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Executives

Dale Dusterhoft - Chief Executive Officer

Mike Baldwin - VP, Finance and CFO

Don Luft - President and COO

Gary Summach - Director, Reporting Investor Relations

Analysts

Scott Treadwell - TD Newcrest Securities

Brian Purdy - Global Hunter Securities

Greg Colman - National Bank Financial

Jeff Fetterly - Peters & Co.

Kevin Lo - FirstEnergy

Trican Well Service Ltd. (OTCPK:TOLWF) Q4 2012 Results Earnings Call February 27, 2013 11:00 AM ET

Operator

Good morning, ladies and gentlemen, welcome to Trican's Fourth Quarter and Yearend 2012 conference call and webcast. As a reminder this conference call is being recorded.

I would like to turn the meeting over to Mr. Dale Dusterhoft, Chief Executive Officer of Trican Well Service Ltd. Please go ahead Mr. Dusterhoft.

Dale Dusterhoft

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 fourth quarter of 2012. Here is a brief outline of how we intend to conduct the call. First of all Mike Baldwin, our 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 region.

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, 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.

Mike Baldwin

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, includes 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 2011 annual information form dated March 22, 2012 for a more complete description of business risks and uncertainties facing Trican.

Our fourth 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 2012 was $486 million a decrease of 30% compared to the fourth quarter of 2011. Consolidated loss was $7.7 million and diluted loss per share was $0.05 compared to profit of $115 million, diluted profit per share of $0.78 for the same period in 2011.

Fourth quarter revenue in Canada decreased by 41% or $173 million compared to the fourth quarter of 2011. Revenue per job decreased by 25% due to a 13% year-over-year decrease in price combined with a lower proportion of fracturing revenue relative to total revenue. The job count decreased by 22% compared to the fourth quarter of 2011, and was consistent with the 22% decrease in Canadian rig count. Fracturing activity was down approximately 40% due to a slowdown over the holiday season, and as customers completed 2012 capital budgets.

Canadian revenue decreased by 24% sequentially in the fourth quarter of 2012, revenue per job decreased by 13% compared to the third quarter of 2012, due to a 7% pricing decline combined with less fracturing revenue as a percentage of total revenue. The job count also decreased by 13% relative to third quarter of 2012.

The strong activity levels in the third quarter combined with reduced fourth quarter activity levels over the holiday season, contributed to the sequential decrease in Canadian job count. Canadian margins decreased sequentially by 1010 basis points. Decreases in pricing led to a 700 basis points decline in margins and reduced utilization on our Canadian equipment led to lower operational leverage on our fixed cost structure. Which accounted for the remaining 310 basis point decline.

U.S. revenue decreased by 20% compared to the fourth quarter of 2011, and an increase in the job count was more than offset by a decrease in revenue per job. Job count increased by 11% and benefited from an increase in cementing and coil tubing activity.

Fourth quarter cementing job count increased by 166% and coil tubing job count increased by a 157% compared to the same period in 2011. These increases were offset partially by a 6% decline in fracturing jobs which compares to the 13% decrease in U.S. rig count during the quarter. Fourth quarter revenue per job decreased by 28% compared to the fourth quarter of 2011.

A year-over-year pricing decline of 13% a decrease in fracturing revenue as a percentage of total revenue and a decrease in fracturing job size, lead to the revenue per job decrease. Fracturing job size has declined due to the increased work performance in oil plays such as the Permian where job size is generally lower.

Revenue for the fourth quarter decreased by 13% relative to the third quarter of 2012. The job count decreased by 11% due to reduced oil field activity as rate count decreased sequentially by 5% in our areas of operations. Fracturing activity was down by approximately 18% primarily due to low utilization due to the Thanksgiving and an extended December slow down. This decrease was partially offset by increased cement and oil tubing jobs as we continue to grow these services lines.

Sequentially U.S. operating margins improved by 1050 basis points. Decreased guar costs and progress made on the cost cutting initiatives led to the improved margins. Realized guar cost were approximately $6.50 per pound in the fourth quarter of 2012 compared to approximately $9 per pound in the third quarter. This reduction led to a 500 basis point improvement in Operating margins.

Cost cutting measures including reduced employee product transportation base and discretionary costs accounts for the remaining 550 basis point improvement in the U.S. sequential margins. Our international operations include financial results for operations in Russia, Kazakhstan, Algeria, Australia, Saudi Arabia and Columbia, with Russia comprising the majority of our international results.

International revenue increased by 11% compared to the fourth quarter of 2011. Revenue per job increased by 42% as increased horizontal work in Russia led to increased fracturing and coil tubing job sizes. Increased pricing and more fracturing revenue as a percentage of total revenue also contributed to the higher revenue per job. Job count decreased by 19% due largely to declines in Russian cementing and coil tubing activity offset slightly by an increase in fracturing jobs.

Revenue for our international operations decreased by $4.3 million on a sequential basis. Job count decreased by 10% due to colder weather in Russia and customer slowdown near the end of the fourth quarter that reduced industry activity levels. Revenue per job increased by 6% due largely to an increase in fracturing revenue as a percentage of total revenue and larger fracturing job sizes.

Trican is pleased to announce a joint business agreement with Geotomo LLC to offer customers an integrated service that will combine hydraulic fracturing engineering with microseismic software capabilities. Geotomo is one of the world's leading edge seismic interpretation companies. The joint business agreement will leverage Geotomo's advanced geophysical software capabilities and Trican's depth of experience in microseismic geological and pressure pumping services to offer customized solutions to our customers. This service will help our customers optimize fracture performance and improve the production of the well.

