operational excellence technical solutionstechnical solutions annual report 2011 corporate profile...

OperatiOnal excellence

technical SOlutiOnSannual report 2011

Corporate profile

trican Well Service ltd. is a major provider of pressure pumping services in the global marketplace. a technical and operational leader, trican’s experience in pressure pumping is among the most extensive in the industry. trican’s services are offered throughout key oil and gas plays in canada, the united States and russia, and has growing operations in many other active regions around the world.

trican became a public company in 1996, and since then has invested more than $2.1 billion in capital expenditures and acquisitions, expanding its equipment, infrastructure and capabilities. as a result of its strategic expansion program, trican has evolved from a regional supplier of cementing services, to one of the world’s largest pressure pumping companies.

trican employs a disciplined and scientific focus to research and development that delivers innovative products and processes, while addressing a shared commitment to safety, quality and reducing our impact on the environment. Services provided include fracturing, cementing, coiled tubing, acidizing, geological and reservoir services, industrial cleaning and pipeline services. trican’s shares trade on the toronto Stock exchange under the symbol “tcW”.

NotiCe of aNNual MeetiNg

trican is pleased to invite its shareholders and other interested parties to the company’s annual Meeting at 2 p.m. on May 9, 2012, in the Metropolitan centre, 333 - 4th avenue SW, calgary, alberta, canada.

aNNual fiNaNCial StateMeNtS aNd Md&a

For further information on trican’s 2011 financial results, please refer to trican’s financial statements and Management’s Discussion and analysis (MD&a) for the years ended December 31, 2011 and 2010, available on SeDar at www.sedar.com or our website at www.trican.ca.

CoNteNt

Financial Summary 1

Message from our ceO 3

Operational excellence technical Solutions 4

Operations by Geographic region 6

technology 16

Sustainability 19

Outlook 20

corporate information Bc

2011 Annual Report 03

2011 2010 change %changerevenue 2,309,647 1,478,345 831,302 56%net income/(loss) 338,636 150,362 188,274 125%adjusted net income/(loss) 351,014 162,724 188,290 116%adjusted earnings per share: (Basic) 2.41 1.18 1.14 97% (Diluted) 2.39 1.17 1.13 97%Funds provided by operations 558,811 320,028 238,783 75%capital expenditures 578,457 261,266 317,191 121%long-term debt (excluding current portion) 400,256 107,152 293,104 274%Shareholders’ equity 1,365,389 999,401 365,988 37%average shares outstanding - Basic 145,805 137,400 8,405 6%average shares outstanding - Diluted 147,085 138,571 8,514 6%Shares outstanding at year end 146,917 144,637 3,280 2%

Canadian operations number of jobs completed 25,393 21,931 3,462 16% revenue-per-job 49,964 38,733 11,231 29%United States operations number of jobs completed 5,065 3,130 1,935 62% revenue-per-job 146,457 115,740 30,987 27%Russian operations number of jobs completed 4,901 4,510 391 9% revenue-per-job 55,902 56,206 (304) -1%

Financial Summary ($ thousands, except per share amounts and operational information)

Operational information (unaudited)

$ $ $$ $ $

50

100

150

200

250

300

350

06 07 08 10 1109

Net Income ($ millions)

5

10

15

20

25

30

06 07 08 10 1109

Return on Assets (%)

5

10

15

20

25

30

35

40

06 07 08 10 1109

Return on Equity (%)

06 07 08 10 11

0.5

1.0

1.5

2.0

2.5

06 07 08 10 1109

Adjusted EPS ($)

100

200

300

400

500

600

06 07 08 10 1109

Funds from Operations ($ millions)

500

1000

1500

2000

2500

06 07 08 10 1109

Revenue ($ millions)

04 Trican Well Service Ltd.


Message FroM our Ceo

On behalf of the employees and Board of Directors of trican Well Service ltd.,

i am pleased to report on our company’s 2011 financial and operational results.

a strong 2011 operating environment allowed us to capitalize on our reputation

for operational excellence and our ability to provide customized technical

solutions to our customers. pressure pumping demand and activity levels were

strong across north america, and our leading position in canada, as well as our

growing presence in the u.S., led to record financial results in 2011. We sustained

our position as a leading pressure pumping company in russia and Kazakhstan,

maintained our presence in algeria, and made progress in establishing our

technical qualifications in Saudi arabia. We also expanded our international

presence in 2011 by entering the australian market by way of an acquisition.

thanks to the dedication of our people and the support of our customers,

suppliers, partners, and investors, 2011 was a tremendous year for trican,

and i look forward to continued success in 2012.

Dale M. Dusterhoft – chief executive Officer


2011 was a year of significant growth and success for trican. Our north american operations continued to benefit from the development of oil and liquids-rich gas plays, which was supported by strong oil prices throughout the year. trican’s services and technology have helped rejuvenate new and existing oil plays, changing the nature of the oil and gas industry in north america. a few years ago, our industry was highly dependent on the development of natural gas wells because the technology was not available to economically develop many of the oil plays in north america. this technology is now used to unlock tight rocks of all types that contain gas, oil or gas liquids. in 2011, approximately 55 percent of wells drilled in north america were oil directed, compared to 42 percent in 2010 and 29 percent in 2009. this shift has mitigated some of the cyclicality of our industry, which is evident by our financial success in 2011, a period of weak natural gas prices.

trican continued to benefit from the growth of horizontal drilling in 2011. horizontal drilling and completions have become the dominant method for developing unconventional oil and gas reservoirs, as approximately 58 percent of wells drilled in north america during 2011 were horizontal. in addition, the number and size of the fracture treatments performed on horizontal wells continued to grow in 2011, which directly benefitted trican.

One of the keys to our success in 2011 was our continued commitment to operational excellence. Success in our industry is dependent on the dedication and service provided by our people, our technology, and the quality of our equipment. Our strategy has always been to offer the best equipment in the industry and we believe trican accomplished this in 2011. We continued to introduce new, innovative custom designed equipment to our industry that improved our reliability and job performance. Our operational excellence was also due to our success in

attracting and retaining the best people. in order to meet the demands of our growing operations, our workforce increased by 30 percent during 2011. trican is dedicated to providing employees with challenging career opportunities in a safe, honest, innovative and collaborative working environment, and has been named one of alberta’s top employers for five years running.

another key to our success in 2011 was our ability to offer customized technical solutions to our customers. Our strategy has always been to differentiate ourselves through technology, by listening to the needs of our customers and understanding the markets in which we operate. trican is committed to being a technical leader within our industry and was named one of canada’s top 100 corporate r&D Spenders* in 2011, a list we have made in four of the past five years. We also opened a new r&D facility in houston and expect to open a new r&D facility in Moscow during 2012, in order to provide customized technical solutions to our customers in the u.S. and russia.

We executed an aggressive capital budget during 2011, which substantially increased the size of our asset base and contributed to our financial success. these capital initiatives position us well for further growth in 2012, as we respond to the strong demand for pressure pumping services in north america.

Despite the volatility in the financial markets over the second half of the year, trican maintained a high level of success, resulting in record financial performance for 2011. Our exceptional performance was a direct result of the dedication and hard work of our employees, and our on-going commitment to providing our customers with operational excellence and innovative technical solutions.

OperatiOnal excellence, technical SOlutiOnS

* compiled by research infosource

Dale M. Dusterhoft - chief executive OfficerMarch 15, 2012


OperatiOnS BY GeOGraphic reGiOn

trican’s canadian operations provide pressure pumping services to exploration and production companies, as well as industrial cleaning and pipeline services to midstream companies. trican operates in all the key canadian oil and gas plays from 17 bases in Western canada, and offers fracturing, cementing, deep coiled tubing, coalbed methane (cBM), nitrogen, acidizing, geological/engineering and reservoir services, as well as industrial cleaning and pipeline services.

trican’s operational excellence and ability to provide technical solutions to our customers allowed us to capitalize on a strong canadian operating environment in 2011. Our canadian operations achieved record annual revenue of $1.3 billion and record operating income of $0.5 billion. Strong demand in the canadian market was led by activity in the oil and liquids-rich gas plays, as oil prices remained strong throughout 2011. although the year-over-year canadian rig count was up by 21 percent, the oil well count increased by 41 percent, while gas well count decreased by 5 percent. in addition, oil represented 67 percent of annual active drilling rigs in 2011, compared to 57 percent in 2010 and 47 percent in 2009. in anticipation of strong oil prices combined with weak gas prices, we expect this trend to continue in 2012. the shift to oil-directed activity has benefitted the pressure pumping industry, as the utilization and margins are typically higher

for fracturing work performed on oil wells due to the specialty fluid systems required and increased jobs per day. Furthermore, given the specialized demands of fracturing work performed on oil wells, we believe trican’s technology-driven focus provides an advantage for our customers and separates us from our peers.

canadian liquids-rich gas activity was also strong throughout 2011 due to the favourable economics of these plays. liquids-rich gas contains ethane, propane, butane, and condensate that are produced with the dry gas. Market prices for these liquids are closely correlated to the price of oil and, as a result, the liquids content provides substantial additional cash flow for the producers in an environment with strong oil prices.

trican’s canadian operations continued to benefit from the strength of horizontal drilling activity in 2011. the number of horizontal wells drilled as a percentage of total wells drilled increased to 55 percent in 2011, compared to 42 percent in 2010. the increase in horizontal drilling favourably impacts our fracturing service line, as horizontal wells typically require 10-30 fracture treatments per well, compared to 2-4 for conventional wells. the size of the fracturing treatments for horizontal wells is also considerably larger compared to conventional wells, which increases the fracturing revenue per job. Our cementing

trican Well Service ltd. is headquartered in calgary, alberta, canada, and operates in canada, the united States, russia, Kazakhstan, algeria, and australia. the canadian operations provide services to customers across the entire Western canadian Sedimentary Basin (WcSB). trican’s u.S. operations are run from bases in texas, arkansas, Oklahoma, and pennsylvania.

in russia and Kazakhstan, trican conducts operations through bases in Western and eastern Siberia, and in Kyzylorda and aktau, Kazakhstan. trican also has bases in hassi Messaoud, algeria and roma, australia.

canada

Drumheller

Brooks

Medicine Hat

CALGARY

Provost

LloydminsterNisku

Red Deer

SASKATCHEWAN MANITOBA

BRITISHCOLUMBIA

ALBERTA

HintonDrayton Valley

Fort St. John

TIGHT GAS

MONTNEY SHALE

HORN RIVER SHALE

VIKING TIGHT OIL

BAKKEN SHALE

Whitecourt

Grande Prairie

Red Earth

Fort Nelson

High Level

Estevan

Brandon

CARDIUM TIGHT OIL

LOWER SHAUNAVONTIGHT OIL

DUVERNAY SHALE

service line also benefits from the increase in horizontal drilling, as horizontal wells require larger, more technical cementing treatments than vertical wells.

pressure pumping demand was strong across the WcSB during 2011, particularly in the areas with strong oil and/or liquids-rich gas, including the Montney, Bakken, cardium and Deep Basin regions. We believe that many of the canadian plays are still in the early stages of development, which is supportive of our view that the canadian pressure pumping market will continue to grow in the future. Growth in the canadian market will also be driven by new plays such as the Duvernay, alberta Bakken, nordegg and Muskwa. in addition, we continue to see an increase in fracturing treatments - or stages per horizontal well - in canada. the average number of stages per well in 2011 increased by over 50 percent, compared to 2010. We expect this trend to continue in 2012, although the rate of growth will slow down as the plays become more mature.

Strong market conditions throughout 2011 led to record financial results for our canadian operations. Year-over-year operating income increased by 65 percent to $465 million and operating margins increased to 36.2 percent, compared to 32.8 percent in 2010. a key factor in the margin improvement was a 14 percent increase in 2011 pricing compared to 2010. Financial results for the first, third and

fourth quarters saw strong utilization levels, driven by oil and liquids-rich gas-directed activity and the continued strength of horizontal drilling. Financial results for the second quarter, which are negatively impacted by spring break-up conditions, were considerably stronger than historical second quarter results due to the emergence of pad well project work. the practice of placing several wells on one pad is advantageous for trican, as we can perform pressure pumping services on several wells without moving our equipment. this is particularly beneficial in the second quarter when road bans limit our ability to move equipment.

Our canadian operations executed on a large scale 2011 capital budget, and the size of our equipment fleet grew accordingly. the canadian fracturing fleet increased by 62,500 horsepower, during 2011, and the size of our cementing, acidizing and nitrogen fleets also expanded during the year. the new equipment was deployed throughout the second half of 2011 and contributed to the substantial increase in year-over-year revenue. Our 2012 proposed canadian capital budget of $183 million includes the addition of 92,500 fracturing horsepower, 5 cementing units, 5 nitrogen pumpers, and 2 acid units. these aggressive capital initiatives reflect our expectation of growth in canadian pressure pumping demand, due to



the continued strength of the oil and liquids-rich gas plays, an increase in fracturing treatments per well, and new play growth in areas such as the Duvernay, Muskwa, and nordegg.

One of the key success factors in the pressure pumping industry is capable supply chain management. During periods of strong demand, the availability of key inputs such as sand, guar, chemicals and acid is limited. any disruptions in the supply chain will result in lost revenue and have a significant impact on financial and operating performance. in anticipation of strong 2011 demand, trican’s focus on supply chain management allowed us to secure adequate levels of key inputs throughout the year. as a result, we experienced no major disruptions in the supply chain, which contributed to our record financial results in 2011.

in order to achieve operational excellence and provide the best technical solutions to our customers, trican must rely on the experience, work ethic, and dedication of our people. availability of people within the oil and gas sector remained a challenge in the canadian market, as the industry continued to thrive throughout the year. During 2011, trican placed significant importance on retaining our employees and attracting and training new people to the

industry. Our recruiting efforts resulted in a year-over-year staffing increase of 33 percent for our canadian operations, as our total canadian workforce reached approximately 2,100 at the end of 2011. Given the strong demand expected for 2012, we expect our canadian workforce growth to continue and we will maintain a strong focus on both retention and the addition of people by offering them rewarding career opportunities.

Geological Services

trican Geological Solutions ltd. consists of world-renowned shale gas experts who are able to analyze rock from wells and provide expert evaluation of a reservoir’s potential to our fracture design engineers. this integrated approach gives trican a significant advantage over most of our competitors. the data generated by this division is also used to provide customers with valuable reservoir information.

During 2011, trican Geological Solutions ltd. completed several research studies on key unconventional plays in the WcSB, including the Duvernay, nordegg, and Montney. this division continues to have ongoing research projects that will provide valuable information to customers and improve fracture designs in shale gas reservoirs.

2007 2008 2009 2010 2011B 2012C

Fracturing crewsa 18 18 18 18 18 22

hp 135,500 158,000 159,950 258,700 321,250 413,700

cement pumpers 54 49 52 48 53 58

Deep coiled tubing units 18 16 16 19 20 20

nitrogen pumpers 28 25 26 27 33 38

acidizing units 12 13 13 15 17 19

number of units at year end (canada)

a a fracturing crew is made up of several pieces of specialized equipment | B Operational or in the final stages of construction | c expected equipment capacity at year end, based on approved budgets, which are subject to change


trican’s u.S. operations provide fracturing, cementing, acidizing, nitrogen and coiled tubing services from our eight operating bases in texas (longview, Springtown, Mathis and Odessa), arkansas (Searcy), Oklahoma (Woodward and Shawnee) and pennsylvania (Mill hall). trican currently operates within several of the major u.S. oil and gas plays, such as the Barnett Shale, the Woodford Shale, the Fayetteville Shale, the haynesville Shale, the Marcellus Shale, the eagle Ford Shale, and the permian basin. Our initial 2012 capital budget includes expansion into new regions, as we continue to expand our u.S. geographic footprint.

Our u.S. operations had a very successful year and achieved record financial results. Our u.S. revenue of $739 million in 2011 was 105 percent higher than in 2010, and our operating income of $191 million was a 173 percent increase compared to 2010. Operating income as a percentage of revenue was 25.8 percent compared to 19.4 percent in 2010, and benefitted from year-over-year pricing increases of 34 percent. Strong financial results were also attributable to increased utilization of our equipment, effective contractual positions for several fracturing crews, and execution of our geographic and service line expansion initiatives. however, our aggressive expansion initiatives also resulted in start-up costs in the second half of 2011 that negatively impacted operating margins in the third and fourth quarters.

2011 was a year of significant growth for our u.S. operations. Our u.S. fracturing service line grew by 41 percent as total

fracturing horsepower increased from 364,500 in 2010 to 515,000 at the end of 2011. these growth initiatives included commencement of fracturing operations in the eagle Ford and permian regions and the addition of a second fracturing crew in the Marcellus region. the expansion was focused on oil and liquids-rich gas areas, as growth in the u.S. market was driven by these plays. the u.S. oil and gas industry saw a substantial shift towards more oil and less gas-directed activity in 2011, with oil wells representing 53 percent of the average active u.S. drilling rigs compared to 39 percent in 2010.

Demand for u.S. pressure pumping services grew in 2011, as the overall u.S. rig count increased by 22 percent. however, most of the growth was generated from areas containing oil and liquids-rich gas, such as the eagle Ford, permian and Oklahoma regions. conversely, dry gas areas, such as the haynesville, Fayetteville and Barnett shales all experienced a decrease in year-over-year rig count. Year-over-year rig count in the oil and liquids-rich gas areas where trican operates increased by 53 percent, compared to a 21 percent decline in the dry gas areas where we operate. Despite these decreases, our utilization in dry gas areas remained strong throughout most of the year, due to the strength of our contracted positions. activity levels did decline in these areas in the fourth quarter of 2011, and as a result, two of our dry gas crews were moved into oil/liquids-rich gas areas in December; one of our haynesville crews was re-deployed into the eagle Ford, and our Fayetteville crew became a travelling crew, working in several different oil/liquids-rich gas areas.

united States

although the Marcellus is a dry gas region, utilization and margins for our pennsylvania base were very strong throughout 2011. Financial results for this base benefitted from the long-term contracted positions of both fracturing crews. in addition, the Marcellus is a large, low cost reservoir situated close to the eastern u.S. natural gas consuming market, which helped keep activity levels stable despite the weak gas prices.

horizontal drilling continued to grow in the u.S. during 2011. horizontal wells represented 57 percent of active u.S. drilling rigs in 2011, compared to 53 percent in 2010 and 45 percent in 2009. the growth of horizontal drilling benefited all of our u.S. service lines in 2011 and we expect this growth trend to continue in 2012. the number of fracturing treatments performed per horizontal well in the u.S. also continued to increase in 2011. although some of

BARNETT SHALE

PERMIAN BASIN

EAGLE FORD SHALE

WOODFORD SHALEFAYETTEVILLE SHALE

MARCELLUS SHALE

HAYNSEVILLE SHALE

TEXAS

OKLAHOMA

ARKANSAS

LOUISIANA

PENNSYLVANIA

Searcy

Woodward

Shawnee

Denton Springtown

Odessa Longview

Houston

Mathis

Mill Hall

2007 2008 2009 2010 2011B 2012C

Fracturing crewsa 10 8 8 10 13 19

hp 173,250 211,500 211,500 364,500 514,500 712,000

cement pumpers - 2 2 5 15 27

nitrogen pumpers - 4 4 7 10 19

acidizing units - 1 2 4 8 18

coiled tubing units - - - - 6 13

number of units at year end (u.S.)




the mature plays, such as the Barnett shale, have seen a plateau in stages per well, other plays such as the permian and eagle Ford are continuing to see stage growth.

We continued to expand our u.S. service lines during 2011 as part of our strategic initiative to become a full service pressure pumping company in this market. We initiated coiled tubing services from our Woodward, Oklahoma base during the second quarter, and from our Mathis, texas base during the third quarter. We also expanded our u.S. cementing service line to our Mathis, texas base during the third quarter and increased the size of our nitrogen and acidizing fleets throughout the year. as a result of these expansion initiatives, the number of non-fracturing jobs performed in 2011 compared to 2010 increased by 123 percent. We will continue to expand our non-fracturing service lines in 2012, as our planned u.S. capital budget includes the addition of 12 cement, 7 coiled tubing, 9 nitrogen, and 10 acidizing units.

During the second quarter of 2011, our u.S. regional office was officially moved from Denton, texas to houston, texas. this move has brought us closer to many of our key u.S. customers and has allowed us to better serve and expand our growing u.S. customer base. in addition, we opened a new research and development center in houston in late 2012, which will allow us to provide customized technical solutions for our u.S. customers.

the u.S. pressure pumping market remains an important growth area for trican, and we will continue to execute on our geographic and service line expansion initiatives in an effort to grow our u.S market share. We have grown to become a leading pressure pumping company in canada and russia by establishing a reputation for operational excellence and technical solutions. We have taken important steps during 2011 in establishing this reputation in the u.S. and will continue to expand these efforts as we move into 2012.


internatiOnal

trican Well Service llc began operating in russia in 2000 and has grown into one of the country’s leading fracturing companies. trican’s services in russia also include cementing, coiled tubing, acidizing and nitrogen. russian operations are based predominantly in the tyumen region of western Siberia, but also extend into the arctic north of the eastern Siberian region of Vankor. trican russia services these regions from its bases in nefteyugansk, raduzhny, nyagan, Gubkinsky, novy urengoy, and the Vankor Oilfield, russia. trican russia’s regional Office is located in nizhnevartovsk, russia.

the majority of trican russia’s customers develop and produce oil reserves. Oil prices were strong throughout most of 2011 and this supported an overall increase in russian pressure pumping activity. however, the russian market remained competitive, with several firms attempting to gain market share, limiting our ability to increase russian operating margins through pricing increases. cost inflation in russia was also a factor, as the annual 2011 inflation rate was approximately 9 percent.

russian oil and gas activity has been challenged by the current russian tax structure over the past several years. industry experts have noted that the oil and gas industry pays higher taxes relative to other industries in russia, which reduces the cash flows available to russian oil and gas companies to reinvest into the market. Small improvements to the tax structure were made during 2011, but trican believes that further improvements will need to be made to encourage russian oil and gas companies to invest in additional production, maintenance and expansion activities.

the 2011 financial results for our russian operations were as expected, based on the contracts awarded during the tendering process. activity levels increased by approximately 7 percent and operating margins were relatively flat, as pricing increases were fully offset by higher costs. cost inflation was a factor during the first half of the year, but stabilized during the second half. Despite the slowdown in overall inflation, trican russia experienced cost increases for items such as hauling, fuel and product during the second half of the year. cost control was a focus for our

Moscow

Aktau Kyzylorda

Nizhnevartovsk

Krasnoyarsk

Raduzhny

Gubkinsky

Novy Urengoy

Nyagan

Nefteyugansk

RUSSIA

KAZAKHSTAN

russia and Kazakhstan


2007 2008 2009 2010 2011B 2012C

Fracturing crewsa

conventional 11 11 11 15 15 15

hp 79,150 79,150 88,150 101,650 109,300 113,800

cement pumpers 6 6 6 6 6 8



number of units at year end (russia and Kazakhstan)


russian operations throughout 2011 and remains a focus in 2012, as we look to optimize our russian cost structure.

the 2011 capital program for russia was $24 million and was largely directed at maintaining the current russian fleet. Our capital program also included the addition of a new r&D facility in association with Moscow’s Gubkin university, which we expect to open in 2012. Gubkin boasts a world renowned petroleum School. We look forward to a long partnership with Gubkin in developing products for the russian market. the russian pressure pumping market requires advanced technical capabilities due to the geological complexities and fluids required to maximize the production of the formations. We believe that investing in an r&D facility in russia will allow us to provide customized technical solutions for our russian customers and give us an advantage in a very competitive market. trican was also recognized as a technical leader in russia during 2011, by winning 2 technology and innovation awards for the application of our isoJet technology.

