Dale Dusterhoft - Chief Executive Officer Mike Baldwin - Senior Vice President of Finance and CFO

Clayton Kovach - Tudor, Pickering, Holt Dan MacDonald - RBC Capital Markets John Daniel - Simmons & Company Scott Treadwell - TD Securities Brian Purdy - PI Financial Dana Benner - Altacorp Capital Jon Morrison - CIBC World Markets Kevin Lo - FirstEnergy

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 third quarter of 2014. 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 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 Senior Director of 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 operations and other unforeseen factors.

Please refer to our 2013 Annual Information Form dated March 21, 2014 for a more complete description of business risks and uncertainties facing Trican. Our third 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 third quarter of 2014 was $771 million, an increase of 41% compared to the third quarter of 2013. The adjusted consolidated profit was $43 million and adjusted profit per share was $0.29 compared to an adjusted profit of $10 million and adjusted profit per share of $0.07 for the same period in 2013.

Funds provided by operations were $114 million compared to $71 million in the third quarter of 2013. I will provide commentary on our Canadian operations financial results on a year-over-year basis as the sequential comparison between the third and second quarters is not as meaningful due to the seasonality of the Canadian business.

Commentary on the financial results of all other geographic segments will based on sequential quarterly basis, as we believe this comparison provides the most meaningful insight and analysis into the third quarter financial results for these regions. Canadian demand was very strong throughout the third quarter and led to 30% increase in revenue compared to the third quarter of 2013.

One of the drivers of the strong Canadian top-line results was an increase in fracturing intensity led to a 25% increase in revenue per job. Fracturing intensity can be measured by both stages and sand volumes pumped per well.

Fracturing stages per well increased by 25% and sand volume per well increased by 30% on a year-over-year basis for our fracturing service lines. Year-over-year increases in pricing, 24 hour operations and demand arising from stronger customer cash flows also contributed to the third quarter revenue growth.

Canadian operating margins for the third quarter of 2014 improved by 200 basis points on a year-over-year basis. Margins benefit from pricing improvements and increased operating leverage on our fixed cost structure from higher activity levels and utilization.

These factors were partially offset by year-over-year cost increases, the most significant cost increases related to sand transportation as well as higher product costs caused by stronger U.S. dollar.

For U.S. operations, revenue increased sequentially by 18% due to increases in utilization, fracturing intensity and pricing.

Most of the pricing gains were realized in the Permian and reflected service quality improvements and strong overall activity levels in the region. Existing idle fracturing capacity was deployed in the Bakken and Permian during the third quarter, which also contributed to the sequential increase in revenue.

Operating margins in the U.S. improved by 170 basis points on a sequential basis due to increased operational leverage on our fixed cost structure as well as pricing improvement.

This was partially offset by higher costs, in particular a significant increase from sand logistics and third party all-in expenses. Our international operations include the financial results from operations in Russia, Kazakhstan, Algeria, Australia, Norway, Saudi Arabia, and Colombia with Russia comprising the majority of our international results.

International revenue was flat sequentially, as increased activity in Norway and Kazakhstan was offset by lower revenue in Russia due to a weaker ruble. Although activity levels in third quarter were strong in Russia, the ruble weakened sequentially by approximately 11% relative to the Canadian dollar.

This decline had an impact on Canadian dollar revenue and operating income as all revenue generated by our Russian operations is denominated in rubles. This decline had a minimal impact on Russian operating income as a percentage of revenue as most of the expenses in Russia are also denominated in rubles.

International operating margins decreased sequentially by 220 basis points due largely to lower margins in Russia caused by changes to customer and job-type mix. Capital expenditures for the third quarter of 2014 totaled $28 million compared with $26 million for the same period in 2013.

Capital expenditures comprised primarily of maintenance programs for the past several quarters and are expected to remain between $20 million and $30 million per quarter until expansion initiatives are considered. During the third quarter of 2014, no significant changes were made to our 2014 capital budget.

Remaining expenditures on approved capital budgets are expected to be approximately $35 million to $45 million, as approximately $15 million of capital expenditures are expected to be carried over into 2015. In October 2014, our $575 million revolving credit facility was extended by an additional year and now matures on October 18, 2018.

All other terms and conditions of the facility remain unchanged. In September 2014, we closed the private placement of C$20 million senior guaranteed notes that mature on September 03, 2024.

With these recent financing transactions, we believe that we will continue to have the financial flexibility necessary to whether the cyclicality of our business, as well as execute on strategic opportunities as they arise. I will now turn the call over to Dale who will be providing comments on operating conditions and strategic outlook.

