Good afternoon ladies and gentlemen and welcome to the Precision Drilling Corporation third quarter 2010 conference call and webcast. I would now like to turn the meeting over to Mr. David Wehlmann, Executive Vice President of Investor Relations. Please go ahead, sir.

Thank you. Good afternoon, everyone. I would also like to welcome you to Precision Drilling Corporation's third quarter 2010 conference call and webcast. Participating today on the call with me are Kevin Neveu, our Chief Executive Officer; Doug Strong, our President of Completion and Production Services; and Rob McNally our Executive Vice President and Chief Financial Officer. Through the news release earlier today Precision Drilling Corporation reported on third quarter 2010 results. Please note that the financial figures are in Canadian dollars unless otherwise indicated. Some of the 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, balance sheet 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. Rob McNally will begin today's call with a brief overview of the third quarter operating results and our capital expenditure plans. Kevin Neveu will then provide a drilling operations update and our outlook going forward. Doug Strong will follow Kevin with a brief overview of the completions and production segment and after that we will open the call up for questions. Before I turn it over to Rob I would like to comment that we are pleased with the quality results of this quarter despite the overhang in the market of low natural gas prices. Oil and liquids rich natural gas drilling in service activity are driving results for precision in both the Unites States and Canada. Our comments today will reinforce that and provide examples of the importance of oil in the markets today. Rob over to you.

Thanks, David. As David mentioned, Precision had a very solid quarter. We reported net earnings of $61 million or $0.21 per diluted share on revenues of $359 million for the third quarter. These results do include an $18 million foreign exchange gain which equates to about $0.05 per share relating to our debt being primarily US dollar denominated. Our Q3 2010 EBITDA was $113 million, which represents a 31% increase over the $86 million achieved in the third quarter of 2009. The improved third quarter results primarily reflect increased utilization. Activity levels have increased meaningfully with the continuation of positive momentum building from the beginning of the year. Drilling days increased 62% in Canada and 76% in the US while service hours were up 42% over the third quarter of 2009. Abnormally wet weather in Canada restricted rig mobility and operating days for Precision's Canadian drilling and well service operations, otherwise Canadian results would have been meaningfully better. In the US, the average land rig count for the third quarter of 2010 was 1,590 compared to 927 in the third quarter of 2009. The average rig count in Canada was up 94% with the Q3 2010 at 359 versus 185 in the prior year period. Combined Precision averaged 176 rigs operating in the third quarter of 2010 versus 130 in the third quarter of 2009. Currently in Canada Precision's active rig count stands at a 119 rigs after averaging 82 during the third quarter. Precision's US and international rig count is currently at 101 after averaging 94 rigs working in US and Mexico during the third quarter. In the quarter we had 35 rigs working under term contracts in Canada representing 42% of our active Canadian rigs. In the third quarter of 2009 Precision also had 35 rigs working under…

Thank you, Rob. I will begin by congratulating Precision's employees for delivering an excellent quarter in terms of safety, operational performance and financial results. Now that we are three weeks into October we are continuing to see strong customer demands for oil drilling opportunities and continuing at the pace we are seeing for most of the year. This positively confirms our prior statements on the reemergence of the oil as a key business driver for Precision Drilling. There should be no doubt in anyone's mind that oil commodity prices in the $60 to $80 range provide ample economics for the long-term development and the redevelopment of vast acreages across the well understood traditional US and Canadian oilfields. As I mentioned earlier on the call our North American business is over 60% oil and a large proportion of this business is horizontal completions utilizing our high performance tier 2 and our Precision super series rigs. Precision's recent growth in the Permian Basin truly highlights this point. At the start of the third quarter Precision had three rigs drilling in Permian. Today, our rig count stands at eight with several additional prospects under negotiation. Now, just to touch on natural gas for a moment, gas storage this morning at 3.683 TTF is approaching last year's record storage levels. Unquestionably this will continue to pressure the commodity price that we filtered down to reduce gas drilling at least over the short-term. However, I remain highly encouraged by the longer term prospects for Precision. With our well established footprint across all North American unconditional plays the proven reputation of our super series rigs we are well positioned as the shale gas resource continues to grow in importance as the fundamental component of North American natural gas supply. Now, looking at our key markets, I've…