We continue to believe in the long-term potential of the russian pressure pumping market. the russian government has set targets to maintain or increase oil and gas production over the next 20 years to meet domestic and export demand. in addition, horizontal drilling and completions have been used on a very limited basis by the russian oil and gas

industry thus far. During 2011, there were several successful horizontal drilling pilot projects that included multi-stage fracturing. We expect horizontal drilling and completions to gain momentum in 2012 and become a significant component of future russian industry activity. this development would substantially increase the fracturing horsepower demands in russia.

trican Well Service llc began operating in Kazakhstan in 2005. trican provides fracturing services to the Kazakhstan market, with two fracturing crews operating out of bases in Kyzylorda and aktau. the Kazakhstan regional office is located in Kyzylorda, Kazakhstan. the majority of the activity within the region is directed at oil wells, as Kazakhstan has approximately 8 billion tonnes of proven recoverable oil reserves.

the oil and gas industry in Kazakhstan is still in the early stages of development and the pressure pumping market is small with relatively basic technological needs. however, we believe the Kazakhstan market will continue to grow and technical solutions will become increasingly important within the region. Our global reputation as a leading pressure pumping company and our existing presence within the region should allow us to capitalize on this growth.

trican began operations in algeria in 2007, establishing a base in hassi Messaoud. trican offers coiled tubing, cementing, and nitrogen services to algeria’s largest state-owned oil company, Sonatrach, as well as other international operating companies that are in partnership with Sonatrach. in 2010, Sonatrach underwent an internal reorganization, which delayed production activities and led to low utilization of our equipment. these delays carried into the first half of 2011 and it wasn’t until the latter part of 2011 that we began to see increased activity levels. this resulted in financial results that were below our expectations for this region. however, supply commitments by algeria to europe indicate that algeria must increase its local gas and oil production over the next 2-3 years. Due to the long-term potential of this region, our strategy in 2012 will be to maintain our presence in algeria and increase utilization on existing equipment to acceptable levels.

in 2010, trican entered into a joint venture agreement with a partner in Saudi arabia. During 2011, we made substantial progress in establishing our technical qualifications with customers in Saudi arabia and developing a sales presence within the region. We expect to submit bids for work tenders in 2012 with our cementing service line. in addition, we plan on initiating industrial services in Saudi arabia in 2012.

We expect the demand for pressure pumping services in Saudi arabia to grow over the next several years.

With Opec quotas restricting the production of oil, we believe the Saudi government will look to meet domestic energy needs by increasing gas production so that the majority of the country’s oil production can be exported. if horizontal drilling and completions technology is required to unlock the potential of the country’s gas reserves, the demand for pressure pumping services should increase in the future.

australia

in July of 2011, trican entered the australian market through the acquisition of a privately owned company that provides cementing and environmental services in eastern australia. trican’s australian operating base is in roma, Queensland.

Our australian operations are small, but our acquisition provided us with a strategic entry point into the growing australian pressure pumping market. australia has supply commitments for significant liquefied natural gas exports and plans to meet these commitments through increased gas production. a significant portion of this production will be from coal seam and shale gas plays that will require pressure pumping services. We believe that our reputation for operational excellence and technical solutions should provide us with an opportunity to grow in this market in the future.

africa and the Middle east

2007 2008 2009 2010 2011A 2012B



acidizing units 1 1 2 2 2 2

cementing units - - - 3 3 3

number of units at year end (algeria)

a Operational or in the final stages of construction | B expected equipment capacity at year end, based on approved budgets, which are subject to change



trican’s operational excellence is a product of our commitment to research and Development. innovation and technology are key drivers for trican, and a recognized competitive advantage. trican’s r&D initiatives developed more than 20 new products in 2011, helping our customers produce their wells safely, effectively and efficiently, and helping us all reduce the impact of our operations on the environment.

to improve our technical capabilities and knowledge, trican has expanded its r&D activities with a new facility in houston and with additional tool development in calgary. in addition, we expect to open a new r&D facility in Moscow during 2012. With this added capacity, trican will:

n Develop new options that continue to address environmental concerns;

n Maintain our technical leadership in each of our service lines;

n Keep product development as a quick, customer-focused process;

n learn from worldwide operations and personnel.

in addition to innovative equipment, tools and products, trican also launched the Drilling Services line in early 2012. Drilling Services provides a comprehensive package that delivers post stimulation drilling following various completion methods, and restores the wellbore back to its full drift diameter. Other services are offered, such as drift runs and additional drill-outs, including cement, float equipment, stage tools and debris subs. By adding Drilling Services to our offering, trican is able to reduce costs and increase job efficiency for horizontal drilling applications, and offer customers a streamlined, single call approach.

technOlOGY

Trican is the only pumping services company to make RE$EARCH Infosource’s

list of Canada’s Top 100 Corporate R&D Spenders in 2007, 2008, 2009 and 2011.

Deep coiled tubing unit


Mast coiled tubing unit

trican’s mast units are built specifically to safely perform work on slant wells, but are also used for conventional coiled tubing jobs. these units are used primarily for 60.3 mm (2 3/8 in) and 73 mm (2 7/8 in) coiled tubing applications. the 24-wheel trailer, coupled with the crane truck used to transport coiled tubing tools and lubricator, corresponds to a package that presents a relatively small footprint on a lease.

Deep coiled tubing unit

trican began operating in the texas eagle Ford Shale with a state-of-the-art deep coiled tubing unit. the first of its kind, this high capacity unit is capable of carrying more than 7,000 meters (23,000 feet) of 60.3 mm (2 3/8 inches) coil.

Generation ii Dry Blend unit

trican’s new version Dry Blend unit mixes powder and liquid together on location to create less expensive, more environmentally friendly fracturing fluids.

HorizoNtal Well fraCturiNg

MVp Frac™

trican’s MVp Frac (Maximum Volume placement) is an enhanced proppant conductivity treatment that involves adding a low volume of nitrogen to trican’s Flowrider™ additive. the MVp Frac process was designed to dramatically reduce proppant settling that occurs during slick water fractures. the process fluidizes and suspends the sand, carrying it deeper and distributing it more effectively into the reservoir. the net result: a more effective proppant distribution across the fracture network, which enhances well production.

SrVmax® (integrated production Optimization process)

SrVmax is our integrated process for helping customers recover as much as possible from their oil and gas reserves. it integrates a series of services and technology to provide a complete understanding of all available reservoir data, allowing operators to utilize the most advantageous wellbore spacing, fracture spacing and fracture design, leading to maximum production from their wells.

trican’s SrVmax process includes:

n trican’s Geological Services;

n reservoir characterization;

n reservoir Services (Microseismic fracture mapping, fracture modelling and reservoir simulation);

n Job execution;

n post job analysis.

navigator™

the navigator tool is used to perform work over services in multi-leg wells using coiled tubing. this tool allows customers selective access to multiple legs in a horizontal wellbore, reducing overall job time and increasing the well’s potential to produce, due to improved work over opportunities. recent developments with navigator include increased coil size and capabilities.

isoJet Frac™

isoJet is an effective method of selectively stimulating multiple zones using jet perforation through coiled tubing. trican recently won two product innovation awards for isoJet in russia. these awards recognized the isoJet method and its application of sand jet perforating technology in combination with the multi-stage fracturing of a horizontal well.

iNNovative equipMeNt


Greener products

trican continues to invest in minimizing the impact of our operations on the environment. We’re working to make greener choices available to our customers in every service line we offer. Some of the developments in this area include trican’s expanding line of ecoclean fracturing fluids.

ecoclean® Fracture Fluids

trican continues to expand the line of ecoclean products, adding ecoclean-xB™, a crosslinked gelled water frac fluid used in higher permeability reservoirs where greater viscosity is required. like others in the ecoclean line, this product includes additives that are non-toxic, bio-degradable and non-bioaccumulating, individually or in combination, and each will pass the stringent Microtox® test. the ecoclean line also includes ecoclean-lW™, a linear (gelled) water system, and ecoclean-GSW™, designed for high performance slick water fracturing.

research

trican is heavily committed to investing in pure research in areas such as water reduction and reclamation, as well as safer and more efficient operations. trican is the only pumping services company to make re$earch infosource’s list of canada’s top 100 corporate r&D Spenders in 2007, 2008, 2009 and 2011. the list is compiled from a variety of data sources, including company statements, security filings and surveys.

trican is continuing to examine ways to reduce the large scale use of fresh water as the base fluid for fracturing by enabling the use of produced/flowback waters or salt water from source wells. previous techniques involved chemically or otherwise treating these waters to make them serviceable, however, trican has developed friction reducers that work with these high salt waters without having to treat them. trican’s salt-tolerant friction reducers pass the Microtox® test at a very high threshold value. these friction reducers are also cost effective, as they are shown to perform well at nearly half the concentration when compared to conventional friction reducers, and lower horsepower is required to place the treatment.

Our new r&D facilities in Moscow and houston will enable us to learn from different regions and develop capabilities to address local issues. in calgary, trican has also expanded our tool development facility space by more than 50 percent, including a coiled tubing assembly line for our Burst port System, and a new Bend Fatigue machine for coiled tubing. this machine is expected to extend the life of coiled tubing. trican is also developing larger diameter tools for use with larger diameter coil in horizontal wells.

trican’s comprehensive research and development program is the key to providing customized technical solutions for our customers. We take pride in differentiating ourselves through technology by investing in r&D initiatives, and by encouraging innovation in our people. through these efforts, we strive to improve or enhance our existing products and services and bring new products and services to the market.

trican has developed 79 stimulation, 26 cementing and 44 coiled tubing products, tools and processes in the past 4 years.


SuStainaBilitY

Best practices in sustainability and protecting our environment are important to trican. We comply with local environmental regulations in our operations and emergency preparedness in response to spills, equipment failure, accidents, or other incidents that could result in environmental damage. We also participate in the voluntary and regulatory disclosure programs that have been established in many jurisdictions. trican recognizes that a responsible environmental program goes beyond what is regulated and adopts what is best for our environment and long-term sustainability.

trican’s policies and procedures on sustainability are communicated to our employees on a regular basis. in addition to classroom time, employees take part in emergency drills that involve spill prevention, incident mitigation and additional safe practices.

regular practices contributing to the safeguarding of the environment include:

n trican’s expanding line of ecoclean® products, designed to reduce the impact of our operations on the environment;

n recovering and re-using water and chemicals used in industrial cleaning;

n re-engineering processes and practices to reduce energy and resource consumption;

n recycling shop materials and lubricants;

n re-furbishing vehicle tires;

n prevention and containment practices to keep job sites clean;

n purchasing energy efficient and emission reducing vehicles and equipment.

During 2011, trican also participated in the carbon Disclosure project (cDp). the cDp is an organization that works with corporations around the world to disclose carbon emissions information to the public. trican will use the cDp data to set emission reduction targets for the company.


canadian demand for pressure pumping services was strong in 2011 and we expect this trend to continue in 2012. recent industry forecasts predict a 10 percent increase in drilling activity in 2012, compared to 2011. Oil and liquids-rich gas directed activity is expected to lead the increase, with strong oil prices anticipated throughout 2012. high demand in the oil and liquids-rich gas plays is expected to be partially offset by a decline in dry gas activity, as natural gas prices are expected to remain weak throughout 2012. however, activity in the canadian oil and gas industry is currently dominated by oil and liquids-rich gas activity. this trend is expected to continue with recent industry forecasts suggesting that oil and liquids-rich gas activity could represent above 80 percent of canadian drilling activity in 2012.

We expect strong canadian demand to be supported by the continued strength of horizontal drilling. the number of canadian horizontal wells drilled during 2011 increased by 43 percent compared to 2010, and represented 55 percent of all canadian oil and gas wells drilled, compared to 42 percent in 2010 and 30 percent in 2009. We expect this trend to continue in 2012 due to the favourable economics of horizontal wells compared to conventional vertical wells.

new play development is also expected to support growth in the canadian pressure pumping industry. We expect to see increased activity in new plays, such as the Duvernay, nordegg, and Muskwa. these plays contain oil and liquids-rich gas reserves and with strong oil prices anticipated, the 2012 well count in these areas is expected to increase compared to 2011.

the canadian equipment built under our 2011 capital program has now been deployed and we expect an increase in year-over-year revenue as a result of the increased capacity. Furthermore, our 2012 budget includes an additional 92,500 of fracturing horsepower, as well as additional cement, nitrogen and acid equipment that we expect to deploy throughout the second half of 2012.

as well, we expect to maintain our strong canadian operating margins in 2012. cost increases for key inputs such as sand, acid and guar, as well as higher employee costs, are anticipated. however, pricing increases are expected to offset the higher costs and result in 2012 margins that are consistent with 2011.

u.S. Operations

We anticipate u.S. activity to grow in oil and liquids-rich gas regions and slow in most dry gas regions. the rig count declines in the haynesville, Fayetteville, and Barnett regions have resulted in a redeployment of equipment out of the dry gas areas and into the oil and liquids-rich gas areas. this redeployment has moderated management’s expectations regarding growth in the u.S. market for 2012. however, we continue to anticipate u.S. activity to remain strong as additional oil and liquids-rich gas plays are developed.

the shift from dry gas into oil and liquids-rich gas plays will negatively impact revenue and operating margins for our u.S. operations during the first quarter of 2012. in addition, first quarter operating margins for our new fracturing, cement and coiled tubing crews in the u.S. will be negatively impacted by low utilization levels as we establish our work programs with new customers in new regions. however, we believe that as we work through these issues during the first quarter and as the market shifts to more oil and liquids-rich gas activity, operating conditions will improve in the u.S. and operating margins will increase. in addition, we expect 2012 results to benefit from our strong u.S. contracted position. 62 percent of our existing u.S. fracturing fleet will be under contract during 2012, which is up from 55 percent in 2011, as two new contracts were added in the permian during the first quarter of 2012.

We expect our u.S. operations will benefit from substantial equipment growth in 2012. Our 2011 capital budget included 205,000 of additional fracturing horsepower, and substantial increases to our cementing and coiled tubing service lines. the majority of this equipment was deployed

canadian Operations

OutlOOK


in the second half of 2011 and in early 2012, therefore our 2012 financial results should benefit from deployment of this new equipment. additionally, equipment from our 2012 capital budget is expected to be deployed throughout the second half of the year. We intend to deploy the new equipment from our 2012 budget into oil and liquids-rich gas focused areas, which is expected to include new geographic regions for trican.

international Operations

Based on the results of the 2012 contract tendering process for our russian and Kazakhstan operations, we expect 2012 revenue to increase by approximately 10 percent compared to 2011. the revenue increase is based on an 8 percent expected rise in activity, combined with a 2 percent expected increase in average revenue per job. the expected increase in average revenue per job is the combined result of increased pricing, partially offset by the impact of smaller fracturing job sizes, and a shift in the sales mix toward the cementing, coiled tubing and nitrogen service lines. these service lines typically experience lower average revenue per job relative to the fracturing service line.

cost inflation continues to be an issue for our russian and Kazakhstan operations. however, we expect a modest increase in operating margins in 2012, as a result of a shift in our work scope to higher margin jobs and continued focus on optimizing our cost structures in russia and Kazakhstan.

customer interest in horizontal completions and multi- stage fracturing is expected to increase in russia during 2012. Several successful pilot projects were completed in 2011 and we expect this momentum to continue in 2012.

although 2011 results for our algeria operations were disappointing, we began to see increased activity in the second half of 2011, as bureaucratic issues within Sonatrach began to ease. algeria also has gas supply commitments to europe and will need to increase production in order to meet these contracts. Given these positive signs, our 2012

strategy in algeria will be to increase equipment utilization levels, which is expected to lead to improved profitability in the region.

Our 2012 strategy in australia will be to expand our cementing service line by building new customer relationships and offering high quality service. We expect to add to the current cementing fleet during 2012 as we continue to establish ourselves in the region. We do not expect the growth of the australian operations to be significant to our overall financial results during 2012; however, we do anticipate establishing a meaningful presence in this market during the year.

in Saudi arabia, we are working to establish our presence in the market and continue to expect to submit bids for pressure pumping tenders in 2012. revenue from this region is not expected to be significant during 2012, as we will focus on establishing customer relationships and a reputation as a high quality service provider.

Description of Services

For a description of trican’s services, visit www.trican.ca/services.


n expectation that canadian oil and liquids-rich gas directed activity will grow in 2012, in anticipation of strong oil prices combined with weak gas prices;

n expectation that many of the canadian plays are still in the early stages of development, which is supportive of our view that the canadian pressure pumping market will continue to grow in the future;

n expectation that growth in the canadian market will be driven by new plays such as the Duvernay, alberta Bakken, nordegg and Muskwa;

n expectation that the number of stages per well in canada will grow in 2012, although the rate of growth will slow down as the plays become more mature;

n expectation of growth in canadian pressure pumping demand, due to the continued strength of the oil and liquids-rich gas plays, an increase in fracturing treatments per well and new play growth in areas such as the Duvernay, Muskwa, and nordegg;

n recent industry forecasts predict a 10 percent increase in drilling activity in 2012 compared to 2011;

n expectation that our canadian workforce growth will continue and we will maintain a strong focus on both retention and the addition of people by offering them rewarding career opportunities;

n expectations that our 2012 u.S. capital budget will include the addition of 12 cement, 7 coiled tubing, 9 nitrogen, and 10 acidizing units;

n expectation that we will continue to execute on our geographic and service line expansion initiatives in an effort to grow our u.S market share;

n expectation that we will continue to expand on our efforts to establish a reputation for operational excellence and technical solutions in the u.S. in 2012;

n belief that investing in an r&D facility in russia will allow us to provide customized technical solutions for our russian customers and give us an advantage in a very competitive market;

n expectation that horizontal drilling and completions will gain momentum in 2012 and become a significant component of future russian industry activity and that this would substantially increase the fracturing horsepower demands in russia;

n belief that the Kazakhstan market will continue to grow and technical solutions will become increasingly important within the region;

n expectation that we will participate in work tenders in 2012 in Saudi arabia with our cementing service line;

n expectation that we will initiate industrial services in Saudi arabia in 2012;

n expectation of the demand for pressure pumping services in Saudi arabia to grow over the next several years.

n belief that the Saudi government will look to meet domestic energy needs by increasing gas production so that the majority of the country’s oil production can be exported;

FOrWarD-lOOKinG StateMentS

this document contains statements that constitute forward-looking statements within the meaning of applicable securities legislation. these forward-looking statements are identified by the use of terms and phrases such as “anticipate,” “achieve”, “achievable,” “believe,” “estimate,” “expect,” “intend”, “plan”, “planned”, and other similar terms and phrases. these statements speak only as of the date of this document and we do not undertake to publicly update these forward-looking statements except in accordance with applicable securities laws. these forward-looking statements include, among others:


n belief that if horizontal drilling and completions technology is required to unlock the potential of Saudi arabia’s gas reserves, the demand for pressure pumping services should increase in the future;

n belief that our reputation for operational excellence and technical solutions should provide us with an opportunity to grow in australia in the future;

n expectation that with added r&D capacity, trican will develop new options to address environmental concerns, maintain our technical leadership in each of our service lines, keep product development as a quick, customer-focused process and, learn from worldwide operations and personnel;

n expectation that our new r&D facilities in Moscow and houston will enable us to learn from different regions and develop capabilities to address local issues;

n expectation that canadian demand for pressure pumping services will remain strong in 2012;

n expectation for oil and liquids-rich gas directed activity to lead the increase in canadian drilling activity, with strong oil prices anticipated throughout 2012;

n expectation of high demand in the oil and liquids-rich gas plays to be partially offset by a decline in dry gas activity, as natural gas prices are expected to remain weak;

n expectation for oil directed activity to mitigate the impact of low gas prices on industry activity levels;

n expectation for horizontal drilling activity to support strong canadian demand in 2012;

n expectation for horizontal drilling activity to remain strong due to the favorable economics of horizontal wells compared to conventional vertical wells;

n expectation that new play development will support growth in the canadian pressure pumping industry;

n expectation of seeing increased activity in new canadian plays such as the Duvernay, nordegg, and Muskwa;

n expectation that an increase in year-over-year canadian revenue will occur as a result of the increased equipment capacity;

n expectation that our 2012 canadian capital budget will include an additional 92,500 of fracturing horsepower, as well as additional cement, nitrogen and acid equipment that we expect to deploy throughout the second half of 2012;

n expectation that we will maintain our strong canadian operating margins in 2012;

n expectation for cost increases in canada for key inputs such as sand, acid and guar, as well as higher employee costs;

n expectation that pricing increases will offset the higher costs in canada and result in 2012 margins that are consistent with 2011;

n expectation that that u.S. activity will grow in oil and liquids-rich gas regions and slow in most dry gas regions.

n expectation that u.S. activity will remain strong as additional oil and liquids-rich gas plays are developed.

n expectation that the shift from dry gas into oil and liquids-rich gas plays will negatively impact revenue and operating margins for our u.S. operations during the first quarter of 2012.

n expectation that first quarter u.S. operating margins for our new fracturing, cement and coiled tubing crews will be negatively impacted by low utilization levels as we establish our work programs with new customers in new regions.

n belief that as we work through start-up issues during the first quarter and as the market shifts to more oil and liquids-rich gas activity, operating conditions will improve in the u.S. and operating margins will increase.

n expectation that 2012 results will benefit from our strong u.S. contracted position.

n expectation that 62 percent of our existing u.S. fracturing fleet will be under contract during 2012

n expectation that our u.S. operations will benefit from substantial equipment growth in 2012.

n expectation to deploy the new equipment from our 2012 u.S. capital budget into oil and liquids-rich gas focused areas, which is expected to include new geographic regions for trican.

n expectation that 2012 russian revenue will increase by approximately 10 percent compared to 2011;


n expectation that the russian revenue increase will be based on an 8 percent expected rise in activity, combined with a 2 percent increase in average revenue per job;

n expectation that the increase in average revenue per job in russia is the combined result of increased pricing, partially offset by the impact of smaller fracturing job sizes, and a shift in the sales mix toward the cementing, coiled tubing and nitrogen service lines;

n expectation of a modest increase in russian operating margins in 2012, as a result of a shift in our work scope to higher margin jobs and continued focus on optimizing our cost structures in russia and Kazakhstan;

n expectation that customer interest in horizontal completions and multi-stage fracturing will increase in russia during 2012;

n expectation that algeria has gas supply commitments to europe and will need to increase production in order to meet these contracts;

n expectation to add to the current australian cementing fleet during 2012;

n expectation that revenue from our Saudi arabia operations will not be significant during 2012.

Forward-looking statements are based on current expectations, estimates, projections and assumptions, which we believe are reasonable but which may prove to be incorrect and therefore such forward-looking statements should not be unduly relied upon. in addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: industry activity; the general stability of the economic and political environment; effect of market conditions on demand for the company’s products and services; the ability to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability to operate its business in a safe, efficient and effective manner; the performance and characteristics of various business segments; the effect of current plans; the timing and costs of capital expenditures; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the company operates; and the ability of the company to successfully market its products and services.

Forward-looking statements are subject to a number of risks and uncertainties, which could cause actual results to differ materially from those anticipated. these risks and uncertainties include: 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. in addition, actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth under the section entitled “risk Factors” in the annual information Form of the company dated March 22, 2012, which is available on SeDar at www.sedar.com.

cOrpOrate inFOrMatiOn

Board of direCtorS

Kenneth M. Bagan(1) (2) (4) independent Businessman

g. allen Brooks (1) (3) (5) president G. allen Brooks, llc

Murray L. Cobbe chairman

Dale M. Dusterhoft chief executive Officer

Donald r. Luft (4) president and chief Operating Officer

Kevin L. Nugent (1) (2) (3) president livingstone energy Management ltd.

