Good afternoon ladies and gentlemen and welcome to the Precision Drilling Corporation Second Quarter 2010 Conference Call and webcast. I would now like to turn the meeting over to Mr. David Wehlmann, Executive Vice President, Investor Relations. Please go ahead.

Thank you. Good afternoon everyone. I’d also like to welcome you to Precision Drilling Corporation second quarter 2010 conference call and webcast. Participating today on the call with me are Kevin Neveu, our Chief Executive Officer and Doug Strong, our President of Completion and Production Services. Also with us here today is Gene Stahl, the President of our Drilling and Operations and our new Executive Vice President and Chief Financial Officer, Rob McNally. Due to news releases earlier today, Precision Drilling Corporation reported on the second quarter 2010 results. Please note that the financial figures are in Canadian Dollars unless otherwise indicated. Some of our comments today will refer to non-GAAP measures such as EBITDA and operating earnings. Please see our press release for additional disclosure on these non-GAAP measures. Our comments today will also include statements reflecting Precision’s views about events and their potential impact on the corporation’s business, operations, structure and financial results which are forward-looking statements. There are risks and uncertainties that could cause actual results to differ materially 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. After I give a brief review of the second quarter operating results, Doug Strong will review the changes to Precision’s debt during the quarter and summarize our capital expenditure plans for 2010 as he transitions out of his role as CFO. Kevin Neveu will then provide an operations update on our outlook and after that, we will open up the call for questions. On June 1, 2010, as a result of a plan of arrangement approved by the holders of trust units of Precision Drilling Trust on May 11, the trust converted into Precision Drilling Corporation. More information is available…

Thanks David. Precision’s financial position continued to strengthen in the second quarter of 2010 as the recovering customer demand experienced in Q1 carried through the second quarter, strengthened oil fundamentals, improved the capital markets and Precisions debt reduction focus over the past year led to favorable opportunities to enhance liquidity, reduced debt servicing cost and secured new rig build and upgrade opportunities with customers. These developments enhance future cash flow visibility and reinforced Precision’s brand promise to provide high performance, high valued customer service. Specifically Precisions pleased to highlight the following developments consistent with our team to seize market opportunities. First, we were able to amend our existing secured debt facility to lower current interest rate spreads on term loan B, on the term loan B by almost 3%. This was accomplished through 1.5% reduction in the LIBOR floor to 1.75% and a 1.45 reduction in the weighted average LIBOR margin to 5%. This in combination with the $74 million repayment associated with non-consenting debt holders lowers annual debt service cost by over CAD15 million. Second, we were able to increase liquidity by $150 million by adding borrowing capacity in our secured facility revolver. This in combination with cash on hand of CAD186 million as of June 30, 2010 provides Precision with liquidity in excess of CAD600 million at quarter end. Third, as we plan forward, we have expanded our capital expenditure program by CAD122 million. That’s announced in our news release this morning and we expect a vast majority, if not all of the spending to be funded from operating cash flow. Precision’s marketing teams and operating performance continues to build customer demand for high performance, super series drilling rigs. We also continue to generate upgrade opportunities to enhance horizontal drilling capabilities. The adjusted capital expenditure plan is now estimated to aggregate CAD244 million with 2010 spending of CAD189 million and a carry-forward of CAD55 million to the first half of 2011. In a moment, Kevin will speak to regional deployment of the new Super Series rig build program which now stands at nine rigs. As emphasized last quarter, we continue to carry a flexible approach to strike the right balance between new investment towards organic upgrade in growth while working within operating cash flow to carry strong liquidity. Further debt reduction remains an important priority for Precision as we bounce capital allocation with accretive organic growth economics. As the recently appointed President of Completion and Production Services, I look forward to transitioning the CFO office with Rob McNally and working with the tremendous people of Precision in my new role. Kevin, that concludes my remarks.

