Dale M. Dusterhoft – Chief Executive Officer Michael A.

Baldwin – Senior Vice President, Finance and Chief Financial Officer Donald R. Luft – President and Chief Operating Officer Gary Summach – Director of Reporting-Investor Relations

Dan MacDonald – RBC Capital Markets Maynard Holt – Tudor, Pickering, Holt & Co., LLC Travis Butler – Simon & Company Scott Treadwell – TD Newcrest Securities Dana Benner – AltaCorp Capital, Inc. Greg Colman – National Bank Financial Jon Morrison – CIBC World Markets Kevin C.

H. Lo – FirstEnergy Capital Corp.

Andrew G. Bradford – Raymond James Todd Garman – Cormark Securities, Inc.

Jeff Fetterly – Peters & Co. Andrew G.

Bradford – Raymond James Ltd.

Thank you very much. Good morning, ladies and gentlemen.

I'd like to thank you for attending the Trican Well Service conference call for the second quarter of 2013. Here is a brief outline of how we intend to conduct the call.

First of all, Mike Baldwin, our Senior Vice President of Finance and CFO will give an overview of the quarterly results. I will then address the issues around current operating conditions and the near term outlook for each of our regions.

We'll then open the call up for questions. Joining us today and available to address questions are Don Luft, our President and Chief Operating Officer; and Gary Summach, our Director of Reporting and Investor Relations.

I'd now like to turn the call over to Mr. Baldwin to discuss the overview of the financial results.

Thank you, Dale. Before we begin our discussion, I'd like to point out that this conference call may contain forward-looking statements and other information based on current expectations or results for the company.

Certain material factors or assumptions were applied in drawing a conclusion or making a forecast or projection, as reflected in the forward-looking information. A number of business risks and uncertainties could cause the actual results to differ materially from these forward-looking statements and financial outlook.

These risks and uncertainties include, but are not limited to fluctuating prices for crude oil and natural gas, changes in drilling activity, general global economic political and business conditions, weather conditions, regulatory changes, the successful exploitation and integration of technology, customer acceptance of technology, success in obtaining issued patents, the potential development of competing technologies by market competitors and availability of products, qualified personnel, manufacturing capacity and raw materials. Among the risks are the ability of the oil and gas companies to finance their operation in their unforeseen factors.

Please refer to our 2012 annual information form date March 21, 2013 for a more complete description of business risks and uncertainties facing Trican. Our second quarter results were released yesterday and are available on our website at www.trican.ca.

As noted in our press release, consolidated revenue for the fourth quarter of 2013 was $397 million, a decrease of 5% compared to the second quarter of 2012. The adjusted consolidated net loss was $50 million and adjusted loss per share was $0.34 compared to an adjusted net loss of $49 million and adjusted loss per share of $0.33 for the same period in 2012.

Funds used in operations were $29 million compared to $44 million in the second quarter of 2012. Canadian revenue for the second quarter of 2013 decreased by 17% compared to the second quarter of 2012.

Revenue for job decreased by 12%, that’s a 26% reduction in pricing was partially offset by an increase in fraction revenue relative to total revenue. In addition, we continue to see an increase in fractional job sizes in Canada which also offset the pricing reductions.

The job count decreased by 7% because of a year-over-year decrease in overall Canadian activity levels. Sequentially, Canadian revenue decreased by 66%, job count decreased by 56% which compared to the 57% sequential drop in the Canadian rig count during the quarter.

Revenue per job decreased by 23% due to the 10% in price combined with a change in the service line mix. Due to the low volume of pressure pumping work combined with the strong quarter for our Canadian industrial services group, industrial services revenue was substantially higher as a percentage of total revenue.

Industrial services jobs had generally lower revenue compared to our pressure pumping service line. For our U.S.

operations second quarter revenue was down 3% compared to the second quarter of 2012. Revenue per job decreased by 15% due to pricing reductions, a smaller proportion of fracturing revenue relative to total revenue and a decrease in fracturing job sizes.

The job count increased by 15% due largely to increased cementing activity combined with higher utilization for our Marcellus and Eagle Ford fracturing crews, which was offset slightly by lower activity in the Haynesville and Oklahoma. U.S.

operating margins for the second quarter of 2013 improved by almost 1,500 basis points on a year-over-year basis, cost reductions for guar product transportation and logistics contributed to a majority of the decrease. On a sequential basis, U.S.

revenue decreased by 4%, revenue per job decreased by 11% due to an 8% drop and a smaller proportion of fracturing revenue relative to total revenue. The job count increased by 9% primarily due to the increased activity in the Marcellus combined with higher cementing and completion tools activity.

These increases were offset partially by decreased utilization in the Haynesville and Oklahoma. U.S.

operating margins decreased by 430 basis points on a sequential basis due to the 8% decrease in price that led to reduced operating leverage on our cost structure. The impact of lower pricing was partially offset by continued progress made on reducing product transportation and logistics costs.

Overall, U.S. operating margins were below our expectations as a result of weakness in spot market pricing, lower than expected utilization of our equipment and lower than anticipated impact to our cost-cutting measures.

We will continue to focus on U.S. cost-cutting initiatives for the second half of 2013.

We believe that we can continue to lower our product handling and transportation costs through better logistics management. In addition, we expect that improvements to our U.S.

infrastructure will provide opportunities to lower outsourcing costs for repairs and maintenance and product storage in the second half of 2013. Our International Operations includes financial results for operations in Russia, Kazakhstan, Algeria, Australia, Saudi Arabia, and Colombia with Russia comprising the majority of our international results.