Douglas F. robinson (2) (3) (4) independent Businessman(1) Member of the audit committee(2) Member of the compensation committee(3) Member of the corporate Governance committee(4) Member of the health, Safety and environment committee(5) lead Director

offiCerS


Donald r. Luft president and chief Operating Officer

Michael a. Baldwin, C.a. Vice president, Finance and chief Financial Officer

Michael g. Kelly, C.a. Senior Vice president, eaMe and ciS

Bonita M. Croft Vice president, legal, General counsel and corporate Secretary

rob J. Cox Vice president, canadian Geographic region

Corporate offiCe

Trican Well service Ltd. 2900, 645 – 7th avenue S.W. calgary, alberta t2p 4G8 telephone: 403.266.0202 Facsimile: 403.237.7716 Website: www.trican.ca

auditorS

KpMG llp, chartered accountants calgary, alberta

BaNkerS

hSBc Bank canada, calgary, aB

regiStrar aNd traNSfer ageNt

computershare trust company of canada calgary, alberta

StoCk eXCHaNge liStiNg

the toronto Stock exchange trading Symbol: tcW

iNveStor relatioNS iNforMatioN

requests for information should be directed to:


Michael a. Baldwin, C.a. Vice president, Finance and chief Financial Officer

MANAGEMENT’S DISCUSSION AND ANALYSIS AND CONSOLIDATED FINANCIAL STATEMENTS

For the Years Ended December 31, 2010 and 2011


MANAGEMENT’S DISCUSSION & ANALYSIS

The following discussion and analysis of the financial condition and results of operations of the Company have been prepared taking into consideration information available to February 28, 2012, and should be read in conjunction with the consolidated financial statements and accompanying notes.

OVERVIEW

Headquartered in Calgary, Alberta, Trican has operations in Canada, the United States, Russia, Kazakhstan, Australia and Algeria. Trican provides a comprehensive array of specialized products, equipment and services that are used during the exploration and development of oil and gas reserves.

Financial Review ($millions, except per share amounts, unaudited)

Three months ended Twelve months ended

Dec. 31, 2011

Dec. 31, 2010

Sept. 30, 2011

Dec. 31, 2011

Dec. 31, 2010

Revenue $694.2 $434.3 $659.1 $2,309.6 $1,478.3

Operating income* 197.3 109.7 193.6 614.5 332.4

Net income 114.9 55.6 111.3 338.6 150.4

Net income per share (basic) $0.78 $0.39 $0.76 $2.32 $1.09

(diluted) $0.78 $0.38 $0.75 $2.30 $1.09

Adjusted net income* 117.9 58.8 114.4 351.0 162.7

Adjusted net income per share* (basic) $0.80 $0.41 $0.78 $2.41 $1.18

(diluted) $0.80 $0.41 $0.77 $2.39 $1.17

Funds provided by operations* 181.9 108.0 174.3 588.8 320.0

* Trican makes reference to operating income, adjusted net income and funds provided by operations. These are measures that are not recognized under International Financial Reporting Standards (IFRS). Management believes that, in addition to net income, operating income, adjusted net income and funds provided by operations are useful supplemental measures. Operating income provides investors with an indication of earnings before depreciation, foreign exchange, taxes and interest. Adjusted net income provides investors with information on net income excluding one-time non-cash charges and the non-cash effect of stock-based compensation expense. Funds provided by operations provide investors with an indication of cash available for capital commitments, debt repayments and other expenditures. Investors should be cautioned that operating income, adjusted net income, and funds provided by operations should not be construed as an alternative to net income and cash flow from operations determined in accordance with IFRS as an indicator of Trican’s performance. Trican’s method of calculating operating income, adjusted net income and funds provided by operations may differ from that of other companies, and accordingly, may not be comparable to measures used by other companies.

Consolidated revenue for the fourth quarter of 2011 was $694.2 million, an increase of 60% compared to the fourth quarter of 2010. Consolidated net income increased by 107% to $114.9 million and diluted earnings per share increased to $0.78 compared to $0.38 for the same period in 2010. Funds provided by operations was $181.9 million compared to $108.0 million in the fourth quarter of 2010.

Our Canadian operations achieved record quarterly revenue of $417.0 million and operating income of $164.8 million during the fourth quarter of 2011. Canadian revenue increased by 56% and operating income increased by 63% compared to the fourth quarter of 2010. Canadian activity levels remained strong during the fourth quarter of 2011 and were led by oil and liquids-rich gas directed activity. Horizontal drilling activity also remained strong in Canada as 58% of wells drilled during the fourth quarter of 2011 were horizontal compared to 38% for the same period in

the previous year. The number of fracturing stages per horizontal well also continued to increase during the fourth quarter, which benefitted our fracturing service line in Canada. In Canada during the fourth quarter, we added 30,000 horsepower to our fleet, exiting 2011 with 321,200 fracturing horsepower compared to 258,700 at the end of 2010.

U.S. activity levels remained strong during the fourth quarter as the U.S. rig count increased by 19% year over year and 3% sequentially. Strong activity levels contributed to record quarterly U.S. revenue of $215.7 million, an increase of 101% compared to the fourth quarter of 2010. U.S. pressure pumping demand continued to be driven by strong oil and liquids-rich gas and horizontal drilling activity. However, weak natural gas prices led to activity declines in our dry gas regions, which partially offset the increases in the oil and liquids-rich gas areas.

FOURTH QUARTER HIGHLIGHTS


One new fracturing crew was deployed into the Eagle Ford shale during the fourth quarter, and crews in Oklahoma and the Permian began operations in early 2012. Equipment utilization levels for the new Eagle Ford crew were low due to typical start-up issues, and our fixed cost structure continued to increase as we hired people to staff the new crews that were added in early 2012. In addition, utilization levels for our Fayetteville crew and one crew in the Haynesville were low near the end of the quarter as they were moved into oil and liquids-rich gas plays. These factors, combined with an extended holiday season that impacted utilization near the end of the quarter, had a negative impact on fourth quarter financial results and contributed to the 440 basis point sequential decrease in operating margins.

Revenue from our international operations was $61.5 million in the fourth quarter of 2011, up 5% year-over-year but down 23% sequentially. Our international operations include the financial results for operations in Russia, Kazakhstan, Algeria, and Australia, with Russia and Kazakhstan comprising the majority of our international results. Revenue and activity levels in Russia and Kazakhstan were down sequentially, but consistent with overall expectations for the region. The sequential decrease in revenue and operating margins was caused by low utilization, which resulted from the completion of our Russian customers’ 2011 work programs and cold temperatures typically experienced near the end of the fourth quarter in Russia.

Capital Budget UpdateManagement completed an in-depth review of the Company’s capital commitments and has reduced the previously announced 2012 capital budget by approximately $96 million to $582 million. The capital program reductions are primarily for our US operations and include the cancellation of 50,000 fracturing horsepower and four twin cementing units.

The reductions are largely due to the decrease in dry gas activity in the U.S. market. Despite these reductions, our 2012 capital budget is expected to increase our U.S. fracturing capacity by 25% and significantly expand our non-fracturing service lines. These increases reflect our positive U.S. outlook for 2012, supported by strong oil and liquids-rich gas activity, horizontal drilling activity, and new play growth.

Dividend IncreaseTrican Well Service Ltd. is pleased to announce that its Board of Directors has approved an increase to its semi-annual dividend from $0.05 to $0.15 per share, thereby increasing the annual dividend to $0.30 per share. This increase reflects our expectation that Trican can sustain strong earnings in the future and maximize shareholder value, while remaining committed to investing in the growth of our existing operations and future growth opportunities. The increase will be effective for the anticipated June 30, 2012 dividend payment.

Comparative Quarterly Income Statements ($thousands, unaudited)

2011% of

Revenue 2010% of

Revenue

Quarter Over

Quarter Change % Change

Revenue 694,214 100.0% 434,271 100.0% 259,943 59.9%

Expenses

Materials and operating 473,693 68.2% 302,236 69.6% 171,457 56.7%

General and administrative 23,226 3.3% 22,314 5.1% 912 4.1%

Operating income* 197,295 28.4% 109,721 25.3% 87,574 79.8%

Finance costs 6,557 0.9% 2,427 0.6% 4,130 170.2%

Depreciation and amortization 36,443 5.2% 30,353 7.0% 6,090 20.1%

Foreign exchange (gain)/loss (3,975) -0.6% 1,867 0.4% (5,842) -312.9%

Other income (1,405) -0.2% (1,277) -0.3% (128) 10.0%

Income before income taxes 159,675 23.0% 76,351 17.6% 83,324 109.1%

Income tax expense 44,805 6.5% 20,750 4.8% 24,055 115.9%

Net Income 114,870 16.5% 55,601 12.8% 59,269 106.7%

* See first page of this report.


($thousands, except revenue-per-job, unaudited)

Three months ended Dec. 31, 2011

% of Revenue

Dec. 31, 2010

% of Revenue

Sept. 30, 2011

% of Revenue

Revenue 417,021 267,831 371,481

Expenses


General and administrative 5,898 1.4% 7,312 2.7% 7,813 2.1%

Total expenses 252,261 60.5% 166,775 62.3% 224,559 60.4%


Number of jobs 7,108 6,674 6,960

Revenue-per-job 58,296 39,378 52,766


CANADIAN OPERATIONS

Sales Mix (unaudited)

Three months ended Dec. 31, 2011 Dec. 31, 2010 Sept. 30, 2011% of Total Revenue

Fracturing 68% 65% 67%

Cementing 16% 17% 17%

Nitrogen 8% 5% 8%

Coiled Tubing 4% 6% 4%

Acidizing 2% 4% 2%

Other 2% 3% 2%

Total 100% 100% 100%

Operations ReviewCanadian pressure pumping demand remained strong during the fourth quarter of 2011. The number of active drilling rigs in Canada increased 15% year-over-year and by 3% sequentially, led by oil and liquids-rich gas directed activity. Oil prices remained strong and supported oil and liquids-rich gas directed activity, which was partially offset by declines in dry gas activity due to weak natural gas prices.

Horizontal drilling activity remains strong in Canada as 58% of wells drilled during the fourth quarter of 2011 were horizontal compared to 38% in the fourth quarter of 2010. Our fracturing service line continues to benefit from the strength of horizontal drilling, as 95% of fourth quarter fracturing and fracturing related revenue was from horizontal wells. The number of fracturing stages per horizontal well also continued to increase during the fourth

quarter, which also benefitted our fracturing service line in Canada.

We completed the majority of our 2011 Canadian capital budget during the fourth quarter of 2011. An additional 30,000 of fracturing horsepower was deployed during the fourth quarter and we exited 2011 with 321,200 of fracturing horsepower in Canada. Strong demand for pressure pumping services in Canada has led to high utilization for all new and existing Canadian fracturing equipment placed into service.

Current Quarter versus Q4 2010Fourth quarter revenue increased by 56% or $149.2 million compared to the fourth quarter of 2010. Revenue-per-job increased by 48% due to larger job sizes combined with a 13% pricing increase. Job size continues to benefit from the trend towards larger fracturing treatments performed


on horizontal wells. The demand for larger treatments has resulted in a demand for more fracturing horsepower per crew. Our average available fracturing horsepower in the fourth quarter of 2011 increased by 60% compared to the fourth quarter of 2010, which allowed us to respond to the demand for larger fracturing crews. Increased Canadian activity levels contributed to the job count increase of 7%.

As a percentage of revenue, materials and operating expenses decreased slightly to 59.1% from 59.5% as increased pricing and operational leverage on our fixed cost structure were offset by cost increases for key inputs and employee costs. General and administrative expenses decreased by $1.4 million due largely to lower share based employee costs and legal fees.

Current Quarter versus Q3 2011Canadian revenue increased by 12% sequentially in the fourth quarter of 2011. Increased equipment availability

contributed to the 2% sequential increase in job count, and an increase in fracturing job sizes led to the 11% increase in revenue-per-job. The additional equipment has enhanced our ability to respond to the demand for larger fracturing jobs and an increase in fracturing treatments per well.

Materials and operating expenses increased as a percentage of revenue to 59.1% compared to 58.3% in the third quarter of 2011, due largely to increased third-party hauling expenses. Increased use of Nitrogen for the fracturing service line led to volume demands that exceeded our capacity to transport the product internally. In anticipation of sustained demand for Nitrogen in 2012, we have taken steps to reduce our third party hauling costs for transportation of Nitrogen.

General and administrative expenses decreased by $1.9 million, due mainly to a decrease in share based employee costs.



% of Revenue

Dec. 31, 2010

% of Revenue

Sept. 30, 2011

% of Revenue

Revenue 215,672 107,588 207,288

Expenses



Total expenses 168,451 78.1% 85,728 79.7% 152,753 73.7%


Number of jobs 1,495 822 1,445

Revenue-per-job 145,151 131,538 144,361


UNITED STATES OPERATIONS

Operations ReviewOverall U.S. activity levels remained strong during the fourth quarter of 2011 and were supported by strong horizontal drilling activity, which increased 23% year-over-year and 4% sequentially. U.S. pressure pumping demand and activity levels were also strong in the oil and liquids-rich gas plays during the quarter. Year-over-year and sequential rig count increases occurred in the oil and liquids-rich gas plays where Trican operates including the Eagle Ford, Permian and Oklahoma regions. Conversely, fourth quarter activity levels declined in the dry gas plays such as the Haynesville, Barnett, and Fayetteville due to weak natural gas prices. In

response to this trend, one Haynesville crew was redeployed to the Eagle Ford, and our Fayetteville crew began operating as a travelling crew in oil and liquids-rich gas plays.

Operating margins remained strong for our two Marcellus crews during the fourth quarter of 2011. Although this is a dry gas region, our contracted positions supported strong utilization levels for both crews.

One new fracturing crew was deployed in the Eagle Ford shale during the fourth quarter, and crews in Oklahoma and the Permian began operations in early 2012. Equipment utilization for the new Eagle Ford crew was low due


to typical start-up issues, and our fixed cost structure continued to increase as we hired people to staff the new crews that were added in early 2012. In addition, utilization levels for our Fayetteville crew and one crew in the Haynesville were low near the end of the quarter as they were moved into oil and liquids-rich gas plays. These factors, combined with an extended holiday season that impacted utilization near the end of the quarter, had a negative impact on fourth quarter financial results and contributed to the 440 basis point sequential decrease in operating margins.

Current Quarter versus Q4 2010Year-over-year revenue increased by 100% due to increases in job count and revenue-per-job. Job count increased by 82% and benefitted from an increase in average available horsepower compared to the fourth quarter of 2010. A 19% increase in year-over-year rig count in our areas of operation and service line expansion also contributed to the job count increase. These factors were partially offset by low utilization near the end of the quarter for the Haynesville and Fayetteville crews that were moved into oil and liquids-rich gas areas. Revenue-per-job increased by 10% as a 20% increase in pricing was partially offset by a lower proportion of work performed in the Haynesville, which generally has higher revenue-per-job than other regions.

As a percentage of revenue, materials and operating expenses decreased to 76.3% from 77.9% because of increased pricing and operational leverage on our fixed cost structure. These factors were partially offset by increased costs relating to the start-up of one new fracturing crew, an increase to the fixed cost structure as we hired people to staff the new crews that were added in early 2012, and

the movement of two fracturing crews into oil and liquids-rich gas plays. In addition, the cost for key inputs such as acid, sand and guar have increased as demand for these products remains strong in the U.S. market. General and administrative costs increased by $1.9 million due largely to higher employee costs.

Current Quarter versus Q3 2011Revenue for the fourth quarter increased by 4% relative to the third quarter of 2011. The addition of a new fracturing crew and a 3% U.S. rig count increase in the areas where we operate contributed to the increase. Activity levels continued to remain strong in our oil and liquids-rich gas areas as the rig count increased by 6% in these regions. U.S. rig count decreased by 4% in the dry gas areas where we operate, which partially offset the increased activity in the oil and liquids-rich gas plays. In addition, utilization near the end of the quarter was negatively impacted by the movement of the Haynesville and Fayetteville crews into oil and liquids-rich gas areas. Revenue-per-job in the fourth quarter was relatively flat on a sequential basis as fourth quarter pricing and sales mix were largely unchanged compared to the third quarter of 2011.

Materials and operating expenses increased to 76.3% from 72.5% as a percentage of sales. Operating margins were negatively impacted by start-up costs for the new fracturing crew, an increase to the fixed cost structure as we hired people to staff the new crews that were added in early 2012, and movement of two fracturing crews into oil and liquids-rich gas plays. General and administrative expenses increased by $1.3 million largely due to increased employee costs and travel expenses.



% of Revenue

Dec. 31, 2010

% of Revenue

Sept. 30, 2011

% of Revenue

Revenue 61,521 58,852 80,335

Expenses



Total expenses 60,254 97.9% 57,851 98.3% 72,251 89.9%


Number of jobs 1,180 1,052 1,388

Revenue-per-job 48,178 53,923 54,686


INTERNATIONAL OPERATIONS


Sales Mix (unaudited)

Three months ended Dec. 31, 2011 Dec. 31, 2010 Sept. 30, 2011% of Total Revenue

Fracturing 74% 78% 76%

Coiled Tubing 13% 12% 11%

Cementing 8% 5% 8%

Nitrogen 5% 5% 5%

Total 100% 100% 100%

Operations ReviewOur international operations include the financial results for operations in Russia, Kazakhstan, Algeria, and Australia. Our Russia and Kazakhstan operations comprise the majority of our international results, and revenue and activity levels in this region were down sequentially due to lower equipment utilization levels. Utilization was negatively impacted by the completion of our customers’ 2011 work programs and cold temperatures typically experienced near the end of the fourth quarter. The year-over-year increase in activity resulted in a 5% increase in revenue, consistent with our expectations for the region.

Relative to the Canadian dollar, the Russian ruble weakened by 3% compared to the third quarter of 2011. The devaluation of the ruble had a negative impact on fourth quarter operating margins, as approximately 25% of our costs in Russia are denominated in Canadian dollars and other foreign currencies.

In Algeria, we offer coiled tubing and cementing service to Sonatrach, the state-owned oil company. Fourth quarter results for our Algeria operations continued to be negatively impacted by low utilization levels. We continue to focus on reducing costs in this region in an effort to improve profitability, as well as work with Sonatrach to improve equipment utilization levels.

We have no active operations or equipment in Saudi Arabia. We are currently establishing a sales office in the region and expect to submit tenders for contracts with customers in Saudi Arabia during 2012.

We offer cementing and environmental services in Australia. Our Australian operations have not grown significantly since acquisition as we continue to establish our cementing service line and sales presence in the region.

Current Quarter versus Q4 2010International revenue increased by 5% compared to the fourth quarter of 2010. Job count increased by 12%, which was relatively consistent with the expected year-over-year increase in activity based on our 2011 Russian contracts. Revenue-per-job decreased by 11% as pricing increases were more than offset by a lower proportion of fracturing revenue relative to total revenue during the quarter. Smaller average fracturing job sizes due to customer mix also contributed to the decrease in revenue-per-job.

Fourth quarter materials and operating expenses as a percentage of revenue remained flat at 91.5% compared to the fourth quarter of 2010. Year-over-year pricing increases were offset by cost increases for items such as fuel and operational employee costs. General and administrative expenses were relatively consistent on a year-over-year basis, as higher employee costs were offset by lower bad debt and share based employee expenses.

Current Quarter versus Q3 2011Revenue for our international operations decreased by 23% on a sequential basis as a result of decreases in revenue-per-job and job count. The 15% decrease in job count was due to decreased activity caused by seasonal slowdowns and the completion of the 2011 work contracts in Russia. Revenue-per-job decreased sequentially by 12% due to a lower proportion of fracturing revenue relative to total revenue, smaller average fracturing job sizes, and a 3% decrease in the ruble relative to the Canadian dollar.

Materials and operating expenses as a percentage of revenue increased to 91.5% from 85.2% on a sequential basis. Reduced operational leverage on our fixed cost structure combined with devaluation of the ruble contributed to the decrease in operating margins. General and administrative expenses increased by $0.2 million due to slightly higher employee costs.


CORPORATE

($thousands, unaudited)

Three months ended, Dec. 31, 2011

% of Revenue

Dec. 31, 2010

% of Revenue

Sept. 30, 2011

% of Revenue

Expenses



Total expenses 15,953 2.3% 14,196 3.3% 15,921 2.4%

Operating loss* (15,953) (14,196) (15,921)

Current Quarter versus Q4 2010Corporate expenses increased $1.8 million from the same quarter last year due primarily to increases in employee salaries and information technology expenses. The increase was partially offset by a decline in share based expenses and legal expenses.

Current Quarter versus Q3 2011Corporate division expenses in the fourth quarter of 2011 were relatively consistent with the third quarter of 2011.

OTHER EXPENSES AND INCOMEFinance costs increased by $4.1 million on a year-over-year basis as a result of interest on the new private placement debt. Depreciation and amortization increased by $6.1 million compared to the same period last year, largely due to capital additions relating to our capital expansion program.

The foreign exchange gain of $4.0 million in the quarter versus a loss of $1.9 million in the same quarter last year was due to the net impact of fluctuations in the U.S. dollar and Russian ruble relative to the Canadian dollar. Other income was $1.4 million in the quarter versus $1.3 million for the same period in the prior year. Other income is largely comprised of interest income on a loan to an unrelated third party and interest income earned on cash balances.

INCOME TAXESTrican recorded income tax expense of $44.8 million in the quarter versus $20.8 million for the comparable period of 2010. The increase in tax expense is primarily attributable to significantly higher earnings before taxes.

OTHER COMPREHENSIVE INCOMEOther comprehensive income for the three months ended December 31, 2011 includes a gain of $4.9 million on the cash flow hedges. There were no designated hedges

in the same period of the prior year. Foreign currency translation differences resulted in a loss of $10.9 million for the quarter as a result of the Canadian dollar spot price strengthening by 2% against the U.S. dollar, and 2% against the Russian ruble compared to spot prices at the end of the third quarter.

2011 HighlightsConsolidated revenue for 2011 increased by 56% to $2.3 billion compared to 2010, and net income increased to $338.6 million compared to $150.4 million in 2010. Adjusted diluted net income per share increased to $2.39 from $1.17 and funds from operations increased to $558.8 million from $320.0 million compared to 2010.

Our Canadian operations achieved record annual revenue of $1.3 billion and record operating income of $464.7 million. Strong demand in the Canadian market was led by activity in the oil and liquids-rich gas plays, as oil prices remained strong throughout 2011. Although the year-over-year Canadian rig count was up by 21%, the oil well count increased by 41%, while gas well count decreased by 5%. In addition, Trican’s Canadian operations continued to benefit from the strength of horizontal drilling activity in 2011. The number of horizontal wells drilled as a percentage of total wells drilled increased to 55% in 2011, compared to 42% in 2010.

Our Canadian operations executed a large 2011 capital budget, increasing the size of our equipment fleet accordingly. The Canadian fracturing fleet increased by 62,500 horsepower during 2011, and the size of our cementing, acidizing and nitrogen fleets also expanded during the year. The new equipment was deployed throughout the second half of 2011 and contributed to the substantial increase in year-over-year revenue. Year-over-year operating income increased by 65% and operating margins increased to 36.2%, compared to 32.8% in 2010.


A key factor in the margin improvement was a 14% increase in 2011 pricing compared to 2010.

Annual 2011 U.S. revenue of $738.9 million was 105% higher than in 2010, and our operating income of $190.8 million was a 173% increase compared to 2010, both record highs for our U.S. operations. Operating income as a percentage of revenue was 25.8% compared to 19.4% in 2010, and benefitted from year-over-year pricing increases of 34%.