Thank you, Kevin. Our completion and production services segment had a successful quarter on all fronts; safety, operations and financial. Q3 2010 activity rebounded over prior year and we look for that trend to continue as we close out the year. As Kevin and Rob touched on all product lines, including Well services, controlled pressure, rentals and water treatment had benefited from strengthening oil prices and we have positioned people and equipment to benefit from resource play activity. This week we have in all 100 service rigs active for 50% based on our 200 rig fleet. This is higher than our Q3 2010 utilization of 42% as weather conditions have improved from the wet summer. Roughly 90% of service rig activity is related to oil wells, and two thirds of that is situated in East Central and Northern Alberta, and in South East Saskatchewan and South West Manitoba, heavy oil and the Canadian side of the Bakken. For the winter we expect additional demand as our customers broaden their focus on winter drilling locations in the West and Northern regions of the Western Canadian Sedimentary Basin. Precision's completion of productions segment is positioned to benefit from horizontal drilling trends to its diverse and mobile well servicing rigs, control pressure snubbing units, and well equipment including tanks for fluid handling. Looking to 2011, we are focused on market opportunities to increase the duration and service intensity levels with customers to grow and maximize equipment utilization. This type of market opportunity was exemplified by the 500 man base camp that we secured and set up North of Fort McMurray in the oil sand region late in Q3, and expect to operate well into 2011. In terms of Q4 2010 customer pricing for our service rig fleet we didn't pass through a field, labor increase was over 5%. And additional margins, that will be little modest. We continue to work with customers to keep their cost of production low to high performance, high value services in a highly competitive Western Canadian market. That concludes our brief completion of production overview. I will turn the call back to operator Camille for questions.

Thank you. We will now take questions from the telephone lines. (Operator Instructions) The first question is from Kevin Lo from FirstEnergy. Please go ahead.

I think when Kevin was talking he was pretty adamant about not building rigs on spec, but can you kind of hint at what 2011 investment might be in a general sense? I mean Doug was just talking about building a base camp. Do you have appetite to build more that type of equipment?

And certainly we will be a lot more transparent from December. But giving you a bit of a sense what our thinking is right now, no question the way our customer spending budgets rolled out in 2010, by-products soon what we saw early in 2010. So we started last year with a very conservative budget, and really we were running just at maintenance CapEx most of you operate. As I commented we do see new build opportunities still on the table with a variety of different customers. And if those are to develop into serious discussions of contract negotiations, you can certainly see that move up our level of importance. Rig tier upgrades remain high on our list of importance, and we working capital maintenance. With Doug moving into the completions productions business, so he will focus on that business. We're uncovering opportunities for investment in that business also but we've got some accounts. Doug talked about trying to capture more of a spend on the production completions business. You know frankly we see some exciting opportunities looking forward to next year, but really rather wait until we run through our budget process first before we give a lot of guidance.

Okay. And in terms of your contracted rates, can you give us a sense of how many of those rigs are focused on natural gas versus oil?

Obviously all of the rigs in the Marcellus are on oil and we've got eight of the contracted rigs there, on gas, excuse me. I'm sorry, got that wrong. And then, its going to be by area. In Hayneville, we have several rigs on contract, I don't have that right here in front of me. But I would say in general, contracted rigs today are probably 50-50.

50-50 but maybe a little bit of shift, some of these rigs shift around both on the Haynesville to the Eagle Ford?

I would have said before it was 60-40, gas, and now I would say 50-50 oil gas.

And of course all the Super Singles in Canada will be all oil related. We actually don't break it up that way because its hard to track some of these play but we'll go back and look at it for future calls.

Great. And just a last thing, when you guys are looking at your rigs rates right now and you kind of alluded to the rates at the margin or at the level where you can actually see new builds. What's the hiccup right now or what's the negotiation points and what we need to change in order for some of those new build contracts to proceed.

Kevin, great question. 2010 sort of rolled through. We started 2010 with six or seven customers having conversations and through most of the first quarter particularly driven by some of the uncertainty on debt in Europe; this conversation is just a flat for while. Then second quarter came, commodity prices looked a bit better, oil particularly and to loosen things up. So I think we're at a point now where the gas projections and storage and gas price is softening. I think some of these conversations are going to go flat for a while. But I think little change isn't necessarily a pricier contractors bring little changes. Let our customers get better visibility of richer gas prices and richer draw down. That will help set direction for our customers. But I don't think we need so much. Rigs that are typical economics with our rates and our terms are appropriate. And you know I was saying about a year ago that we were a $1,000 door to away or maybe a year to win contractors. That's not potentially there. I think we just waited for a stimulus of the market, and I think richer gas prices could help that or they can hurt that, we'll have to see.

Thank you. The following question is from Nima Billou from Bloom Investment. Please go ahead.

First of all, I'm glad you highlighted your participation in that Chile Rescue. You guys should be proud because you never know who actually knows your level of involvement. So that was I thought very neat participation. I just wanted to ask mainly about the CapEx program. Has that number slightly trended higher given your more positive outlook in the shift towards oil shale plays and NGL drilling because it seemed they were sort of hovering around the $200 million mark but it started to creep higher in terms of $218 million for 2010?

Well, its increasing higher throughout the course of the year. Once we recorded, we bumped it up a bit. Obviously we've been swaddling our capital very carefully against customer demands. So generally when we drilled up to the CapEx is because we have firm customer demand.

Now when you break it out in terms of the $140 odd million with respect to maintenance and then $70 million for growth. But 4140 million in terms of newer rigs wouldn't that still enable your ability to take greater share. It almost seems like its all growth CapEx in a way in a sense that they are more efficient rigs to be able to sort of start taking share from all the rigs and displacing all the rigs in the marketplace?