Second quarter revenue in 2013 for our International operations increased by 11% compared to the second quarter of 2012, revenue per job increased by 22% due primarily to the increase in fracturing revenue relative to total revenue, an increase in fracturing job size and a slight increase in Russian pricing. An increase in horizontal completions and multi-stage fracturing for our Russian operations led to an increase in fracturing job size.

The job count decreased by 9% due largely to a year-over-year decrease in coiled tubing and cementing activity for our Russian operations. International operating margins decreased year-over-year due to higher product costs in Russia as well as operating losses in Algeria.

International revenue increased by 13% sequentially, due to increases in both the job counts and revenue per job. The job count increased by 6% due to increased activity in Russia for all our major service lines.

Increased activity in Russia was largely due to seasonal improvements as the first quarter was impacted by cold weather. Increasing cementing activity in Australia also contributed to the job count increase.

Revenue per job increased by 4% due primarily to an increase in fracturing revenue relative to total revenue. International operating margins improved on a sequential basis due largely to increased operational leverage on our fixed cost structure in Russia.

The improvement in Russia were partially offset by operating losses in Algeria. During the quarter, we lowered our $6.4 million in goodwill relating to our Australian operations, which was partially offset by the reversal of $2.3 million in performance based contingency payment.

The Australian market has developed slower than initially anticipated, however, we continued to believe in the long-term potential of the Australian market and will continue to focus on growing our presence in the region. Trican’s total capital expenditures for the second quarter of 2013 were $30 million compared to $148 million for the same period in 2012.

We have recently increased our 2013 capital budget by $27 million, which is directed at the conversion of some frac pumpers to buy fuel capabilities as well as maintenance and infrastructure initiatives for our Canadian and U.S. operations.

Capital expenditures for the remainder of 2013 are expected to be approximately $100 million to $120 million based on current 2013 budgets and remaining capital expenditures on prior year budgets. We anticipate our total 2013 capital spend to be between $160 million to $180 million.

I will turn the call over to Dale who will be providing comments on operating conditions and strategic outlook.

Thank you, Mike. Our second quarter Canadian results were significantly impacted by wet weather and spring breakup conditions.

Breakup was more severe and prolong than in pervious years and this had a negative impact on all our pressure pumping service lines in Canada during the second quarter. We are expecting a strong rebound in Canadian drilling and completions activity and anticipate that our equipment utilization were behind Canada during the third quarter of 2013.

Because of the strong outlook for the third quarter, we maintained our staffing levels throughout the second quarter in order to be well positioned to capitalize on the expected increase in activity. As a result, we were unable to make any substantial reduction to our fixed cost structure in Canada during the second quarter, which had a negative impact on operating margins.

Canadian pricing levels decreased by 10% sequentially at 26% compared to the second quarter of 2012. We typically see pricing weakness in the second quarter due to lower activity levels which cause the portion of the second quarter pricing drop.

Pricing levels also weakened due to competitive Canadian market conditions as an increase in the available pressure pumping equipment in Canada comparing to 2012 has led to pricing decreases over the past several quarters. Third quarter pricing is expected to improve compared to the second quarter of 2013 but is not expected to return to first quarter pricing levels.

Pricing should remain consistent with Q3 levels for the rest of the year, as we did not believe Canadian prices will increase substantially until activity levels and equipment utilization remains strong over the same period of time. Given the expectation of lower year-over-year pricing, we believe operating margins will be lower in the third quarter of 2013 compared to the third quarter of 2012 despite higher anticipated activity levels.

Our Canadian business will continue to be strong, meeting our return on capital targets. Based on early indications from our Canadian customers, our view of the fourth quarter has strengthened and we expect Canadian demand and activity levels to remain strong during the fourth quarter.

We’re currently anticipating a typical seasonal slowdown during the Christmas season, which may result in a marginal sequential drop in fourth quarter activity. That being said, we do expect fourth quarter demand and activity levels to be above fourth quarter of 2012 levels.

We will continue to monitor spending and cash flows of our customers through the end of the year and adjust up or down accordingly. Early indications for 2014 indicate growth in the Canadian market driven by further development of the Duvernay play and LNG related activity in gas plays such as the Montney and Horn River.

We believe that to adequately service these place a large employee base and equipment fleet is required due to the size and scope of the work. We have the largest fleet of pressure equipment in Canada and over 2,000 Canadian employees and we believe this gives us competitive advantage over many of our Canadian peers.

We also have extensive experience in Horn River and continue to set performance records in this region. We’re currently doing a large Horn River project this quarter and are on target to exceed our record breaking 85% pumping efficiency from last year.

We have a broad customer base in Canada, that values our service and technology, which helps to mitigate the volatility of individual customer spending and activity levels. We continue to be a leading player in the Duvernay formation and anticipate our customers to increase their work in this area in the second half of this year and into 2014.

As a result, we believe we are very well positioned to capitalize on the growth of the Canadian pressure pumping market as it develops. In the United States, overall activity levels were flat sequentially as the average U.S.

rate count for the second quarter of 2013 was relatively consistent with the first quarter. Trican’s U.S.

equipment utilization in the second quarter was also unchanged on a sequential basis. We continued to see strong utilization from our fracturing crews operating in the Eagle Ford and Marcellus plays.

In response to the strong demand in the Marcellus, we have deployed a third full time fracturing crew in this region near the end of the second quarter and have also transferred a fourth crew from one of our southern districts into the region for the remainder of the year. Conversely, overall activity levels were flat in the Permian, and were down in the Bakken and Oklahoma as these areas remain very competitive and over-supplied with fracturing equipment throughout the second quarter.

