first quarter peaks to second quarter troughs, while our cash flow reduction were even more severe. This abrupt seasonal cycle in activity drop has taught Precision's people to develop systems to deal with the rapid abrupt changes in customer demand. Following breakup, our forward visibility often remains cloudy and subject to the vagaries of rainy Canadian spring and summer weather. As a result, our Canadian-based activity is often handicapped by 2 quarters of seasonally depressed and unpredictable activity. With our recent…

[Operator Instructions] The first question is from John Tasdemir of Canaccord Genuity.

I guess I just have a couple of questions. Couple of crosscurrents in the U.S., you kind of said that you do expect some modest utilization improvement as some of those rigs get redeployed from the Marcellus. But you also said that spot rates are coming down a bit. How do you -- how should we think about margins kind of progression from second to third quarter? I mean, same? Get better? Help me out.

John, this is Rob. Yes, I think you really have to think about it in terms of the tier of rigs and where they are. I think the Tier 1 rigs are going to hold up better than others, although there may still be some pressure. But the Tier 2 and Tier 3 rigs is where we would expect to have the greatest pressure. And then I think it's going to also vary by basin. My overall sense is it's going to be flat to down-ish for blended margins and not likely that we're going to see it move up.

Okay. And ultimately that, I guess, persists until activity starts to pick up and utilization across the board for drilling activity improves?

Yes. I think that's a safe assumption. I'll tell you that every customer call we make these days when eventually the oil price is getting below $80. So it's a great opportunity for the customers to work hard on leveraging down prices, and Precision will maintain discipline and focus on our margins, focus on our margins and returns, with less emphasis on utilization.

Okay. Would you -- I think one of your competitors said they were kind of saying, say, 10-ish percentage kind of drops the spot pricing on the Tier 1s and maybe 15% on the lower end. Is that consistent, or is there a difference between Canada and the U.S.?

John, I think it does become quite regional. You can expect pretty firm markets in places like Bakken, West Texas, a little more softness in the Eagle Ford as you look at prices, certainly anything that's remotely gassy will be under more pressure. Spot market in Canada, uncontracted. I gave some guidance on that, but we've got a pretty good lock on Canadian prices through the third quarter right now. I'll fall short of giving you a clear guidance on what we think the drops are going to be, but I do think our Tier 1 ratio will look quite well.

Okay. And then, I guess, just one other question, and I'll turn it to someone else, just would you remind me on the International day rates, working internationally, when they show up in your results, are they counted in the U.S. operating days and operating cost per day, or is that other?

It falls into the other category, John.

The next question is from Jeff Spittel of Global Hunter Securities.

I want to ask a little bit about your repricing exposure as contracts are set to expire. Are there any particular areas given the different dynamics, regionally, where you have a disproportionate concentration of rigs that are set to expire in either a basin where things are holding up a little bit better, or an area where things are a little weaker?

Jeff, good question. I think we've come through the quarter where our Marcellus rigs were mainly set to roll off. And then we're pretty well balanced around the U.S. and Canada right now. Fairly equally balanced among all the areas. John D. Lawrence - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Good to hear. And then switching over to the new build, too, can you just maybe give us a little refresher on the progression of what's left to deliver and the disposition between Canada and the U.S. the next few quarters?

Yes so far, year-to-date, we've delivered 11 out of 20 of the rigs that are going to Canada. And we've delivered -- just to make sure I get the number right, 8 out of 15 that are going to the U.S. And then we'll have 2 additional rigs delivered early 2013 in Canada and 1 in the U.S.

The next question is from John Daniel of Simmons. John M. Daniel - Simmons & Company International, Research Division: Just wanted to see if I can get some color on the components of the sequential U.S. cash margin decline. Was there any one-off increases for things like workers comp or the like?

No, John. It's a combination of things. It was the increase in wages. It went through at the end of last year. We have a higher percentage of our rigs now working in higher cost basins like the Bakken. And then it's more extended reach horizontal drilling that drives up costs. It's harder on the equipment than some of the simpler wells. So it's nothing that I would characterize as a one-time item that's going to come out next quarter. John M. Daniel - Simmons & Company International, Research Division: Okay. All right. And then although you've not given financial guidance in the past, the last couple of quarters, as you talked about your CapEx, you would make the comments generally speaking that the CapEx spend wouldn't be significantly higher than cash flow in terms of you are now offset significantly. Now that CapEx has dialed back to 875, same logic holds, I presume?