Thank you, Doug. I’d like to start by congratulating Doug on his new appointment. Most of you on the call well know Doug’s passion for excellence and his focus on Precision’s business. I am very excited to see Doug now apply his expertise to operations for Precision’s Production to Completion business and you can expect to hear a lot more about this business segment in the future. I also ask you that join me in welcoming Rob McNally to Precision Drilling as our new Executive Vice President and Chief Financial Officer. As with all Precision new recruits, Rob has met Precision’s internal requirements and besides his comprehensive finance and operations background, he has also passed a physical testing and drug screening. I can assure Rob that with his operations background, should the position of CFO not work out, we will have a position for him on one of our Super Series rigs. Now on a more serious note, Rob’s experience both in finance and operations combined with his extensive personal network and his visibility in the US capital markets will prove invaluable for Precision as we continue our US growth plans. We will work out our schedule with all of you to ensure you get a chance to meet Rob in person over the next few weeks. Now turning to the quarter. Reporting loss for the second quarter, be it cash or non cash is very disappointing for me. Clearly, our operating margins have room for improvement. And while some of the developments I’ll describe later in this call bode well looking forward. I’m confident that our people are well focused on the current business and we expect to improve these margins going forward. Yes for several months, I’ve been talking about ongoing conversations and opportunities of customers, both in…

Thank you, we will now take questions from the telephone lines. (Operator Instructions) Our first question is from John Daniel from Simmons & Company. Please go ahead. John Daniel - Simmons & Company: Hey guys, couple of questions for you first on the Canadian drilling market, you talked about pricing opportunities as you head into the winter season, can you give us just a sense of, what the magnitude might be? Is there any talk right now with customers?

John thank you for the question. I really don’t work with all the guidance out on our strategies, or pricing this fall. We get back to our customers very quickly and just makes the conversations that much tougher. Certainly the utilization’s often to a point just to where we think things will be this winter and they were substantially lower than the market with expected to having known, we would see that much activity. So, it will be an interesting October for our sales team, we will do the best we can to get the rigs pushed up for us progressively. John Daniel - Simmons & Company: Well, how about look at it this way, can we look and say what happened in the US market somewhere say rates dropped to where they are today as an indication of possible change up in the Canadian market?

I’m going to have to leave it to you guys to draw your models on that, I’m sorry John. John Daniel - Simmons & Company: Okay, the completion of production services segment if you would look back in 08 and 09 revs were up about 50% quarter-over-quarter and Q2 to Q3 I think you said you are tracking 30% above now, is that fair with 30% on revs or just on activity?

Yeah, John, it’s Doug, we like the momentum we are carrying out in the month of June, and the activity pickup would be higher than the 30% currently. John Daniel - Simmons & Company: Okay. Alright, and then I guess just one more from me. Can you remind us how many of the rigs in your capital program are, how many do you have upgraded? 15, this year on the drilling side?

John, we guided originally to something in the range of 10 to 15. John Daniel - Simmons & Company: Yes.

Lucky the scope of the upgrade that number might come in closer to 10.

Thank you, our next question is from Mike Urban from Deutsche Bank.

I had a question on the C&P side obviously Doug already as you said kind of indicated an increased focus on that business, should we expect to see in that emphasis is that to imply a geographic exposure? Sounds like you’ve already moved some asset, is it organic growth? Do you need to add or want to add some product and service lines, or all of the above?

Mike tomorrow is probably Doug’s first official day on the job. We’ll let him get settled first. Certainly we understand that our position in Canada is very strong and our productions and completions business. And I think there’s a lot of challenges in the U.S. market. So I wouldn’t want reasons to believe that we have immediate growth plans to the U.S. That’s not on the short progression force.

Are there opportunities to do more within Canada where you already have a strong market position, again as you said moving some assets or again adding products just as you stay with focus only in Canada?

We’ve got a core focus on our existing business lines and we see rising momentum opportunities there to ensure that we continue to provide safe and reliable service. The completion production is a little bit more of a call out service, and its got the 24 hour momentum if you will that drilling has, so the industry over the past couple years really contracted hard, and we’ll be sticking to our selling here in the short term to bolster both the human capital and any equipment within our C&P business.

That makes sense and maybe difficult to answer this point but as you look down the road and then this maybe more of the big picture strategic kind of question, but do you think that alternately Precision can remain more or less a drilling focus contract or do you see a need somewhere on the horizon to be more integrated to offer more services or customers requiring that or are you seeing more requirements for bundling the services maybe even the higher in place or just stay focused on the drilling market by now?

Good question, Mike and it really depends geographically where you are thinking. Outside North America the integrated services more than has lot of traction in countries and places where the interim groups of the national oil companies maybe don’t have the depth, that they have in North America. But, North America, the drilling departments have most of our customers have a lot of depth, and if there isn’t depth then it is a local third party group that usually provides that type of service in Canada. So, the business room that has remained quite fractured and even those drillers that have your drilling rigs and service rigs and some even have pressure pumps, a very small wedge of that is actually combined in any kinds of integrated service business in North America. I think our customers are quite comfortable keeping the business fractured and if one plus one equals two, and they can save a lot of money then we put them together.