Thanks Mike. We were very pleased with our third quarter trading results that reflected our strong market position in Canada.

During the third quarter, we were able to capitalize on the customer diversity, technology, operational excellence and scale of our Canadian business. We continued to see an increasing demand for 24 hours crews in Canada during the third quarter of ‘14.

Approximately 70% of third quarter revenue was generated from 24-hour crews compared to approximately 50% in the third quarter of 2013. Our Canadian customers continued to demand more 24-hour crews due to the associated efficiency gains and with our large Canadian presence we were able to meet these demands during the third quarter and expect to be able to meet them going forward.

Third quarter results in Canada also benefited from our ability to provide technological solutions to our Canadian customers. Our MVP fracturing system continued to gain market acceptance, with recent case study showing a 30% in well production in the Montney and a 20% increase in production in the Cardium based on sampled wells from each region.

We believe that technology has led the market share gains for our fracturing business in the Montney and Cardium regions. During the third quarter, approximately 20% of the wells we fractured were used our MVP system.

We believe the MVP system can be applied to other regions in North America and we’ll focus on expanding the geographical use of this technology going forward. We completed another successful Horn River project during the third quarter of 2014.

An average of seven fracturing stages per day were completed over a five week period, which set another Trican record for pumping efficiency in this region. Due to the high utilization and efficiency of the 60,000 horsepower crew, third quarter operating margins increased by 100 basis points as a result of this project.

Strong third quarter demand provided opportunities to increase Canadian pricing levels. Average pricing increased by approximately 10% in the third quarter compared to the second quarter of 2014.

We completed work for over 180 different Canadian customers during the third quarter and believe that our diverse customer base contributed to the pricing and utilization gains realized in the quarter. Strong demand in Canada is expected to continue into the fourth quarter of this year.

Demand continues to be driven by increased fracturing intensity, as well as the rise cash flows of our Canadian customers. Typical seasonal slowdown is expected in Canada during the second half of December, which is expected to result in a slight decrease in fourth quarter revenue and operating income on a sequential basis.

However, fourth quarter seasonality is expected to be partially offset by a sequential increase in 24-hour operations and an additional 25,000 horsepower fracturing crew that was deployed in October using existing idle capacity. With the recent declines in oil and gas prices, we will take a cautious approach when making decisions regarding new equipment deployment, capital spending and cost management during 2015.

Our Canadian customers have not yet finalized capital budgets for ‘15, but based on recent discussions and initial work programs, we expect to be fully utilized during the first quarter of 2015. Overall Canadian pressure pumping supply has not increased significantly and we did not currently expect significant supply increases during ‘15.

With continued increases in fracturing intensity and a small pull back at oil field, we anticipate fracturing supply demand rebalance during next year. However, demand next year will depend on commodity prices that drive the cash flows of our customer base.

We anticipate our customers to initially release conservative budget and then adjust them as they get a better fuel for cash flow during the year. Each of our customers is affected differently by the price of gas and oil depending on their commodity mix.

The low Canadian dollar also continuous to help improve our client’s cash flow. We believe that our diverse customer base will continue to be an advantage for us in 2015.

For our U.S. operations, third quarter increases in pricing, utilization and fracturing intensity led to strong revenue growth for this segment.

Third quarter utilization was strong for our Permian, Bakken, Marcellus, Eagle Ford and Barnett regions and was partially offset by lower sequential utilization in the Oklahoma and Haynesville region. During the quarter, we added additional crews to our Bakken and Permian region, which also contributed to our growth of revenue.

Much like Canada, U.S. fracturing demand continues to benefit from an increase in fracturing intensity.

For our U.S. fracturing business, stage count per well has grown by 32% and sand volumes per well has increased by 60% on a year-over-year basis.

Although these trends have been positive for fracturing demand, they have also price significance straying on our sand logistics infrastructure. I’ll show you some trans-loading facilities, rail cars and sand hauling trucks has forced us to use more subcontractors, which has led to cost increases.

These cost increases caused July margins to be substantially lower than forecast. As the quarter progressed, we were able to pass some of these costs on to our customers through higher pricing and added additional internal sand hauling rail capacity that resulted in cost improvements with September margins improving to 10%.

Based on existing customer contracts and drilling completion programs, we expect fourth quarter utilization for our U.S. operations to be strong outside of seasonal slow-downs over Thanksgiving and Christmas.

We also expect to deploy additional horsepower to existing crews in our southern U.S. region during the fourth quarter.

Increased fracturing intensity is leading to demand for larger fracturing crews, and the deployment of this horsepower will help meet this demand. The incremental horsepower will come from existing idle capacity.