Wet weather in the Bakken and tornados in Oklahoma also had a negative impact on activity levels in these regions. As a result, Trican’s equipment utilization levels did not increase sequentially in the Permian, Bakken and Oklahoma.

Fracturing contracts in the Haynesville and Barnett expired during the second quarter of 2013. The contracts in the Barnett was extended and utilization for this crew was stable throughout the quarter.

The Haynesville contract expired near the end of the second quarter, and we were unable to renew this contract at acceptable prices. We are currently looking to replace this work in the Haynesville, but will also consider redeploying this equipment into a more active region if necessary.

Second quarter U.S. pricing decreased by 8% compared to the first quarter of 2013.

Majority of the decrease was due to the renewal of three fracturing contracts late in the first quarter, where pricing was adjusted down to reflect current market pricing. In addition, spot market pricing decreased in the Permian, Oklahoma and Bakken plays on a sequential basis.

We expect the U.S. pressure pumping market to remain competitive for the rest of 2013 as there continues to be an excess pumping equipment into the market.

For this reason, we do not believe that there will be an opportunity of increased pricing levels in 2013. However, we expect spot market pricing to remain stable for the remainder of the year.

All of our long-term contracts for 2013 have been re-negotiated with all renewed except for the one crew in the Haynesville shale. We do not foresee additional price drops on these contract and crews throughout the remainder of this year.

We will continue to focus on increasing U.S. equipment utilization in the upcoming quarters.

Despite the competitive and challenging market conditions, we believe there will be opportunities to increase utilization through high-technology product offerings including water recycling services, fluid systems and completion tools. We believe we have differentiating technology, and our focus in the U.S.

will be to effectively market this technology to new and existing U.S. customers in order to increase utilization.

Although activity in the Bakken was delayed in the second quarter, our recycle fluid solution will allow us to increase (inaudible) activities sequentially in the third quarter. The addition of two more frac crews to the Marcellus will offset the reduction of Haynesville activity, and we anticipate overall activity in the second half of the year to be higher than 2012 levels.

This increased activity combined with additional cost control is expected to have a positive sequential impact on U.S. margins in the third quarter of 2013.

However, U.S. operating margins in the second half of 2013 will depend significantly on maintaining high equipment utilization levels in a low price environment in all of our regions.

We continue to see growth in our U.S. cementing service line during the second quarter of 2013.

Cementing revenue increased by 25% sequentially, and by 57% year-over-year as we are seeing good customer acceptance of our U.S. mining business.

The U.S. coiled tubing market remained very competitive during the second quarter and as a result, we did not see any growth in this service line during the quarter.

Our Russian operations comprised majority of our international results and activity levels in Russia were slightly below expectations during the second quarter of 2013. Several of our Russian customers were at programs which was slightly behind the schedule, which contributed to the lower than expected revenue.

Although the second quarter results in Russia were below our expectations, our 2013 outlook for this region does not change. We continue to expect revenue to increase by 15% to 20% relative to 2012 with modest improvements in operating margins.

Revenue increases are being driven by the increase in the horizontal drilling and multi-stage fracturing as the Russian market continues to trend towards more unconventional work. Second quarter financial results were strong in Kazakstan for our two fraction crews operating in this region and remain relatively consistent with the first quarter of 2013.

We continue to expect activity levels to be down slightly year-over-year with strong operating margins for the remainder of 2013 in this region. Financial results for Algeria have weakened year-over-year and are also down sequentially due to a decrease in spend activity for Trican in the region.

We were unable to renew contracts for our Algerian spending business at acceptable rates to Trican and apart two cementing units with the intention of relocating them to another region. We continue to see strong operating margins from our coiled tubing operations in Algeria, but gained some coiled tubing service line were more than offset by windup losses of our cementing service line during the second quarter.

We will continue to focus on growing our coiled tubing business and expecting it in this region.

This was the first fourth quarter of operations for i-TEC as a Trican managed business. We’re currently integrating i-TEC tools into all of our geographic regions, and as a result our completion tools business did not have a meaningful impact in our second quarter financial results.

However, we are pleased with the progress made by our completion tools division during the second quarter of this year. We are seeing good customer and technical acceptance of our i-TEC tools in the U.S., Canada and Russia and we will continue to focus on building the market presence of our completion tool business at all of our key regions.

All of our markets remain very competitive and we believe we can separate ourselves from the competition by operating innovative technical solutions. We’re continuing to develop new stimulation fluids that increase production and are lower cost for our customers, by (inaudible) fracturing fluid is a guar free product that was introduced in late 2012.

We have pumped 175 stages with this new fluid, for five different Canadian customers so far in 2013. Customer feedback has been positive as the low flow back has been quicker and cleaner than other similar fluids currently being used in the market.

We will continue the market this new system with our customers and build up a case history throughout the rest of 2013.

Our customers continue to see production increases and cost savings as a direct result of using the MVP system, and we will soon be publishing two case histories demonstrating up to 20% production increase for wells using MVP as compared to regular slick water fracturing treatments. We will continue to market this product to more customers in Canada, and are scheduled to field trial with the large U.S.

customer in the third quarter. We are in the early stages of our joint venture with Geotomo.

Geotomo is one of the worlds leading seismic software companies and we believe our combined efforts will lead us to having a competitive advantage in the microseismic business. By combining microseismic with our existing Geological and Reservoir Solutions Group, we will be able to provide our clients with an integrated engineered solution to help optimize their reservoirs and fracturing projects.