This was not about characterization of both, the upgrades or the new build CapEx. The upgrades are in many ways as good as or even better than new build CapEx because we get great returns like we almost always covered by pay order and near full pay of contracts or in terms, usually lost in three year paid economics. The upgrades are excellent. And your right it does well to take market share. It does allow us to displace other lower tier rigs. Viewing is as growth CapEx, we haven't talked about it that way, but in many ways it behaves the same way.

Maybe just one thing to add to that Nima is that in my comments, this wasn't in the press release but in my comments I mentioned that the break out of that was $60 million for what you recollect by as real maintenance level CapEx or infrastructure. And then $84 million was towards upgrades which clearly is expensive type CapEx. And then $74 million for new build rigs and then expansion CapEx.

Thanks for the clarity. That actually helps a lot. I guess the final thing is interest expenses have been trending lower especially sequentially. Can you just describe I mean what contributed to the massive decrease in interest CapEx given the debt level with a shift too much I know part of it has to do with your floors and spreads but it went from 50 million to like 21. So wanted a little bit further clarity?

Well certainly, in the second quarter there were two big events. One related event with two pieces, one was repaid down about $75 million with debt and we lowered our interest rates, we were making and lowered our interest rates on our term A and term B loans and effectively lowered by 150 basis points, Rob is that.

Yes it's like term B loans only.

Yes so there's a significant decrease in interest expense and then in this quarter we picked up another 13 million. You won't see the effect of that in the third quarter but rather in the fourth.

Okay, so that 150 bps spread out over the couple of $100 million, was it really causing that shift then, in addition to close to $100 million of actual total debt pay down.

That's correct.

Okay. Now, the situation is looking better and better. Thanks very much.

Thank you. The following question is from Mike Urban from Deutsche Bank, please go ahead.

So, Kevin you've talked about your international strategy for 2011 is kind of being a boots on the ground, poor status peak and that's kind of getting a field for the market perhaps putting some infrastructure in place. Is there something that could cause you to accelerate that or are there any opportunities out there that would allow you to do that or is it just not really feasible without putting those initial efforts in place?

Yes, Mike, certainly there are things that could occur that could accelerate that, but even an accelerated international strategy is still going to be a much slower process than we are used to in North America. So I wouldn't be modeling a lot of activity in 2011 that moves the marks of Precision either on the expense side or on the revenue side. I am hopeful there would be lots of activity but relative to the size of the company right now, I think in 2011 it has minimum impact.

It's been a long term play for us and we are talking tiers 1, 2, 3, 4, and 5 not just tier 1.

Sure and would it be reasonable to expect to hear more about it next year in some of those opportunities and then be a longer term in 2012 and beyond revenue opportunity?

Yes, I would really prefer giving a lot more detail once we have something to give detail on. So and that would be customer contracts.

Thank you. The following question is from Dana Benner from Stifel Nicolaus. Please go ahead.

I wanted to start by focusing on Canada if we could given the amount of wet weather we saw in September or late August, your numbers ended up by coming in better than at least I would have thought and I wonder if there's been something else that may have also contributed to any client mix, and maybe the types of loans that you are increasingly working on and if that may have helped you and really the same comment on the service rig side, I am very pleasantly surprised that how you well you are able to do overall?

You know Dana a couple of things, about weather, expectations for the quarter, given the range as well as 65 rigs of size 105, we were disappointed. We would have liked to seen that run above 105 to the fourth quarter. So its disappointing for us to weather no question about that, but I think this really demonstrates the leverage in Precision and our fixed costs, our minimal fixed costs and the leverage we have when activity picks up and its tough for you guys to model our margins when activity is going just quickly and clearly 60% was it David, 62% over last year increase in Q3 activity in Canada.

62, yes.

Yes, I mean that's a cute swing, and frankly I don't think we have got a much lower fixed cost. It's all been leveraged on the organization so we have always posted above the rig margins in our vertical integration. I think it really played nicely in Q3 for us.

Yes, and the variable cost model being able to add expenses when you need them and take them out when you don't. So.

Looking at the contracting segment and particularly in Canada if I back out what I think were your drilling, your strict drilling revenues that other category was also higher than I was expecting and I wonder if you could maybe give us some more granularity on and you mentioned the camp etcetera but where beyond drilling in Canada are you really excelling in your opinion?

I think if you look at the number of horizontal wells that are being drilled, there is nice pull through as you have seen for many service companies around that. So we are certainly seeing it in the rental side of the business around the surface tanks. We are seeing in some of the infrastructure areas like our cap business and you will not extend through to our waste log side of things with tier 1 solutions. So, we are certainly seeing it there. We also see it on top drives. The majority of the rigs out there now have topped that capability system that's a nice revenue piece for us.

Right and I guess no reason to think that you will see continued growth in that in Q4 and '11 versus '10 oil sequel?

Yes.

Yes and we've taken some steps with those business, particularly rentals to really focus on the fracing business with fracing the pools and with tankers on location. And again leveraging up either Q2 or last year's numbers we cannot, not many outfits have great operational leverage.