As a result, we expect fourth quarter U.S. revenue to be flat sequentially as pricing improvements and additional active horsepower in the quarter are expected to be offset by typical fourth quarter seasonal slowdowns.

We do not anticipate that seasonal slow-downs will be as large as last year as our Marcellus crews, which experienced a substantial slowdown in 2013, are expected to have strong utilization throughout most of the fourth quarter. We anticipate the utilization of our crews in our other regions will also be higher year-over-year despite the expected holiday slowdowns.

Pricing improvements and cost initiatives obtained during the third quarter are expected to be fully realized during the fourth quarter of ‘14. Therefore, we expect to see a sequential improvement in fourth quarter operating margins in our U.S.

operations. With recent improvements in service quality and continued strong demand in areas such as the Permian, Eagle Ford, Marcellus, and the Bakken, we will continue to seek pricing increases as the opportunities arise.

Despite the recent declines in oil prices, we expect demand to be strong through to the end of the first quarter of 2015 based on existing customer contracts and work commitments. However, any additional declines in commodity prices could result in reduced demand in the remainder of 2015.

We will continue to monitor activity levels in all our U.S. regions and react appropriately if market conditions change.

Majority of international revenue is generated from our Russian operations and activity levels in Russia were strong during the third quarter of ‘14. Third quarter operating conditions are generally supported by favorable weather conditions in Russia and it was the case this year.

An increase in horizontal drilling on conventional sandstones and completions activity in Russia has contributed to strong utilization for our pressure pumping fleet during the third quarter. Russian operating margins decreased slightly on a sequential basis due to changes in customer and job-type mix.

We continue to monitor the impact that existing and potential economic sanctions may have on our Russian operations. Currently, the financial impact of existing sanctions on our Russian operations has been minimal and we do not anticipate any disruptions to our Russian business throughout the remainder of this year based upon the sanctions that have been imposed to-date.

However, we will continue to monitor this situation closely. We expect our Russian business to experience typical seasonal slowdowns during the fourth quarter and, as a result, we expect revenue and operating income to decrease sequentially for this region.

We also expect Russian revenue to decrease sequentially based on recent declines in the value of the Russian ruble relative to the Canadian dollar. We have started the tendering process for the 2015 Russian work program.

Increased demand from the continued growth in horizontal drilling on sandstones and completions activity is expected to be offset by reduced spending from our Russian customers caused by existing economic sanctions. As a result, the current expectation is that 2015 revenue and operating margins will be relatively consistent with 2014.

However, these expectations could change over the next few months as our tenders are finalized. Third quarter financial results were strong in Kazakhstan for our two fracturing crews operating in the region and increased compared to the second quarter of this year due to favorable weather conditions.

Our Algerian operations incurred an operating loss during the third quarter due to continued weak utilization in the region. We will exit Algeria in the fourth quarter of this year when our current contractual commitments have been met.

We continued to develop customer relationships and establish a presence in growing international regions including Saudi Arabia and Colombia. These regions had a small negative impact on third quarter operating results.

Our operations in Australia continue to grow sequentially but still did not have a meaningful impact on third quarter international operating income. We will continue to focus on growing our presence in Saudi Arabia, Colombia and Australia during the fourth quarter of this year and into 2015 and expect to see continued growth in these regions.

We continue to be pleased with the progress made by our completions tools division. Customer acceptance of the completion tool technology in Norway, Canada and the U.S.

continue to be strong during the third quarter. We continue to make progress on expanding our customer base for this service line and expect this division to continue to show solid growth going forward.

I thank you for your attention today and your interest in Trican. And I’d like to turn the call over to the operator for any questions.

Hey, good morning guys.

Hi Clayton.

My first question is just regarding the additional idle horsepower being deployed to your existing crews in Q4. How much of the idle 60,000 will this absorb and how much larger will these existing crews be?

Yes, it’s probably right around 30,000, 25,000 kind of range that we’ll deploy to existing crews and that spread out to all of our crews, so every crew size is a little bit different. So, it’s not really particular one region growing a lot.

I would say Permian is probably seeing the biggest increase in crew size of this year.

Okay, great. And then how much of improvement in U.S.

margins are you expecting in Q4 versus Q3? Should we expect these to be above September’s run rate at 10%?

Yes. We would anticipate that we’ll be able to build on that September number somewhere between 10% and 15%.

Our internal goal is still to hit 15% at the end of the quarter or during the quarter. And we’re still working pretty hard towards that and believe that the fourth quarter will be somewhere between 10% and 15%.

Okay. And then just lastly on your goal to get 15%, is this kind of mainly come from an improvement and logistics more 24-hour work or just deployment of idle horsepower.