Thank you, our next question is from Victor Marchon from RBC Capital Markets.

Thank you, good afternoon guys. First question is on new bills, Kevin let me get your sense as into, we have seen a couple of the other publicly trading companies talk about adding some rigs in the U.S. and I just wanted to see if you had a sense as into what the total industry order book looks like right now and what’s your sense in the demand that you see for these Tier 1 assets as into the opportunity set for the industry say over the next six to 12 months?

Victor so first all, are you referring to the full order book across the sector?

That’s right.

That’s a tough one to give you [sum] exactly because some people are building rigs on specs, some people are building inventory items they can turn into rigs quickly and then some of us have announced full rig builds. I know we have and a couple of our US peers have discussed full rig builds. So what I would kind of point you first of all that the clearly announced rig builds that appear to have customer targets probably less than 25 or 30. Now there maybe more rigs in process either as spec or loosely specked rigs or parts, don’t know for sure and again it’s a real tough number to get your arms around, but you would thinking 25 to 50 in the range. No I don’t think I can argue that it is going to be less than 25 or maybe not a lot more than 50. Now what I see for demand going forward. I think it’s rather remarkable that considering what we have been through that there is even one new rig being talked about here. So I think these are all good signs about just how effective the Tier 1 and Tier 2 assets are in the marketplace, but more importantly whether it’s tight oil or conventional oil in the horizontal drilling or unconventional gas or shale gas, clearly the Tier 1 and Tier 2 rigs are required. And the Tier 2 rigs really are still heavily over supplied. We have opportunities for maybe regional rig drilling opportunities or maybe some vertical wells or low cost wells. But the growth areas in North America will continue to be unconventional style drilling. So the game on new build rigs is far from being finished.

You had mentioned the interest in upgrading some of the Tier 2 assets. Is that driven by customer demand where that would be back by a contract or is that just, you guys doing it, in anticipation or just in looking at how tight the Tier 1 market is?

We generally try to tie all CapEx improvements for the rig to customer contracts. We have a fair amount of discipline in insuring that they’re getting, certainly near full payout terms of new rigs, but even on the upgrades we are doing, we are looking for big contractors that insure we get back most of all of our capital. In very broad terms, virtually all of our upgrades will be contracted rigs.

Just switching to pricing, to something you had mentioned earlier on the blended margins in the US have troughed. And I was just trying to get the sense as into how that looks coming out of the other side, just given your guidance mix of term contracts and the spot market today. If the blended average were at or near the low, what is your thought as into the progression going forward given the mix between term contracts, the spot market and as some of these terms rollover? Is it something that we are looking for some improvement in the say fourth quarter, first quarter of 2011. And is it look more of a gradual improvement or is it something more, not a hockey stick, but something that’s more significant based on the mix?

Our view on how the rigs might move up on the aggregate going forward is, it is as visible as we see our customers drilling plans right now. Frankly their plans are going to run out at the end of this year with the 2011 budgets yet to be announced. So that’s one factor that makes it hard for us to guide forward on day rates. The trough in activity, kind of lagged or dragged on from some time in April through pretty much July. It was almost a two quarter type lag. So as you know the day rate will stagger a little bit in aggregate, wouldn’t surprise me but we are working hard to push them up, clearly the top the tier rigs are doing very well right now. We talked it before in the past of CAD2,500 to CAD3,500 any types step ups in top tier rigs. We talked about a little less on the Tier 2s, maybe a 1,000 to 2,000, we will also do a tier upgrade. Now that’s kind of magnitude we’re looking for. Again we’re rolling out contracts from 2007; there were some very good contracts even at the lower tiered rigs. So it takes a while to wash this out. I think by the end of the third quarter, when we report earnings in third quarter we’ll start to see some of the front end of that curve that, I ask for some time on this and come back to you in October.

And just the last one, any guidance to provide on the G&A side as well as tax rate going forward

First of all, on the G&A, side, we’re still running this business, and I’ll use the word like it’s June 2009. We are running lean and keeping things right on the G&A side.

On the tax rate side is the corporation now. Our statutory tax rate, take an average between our Canadian and US operations, as we guided last quarter is in that 25% to 30% range. As we’ve seen to get down to our underlying effective tax rate there are some, there is variables in play that reduce it. But on a long-term basis continue to guide in that 25% to 30% range. Not all of which is cash, obviously. And as we continue in what is really a pretty low pricing environment, you’ll find very little of that is cash.