Demand for U.S. pressure pumping services grew in 2011, as the overall U.S. rig count increased by 22%. However, most of the growth was generated from areas containing oil and liquids-rich gas, such as the Eagle Ford, Permian and Oklahoma regions. Conversely, dry gas areas such as the Haynesville, Fayetteville and Barnett shales all experienced a decrease in year-over-year rig count. Year-over-year rig count in the oil and liquids-rich gas areas where Trican operates increased by 53%, compared to a 21% decline in the dry gas areas. Horizontal drilling continued to grow in the U.S. during 2011. Horizontal wells represented 57% of active U.S. drilling rigs in 2011, compared to 53% in 2010 and 45% in 2009. The growth of horizontal drilling benefited all of our U.S. service lines in 2011.

Our U.S. operations grew substantially during 2011. The expansion included commencement of fracturing operations in the Eagle Ford and Permian regions and

the addition of a second fracturing crew in the Marcellus region. However, our aggressive expansion initiatives also resulted in start-up costs in the second half of 2011 that negatively impacted operating margins in the third and fourth quarters.

Our international operations include the financial results for operations in Russia, Kazakhstan, Algeria, and Australia. Revenue from our international operations was $288.0 million in 2011, up 11% compared to 2010. Our Russia and Kazakhstan operations comprise the majority of our international results and revenue and activity levels were consistent with overall expectations for the region, based on the results of the 2011 tendering process. Activity levels increased by approximately 7% and operating margins were relatively flat, as pricing increases were fully offset by higher costs. Cost inflation was a factor during the first half of the year, but stabilized during the second half. Despite the slowdown in overall inflation, our Russian and Kazakhstan operations experienced cost increases for items such as hauling, fuel and products during the second half of the year.

In July of 2011, Trican entered the Australian market through the acquisition of a privately-owned company that provides cementing and environmental services in Eastern Australia. This acquisition provided us with a strategic entry point into the growing Australian pressure pumping market.

Comparative Annual Income Statements ($thousands, unaudited)

Year ended December 31 2011% of

Revenue 2010% of

RevenueYear-Over-

Year Change % ChangeRevenue 2,309,647 100% 1,478,345 100.0% 831,302 56.2%

Expenses

Materials and operating 1,598,470 69.2% 1,076,062 72.8% 522,408 48.5%



Finance costs 20,041 0.9% 9,332 0.6% 10,709 114.8%

Depreciation and amortization 126,576 5.5% 112,089 7.6% 14,487 12.9%

Foreign exchange (gain)/loss (4,275) -0.2% 5,573 0.4% (9,848) -176.7%

Other income (5,985) -0.3% (3,878) -0.3% (2,107) 54.3%

Income before income taxes 478,167 20.7% 209,238 14.2% 268,929 128.5%

Income tax expense 139,531 6.0% 58,876 4.0% 80,655 137.0%

Net Income 338,636 14.7% 150,362 10.2% 188,274 125.2%



2011 Canadian revenue increased by 49% compared to 2010 due to increases in job count and revenue-per-job. The job count increased by 16% and compares to the 21% year-over-year increase in the average number of Canadian active drilling rigs. Revenue-per-job increased by 29% and benefitted from a 14% annual price increase combined with a demand for larger fracturing treatments. 2011 financial results for our Canadian operations also benefitted from an increase in average available fracturing horsepower, as well as increases to our cementing, nitrogen and acidizing service lines. The increased capacity allowed us to respond

to the increased demand for larger fracturing treatments and more treatments per horizontal well.

As a percentage of revenue, materials and operating expenses decreased to 61.6% from 64.2% compared to 2010. The decrease was due to improvements in pricing and increased operating leverage on our fixed cost structure and was partially offset by cost increases for key inputs such as acid, sand and guar. General and administrative costs increased by $2.4 million due largely to increases in employee costs.

CANADIAN OPERATIONS


Year ended December 31 2011 % of Revenue 2010 % of RevenueYear-Over-Year

ChangeRevenue 1,282,684 858,201 49%

Expenses

Materials and operating 790,508 61.6% 551,222 64.2% 43%

General and administrative 27,486 2.1% 25,078 2.9% 11%

Total expenses 817,994 63.8% 576,300 67.2% 42%

Operating income* 464,690 36.2% 281,901 32.8% 65%

Number of jobs 25,393 21,931 16%

Revenue-per-job 49,964 38,733 29%


UNITED STATES OPERATIONS



ChangeRevenue 738,916 361,055 105%

Expenses



Total expenses 548,089 74.2% 291,180 80.6% 88%

Operating income* 190,827 25.8% 69,875 19.4% 173%

Number of jobs 5,065 3,130 62%

Revenue-per-job 146,457 115,740 27%


U.S. revenue for 2011 increased by 105% compared to 2010. The job count increase of 62% was attributable to more available fracturing horsepower and additional

non-fracturing equipment compared to 2010. In addition, the number of active U.S. drilling rigs in our areas of operations increased by 21% on a year-over-year basis.


Revenue-per-job increased by 27% and benefitted from a 34% increase in year-over-year pricing. Pricing increases were partially offset by a 5% weakening of the U.S. dollar relative to the Canadian dollar and a slight increase in the proportion of non-fracturing work performed.

Material and operating expenses as a percentage of revenue decreased to 72.5% in 2011 from 78.8% in 2010. Operating

margins benefitted from increased operational leverage on our fixed cost structure and increased pricing. These factors were partially offset by start-up and redeployment costs incurred in the second half of 2011 and increased product and employee costs compared to 2010. General and administrative expenses increased by $5.8 million due largely to increased employee costs.

INTERNATIONAL OPERATIONS



ChangeRevenue 288,047 259,089 11%

Expenses



Total expenses 265,360 92.1% 235,325 90.8% 13%

Operating income* 22,687 7.9% 23,764 9.2% -5%

Number of jobs 4,901 4,510 9%

Revenue-per-job 55,902 56,206 -1%


Year to date revenue for our International operations is up 11% compared to the same period in 2010. The job count increased by 9% and is consistent with our expectation of an increase in activity based on the 2011 tender results. Revenue-per-job decreased by 1% as price increases obtained during the 2011 tender results were offset by a lower proportion of fracturing revenue relative to total revenue combined with smaller average fracturing job sizes due to customer mix.

Materials and operating expenses as a percentage of revenue increased slightly to 86.9% from 86.8% compared to the same period in 2010. Improved pricing and operating leverage on our fixed cost structure were offset by cost inflation. General and administrative expenses are up $4.5 million largely due to increased employee costs combined with the impact of bad debt recoveries that reduced general and administrative expenses in 2010.

CORPORATE

($thousands, unaudited)


ChangeExpenses



Total expenses 63,680 2.8% 43,186 2.9% 47%

Operating loss* (63,680) (43,186) 47%



Corporate expenses increased $20.5 million compared to last year due largely to an increase in employee salaries, profit sharing expense, and corporate information technology costs. These increases were partially offset by a decrease in share based expenses.

OTHER EXPENSES AND INCOME2011 finance costs increased $10.7 million relative to 2010 due to interest on the new private placement debt. Depreciation and amortization increased by $14.5 million as a result of the North American focused capital asset additions.

Foreign exchange gains of $4.3 million have been recognized in 2011 compared to losses of $5.6 million in 2010. The 2011 gain is due to the net impact of fluctuations in the U.S. dollar and Russian ruble relative to the Canadian dollar. Other income increased by $2.1 million from the same period in 2010 due largely to proceeds from an insurance claim.

INCOME TAXESThe income tax expense for the year ended December 31, 2011 was $139.5 million compared to the income tax expense of $58.9 million in 2010. The increase in the tax provision is largely attributable to the significantly higher earnings.

OTHER COMPREHENSIVE INCOMEOther comprehensive income includes an unrealized loss of $1.4 million on the cash flow hedges; there were no designated hedges in the same period of the prior year. In addition, a year-to-date unrealized loss of $2.2 million was recognized on the translation of the financial statements of our foreign subsidiaries whose functional currency is not Canadian dollars. From December 31, 2010 to December 31, 2011, the Canadian dollar weakened against the U.S. dollar by 2% and strengthened by 4% against the Russian ruble.

Liquidity and Capital Resources

Operating Activities

Funds provided by operations increased to $181.9 million in the fourth quarter of 2011 from $107.7 million in the fourth quarter of 2010, largely as a result of increased earnings.

Trican’s ending 2011 working capital increased by $263 million compared to the end of 2010. The increase is predominantly due to year-over-year increased activity levels, causing trade receivables, inventory, and prepaid

expenses to rise, partially offset by increased accounts payable. In addition, the Company has a cash balance of $126 million at the end of the year, which is largely a result of the cash generated during 2011 and the proceeds from the debt private placement earlier in 2011.

Investing Activities

Capital expenditures for the fourth quarter of 2011 totaled $162.8 million compared with $60.3 million for the same period in 2010.

Trican’s 2012 capital budget is projected to be $582 million, and has been reduced by $96 million from the previously announced 2012 capital budget. The capital program reductions are primarily for our U.S. operations and include the cancellation of 50,000 fracturing horsepower and four twin cementing units in the U.S.

$183 million of the projected capital budget will be directed towards our Canadian operations, $348 million towards our U.S. operations, and $51 million towards International operations. In addition, the 2012 capital budget is expected to consist of $448 million in expansion capital, $89 million in infrastructure needed to support new and existing operations, and $45 million in maintenance capital.

The 2012 capital budget is expected to add significant additional revenue generating capacity and includes an additional 92,500 of fracturing horsepower, 5 cement pumpers, 7 nitrogen pumpers, and 4 acid pumpers for our Canadian operations. Capacity for our U.S. operations is expected to increase by 142,500 of fracturing horsepower, 12 cement pumpers, 7 coiled tubing units, 9 nitrogen pumpers, and 10 acid pumpers.

The international operations’ capital expenditures largely consist of additional cementing capacity for Australia and maintenance capital for Russian and Kazakhstan.

At December 31, 2011, Trican had a number of ongoing projects relating to its capital program and estimates that $505 million of additional investment will be required to complete them.

On February 28, 2012, Trican announced an increase to its semi-annual dividend from $0.05 to $0.15 per share, thereby increasing the annual dividend per share to $0.30. The increase will be effective for the anticipated June 30, 2012 dividend payment.


Financing Activities

On October 18, 2011, Trican entered into a new $450 million four year extendible revolving credit facility (the “New Facility”) with a syndicate of banks. The New Facility, which replaced the previous $250 million three year extendible facility, is unsecured and bears interest at the applicable Canadian prime rate, U.S. prime rate, Banker’s Acceptance rate or at LIBOR plus 50 to 325 basis points, dependent on certain financial ratios of the Company. The New Facility requires Trican to comply with certain financial and non-financial covenants that are typical for this type of arrangement.

On April 28, 2011, Trican closed the issuance of U.S.$250 million and CAD$60 million senior unsecured notes on a private placement basis (the “Private Placement”). The notes issued under the Private Placement are subject to various terms with an average term of 7.5 years and an average rate of approximately 5.4%. The notes are unsecured and rank equally with Trican’s bank facilities and other outstanding senior notes.

As at February 28, 2012, Trican had 146,943,926 common shares and 5,637,189 employee stock options outstanding.

The Company has filed a Notice of Intention to make a Normal Course Issuer Bid (“NCIB”) with the Toronto Stock Exchange. Under the NCIB, the Company will be permitted to acquire up to approximately 12.7 million of its common shares during the period March 2, 2012 to March 1, 2013. All common shares purchased through the bid will be cancelled. A copy of the Notice of Intention to make a NCIB is available without charge on request to the Company’s Corporate Secretary.

OUTLOOK

Canadian OperationsCanadian demand for pressure pumping services was strong in 2011 and we expect this trend to continue in 2012. Recent industry forecasts reflect a 10% increase in drilling activity in 2012, compared to 2011. Oil and liquids-rich gas directed activity is expected to lead the increase, with strong oil prices anticipated throughout 2012. High demand in the oil and liquids-rich gas plays is expected to be partially offset by a decline in dry gas activity, as natural gas prices are expected to remain weak throughout 2012. However, activity in the Canadian oil and gas industry is currently dominated by oil and liquids-rich gas activity. This trend is expected to continue with recent industry forecasts suggesting that oil and liquids-rich gas activity could represent above 80% of Canadian drilling activity in 2012.

We expect strong Canadian demand to be supported by the continued strength of horizontal drilling activity. The number of Canadian horizontal wells drilled during 2011 increased by 43% compared to 2010, and represented 55% of all Canadian oil and gas wells drilled, compared to 42% in 2010 and 30% in 2009. We expect this trend to continue in 2012 due to the favourable economics of horizontal wells compared to conventional vertical wells.

New play development is also expected to support growth in the Canadian pressure pumping industry. We expect to see increased activity in new plays such as the Duvernay, Nordegg, and Muskwa. These plays contain oil and liquids-rich gas reserves and with strong oil prices anticipated, the 2012 well count in these areas is expected to increase compared to 2011.

The Canadian equipment built under our 2011 capital program has now been deployed and we expect an increase in year-over-year revenue as a result of the increased capacity. Furthermore, our 2012 budget includes an additional 92,500 of fracturing horsepower, as well as additional cement, nitrogen and acid equipment that we expect to deploy throughout the second half of 2012.

As well, we expect to maintain our strong Canadian operating margins in 2012. Cost increases for key inputs such as sand, acid and guar, as well as higher employee costs are anticipated. However, pricing increases are expected to offset the higher costs and result in 2012 margins that are consistent with 2011.

U.S. Operations

We anticipate U.S. activity to grow in oil and liquids-rich gas regions and slow in most dry gas regions. The rig count declines in the Haynesville, Fayetteville, and Barnett regions have resulted in a redeployment of equipment out of the dry gas areas and into the oil and liquids-rich gas areas. This redeployment has moderated managements’ expectations regarding growth in the U.S. market for 2012. However, we continue to anticipate U.S. activity to remain strong as additional oil and liquids-rich gas plays are developed.

The shift from dry gas into oil and liquids-rich gas plays will negatively impact revenue and operating margins for our U.S. operations during the first quarter of 2012. In addition, first quarter operating margins for our new fracturing, cement, and coiled tubing crews in the U.S. will be negatively impacted by low utilization levels as we establish our work programs with new customers in new regions.


However, we believe that as we work through these issues during the first quarter and as the market shifts to more oil and liquids-rich activity, operating conditions will improve in the U.S. and operating margins will increase. In addition, we expect 2012 results to benefit from our strong U.S. contracted position. 62% of our existing U.S. fracturing fleet will be under contract during 2012, which is up from 55% in 2011, as two new contracts were added in the Permian during the first quarter of 2012..

We expect our U.S. operations will benefit from substantial equipment growth in 2012. Our 2011 capital budget included 205,000 of additional fracturing horsepower, and substantial increases to our cementing and coiled tubing service lines. The majority of this equipment was deployed in the second half of 2011 and in early 2012, therefore our 2012 financial results should benefit from deployment of this new equipment. Additionally, equipment from our 2012 capital budget is expected to be deployed throughout the second half of the year. We intend to deploy the new equipment from our 2012 budget into oil and liquids-rich gas focused areas, which is expected to include new geographic regions for Trican.

International OperationsBased on the results of the 2012 contract tendering process for our Russian and Kazakhstan operations, we expect 2012 revenue to increase by approximately 10% compared to 2011. The revenue increase is based on an 8% expected rise in activity, combined with a 2% expected increase in average revenue-per-job. The expected increase in average revenue-per-job is the combined result of increased pricing, partially offset by the impact of smaller fracturing job sizes, and a shift in the sales mix toward the cementing, coiled tubing and nitrogen service lines. These service lines typically experience lower average revenue-per-job relative to the fracturing service line.

Cost inflation continues to be an issue for our Russian and Kazakhstan operations. However, we expect a modest increase in operating margins in 2012, as a result of a shift in our work scope to higher margin jobs and continued focus on optimizing our cost structures in Russia and Kazakhstan.

Customer interest in horizontal completions and multi-stage fracturing is expected to increase in Russia during 2012. Several successful pilot projects were completed in 2011 and we expect this momentum to continue into 2012.

Although 2011 results for our Algeria operations were disappointing, we began to see increased activity in the

second half of 2011, as bureaucratic issues with Sonatrach began to ease. Algeria also has gas supply commitments to Europe and will need to increase production in order to meet these contracts. Given these positive signs, our 2012 strategy in Algeria will be to increase equipment utilization levels, which is expected to lead to improved profitability in the region.

Our 2012 strategy in Australia will be to expand our cementing service line by building new customer relationships and offering high quality service. We expect to add to the current cementing fleet during 2012 as we continue to establish ourselves in the region. We do not expect the growth of the Australian operations to be significant to our overall financial results during 2012; however, we do anticipate establishing a meaningful presence in this market during the year.

In Saudi Arabia, we are working to establish our presence in the market and continue to expect to participate in pressure pumping tenders in 2012. Revenue from this region is not expected to be significant during 2012, as we will focus on establishing customer relationships and a reputation as a high quality service provider.

ACCOUNTING STANDARDS PENDING ADOPTIONAll accounting standards effective for periods beginning on or after January 1, 2011 have been adopted as part of the transition to IFRS. The following new IFRS pronouncements have been issued but are not in effect as at December 31, 2011. However, the pronouncements may have a future impact on the measurement and/or presentation of the Company’s financial statements:

As of January 1, 2015, Trican will be required to adopt IFRS 9, Financial Instruments, which is the result of the first phase of the IASB’s project to replace IAS 39, Financial Instruments: Recognition and Measurement. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The adoption of this standard is currently not expected to have a material impact on Trican’s Consolidated Financial Statements.

In May 2011, the IASB issued four new standards, and revised two existing standards. All of the new standards are effective for annual periods beginning on or after January 1, 2013.


IFRS 10, Consolidated Financial Statements, introduces new principle-based definition of control, applicable to all investees to determine the scope of consolidation. The standard provides the framework for consolidated financial statements and their preparation based on the principle of control.

IFRS 11, Joint Arrangements, replaces IAS 31 Interests in Joint Ventures. IFRS 11 divides joint arrangements into two types, each having its own accounting model. A ‘joint operation’ continues to be accounted for using proportional consolidation, where as a ‘joint venture’ must be accounted for using equity accounting.

IFRS 12, Disclosure of Interests in Other Entities, is a new standard which combines all of the disclosure requirements for subsidiaries, associates and joint arrangements in order to provide information related to the risks associated with an entities interest in other entities, and the effects of those interests on the entity’s financial positions, financial performance and cash flows.

IFRS 13, Fair Value Measurement, is a new standard meant to clarify the definition of fair value, provide guidance on measuring fair value and improve disclosure requirements related to fair value measurement.

IAS 27, Separate Financial Statements, was revised with the issuance of IFRS 10, and prescribes the accounting and disclosure requirements for investments in subsidiaries, joint ventures and associates when an entity prepares separate financial statements.

IAS 28, Investments in Associates and Joint Ventures, was revised with the issuance of IFRS 10, 11 and 12 and the revision to IAS 27, and provides the framework for the application of the equity method when accounting for investments in associates and joint ventures.

The Company intends to adopt the amendments in its financial statements for the annual period beginning in the year applicable. The extent of the impact of adoption of the amendments has not yet been determined.

CRITICAL ACCOUNTING ESTIMATESThe Company prepares its consolidated financial statements in accordance with International Financial Reporting Standards. In doing so, management is required to make various estimates and judgments in determining the reported amounts of assets and liabilities, revenues and

expenses, as well as the disclosure of commitments and contingencies. Management bases its estimates and judgments on its own experience and various assumptions believed to be reasonable under the circumstances. Anticipating future events cannot be done with certainty; therefore, these estimates may change as new events occur, more experience is acquired or the Company’s operating environment changes. The accounting estimates believed to require the most difficult, subjective or complex judgments and which are material to the Company’s financial reporting results are as follows:

Allowance for Doubtful Trade ReceivablesTrican evaluates its trade receivables through a continuous process of assessing its portfolio on an individual customer and overall basis. This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, financial condition of the Company’s customers, and other factors. Based on its review of these factors, it establishes or adjusts allowances for specific customers as well as general provisions if industry conditions warrant. This process involves a high degree of judgment and estimation and frequently involves significant dollar amounts. Accordingly, the Company’s results of operations can be affected by adjustments to the allowance due to actual write-offs that differ from estimated amounts.

Impairment of Financial AssetsThe Company evaluates impairment for financial assets measured at amortized cost at both a specific asset and collective level. All individually significant assets are assessed for specific impairment annually. Assets that are not individually significant are collectively assessed for impairment by grouping together assets with similar risk profiles.

Impairment is assessed using historical trends of default, timing of recoveries and the amount of loss incurred, adjusted for management’s judgment in relation to how the current economic and credit environment will impact losses being greater or less than historical trends.

An impairment loss is determined as the difference between an assets’ carrying amount and the present value of future cash flows. Losses are recognized in profit or loss and reflected in an allowance account against loans and receivables. When an event occurring after the impairment was recognized causes the amount of impairment to decrease, the recovery is reversed through profit and loss.


As at December 31, 2011, we performed impairment tests over our financial assets and determined that the carrying value of these assets is fairly stated.

Impairment of Non Financial AssetsThe recoverable amount of an asset or cash generating unit is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. For the purpose of impairment testing, assets that cannot be tested individually are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or other groups of assets (cash generating unit or CGU).

As at December 31, 2011, we performed impairment tests over our non-financial assets and determined that the carrying value of these assets is fairly stated.

Goodwill ImpairmentGoodwill arises upon the acquisition of subsidiaries. For acquisitions on or after January 1, 2010, the Company measures goodwill as the fair value of the consideration transferred including the recognized amount of any non-controlling interest in the acquiree, less the net recognized amount (generally fair value) of the identifiable assets acquired and liabilities assumed, all measured as of the acquisition date. As part of the transition to IFRS, the Company elected to restate only those business combinations that occurred on or after January 1, 2010. In respect of acquisitions prior to January 1, 2010, goodwill represents the amount recognized under Canadian GAAP.

Goodwill is allocated as of the date of the business combination to the Company’s cash generating units that are expected to benefit from the synergies of the business combination. Goodwill is not amortized, but is tested for impairment at least annually. An impairment loss in respect of goodwill is not reversed.

We have determined that none of the existing goodwill is impaired as at December 31, 2011.

Depreciation and Amortization of Property and EquipmentDepreciation methods, useful lives and residual values are reviewed each financial year end and adjusted if

appropriate. There have been no significant changes to the estimated useful lives of the Company’s property and equipment during the past two years.

Income TaxesDeferred income tax assets and liabilities are measured based on income tax rates and tax laws that are enacted or substantively enacted by the end of the reporting period and that are expected to apply in the years in which temporary differences are expected to be realized or settled. Deferred income tax assets are reviewed at each reporting period and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As such, income taxes are subject to measurement uncertainty and the interpretations can impact net earnings through the income tax expense arising from changes in deferred income tax assets or liabilities.

InventoryInventory is measured at the lower of cost and net realizable value. The cost of inventory is determined using the weighted average cost method. Inventory balances include all costs of purchase, costs of conversion and other costs incurred in bringing the inventory to their existing location and condition.

Net realizable value is the estimated selling prices in the ordinary course of business, less estimated costs of completion and selling expenses.

Share-Based Payment TransactionsThe Company has a share option plan and accounts for share options by expensing the fair value of share options measured using a Black Scholes option pricing model. In determining the fair value there are a number of assumptions related to risk-free interest rate, average expected option life, estimated forfeitures, estimated volatility of the Company’s shares and anticipated dividends. The fair value of the options is determined on their grant date and is recognized as administrative expense over the period that the share options vest, with a corresponding increase to contributed surplus.

The fair value of the Director Share Units and Performance Share Units is recognized based on the market value of


the Company’s shares underlying these compensation programs.