Yes, John. Were conscious of trying to keep CapEx within a reasonable distance of what we think cash flow or EBITDA will be. John M. Daniel - Simmons & Company International, Research Division: Okay. And then just the last one from me, it's housekeeping more than anything, but you provided a contract coverage for all of the rigs for the next 3 quarters. Can you share with us the break down between the Canada U.S. and international?

I'll go through all of them as I repeat what Rob said. So in Q3 2012, we'll have a total of 122 rigs, 66 in the U.S., 48 in Canada and then 8 internationally. In Q4, it's 113 total, 57 in the U.S., 48 in Canada and 8 internationally. And then full year for 2012 will be 129 total, 70 U.S., 54 Canada and 5 internationally. And then for full year of 2013, it's 84 total, 31 U.S., 45 in Canada and 8 internationally.

I want to add on a small point here. We still see customers renewing contracts, renewing those contracts on terms. So we're not expecting that, that contract falloff to falloff at that rate.

The next question is from Dan McDonald of RBC Capital Markets.

I've got Kurt here with me as well. Just wondering when we look at the new build schedule here and the upgrades, what portion of those you think might be at risk to display some of your existing equipment as you've alluded to has been seen in the Bakken versus likely, or your expectations to be incremental to your rig count here in the back half of the year?

Dan, [indiscernible] in my prepared comments around we expect a modest increase in utilization. I'd be surprised if we see a lot more attrition to the current fleet. So I think most of it should go to the market to add on to what's going on now. Now, let me qualify that, in you see further pricing softness, I'm wrong.

Yes. I think if we get -- if we're kind of in a $80 or sub-$80 oil world, then I think that it's likely that we see the existing rig fleet continue -- the utilization continue to deteriorate some. If pricing is more robust, then I think Kevin's comment is right that we're likely to kind of have seen the attrition that were going through on our current rig fleet.

But I am really quite certain that we're not very good at forecasting forward energy prices, so we we're quite good at responding to them.

You and us, both. And then just looking at the new build market, given the 4 or the 5 that you just announced being in Canada versus the U.S., can we read through that the appetite perhaps for contracted new build is a little bit healthier up here in Canada or was it just a matter of customer mix, and it's more or less equal on both sides?

Dan, that's a good question. It might just be timing more than anything. If you're here in Canada you want a rig for winter 2013, you can order it right now. So we're kind of at a point in time when it's really important to hear orders in from Canada so you can have rigs for the next winter. So that may be the issue there. We have kind of a party list for our customers discussing new builds, and I've always been giving that information, the fast, the most. I didn't give it out today. But I'll give it right now. We still have a bunch of customers, I think it's 8 or 12 customers looking at somewhere right at 25 new builds. Now my expectation is probably we're going to skip up until the third quarter, but -- and maybe some of those are converted into upgrades or things like that, but the discussion on new builds has not gone to 0. And the large shot customers, you're looking at long-term plans. Still intending to use Tier 1 rigs. If they can get them in the other market they will build them.

The next question is from Dana Benner of AltaCorp Capital.

Perhaps, I missed it, but with respect to the 5 new builds that have been added to the tally. Can you give us a sense as to when those ultimately will hit the field, and is there any portion of the $875 million that -- I would imagine there is some long lead time items, et cetera. But is that mostly an '13 spend?

So, Dana, this is Carey. We expect that 2 of those rigs be delivered in the back half of 2012 and the remaining 3 should be delivered in the first part of 2013. And the cost associated with that are split about the same way, where the majority of the new build costs for the 3 rigs that are delivered in 2000 -- that the 2 rigs that are delivered in 2012 will be captured in the $875 million, and there'll be a carryover cost to complete those additional 3 rigs in 2013.

I think actually, Dana, the number is about $40 or $45 million that's going to carryover into 2013 to finish those rigs.

Right. One of the interesting stats you've given on prior calls is you've talked about the counter-party risk or lack thereof, with respect to the E&P client signing these contracts up. Is there any -- and I've seen on your call $25 billion market cap was the average counter-party market cap. In any case, is -- does that number change materially with these 5 new builds, or are the clients who are signing these up still very much in that vein.