Can you just walk us through that?

Yes. It’s realizing some of the gains that we saw at the end of the third quarter in terms of pricing, because we’re able to push some pricing increases as the quarter went on.

And it’s also some improvement in logistics that we were able to experience in September and we’ve got some additional improvements there. We have deployed some additional Trican equipment into a lot of our operating areas that will reduce our third-party costs in some areas, which we think a lot of net benefit on our operating margins in the fourth quarter.

We still have some utilization improvements in a couple of regions that we’re working on and for us to hit 15% we’d like to see those utilization improvements realized as well.

Alright, great. Thanks guys.

We’ll turn it back over.

Hi, good morning guys. Just wondering, Dale, if you’ve seen any kind of change in tone from the client side over the last say a month or so as you work to continue to kind of bring pricing up to acceptable levels and pass costs through given what’s going on with the commodity or has there been really no change?

We haven’t yet, Dan, ever since interesting situation. I mean things are moving so quick on the commodity side of things and I think our customers there still trying to digest it themselves.

But we have a real disconnect right now with what our field people and our operations people in our various regions are hearing as compared to what’s happening on the price of oil. So right now, we still have customers looking for additional crudes, looking to expand their work programs going into ‘15.

And we’re just kind of cautious as this develops and we’ll monitor it for the next few months. But the tone hasn’t changed from the operating departments yet and we’ll see what happens as budgets get finalized here.

Are there any operating regions left in the U.S. that you’d be hesitant to redeploy idle equipment to at this point just given where leading edge margins or are they all kind of above your targeted threshold?

We still would like to see some improvement in some of our regions. So, our Oklahoma region isn’t strong yet.

We’ve made significant progress in the Barnett shale. We’ve got really good utilization and good contracts in there and good operating results there.

So, I think we’re comfortable with that. We’re not that comfortable with the Haynesville yet.

We still would like to some improvements primarily in utilization there. We’re contracted there, but we would like just more wells delivered underneath that contract.

We’re watching the Bakken is very strong for us and the Permian is improving for us. I wouldn’t say that we’re comfortable with Permian results yet.

We’d like to see some improvement there and I think there is still some pretty big wins for us there on the margin side of things. So, I think we’d be reluctant to put additional crudes in the Permian right now.

And the Bakken, even though strong we’re just a little cautious on where the price of oil is going to take that region. So, we’ll watch that for a little bit as we deploy crews.

But it’s very strong right now and there are certainly opportunities to probably grow in there.

Thanks. And then just lastly on the fracturing intensity side, I guess sort of has it continued to trend higher as you look to sort of where it was when I’m thinking about North America where it was from a propping for stage and for well base is entering Q3 as to where it exited just as and obviously there is a decent potential offset if we think about maybe lower completion activity on the hole next year?

Yes. It’s continued to trend higher, but the rate of growth isn’t as high as it was earlier in the year.

So, Q3 we saw a trend upward still, but not quite a substantial. A lot of that big jump that we started in the year was just as the Permian was moving and changing to a lot larger job sizes.

And I think now we’d kind of see normalized growth we always sequentially do see some stage growth for the last few years.

So, we think it would after ‘15 maybe normalizing to more of a single or maybe low double-digit kind of growth rate?

Yes. I think that’s reasonable.

In Canada we’ve seen kind of 15%, 16% for the last number of years. I think that’s a reasonable number.

We can expect to somewhere in that 10% to 15% range is probably pretty conservative or reasonable.

Okay. Thanks a lot, Dale.

I’ll turn it back over.

Sure, thanks.

Hey guys. Good quarter.

Thank you.

Dale, you said that you’ll be exiting Algeria in Q4, are there going to be any material costs associated with that exit that we should be modeling?

No, it’s Mike here, John. There shouldn’t be too much significant, I mean we’re currently reviewing everything that we’ve got, but quite a bit of the equipment that we have in place will be able to move most of that out of our Algeria -- in fact all of it out of Algeria.

And so there shouldn’t be any impairment on those assets. And the area that we’re taking a closer look at, at this stage is on the inventory side, but we don’t really have a significant balance there.

So I don’t expect any material write-downs on that side of thing.

And I’ll add John that we’ve been preparing this for a little while, so we’ve been peeling out inventory and selling some of the inventory and kind of reducing our exposure there for the last quarter or so.

Okay. And then I just want to jump to one other topic and I’ll turn it back over.

But with respect to the sand logistics, do you see enough third-party, those internal capacity expansions such that the cost will go down in the coming quarters? And then as follow on to that, a lot of you guys have been able to pass through surcharges to your customers given those challenges, I’m just wondering if -- as capacity eases, as your customers come back and remove those surcharges so to speak, just your thought?