We continue to see many opportunities and challenges in all of our operating areas. We are seeing an improved outlook in Canada, challenging market conditions with opportunities to improve utilization and lower cost in the U.S.

and opportunities for growth internationally. In all of our regions we will continue to focus and providing our customers with superior operational service and technical expertise.

In June of this year, Calgary and Southern Alberta experienced flooding in a number of neighborhoods. From the Monday after flood, we have had about 25 to 50 people per day, and it’s far away the grand priority helping people restore their home, supply meals, and providing goods in flood effected areas.

We also supplied vacuum trucks and safety equipment to assist in our efforts. We continue to have our people work in the highway of reality in today.

I want to sincerely thank all of our staff who willingly and eagerly volunteered to help others in our community. They truly made a difference in a lot people lives.

Thank you for catching today and your interest in Trican, and I would like to turn the call over to the operator for any questions. Thank you.

Hi, good morning guys.

Hi, Dan.

Just wondering if there were any sort of one time issues in your U.S. operations in the second quarter that might have also kind of contributed to the compression on the margin side that might obviously not recur in the third quarter?

No, I don’t really think there was, Dan anything from a one time basis as I had mentioned in my narrative there. The main impact on the margins were lower utilization, lower spot market pricing, as well as cost cutting measures that probably didn’t quite take hold as quickly as we thought they would, we still think they’re going to come in the second half of the year, but not quite as significant as what we had hoped in the second quarter.

Yeah, and I’ll just add to that Don, it’s. It’s Dale here.

I think we were delayed a little bit in our North Dakota work. We saw for various reasons the customer delays partially weather and partially just due to the customers not getting their work programs, so which pushed that worked into the third quarter, so there’s a little bit off of that.

And then we did have a little bit of an issue with tornados in Oklahoma with one of our bases there that had a small effect, but it wasn’t a huge effect on the numbers.

Okay. And then just given the focus on the technology portion in the U.S., can you give us a sense, sort of how much of your work utilizes the high tech completion tools at this point?

Well, we sell our high-tech completion tools separate from Trican in most of our operating areas in the U.S., and so we don’t couple it fracturing with most of it, we may do the fracturing sometimes, but we don’t sell as bundle package, but we have seen very good customer acceptance and in particular with some major clients in the U.S. that is going to be substantially increase the job comp for the second half of the year for that completion tool division.

In terms of actual job numbers for i-TEC, we don’t provide that data as it’s rolled into our complete U.S. numbers.

Okay, and then just lastly turning over to Canada, maybe can you, help us sort of quantify the Duvernay opportunity specifically for you guys, it’s in the center and how much of your capacity you think is more or less going to be operating here in the play, moving up to the back half of this year?

There were probably around two fracturing crews, not every single day sometimes, it depends a little bit on customers’ workflow, but we’ll be in the two range and some days, it’s little bit higher but average too probably for the second half of the year as we go forward and we’re doing work in the North Duvernay, we’re doing working in the South Duvernay and have some pretty, very strong client presence there, we are positioned with some guys that have large capital program, both in the Duvernay this year and we’re anticipating in Duvernay 2014 as well. So we will really like our position there with our client base and we’d anticipate that that back goes up going into 2014.

Do you think if that goes up to the point that you might be able to take a bit of more firmer and a contractual commitments from some of those clients for that play?

I think that what we would like to see from our clients in that region is a continuous workflow so, there is still isn’t enough work with those clients, where they go to job and just keep that frac committed to them only, so right now we’re working with a few different clients and they may use it for three weeks out of a month but then we will go do someone else for another week. And so as soon our customers get to a point where they’ve got a continuous workflow in there then they’ll look at contracts for just that crew and I think we’re very well positioned to just kind of roll our agreements into kind of full commitments on a crew or be positioned to kind of take additional work in that area as well.

Great, I’ll leave with that. Thanks a lot guys.

Okay. Thanks.

Good morning guys.

Good morning guys.

Hi, Maynard.

It sounded like the outlook for the Marcellus on the frac side is really constructive for the back half of the year. Just curious as to whether there is third and fourth frac spreads or working in the spot market or is there some sort of contract that’s in place?

It sounded like the outlook for the Marcellus on the frac side is really constructive for the back half of the year. Just curious as to whether there is third and fourth frac spreads or working in the spot market or is there some sort of contract that’s in place?

Yeah. The third crew is working on a contract basis and the fourth crew is in the spot market.

And so, we anticipate that will remain in the market in the Marcellus area for the rest of the year, but it’s on the spot. So, we’ll adjust as we see this kind of going forward.

And it sounded like your utilization levels in some of the U.S. basins were holding up reasonably well.

Just, what are your stand today in terms of hydraulic frac spreads in the U.S. and it sounds like the one that’s in the Haynesville, you’re willing to move out if maybe, but I’m just trying to think about, kind of your idle capacity at this point on the U.S.

side?

And it sounded like your utilization levels in some of the U.S. basins were holding up reasonably well.

Just, what are your stand today in terms of hydraulic frac spreads in the U.S. and it sounds like the one that’s in the Haynesville, you’re willing to move out if maybe, but I’m just trying to think about, kind of your idle capacity at this point on the U.S.

side?

Hey, Maynard, it’s Gary. Right now we’ve got three idled crews or park crews in U.S.