Financial InstrumentsThe fair values of cash and cash equivalents, trade and other receivables, and trade and other payables included in the consolidated statement of financial position, approximates their carrying amount due to the short-term maturity of these instruments. The fair value of contingent consideration approximates its carrying value as it reflects the fair value at purchase. The bank loans including the equipment and acquisition loan facility approximate their carrying amount due to the variable interest rates applied to these loans and credit spreads on the facilities approximate market rates. The fair value of capital lease obligations was determined by calculating the future cash flows, including interest, using market rates. The fair value of the loan to an unrelated third party calculated using a discounted cash flow approach. The Company calculates the fair value of the cash flow hedges using market forward rates reflecting the remaining term of the hedges at each reporting period.

Revenue RecognitionService and other revenue is recognized when the services are provided and collectability is reasonably assured. Customer contract terms do not include provisions for significant post-service delivery obligations.

BUSINESS RISKSOur business is subject to a number of risks and uncertainties, some of which are summarized below. We encourage you to review and carefully consider the risks described below, as well as those described elsewhere in this report and in other publicly disclosed reports and materials. If any such risks were to materialize, our business, financial condition, results of operations, cash flows or prospects could be materially adversely affected. In turn, this could have a material adverse effect on the trading price of our securities. Additional risks and uncertainties not currently known to us or that we currently deem immaterial may also adversely affect our business and operations.

Demand for Trican’s services is dependent upon the level of expenditures in the oil and gas industry, which can be volatile.

The demand, pricing and terms for Trican’s services depend significantly upon the level of expenditures made

by oil and gas companies on exploration, development and production activities. Expenditures by oil and gas companies are typically directly related to the demand for and price of oil and gas. Generally, when commodity prices and demand are, or are predicted to be, relatively high, demand for Trican’s services is high. The converse is also true.

The prices for oil and natural gas are subject to a variety of factors including: the demand for energy; the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels for oil; oil and gas production by non-OPEC countries; political and economic uncertainty and socio-political unrest; cost of exporting, producing and delivering oil and gas; technological advances affecting energy consumption; and weather conditions. Any prolonged or substantial reduction in oil and natural gas prices would likely decrease the level of activity and expenditures in oil and gas exploration, development and production activities and, in turn, decrease the demand for Trican’s services.

In addition to current and future oil and gas prices, the level of expenditures made by oil and gas companies are influenced by numerous factors over which the Company has no control, including but not limited to: weak general economic conditions; the cost of exploring for, producing and delivering oil and gas; the expected rates of current production; the discovery rates of new oil and gas reserves; cost and availability of drilling equipment; availability of pipeline and other oil and gas transportation capacity; North American natural gas storage levels; political, regulatory and economic conditions; taxation changes; government regulation; environmental regulation; ability of oil and gas companies to obtain credit, equity capital or debt financing; and movement of the Canadian dollar and Russian ruble relative to the U.S. dollar. A material decline in expenditures by oil and gas companies, caused by a decrease in oil and gas prices or otherwise, could have a material adverse effect on Trican’s business, financial condition, results of operations and cash flows. We may also be disadvantaged competitively and financially by a significant movement of exploration and production operation to areas of the world in which we are not currently active.

Additionally, during times of weak industry conditions, the risk of payment delays and failure to pay increases due to a reduction in customers’ cash flow and challenges relating to their ability to access debt and equity markets among other factors.


Trican’s Canadian Operations are susceptible to weather volatility. The well service industry is characterized by considerable seasonality in Canada, and to a lesser extent in Russia and the U.S. During the second quarter when the frost leaves the ground, many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment resulting in severe restrictions in the level of well servicing activity. The duration of this period, commonly referred to as the “spring break-up”, has a direct impact on the level of our activities, particularly in Canada. During other periods of the year, rainfall can also render some of the secondary and oilfield service roads impassable for the Company’s equipment. Additionally, if an unseasonably warm winter prevents sufficient freezing, Trican may not be able to access well sites.

These factors can all reduce activity levels below normal or anticipated levels. Activity levels in the U.S. and Russia are typically not impacted to the same extent by seasonality.

The oilfield services industry is highly competitive. We compete with multi-national, national and regional competitors in each of our current service lines in each of our geographic regions. Although we believe that we are continuing to build market share and have a significant presence in respect of all of our services, we do not currently hold a dominant market position with respect to any of the services we offer in any of the markets in which we operate. Certain of our competitors may have financial, technical, manufacturing and marketing advantages in certain regions and may be in a stronger competitive position than Trican as a result.

Competitive actions taken by our competitors such as price changes, new product and technology introductions and improvements in availability and delivery could affect our market share or competitive position. To be competitive, we must demonstrate value for our customers by developing new technologies and providing reliable products and services. The intense competition within our industry could lead to a reduction in revenue or prevent us from successfully pursuing additional business opportunities.

In addition, certain foreign jurisdictions and government-owned petroleum companies have adopted policies or regulations which may give local nationals in these countries a competitive advantage and which may impede our ability to expand into or to sustain a market share in such countries.

Trican would be adversely affected should access to a credit facility or additional financing be unavailable to Trican or its customers.

Trican’s growth strategy is subject to the availability of additional financing for future costs of operations or expansion that may not be available, or may not be available on favourable terms. Trican’s activities may also be financed partially or wholly with debt, which may increase its debt levels above industry standards. The level of Trican’s indebtedness from time to time could impair its ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise. If the Company’s cash flow from operations is not sufficient to fund its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, on favourable terms.

Furthermore, many of our customers access the credit markets to finance their oil and natural gas drilling activity. If the availability of credit to our customers is reduced, they may reduce their drilling and production expenditures, thereby decreasing demand for our products and services. Any such reduction in spending by our customers could adversely impact our operating results and financial condition.

The loss of key customers could cause Trican’s revenue to decline substantially.

For the year ending December 31, 2011, Trican had one significant customer. This customer represented approximately 16% of our consolidated revenue and all of the revenue from this customer was generated in the United States. There can be no assurance that Trican’s relationships with this customer will continue, and a significant reduction or total loss of the business from this customer, if not offset by sales to new or existing customers, would have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.

Failure to receive timely delivery of new equipment and parts from suppliers could adversely affect Trican’s growth plans.

The Company’s ability to expand its operations and provide reliable service is dependent upon timely delivery of new equipment and replacement parts from fabricators and suppliers. During past periods of high industry activity,


a shortage of skilled labour to build equipment coupled with high demand has placed a strain on some fabricators. If a similar strain occurs in the future, it could potentially increase the order time on new equipment and increase uncertainty surrounding final delivery dates. Significant delays in the arrival of new equipment from expected dates may constrain future growth and may have a material adverse effect on the financial performance of the Company.

Trican is subject to various risks from its foreign operations. Some of Trican’s current operations and related assets are located in Russia, Kazakhstan, Algeria and Australia. Further, Trican’s growth plans may contemplate establishing operations in additional foreign countries where the political and economic systems may be less stable than those in North America. Operations in these countries may be subject to a variety of risks including, but not limited to: social unrest or civil war, currency fluctuations, devaluations and exchange controls; inflation; uncertain political and economic conditions resulting in unfavourable government actions such as unfavourable legislation or regulation, trade restrictions, nationalization, expropriation, unfavourable tax enforcement or adverse tax policies; the denial of contract rights; trade restrictions or embargoes imposed by other countries; restrictions on the repatriation of income or capital; and acts of terrorism, extortion, or armed conflict. If any of the risks described above materialize, it could reduce Trican’s earnings and cash available for operations.

Further, government-owned oil companies located in some countries have adopted policies or are subject to governmental policies giving preference to the purchase of goods and services from companies that are majority-owned by local nationals. As a result, we may rely on joint ventures, license arrangements and other business combinations with local nationals in these countries. Activities in these countries may require protracted negotiation with host governments, national oil companies and third parties.

Our operations outside of Canada could also expose us to trade and economic sanctions or other restrictions imposed by the Canadian or other governments or organizations. Federal agencies and authorities may seek to impose a broad range of criminal or civil penalties against corporations or individuals for violations of securities laws, foreign corrupt practices laws or other federal

statutes. If any of the above described risks materialize, it could materially impact Trican’s operating results and financial condition.

Further, Trican is subject to various laws and regulations in the U.S. jurisdictions in which it operates that govern the operation and taxation of its business. The imposition, application and interpretation of such laws and regulations can prove to be uncertain.

An oversupply of oilfield service equipment could lead to a decline in the demand for Trican’s services. Because of the long-life nature of oilfield service equipment and the lag between when a decision to build additional equipment is made and when the equipment is placed into service, the inventory of oilfield service equipment in the industry does not always correlate with the level of demand. Periods of high demand often result in increased capital expenditures on equipment and those capital expenditures may add capacity that exceeds actual demand. This excess capacity could cause Trican’s competitors to lower their prices and could lead to a decrease in prices in the oilfield services industry generally. Consequentially, Trican could fail to secure enough work in which to employ its equipment. This could have a material adverse effect on Trican’s operating results and cash flows.

Fluctuations in foreign currency exchange rates could adversely affect the Company. Trican’s consolidated financial statements are presented in Canadian dollars. The reported results of our foreign subsidiary operations are affected by the movement in exchange rates primarily between the Canadian and United States dollar and Russian ruble. Trican’s Canadian Operations include exchange rate exposure as purchases of some equipment and materials are from United States suppliers. When acquiring Trican U.S., we took on United States dollar denominated debt which acts as a partial hedge against this investment.

Business acquisitions entail numerous risks and may disrupt Trican’s business or distract management attention. As part of Trican’s business strategy, it will continue to consider and evaluate acquisitions of, or significant investments in, complementary businesses and assets. Any acquisition that Trican completes could have unforeseen


and potentially material adverse effects on the Company’s financial position and operating results.

Acquisitions involve numerous risks, including:n unanticipated costs and liabilities;

ndifficulty of integrating the operations and assets of the acquired business;

n the ability to properly access and maintain an effective internal control environment over an acquired company;

n potential loss of key employees and customers of the acquired company; and

n an increase in expenses and working capital requirements.

Trican may incur substantial indebtedness to finance acquisitions and also may issue equity securities in connection with any such acquisitions. Trican will be required to meet certain financial covenants in order to borrow money under its credit agreements to fund acquisitions. Debt service requirements could represent a significant burden on the Company’s results of operations and financial condition and the issuance of additional equity could be dilutive to shareholders. Acquisitions could also divert the attention of management and other employees from Trican’s day-to-day operations and the development of new business opportunities. In addition, Trican may not be able to continue to identify attractive acquisition opportunities or successfully acquire identified targets. Even if the Company is successful in integrating its recent or future acquisitions into its existing operations, it may not derive the benefits, such as operational or administrative synergies, that it expected from such acquisitions.

Failure to adequately protect its intellectual property could adversely impact Trican’s business. When providing services, Trican relies on trade secrets and know-how to maintain its competitive position and where possible, it undertakes to protect its intellectual property by applying for patent protection. Trican’s business may be adversely affected if it fails to obtain patents, its patents are unenforceable, the claims allowed under its patents are not sufficient to protect its technology or its trade secrets are not adequately protected. Trican’s competitors may be able to develop similar technology independently without infringing on its patents or gaining access to its trade secrets.

Furthermore, if any of its competitors obtain patents over valuable intellectual property, Trican may be unable to offer certain services in certain jurisdictions, may be forced to use less effective or costlier alternative technology, or required to enter into costly licensing agreements.

Trican’s business is affected by governmental regulations and policies. Trican’s operations, and those of its customers, are subject to a variety of federal, provincial, state and local laws, regulations and guidelines, including laws and regulations related to health and safety, the conduct of operations, the manufacture, management, transportation and disposal of certain materials used in its operations. Trican believes it is in compliance with such laws and regulations and has invested financial and managerial resources to ensure such compliance. Such expenditures historically have not been material to Trican. However, because such laws and regulations are subject to change it is impossible for Trican to predict the cost or impact of such laws and regulations on its future operations, nor their impact on its customers’ activities and thereby on the demand for its services.

Trican’s operations are subject to inherent hazards which may not be covered by insurance. Trican’s operations are subject to hazards inherent in the oil and gas service industry, such as equipment defects, damage, loss, malfunctions and failures, and natural disasters which may result in fires, vehicle accidents, explosions and uncontrollable flows of natural gas or well fluids that can cause personal injury, loss of life, suspension of operations, damage to formations, damage to facilities, business interruptions, and damage to or destruction of property and equipment. These hazards could expose Trican to liability for personal injury, wrongful death, property damage and other environmental damages. Trican continuously monitors its activities for quality control and safety and maintains insurance coverage it believes to be adequate and customary in the industry. Additionally Trican seeks to obtain indemnification from its customers by contract for certain of the above risks. However, such insurance and indemnities may not be adequate to cover Trican’s liabilities and may not be available in the future at rates Trican considers reasonable and commercially justifiable. If the Company were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if the Company were to incur such liability at a time when it is not able to


obtain liability insurance, its business, financial condition, results of operations and cash flow could be materially adversely affected.

Compliance with various environmental laws, rules legislation and guidelines could impose greater costs on Trican’s business or lead to a decline in the demand for services. Participants in the well services industry are subject to various environmental laws and regulations. These laws and regulations primarily govern the manufacture, processing, importation, transportation, handling and disposal of certain materials used in Trican’s operations and may require extensive remediation or impose civil or criminal liability for violations. Trican’s customers are subject to similar laws and regulations, as well as limits on emissions into the air and discharges into surface and sub-surface waters.

Recent regulatory initiatives have been undertaken in various jurisdictions to address assertions that hydraulic fracturing processes use chemicals that could affect drinking water supplies. Legislation has been enacted in some jurisdictions, and is being proposed in others, that require the energy industry to publicly disclose the chemicals it mixes with the water and sand it pumps underground in the fracturing process. These actual and proposed legislative changes could lead to operational delays and increased operating costs. The adoption of any future federal or state laws or implementing regulations in Canada and/or the United States, or in other jurisdictions in which the Company carries on business, which impose reporting obligations on, or otherwise limit the hydraulic fracturing process could reduce demand for pressure pumping services or make it more difficult for the Company to provide fracturing services for natural gas and oil wells, and could affect the Company’s ability to utilize proprietary technological developments to compete effectively in the pressure pumping industry. This could have a material adverse impact on the Company’s financial position and operating results.

Stringent regulation of fracturing services could have a material adverse impact on the Company’s financial position and operating results.Trican is subject to increasingly stringent environmental laws and regulations, some of which may provide for strict liability for damages to natural resources or threats to public health or safety. While Trican maintains liability insurance, the insurance is subject to coverage limits and may exclude

coverage for damage resulting from environmental contamination. There can be no assurance that insurance will continue to be available to Trican on commercially reasonable terms, that the possible types of environmental liability will be covered by insurance or that the dollar amount of such liabilities will not exceed Trican’s policy limits. Even a partially insured claim, if successful and of sufficient magnitude, could have a material adverse effect on Trican’s business, results of operations and prospects.

Future regulatory developments could have the effect of reducing industry activity. Trican cannot predict the nature of the restrictions that may be imposed. Trican may be required to increase operating expenses or capital expenditures in order to comply with any new restrictions or regulations. Such expenditures could be material.

Failure to maintain Trican’s safety standards and record could lead to a decline in the demand for services. Standards for the prevention of incidents in the oil and gas industry are governed by service company safety policies and procedures, accepted industry safety practices, customer specific safety requirements and health and safety legislation. In order to ensure compliance, Trican has developed and implemented safety and training programs which it believes meet or exceed the applicable standards. A key factor considered by customers in retaining oilfield service providers is safety. Deterioration of Trican’s safety performance could result in a decline in the demand for Trican’s services and could have a material adverse effect on its revenues, cash flows and profitability.

Trican may be subject to litigation, contingent liabilities and potential unknown liabilities.From time to time, Trican is subject to costs and other effects of legal and administrative proceedings, settlements, reviews, claims and actions. Trican may in the future be involved in disputes with other parties which could result in litigation or other actions, proceedings or related matters.

Further there may be unknown liabilities assumed by Trican in relation to prior acquisitions or dispositions as well as environmental or tax issues. The discovery of any material liabilities could have an adverse effect on Trican’s financial condition and results.

The results of litigation or any other proceedings or related matters cannot be precisely predicted due to uncertainty as to the final outcome. Trican’s assessment of the likely


outcome of these matters is based on its judgement of a number of factors including past history, precedents, relevant financial and other evidence and facts specific to the matter as known at the time of the assessment.

Trican may be adversely impacted by a shortage of qualified personnel.

Trican requires highly skilled personnel to operate and provide technical services and support for its business. Competition for the personnel required for its businesses intensifies as activity increases. Trican’s ability to manage the costs associated with recruiting, training and retention of a highly skilled workforce could impact its business. In periods of high utilization it may become more difficult to find and retain qualified individuals. This could increase Trican’s costs or have other adverse effects on its operations.

There are certain risks associated with Trican’s dependence on third-party suppliers. Trican sources raw materials, such as oilfield cement, proppant, nitrogen, carbon dioxide and coiled tubing, from a variety of suppliers, most of whom are located in Canada, Russia and the United States. Alternate suppliers exist for all raw materials. The source and supply of materials has been consistent in the past; however, in periods of high industry activity, Trican has experienced periodic shortages of certain materials. Management maintains relationships with a number of suppliers in an attempt to mitigate this risk. However, if the current suppliers are unable to provide the necessary materials, or otherwise fail to deliver products in the quantities required, any resulting delays in the provision of services to Trican’s clients could have a material adverse effect on its results of operations and financial condition.

Merger and acquisition activity may reduce the demand for Trican’s services. Merger and acquisition activity in the oil and gas exploration and production sector may constrain demand for the Company’s services as customers focus on reorganizing the business prior to committing funds to exploration and development projects. Further, the acquiring company may have preferred supplier relationships with oilfield service providers other than Trican.

New technology could place Trican at a disadvantage versus competitors.The ability of the Company to meet customer demands in respect of performance and cost will depend upon

continuous improvements in operating equipment. There can be no assurance that the Company will be successful in its efforts in this regard or that it will have the resources available to meet this continuing demand. Failure by Trican to do so could have a material adverse effect on the Company’s business, financial condition, results of operation and cash flows. No assurances can be given that competitors will not achieve technological advantages over the Company.

Operations with independent third parties could create uncertainty.Trican conducts some operations whereby control may be shared with unaffiliated third parties. Although Trican currently has a controlling interest in such arrangements, differences in views among participants may result in delayed decisions or in failures to agree on major issues. Trican may enter into similar arrangements as we pursue additional opportunities. Although the Company has not been constrained by our participation in such arrangements to date, no assurance can be given that the actions or decisions of third parties will not affect our business in a way that hinders our operations.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Disclosure Controls and ProceduresAn evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures was conducted at December 31, 2011 by management under the supervision of the Chief Executive Officer (CEO) and Chief Financial Officer (CFO).

Based on this evaluation, the Company’s management have concluded that the Company’s disclosure controls and procedures, as defined in National Instrument 52-109, are designed to provide a reasonable level of assurance over disclosure of material information, and are effective as of December 31, 2011.

Management’s Report on Internal Control over Financial ReportingThe Company’s management, including the CEO and CFO, have assessed and evaluated the design and operating effectiveness of the Company’s internal control over financial reporting as defined in National Instrument 52-109 as of December 31, 2011. In making this assessment, the


Company used the criteria established by the Committee of Sponsoring Organizations (COSO) in the “Internal Control-Integrated Framework”. These criteria are in the areas of control environment, risk assessment, control activities, information and communication, and monitoring. The Company’s assessment included documentation, evaluation, and testing of its internal control over financial reporting. Based on this evaluation, the Company’s management concluded that the Company’s internal control over financial reporting are effective and provide reasonable assurance regarding the reliability of the Company’s financial reporting and its preparation of financial statements for external purposes in accordance with International Financial Reporting Standards, and are effective as of December 31, 2011.

Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, internal control over financial reporting determined to be effective can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect all misstatements.

Changes in Internal Controls over Financial Reporting during Q4There were no changes in the Company’s internal control over financial reporting during the last quarter of the year

ended December 31, 2011 that have materially affected or are reasonably likely to materially affect The Company’s internal control over financial reporting. The transition to International Financial Reporting Standards (IFRS) and the ongoing preparation of financial statements in accordance with IFRS did not materially change the Company’s internal control over financial reporting.

INTERNATIONAL FINANCIAL REPORTING STANDARDS UPDATE

Trican has prepared its December 31, 2011 Consolidated Financial Statements in accordance with IFRS 1, First-time Adoption of International Financial Reporting Standards, as issued by the IASB. Prior to 2011, Trican prepared its financial statements in accordance with Canadian GAAP. The adoption of IFRS has not had a material impact on Trican’s operations, strategic decisions, or internal controls.

Trican’s IFRS accounting policies are provided in Note 2 to the Consolidated Financial Statements. In addition, Note 24 to the Consolidated Financial Statements presents reconciliations between the Company’s 2010 previous GAAP results and the 2010 IFRS results and an explanation of how the transition from Canadian GAAP to IFRS has affected the Company’s financial position, financial performance and cash flows.

SELECTED ANNUAL INFORMATION

($thousands, except per share amounts and operational information) 2011 2010 2009**Revenue $2,309,647 $1,478,345 $811,488

Profit / (loss) for the year 338,636 150,362 (8,513)

Earnings / (loss) per share:

Basic 2.32 1.09 (0.07)

Diluted 2.30 1.09 (0.07)

Funds provided by operations* 558,811 320,028 38,819

Capital expenditures 578,457 261,266 45,867

Total assets 2,217,183 1,413,886 1,029,839

Total long-term financial liabilities 400,256 107,152 174,660

Shareholders’ equity 1,365,389 999,401 647,193

Average shares outstanding - Basic 145,805 137,400 125,616

Average shares outstanding - Diluted 147,085 138,571 125,616

Shares outstanding at year end 146,917 144,637 125,639

Dividend per share $0.10 $0.10 $0.10

* See first page of this report.** 2009 results have been presented in accordance with Canadian GAAP.


Operational Information2011 2010 2009

Canadian operations

Number of jobs completed 25,393 21,931 16,262

Revenue-per-job 49,964 38,733 25,153

United States operations


Revenue-per-job 146,457 115,740 86,416

Russian operations


Revenue-per-job 55,902 56,206 61,090

SUMMARY OF QUARTERLY RESULTS

($millions, except per share amounts, unaudited)

2011 2010

Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1Revenue 694.2 659.1 421.7 534.6 434.3 407.8 306.3 330.0

Profit for the period 114.9 111.3 30.1 82.4 55.6 53.3 8.9 32.5

Earnings per share

Basic 0.78 0.76 0.21 0.57 0.39 0.38 0.07 0.26

Diluted 0.78 0.75 0.21 0.56 0.38 0.38 0.06 0.26

2010 versus 2009 – Selected Annual Information2010 was a year of expansion for Trican, particularly in North America, and resulted in record revenue, operating income and net income for the Company worldwide. As the oil and gas industry began to emerge from the 2009 global economic recession, activity levels and demand for our services in Canada and the U.S. increased substantially. Horizontal drilling activity continued to increase in 2010 and resulted in high demand for North American pressure pumping services due to an increase in the number of fractures per well. In addition, the size of the fracturing treatments is generally larger than treatments for vertical wells, which leads to higher revenue-per-job. Our North American operations benefitted from these trends, which was evident in the strong 2010 operating results for our Canadian and U.S. regions.

Consolidated revenue for 2010 increased by 82% to $1.5 billion compared to 2009, and adjusted net income increased to $163.3 million from a loss of $8.1 million. Adjusted diluted net income per share increased to $1.18 from a loss of $0.07 and funds from operations increased to $331.7 million from $38.8 million compared to 2009.

Canadian operating results in 2010, when compared to 2009, benefitted from increased overall industry activity and, in particular, an increase in horizontal drilling and oil and liquids-rich gas directed activity. Higher activity levels led to increased demand for our services and provided opportunities for price increases. As a result, operating margins and profitability improved substantially from 2009.