Thank you the next question is from Kevin Low from FirstEnergy.

Just looking at your balance sheets, can you kind of talk about why you thought you needed to explain your bank line?

The short answer on it Kevin is, we’re getting back to liquidity that we saw back in Q4 2008. And broadening of our lending relationships, the markets opened considerably since then and there is a great opportunity at very little cost to get the relationships that quite frankly match our underlying market and platform for growth going forward.

A round about way of asking a different question would be do you see those as being a little more aggressive in terms of spending capital if there's opportunities available, I guess, in the next six to 12 months.

Not at all, we think the size of our credit line is right in line with the scope of our operations.

In terms of what Kevin was talking about in terms of the Middle East and South America. It sounds like just from maybe tone it sounds like you are a little more enthusiastic or optimistic that the Middle East is a little more imminent or the probability is a little bit higher, would that be safe to say?

I wouldn’t go that far Kevin, that particular bit I was mentioning was the public opening in the Middle East and I don’t want to give a lot of specifics, but we are in public record in Middle East on a particular bid as having been one of a qualified bidders that delivered a compliant bid. And what’s happening right now in Latin America, until we have something substantial to report, I don't really want to give a lot more detail right now.

I guess, if we look at the cycle right now, and you know you are saying that the rates have troughed and we should see a little improvement from these levels, how far away do you think we are from mid-cycle pricing?

On a bi-tier basis, the fact we are announcing some new builds right now. It might be fair that those Tier I rigs are not far off of above mid-cycle pressure. Replacement pricing on those contracts, our discipline on contracts.

Okay and the remainder is below like material below or?

No, it’s the Q3 rigs are CAD2000 to EBITDA margins that’s about it. Q2 rigs are doing well and if we can update this to tier 1, it's investing range. So we got to do the past to be thinking about your steps and the tiers being at CAD3000 to CAD5000 a day of soft of the EBITDA step range. That guidance nothing still stands.

Okay and last question is, you guys have put down a few rigs and you are hearing if guys with drill rigs in there what do you guys see in terms of rig de-commission other from yourself or the industry in Canada?

Okay and last question is, you guys have put down a few rigs and you are hearing if guys with drill rigs in there what do you guys see in terms of rig de-commission other from yourself or the industry in Canada?

We de-commissioned lots of rigs back in December as you all know. We do it when we think the time is right. We look at our fate and look at our utilization and things like that. Look at opportunities down the road. I can’t speak to our competitors and have the reanalyzed difference.

Thank you. Our next question is from Dana Benner from Stifel Nicolaus. Please go ahead.

I wanted to follow-up, I think it was Victor’s question with respect to day rates and margins mine is on the day rate side. You’d given some day rate delta's for Q1 and 2 rates principally and so I wanted to maybe put a finer point on it and that is if you look at your second quarter results, can you give us a sense for how much of those rates may have moved by tier in the second quarter in the US. Can you give us may be a bit more color there?

The rates on the tier 1 rigs from the bottom of the cycle in mid 2009 to today have probably moved in CAD2500 to CAD5000 range. This last quarter they are up a little bit of that increment not, I would say probably 10 to 15% what happened in the second quarter, they are still moving up. Obviously we got due replacement cost, economic because we are building new rigs. Does that answer your question?

Right, so that would be tier 1, what about tier 2?

Tier 2 were probably up CAD1,500 to CAD3,000 bottom of cycle to today and again some of that took place earlier I would say 10 to 15% of that increase is in this last quarter as well, I think that’s a pretty standard across the tiers.

Firmer utilization plays into that.

I guess as we think about Q3 leading edge rates, would that more in keeping with the trend line established in Q2. Do you see any type acceleration or is there too much uncertainty with respect to stronger oil drilling and a backing off of gas?

Yeah, as Kevin said earlier, we have as much visibility as we have with our customers and so we don’t want to get into projecting Q3 right now, we are running 91 rigs in the US and 77 in Canada which is well above last year’s pace and we don’t see anything to tell this today that number is going to shrink but, it’s a long time to the end of the third quarter.