We’ve got 18 available and 15 active. That 15 does include Haynesville spread that’s obviously been temporarily idle but we will all look for work in the Haynesville or another region for that crew if necessary.

Okay. That’s it for me.

Thanks guys.

Okay. That’s it for me.

Thanks guys.

Thanks Maynard.

Hi guys. Good morning.

Hi Travis

I’ll start off with some of the previous remarks that you guys made on just weather in the Bakken and Oklahoma during the quarter. But when you think about results during the quarter, could you kind of quantify what kind of negative impact weather in these two areas contributed to U.S.

results, so in terms of top line and margin impact?

We wouldn’t have that separated out as exactly what was weather, because I think it just contributed to customers just delaying their programs as much as anything else. So we didn’t really separate that out.

But I would say overall it was minimal compared kind of just the overall slowdown in some of the areas – in both those areas that we saw from variety of reasons. Sometimes it was customers just not getting their work scope lined out so that we had high utilization, [went] job to job to job, which is probably the biggest issue we saw.

And then, in other cases, that was us tendering spot market, working and getting a gap in the schedule because we just didn’t have anything to sell for a two-week period or something.

Okay. And then shifting over to the Marcellus, you guys deployed one of the ideal fleets to the area and it looks like you relocated another fleet to the basin well.

You guys have talked about in the past, 15% to 20% type margins for threshold for redeploying some of these idle fleets. Is it safe to assume that you guys are generating that kind of margins on these two fleets that were deployed to the basin?

Yeah, we’re comfortable that the Marcellus is our highest margin area. First of all we’re comfortable that we’re at a rate that, we’re in that kind of range.

Okay. And so with that kind of as the backdrop just thinking about Q3 margins for the U.S.

you should get a slight benefit from Oklahoma and the Bakken, are often being equal with no weather impact. A higher margin contribution from the Marcellus, and I guess, continued benefit from cost restructuring initiatives.

I know there is puts and takes here, but is it possible for U.S. margins to hit the kind of double-digit level in Q3?

Yeah, I think it’s very utilization dependence. And so, our view is it is possible once we keep out utilization high in our areas and in particular, the areas that we have to really get our utilization kind of lined out where we are going to job to job to job would be the Permian basin, where we still have quite a bit of equipment working there.

In Oklahoma, where we are still too choppy, we still have gaps in the schedule on the Oklahoma region and the in the Bakken, where we definitely, will see an improvement this quarter. But I would say that where we’ve got some opportunities to improve utilization in that region too.

And how well we do all this utilization issue, will probably have the biggest effect in our margins right now going forward. We are pretty comfortable with our utilization in the Haynesville and the Marcellus.

I would say that, sorry in the Eagle Ford and the Marcellus, both of those areas contract, the cruiser contracted with pretty high utilization rates and then the negative drawn us right now, would still be the Haynesville, until we get that crude either redeployed in another region or working in the Haynesville area going forward. So that one would be kind of pull backwards on us a little bit.

Okay, very helpful. Thanks for that.

I’ll turn it back.

Good thank, you.

Thanks. Good morning guys maybe touch on Canada and again try and put some goal post in here, would I be correct in assuming that the last quarter you had with sort of flat out utilization for the entire quarter, was probably Q1 of 2012?

We were probably over utilized in Q1 of 2012, actually so with equipment fleets we had and the place we’d have been running over a 100% for most of that quarter, and then we got equipment so we’ve normally will run 75% to 80% now on our equipment fleet.

Okay, so if I kind of normalize for that, is Q3 sort of shaping up to be that kind of maybe not 100% effective utilization, but it’s tough to get much busier rather than say, Q1 of this year where the first half was sort of medium paced and then the back half was flat?

Yeah, I would say at the start of Q3, we are turning down work right now and we are fully booked out and everything is rolling along at a real high level. But we are probably sitting in that 75% to 85% utilization level, which is kind of more in line with where we want to run our equipment on a long-term basis.

And our view on September looks pretty good, sometimes you can get weather issues or something like that in September, that’s great for you. But right now, I would say, it’s like a very strong quarter from an activity standpoint.

The only issue would be that pricing is down year-over-year and so that will drag down margins from kind of those peak levels that you see in from the 2012 timeframe.

Right, okay. And again just I guess quantifying a bit.

Last year Q4 you were kind a on top line down 25% in Canada, that’s not at all the sort of ballpark you are thinking about, you’re more of a typical last two weeks of December slowdown, but the rest of Q4 looking at least at this point sort of solid?

Yeah, I would say at this stage, the client that we are speaking to Q3 to Q4 is very marginal. And yeah, we are just anticipating that type of a situation where you get the Christmas slowdown.

We could end up seeing, there is a possibility of seeing, activity remain strong enough that we go through that time period, but at this point in time, our call is that likely won’t happen and we’ll see how it plays out.

Okay, perfect. And last one I have is kind of a little more detail on the horsepower disposition; still 100,000 horsepower in Canada that’s at least on the surface marked for the U.S.

that hasn’t been moved anywhere at this point?

That’s U.S. horsepower and we still have some of the parts, we have still parts of horsepower, yes, brand new crews, we built and never did deploy.

Okay. And would there be any incremental CapEx if, let’s say, Canada starts to still look even incrementally better for the first part of 2014, is there any more CapEx required to get that stuff off the fence or is it just kind of hiring and training staff?

It’s mainly hiring and training staff, I think we’ve gotten up equipment in North America that if we saw meaningful increase or we needed to deploy additional equipment we have that available to us. So yes it’s definitely training and hiring people.