During 2013, we'll broaden our integrated reservoir management service into the United States and it's a known existing international market. With the recent announced acquisition of i-TEC, this joint business agreement with Geotomo reflects Trican's continued commitment to provide innovative technical solutions to our customers and diversify our product lines.

Trican's 2013 capital budget is expected to be approximately $32 million, with carry over spending from our 2012 capital budget of approximately $110 million. As a result our total capital spending for 2013 is expected to be between $130 million and $250 million. This capital budget is directed at maintaining Trican's global equipment fleet and infrastructure. Given the current operating environment in all of our key regions, minimal expansion capital initiatives have been included in the 2013 capital budget and as such we are not planning to increase our North American operating capacity during the year.

Although the 2013 capital budget is modest, Trican stands by our commitment to provide service to our customers with our state-of-the-art and well maintained fleet of equipment. Many of our maintenance spending requirements for 2013 were incurred in 2012 and we are confident our fleet will be maintained in top operating conditions throughout the coming year.

We believe the 2013 capital expenditure plan is appropriate given the current market environment and our cash flow generating capabilities during the year. As such we expect to maintain our current balance sheet strength given our right sized capital budget and our favorable debt structure. Trican will continue to closely monitor its capital program and cash flow from operations and make any necessary modifications with greater visibilities obtained throughout 2013.

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

Dale Dusterhoft

Thank you, Mike. Our fourth quarter results reflect reduced drilling and completions activity in Canada at the end of 2012, cost improvements in the U.S. despite the weak market conditions and international results that were consistent with the expectations. Canadian pressure pumping activity was down during the fourth quarter of '12 and last year-over-year and sequential decreases in Canadian revenue and operating income.

In the fourth quarter of '12 the number of active drilling rigs in Canada decreased by 22% and the number of Canadian wells drilled was down 19% compared to the fourth quarter of '11. Sequentially Canadian rig count increased by 10%, but the number of wells drilled was down 4%. Despite the sequential increase in Canadian rig count fracturing activity was down substantially near the end of the quarter as customers slowed activity in December as 2012 capital budgets came to a close and the Canadian rig count fell to approximately 200 rigs.

Canadian pricing decreased by 7% compared to the third quarter of '12 and by 13% compared to peak pricing levels seen in the fourth quarter of 2011. Additional pressure pumping supply combined with reduced activity levels led to the pricing decrease. However, peak pricing seen in the fourth quarter of 2011 occurred when the Canadian market was significantly undersupplied and we did not expect these pricing levels to be sustained.

Demand for pressure pumping services in Canada is expected to be stable in 2013 compared to 2012, with recent industry forecasts reflecting a 3% increase in the number of wells drilled this year. These growth estimates can be conservative if activity levels in the Duvernay to grow more than expected.

Duvernay activity levels were limited in 2012 with our customers test of their land positions. We expect Duvernay activity level to increase moderately in '13, but activity in the region could increase more than what we expect given the huge potential of the play. Today the Duvernay has been one of the largest land buys in our Alberta history and we expect at least 6,000 drilling locations will be required to develop the basin.

The Duvernay play has oil, liquids rich gas and dry gas windows and based on the work Trican has performed in the region thus far, we believe pressure pumping costs per well will be second in Canada to only the Horn River. Duvernay fracturing and crude sizes are expected to be 30,000 to 40,000 horsepower, with approximately 15 to 20 fracturing stages per well. Trican has worked with several customers in this region and we believe we are well positioned to capitalize on increasing Duvernay activity levels beginning in 2013.

The amount of frac - available fracturing equipment in Canada has increased substantially over the past year as the industry built equipment into an undersupplied pressure pumping market in 2012. Trican in particular has increased fracturing capacity by three crews, which is a 17% increase in crews and a 29% increase in horsepower.

Despite the steady Canadian pressure pumping activity anticipated in 2013 increased supply is expected to result in a year-over-year reduction in pricing. However, most of the price declines occurred in the second half of 2012 and we do not expect any significant additional pricing decreases in Canada during the remainder of '13. Despite the relatively flat demand and increased supply we believe the Canadian market in the first quarter is under supplied and will be slightly over supplied or balanced in the second half of the year.

We do not expect a meaningful increase in Canadian horsepower supply in 2013 and believe the sustained demand levels will keep the market close to balanced on a full year basis. We will continue to monitor the capital budgets and cash flows of our customers and changes to commodity prices which could positively or negatively change second half of the year plans for our clients. We will react appropriately should market conditions change.

We expect 2013 first quarter activity levels in Canada to significantly increase relative to the fourth quarter of 2012, as we enter the busy Canadian drilling season. However, we do not expect first quarter activity level to be as strong as last year as the rig count is down approximately 10% year-over-year. This combined with the year-over-year price decrease of 13% that we are carrying into the quarter will result in first-quarter operating margins that are higher sequentially but lower year-over-year.

Cementing activity increased in early January, but fracturing activity did not increase until mid to late January. February has seen full utilization as we are turning down work in all of our service lines. [Barge] bookings are very strong, but our results will be dependent on how weather holds up later in the month.

Overall U.S. activity levels weakened during the fourth quarter of 2012. U.S. rig count decreased in our areas of operation by 13% compared to the fourth quarter of 2011, and by 5% compared to the third quarter of 2012. The drop in U.S. demand was largely due to reduced activity over the U.S. Thanksgiving and December periods.

The U.S. pressure pumping market continued to be oversupplied during the fourth quarter and no significant improvements in overall market conditions were noted. Despite the oversupplied market, Trican pricing remained relatively stable on a sequential basis for both contracted and spot market crews.