Yes. So, it’s kind of two parts to that.

We believe that third-party trucking usually is a very fluid business and we do see that kind of respond quickly to supply demand. Truck is a very mobile as you know and can haul groceries one day and sand the next quite often.

So, over the next couple of quarters, we do see more third-party haul coming to play in certain regions in particular. You will see us also look at Trican internal solutions.

I think there are some things that we have underway that will help reduce our reliance on third-party trucking, both through internal trucking that we’ve deployed as well as flat storage, railcars trans-loading facilities and things like that. So, we’re not just relying on third party trucking to reduce our logistic property, have some internal things as well.

The price increases that we’ve passed on weren’t so much surcharges; they were just basic general increases on our price per job. I mean some of that was certainly predicated by the price of sand cost increases.

But I would say that every renegotiation of a price will probably take into account all things in the industry. Our customers they’ll will be looking at overall industry activity and everything, when are we negotiating prices and will be looking at our cost structure when we’re doing it.

So to say, it’s not going to come into effect, they don’t really look too much internally at our direct costs coming down on that front, when they’re renegotiating it’s more what they think where the market is at.

Got it, okay. Thank you for your time.

Okay. Thanks.

Thanks. Good morning, guys.

I wanted to maybe start actually in Russia. You said that the currency changes have had a pretty minimal effect on margins.

I’m just wondering that since the end of the quarter, there has been some further devaluation and I’m just wondering if at some point Russian margins do get squeezed by the currency, if at some point -- some of the costs will start to move independent of supply and demand based on the currency or if you’re really comfortable that sort of margins will be driven simply by business fundamentals?

Hi, Scott. It’s Mike.

Yes, we don’t -- basically because our cost structure is largely denominated in rubles, I mean it’s between 80% to 90% denominated in rubles, you just don’t see as much impact on the margin side, when you translate your revenue and your operating expenses into Canadian dollars. That being said, when you start seeing -- historically when you’ve seen some situations where you had significant devaluation in the ruble what tends to happen is you start seeing a spike in inflation.

So we haven’t really seen a lot of that yet, but I think most economists are kind of expecting that in 2015 and that’s something we’ll have to be prepared for during that year.

Okay, good. Next one on maintenance CapEx.

You gave a pretty good outlook there but I know certainly in the past you had a pretty decent surplus of capital spares that sort of helped offset maintenance CapEx. Is that sort of run rate of 20 million to 30 million a quarter?

Is that sort of purely -- it’s not aided by any extra spares you’ve got, that’s the number you should think about based on the assets and activity you have today?

Yes, I mean I don’t know if everybody believes us on this. But we don’t really rely heavily on our spares.

We always keep all of our equipment well maintained and operating. So, even the numbers in the past haven’t been masked by that all.

So I think that’s a pretty good run rate when you start talking about where we’re at today and everything else. As things come along and as there is some referb that mask that might spike up a little bit, but I don’t expect it to move meaningfully.

And certainly in regards to on a go forward basis, as we deploy additional equipment then, we’re going to have to get a market read at that point in time as to whether we need to do any expansion on a capital or anything like. But at this stage, given the uncertainty where the oil price is, we don’t expect that conversation to happen for the next little while.

Okay, good. And then the sort of last operational one for me is can you give us an idea of your kind of pricing contract coverage over the next two quarters?

Obviously Canada is a little bit more a fluid situation but you’ve certainly got some firm handshakes. It’s sort of half the revenue kind of there is a pinning it for pricing or is it something more than that?

It will be much more than that. We’re pretty close to 80%, 85% of our work committed in the quarter.

We normally would just have a small amount of spot work kind of in environments that we’re in right now. So Canada looks pretty committed and I’d say pretty solid on pricing staying where it’s at.

In the U.S. we’re pretty comfortable with our exposures all the way through Q1 and our commitment through Q1 past that, we’ve got some contracts negotiations going forward, but they’re kind of normal rollovers that we would have in our business.

There is no real special trigger points or anything like that where everything rolls over at once.

Okay. And can you just today what the spare or idle horsepower you’ve got in North America is?

It’s today at 60,000. So, we talked about deploying some additional assets in Q4 to increase crew sizes.

So, by the end of the year we should be between 30 and 35 and that would be kind of what’s left in terms of brand new horsepower that hasn’t been used yet.

Yes. And I will say Scott we’re still looking at opportunities to deploy that 30, 35, but little cautious as we see budget unfold with our clients as to what their programs are going to be.