My final question is a two part one. I understand that you don't want to quantify this but maybe you could give us some sense. Right now as you get back to better utilization in Canada comparing it versus the US, so your drilling margins higher in Canada or the US, given your current run rate of rigs? And the second part is, maybe just give us a sense for any leading edge trends on day rates heading into winter in Canada or in Q4 in the US.

I don't think that the emerging difference between Canada and the US is a material difference now. That said, our operational tech center in Canada is fully functional for exploiting the rigs. In the US our tech center is coming on line later this year into next year. So that'll help with our costs in the US. So if there's a difference it'll be driven by our tech center, it wouldn't be driven by much else. Other than that most of the margins are going to be in line or consistent.

And then leading edge comments for Q4 in either jurisdiction.

Leading edge comments about activity or about primary…? Certainly, I'd say that we've seen some pretty good uptake in day rates through the course of 2010 in the US. That's flowing a little bit right now, the gas pricing end of year. While in Canada I think our figures have a little bit of extra budget to spend. I think they've done a pretty good job in the US grinding through the budgets. And we might between the combination of gas softening up a little bit, we might see things, I won't say pricing soften but the relative pricing slowdown in the US. In Canada we're just getting into the new pricing set by our sales team over the past few weeks. And I think they've done a very good job and its been competitive out there. But I think the industry is anticipating this business level far better than last year.

I gather from that that means an upward bias?

We reworked price last year for a market of a 100 rigs and we run a 142 rigs.

Thank you. The following question is from John Daniel from Simmons & Company. Please go ahead. John Daniel - Simmons & Company: You mentioned you're still in discussions for some new builds. I think at the time of Analyst Day there was something like nine customers looking. Is that still the case today, in terms of the numbers of people looking?

I didn't ask the sales guys that question this morning, but I'll hazard a guess, it was probably every state. I'll tell you, John, early October to the Analyst Day till now, I'd say they we're kind of sliding into more of a quite period. None of these are going away. And we saw the same thing happen last year were things slowed down a bit in the first quarter, nothing went away but then it came back. The customers are talking to a large cap customers with big projects; some of it is a bit gas sensitive, but some of it isn't. So I'd say conversations have been alive in our forefront. And we will get a better sense early in the winter season. John Daniel - Simmons & Company: Just one more on drilling and a quick one on workover, as you look at the rigs that are under term contracts today, particularly those in the traditional gas markets, and let's say for some of those rigs that might see contracts expire in the next quarter or two are any of the operators of those rigs telling you at this point that they don't intend to keep the rig once the contract expires?

So the way you phrase the question I haven't actually asked that specific question to sales team, but we have gone through our contract list and looked at the gas sensitivity. We don't believe we are heavily exposed to contracts rolling up in gas.

I think it's fair to say though that we have seen some rigs out of traditional gas areas over the last month or three weeks being let go when moved oily areas. So like South Texas straight gas holes being moved to some more of the Eagle Ford and some Haynesville rigs have moved to couple. We have seen two or three rigs in that. And no different than what we actually saw probably second quarter latest first quarter of this year.

And you know one of those large drillers in Haynesville reported earnings yesterday and talked about a reduction in spending in 2011. We're mindful of that and we'll watch that carefully. John Daniel - Simmons & Company: At this point are they being kind enough to pay for rig relocations to oil markets or are you guys bearing the brunt?

All of the rig relocations oil markets have all been covered by the operator. John Daniel - Simmons & Company: Last one, very quick. Just on the workover business for Doug. Can you remind me what the peak count was back in prior cycles, and just give me some perspective as to where we are today, the likelihood of getting back to those levels if at all?

Back in the peak which would have been two to three years ago with a fleet of 230 rigs, and all rigs worked. On a call-out basis, on any given day we would have 80% to 85% of the fleet. It worked on a given day just based on logistics with the customer. John Daniel - Simmons & Company: Is it unrealistic to think that could happen again as you get in the winter season or …?

The perspective to keep there is that, I think the deeper gas market is weak, frankly. We got the shale place going on but it's not enough to sustain the amount of [skivet] double service rigs that are out in the market. So I think you'll find that will be the area of weakness mostly in the winter.

The following question is from John Tasdemir from Canaccord Genuity. Please go ahead.

The first question is for Rob, real easy question for you. What's the precise tax rate we should be modeling for the fourth quarter and all of next year?

I would guide you towards, 25% to 30% is the right place, tax rate. Sorry I missed the end of your question, you said for this year or going forward?

Well I said, just going forward fourth, quarter and next year.

Yes, so fourth quarter is going to be low, in the same range as it was this quarter. And then as we move forward, it's going to move back towards that kind of 25% range.

Okay, moving on. Wanted to ask you guys about, we're obviously seeing a lot more stuff going on in the Permian Basin. Bone Springs is really popping up. We think a lot more rigs going to work in that area. Have you guys looked yet at much of that area and seen what type of rigs that area in particular might need? Are they going to need some of the higher performance rigs or have you really figured that out yet?