Due to the weak U.S. operating environment, four U.S. fracturing crews remained idle during the fourth quarter including two new crews that have not been manned and two crews that were previously active. The four idle U.S. crews are expected to remain inactive until U.S. market conditions improve, or a strategic opportunity arises in North America or internationally.

U.S. pressure pumping demand will continue to be driven by commodity prices, new play development and the cash flows and capital budgets of our U.S. customers. Based on the current commodity price and capital spending environment in the U.S., we are not expecting a significant improvement in 2013 pressure pumping demand relative to demand levels seen in the second half of 2012.

We are not anticipating a meaningful amount of new horsepower to enter the U.S. market in 2013. There is potential for modest declines in available U.S. horsepower to occur in 2013 if equipment is redeployed out of North America and into international markets, and if older U.S. equipment is permanently retired; however, we are not expecting a significant drop in U.S. pressure pumping supply in 2013. And the market will likely remain over supplied until we have seen increased in rig count. That being said, the U.S. pressure pumping market can change quickly and we'll continue to monitor commodity prices and the spending of our customers and react appropriately if market conditions change.

We expect U.S. spot market pricing to remain relatively stable in 2013 given the expectations of a steady supply and demand environment in the U.S.; however, pricing could soften slightly in some of the more active oil and liquids-rich gas plays if equipment continues to be redeployed into these areas. In addition, approximately 60% of our active U.S. fracturing equipment is currently under contracts and will be expiring in 2013.

We will be working with new and existing customers to obtain work for these crews as contracts expire. We expect to see some pricing declines in oil liquids areas in 2013, as contracts are renegotiated and expect [2000] utilization of our U.S. fracturing crew to be higher than the sec half of '12.

In particular, we accept the equipment utilization to be higher for our crews in Permian, Eagle Ford and Bakken as we continue to establish our technology and customer relationships in these new regions. In addition, we are starting to see some renewed interest in the Marcellus as we are currently active in this region and expect utilization to be higher than what we saw in the second half of 2012. As a result we do not expect pricing declines to significantly impact our margins, as equipment utilization and cost control should have a more meaningful impact on our 2013 margins and pricing.

Despite the prospect of an oversupplied U.S. pressure pumping market in 2013, we believe Trican's U.S. operating margins will increase gradually throughout the year as utilization improves and we continue to reduce our cost. We have undertaken substantial cost cutting initiatives that are expected to improve margins and have already started to see some of the benefits of these initiatives in the fourth quarter and in the first quarter of 2012 - fourth quarter 2012, and the first quarter of 2013.

In addition, we're expecting realized guar prices to continue to decline in the first quarter of '13 as we work through our higher priced inventory. Trican is confident that guar prices will remain within a reasonable range in the future due to the existence of fully developed and field-tested (Inaudible). Trican has developed two guar replacement systems, which are cost affective replacement to conventional guar based fluid system.

One of these systems is a proprietary unique guar free system that not only reduces guar use but also reduces cost over other guar-free systems, lowers formation damage and has improved well productivity. We are pleased to report the both systems have been field tested and have gained customer acceptance and allowed us to obtain additional work for our U.S. crews.

Our Russian operations, comprised majority of our international results and revenue and activity levels in this region were up year-over-year, as customers increased that our work scope to meet 2012 capital spending budgets. Fracturing activity was particularly strong as job count increased slightly and our fracturing jobs size increased substantially year-over-year, due to the increase in work performed on horizontal wells.

The increase in fracturing activity was partially offset by reduced cementing and coil tubing activity. Despite the improved fourth quarter results, some Russian customers did not meet spending targets for 2012, which contributed to '12 result that went below expectations.

Russian activity levels were down sequentially due to cold temperatures typically experienced near the end of the fourth quarter. The emergence of horizontal completion to multistage fracturing continues to be positive development in Russia.

Approximately 12% of 2012 fourth quarter Russian fraction revenue was from work performed on horizontal wells compared to between 2% and 3% in the fourth quarter of 2011. This is an important development for the pressure pumping industry in Russia as the shift towards more unconventional drilling and completion is expected to increase the demand for horsepower in the region and places a larger emphasis on technology.

Fourth quarter operating results were strong in Kazakhstan for our two fracturing crews operating in the region, we continue to see improved results for our Algerian operations as year-over-year margins improved substantially. We're also continuing to grow and establish our cementing business in Australia and had solid revenue growth for our cementing service line during the fourth quarter of 2012.

Despite the improvements in Algeria and Australia financial results during the fourth quarter were below expectations in these regions.

Based on the results of the 2013 contract tendering process at our Russian operations, we expect '13 revenue to increased by approximately 25% compared to 2012. The estimated revenue increase is based on 2% expected rise on overall activity combined with 23% expected increase in average revenue per job.

Expected increase in average revenue per jobs is a combined result of a trend towards larger fracturing job sizes in multistage completions, shift in the sales mix toward more fracturing work relative to coil-tubing and cementing and a modest increase in pricing.

A high rate of inflation in the Russian market and strong competition continues to challenge the Russian operations profitability. However, we are anticipating moderate improvements in operating margins in 2013, as a result of the shift in our work scope to higher margin work and multistage frac activity. Including Completion Tool revenue and a continued focus on optimizing the Russian operations cost structure.

2012 was a successful year for our two fracturing crews in Kazakhstan, and we expect the Kazakhstan pressure pumping market to be stable in 2013. Activity levels are expected to be down slightly; however, operating margins are expected to remain strong in this region.