But saying that as of today right now we could absolutely deploy in a lot of difficult markets because customers are looking for additional equipment. And so we’re just trying to get a view on their long-term plans and their long-term commitment to that equipment.

And I anticipate that we’ll have some opportunities. We have a few regions in the U.S.

in particular to deploy that equipment here in the next couple of quarters.

Okay. And one last one, actually Mike, with the big reduction in share prices subsequent to the quarter-end has Trican executed any buybacks under the NCIB?

Well, not subsequent to the quarter-end because we were in blackout, but we’re taking a look at that right now and would be surprised with that little activity on that in the fourth quarter.

Okay, perfect. That’s great guys.

I appreciate the color. I’ll turn it back.

Good morning guys.

Hi Brian.

I just want to ask about your 24-hour operations, obviously it’s been moving up pretty significantly. Do you see some upper limits for that in Canada, it sounds like you were 70% in the quarter and I was just wondering if you could contrast that with U.S.

and what you see happening there in terms of upper limits and what you could actually manage on a 24-hour basis.

Yes. I would say that U.S.

is very similar; we’re right around 70% range as well in the U.S. We could probably take that up a little bit more as depending on customer demand and the customers we’re working for.

It’s the staffing issue, but saying that we’re pretty good at hiring training people with enough notice that we’ve had to at overnight. But if we have a planned growth in our business we can usually get them on board within a quarter and up and running.

So, we kind of continue to look at that, but potentially there is additional upside there.

Okay. And in terms of CapEx, I’m sure you guys are still thinking about 2015.

But would you say that you are leaning more to being a bit conservative, I mean it sounds like your customers maybe conservative, I’m just wondering if your mind set is in somewhere place?

Yes. We’re very much just looking to maintenance capital right now with exception of some sand and hauling infrastructure that we’ve potentially looked at going into ‘15, but pretty minimal on that front.

The amount of infrastructure and capital spend on that part of the business isn’t huge to be in the $10 million to $15 million range right now. But we’ll see as the year goes on and we’ll finalize our capital program in December and release at that point in time.

No new pressure pumping equipment, we’re still are in a good position of getting a lot of cash generation ability of our existing asset. So, we have a huge upside on our U.S.

business in particular by just improving margins on that existing asset base, which will drive significant growth for us. So, we don’t have to be building a lot of equipment at this point in time to have a really good ‘15.

Okay. And I just wanted to ask about maybe some of the weaker areas you’re in, in U.S., the sort of dryer gas areas that are suffering from utilization that’s maybe not as good as your four big areas.

Are you still looking at maybe cutting some of those areas and redeploying those assets?

Yes, we’re always looking at it. And if we can’t get them fixed, then we do exactly that.

And we’ve done over this year. I would say that we’ve got the Barnett fixed, it’s doing really well for us.

So it’s really the Haynesville area and that’s the one that we’re a little concerned with. Saying that we have a contract in place.

It’s a contract that if the customer delivers on the well count, then it will be the contract for us, but it’s been a little weak for the last few months in just in terms of us getting the required utilization out of that crew. So, we’ll continue to work with our client to get a higher utilization but if we can’t see it, maybe it’s an area that we keep, we watch really closely.

Rest of our operations I think we have some initiatives, employees that should get our utilization improved. And we’ve got to keep on it and keep working it but not as concerned with them.

Okay. I mean would you say the Haynesville was at a level in the third quarter where you would keep the crew working there?

No. It’s got to improve and we’re in process of doing that.

So, I think we actually recently saw some improvement there. So, we’ll continue to focus on it and want to see a few more -- more than one month improvement there.

But right now, I’d say it’s heading in the right direction.

Okay. Thanks.

That’s all I had.

Thanks.

Good morning, guys.

Hi Dana.

I wanted to start with pricing in Canada; it’s been tortuous exercise here I guess last six months, you pushed hard, you talked about 10% realized pricing gains et cetera. Obviously a tight market today; it has supported that and good work.

But having said that, given what we’ve seen in the market, how sticky do you think these pricing increases will be? It’s one thing to convince clients that enough is enough and you simply can’t maintain industry wide fleets with the kind of margins we’ve got to but cash flows are cash flows for E&P companies.

And there is a point where it just doesn’t matter so curious to get your thoughts on that as we move through 2015.

Yes, we think were pretty sticky through the first quarter. And after that there is a pretty significant downturn in the industry or probably our clients coming to us asking for some kind of reductions that we’re going to be fighting back say and that we need to keep our margins up and the normal stuff.

So good to the end of Q1, pretty comfortable with that and we’ll see what happens after that as year unfolds.