Well, the first part of the answer is with the oil price pulled back, the market cap had shrunken a little bit. But go ahead.

Yes. So, Dana, they wouldn't -- this wouldn't move the needle on the size of our average customer deciding new builds. These are right the sweet spot.

So no material change?

No.

Moving to your service rig business, I guess, in one sense, a very pleasant surprise given the weather, but there may be some broader structural trends emerging with respect to the move to oil versus gas wells. So maybe you can address whether you think that this was simply -- or whether it was more a case of where the rigs were in relation to bad weather, or in fact this is part of the emergence of that structural trend of the move to oil and what it implies for the strength of your service rate business as part of the corporate whole.

Dana, Doug is smiling here, so I'll let him answer the question.

I think it's a real good indicator. It's early, but a really good indicator of the underlying strength in the production work. Yes, we had good weather in Southern Saskatchewan that enabled it, but it really -- the quarter represented a shift where we had reduction in abandonments, completions and the nice increase in production work, consistent with the number of oil wells that are coming online continuously, so a good development.

And just finally, you've teased us a little bit more with respect to your International business. Obviously, a good progress moving to the 8. Should we conclude that it's more likely that we would see growth in current international areas, or could it just as likely be a move to perhaps a third country?

Dana, at this point, we'll be focusing on the areas we're currently in and try to build out larger base. We're really pleased with where Mexico's gone. I'd love to see our Middle Eastern Arabian Gulf footprint expand. But remember, that even if I signed a contract tomorrow, it's 6 months or 1 year before the rigs get deployed, just depending on the spec and the scope. So this will be a small growth story for us, but a very nice business. We're not out chasing rapid growth, we're not out chasing, let me call them, low-margin high utilization type jobs.

The next question is from John Lawrence of Tudor, Pickering, Holt. John D. Lawrence - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Kevin, maybe a bigger picture question for you, on outlook for the U.S. gas rig count, does it feel like we've seen the worst so far or do you think there's another leg down?

Well, it's been pretty done so far but my sense is it will just keep on whittling itself down a little bit further. I'm not surprised [ph] the bottom June, but I think we're close to the bottom. John D. Lawrence - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, okay. Good. And then on the Tier 1 assets that are rolling off contract in the back half of the year, would you expect all those to find work, or could some of those potentially go idle?

I think it's really sensitive to the commodity price. If price is staying closer to $90, I expect that all those go back to work. If we see another dip down into the $70s, and we all know the risk of that is, then some of those rigs go idle. John D. Lawrence - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Sure. But you'd say in the current environment, most of them find work.

Those are very good rigs. They're doing a good job for our customers, most of those are on long-term drilling plans. I think they'll be just fine. John D. Lawrence - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And then just last one, any customers trying to back out of contracts for Tier 1 assets?

No. [indiscernible] that's an early indicator we've always watched for. And last time in 2009, we didn't actually have any backouts. We kept all of our rigs going. I think we have one by '09 [ph], so what they do often is they're a little tight or breakdown [indiscernible] standby for the rig, the margins standby. There are no indications of that. In fact, the rigs, wherever they are, the customers are trying to promote the location.

The next question is from Scott Treadwell of TD Securities.

Just a couple of maybe housekeeping questions. When I think about the rig fleet and the potential, as you've talked about the spot prices that continue to weaken, is it fair to say that the legacy contracts you've got today that maybe 1, 2 or 3 years old were probably signed at rates that are below where the spot prices today or has been for the last 6 months and then even if these things rollover over the next 18 months, it's going to take a while for the impact of that to be felt on the Tier 1 day rate. Is that a fair kind of broad assumption?

Well, you're kind of right, in that there's always some lag time between spot markets and contracts running lining the soft stock up again. So if we're early into a long-term soft period, it will take a while to wash itself through. But I wouldn't model in stable day rates, Q3, Q4, Q1 in a softening environment.

Okay. No, that's kind of what we've got. The other thing on the G&A side. I know you mentioned in the release that there was a reduction in stock-based compensation. It looked like the corporate kind of EBITDAR or G&A contribution was a $5 million drop. Was that all due to the stock base comp, or was there some sort of structural savings that we should be thinking about going forward?

The majority of that was based on the stock-based comp.

Okay. And just finally...

Scott, we hope that, that number reverses itself in Q3 for our investors.