Our Algeria operations improved in 2012, in particular for our coiled tubing service line. We expect Algerian coiled tubing activity and pricing to remain in the -- to remain stable in '13 and we will look to secure additional contracts for this service line to keep equipment utilization strong. The cementing market in Algeria was very competitive in 2012 and we expect this to continue in 2013. We will look to increase pricing and utilization of our cementing equipment in Algeria this upcoming year.

Our 2013 strategy in Australia will be to continue to expand our cementing service line and build new customer relationships. We expect to see moderate growth in Australian cementing revenue and operating income improvements in '13.

We are seeing growth in fracturing in this region and we'll be tendering a number of fracturing contracts in the first half of the year. Through our joint business arrangements in Saudi Arabia and Columbia, we are working to establish our presence in these markets and expect to participate in pressure pumping tenders in 2013. Initially, we will look to add cementing and coiled tubing services with an eventual goal of being full service pressure pumping company in these regions.

During the fourth quarter we continued to market our MVP Frac process, that has been designed to reduce proppant settling that occurs during slick water fracturing treatments. Initial results have shown that in comparison with regular slick water fracturing treatments, MVP Frac transports proppant 25% farther into the reservoir, suspends proppants throughout the frac and thereby increases reservoir production. Additional benefits include higher sand volume concentrations resulting in 25% less water usage on average and a reduced need for coiled tubing cleanouts.

In Canada we've [upped] MVP Frac on 279 stages for six different customers during the second half of 2012 and of contracts in place for 2013. This technology is exclusive to Trican and we believe it will give us competitive advantage in the market.

Trican has taken a significant step into the global horizontal multistage completion market with the recently announced acquisition of i-TEC, a technology focused developer of innovative completion tools. i-TEC has developed several completion and intervention tools which we are particularly excited about. And in particular are excited about i-TEC's patented i-FRAC valve system. This multi stage frac system allows for valve clusters to be placed on prolific portion of the reservoir so the customers can optimize production regardless of whether the completion is cemented or open hole.

The i-FRAC technology maximizes the number of fracture initiation sites with up to 400 valves in a single completion being activated by only 20 valves/ Trican believes this technology is game changing and should convert plug and perf users sliding sleeves and allow Trican's customers to perform more cemented sliding sleeve completions with confidence. We will offer this technology as a standalone service line in all of our regions worldwide.

As a oil and gas services company we believe it is important to minimize the impact of our operations on the environment while also reducing cost for our customers. Accordingly, Trican is continually seeking ways to reduce fresh water usage and water usage overall while continuing to provide high quality technology and service to our customers.

Trican has designed a series of salt-tolerant friction reducer to give optimal friction reduction performance in water containing high salt concentration. These friction reduces passed [drinking water] standard test, and facilitates the use of produced and flow back waters alleviating the strain of fresh water sources. In addition, we can run our new friction reducers at nearly half the concentration when compared to conventional friction reducers leading to reduce cost for the customers. These products, combined with our water recycling initiatives have gained quick market acceptance as they reduce well cost. Trican has obtained work in 2013 in our U.S. operations with new clients as a result of this technology.

We believe we will gain market share and prove our technical reputation in U.S. operations as we continue to commercialize all of our water reduction technology. Trican was recently named one of Canada's top 100 R&D spenders and we continue to focus on separating ourselves from our competition and meeting the needs of our customers through innovation of technology.

We believe, we will continue to improve our market position and value to our clients as we continue to commercialize new products that reduce our customers cost or increase production from their wells. Trican is awaiting the final installation to convert six, 2500-horsepower fracturing units to duel field system units, to use both liquefied natural gas and diesel. Units are expected to be ready for field testing and job performance evaluation by June of this year.

Engine manufacturers, expect cost savings from reduced diesel fuel usage and fuel efficiencies related to the engine performance specifications. Using LNG in a conventional diesel engine has evolved rapidly over the past year. And we are optimistic that the most recent technology that we are testing has led to a product design that is well suited for our service conditions. This is an exciting development for our industry and we'll continually to actively participate in this development and partnership with our engine manufactures.

Effective January 31, of this year Michael Kelly has resigned from Trican to pursue other opportunities, Michael joined Trican in 1997 as a CFO and remained to that position until March of 2009. He then became the Senior Vice President of Business Development and in June 2012 transferred to Russia as Senior Vice President, Russia and Middle East.

In January of this year Michael was appointed our Senior Vice President EAME and CIS where he managed our operations in Russia, Kazakhstan, Algeria and the Middle East, should say that was in January of 2012. Michael has had a large inputs on the direction of Trican, he was part of the corporate executive group that saw the company grow from a Canadian operation with the few hundred employees to one, that's close to 6000 employees worldwide in 9 operating countries. We wish Michael the best in his future endeavors and thank him for his many years of service to Trican.

We are pleased to announced that David Jones, Vice President of Business Development will assume the duties of Michael Kelly and will become the new Vice President EAME and CIS. David will continue to oversee our Business Development Group until its successor has been named.

Despite the recent weakness in our major markets, Trican has made progress on some key strategic goals in 2012. We expanded and developed our presence in international markets including Columbia, Saudi Arabia and Australia we expanded our U.S. geographic equipment by opening new bases in the Bakken and Permian we enhanced our position as technological leader through development of innovative pressure pumping fluids and systems from our research and development centers in Calgary, Houston and Moscow. And we expanded our Completion Systems Service line through the acquisition of i-TEC in early 2013.

In addition, the addition of our Geotomo joint venture is also very strategic for us as we will able to offer our clients an integrated reservoir management service that add values to our fracturing service line and will also run as a standalone business.