The second and final question, relates to the I guess the trepidation that you and so many others feel right now on the natural gas side, and not withstanding the cautiousness that you and other oil service companies have had on the gas market this year, the gas rig count continues to move higher and I wonder if you could maybe give us your sense as to why you think it has moved as high as it has given gas prices stalling out? Lots of reasons out there we all know about, but how would you prioritize those reasons for why the gas rig count has moved higher than the service companies and even analysts and PMs would have thought?

There’s no question that Marcellus probably makes sense of these pricing levels. So I think that Marcellus continues to have good fundamental value. When you move into the other shale plays in the U.S. particularly, obviously hedging and land position drove the hold our drivers no question about it. And one view might be that eventually the drilled holes run out. Another view might be that the drilled up holes continue on because there’s other lines being bought that has to be held. So these are hard things for us to model, and there’s also talk about how inventory wells that drill are not completed and not tied in, those are hard to model too. Now we’re in touch with our customers and we work closely with them. We’re drilling fully in those shales we are drilling for large Cap companies with solid hedging programs. Some of those companies seem to be going against the green on their plans for CapEx spending around gas. And we’re part of that play with them.

Well it’s good to see the utilization, but it’s still been an interesting year, so I’ll turn it back. Thank you.

Thank you. Our next question is from Mike Mazar from BMO Capital Markets. Please go ahead.

Just before I get to a couple of quick questions, I missed something earlier. What are the specks on the Eagle Ford rig? The rig moved to the Eagle Ford was that a super single?

The Eagle Ford was a super triple 1,500 horsepower, three of them. The new built rig for the Marcellus was a 1,200 horsepower Marcellus super triple.

The one that moved from Haynesville to Eagle Ford was the 1,500 horsepower that’s what he is after. 1500 horsepower super triple.

Okay, that’s terrific. Secondly here was there something weird in depreciation this quarter?

Not particularly, Mike what’s your observation?

It’s about $11 million higher than Q2 ’09, I realize utilization was little bit better but it's actually more than what Q4 or Q ’09 were too.

There were some plays I think you till you model up the activity increases and where we experience the increase between U.S. and Canada. It’s based on linear production method.

Right. So I would have thought with lower utilization Q2 it would have been lower, but okay. So but there is not a write off or anything in there?

No.

The directional business, can you give us bit of an update on that?

Sure can, I think I commented the last call we just wanted to progress so far and right now we have several rigs in Canada on two customers specifically that we partnered with, they are important customers, they are strategic, we are going through and frankly we are convincing the customers, we can do a great job. And this is going well so far. In U.S. we are doing the same thing focusing over couple of customers, establishing close report, close relationship and we are changing one drilling image turning at this point.

Okay. So you haven’t materially expanded the capacity in that business yet?

We are recording some more tools and things like that along the way but no acquisitions, nothing major.

Okay. And then finally just because I guess I have to ask any update on the thoughts on the dividend? Or reinstating a dividend or what were your views on potential dividend there?

Mike, the answer is yes, it remains the same. Our debt level isn’t where we want it to be ultimately. Until we get there we will just hold that in conversation about how we deal with the cash after that

Thank you. Our next question is from Roger Serin from TD Securities. Please go ahead.

I have most of my questions have been answered. I have one question and it relates to, if you can look at Q2 '09, I didn't knows and say Q2 '10 margins, 5% to 6%, if you can break it down, you gave language in the Press Release, but what portion was comprised, of lower day-rates what you know higher cost can you break it out a little bit?

The biggest piece of the difference was Q2, 2009 still has a lot of 2008 contracts was mainly in US. So it really was just the exceedingly strong contract position we had coming into the downturn that help support Q2’s margins.

Roger you are also seeing our U.S. operation that we had significant out of the contracted revenue and we also have been amounted CAD15 million and we also had CAD6 million of lump sum rig payouts in Q2, ‘09.

So would I add those and say that CAD20 million of rate to the bottom line numbers that didn’t show up this year?

21 million that’s right.

Thank you. Our next question is from John Tasdemir from Canaccord. Please go ahead.

Hey. So I guess just looking at the rig count in Canada, and seeing how the staggering growth we seen in the Cardium and looking at what's going on in the Viking and lower shale and upper Bakken, there has been a pretty big reemergence up there. Kevin, what inning you think we are in with that stuff and is that reshaping what's going on in Canada?

First sitting was last summer, it went from handful of rigs drilling in Cardium to maybe 85 rigs last winter industry wide. That’s a pretty good jump in six months and right now today I think we actually have more rigs drilling in Viking than we have drilling Cardium, both coming up nicely. But, as I’ve listened to a few of the E&P companies talk about their line positions and how long they can drill for. They are talking about years and years, not Q1 2011, but they are talking about year and years. So I think we are very early in this game.