John, I went two weeks ago touring around the Permian Basin visiting a bunch of our rigs with a couple of our big clients up there. So yes, we have looked at it pretty closely. I talked with our sales team, operation team about 10 times in the past three weeks. Did that give you some sense of our focus? That said, you know what's interesting is there are lots of good vertical straight holes being drilled right now that use two or three assets very effectively and there is some horizontal drilling going on using Tier 1 assets right now, so it's interesting. And I understand they are even doing some multistage fracs, two, three-stage fracs on vertical wells. So I think that the operators are getting are much more comfortable with, lets call it 2010 production completions technique that's working on to other plays and starting to ply it back in Permian. My conversations with the customers tell me that we've got years of work ahead of us out there.

Okay. So it sounds like lots of different kinds of rigs are going to be needed in that area.

I think you're going to see its going to be a market for Tier 1 rigs in some of these new plays. We've drilled through a few shales. There are some shales out in the Permian Basin. And there will be horizontal work but a lot of it will be two or three rig also.

Okay, that's helpful. The other thing I was going to ask you was, just a little more clarity on; as we roll from 2010 into 2011, when we think about margins for your contracted rigs, just because of the roll-off and how they got repriced, would we expect to see the contract, the rigs you have on contract, would we see those prices migrating higher or margins migrating higher in 2011 and 2010? And will you get a bump?

We don't have a lot of the new builds rolling off in 2011, not a lot, but our experience has been quite positive at least at the same day rate type rollovers on new builds that are performing well. So then you go back to the contracted rigs at our new builds, but their upgrades. If their upgrades, likely we have good, fair pricing, maybe little bit of room to move, depending on how well they performed.

Yes I think overall, I wouldn't expect it to change a whole lot.

And then one final one, I guess falling off of one of the previous questions. Sounds like when you guys talk about growth potential, just because Canada has come off of a much harsher bottom, that Canada might show a little bit more incremental growth for you guys than the US. Did I read that right?

The bottom in Canada was brutal last year John, yes that's right. But in the whole scheme of things the US is still going to dominate.

And if you're talking about new build John, I mean of our new nine new builds, I think we have three going into Canada and six in the US. So, Canada still has some growth opportunities for the super single rigs. So I am not sure how you met the question but hopefully we answered it.

The benefit in Canada will be operational leverage.

The following question is from Roger Serin from TD Securities. Please go ahead.

You certainly beat us on margins and I think everybody else which leads to some of my questions. So on the day rates that you're getting, are they similar now Canada to the US?

Getting closer, recognize the US fleets deeper and no bigger rigs. Canada, a lot more shallower rigs and the average depth is shallower. So generally the day rates are probably appropriately proportional.

Okay. So apples-to-apples, they are fairly close.

Yes, a similar rig in both countries would be about the same.

Okay. And can you give me a range of day rates Tier 1 to Tier 3?

Dave go ahead.

Yes I mean, Tier 1 rigs are, they are going to be anywhere from probably 18,000 plus. We don't have anything to start again fortunately but we got stuff in the low to mid 20s. Tier 2 rigs are going to be in the, and these are three broad ranges but its probably 14 to 18 depending on who the customer is. And then the Tier 3 you're going to be 14 or lower. And not obviously just a couple of thousand dollar range there.

But there are some local areas where we're getting rates higher than those ranges. If there's a rig at the right place at the right time, it doesn't need a mobilization.

And as you get contracts rolling over, what are you seeing for pricing? Because those would have generally been Tier 2 or Tier 3 and newer builds. Are you getting flat pricing, pricing increases relative to the trailing contract prices?

You know Roger, our average blended rate in the US has been up now two quarters in a row, more substantially this quarter over last quarter. Short of and in saying that we think that might be a flattening as this was after the year the US, its probably the fair statement, but I don't want to give a lot more clarity to this, as people are scoring up the marketplace right now.

So you made the point that your fixed costs haven't really moved up much so I am just trying to get a sense here so we go forward and we are looking for a modest pickup in either Canadian and US activity, how much could you see in terms of activity pickup without having that much fixed cost. I am just trying to get a sense for torque on your margins on a go forward if activity pickups a little?

Yes, on the fixed cost side, just as things we are doing in the US right now with our tax center so a lot of rule but a little bit of fixed cost in the US but it should be leveraged out in operating costs of the rig. So there will be a little bit of trade off in that next year but we will sort of explain it as the year goes on. That will better be a trade off with substantially better margins, hopefully to follow on that. But I don't think we need to add a lot of fixed costs for domestic operations.

It's pretty small. I think there's a quite a bit of leverage ability to increase revenues without adding much to the fixed cost line at all.

As we talked about our international footprint, likely if we get a few rigs going that might be a net-net for the next year or so as we go internationally. That's why costs get more in much incremental into international in 2011.

Thank you. The next question is from Brian Purdy from National Bank Financials. Please go ahead.

I was just wondering, you're obvious increasing the capital budget on the upgrade side. I was just wondering if you could give us the top two or three upgrades that customers are looking for. If you're taking a rig from one tier to the next. What is it they're really looking for that you need to fix up?