If you were to hazard a guess, do you think prices all else equal would be stickier in Canada versus the U.S. or is too early to tell?

I think we’re comfortable in both regions to the end of Q1. Canada still has a little tighter supply demand overall and a few less competitors.

So normally, it’s a bit stickier as a region compared to the U.S. So I guess if compared, I’d say Canada is a little sticker but we’re pretty comfortable that our pricing agreements are in place for Q1 in U.S.

as well.

Right. Two more questions.

Firstly, what’s the likelihood we could see a positive upward surprise in terms of gas related activity of course we’ve all been focusing on oil so much, but gas prices are creeping up and LNG is potentially not all that far away? And is it possible we could see upward surprises on that side of business?

Yes, it depends on clients as much as anything because they’re so diverse and they have such a blend of commodities within their cash role models, it’s condensate; it’s crude oil and it’s gas. And some of our clients that are still getting most of their cash flow from gas play like 70% of their cash flow from gas.

And so, we would anticipate that those clients are actually pretty comfortable with the recent gas price increase in Canada. So, we’ll see how it goes Dana, it’s hard to predict.

I wouldn’t want to call a gas boom or anything but I think you’ll see client-by-client we’ll respond differently based on their cash flow. The big thing is just cash flow and with cash flow on the upturn as well that if they generate more cash, they spend it; if they generate less cash, usually cut back.

All right. And then just one last question.

So of the various areas in the U.S. where do you think your most exposed to oil states in the 70s; would it be within Texas or the Bakken or how would you think?

Well I think the areas that we watch we would watch the closest would be the Bakken and the Permian; they’re both pretty oily areas. And it’s really hard for us and hard for you guys too to figure out where the breakeven is for our clients exactly in those areas.

And if oil stays for a prolonged period of time, we’ve probably got to test that and get a feel for who is going to keep go on and who will slow their programs down. But those still -- I mean just logically I think they’re most affected by oil within our U.S.

operations. So rest of it is pretty not as big an issue because you have gas, you have liquids, you have some oil, it’s more of those to the areas.

Right. Okay.

I’ll turn it back. Thank you.

Okay. Thanks Dana.

Good morning all.

Hi, John.

Was the Horn River working in Q3 of this year larger relative to last year either from a revenue or margin perspective?

No, it’s less actually it was only about 4% of revenue and a 100 basis points of margin for us and that would be less than Q3 last year.

So, it’s fair to say that that was an incremental to year-over-year margin improvement?

No.

Can you talk about what you are actually doing on the logistics side to manage the cost inflation? And should we be thinking about logistical investment spend being an ongoing outlay for the next couple of years or is it largely going to come to an end in the next few quarters?

Well, so it’s right now it’s kind of three components that go into it. You’ve got trucking, you’ve got rail and you have got trans-loading or storage we’ll call it.

And I’d say that we have efforts underway in all of them that in all cases will reduce, it tend to reduce our cost in those areas. And I don’t -- it depends on sand growth goes quite honestly as to whether that’s continue to be a problem, but I don’t anticipate people are going to see the same type of or same rate of growth in amount of sand pumped like we saw this year in next year.

This year was really an abnormality in terms of the U.S. market in particular where we’re pumping 60% or 70% more sand, 60% more sand than we did in January.

So, it is our year-to-date growth. So, I don’t anticipate that that will be the case, which means that obviously once we guide and spent some money in there and think to get ourselves right sized again, we probably won’t have spend as much money going forward.

That’s we see another jump up or something.

So, do you believe that the bottlenecks are bigger from the mine to the local trans-loading facility or the local trans-loading facility to the wells side?

The bottlenecks, it varies by region, quietly honestly. Sometimes it’s real.

It’s not too much at the sand based or at the mine based. We’re pretty solid on getting sand and that’s not the big issue.

But in some regions, there is not enough rail capacity to go in. So, the Permian has a issue with rail capacity just getting into that region and other area that’s trans-loaders haven’t kept up and you just can’t get trans-loaders that is post year work.

So the cost associated with being far away. And in other areas as well, if third-party trucking has been scarce and rate of increase.

So, it varies a lot. U.S.

is a big area and there is a lot and similar to Canada we haven’t seen this pronounced effect, but similar to Canada certain parts of Canada have the same issues.

In the U.S., was there any one-time noise in July or August that would have been a drag to the overall margin? I guess I was just surprise in context to exit at 10% on average 10% in September, but I would have thought the average would have been a little bit higher?

Yes. Well, July was [bridle] for us, gave us a scare and resulted it was primarily the logistic side of the business which came up.