Yeah I may just add to that Scott, we (inaudible) our equipment, we target, it doesn’t get touched, it is all ready to go, there is not many parts taken off of it, yeah it’s all basically all I have to do is idle about and have people staff it.

Okay, great the last one maybe a bit more detail on that shift you have had in the States, did you say that the shift the moving cruise into the Marcellus kind of offset the impact of idling that Haynesville crew is that sort of the way to think about it that right now is a bit of a wash on the revenue side, but probably accretive to margins?

It’s going to be, it’s really going to be dependent on that utilization on that spot crew in the Marcellus. I think we have the possibility of that playing out, but the Haynesville was fairly significant, and meaningful to our numbers, and as well carrying that crew and looking for additional work, so if we don’t get that work you might see a bit more of a negative drag on the Haynesville, so you might be a little bit down with some optimism being flat.

Okay. That’s all I have got guys.

Thanks very much for the color.

Okay, thank you.

Good morning guys.

Hi Dana.

I wanted to start with the topic of LNG in Canada we have already seen a number of announcements in a variety of subsectors where specific equipment is being lined up either existing equipment, new build equipment variety of timeframes and I know from prior calls and guidance et cetera you felt like in the middle of 2014 was maybe when you would see a specific say project related ramp or maybe contractual commitment underlying work or something that was a little harder than we are working in the right area and we know these things can start in fits and starts, so what additional color could you provide on the topic?

I think our view is still that it’s a later half 2014 event, but I won’t say the change in our view would be the customers are now starting to line up in particular some Horn River program. So, there are some customers talking about Horn River programs that involve three-year contracts that will likely be kind of confirmed and committed to later in the year and that there will be tender processes around stocks, but I think we are very well positioned with those customers with work we’ve done with them in the past to participate in these tenders and win them.

The customer that we currently do Horn River work for is also evaluating what they are going to do in 2014 and I would say later, little bit later in the year we will have some visibility and whether they increase their programs or go to little more full scale development. We are very, very well-positioned with that client and I think we are committed to 2014 work with them we just don't have a volume number at all yet so.

So it's not firm, we don't have any contracts that are signed on a longer term basis, we think that the Horn River stuff probably does in second half and overall they’re seeing quite a bit of movement that we wouldn't have seen this time even two quarters ago.

Right. How do you think about your capital equipment base over the n ext two years I’m sure there is some measure of advanced planning contingencies et cetera you’ve got a fleet in Canada that’s quite well utilized, although, of course some seasonality around it, quite a bit more oil capacity in the U.S.

At what point, what do you need to see before you would move meaningful capacity out of the U.S. or do you fear that that may abandon the market that could turn there and you would need to build in Canada, how do you think about that?

No we don’t anticipate anything having to build anything for Canada. We still have those three-part crews that are assigned to our U.S.

operations, but they’re built in Canada, they are built in Canadian standards and they can be deployed very, very easily into the Canadian marketplace. With (inaudible) Mike talked about earlier just a staffing thing.

So that would be our intent if we start seeing Canadian activity grow and start pushing our past where we were comfortable on the utilization of our existing fleet. And I still think we would have some utilization move on our existing fleet yet in especially on some quarters where every quarter time varies a little bit.

But if we start pushing that up then we’ll add though that new build capacity that has to be deployed into the Canadian marketplace. In terms of positioning ourselves for Horn River activity as Mike said in his comments, we are converting some additional equipment to our biofuel capacity.

That is partially for Horn River activity as our customers in that region are looking at piping gas right to their sites and having biofuel operations. And so we’re converting some more of our fleet, we’ve converted some already and kind of in the process of converting some right now and we’re going to convert more of our fleet biofuel capacity that is primarily related to L&G activity in the Horn River and or the Montney.

Long-term, as we’ve talked about in the past, there is possibilities that you build little bit different style of equipment, we had experimental pumpers that we’ve built and are trying that use different power mechanisms that we’ve had as R&D projects for some times and are basically making sure that we understand all the nuances of running something without a diesel engine nor traditional diesel engine. That will allow us to potentially if we have to design new style frackers in the future.

Yeah, actually my new question with respect to the Biofuel how do you make the return on capital decision to do that by converting to you simply put yourself in a better position to get the work or do you think that there is an immediate return in doing so potentially with higher pricing I mean there is a capital decision and then an offset hopefully economic return.

Yeah, I think there is, it is a combined thing first of all, it puts you in a good position to get the work and so that it’s going to be a potentially requirement for some customers in the Horn River area that if you don’t have biofuel you’re not going to be able to participate in these large projects and so that’s going to be a requirement, and then the other aspect is there is going to be cost savings on the fuel side which we will share with our customers but we certainly see some opportunities there ourselves.

Right and I guess just a final question on the Russia I mean there is clearly some growth in that market although turned out to be still somewhat waxing and I wonder if you still as encouraged on the evolution of the Russian marketplace sort of India Wheel House or whether it’s proving to be I guess that still somewhat waxing?

Yeah I think that it’s been little bit slower than we had expected obviously which is to use your term waxing, yeah I think that there is good progress there but it’s like any other market where you start moving to different style of work in unconventional fracturing and people have plans and they don’t really know exactly how that unfolds, we start seeing a little bit delay here and there, and that type of thing. I would say that some of the commentary that we had on activity levels not being quite expected it to in the second quarter.

A large part of that was related to TNK-BP. There seems to be in certain areas some management changes in there, put the (inaudible) acquisition, which pretty much usually creates paralysis with customers when there is management changes.