It kind of falls into two categories. One category being top drive mud pumps, to make a rig highly capable horizontal drilling rig, that needs to have a top drive, needs to have high hydraulic horsepower. The other sort of significant upgrade is making our ability shift for a rig that unlike we have taken quite a few of our tier three rigs and made them into tier ones by converting the pad rigs. The rigs that can move in couple of hours well to well over the pad. So, those will just give you a sense of cost and drive upgrade you might be looking at something less than $3 million. On the moving system upgrade somewhere in the range of $1 million to $3 million and maybe $4 million depending on the scope of the upgrade.

Given those expansions don't seem exceptional, are there rigs in your fleet that you couldn't just add that type of technology to and upgrade them to a better tier?

Absolutely, right across the North America fleet. Let's just source the numbers around and say there's about 1200 tier three rigs in North America. My guess is that probably only about 25% of those rigs would be upgraded because they masks are so small, the subtracts are so small. In our case, in our tier three fleet we think that number is probably less than 50 that we will never see tier upgrades. However, inside that 50 a few of those can still take surplus.

And just shifting gears for a second, I wanted to ask about one of the IFRS changes that you mentioned there. The $125 million to $175 million reduction in carrying value of drilling rigs. How was that new carrying value being determined? Can you give us some idea of what the real metric is that is being discussed?

It's just taking another look at the valuation of some of these. Its a handful of the larger rigs, 2000 horsepower plus kind of rigs, that just aren't seeing activity like they were a few years ago when that transaction took place and so we were forced to have a look at those rigs and determine whether we've got too high a carrying value performance so we will use normal valuation techniques for those rigs and which of course isn't much of a science. But it leads us to believe that the right answer is somewhere in a reduction in those carrying values of $125 million to $175 million

And remember its only on a handful of rigs.

Yes, its 20 rigs there about.

I mean is that what you have to look at, a multiple of EBITDA given a lower utilization rate or is it some sort of market value, I am trying to get at it.

It's a combination, you look at just kind of cash flow, you look at asset values, you look at what's the order of liquidation value of the rigs and look at outside help, we will get outside advisors that help us with that, which we are in the process of doing.

That was all I had. Thanks very much.

Thank you. The following question is from Andrew Bradford from Raymond James. Please go ahead.

The question I want to focus on is on these upgrades. So Rob I think I heard you say, I forget this right, $84 million, is in your capital budget for upgrades.

Yes, that's the total 2010 number for rig upgrades.

Okay. So I might understand then you are upgrading something like 25 to 30 rigs and this is working with the $3 million number.

We are all looking at each other.

So they pointed to me to answer. The reason we don't want to give you a number Andrew is its dependent upon what the customers need. We are doing a lot of these upgrades just like we do our new build rigs we are getting contracts first. In other words a customer needs a rig for let's just pick a US Bakken application, and then we say okay well what do you want, and then we will go in and we got to spend $3.5 million on that rig. So it's quite a few upgrades. We're also looking at some international type upgrades as well. So the point being is that, I don't want to give you a number because I don't know we will give you the number at the end of the year.

As we book rigs to contracts.

Yes.

So it will all come out with the contract changes as we go forward, is that right?

As you look at our Tiers of our rigs too you will see not all of our upgrades are Tier moving but a lot of them are. So as you watch us you watch us you will see some additions to our Tier 1 and Tier 2, out Tier 3 and Tier 2 respectively.

It just seems to me like this is the sort of thing that can very quietly move the needle for you guys. So are you of most of the upgrades that you're doing, where you're actually taking a rig to the next Tier, or is it mostly Tier 3 to Tier 2?

Well it's not mostly anything, but their all Tier changes. There will be a handful of the upgrades that keep the rig within moving from kind of a lower Tier 2s with upper Tier 2. But the majority of the upgrades are all Tier changes, Tier 3 to Tier 1 and Tier 2 to Tier 1.

So I'd be right in assuming that you're doing about a 100% or fairly close to full utilization on these Super Series rigs.

Yes.

And so you went through the day rates, so the other side of that is the utilization rates. How are you doing on the Tier 2's and Tier 3's utilization wise?

Right now Tier 2s are around 55% to 60% and Tier 3s are 25% to 30%.

And actually with the rig count that might be a little higher than Q2.

It might be a little higher than the 60%.

Yes the rig count is coming up quickly in Canada.

Yes that's a good point.

But most of the swing comes in the tier 3 in Canada.

Tier 2 and Tier 3.

Tier 2

But that's a good point; the leverage we saw in Q3 is driven by those assets getting back to work.

And when they come back in to work there's not a lot of price sensitivity, they usually come back in at those rates that you quoted, is that right?

They come back at good rates. The other point that we said before, our rig fleet is ready to market. We don't have to go through our CapEx upgrades on these rigs that are not going to Tier upgrades. I'll just kind of draw a story back in the rig in Chile. That rig was stored for 2 years and yes the wiring was ripped off the rig, like happens in a lot of these places, and beyond that the rig fired up and ran with no other CapEx other than getting the rig. The engine started on the first tenth of the rig ran and drilled. Our rigs are in the market, there is drill pipe and they are in good shape.