Yes, perfect. Last one, the rigs that you've talked about having been displaced are seeing some noise in the Bakken. Those are all spot rigs, or are those contracted rigs that you're just -- the customer is waiting for a new location or a new play to get them back to work until you've got really strong visibility? Or are they spot rigs and you're just marketing them as we speak?

The majority of those are on spot market now. we're looking for work form in the Bakken and other places, but they're typically Tier 2, good Tier 2 rigs that now that have been replaced by new Tier 1 assets. And so we'll find a home for those eventually because they are good rigs.

Okay. And on the CapEx reduction side, you talked about the lowering in terms of long lead items. Fair to say that with low appetite for new builds, the time for some of these large capital items is probably going to be shorter going forward than it is looking back.

Yes, a little bit. But actually the rig build is out of business right now. The disposition of the suppliers, is actually there's still quite backlog and we're busy. Another service lines I go to be think things like that, it might be slowing down a little more, but things like top drives and mud pumps are still quite busy. You get later in the year and our credit program winds down -- industry winds down a little bit, those lead times will shorten a little.

The next question is from Tom Curran of Wells Fargo.

Kevin, how would you currently define Tier 1 in Canada, and based on that definition, what do estimate is the total industry-wide fleet?

We [indiscernible] definition is our Tier 1 rigs are the rigs that are designed for horizontal drilling with the control systems top drives and mud pumps to be highly efficient to drill horizontal wells, but they also have extremely high mobility, meaning they can relocate rig down, rig up and relocate and, typically in hours in Canada. I tell you that in Canada, a much larger component of the Canadian fleet is Tier 1. Many of our peers [indiscernible] raised to drill horizontal wells, we do. It's almost a result of the short winter season that requires so many wells to be drilled in such a short period of time. So I feel pretty good about the Canadian fleet being well-suited for its shallower drilling generally than U.S. drilling. Fast-moving, and deployable. But it is interesting that over the last 18 months, I'm running over this quarter, but then if you want I think we booked 55% of the new builds in Canada over about a 12-month period. Super Singles rig is just so well-suited for Canada that. Is there anything you can refresh me in our rig count in Canada for Super Singles? You check that, I'm just finishing up my comment here. 66 rigs. I think in that category, we have a very strong position on market share.

Would you estimate that it's roughly in line with what your win rate has been for new builds?

Probably a little less than that. Our win rate on new builds going to be less than our share of Tier 1 rigs. Because we've been so successful with that Super Single. But the last quarter for Canada are also for Super Triples, so we have a lot of work to show up here.

Right. That's helpful. Rob, please remind us. When it comes to your standby rates, how did those work, and what's the range? And then in Canada, how much flexibility do you have on labor-related cost between now and when you would renegotiate wages with the unions, and when is that next renegotiation period?

I'll answer the question backwards, Tom. And there aren't unions that we're dealing with in Canada. The wage rates are recommended by the CAODC, and that happens in the fall each year, I think it's in October. So that will be the next time that we look at wage rates, and that will move kind of coupled with what's happening in the market, both in the labor market, as well as for rigs. So that won't be addressed until the fall. And -- sorry, what's the first part of the question? Oh, standby, I'm sorry. It's, respectively, it's the margin. So if we're going to accept -- if they're going to accept the rig down, they'll pay us the margin and the costs essentially go away.

But it is 100% of the margin expected in the contract at full utilization?

That's correct.

Okay. And then last one for me, could you please give us an update on how your growth expectations for the directional drilling business over the balance of 2012 has changed, if at all, as a result of the second cut to your CapEx budget?

We've pulled that down to reflect the market conditions and also to show that we can be flexible on our capital spending. So it's a couple of important strategic moves for us. But, Carey, remind me, we began the year at about 70 kits?

A little shy of 70, now we're at 81.

81 now, and likely finish the year a little over 100 kits.

And, Tom, I just want to have one clarifying point. In Canada, our Tier 1 rig fleet is just shy of 90 rigs. So I think we're at 87 rigs today.

Including Tier 1, Tier 2 -- including Tier 1 and Super Singles.

Right. The Super Singles would be kind of in the low 70s, high 60s, low 70s.

So the total industry is probably at somewhere between 180 and 200?

I'd still go back and look but that's not a bad estimate.