We believe these efforts combined with the continued focus on meeting the needs of our customers have positioned Trican to capitalize on growth opportunities in new and existing markets as they arise in the future. 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.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) And the first question is from Scott Treadwell from TD Securities. Please go ahead.

Scott Treadwell - TD Newcrest Securities

Thanks guys. Good morning. Wanted to I guess touch on Russia first with the growth in the horizontal multistage work that's happening there, do you foresee in the short term any need for more robust, higher horsepower equipment that the same transition you saw in North America or is what's there can handle what you see coming down the pipe in the next year?

Dale Dusterhoft

Yeah thanks, Scott. We're currently planning on running with our existing equipment fleet to handle the additional working and the more high technology work that's there. And we're monitoring this pretty closely and may transfer some assets from North America into Russia if we continue to see the trend increasing throughout the year. And also as we continue to see our rate changes on that jobs or the job designs change. So it's a bit of a fluid situation I'd say at the present time our planets to keep everything kind of intact to run with what we have but we'll monitor closely.

Scott Treadwell - TD Newcrest Securities

Okay, thanks. And the second one there in Russia, obviously you've got a pretty nice bump on a revenue per job in 2013, I'm just wondering does i-TEC form part of that that you negotiated the contracts and have the tool revenue now as part of that but the deals closed or does that represents some of the incremental revenue in Russia?

Dale Dusterhoft

In that revenue there is some aspect of tools, we had a legacy contractor, a legacy arrangement that was supplying that. And we're currently reviewing what we're doing there. We do believe that i-TEC will probably play more of meaningful role as we go along but that's going to be dependent on the growth of the activity and what our customers want to see from a two perspective.

Scott Treadwell - TD Newcrest Securities

Okay, that's good, thanks. Turning to the U.S. I know we've gone through contracts a few times on these calls, can you just may be remind that may be the age of some these contracts that are rolling over, I know you probably wouldn't want to speculate on what the magnitude of a price drop might be but you know how old are some of these contracts and had they been renegotiated as some point during 2012?

Dale Dusterhoft

Yes, some of them had been renegotiated, a large of portion of them, there would be few that will probably take at our market price adjustment on. I would be the minority of the contracts, a lot of them have already been renegotiated as I said during 2012. They expired various times during the year, they really I would say run midyear to, well starting already now to the end of the third quarter in that range and so we'll be renegotiating as they go.

The one thing that we are seeing in all the contracts is that we're able to renegotiate higher utilization, the customers understand our need for keeping our margins or improving our margins in some of the contracts. And so we're able to renegotiate higher utilization and give up pricing and actually, if you combine those together we're not seeing a lot of margin drop, on some of the negotiations we've had so far.

But that's fluid situation as we go through it every contrast in a different region and every region is little bit more competitive than another and with this kind of deal that as we go, but so far I'd say we're not really stressed over what we've seen in terms of giving up pricing as we've been able to trade utilization for it.

Scott Treadwell - TD Newcrest Securities

Okay and also on the U.S. the guar obviously a pretty big headwind through 2012. Do you have an idea of where the guar substitutes would equate on price, I know, I had heard numbers around $5 or $6 a pound, is that still a fair estimate of if guar gets above that you're going to see some more switching to the substitutes?

Dale Dusterhoft

Yeah in our case it's probably a little bit from industry that we've got a substitute that's probably in that $6 a pound range but we've also developed some others throughout the year that our customers are using now already but it's just not just because the price of guar, it's because they're getting better performance with those fluids. And so we're actually running these fluids, they create less damage in the formation. Production has been looking a little bit better for our clients and we're running these fluids even with a low price of guar right now.

You're right on the $6 and then the some of the other fluids actually lower than that, they'd be in the $5 range and potentially even a little bit lower than that to kind of what loadings we'll run. So I anticipate they will be running more guar substitutes regardless more prices here as we're getting pretty good customer acceptance on some of these fluids.

Scott Treadwell - TD Newcrest Securities

Okay perfect and my last question is on Canada may be a bit of a higher level, you know with the transactions you've seen in the E&P space now closed and really a focus on the Duvernay and L&G resource development. Have you gotten a sense from the marketplace that, some of those projects that are coming down the pipe or customer growth programs are being viewed as a real strategic imperative and that that might limit, where pricing goes in the short term that guides again to use your words would certainly give up price to lock up a strategic client like that or people taking a more high level view that the basin is relatively balanced and any additional work is likely to tighten the basin and they're bidding it on that sense?

Dale Dusterhoft

I think that really varies, depending on the client and then also the competitor. And I will say that we've already locked up, we've met this for some time and we've got some crews working in the Duvernay this year in the 2 to 2.5 crews on full year basis for a number of different clients and we've walked up in the Duvernay. And those ones were negotiated already back in '12.

And then additional work that's coming up it really varies sometimes you have a very strong client relationship and they will value the technology offering, that we have or the service quality that we have. And they don't open it up to anybody they'll market check your price but they don't bid it. And so in some cases we obtained work that way. Other customers will have a different view on things and they'll tender it out and commoditize it a little bit more in that case it could be open to a number of different companies or competitors and you may see a more strategic type pricing on those. And really varies a lot and I wouldn't say that you could say that anything dominates over another right now, Scott.

Scott Treadwell - TD Newcrest Securities

Okay that's great guys. As always appreciate the color and I'll turn it back.

Dale Dusterhoft

Okay, thank you.

Operator

Thank you. The next question is from Brian Purdy from Global Hunter Securities. Please go ahead.

Brian Purdy - Global Hunter Securities

Good morning, guys.

Dale Dusterhoft

Hi, Brian.