Just one last housekeeping question for Rob, I guess is, why is it that the tax rate was as low as it was, and why will it be that again in the fourth quarter?

There is a combination of things that are fairly complex, but its some revenue they just taxed at lower rates and the FX gains have a different tax regime. So it's fairly complex and it's a good deal of tax planning goes into it. So I don't have a simpler answer for you.

Chock it up to accounting, jiggery, pokery then?

It's real stuck; it is more complex than a one sentence answer.

If you look at the cycle, we are at comparatively lower earnings level still, so factor that in as well.

The next question is from Victor Marchand from RBC Capital Markets. Please go ahead.

First one, just on Mexico realizing that it's small position for you guys. But just wanted to get your thoughts there near term on the contracts and how does that market come into play as you look at your international opportunities? Is that going to be a two rig market for the foreseeable future? Are you guys looking at opportunities down there over the next two, three, four years?

Victor, we've got the headlights on we're watching the market. I will give a lot of clarity what really plays on 2011 in Mexico yet. My sense is that this corner for tech field will become active again, but boy it's still a price dog fight up there. And we are doing really well with our super series rigs in other places right now. So I'm not going to focus on that likely. We are happy with our deep work in South networks either been signed off, renewed, or its being renewed. But we know it's secure for the next couple of years. So I'd say we would be focusing more on the deeper plays rather than getting into the mess in Mexico.

As relates to the opportunity set, as you guys look around the world, whether it's the Middle East or so, Mexico would be another market that you guys are eyeing to build out a more significant presence, or would you put it behind, say, what you guys may be doing in the Middle East?

Victor, there is a limited number of bids out there right now, and if I give any indication whatsoever, everybody that competes with me knows what we are talking about. So I am just not going to give any guidance, unfortunately not much to talk about until we have something to talk about, Middle East, Latin America.

And the other question I had, just as relates to the comments on pricing, potentially flattening out, in the near term in the US and just wanted to get a sense is that across all Tiers where you guys think that could occur? And I guess what would be driving that, particularly when you're looking at the Tier 1 fleet essentially sold out and Tier 2 starting to push out to that 70-75% marker, where things start to get tight, start to get some pricing there. So just trying to understand the dynamic of pricing in the US going forward and how to think about that in relation to where utilization is?

Yes I think 3.683 tcf on gas and storage is going to put some pressure on the commodity price. Could we see a pull back in gas drilling that would just affect the market? Absolutely. I think that risk is there. I think there's enough demand in the oil side probably take up most of the rigs. But probably, the likelihood of having price leverage over leverage from the supply side gets a bit looser for a while. I think we need to get some clarity on richer prices before we get back into a price equation of the market on the big rigs.

And where would you say the greatest price increases have occurred over the last three months? Has it been the Tier 2 as utilization has started to move there? Or has it been Tier 1? Any color behind that?

Its Tier 2 and Tier 1, both. Tier 1 one remains strong pricing. But as the Permian picks up a little bit, there's been a little bit of movement on Tier 3 pricing even up there. So across our level but clearly is still the greatest in Tier 1.

And it somewhat markets geographies specific as, like the Balkan has been a great growth area for Precision and we've been able to push Tier 2 rates up there quite a bit and obviously Tier 1 as well.

And would you guys see a benefit of that? Again this could just be a transition period. But if rates do flatten out could your average day rates still push higher, basically the reverse of what had happened going back six, nine months ago as higher rates were rolling over to lower rates? Will you guys see that on, going the other way if rates were to flatten, where your average rates would still push higher?

There will be a little bit of carry off for sure. Victor, the rate flattening, I think that's a question that will sort itself out over the next few weeks between now and the end of the year.

The following question is from Jim Cantrell from Barclays. Please go ahead.

Kevin, could you talk about your investment in MWD and what you hope to achieve with this longer term?

Absolutely. We have seven chips on the ground right now. I think four or five are drilling today. I know our guys are having some great success out there. We currently have three strategic customers that we are working with and we've done work for as was many as about a dozen different customers. We're changing the paradigm. What we're doing is we are including directional drilling on our rigs as part of our service like we include top drives in our rigs. Now we charge extra for the top drive. So we charge extra for directional drilling. But we will save the operator the cost of two directional drillers eventually and two WD hands at the other rig full time. Our drillers, our Tier 1 rigs are highly qualified drillers and so far the trading on our drillers is going very, very well. So we think that knowing that 80% of our rigs are going directionally about 70% of the time and half of that business is independent directional companies. We see great opportunity for us over the next few years.

And you're just measuring, Kevin, direction plus gamma, or is it more than that?

Really we're doing the in-field style hot bed directional drilling, nothing special. Maybe gamma, not going to get into R&D. This is going to be the vanilla directional work.

Just off the shelf technology doing directional inclination and gamma at the most. No LWD tools, no grosting, no (inaudible).

Disappointing, you're have not taking on Schlumberger.

We're targeting the independent mom-and-pop directional companies that are right across North America.