I'd say use round numbers, 200 is probably is a good number.

The next question is from Kevin Lo of FirstEnergy.

In your commentary, you're talking about you have decent visibility into Q3 in just the pricing, can you kind of share with us what that is in Canada?

Kevin, I think the pricing status last fall will carry through this fall. Unless there were a dramatic reduction in the oil price, and I mean a real collapse. I think our pricing in our contracts stays firm through the October renegotiation. You may recall that in the past I generally think the activity and demand in Q3 is a good proxy for Q1, following winter. So that will help us understand what pricing looks like in October. So if we see that price stay stronger in the orders activity, slightly picks up a little bit and we have pretty good summer. That's a good proxy for the winter, which we forecast at strong winter all driven by commodity prices. And in that environment, you might see rates go up a little bit and day rates go up a little bit. [indiscernible] Certainly that will continue moving along with what we're seeing right now and likely flat labor increases in October and likely flat labor increases, if you're modeling in a structure on the price oil, that's your off.

In terms of your day rates and expenses in the U.S. how much of that was attributed to R&M versus pricing or other cost issues?

Depending on if you look at it sequentially, from Q1 to Q2, the majority of that is R&M. If you look at it year-over-year, where it's a bigger increase than you have call it 1/2 or a little more is due to though wage increase that came through the end of 2011.

In terms of utilization for the rigs in the Marcellus, and you're looking to deploy some of those rigs, how many of those rigs do you think you can deploy next few months here?

I think it will be a handful. Looks like on our current rig count, Marcellus, we have 7 rigs, and there are a couple of rigs are being deployed right now. So I think it should stay kind of single-digits, Kevin. But I think we might be wrong in reaching the trough in the Marcellus, it remains for lower cost basis in the U.S.

And I apologize...

For our customers, that is.

Okay. I apologize if you guys answered this already, because I was trying to go [ph] down. But how many of your rigs that you're building right now are not contracted?

0.

So all the rigs that you're building right now are lapped contracts by the end of it.

We have been very consistent in not building any rigs on spec, so there's 0 rigs that are uncontracted.

Yes. We did have earlier those long lead type programs that are now closed down. And we did have a potential European spec rig that's out of the budget. But as far as our current rig program and our current capital budget, everything is contracted.

Okay. So in your commentary and your MD&A when you were talking about you do still see new contracts available, so any of that you would have to increase your capital program yet again?

Well, I don't think any additions that we'll make. If we build 5 more rigs in Q3, for example, that's not impossible, but I don’t think it will happen. If that were to happen, it's not going to happen, that's likely 2013 capital, not 2012 capital.

[Operator Instructions] The next question is from Dave Wilson of Howard Weil.

Just wanted to follow up on the International and the 8 rigs working there. With the start-up cost behind you, can you share what level of EBITDA you expect to be generating from the International business?

I won't give you any specific numbers, but these are all good-sized rigs. Think of them like 1,500-horsepower North American rigs or a little more than that.

Okay. And I know you kind of mentioned it earlier, but is it still too early to talk anything concrete about adding more rigs to either of those areas?

Well, we're seeing a very strong customer inquiry, interest right now. We're bidding a lot of things out. We're going to focus on kind of building out on our current places in Dubai and in Mexico. Unless something else came along, there was a serious concentration of activity that give us a third leg, but you expect to see some growth in areas we are in right now. Dave, it's going to be slow going even if we have something in 4 weeks time, likely it's months and months before it reach the point of start up.

Right. Got you. And then one final one, maybe this one's for Doug. I know last quarter you mentioned some pricing traction on the Completion and Production Services side of things, and then today, you mentioned some cost pressures share as well. As we move forward, how should we think about margins in this business?

I think that will tie in with Kevin and Rob's comments on commodity prices. Clearly, $80-plus, call it $80-plus, I think we're in a good stable environment. And we've shown some nice year-over-year increase. That's partly rig mix but there's a layer of profitably there that frankly reimburses us for a lot of the reinvestments that has come back into the fleet. So we're encouraged to keep the current pricing platform as it is, we'll see how commodity prices evolve.

There are no further questions registered at this time. I would like to return the meeting back over to Mr. Ford.

I'd like to thank everybody for joining us today. That concludes our second quarter 2012 conference call.

Thank you. The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.