When you look at those plays today versus what was driving the Canadian activity three or four years ago. Obviously we need to get some more rigs utilized before you see major changes in pricing, but how is it different, are those more profitable or they are same type of rigs? Is that changed at all?

John, if you look back three or four years ago, the oil drilling that was horizontal was only the heavy oil, say [D-type] wells, virtually every other oil well being drilled in North America, three or four years ago would have been a vertical well, would have been a tier three rig. Today, these are tier two and tier one rigs required to drill these ten, 11 and 12- stage horizontal fracs, even for the conventional Cardium and Viking type wells. So it’s really helping with line up for the Precision’s rig drill right now.

So a bit of a transformation in the sense of what's going on in Canada right now.

Our next question is from Jeff Fetterly from CIBC World Markets.

On the CapEx side the CAD CAD121 million, how does that split between upgrade and maintenance?

Of the additional capital that we announced, CAD CAD106 million of that is expansion, the balance is upgrade.

If you put it pro forma the number of rig upgrades coming back to about ten rather than toward the 15 side. So do you have a sense in terms of the overall component, what would be upgrade versus maintenance?

Yes, that 10 upgrade number, those are significant rig upgrades refurbishments that does not include some of the top drive additions that are within that upgrade capital number. So bare that in mind as you think about a rig count.

The rig builds, that are coming in, do you have a sense whether those are incremental additions for producers to their programs or whether they're displacements?

Our sense would be they are all incremental.

Do you have a sense in terms of what percentage of your fleet today would be running on a lease retention or drill to keep basis?

I commented earlier, I think I said 8 and 18 rigs drilling in the Haynesville and the Marcellus. Some percentage of those rigs, but it’s not a big number relative to the activity we have across the fleet.

In the numbers you listed off earlier, I counted just over 70 rigs that are operating in resource plays, do you know what that number is in total for your fleets? And then maybe contrast that in terms of the type of drilling they're doing within those resource plays?

We did comment earlier that I think over the course of the quarter more than 80% of rigs drilled horizontal directional type wells. And that’s probably not a bad proxy for resource plays and heavy oil combined.

And lastly, your comment Kevin about debt repayment with the doubling in the CapEx program, and the working capital requirements for the business in the back half of the year, do you believe you have the capacity to pay off debt in the second half of 2010?

What I can tell you is we are paying for our CapEx completely within our means. And I will also tell you that we still have optionality on how we decide to pay down our debt. If you have noticed though in past payments we have made, the notes and payments we made. Each time we have done that, we have used it to seek some form of amendment to the debt terms or some further relaxation of some further space. And I think we have been very strategic about where we apply that cash to the debt. So it is not just pay down debt, but pay down debt intelligently and improve our banking terms, and it’s worked well for us so far. We are not backing off on that.

Outside of using the balance sheet do you believe you’re going to have some free cash flow to continue debt repayment or is that a 2011 initiative?

I think for 2010, I think we are balanced. We are deploying our free cash flow against debt and it will go towards our expanded capital expenditure program. 2011 comes down to where we’ll see what kind of momentum we carry out of Q4 that. We have got a flexible plan, we have got CAD55 million committed on expansion capital and a lot of flexibility around our maintenance upgrade capital for next year to continue to carry significant free cash flow to apply against debt.

Our next question is from Jeff Mochoruk from Cormark Securities

Most of my questions had been answered but could you provide us with the timing on the new rigs?

I did through the course of the conference call. David do you have it on your fingertips?

Yes, basically they start here, the earliest rigs will go out in the third quarter. I think we have one and a couple more in the fourth quarter and then they will spread out over the first half of next year.

On the cost, things are heating up a little bit. Are you seeing any cost pressures particularly in the US market, I noticed that, it looks like your costs on a sequential basis were up about CAD CAD500, are you seeing any cost on where those are coming from?

Sure, yes. I mean as we’ve grown our rig count up from the low 40 in the US upto 91 here today. We are putting rigs to work that some of them haven’t worked in a little bit and as such there is some startup costs associated with that, but something as we project for don’t intend to see rising.

Is there any incremental costs or more costs working in some of these new regions such as the Marcellus, even backing off the start-up costs?

Not particularly, Jeff.