Is part of your vision here with Precision to create a significant oil service company? Taken lets say a three to five year view?

Jim our view is to be certainly a Pan North American and a well positioned international or high performance high-value drilling contractor. And then we have options already on several other product lines that we're very good at in Canada.

And lastly, Kevin, can you talk a bit about what your plans are internationally and where your focus is today?

Jim, we had a slow start internationally and that market was sort of chopping itself out during 2009 and '10. It's back in the uptick right now, that's all good. But frankly there are only a handful of opportunities out there right now. There is some bids coming up in Colombia, there is some bids in Saudi, there is some bids in Kuwait, there is some bids in Iraq, but all of my competitors are bidding on the same job. So we are out there in a competitive marketplace, places where customers are looking for high performance, looking for safety, looking for maybe horizontal drilling. We obviously have our eyes very closely on Poland for shale gas. We have an engineering team right now which is working on a high performance rig design that will be mobile and transportable inside Europe. So there are a lot of things are going, but you're short of lots of good work in place, look to the ground in a couple of places until we have some work to actually talk about. It's hard for me to get too strategic on what we do internationally.

Okay, I don't know if you can address what the strategy is in Iraq but that's one market that could be a lot of rigs looking forward, is your strategy to bid in conjunction with a big oil service company on integrated packages or what?

We are exploring those avenues right now. Jim there's lots of ongoing activity in Iraq and I don't what to be too specific. That's why it's a virtual marketplace.

And in general with the projects that you are bidding on, how do you think the returns compare internationally versus what you can get here in North America today?

Frankly, I will tell you that I think that the peak prices in North America because we have the sharp cycles book in Canada and the US. The peak prices in North America are really attractive pricing. But at the same time those swaps come quickly and suddenly. I think what we see internationally is much smoother revenue stream; you know lower peaks but certainly much higher troughs. And as we look at these markets, Canada is a substantial market, US is a larger market. Internationals are very substantial markets, even if you exclude China and Russia, it's still a substantial market, with large cap players that have long term plans that don't drill season to season but they drill for three or four, five years. It's a very attractive business for us and we have thought of being there as a high performance driller supporting international oil companies, large service companies and some of the national companies, its very attractive to us.

Thank you. The following question is from Jeff Mochoruk from Cormark Securities. Please go ahead.

Just wanted to get a little bit of clarification on your CapEx number, did you bump it up. So you have $218 million for this year and $82 million for next year. So is that $82 million in addition to the $218 or is that rolling over and it will be $136 million for this year? How is that?

It's in addition to $218 million. So the total capital from projects started in 2010 is $300 million but we can't, we won't get a script this year.

Okay and of that $82 million for next year, there is no maintenance of CapEx, and that's just completely rig upgrades and new builds, is that correct?

That's correct. That's all expansion CapEx and so of course we're now to the point of announcing our 2011 capital budget but there will be maintenance CapEx on top of this and other things that we'll talk about in December.

And you've seen a pretty sharp ramp-up here in your rig count in Canada in the past month, kind of 25 rigs above your average for Q3, can you kind of give us a mix of what those rigs that have come on are in terms of tiers and in terms of singles, doubles and triples?

We don't have that information at our fingertips, but if you will call David later he can try to dig some of that for you.

The last question is from Todd Garman from Peters & Company. Please go ahead. Todd Garman - Peter's & Company: I just wanted to ask you about the, you mentioned in the release, that there's a chance that your US labor costs would rise. And I guess, I'd be interested to know if that is, if the company is playing catch-up for lower labor costs or if it's just keeping up with where US labor rates are and that I'd be also interested in knowing if that labor cost increase were to happen and they could be passed on to the rigs that you are drilling for gas right now.

Actually a very technical question, frankly. Highly regional on labor rates; the labor work pool is not mobile in the US like it is in Canada generally. So labor rates in North Dakota is a little different than it is in West Texas and otherwise. So it's going to be a regional sort of group of increases. And the short answer is yes, we will pass it on to the customers. However the longer answer is that we are not waiting for a renewal, we will have to decide whether or not we are still competitive. So I'd say we are likely to being successful of passing it through sort of ranges in the 50% range. Todd Garman - Peter's & Company: So would it based on current utilization levels than that your margins should be flat toward there now or do you think there's actually a chance that you might decline given that prices are likely to be flat?

I don't think they will decline. I think we'll be fine and I think we will be able to see slow increases here and there, regional bump ups in price and if there's competitive region that we have to increase the rig rate, likely we are increasing the rig rate there a little more so it tends to wash itself out. But I don't want you to walk away believing that it's like Canada where we can push most of this through. This is different. Todd Garman - Peter's & Company: And then just lastly on the $84 million of upgrade capital, can you at least give us a sense of which business line it's focused to? Is it focused to the drilling side or to the completion side?

Most of it towards drilling.

We have no further questions at this time. I would now like to turn the meeting back over to Mr. Wehlmann. Please go ahead.

Well, we just want to thank everybody for being on the call today. We appreciate your support, talk to you soon.

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