U.S. operations gained from higher industry activity levels throughout 2010 as the rig count was up in all of our areas of operation. The growth of horizontal drilling led to steady demand for our services and provided opportunities for pricing increases throughout the year. 2010 was also a year of expansion for our U.S. operations as we added new bases in Oklahoma and Pennsylvania.

Activity levels in Russia were consistent with our expectations as revenue increased by 9% and job count increased by 19% compared to 2009. However, overall cost inflation was experienced throughout the year and contributed to a decline in operating margins relative to 2009.


Q4 – 2011n Consolidated revenue for the fourth quarter of 2011 was

$694.2 million, an increase of 60% compared to the fourth quarter of 2010. Consolidated net income increased by 107% to $114.9 million and diluted earnings per share increased to $0.78 compared to $0.38 for the same period in 2010.

n Our Canadian operations achieved record quarterly revenue of $417 million and operating income of $164.5 million during the fourth quarter of 2011. Canadian revenue increased by 63% and operating income increased by 51% compared to the fourth quarter of 2010. Canadian activity levels remained strong during the fourth quarter of 2011 and were led by oil and liquids-rich gas directed activity. Horizontal drilling activity also remained strong in Canada as 58% of wells drilled during the fourth quarter of 2011 were horizontal compared to 38% for the same period in the previous year.

n U.S. activity levels remained strong during the fourth quarter as U.S. rig count increased by 19% year-over-year and 3% sequentially. Strong activity levels contributed to record quarterly U.S. revenue of $216 million, an increase of 100% compared to the fourth quarter of 2010. U.S. pressure pumping demand continued to be driven by strong oil and liquids-rich gas and horizontal drilling activity. However, weak natural gas prices led to activity declines in our dry gas regions, which partially offset the increases in the oil and liquids-rich gas areas.

n Revenue from our international operations was $61.5 million in the fourth quarter of 2011, up 5% year-over-year but down 23% sequentially. Revenue and activity levels for our international operations were down sequentially, but consistent with overall expectations for the region. The sequential decrease in revenue and operating margins was caused by low utilization, which resulted from the completion of our Russian customers 2011 work programs and cold temperatures typically experienced near the end of the fourth quarter in Russia.

Q3 – 2011n Consolidated revenue for the third quarter of 2011 was

$659.1 million, an increase of 62% compared to the third quarter of 2010. Consolidated net income increased by 108% to $111.3 million and diluted earnings per share increased to $0.75 compared to $0.40 for the same period in 2010.

n Our Canadian operations achieved record quarterly revenue of $371.5 million and operating income of

$146.9 million during the third quarter of 2011. Revenue increased by 56% and operating income increased by 70% compared to the third quarter of 2010. Canadian operations benefitted from the continued strength of horizontal drilling and favourable weather conditions throughout most of the third quarter, which contributed to the 27% year-over-year increase in the number of active drilling rigs in Canada. Oil directed activity supplied most of the rig count increase and represented 70% of the active drilling rigs in Canada during the third quarter of 2011.

n Third quarter revenue of $207.3 million for our U.S. operations was 20% higher than the second quarter of 2011 and represented a new quarterly record for this region. Operating income was $54.5 million, an increase of 10% sequentially and 154% compared to the third quarter of 2010. Third quarter results for our operations in the oil and liquids-rich gas plays, including our Eagle Ford and Oklahoma bases, were strong and contributed to the sequential and year-over-year growth. Utilization levels in dry gas producing regions were also strong as our contractual positions mitigated the decrease in activity in the Barnett and Haynesville shales. Third quarter results were particularly strong for our Marcellus base, which services dry gas producing plays.

n Russian revenue was $80.3 million during the third quarter of 2011, which was a 13% year-over-year increase and a 1% sequential decrease. Activity levels met expectations for all service lines as customers executed on their 2011 work plans. Third quarter operating income for our Russian operations decreased to $8.1 million compared to $11.4 million in the third quarter of 2010 and $11.2 million in the second quarter 2011.

Q2 – 2011n Consolidated revenue for the second quarter of 2011

was $421.7 million, an increase of 38% compared to the second quarter of 2010. Consolidated net income increased by 237% to $30.1 million and diluted earnings per share increased to $0.21 compared to $0.06 for the same period in 2010.

n Record second quarter revenue of $167.8 million was achieved by our Canadian operations, which was 20% higher than the second quarter of 2010. Second quarter operating income of $31.3 million was also a new Canadian record and was 17% higher than same period in 2010. Canadian operations in the second quarter


benefitted from the growth of pad well project work, which is less prone to spring break-up conditions.

n U.S. operations second quarter revenue of $172.4 million was 20% higher than the first quarter of 2011 and represented a new quarterly record for this region. U.S. operating margins were 28.9% in the second quarter of 2011, which was a 150 basis point improvement sequentially and a 1,070 basis point improvement compared to the second quarter of 2010. Second quarter U.S. results benefitted from robust industry activity levels and our geographic and service line expansion initiatives started in 2010.

n During the second quarter, our U.S. head office was officially moved from Denton, Texas to Houston, Texas. This move brought us closer to many of our key U.S. customers.

n Russian revenue increased to $81.5 million, which was a 14% year over year increase and a 26% sequential increase. Second quarter operating margins for our Russian operations improved to 13.7% compared to 10.4% in the second quarter of 2010. Second quarter activity levels in Russia benefitted from improved weather conditions and allowed our customers to execute their 2011 work plans after delays experienced in the first quarter.

n On April 28, 2011, Trican closed the issuance of U.S.$250 million and CAD$60 million senior unsecured notes on a private placement basis (the “Private Placement”).

Q1 – 2011n Trican’s consolidated revenue for the first quarter of 2011

increased to $534 million, a 62% increase relative to the first quarter of 2010. Net income for the quarter was $82.4 million compared to $32.5 million for the same period in 2010. Diluted net income per share was $0.56 in the first quarter of 2011 versus diluted net income per share of $0.26 in the first quarter of 2010.

n Record first quarter revenue of $326.4 million was achieved by our Canadian operations, which was a 53% increase over the first quarter of 2010. Strong Canadian results continued to be influenced by the strength of horizontal drilling and the growth in oil and liquids-rich gas directed activity.

n Record quarterly revenue was also achieved by our U.S. operations during the first quarter of 2011. U.S. revenues increased to $143.6 million up 142% compared to the first quarter of 2010. Activity levels benefitted from

the first full quarter of operations for our base in the Marcellus region and the continued strength of horizontal drilling activity.

n Revenue in our Russian region increased 12% compared to the first quarter of 2010. Based on the results of the 2011 Russian contract tendering process, we expected activity levels to increase by approximately 7% relative to 2010. The year-over-year job count increase of 5% was slightly below this expectation due largely to warm weather experienced near the end of the first quarter that delayed certain jobs into the second quarter. Modest pricing increases were also achieved during the 2011 tendering process; however, operating margins in Russia remained consistent with the fourth quarter of 2010 due to cost inflation experienced in the region.

Q4 – 2010n Consolidated revenue for the fourth quarter increased

by 98% compared to the fourth quarter of 2009 and reflected a strong operating environment in North America and activity levels in Russia that were consistent with expectations.

n Revenue in Canada increased by 110% compared to the fourth quarter of 2009 and 13% compared to the third quarter of 2010. Canadian operating results continued to benefit from the strong horizontal drilling and oil and liquids-rich gas activity. Price increases of 20% compared to the fourth quarter of 2009 and 5% compared to the third quarter of 2010 contributed to improved operating margins both sequentially and year-over-year for our Canadian operation.

n Revenue in the U.S. increased by 193% year-over-year and 8% on a sequential basis. Our U.S. operations benefitted from the growth in horizontal drilling and the opening of a new base operating out of the Marcellus play. Fourth quarter operating margins were down slightly compared to the third quarter of 2010 as our ability to increase pricing was limited due to the fixed term nature of certain contracts. Costs associated with start-up activities in the Marcellus and cost increases for key inputs also had a negative impact on fourth quarter margins in the U.S.

n Activity levels for our Russian operations were consistent with expectations as revenue increased 5% compared to the fourth quarter of 2009. Sequential revenue declined by 17% due to the decreased activity caused by typical seasonal slowdowns and the completion of the 2010 work contracts. Operating margins for our Russian operations


were negatively impacted by significant cost inflation, particularly related to fracturing proppant chemicals and equipment components.

Q3 – 2010n Our third quarter results continued to reflect a strong

operating environment in North America brought on by the continued growth of completions work performed on horizontal wells. Utilization levels continued to improve yielding opportunities for pricing improvements in Canada and the U.S.

n Revenue in Canada increased by 159% for the third quarter while operating income increased by 391% compared to the same period in 2009. This growth can be attributed to an 87% growth in active drilling rigs compared to 2009 as well as continued growth in the unconventional horizontal activity. The development of oil and liquids rich gas reservoirs also had a positive impact on overall activity levels in Canada as revenue from these plays was 45% of total revenue.

n Demand for fracturing services in the U.S. remained strong throughout the third quarter as revenue increased 200% over the same period in 2009 and 4% on a sequential basis. Continued strong demand provided opportunities for pricing increases resulting in higher operating margins.

n Russian revenue increased 11% over the same period in 2009. Sequential operating income improved due to favorable weather conditions throughout the summer resulting in lower fuel and maintenance costs. Margins remained lower than 2009 levels due to overall cost inflation experienced throughout the region combined with weak financial results in Algeria.

Q2 – 2010n Operating results for the second quarter of 2010

continued to improve with revenue 125% higher than the same period in 2009. Canadian and U.S. activity continued to increase while Russian operations were negatively impacted by cost inflation.

n Canadian revenue increased 198% for the quarter compared to the second quarter of 2009. As expected, second quarter results were impacted by spring break-up conditions; however, activity levels benefitted from the extension of first quarter completions work into the second quarter, increased year-ever-year activity in the Montney, Cardium and Viking regions, and more pad work, which is less prone to work stoppages from road bans.

n Revenue in the U.S. increased 183% compared to the same period in 2009, and 60% over the first quarter of 2010. The increase in revenue can be attributed to an increase in horizontal drilling as well as the Shawnee base being operational for the entire quarter.

n Second quarter Russian activity levels increased compared to the same period in 2009, resulting in a 28% increase in revenue. Although activity levels were high, cost inflation and service line mix resulted in lower than expected margins for our Russian operations.

Q1 – 2010n Operating results for the first quarter of 2010 reflect

improved operating conditions in Canada and the U.S., while Russia encountered smaller job sizes and unfavorable weather conditions.

n Revenue in Canada increased 42% compared to Q1 2009. Strong Canadian results for the quarter can be attributed to a rise in industry activity brought on by increased interest in unconventional plays and commodity price improvement.

n The U.S. experienced a 19% increase in rig count during the first quarter of 2010 yielding a 10% increase in revenue for our U.S. operations. In addition, an 8% pricing increase contributed to the significant improvement in operating margins. During Q1 we acquired $49 million of fracturing assets from a private U.S. company increasing our presence in the U.S. market.

n Russian operations were negatively impacted by the devaluation of the ruble relative to the Canadian dollar as well as smaller job sizes and reduced utilization due to unfavorable weather conditions. This resulted in an 8% decrease in revenue compared to the first quarter of 2009 as well as a decrease in operating margins.

NON-IFRS DISCLOSUREAdjusted net income, operating income and funds provided by operations do not have any standardized meaning as prescribed by IFRS and, therefore, are considered non-IFRS measures.

Adjusted net income and funds provided by operations have been reconciled to net income and operating income has been reconciled to gross profit, being the most directly comparable measures calculated in accordance with IFRS. The reconciling items have been presented net of tax.



(thousands; unaudited) Dec. 31, 2011

Dec. 31, 2010

Sept. 30, 2011

Dec. 31, 2011

Dec. 31, 2010

Adjusted net income $117,873 $58,823 $114,352 $351,014 $162,724

Deduct:

Non-cash share-based compensation expense 3,003 3,222 3,088 12,378 12,362

Net income (IFRS financial measure) $114,870 $55,601 $111,264 $338,636 $150,362



Dec. 31, 2010

Sept. 30, 2011

Dec. 31, 2011

Dec. 31, 2010

Funds provided by operations $181,916 $108,047 $174,284 $558,811 $320,028

Charges to income not involving cash

Depreciation and amortization 36,443 30,353 31,474 126,576 112,089

Stock-based compensation 3,003 3,222 3,088 12,378 12,362

Loss / (gain) on disposal of property and equipment 678 (129) (1,075) (369) (167)

Gain on revaluation of deferred consideration - - - - (22)

Unrealized foreign exchange (gain) / loss (2,273) - 98 (3,157) (880)

Income tax expense 44,805 20,750 46,434 139,531 58,876

Income tax paid (15,610) (1,750) (16,999) (54,784) (12,592)

Net income (IFRS financial measure) $114,870 $55,601 $111,264 $338,636 $150,362



Dec. 31, 2010

Sept. 30, 2011

Dec. 31, 2011

Dec. 31, 2010

Operating income $197,295 $109,721 $193,620 $614,524 $332,354

Add administrative expenses 25,398 23,652 25,814 102,514 73,860

Deduct depreciation expense (36,443) (30,353) (31,474) (126,576) (112,089)

Gross profit (IFRS financial measure) $186,250 $103,020 $187,960 $590,462 $294,125


n The company expects to submit tenders for contracts with customers in Saudi Arabia during 2012;

n the 2012 capital budget is expected to consist of $448 million in expansion capital, $89 million in infrastructure needed to support new and existing operations , and $45 million in maintenance capital;

n the 2012 capital program is expected to add significant additional revenue generating capacity to U.S. and Canadian operations;

n capacity for our U.S. operations is expected to increase by 142,500 of fracturing horsepower, 12 cement pumpers, 7 coiled tubing units, 9 nitrogen pumpers, and 10 acid pumpers during 2012;

n even with reductions to our capital budget, we still expect to have 712,500 of available U.S. fracturing horsepower by the end of the year;

n our 2012 capital budget is expected to increase U.S. fracturing capacity by 25% and significantly expand our non-fracturing service lines;

n expectations that strong demand for Canadian pressure pumping services will continue in 2012;

n oil and liquids -rich gas directed activity is expected to lead the increase in drilling activity in Canada in 2012;

n high demand in the oil and liquids-rich gas plays is expected to be partially offset in Canada by a decline in dry gas activity;

n gas prices are expected to remain weak;

n Canadian market is expected to continue to be dominated by oil and liquids-rich gas activity;

n expectations that strong demand will continue to be supported by the strength of horizontal drilling activity;

n expect the proportion of horizontal wells drilled in Canada to continue to increase in 2012 as a result of the favorable economics when compared to conventional wells;

n new play development in Canada is expected to support growth in the Canadian pressure pumping industry;

n expectations of increased activity in the Duvernay, Nordegg and Muskwa as the 2012 well count in these regions are expected to increase;

n expect an increase in revenue year-over-year as a result of increased capacity in connection with equipment built under our 2011 capital budget;

n 2012 builds are expected to be deployed to our Canadian operations throughout the second half of 2012;

n cost increases are expected during 2012 in the Canadian geographic region; however it is anticipated that pricing increases are expected to offset these increases keeping margins strong throughout 2012;

n relatively moderate expectations in regards to the growth in the U.S. market for 2012;

n expect rig count declines in dry gas areas, lower activity levels in these areas combined with movement of equipment and crews into oil and liquids-rich gas plays will negatively impact U.S. operations in the first quarter of 2012;

n expectation that U.S. activity will continue to grow due to growth in existing oil and liquids rich gas plays;

n expect our U.S. operations will benefit from substantial equipment growth in 2012;

n expectation that our U.S. results will benefit from a full year of availability of the equipment built in 2011;

n equipment from our 2012 capital budget is expected to be deployed to our U.S. operations throughout the second half of the year;

n intend to deploy the new equipment from our 2012 budget into oil and liquids-rich gas focused areas, which is expected to include new geographic regions for Trican;

FORWARD-LOOKING STATEMENTS

This document contains statements that constitute forward-looking statements within the meaning of applicable securities legislation. These forward-looking statements are identified by the use of terms and phrases such as “anticipate,” “achieve”, “achievable,” “believe,” “estimate,” “expect,” “intend”, “plan”, “planned”, and other similar terms and phrases. These statements speak only as of the date of this document and we do not undertake to publicly update these forward-looking statements except in accordance with applicable securities laws. These forward-looking statements include, among others:


n expect 2012 revenue to increase by approximately 10% compared to 2011 related to operations in Russia and Kazakhstan;

n 8% expected rise in activity, combined with a 2% expected increase in average revenue-per-job will result in increased revenue for our International operations;

n expected increase in average revenue-per-job;

n we expect a modest increase in operating margins in 2012, as a result of a shift in our work scope to higher margin jobs; customer interest in

horizontal completions and multi-stage fracturing is expected to increase in Russia during 2012;

n expect momentum to continue in 2012 in respect of several successful pilot projects completed in 2011;

n out 2012 strategy in Algeria will be to increase equipment utilization levels, which is expected to lead to improved profitability in the region;

n we expect to add to the current cementing fleet in Australia during 2012;

n do not expect the growth of the Australian operations to be

significant to our overall financial results during 2012;

n anticipate establishing a meaningful presence in the Australian market during the year;

n expectations that we will participate in pressure pumping tenders Saudi Arabia in 2012;

n the expectation that Trican can sustain strong earnings in the future and maximize shareholder value while remaining committed to investing in the growth of our existing operations and future growth opportunities.

Forward-looking statements are based on current expectations, estimates, projections and assumptions, which we believe are reasonable but which may prove to be incorrect and therefore such forward-looking statements should not be unduly relied upon. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: industry activity; the general stability of the economic and political environment; effect of market conditions on demand for the Company’s products and services; the ability to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability to operate its business in a safe, efficient and effective manner; the performance and characteristics of various business segments; the effect of current plans; the timing and costs of capital expenditures; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market its products and services.

Forward-looking statements are subject to a number of risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks and uncertainties include: 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. In addition, actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth under the section entitled “Business Risks” in this document.

Additional information regarding Trican including Trican’s most recent annual information form is available under Trican’s profile on SEDAR (www.sedar.com).


MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS

The management of Trican Well Service Ltd. is responsible for the preparation and integrity of the accompanying consolidated financial statements. The consolidated financial statements have been prepared in conformity with International Financial Reporting Standards and include amounts that are based on management’s informed judgments and estimates where necessary.

The Company maintains internal accounting control systems which are adequate to provide reasonable assurance that assets are safeguarded, transactions are executed in accordance with management’s authorization and accounting records are reliable as a basis for the preparation of the consolidated financial statement.

The Board of Directors, through its Audit Committee, monitors management’s financial and accounting policies and practices and the preparation of these financial

statements. The Audit Committee meets periodically with external auditors and management tor review the work of each and the propriety of the discharge of their responsibilities. Specifically, the Audit Committee reviews with management and the external auditors the financial statements and annual report of the Company prior to submission to the Board of Directors for final approval. The external auditors have full and free access to the Audit committee to discuss auditing and financial reporting matters.

The shareholders have appointed KPMG LLP as the external auditors of the Company and, in that capacity, they have examined the financial statements for the periods ended December 31, 2011. The Auditors’ Report to the shareholders is presented herein.

SIGNED “DALE M. DUSTERHOFT”DALE M. DUSTERHOFTCHIEF EXECUTIVE OFFICER

SIGNED “MICHAEL A. BALDWIN”MICHAEL A. BALDWINVICE PRESIDENT, FINANCE AND CHIEF FINANCIAL OFFICER

February 28, 2012


INDEPENDENT AUDITORS’ REPORT

To the Shareholders of Trican Well Service Ltd.

We have audited the accompanying consolidated financial statements of Trican Well Service Ltd., which comprise the consolidated statements of financial position as at December 31, 2011, December 31, 2010 and January 1, 2010, the consolidated statements of comprehensive income, changes in equity and cash flows for the years ended December 31, 2011 and December 31, 2010, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ ResponsibilityOur responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

OpinionIn our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Trican Well Service Ltd. as at December 31, 2011, December 31, 2010 and January 1, 2010, and its consolidated financial performance and its consolidated cash flows for the years ended December 31, 2011 and December 31, 2010 in accordance with International Financial Reporting Standards.

SIGNED “KPMG LLP”Chartered Accountants Calgary, Canada

February 28, 2012


CONSOLIDATED STATEMENT OF FINANCIAL POSITION

(Stated in thousands) December 31, 2011 December 31, 2010 January 1, 2010ASSETS

Current Assets

Cash and cash equivalents (note 4) $125,855 $81,058 $26,089

Trade and other receivables (note 5) 607,672 364,986 181,483

Current tax assets 1,553 6,046 -

Inventory (note 6) 173,515 106,607 91,197

Prepaid expenses 31,996 9,257 8,568

940,591 567,954 307,337

Property and equipment (note 7) 1,178,410 700,755 532,317

Intangible assets (note 8) 14,662 20,816 28,082

Deferred tax assets (note 15) 33,369 74,330 81,790

Other assets (note 9) 6,445 13,115 17,918

Goodwill (note 8) 43,706 36,916 36,916

$2,217,183 $1,413,886 $1,004,360

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities

Bank loans - - $27,997

Trade and other payables (note 11) 287,689 209,305 106,566

Contingent consideration (note 3) 2,867 - 1,882

Current tax liabilities 3,363 22 6,505

Current portion of loans and borrowings (note 10) 25,425 - -

319,344 209,327 142,950

Loans and borrowings (note 10) 400,256 107,152 176,918

Deferred tax liabilities (note 15) 132,031 98,006 45,809

Shareholders’ equity

Share capital (note 12) 529,062 486,594 246,854

Contributed surplus 45,894 42,919 32,811

Accumulated other comprehensive loss (note 12) (22,805) (19,273) -

Retained earnings 813,238 489,161 358,722

Total equity attributable to equity holders of the Company 1,365.389 999,401 638,387

Non-controlling interest 163 - 296

$2,217,183 $1,143,886 $1,004,360

Contractual obligations (note 19)Contingencies (note 22)See accompanying notes to the consolidated financial statements.


CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Stated in thousands, except per share amounts)

Year ended December 31 2011 2010

Revenue $2,309,647 $1,478,345

Cost of sales 1,719,185 1,184,220

Gross Profit 590,462 294,125

Administrative expenses 102,514 73,860

Other income (2,089) (886)

Results from operating activities 490,037 221,151

Finance income (3,896) (2,992)

Finance costs 20,041 9,332

Foreign exchange (gain) / loss (4,275) 5,573

Profit before income tax 478,167 209,238

Income tax expense (note 15) 139,531 58,876

Profit for the year $338,636 $150,362

Other comprehensive income

Unrealized loss on cash flow hedge (1,358) -

Foreign currency translation differences (2,219) (18,964)

Total comprehensive income for the year $335,059 $131,398

Profit / (loss) attributable to:

Owners of the Company 338,707 150,362

Non-controlling interest (71) -

Profit for the year $338,636 $150,362

Total comprehensive income attributable to:

Owners of the Company 335,175 131,418

Non-controlling interest (116) (20)

Total comprehensive income for the year $335,059 $131,398

Earnings per share (note 13)

Basic $2.32 $1.09

Diluted $2.30 $1.09

Weighted average shares outstanding - basic 145,805 137,400

Weighted average shares outstanding - diluted 147,085 138,571

See accompanying notes to the consolidated financial statements.


CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Stated in thousands)

Share capital

Contributed surplus

Accumulated other

comprehensive loss

Retained earnings Total

Non-controlling

interestTotal

equity

Balance at January 1, 2010 $246,854 $32,811 - $358,722 $638,387 $296 $638,683

Profit of loss for the year - - - 150,362 150,362 - 150,362

Foreign currency translation differences - - (19,273) - (19,273) - (19,273)

Dividends to equity shareholders ($0.10 per share) - - - (14,401) (14,401) - (14,401)

Share-based payments transactions - 12,361 - - 12,361 - 12,361

Share options exercised 16,267 (2,253) - - 14,014 - 14,014

Issuance out of treasury for deferred consideration 693 - - - 693 - 693

Issuance of shares 222,780 - - - 222,780 - 222,780

Acquisition of non-controlling interest - - - (5,522) (5,522) (296) (5,818)

Balance at December 31, 2010 $486,594 $42,919 $(19,273) $489,161 $999,401 - $999,401

Profit or loss for the year - - - 338,707 338,707 (71) 338,636

Foreign currency translation differences - - (2,174) - (2,174) (45) (2,219)

Dividends to equity shareholders ($0.10 per share) - - - (14,630) (14,630) - (14,630)

Share-based payments transactions - 12,378 - - 12,378 - 12,378

Share options exercised 42,468 (9,403) - - 33,065 - 33,065

Unrealized loss on cash flow hedge - - (1,358) - (1,358) - (1,358)

Investment in subsidiary - - - - - 279 279

Balance at December 31, 2011 $529,062 $45,894 $(22,805) $813,238 $1,365,389 $163 $1,365,552See accompanying notes to the consolidated financial statements.


CONSOLIDATED STATEMENT OF CASH FLOWS

(Stated in thousands)Year ended December 31, 2011 2010Cash provided by / (used in):Operations

Profit for the year $338,636 $150,362Charges to income not involving cash

Depreciation and amortization 126,576 112,089Amortization of debt issuance costs 375 -Equity settled share-based compensation 12,378 12,362Gain on disposal of property and equipment (369) (167)Net finance costs 16,145 6,340Gain on revaluation of deferred consideration - (22)Unrealized foreign exchange gain (3,157) (880)Income tax expense 139,531 58,876

630,115 338,960Change in inventory (67,225) (19,688)Change in trade and other receivables (232,628) (175,271)Change in prepaid expenses (21,995) (1,046)Change in trade and other payables 72,061 63,262

380,328 206,217Interest paid (17,454) (9,161)Income tax paid (54,784) (12,592)

308,090 184,464Investing

Interest received 1,851 2,598Purchase of property and equipment (578,457) (261,266)Proceeds from the sale of property and equipment 2,489 531Payments received on loan to an unrelated third party 6,175 5,336Business acquisitions (9,372) (5,818)

(577,314) (258,619)Financing

Net proceeds from issuance of share capital 33,065 230,167Repayment of bank loans - (28,093)Issuance (repayment) of long-term debt, net of financing fees 294,118 (59,638)Dividend paid (14,517) (13,453)

312,666 128,983Effect of exchange rate changes on cash 1,355 141

Increase in cash and cash equivalents 44,797 54,969Cash and cash equivalents, beginning of year 81,058 26,089Cash and cash equivalents, end of year $125,855 $81,058

See accompanying notes to the consolidated financial statements.


Nature of Business

Trican Well Service Ltd. (the “Company” or “Trican”) is an oilfield services company incorporated under the laws of the province of Alberta. These consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly owned, with the exception of Saudi Arabia, in which Trican has a 90% ownership (together referred to as the “Company”). The Company provides a comprehensive array of specialized products, equipment, services and technology for use in the drilling, completion, stimulation and reworking of oil and gas wells in Canada, U.S., and International operations, made up of Russia, Kazakhstan, Algeria, and Australia. The International operations also include Saudi Arabia where Trican is currently establishing its position in the region.

The consolidated financial statements of the Company as at and for the year ended December 31, 2009 and prior thereto were prepared under Canadian generally accepted accounting policies (Canadian GAAP).

Basis of Presentation

The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS). These are the Company’s first annual consolidated financial statements prepared in accordance with IFRS and IFRS 1 First-Time Adoption of International Financial Reporting Standards has been applied.

An explanation of how the transition to IFRS has affected the reported financial position, financial performance and cash flows of the Company is provided in note 24. This note includes reconciliations of equity and total comprehensive income for the comparative period and of equity at the date of transition reported under Canadian GAAP to those reported for those periods under IFRS.

The consolidated financial statements have been prepared on an historical costs basis except for financial instruments at fair value through profit or loss and liabilities for cash settled share based payment arrangements which are measured at fair value in the Statement of Financial Position.

The consolidated financial statements are presented in Canadian dollars and have been rounded to the nearest thousand, except where indicated.

Management is required to make estimates and assumptions that affect the application of accounting policies, reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reported period.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected.

Information about critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the consolidated financial statements is included in the following notes:

n Note 8 – impairment of intangible assets is evaluated using discounted future cash flows;

n Note 10 – present value of future minimum lease payments;

n Note 15 – the extent to which the deferred tax asset will be recognized; and

n Note 16 – fair value of cash flow hedges is determined using forward rates and is based on a future transaction.

These consolidated financial statements were approved by the Board of Directors on February 28, 2012.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2011 and 2010

NOTE 1 - NATURE OF BUSINESS AND BASIS OF PRESENTATION

NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES

The following is a summary of significant accounting policies used in the preparation of these consolidated financial statements and in preparing the opening IFRS balance sheet at January 1, 2010 for the purposes of the transition to IFRS, unless otherwise indicated.

Consolidation

Subsidiaries are entities controlled by the Company. The financial results of subsidiaries are included in the consolidated financial statements from the date that control


Buildings and improvements 20 years

Equipment 3 to 10 years

Furniture and fixtures 2 to 10 years

commences until the date that control ceases. All inter-company balances and transactions have been eliminated on consolidation.

Transaction costs, other than those associated with the issue of debt or equity securities, that the Company incurs in connection with a business combination are expensed as incurred.

Non-controlling interests in subsidiaries are identified separately from the Company’s equity therein. The interests of non-controlling shareholders may be initially measured either at fair value or at the non-controlling interests’ proportionate share of the fair value of the acquiree’s identifiable net assets. The choice of measurement basis is made on an acquisition-by-acquisition basis. Subsequent to acquisition, the carrying amount of non-controlling interests is the amount of those interests at initial recognition plus the non-controlling interests’ share of subsequent changes in equity. Total comprehensive income is attributed to non-controlling interests even if this results in the non-controlling interests having a deficit balance. Acquisitions of non-controlling interests are accounted for as transactions with equity holders in their capacity as equity holders and therefore no goodwill is recognized as a result of such transactions.

Cash and Short-Term DepositsThe Company’s short-term deposits with original maturities of three months or less are considered to be cash equivalents and are recorded at cost, which approximates fair market value. Bank overdrafts that are repayable on demand and form an integral part of the Company’s cash management are included as a component of cash and cash equivalents for the purpose of the statement of cash flows.

InventoryInventory is measured at the lower of cost and net realizable value. The cost of inventory is determined using the weighted average cost method. Inventory balances include all costs of purchase, costs of conversion and other costs incurred in bringing the inventory to its existing location and condition.

Net realizable value is the estimated selling prices in the ordinary course of business, less estimated costs of completion and selling expenses.

Property and EquipmentProperty and equipment are stated at cost less accumulated depreciation and accumulated impairment losses. Cost

includes expenditures that are directly attributable to the acquisition of the asset, and subsequent expenditure to the extent that they can be measured and future economic benefit is probable. The carrying values of replaced parts are derecognized when they are replaced. The cost of replacing a part of an item of property and equipment is recognized in the carrying amount of the item if it is probable that the future economic benefits embodied within the part will flow to the Company, and its cost can be measured reliably. Repairs and maintenance expenditures which do not extend the useful life of the property and equipment are expensed.

Management bases the estimate of the useful life and salvage value of property and equipment, with the exception of land which is not depreciated, on expected utilization, technological change and effectiveness of maintenance programs. When parts of an item of property or equipment have different useful lives, they are accounted for as separate items (major components) of property and equipment. Although management believes the estimated useful lives of the Company’s property and equipment are reasonable, it is possible that changes in estimates could occur which may affect the expected useful lives and salvage values of the property and equipment.

Gains and losses on disposal of an item of property and equipment are determined by comparing the proceeds from disposal with the carrying amount of property and equipment, and are recognized net within other income in profit or loss.

Depreciation is recognized in profit or loss on a straight-line basis over the estimated useful lives of each part of an item of property and equipment, since this most closely reflects the expected pattern of consumption of the future economic benefits embodied in the asset.

Leased assets are depreciated over the shorter of the lease term and their useful lives unless it is reasonably certain that the Company will obtain ownership by the end of the lease term.

Depreciation is calculated using the straight-line method over the estimated useful life less residual value of the asset as follows:


Depreciation methods, useful lives and residual values are reviewed each financial year end and adjusted if appropriate.

Impairment of Non Financial Assets

The carrying amounts of the Company’s non financial assets except inventory and deferred tax assets are reviewed at each reporting date to determine whether there is an indicator of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. The recoverable amount of goodwill and indefinite life assets is estimated yearly in the fourth quarter.

The recoverable amount of an asset or cash generating unit is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. For the purpose of impairment testing, assets that cannot be tested individually are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or other groups of assets (cash generating unit or CGU).

The Company’s corporate assets do not generate separate cash inflows. If there is an indication that a corporate asset may be impaired, then the recoverable amount is determined for the CGU to which the corporate asset belongs.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the unit on a pro rata basis. Impairment losses recognized in prior periods are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortization, if no impairment loss had been recognized.

Goodwill

Goodwill arises upon the acquisition of subsidiaries. For acquisitions on or after January 1, 2010, the Company measures goodwill as the fair value of the consideration

transferred including the recognized amount of any non-controlling interest in the acquiree, less the net recognized amount (generally fair value) of the identifiable assets acquired and liabilities assumed, all measured as of the acquisition date. As part of the transition to IFRS, the Company elected to restate only those business combinations that occurred on or after January 1, 2010. In respect of acquisitions prior to January 1, 2010, goodwill represents the amount recognized under Canadian GAAP.

Goodwill is allocated as of the date of the business combination to the Company’s cash generating units that are expected to benefit from the synergies of the business combination. Goodwill is not amortized, but is tested for impairment at least annually. An impairment loss in respect of goodwill is not reversed.

Intangible Assets

Non-compete agreements relate to the Company’s acquisitions and are recorded at their estimated fair value on the acquisition date and amortized on a straight line basis over 8 years.

Customer relationships relate to the Company’s acquisitions and are recorded at their estimated fair value on the acquisition date and amortized on a straight line basis over 5 years.

The “CBM Process” relates to an acquisition by the Company and was recorded at the estimated fair value on the acquisition date and amortized on a straight line basis over 10 years.

All amortization of intangible assets is charged to cost of sales in the consolidated Statement of Comprehensive Income.

Financial InstrumentsNon-Derivative Financial Assets

The Company initially recognizes loans and receivables and deposits on the date that they are originated. All other financial assets are recognized initially on the trade date at which the Company becomes a party to the contractual provisions of the instrument.

The Company derecognizes a financial asset when the contractual rights to the cash flows from the asset expire, or it transfers the rights to receive the contractual cash flows on the financial asset in a transaction in which substantially all the risks and rewards of ownership of the financial asset are transferred. Any interest in transferred financial assets that is created or retained by the Company is recognized as a separate asset or liability.


Loans and Receivables

Loans and receivables are financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, loans and receivables are measured at amortized cost using the effective interest rate method less any impairment losses.

Loans and receivables comprises cash and cash equivalents and trade and trade and other receivables.

Impairment of Financial Assets

The carrying amount of the Company’s financial assets include cash and cash equivalents, trade and other receivables, and a loan to an unrelated third party. A financial asset is impaired if there is objective evidence of impairment as a result of one or more events that occurred after the initial recognition of the asset, and that loss event had an impact on the estimated future cash flow resulting from that asset.

Evidence of impairment would include default or delinquency by a debtor, restructuring of an amount due to the Company on terms that the Company would not consider otherwise, indications that a debtor will enter bankruptcy, adverse changes in the payment status of borrowers or economic conditions that correlate with defaults.

The Company evaluates impairment for financial assets measured at amortized cost at both a specific asset and collective level. All individually significant assets are assessed for specific impairment annually. Assets that are not individually significant are collectively assessed for impairment by grouping together assets with similar risk profiles.

Impairment is assessed using historical trends of default, timing of recoveries and the amount of loss incurred, adjusted for management’s judgment in relation to how the current economic and credit environment will impact losses being greater or less than historical trends.

An impairment loss is determined as the difference between an assets’ carrying amount and the present value of future cash flows. Losses are recognized in profit or loss and reflected in an allowance account against loans and receivables. When an event occurring after the impairment was recognized causes the amount of impairment to decrease, the recovery is reversed through profit and loss.

Non-Derivative Financial Liabilities

Financial liabilities are recognized initially on the trade date at which the Company becomes a party to the contractual provisions of the instrument. Such financial liabilities are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition these financial liabilities are measured at amortized cost using the effective interest rate method, with the exception of contingent consideration which is stated at fair value, at each reporting period, net of transaction costs directly attributable to the issuance of the debt. Transaction costs related to the issuance of any long term debt are netted against the carrying value of the associated long term debt and amortized as part of financing costs over the life of the debt using the effective interest rate method.

The Company derecognizes a financial liability when its contractual obligations are discharged, cancelled or expire.

The Company has the following non-derivative financial liabilities: loans and borrowings, contingent consideration, and trade and other payables.

Financial assets and liabilities are offset and the net amount presented in the statement of financial position when, and only when, the Company has a legal right to offset the amounts and intends either to settle on a net basis or to realize the asset and settle the liability simultaneously.

Derivative Financial Instruments, Including Hedge Accounting

The Company holds derivative financial instruments to manage its exposure to the risk associated with fluctuations in foreign exchange and interest rates.

The Company has designated all cross currency swap agreements as cash flow hedges. The Company formally documents all relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking the hedge transaction. This process includes linking all derivatives that are designated in a cash flow hedging relationship to a specific firm commitment or forecasted transaction. The Company also formally assesses both at inception and at each reporting date, whether derivatives used in hedging transactions have been highly effective in offsetting changes in cash flows of hedged items and whether those derivatives may be expected to remain highly effective in future periods.

The Company calculates the fair value of the cash flow hedges using market forward rates reflecting the remaining term of the hedges at each reporting period. Under cash flow hedge accounting, the effective portion of the change


in the fair value of the hedging instrument is recognized in other comprehensive income (OCI) and presented within shareholders equity in accumulated other comprehensive income. The ineffective portion of the change in fair value is recognized in profit and loss. Upon maturity of the financial derivative instrument, the effective gains and losses previously accumulated in OCI within shareholders’ equity are recorded in profit and loss.

The Company utilizes foreign denominated long-term debt to hedge its exposure to changes in the carrying values of the Company’s net investment in certain foreign operations as a result of changes in foreign exchange rates.

Under the accounting for hedges of a net investment in foreign operations, the foreign denominated long-term debt must be designated and documented as a hedge, and must be effective at inception and on an ongoing basis. The documentation defines the relationship between the foreign denominated long-term debt and the net investment in the foreign operations. The Company formally assesses, both at inception and on an ongoing basis, whether the changes in fair value of the foreign denominated long-term debt is highly effective in offsetting changes in fair value of the net investment in the foreign operations. The portion of gains or losses on the hedging item that is determined to be an effective hedge is recognized in OCI, net of tax and is limited to the translation gain or loss on the net investment, while the ineffective portion is recorded in earnings.

If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated or exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. If the forecast transaction is no longer expected to occur, then the balance in shareholders’ equity is reclassified in profit or loss.

Common Shares

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any tax effects.

Provisions

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be reliably measured, and it is probable that an outflow of economic benefits will be required to settle the obligation.

Financial Risk Management

The Company has exposure to the following risks from its use of financial instruments:

n Market risk

n Credit risk

n Liquidity risk

Market Risk

Market risk is the risk that the fair value or future cash flows of financial assets or liabilities will fluctuate due to movements in market rates and is comprised of the following:

Interest Rate Risk

The Company partially mitigates its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt.

Foreign Exchange Rate Risk

As the Company operates primarily in North America and Russia, fluctuations in the exchange rate between the U.S. dollar/Canadian dollar and Russian ruble/Canadian dollar can have a significant effect on the operating results and the fair value or future cash flows of the Company’s financial assets and liabilities.

Canadian entities are exposed to currency risk on foreign currency denominated financial assets and liabilities with adjustments recognized as foreign exchange gains and/or losses in the profit and loss, except for items that are designated in a hedging relationship such as a portion of the US denominated debt.

Foreign entities with a domestic functional currency expose the Company to currency risk on the translation of these entities’ financial assets and liabilities to Canadian dollars for consolidation. For instance, the operations in Russia have a ruble functional currency, and adjustments arising when translating this foreign entity into Canadian dollars are reflected in the Consolidated Statement of Other Comprehensive Income as unrealized gains or losses on translating financial statements of foreign operations.

Foreign entities are exposed to currency risk on financial assets and liabilities denominated in currencies other than their functional currency with adjustments recognized in the profit and loss. For instance, the operations in Russia where the functional currency is the ruble will incur foreign exchange gains and/or losses on financial assets and liabilities denominated in currencies other than the ruble.

griffith

Underline

griffith

Underline


Credit Risk

Credit risk refers to the possibility that a customer or counterparty will fail to fulfill its obligations and as a result, create a financial loss for the Company.

Customer

The Company’s trade receivables are predominantly with customers who explore for and develop natural gas and petroleum reserves and are subject to normal industry credit risks that include fluctuations in oil and natural gas prices and the ability to secure adequate debt or equity financing. The Company assesses the credit worthiness of its customers on an ongoing basis as well as monitoring the amount and age of balances outstanding. Accordingly, the Company views the credit risks on these amounts as normal for the industry. The carrying amount of accounts receivable represents the maximum credit exposure on this balance.

Payment terms with customers vary by region and contract; however, standard payment terms are 30 days from invoice date. Historically, industry practice allows for payment up to 70 days from invoice date.

Counterparties

Counterparties to financial instruments expose the Company to credit losses in the event of non-performance. Counterparties to cash transactions are limited to high credit quality financial institutions. The Company does not anticipate non-performance that would materially impact the Company’s financial statements.

Liquidity risk

Liquidity risk is the risk the Company will encounter difficulties in meeting its financial liability obligations. The Company manages its liquidity risk through cash and debt management, which includes monitoring forecasts of the Company’s cash and cash equivalents and borrowing facilities on the basis of projected cash flow. This is generally carried out at the geographic region level in accordance with practices and policies established by the Company.

Revenue Recognition

The Company’s revenue comprises services and other revenue and is generally sold based on fixed or agreed upon priced purchase orders or contracts with the customer. Service and other revenue is recognized when the services are provided and collectability is reasonably assured. Customer contract terms do not include provisions for significant post-service delivery obligations.

Finance Income and Finance Costs

Finance income is made up of interest income on funds invested along with any fair value gains on financial assets at fair value through profit or loss. Interest income is recognized as it is accrued in profit or loss, using the effective interest rate method.

Finance costs are made up of interest expense on borrowings, fair value losses on financial assets through profit or loss, and impairment losses recognized on financial assets (other than trade receivables).

Borrowing costs that are not directly attributable to the acquisition, construction or production of a qualifying asset are recognized in profit or loss using the effective interest method.

Income TaxesThe Company uses the liability method of accounting for income taxes. Under the liability method, deferred income tax assets and liabilities are recognized as the difference between the carrying amounts of assets and liabilities and their respective income tax basis (temporary differences). A deferred tax asset may also be recognized for the benefit expected from unused tax losses available for carry forward, to the extent that it is probable that future taxable earnings will be available against which the tax losses can be applied.

Deferred income tax assets and liabilities are measured based on income tax rates and tax laws that are enacted or substantively enacted by the end of the reporting period and that are expected to apply in the years in which temporary differences are expected to be realized or settled. Deferred income tax assets are reviewed at each reporting period and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As such, income taxes are subject to measurement uncertainty and the interpretations can impact net earnings through the income tax expense arising from changes in deferred income tax assets or liabilities.

Foreign Currency Translation and Transactions

For foreign entities whose functional currency is the Canadian dollar, the Company translates monetary assets and liabilities at period-end exchange rates, and non-monetary items are translated at historical rates. Income and expense accounts are translated at the average rates


in effect during the period. Gains or losses from changes in exchange rates are recognized in the profit or loss in the period of occurrence. Foreign exchange gains or losses arising from a monetary item receivable from or payable to a foreign operation, the settlement of which is neither planned nor likely to occur in the foreseeable future and which in substance is considered to form part of the net investment in the foreign operation, are recognized in other comprehensive income in the cumulative amount of foreign currency translation differences.

For foreign entities whose functional currency is not the Canadian dollar, the Company translates assets, including goodwill, and liabilities at period-end rates and income and expense accounts at average exchange rates. Adjustments resulting from these translations are reflected in the Consolidated Statements of Other Comprehensive Income as unrealized gains or losses as foreign currency translation differences.

When a foreign operation is disposed of, the relevant amount in the cumulative amount of foreign currency translation differences is transferred to profit or loss as part of the profit or loss on disposal. On the partial disposal of a subsidiary that includes a foreign operation, the relevant proportion of such cumulative amount is reattributed to non-controlling interest. In any other partial disposal of a foreign operation, the relevant proportion is reclassified to profit or loss.

Employee BenefitsShort Term Employee Benefits

Short term employee benefit obligations are measured on an undiscounted basis and are expensed as the related service is provided. A liability is recognized for the amount expected to be paid under short term cash bonuses or profit sharing plans if the Company has a present legal or constructive obligation to pay this amount as a result of past service provided by the employee, and the obligation can be reliably estimated.

Share-Based Payment Transactions

The Company has a share option plan and accounts for share options by expensing the fair value of share options measured using a Black Scholes option pricing model. The fair value of the options is determined on their grant date and is recognized as administrative expense over the period that the share options vest, with a corresponding increase to contributed surplus. When share options are exercised, the proceeds together with the amount recorded as contributed surplus are recorded in share capital.

Cash-Settled Transactions

The Company has a deferred share unit (“DSU”) plan for its Directors. The DSUs vest immediately and the fair value of the liability and the corresponding expense is charged to profit or loss at the grant date. Subsequently at each reporting date between grant date and settlement date, the fair value of the liability is re-measured with any changes in fair value recognized in profit or loss for the period.

The Company has a restricted share unit (“RSU”) plan for its employees and the fair value of the RSU’s is expensed into profit and loss evenly over the same period that the units vest and at each reporting date between grant date and settlement, the fair value of the liability is re-measured with any changes in fair value recognized in profit or loss for the period.

The Company has a performance share unit (“PSU”) plan for Executive Officers of the Company. Under the terms of the plan, the PSU’s vest when the Company meets a certain financial target and expire on a date no later than December 31 of the third calendar year following the calendar year in which the grant occurs. Management makes an assessment for each grant of units on how likely and when the PSU’s might vest. The fair value of the units is expensed over the period until it is estimated that the vesting conditions will be met.

Earnings per Share

Basic earnings per share is calculated using the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated based on the weighted average number of shares issued and outstanding during the year, adjusted by the total of the additional common shares that would have been issued assuming exercise of all share options with exercise prices at or below the average market price for the year, offset by the reduction in common shares that would be purchased with the exercise proceeds.

Segment Reporting

An operating segment is a component of the Company that engages in business activities from which it may earn revenues and incur expenses. All operating results are reviewed regularly on a segmented basis by the Company’s CEO to make decisions about resources to be allocated to the segment and assess its performance, and for which discrete financial information is available.

Segment results that are reported to the CEO include items directly attributable to a segment as well as those that


can be allocated on a reasonable basis. Unallocated items comprise mainly corporate assets, head office expenses and public company costs.