Our next question is from Brian Purdy from National Bank Financial. Please go ahead.

I was wondering if you can give us maybe any guidance on what the payback period is for these new rigs. Would it be under four years?

Brian, our guidelines are in the four to five year range and contracts that generally cover between three quarters and full paybacks. That’s the guidance on the contract.

Okay, perfect and then just on the completions and production side, I am just wondering what the pricing trends there are. It seems like prices have still slipped from a year ago levels?

Brian if you look hard at the second quarter results, you will see our margins are relatively flat, Q2 09 over the current quarter. And as we come out of June, we’ve had some delays, we are carrying a strong momentum, we saw activity act significantly in the quarter, we are carrying higher levels of activity compared to last year at this point so the industry went through significant rate reductions and that we are working with our customers to get some of the value back and to have opportunities to reinvest back in the equipment and bring some technology back in, into play as well.

Okay. So it sounds like that's a bit of a work in progress for a while.

It’ll take time.

Thank you. Our next question is from Todd Garman from Peters & Company. Please go ahead. Todd Garman - Peters & Company: In the US on the cost per day side, if I look at the sequential in U.S. operating costs per day, of say CAD400 to CAD500, is that entirely related to the reactivation of the rigs because I am, the turn-key revenues are also up say 50% and I'm wondering what the cost impact there would be on a per day basis.

Turn-key does effect that we had more rigs operating in this quarter of 10 over second quarter of 9 so in turn-key cost always going to be higher because you pay more well cost of course you have offsetting revenue. Todd Garman - Peters & Company: So if I look at want to expand the Q2 2010 is that that a cost increase all turn-key revenue because of turn-key costs, or is it rig reactivation cost?

There’s a little bit of both in there but turn-key is a big component of it. Todd Garman - Peters & Company: And then if we just flip over to Canada, what would be Precision’s sense of Sag D activity in Q1 of 11 and then what percentage of the tier 1 assets that you have might be applicable to that type of activity?

I’m sorry I didn’t catch your question, could you repeat it? Todd Garman - Peters & Company: Based on what you see for sag D activity in Q1 2011, how many tier 1 rigs do you think you can put to work as it stands right now? Based on what you see.

I think in tier 1 11 every tier 1 rig Precision has been running. Todd Garman - Peters & Company: My mistake guys the tier 3 rigs, excuse me.

The real question might be how many more tier 3 rigs might we consider upgrading for Q1 2011. That might be probably more helpful because, frankly if it’s a horizontal well, unless it's an exception it likely will get a lot of work. We do have a couple of tier 3 during horizontal wells. So it’s not an absolute, but our tier 3 fleet of very such rigs, I think 18 or 19 are working right now. We could double that in recent demands, we can put twice as many of those to work, or more. But we’re not so much on that being something we need to worry about for Q1.

Thank you. Our next question is from Mike Clark, Star Capital. Please go ahead.

Sorry, guys, the questions were answered. Thanks.

(Operator Instructions). And we have a follow-up question from Jeff Mochoruk from Cormark Securities. Please go ahead.

I just wanted to touch on the service remark; you didn’t really talk about it very much. What are you seeing there with the change in the oil and gas mix in Canada, and how is that impacting your utilization? How you see that going forward? And what else are you seeing any opportunities to increase prices in that market?

I had commented earlier during the call that we had redeployed 14 rigs to areas that we were under servicing, that was specifically for oil and the activity is summing up nicely right now, both in the Cardium, Viking and heavy oil, all oil driven. What we are missing is the old deep gas completions where it is used to be really good for that business. That’s not coming back right and we don’t see it coming back anywhere on the short horizon, but we all started business, little lower margins, a little less sophisticated work, but we aren’t complaining. It’s going to work for us.

How do you see pricing playing out in that market as the year progress and we head into the winter and fall of this year?

Jeff, I would add that on the service rig market, our customers are seizing the opportunity right now. Rates are comparatively low for where they have been. As we came out of the second quarter, we’ve seen some nice activity in the north and west part of the western camp sedimentary basin. No question oil is carrying the day, but we are seeing customers do think like working over abandonment type wells and so, you see that momentum continuing and as drilling persists, we expect our completion work to gradually improve, as we saw in the second quarter of ‘10 versus ‘09.

Thank you, this concludes the question-and-answer session. I’d now like to turn the meeting back over to Mr. Wehlmann.

Just like to thank everybody for participating on the call with us today and have a great day. Thank you.