So we didn’t see as much activity as we first anticipated, as a result big part of it and there was a couple of smaller customers that also had some issues on location with their wells. They weren’t quite ready as quick we thought.

You still have a few delays as the Russian market learns more and more both little unconventional horizontal fracturing as well as kind of just regular market issues and the net acquisition that’s creating some delays as well.

Okay, well that’s great. Thank you.

No, I am all good guys. Answered earlier.

Okay. Thanks Greg.

Hi guys.

Hi, Jon.

How meaningful was the spread in terms of difference between what you guys were expecting to get and what the customer was demanding on the Haynesville crew, that rolled over in the quarter?

The pricing spread on that one?

Yeah, like it wasn’t even close or is it just still competitive adjusting lot of cash?

I think it got down to an operating margin and a return on capital for Trican that was not worth doing basically. So I think we had a opportunity to match pricing in that particular area or to lower that pricing in that area, but it was getting to a level that we just weren’t comfortable with.

How much lower would pricing had to go in the U.S. where you start making the decision to start parking additional capacity on selective crews that it just doesn’t make sense from a wear and tear perspective.

It’s not just pricing as we’ve talked about. We’re fine with pricing lowering in the few areas as long as utilizations are.

We could potentially go down in pricing in a couple areas, improve utilization and have higher margins. So utilization is actually disruptively for the most of our pricing is pretty low in a lot of the regions, utilization is having a bigger effect right now on any swing in our margins and pricing would be.

So the two of them are combined and so its really hard to say that how much lower can pricing go, because relative if it’s [sauced] by utilization we actually have an improvement in margins and we see that in our strongest areas like Eagle Ford and the Marcellus, first Eagle Ford and yeah I am sorry the Marcellus where we didn’t take pricing high, gets in there but we still kept relatively good margins.

So it’s really just a function of covering the cost base is a regular programs at this point, they get margins up?

It would be a function of improving our activity levels in the current pricing environment in Oklahoma, Permian and Bakken primarily and then also in Haynesville crew. I think we kind of know what we are going to get to some extend and in our other areas with the exception of as Mike talked about that one Marcellus Park crew which anticipate will do well with that one, but there could be some volatility or variability as that one in spot market work.

Okay and just on the Marcellus stuff; where are you guys actually staffing that from?

We staff it out of Pennsylvania.

Okay, so it is domestically staffed from that region?

Yeah, that’s correct, we will hire people within Pennsylvania, then we have one crew that we transferred in there came out of the Permian.

Okay. So is there potential for remote operating cost now one crew to come down over time?

Has become more permanent in that market?

Possible.

Okay, so yes, thanks guys.

Hey, thank you.

Good morning, folks, can you kind of talk about, how much of your work during the quarter was 25 (inaudible) versus non?

We had four crews in Canada and four crews in the U.S. that were 24 hours of our total fleet.

So roughly half of the North American fleet.

No, no our American fleets around 15 so.

It’s about 25% of the U.S. horsepower was on 24 hours in the second quarter

Okay, and the Marcellus how much of the, at what point do you see that becoming a lot more saturating I guess, so maybe all workers, you guys are moving more equipment (inaudible) talked about moving more equipment in, and I expect other guys, are you guys seeing that saturation point yet, or what do you think that looks kind of maybe 6 to 12 months out?

We’re currently contracted on the three crews that we are comfortable, then the fourth crew is spot markets, so there is something sustainable or some sustainability to saturation on that spot market crew. And right now we’re not seeing the market become saturating.

There is still customer opportunities in that region that we’re able to do for the work flow.

Okay, great and last thing is I just want to clarify your remark on Q4 in your written comments you were suggesting that Q4 is going to look and in Q3 and I think there was question asked before about whether is it just a seasonal effects of Christmas you were saying that Q4, it was quite strong, so I’m trying to reconcile that, how you see Q4, is it a seasonal effect or is it a demand effect?

It’s a seasonal effect, is what our expectation at this stage.

Okay, great. Thanks, that’s all from me.

Thanks, Kevin.

Thanks. All these smart guys have already asked all the questions that I was looking for, so thanks.

Thanks, Andrew.

Good morning. I just wanted to get your sense based on your discussions with your clients in the Duvernay shale, when they may get to continuous workflow.

Do you have any sense when that might happen?

There is someone talking about already for 2014, so we won’t know it until they finalize their capital budgets later in the year, which is usually anywhere from that October to November timeframe, that’s when we get clarity on that. But I would say that, that one time in particular is probably ahead of the others, and potential to go to a bigger program next year, and some others are talking about it, it’s a little bit early to say on the other side, I think one would be a little further ahead than some of them.

Okay. And then just moving to the U.S., based on what you – or what your clients are telling you now for the fourth quarter, absent any improvement in equipment utilization from new clients, what would be your expectations or expectation for how U.S.

activity levels shape up based on what your clients are telling you that you might do in Q4 based on their budgets?

Yeah, so I think, right at present time, it’s – we think we’re going to have that December slowdown maybe not as severe as we saw last year, but we’ll still see December slowdown that’s related to Christmas, not too much talk from our clients on slowdown due to budget cuts or budget spending at the present time. But we’ll – that will evolve as it goes as we usually try to find out later in the years on that one.

But right now it looks pretty good.

Okay great, thank you.

Good morning guys, a couple of quick questions. On the CapEx side the decision to increase the capital program versus shifting CapEx around and or paying off debt, can you walk us through that please?