Mike Baldwin

Hi, Brian.

Brian Purdy - Global Hunter Securities

I just wanted to ask about the U.S. market and in terms of the contract renewal process that you're looking at here in 2013. I mean obviously you're not looking for a lot of pricing improvement this year, I mean a lot of equipment on the market, does it still make sense to sign deals that are more than 1 year or how you're looking at your contract, your progression as these role over?

Dale Dusterhoft

Yeah they're pretty, they're one year deals right now, because we're not going to sign anything with lower margins anyhow that's a longer term deal. But a lot of the contracts that we're doing right now will have some kind of pricing renegotiation mechanism in them, in case things, you know we see cost increases like guar, or anything like that too. So it's a -- I would say there's variations in all of them but much shorter term than what they used to be so one year max.

Brian Purdy - Global Hunter Securities

Okay and then as we push into 2013 here I mean obviously you've made good progress on your cost structure in the fourth quarter. How should we thinking about your margins as we head through 2013, you are talking about gradual progression but I am just wondering if you can give us any more color as to what that might look like?

Dale Dusterhoft

Yeah, the U.S. is playing out pretty well exactly as we thought it would and we kind of messaged back almost six months ago, little over six months ago and that we would have cost improvements. Through Q3 and Q4 we said we would be slightly negative and we saw that and were still of the opinion that our margins were positive in Q1 and we're on track for that. I think it's right on track for everyone. And our believe all along what we have been guiding is that when we get to market conditions, which we believe will be kind of around the 10% range mid-year. So we're continuing to improve kind of gradually almost on a straight line basis as the year goes on. And then passed out we are going to need to see a market improvement, either you know a pricing improvement or a utilization improvement or something really it’s driven by a higher rig count that's going to get us up into the high teens or anything like that. So the self help gets us kind of where we think it maybe kind of mid teen margins.

Brian Purdy - Global Hunter Securities

Okay. That's very helpful. And looking at Canadian market, obviously you had couple of Horn River jobs in the middle part of the year that helped out. What is the outlook in 2013 for the Horn River. I mean, is activity really pulling back in that basin?

Dale Dusterhoft

Well we have still Horn River projects scheduled again with the same plan we did for last year. We had really-really good results with our client where we had optimal. Our operations efficiency where essentially we were pumping 85% of the time during a 24 hour day, which they have never seen before and our number of jobs per day was naturally higher than what the customers had seen in the past, but also ran right through their stretched targets. So, it was - they locked us in right at the end of last year as soon as we finished the project. They basically locked us up for 2013. So that's positive. That project we'll start it in June or July we don't know yet, its weather dependent on the second quarter and that's the only variability that we have not seen a defined number of wells on that project. So, we will be doing sum as we anticipate, but the projects hasn't been finalized in terms of whether we are doing 2 wells or 20 wells.

Brian Purdy - Global Hunter Securities

Okay. So you are expecting some work there, but it sounds pretty loose in terms of…

Dale Dusterhoft

Yeah they'll be loose for about another month, customer and us are meeting here. I'd say another couple of months. By April we'll have it all firmed up.

Brian Purdy - Global Hunter Securities

Okay, great. Then just a housekeeping thing, it seemed in the Q4 release where you guys mentioned some costs around i-TEC acquisition. I was just wondering if you could give some more clarity on how much that might have been and if there is any more that you would expect to see in Q1?

Dale Dusterhoft

Yes, the costs were I think about $600,000 to $700,000, its all typical acquisition type costs. I think there is a little bit more carryover into Q1, but not that significant as we closed the deal in January.

Brian Purdy - Global Hunter Securities

Okay not that material. Okay, thanks very much.

Operator

Thank you. The next question is comes from Greg Colman from National Bank Financial. Please go ahead.

Greg Colman - National Bank Financial

Just jumping into Q4 results in Canada, wondering if you could comment on the nature of the sequential pullback. Was it the kind of thing that you saw across the board in all customer or basins or was it a little bit more spotty with some areas pulling back substantially and others in fact staying relatively flat.?

Dale Dusterhoft

The basins that are most active is the ones that are driving our farc revenue and are spending revenue I guess. So it would have been across most of those basins that wasn't really anything specific, it was more customer dependent as some of the customers have already spent their 2012 budgets or weren't going to increase anything or curtailed their activity until January started. So I would say it was probably more customer specifically. Our certain customers slowed down pretty heavily that we were busy for in Q3 and actually busy for at very start of Q4 as well. Then other customers would have slowed down moderately. So more customers in play.

Greg Colman - National Bank Financial

Just then carrying on that thought, those specific customers that slowed down for particular reasons. How is that activity playing out in Q1 and you mentioned it was fairly slower rates at beginning of the quarter but picked up nicely in January?

Dale Dusterhoft

Yes. I should qualify, it picked up really rapidly on spending for us in January so we came out in the first week of January and just adding number of rigs that were cementing quite rapidly. So cementing picked up rapidly and its very normal actually that fracture lagged cementing by about three weeks, by the time you drill a hole (inaudible) gets completed. So we didn't have a of 2012 wells that were done ready to be fraced. So fracturing has anticipated really a lag than we didn't really start picking up until mid to late, mid to third week of January is when we start to get quite busy fracturing. We are busy before that, but it's not as busy as we would normally be compared to say last year. And currently I would say all the customers have slowed down, ramped up as they told us they would. Some of them that were running one or two rigs in December went up to 9 to 12 rigs in January. So I would say that issue isn't playing out at all in Q1. Basically our customers are ramped up pretty substantially.