It’s always growing and that it hit us pretty hard in July and it took us little bit to get ourselves sorted out in terms of adjusting to that cost increases, a lot of passing on some of those costs to our clients, which we did throughout the quarter. So, July is quite a bit below 5% and just nearly about zero kind of thing.

And so we had to adjust the business quite rapidly to that and improvement in August and then where we want it to be in September for the quarter, but definitely started at a low base.

Okay. Just a point of clarification, you didn’t inclusive of Christmas and Thanksgiving interruptions you believe that U.S.

margins can come in between 10% to 15% coverage in the quarter for Q4?

That’s our view right now and that’s our internal goal right now that we’ll able to continue to build upon what we saw in September.

What visibility you guys have from a contract perspective on the stuff you’ve recently deployed in the U.S.? Is that largely playing the spot market or has fairly good customer visibility at this point?

Yes. It’s got pretty good customer visibility through the end of Q1.

On the completion tool side of the business, given the growth that you guys were experiencing, is it something that you have to start looking internalizing manufacturing to get scheduled supply or you’re okay at this stage getting enough systems?

No, we are spending some money in this part of the business and particularly in the Canadian business in terms of putting a tool fabrication facility in place, which we’ll open next quarter for us kind of in the December timeframe. And so that will help our business and we’ve also broadened our supply chain a bit.

We’re not planning on manufacturing components ourselves yet, but we’ll just continue to examine that as we go forward and as we get scale in that business.

Last one just for me. On the pricing side, do you believe that you can actually push pricing on a sequential basis further anywhere in North America right now over the next few quarters relative to the macro environment that we’re in?

Yes. That’s a good question.

Our view is that there are certain contracts that we have as the company that we think are under market and we will try to be pushing those. We’ll see how successful we are in the environment that we’re in.

But I would say Canada, I wouldn’t anticipate that we’re going to be able to push too much in Canada, I think most of our work as I alluded to earlier, it’s kind of secured and I don’t think we’re pushing too much more on pricing, little maybe on spot market. In the U.S.

though as we talked to our clients over the next few quarters, this certain area this certain contract that we’ll still work on and we’ll see how that goes.

I appreciate the color. Good quarter.

Yes, thanks Jon.

Hey guys. In your press you talked a lot about your technology offering and how much of the business you think that you won is because of your technology and -- or is it just because you have a good product to augment the existing business?

Yes. Well, we’re -- we believe that it has won us market share and we’ll not quantify it for competitive reasons.

But we certainly, as I mentioned in the call, we’re seeing become material to our fracturing business now where 20% of the work we’re doing is using the MVP technology which is patented by Trican and public or patented by Trican and protected by patents. And so we think we’ve got a proprietary technology there that is making a difference for us and basically gaining some market share but we’re not going to disclose exactly who and how.

All right, that’s fair. Now has the structure of your company changed in terms of cost?

I mean I think we know that the fracturing industries tend to have little more fixed cost. Have you changed the company in a last little while to have as more variable or if we do see a downturn, you’re going to have the same down draft issues as you normally would in most down cycles?

Yes. Kevin, it’s Mike.

It hasn’t really dramatically changed from split between variable and fixed cost. So yes, and I would expect this to -- if there is a down draft then you’ll see similar reactions that we’ve had in the past.

Obviously we take a look hard at cost cutting as much as we can in the areas that are discretionary and look to salaries and wages and people as a last resort. At this stage, we don’t anticipate any need to do that, but obviously you have to keep an eye on that as we see where the oil price and other commodity prices go.

Great, fantastic. That’s all from me.

Thank you.

Thanks.

Hi, thanks for putting me back in. Just a quick one, housekeeping on depreciation.

Have you guys started to point the idle equipment, is that much higher again in Q4?

It wouldn’t be significant. The brand new stuff that’s never been used has been depreciated yet, that doesn’t get depreciated till it’s deployed.

But the other stuff that was previously used has been depreciated the whole time. So, I wouldn’t expect to bit of a change there.

Okay. And then the last one for me is just on international.

I know you mentioned that Russia gets impacted because of seasonal things, but you also talked about some of the other areas that might grow just as you look at the whole international segment in totality, is it the guidance for revenues simply a little bit lower in Q4?

Yes, it is John. And Russia still dominates our international results and our international revenue growth as well.

So, if it comes back, it will pull down the whole international segment in terms of revenue.

The other areas we are expecting a little bit of growth, but they’re still relatively small and don’t really amount to being a needle mover at this stage.

Fair enough. Thank you guys.

Okay. Thanks John.

Yes. Well, thank you very much for your interest in Trican this quarter.

We’re looking forward to talking to you again when we finish our fourth quarter and have our conference call at that time. Thank you.