Yeah I mean it’s really the CapEx that you are looking at isn’t incremental CapEx for more equipment. I mean as we talked about there is retrofitting for bi-fuel on some of the frac pumpers, which is obviously a initiative that we’re focusing on for the Horn River, and then as well as some infrastructure and maintenance CapEx.

So it’s really just maintaining what we currently have and that type of thing. So at this point in time, we still are in a mode of keeping the minimal CapEx effort out there, as we’ve talked about previously, we announced a pretty small CapEx budget at the start of the year and did mention that there was the possibility that creeps up a little bit, we would basically manage it on a quarter-over-quarter basis and I think we’ll continue to do that.

The bi-fuel pumps that you are converting, are you going to move entire crews over to a bi-fuel scenario, or are these bits and pieces still?

Well it will end up being higher crews if you are going to be in a Horn River application; in that case they are going to supply fuel in a compressed or LNG fuel to the site. So no you want to have whole crew able to do that type of work.

Okay, sorry I guess what I’m asking there is, do you expect those crews to run full-time on a bi-fuel or natural gas basis or is it still going to be a mix of diesel and Nat-gas?

I would say that it depends on how the contracts kind of get awarded and what our work scope is in a few of the areas where the customers want to run biofuel. But right now the view would be that they will probably switch around and do some diesel and some biofuel work.

Okay. On the Canadian outlook side, you are more positive commenting for the, mostly Q4.

Is that work that was scheduled to go in the first half or in Q2 that is increasing demand for the second half, are you hearing about or hearing from your customers about CapEx increases?

It’s not necessarily CapEx increases. It’s more, I shouldn’t say that.

There are some customers that have increased CapEx. So some of our clients have increased CapEx earlier this year in that.

So they increased their spending for the second half of the year. So it will be a little bit of that.

And then in other cases it was just scheduled work that they planned on doing in the second half of year. It is a work that’s pushed out of Q2.

We’re catching that in Q3 for the most part and I would say that we’ll probably get through most of the Q2 type stuff we had scheduled this quarter.

Okay. Last question.

On the Marcellus side, the impetus to adding the two incremental crews in that market, are you expecting the rig count to increase or are you expecting to take market share away?

So we’ve already contracted the one crew in there. So we basically, I guess, have to take in market share from someone else there or we’ve, or the customers have added capacity and need the additional crews.

And then the spot market crew, I would say, is for the most part just, it’s already working in that area and it’s going to be committed through the third quarter in that area and it’s basically, probably picking up market share.

Great. Thanks for the color.

Okay. Thank you.

You’re back.

Sorry, I had a mute button on and I lost my chance again. I had two questions, I only ask one of them, the other one I had is, we’ve had some pretty cold weather in Western Canada here for the first part of July.

Is that having any impact on your workflows or has that sort of changed some of the utilization rates and that you’ve thought you were going to get originally in the third quarter? And second question is, if you’re running 75%, 80% today, and somebody comes, customers are coming actually, why you’re turning that business away necessarily, which mean going to 85%, I know it’s not your target, but it’s got to be look like something like a gift from God today to begin in that kind of utilization?

Yeah, sure, I can answer that one. So, what was first part of your question again, sorry?

Weather (inaudible).

Yeah, this is Michael. On that side, I don’t think the weather has had a major impact.

There was a little bit of a delay at the start of the July as a result of flooding and kind of some of the, people not being in Downtown and that everything. But we fully expect to catch that up by the end of the quarter with too much difficulty.

So, not no real impact on the weather from July.

Yeah, and in terms of the utilization, Andrew isn’t so much that you can take on the work, it’s how you can take on the work. So it’s a scheduling issue.

So if you have a crew that’s committed in the Montney on a certain day and a customer comes to you and wants to work down in the Cardium, the next day, you just can’t get to it in time. And if the customer, if it’s a smart market type customer, then potentially it’s going to get that elsewhere or he is going to reschedule of into our schedule when we have a gap in the schedule.

So it’s actually, we would absolutely take it on if we can go from a Montney well to another Montney the next day, but if we have to drive down to the Cardium or to a [liking] well or up into the Deep Basin and we just can’t logistically get it done in time. That poses us the biggest issue on taking on more work.

But we’ll do everything we can to keep our clients happy and do the work whenever possible, just sometimes logistically isn’t possible. And even on the infrastructure, I’d say (inaudible) and product sometimes does really allow us to do that on if it’s a real big move for a one well package or something.

Okay. Perfect sense.

Thank you. Actually I do have one more relates to iTEC.

At the time of the acquisition there was the compensation of the consideration structure a lot for a sliding scale based on certain financial targets. And I know you don’t want to comment too much about sort of what the profitability looks like from the iTEC product line, but can you say sort of where you are in terms of that range of profitability?

Yeah, I think that at this point in time it’s basically meeting the expectations that we have for profitability coming into the acquisition and I would say that the continued consideration is very much the threshold there, is very much set, and based on where our expectations were at.

So (inaudible) not to define a point on, but are you closer to sort of the base line or is it you’re hitting on some of the upside figures a little bit?

It’s too early to tell to be quite honest, I mean, like the second half of the year the big part to see where it comes in that. So I would say that we’re probably near that base line at this stage, but it can swing pretty dramatically.

Okay. Just one last question then I’ll leave alone, is that the financial target for iTEC had to be relate to 2013 performance is that right?

Yeah.

Okay. Thank you very much.

Yes. Well, thank you very much.

We thank you for your participation in our call today. We look forward to talking to you at the end of the next quarter.

Thank you and have a great day.