Greg Colman - National Bank Financial

All right, excellent. Then just one last really (inaudible) here on the guar pricing, but on the substitute good questions earlier the about switching cost, the price at which you would switch over to substitutes. Is there any, would there be any limitations, would there be any percentage limitations for the guar across your usage in the U.S. that wouldn't be able to be switched over to the substitute. Is there any specific area where simply been the natural guars all that can be used or is it across the board able to swap?

Dale Dusterhoft

I would say all areas you are able to swap. In some cases it's a little bit more difficult but for the most part all areas you are able to swap.

Greg Colman - National Bank Financial

Great, thanks very much.

Dale Dusterhoft

Okay. Thank you.

Operator

Thank you. (Operator Instructions) And the next question is from Dana Benner from Altacorp Capital. Please go ahead.

Dana Benner - Altacorp Capital

Good morning guys.

Dale Dusterhoft

Hi Dana.

Mike Baldwin

Hi Dana.

Dana Benner - Altacorp Capital

I wanted to probe a little bit further on the U.S. market right now, and would be curious if you could tell me what scenario would we need to see your or scenarios for you to have a view to be able to de-idle the current things is what for frac spreads. Do you need much higher gas prices would it be an the individual client relationship. May be spec detail first.

Dale Dusterhoft

Yeah, ultimately it's going to require us to get a return on capital on that equipment that we're happy with. And that return on capital has to be up close to 20% quite honestly. So it's going to have, we are going to have to see that. I would say that we would do it for strategic clients, maybe at a little bit lower with the expectation that we are going to raise it as we grow the business relationship with them. So you may see some of that. If we thought that was in the best interest of Trican long-term/ From a margin standpoint you have to be above 15. Really I think we want to respond and see our margins above that and some are between 15 to 20 you might - thinking about it.

In one case I would say in the Bakken we are only running one crew currently there now. That's not optimal efficiency to have only run one crew out of our base. So we'll look at that area and if we see utilizationing and get reasonable pricing and good margins in particular. Then you may see us look at adding another crew in to there as the year goes on. But right now I would say that what caused the margins to get up to a level that we're happy with, it's just an increase in the U.S rig count probably more than anything, so that we get just a little bit of our capacity use in the to pass and we are still attending that we need to add kind of the 200 rigs that was lost over 2012 back into the market just tightening and up enough that the customers are willing to pay the price or give us the utilization that we require to get our margins up there.

Dana Benner - Altacorp Capital

If we think about margin progression this year, to what extent is your I guess may be very guarded optimism about margin progression. To what extent is that up reliant on your ability to push more cementing and coil equipment into the market and get back utilized as supposed to save a recovery however modest in the fracing business?

Dale Dusterhoft

Yeah, right now I'd say it's all based on the farac, cementing business for the most -- not anticipating a lot of changes in job mix that we wouldn't have already had in 2012. So it's going to be self help quite honestly. So us continuing to focus on cost cutting initiatives and improving utilization of our fracturing crews that'll drive that number. If we see anything else, that will be a benefit to us. So if we see cementing coil opportunities that give us higher margins than we can add additional equipment into those and grow those service [branches] that will help. Then we are not anticipating any pricing improvement at all and that's analysis where we improve our margins. So we have to see some pricing improvement that will also help.

Dana Benner - Altacorp Capital

Right, just one final question moving to Russia with respect to the guidance that you have given about 25% increase in year-over-year revenue at target intervals, and also the noted guidance that you think margins could may be migrate a little higher this year. Traditionally in this business with a move towards these types of wells that type of program we see are more robust expansion of margins. Are you simply being cautious and wanting to outperform or is that just the reality of the Russian marketplace at this point?

Dale Dusterhoft

Well I think it's reality at the Russian marketplace right now to some extent Dana. There is a couple of things in Russia, one is they don't have the same quality of rigs that we have. So they don't have that many rigs that can do long extended reach horizontals. So the horizontals that they are doing there are actually quite short in length, and so that allows you to do five or six fracs a well but you are not doing 10 to 20 fracs a well. So I think we need to see some improvements in rig quality before we start seeing that kind of robust significant jump up and they also probably need to see some additional jobs size changes. So right now they are really is taking what they are doing on the verticals and much like we did in the North America when we started this, just applying, doing six of those in a well, but that we haven't really seen, we see some increases that better qualify that. We've seen some increases in the job sizes, but not to the extent that we saw in North America where we went from doing 20 ton fractional verticals to 100 ton fracs 12 times on the horizontal.

So that will also have to change and I anticipate both of those will evolve, but it will be slower. All internationally areas (inaudible) are out slower than North America, that is don't have the ability to ramp up to the same rate that we have the ability to do that in North America from a technological standpoint, from a people standpoint some even the oil companies capacity to do it. It will go slower but it is we're liking the direction.

Dana Benner - Altacorp Capital

You know that's great, I'll turn to back, thank you.

Dale Dusterhoft

Okay, thanks Dana.

Operator

Thank you. The next question is from Jeff Fetterly from Peters & Co. Please go ahead.

Jeff Fetterly - Peters & Co.

Good morning guys, just a couple of questions on the U.S side. You talked in the quarter about half of the margin improvement being guar related half of it being other costs. To get to the profitability level in Q1 and to that 10% to 15% level you talked about and back half of the year. How much of that do you think is going to be cost based, guar based versus revenue based?

Dale Dusterhoft

It would be three aspects, so a little bit of improvement from utilization and the other two aspects are cost and revenue and I would say that the levels increased between the three of them. So all three of them will materialize and help.

Mike Baldwin

To just kind of clarify that. I think guar will see another improvement in Q1, but that's probably where it tops out. So I think Dale was right the builds are going to be the three factors for the improvement in our Q1 margins, but beyond that, then it's going to be just more on the cost cutting and the utilization and I think if you go 50-50 on and that's probably a good way to think about it.

Jeff Fetterly - Peters & Co.

Okay, just to clarify what you said earlier Mike, guar costs in Q4 was about 650 a pound?

Mike Baldwin

That's right.

Jeff Fetterly - Peters & Co.

And what's was that number for both Q3 and Q4 '11?

Mike Baldwin

They probably would have been in the 950 for Q3.

Dale Dusterhoft

Yeah, Q3 was nine.

Jeff Fetterly - Peters & Co.

Yeah.

Dale Dusterhoft

Q4 '11 was around three. That was kind about the low point for guar pricing.

Jeff Fetterly - Peters & Co.

And so what are you thinking from a guar pricing standpoint for 2013 is this higher cost of inventory is burned off?

Dale Dusterhoft

We're anticipating there will be $4.50 to $5 probably average realized price, guar price in Q1.

Jeff Fetterly - Peters & Co.

Okay. On the Canadian side Q2, I know the Horn River project could have some impact in Q2, but what is your visibility for the quarter both pricing and activity launch right now?

Dale Dusterhoft

Yeah, it's a good question, I would say right now we're seeing that activities probably not going to be any better than next, than it was last year with that qualifier that if Horn River kicks in June than it gets much better, but we're not - we're seeing kind of the same activity level as we saw in '12 and we're carrying a 13% year-over-year price decrease in there and we may, it's going to be a competitive quarter. And so we may, as we sometimes do offer additional discounts in Q2 to try and push work into there. So, right now I'd say that we're going to have to monitor our cost very, very closely in Q2 and probably reduce our - we will reduce our cost in Q2 in the [same] market because we're not anticipating it to be a better quarter year-over-year.

Jeff Fetterly - Peters & Co.

Your commentary around pricing being fairly stable through 2013, if you're going to see that type of pressure in Q2, what are your expectations for Q3 and Q4 both pricing as well as utilization?

Dale Dusterhoft

Yeah, right now I'd say we're taking the well state very similar to where we're at. You may - its competitive market though and so we'll see our competitors react and what utilization levels are at. So you may see some fluctuation at Alberta. Right now I'd say we're pretty comfortable saying that we're going to be able to kind of hold it in. The pricing declines that we gave in Q2 are often temporary ones. So, if we drop back pricing in Q2, that's just to push work in there. So, we'll give the client a better deal to do work in Q2 and if you look historically over the last three years, we've done that, we'll get a little dip in Q2 pricing as a result of that.

Mike Baldwin

And just to add to that, I think we're expecting pretty good levels of activity in the back half of the year and a large part of that's going to be predicated on increased activity in the Duvernay play. We see some increased spending from some of the larger players that have recently gotten into the market. So, there is a lot of good positive macro elements that are being talked about in the Canadian market and we're expecting to see some of that play out in the second half. So, if that happens and we're pretty comfortable with the guidance that we're giving, if it doesn't than I think you've got probably a little bit more of an oversupplied situation where you probably get a little more competitive on the pricing side. I think that at this point in time, we haven't gotten really firm work programs from our customers for the second half of the year.

I think that will play out over the next two to three months and while a better feel for at that point in time, but early indications would say that that's going to happen that we should see activity increases from the Duvernay and plays like that.

Jeff Fetterly - Peters & Co.

Thank you very much. I appreciate the color.

Dale Dusterhoft

Thanks, Jeff.

Operator

Thank you. There are no further questions registered at this time, I'd like to turn the meeting back over to Mr. Dusterhoft.

Dale Dusterhoft

Yes, oh, hang on, there is another question popped on our screen operator, so….

Operator

Yes, thank you. The next question is from Kevin Lo from FirstEnergy. Please go ahead.

Kevin Lo - FirstEnergy

Good afternoon, guys. I'm wondering if you guys can talk about as the amount of pumps and capacity having Canada titled?

Dale Dusterhoft

We don't, we have a little bit of frac capacity on the pumper side idle, but for the most part, most of is just distributed amongst our existing crews. So next to nothing.

Kevin Lo - FirstEnergy

And I guess follow-on to that than is, is there a possibility that you would move some of the U.S. idled fleet back up to Canada?

Dale Dusterhoft

If we saw market opportunities we could do that, there is equipment we build from the last three years or so, we build it to what we call Canadian standard. So, it's pretty heavy robust equipment that allows us to move that for its across the border and we could do it quite easily and quite honestly. So, if we saw the Canadian market, it improve or had opportunities to tie-up some equipment here, we would be going along to do that.

Kevin Lo - FirstEnergy

Great. The last question, I'm just we're looking at the international side and looks I mean look somewhat positive in the commentary obviously is better, can you kind of quantify your what margin improvement could have happened if you would as disappointed with some of your other business like the Algerias and the Australia side?

Dale Dusterhoft

Yeah, I don't know if I could do that to just put the math in my head right now Kevin. So, I would say that yeah, it's tied to it right now. Yeah, but I think just given a little bit of a thought that I don't think it's that massive I think you might be able to increase it by saying in the three to four hundred point range.

Kevin Lo - FirstEnergy

Okay, great. Thanks guys.

Dale Dusterhoft

Okay.

Operator

Thank you. Mr. Dusterhoft, there are no further questions at this time.

Dale Dusterhoft

Okay, well thank you for your interest in Trican today. We appreciate, you're spending the time with us and we look forward to talking to you again in our first quarter. Thank you.

Operator

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

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