Leased AssetsLeases which the Company assumes substantially all the risks and rewards of ownership are classified as finance leases. Upon initial recognition the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset. Minimum lease payments made under finance leases are apportioned between the finance expense and the reduction of the outstanding liability. The finance expense is allocated to each period during the lease term so as to produce a constant periodic rate of interest on the remaining balance of the liability. Other leases are operating leases and are not recognized in the Company’s statement of financial position. Payments made under operating leases are recognized in profit or loss on a straight-line basis over the term of the lease.

New Standards and Interpretations not yet Adopted

A number of new standards and amendments to standards and interpretations are not yet effective for the year ended December 31, 2011 and have not been applied in preparing these consolidated financial statements. None of these are expected to have a significant effect on the consolidated financial statements of the Company, except for IFRS 13 Fair Value Measurements, which becomes mandatory for the Company’s 2013 consolidated financial. The extent of the impact has not been determined.

All accounting standards effective for periods beginning on or after January 1, 2011 have been adopted as part of the transition to IFRS. The following new IFRS pronouncements have been issued but are not in effect as at December 31, 2011. However, the pronouncements may have a future impact on the measurement and/or presentation of the Company’s financial statements:

As of January 1, 2015, Trican will be required to adopt IFRS 9, Financial Instruments, which is the result of the first phase of the IASB’s project to replace IAS 39, Financial Instruments: Recognition and Measurement. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that

has only two classification categories: amortized cost and fair value. The adoption of this standard is currently not expected to have a material impact on Trican’s Consolidated Financial Statements.

In May 2011, the IASB issued four new standards, and revised two existing standards. All of the new standards are effective for annual periods beginning on or after January 1, 2013.

IFRS 10, Consolidated Financial Statements, introduces new principle-based definition of control, applicable to all investees to determine the scope of consolidation. The standard provides the framework for consolidated financial statements and their preparation based on the principle of control.

IFRS 11, Joint Arrangements, replaces IAS 31 Interests in Joint Ventures. IFRS 11 divides joint arrangements into two types, each having its own accounting model. A ‘joint operation’ continues to be accounted for using proportional consolidation, where as a ‘joint venture’ must be accounted for using equity accounting.

IFRS 12, Disclosure of Interests in Other Entities, is a new standard which combines all of the disclosure requirements for subsidiaries, associates and joint arrangements in order to provide information related to the risks associated with an entities interest in other entities, and the effects of those interests on the entity’s financial positions, financial performance and cash flows.

IFRS 13, Fair Value Measurement, is a new standard meant to clarify the definition of fair value, provide guidance on measuring fair value and improve disclosure requirements related to fair value measurement.

IAS 27, Separate Financial Statements, was revised with the issuance of IFRS 10, and prescribes the accounting and disclosure requirements for investments in subsidiaries, joint ventures and associates when an entity prepares separate financial statements.

IAS 28, Investments in Associates and Joint Ventures, was revised with the issuance of IFRS 10, 11 and 12 and the revision to IAS 27, and provides the framework for the application of the equity method when accounting for investments in associates and joint ventures.

The Company intends to adopt the amendments in its financial statements for the annual period beginning in the year applicable. The extent of the impact of adoption of the amendments has not yet been determined.


Effective July 8, 2011 Trican acquired all of the outstanding shares and units of Viking Energy Pty Ltd., Viking Energy PNG, Viking Energy Unit Trust, and Thor Laboratories Pty Ltd. (collectively “Viking”) for a purchase price of $12.1 million, which includes a $2.8 million performance contingency payment. All of Viking’s earnings have been included in Trican’s consolidated statement of comprehensive income since July 8, 2011. Since acquisition, Viking has contributed

revenue of $4.4 million and a loss for the period of $1.5 million. If the acquisition had occurred on January 1, 2011, management estimates that revenue would have been $8.8 million and the loss for the year would have been $2.0 million. Costs related to the acquisition have been expensed into the consolidated statement of comprehensive income as incurred.

The acquisition has been accounted for as follows:

(Stated in thousands)Acquired net assets:

Property and equipment $5,495

Goodwill 6,551

Current assets acquired 1,360

Current liabilities acquired (1,267)

$12,139

Financed as follows:

Cash $9,372

Contingent Consideration 2,767

$12,139

The goodwill is attributable mainly to the skills and talent of Viking’s workforce and the synergies expected to be achieved with the integration of Viking into the Company’s existing well service operations. None of the goodwill recognized is expected to be deducted for tax purposes.

(Stated in thousands) December 31, 2011 December 31, 2010 January 1, 2010Bank balances $125,825 $81,058 $26,089

Short-term deposits 30 - -

Cash and cash equivalents in the statement of cash flows $125,855 $81,058 $26,089

NOTE 5 - TRADE AND OTHER RECEIVABLES

(Stated in thousands) December 31, 2011 December 31, 2010 January 1, 2010Trade receivables $595,141 $344,800 $173,697

Loans and other receivables 18,078 31,917 20,185

Total 613,219 376,717 193,882

Non-current (note 9) 5,547 11,731 12,399

Current $607,672 $364,986 $181,483

NOTE 4 - CASH AND CASH EQUIVALENTS

NOTE 3 – BUSINESS COMBINATIONS


NOTE 6 - INVENTORY

(Stated in thousands) December 31, 2011 December 31, 2010 January 1, 2010Product inventory

Chemicals and consumables $73,376 $53,409 43,292

Coiled tubing 21,310 12,860 14,847

Parts 78,829 40,338 33,058

$173,515 $106,607 $91,197

The total amount of inventory recognized as cost of sales during the year was $676.5 million (2010 – $476.2 million). There were no significant write-downs of inventory during the year-ended December 31, 2011 (2010 – nil).

NOTE 7 - PROPERTY AND EQUIPMENT

(Stated in thousands)Land and buildings Equipment

Fixtures and fittings Total

CostBalance at January 1, 2010 $70,991 $744,580 $27,303 $842,874Additions 11,949 267,534 4,777 284,260Disposals - (26,432) - (26,432)Effect of movements in exchange rates (940) (20,025) (55) (21,020)Balance at December 31, 2010 $82,000 $965,657 $32,025 $1,079,682

Additions 17,026 573,857 6,009 596,892Acquisitions through business combinations - 5,495 - 5,495Disposals - (28,711) - (28,711)Effect of movements in exchange rates 74 2,498 (11) 2,561Balance at December 31, 2011 $99,100 $1,518,796 $38,023 $1,655,919

Accumulated DepreciationBalance at January 1, 2010 $12,025 $282,112 $16,420 $310,557Depreciation 3,833 98,040 3,709 105,582Disposals - (29,986) - (29,986)Effect of movements in exchange rates (238) (6,955) (33) (7,226)Balance at December 31, 2010 $15,620 $343,211 $20,096 $378,927

Depreciation 3,355 112,850 5,386 121,591Disposals - (20,848) - (20,848)Effect of movements in exchange rates (48) (2,094) (19) (2,161)Balance at December 31, 2011 $18,927 $433,119 $25,463 $477,509

Carrying amountsAt January 1, 2010 58,966 462,468 10,883 532,317At December 31, 2010 66,380 622,446 11,929 700,755At December 31, 2011 80,173 1,085,677 12,560 1,178,410

Included within equipment are assets held under finance lease with a gross value of $35.2 million (2010 - $19.5 million) and accumulated depreciation of $9.4 million (2010 - $6.2 million). The lease obligations are secured by the leased equipment.


NOTE 8 - INTANGIBLE ASSETS AND GOODWILL

(Stated in thousands) GoodwillNon-compete

agreementsCustomer

relationships CBM process TotalCostBalance at January 1, 2010 $36,916 $24,074 $13,596 $8,503 $83,089Effect of movements in exchange rates - (1,087) (442) - (1,529)Balance at December 31, 2010 $36,916 $22,987 $13,154 $8,503 $81,560

-

Acquisitions through business combinations 6,551 - - - 6,551Effect of movements in exchange rates 239 468 191 - 898Balance at December 31, 2011 $43,706 $23,455 $13,345 $8,503 $89,009

Amortization and impairment lossesBalance at January 1, 2010 - $8,275 $7,478 $2,338 $18,091Amortization - 2,966 2,691 850 6,507Effect of movements in exchange rates - (466) (303) - (769)Balance at December 31, 2010 - $10,775 $9,866 $3,188 $23,829

Amortization - 2,859 2,620 850 6,331Effect of movements in exchange rates - 293 190 - 482Balance at December 31, 2011 - $13,927 $12,676 $4,038 $30,642

Carrying amountsAt January 1, 2010 $36,916 $15,799 $6,118 $6,165 $64,998At December 31, 2010 $36,916 $12,212 $3,288 $5,315 $57,732At December 31, 2011 $43,706 $9,528 $699 $4,465 $58,368

For the purposes of impairment testing, goodwill is allocated to he Company’s geographic segments. The aggregate carrying amount of goodwill allocated to each region is as follows:.

(Stated in thousands) December 31, 2011 December 31, 2010 January 1, 2010Canada $22,690 $22,690 $22,690International 21,016 14,226 14,226

$43,706 $36,916 $36,916

The recoverable amount was determined by discounting the future cash flows to be generated from the continuing operations of each geographic region. For both the Canadian and International operations the recoverable amount was in excess of the carrying amount attributable to each region. No impairment was recorded relating to the years ended December 31, 2011 and 2010.

NOTE 9 - OTHER ASSETS

At December 31, 2011, the Company had a U.S.$12.9 million secured, interest bearing first mortgage real estate loan (the “loan”) to an unrelated third party located in the U.S. (2010 – U.S.$19.2 million).

The non-current portion of the loan of U.S.$5.5 million (2010 - U.S.$11.8 million) has been included in other assets, along with miscellaneous other assets, on the statement of financial position. The current portion of the loan of U.S.$7.4 million (2010 - U.S. $7.4 million) has been included in trade and other receivables on the statement of financial position.


NOTE 10 - LOANS AND BORROWINGS

Bank Loans

The Company’s Russian subsidiary has a U.S.$20 million (Canadian equivalent of $20.3 million) demand revolving facility with a large international bank. This facility is

unsecured, bears interest at LIBOR plus a premium, as determined by the bank, plus 2.75% and has been guaranteed by the Company. As at December 31, 2011 there was nothing drawn on this facility (December 31, 2010, nil).

(Stated in thousands) December 31, 2011 December 31, 2010 January 1, 2010Notes payable $412,646 $99,460 $104,660

Finance lease obligations 26,766 11,753 4,694

Equipment and acquisitions loan - - 70,000

Revolving credit facility - - -

Hedge receivable (4,903) - -

Total $434,509 $111,213 179,354

Current portion of finance lease obligations (1) 8,828 4,061 2,436

Current portion of long-term debt 25,425 - -

Non-current $400,256 $107,152 $176,918

(1) Current portion of finance lease obligations is included in trade and other payables.

Long-Term Debt

On October 18, 2011, Trican entered into a new $450 million four year extendible revolving credit facility (the “New Facility”) with a syndicate of banks. The New Facility, which replaced the previous $250 million three year extendible facility, is unsecured and bears interest at the applicable Canadian prime rate, U.S. prime rate, Banker’s Acceptance rate or at LIBOR plus 50 to 325 basis points, dependent on certain financial ratios of the Company. The New Facility requires Trican to comply with certain financial and non-financial covenants that are typical for this type of arrangement.

During the first quarter of 2011, the Company replaced its existing Revolving Credit Facility with a new syndicated CAD $250 million three year extendible Revolving Credit Facility. This facility was unsecured and bore interest at Canadian prime rate, U.S. prime rate, Banker’s Acceptance rate or at LIBOR plus 125 to 375 basis points, dependent on certain financial ratios of the Company. This facility was replaced by the New Facility, as discussed above.

Notes Payable

On April 28, 2011 the Company closed a private placement of Senior Unsecured Notes (the “Notes”) that will rank equally with the Company’s bank facilities and other outstanding senior notes. The following outlines the terms of the new Notes:

n Canadian $45 million Series C Senior Notes maturing April 28, 2016, bearing interest at a fixed rate of 5.22% payable semi-annually on April 28 and October 28;

n Canadian $15 million Series D Senior Notes maturing April 28, 2021, bearing interest at a fixed rate of 6.11% payable semi-annually on April 28 and October 28;

n U.S. $65 million Series E Senior Notes maturing April 28, 2016, bearing interest at a fixed rate of 4.61% payable semi-annually on April 28 and October 28;

n U.S. $80 million Series F Senior Notes maturing April 28, 2018, bearing interest at a fixed rate of 5.29% payable semi-annually on April 28 and October 28; and

n U.S. $105 million Series G Senior Notes maturing April 28, 2021, bearing interest at a fixed rate of 5.90% payable semi-annually on April 28 and October 28.

On June 21, 2007, the Company entered into an agreement with institutional investors in the U.S. providing for the issuance, by way of private placement of U.S. $100 million of Senior Unsecured Notes (the “Notes”) in two tranches:

n U.S. $25 Million Series A Senior Notes maturing June 22, 2012, bearing interest at a fixed rate of 6.02% payable semi-annually on June 22 and December 22; and


n U.S. $75 Million Series B Senior Notes maturing June 22, 2014, bearing interest at a fixed rate of 6.10% payable semi-annually on June 22 and December 22

The Notes require the Company to comply with certain financial and non-financial covenants that are typical for this type of arrangement. At December 31, 2011, the Company was in compliance with these covenants.


December 31,

Total future minimum

lease payments

2011

Interest payments

2011

Minimum lease

payments

2011

Total future minimum lease

payments

2010

Interest payments

2010

Minimum lease payments

2010Less than one year 9,641 813 8,828 2,957 521 2,436Between one and five years 18,727 789 17,938 9,876 559 9,317More than five years - - - - - -Total 28,368 1,602 26,766 12,833 1,080 11,753

Finance Lease Liabilities

NOTE 11 - TRADE AND OTHER PAYABLES

(Stated in thousands) December 31, 2011 December 31, 2010 January 1, 2010Trade payables 167,692 129,252, 72,292Accrued liabilities 78,693 54,678 13,629Dividend payable 7,346 7,232 6,282Finance lease obligations 8,828 4,061 2,436Other payables 25,130 14,082 11,927Total trade and other payables 287,689 209,305 106,566

The Company’s exposure to currency and liquidity risk related to trade and other payables is disclosed in note 16.

NOTE 12 - SHARE CAPITAL AND ACCUMULATED OTHER COMPREHENSIVE LOSSShare CapitalAuthorized: The Company is authorized to issue an unlimited number of common and preferred shares, issuable in series. The shares have no par value. All issued shares are fully paid.

Issued and Outstanding - Common Shares

(stated in thousands, except share amounts) Number of shares AmountBalance, January 1, 2010 125,638,669 $246,854

Exercise of stock options 1,248,566 9,958

Reclassification from contributed surplus on exercise of options - 2,254

Fair value adjustment of stock options previously exercised - 4,054

Issuance of shares (net of issuance costs) (1) 17,698,500 222,781

Issuance out of treasury for CBM deferred consideration 50,848 693

Balance, December 31, 2010 144,636,583 $486,594

Exercise of stock options 2,280,276 333,280

Reclassification from contributed surplus on exercise of options - 9,188

Balance, December 31, 2011 146,916,859 $529,062(1) The tax impact of the issuance costs was $2.6 million.


Normal Course Issuer Bid

Subsequent to year end the Company has filed a Notice of Intention to make a Normal Course Issuer Bid (“NCIB”) with the Toronto Stock Exchange. Under the NCIB, the Company will be permitted to acquire up to approximately 12.7 million of its common shares during the period March 2, 2012 to March 1, 2013. All common shares purchased through the bid will be cancelled. A copy of the Notice of Intention to make a NCIB is available without charge on request to the Company’s Corporate Secretary.

Accumulated Other Comprehensive Loss

Foreign Currency Translation Differences

The foreign currency translation differences comprise all foreign currency differences arising from the translation of the financial statements of foreign operations, as well as the translation of the liabilities that hedge the Company’s net investment in a foreign operation.

Unrealized Gain on Cash Flow Hedge

The unrealized gain on cash flow hedge comprises the effective portion of the cumulative net change in the fair value of cash flow hedges related to hedged transactions that have not yet affected profit or loss.

NOTE 13 - EARNINGS PER SHARE

(Stated in thousands, except share and per share amounts)

For the year ended December 31, 2011 2010Basic income per share

Profit attributable to the owners of the Company $338,707 $150,362

Weighted average number of common shares 145,804,728 137,400,019

Basic earnings per share $2.32 $1.09

Diluted income per share

Profit attributable to the owners of the Company $338,707 $150,362

Weighted average number of common shares 145,804,728 137,400,019

Diluted effect of stock options 1,279,942 1,171,371

Diluted weighted average number of common shares 147,084,670 138,57,1,390

Diluted earnings per share $2.30 $1.09

At December 31, 2011, 1.5 million (2010 - 5.5 million) options were excluded from the diluted weighted average number of ordinary shares calculation as their effect would have been anti-dilutive.

NOTE 14 - SHARE-BASED PAYMENTS

The Company has four stock-based compensation plans which are described below.

Incentive Stock Option Plan (Equity-Settled):

Options may be granted at the discretion of the Board of Directors and all officers and employees of the Company are eligible for participation in the Plan. The option price equals the volume weighted average closing price of the

Company’s shares on the Toronto Stock Exchange for the five trading days preceding the date of grant. Options granted prior to 2004 vest equally over a period of four years commencing on the first anniversary of the date of grant, and expire on the fifth or tenth anniversary of the date of grant.

In 2004, the Company prospectively revised the stock option plan so that one-third of new options issued vest on each of the first and second anniversary dates, and the remaining third vest ten months subsequent to the second anniversary


date. These options expire on the third anniversary from the date of grant. In 2010, the Company prospectively revised the stock option plan so that one-third of new options issued vest on each of the first, second and third anniversary dates with an expiry date of 5 years from the date of the grant.

The compensation expense that has been recognized in profit for the year is $12.4 million (2010 - $12.4 million). The

corresponding amount has been recognized in contributed surplus. The weighted average grant date fair value of options granted during 2011 has been estimated at $7.04 per option (2010 - $5.32) using the Black-Scholes option pricing model. Expected volatility is estimated by considering historic average share price volatility. The Company has applied the following assumptions in determining the fair value of options for grants during the years ended:

For the year ended December 31, 2011 2010Share price $21.73 $15.06

Exercise price $21.73 $15.06

Expected life (years) 2.7 2.5

Expected volatility 47% 58%

Risk-free interest rate 2.0% 1.7%

Forfeitures 6.2% 10.9%

Dividend yield 0.5% 0.7%

The Company has reserved 14,691,686 common shares as at December 31, 2011 (December 31, 2010 – 14,463,658) for issuance under a stock option plan for officers and employees. The maximum number of options permitted to be outstanding at any point in time is limited to 10% of the Common Shares then outstanding. As of December 31, 2011,

5,672,506 options (December 31, 2010 – 6,700,864) were outstanding at prices ranging from $2.67 - $22.67 per share with expiry dates ranging from 2012 to 2016.

The following table provides a summary of the status of the Company’s stock option plan and changes during the years ending December 31:

2011 2010

OptionsWeighted average

exercise price OptionsWeighted average

exercise priceOutstanding at the beginning of the year 6,700,864 $14.55 6,163,159 $14.73

Granted 1,837,600 21.73 3,979,500 15.06

Exercised (2,280,276) 14.57 (1,248,566) 7.98

Forfeited (165,806) 17.82 (448,295) 16.63

Expired (419,876) 16.36 (1,744,934) 20.53

Outstanding at the end of the year 5,672,506 16.64 6,700,864 14.55

Exercisable at the end of the year 1,301,531 $8.53 1,967,883 $12.92

The weighted average share price for the year ended December 31, 2011 was $20.26 (2010 - $14.93).

The following table summarizes information about stock options outstanding at December 31, 2011:


Deferred Share Unit Plan (Cash-Settled):In 2004, the Company implemented a deferred share unit (“DSU”) plan for outside directors. Under the terms of the plan, DSU’s awarded will vest immediately and will be settled with cash in the amount equal to the closing price of the Company’s common shares on the date the director specifies upon tendering their resignation from the Board, which in any event must be after the date on which the notice of redemption is filed with the Company and within the period from the Director’s termination date to December 15 of the first calendar year commencing after the Director’s termination date. There were 221,996 DSU’s outstanding at December 31, 2011 (2010 – 215,779).

Restricted Share Unit Plan (Cash-Settled):In 2010, the Company introduced a restricted share unit (“RSU”) plan for employees. Under the terms of the plan, the RSU’s awarded will vest in three equal portions on the first, second and third anniversary of the grant date and will be settled in cash in the amount equal to the weighted volume average trading price for the twenty trading days preceding the particular vesting date of the award. The fair value of the RSU’s is expensed into income evenly over the same period that the units vest and at each reporting

date between grant date and settlement, the fair value of the liability is re-measured with any changes in fair value recognized in profit or loss for the period. All officers and employees of the Company are eligible for participation in the plan. There were 1,113,616 RSU’s outstanding at December 31, 2011 (2010- 501,300).

Performance Share Unit Plan (Cash-Settled):

In 2010, the Company introduced a performance share unit (“PSU”) plan for Executive Officers of the Company. Under the terms of the plan, the PSU’s vest when the Company meets a certain financial target and expire on a date no later than December 31 of the third calendar year following the calendar year in which the grant occurs. The performance share units will be settled in cash in the amount equal to the weighted volume average trading price for the five trading days preceding the particular vesting date of the Common Shares of the Company. Management has made an assessment on how likely and when the current PSU’s might vest and currently the fair value of the units are being expensed over the period until it is estimated that the vesting conditions will be met. There were 96,600 PSU’s outstanding at December 31, 2011 (2010- 198,640).

Options outstanding Options exercisable

Range of exercise pricesNumber

outstandingWeighted average

remaining lifeWeighted average

exercise priceNumber

exercisableWeighted average

exercisable price$2.67 to $4.00 224,250 0.46 3.82 224,250 2.82

$4.01 to $9.50 41,333 0.30 7.50 16,667 7.87

$9.51 to $19.20 3,601,198 3.25 15.05 1,055,614 15.09

$19.21 to $22.67 1,805,725 4.29 21.74 5,000 20.55

$2.67 - $22.67 5,672,506 3.45 16.64 1,301,531 8.53

(Stated in thousands)For the year ended December 31 2011 2010Stock based compensation expense $12,378 $12,362

Expense arising from DSU’s 20 1,910

Expense arising from RSU’s 8,768 5,565

Expense arising from PSU’s 1,414 3,605

Total expense related to share based payments $22,580 $23,442

Total liabilities for cash-settled arrangements $14,566 $13,375


NOTE 15 - INCOME TAXES

(Stated in thousands)For the year ended December 31, 2011 2010Current tax expense / (recovery)

Current year $62,088 $119Adjustment for prior years 876 (182)Recognition of previously unrecognized tax losses (370) -

$62,594 $(63)Deferred tax expense

Deferred tax expense recognized in the current year $76,827 $59,110Adjustment for prior years 110 (171)

$76,937 $58,939Total tax expense $139,531 $58,876

(Stated in thousands)For the year ended December 31, 2011 2010Deferred tax

Share issue costs - $(2,572)Total income tax recognized directly in equity - $(2,572)

Income Tax Recognized Directly in Equity

(Stated in thousands)For the year ended December 31, 2011 2010Current tax - -Deferred tax

Unrealized foreign exchange (3,931) 661Other - 30

Total income tax recognized in other comprehensive income $(3,931) $691

Income Tax Recognized in Other Comprehensive Income

(Stated in thousands)For the year ended December 31, 2011 2010Canada $361,007 $197,101Foreign 117,160 12,137

$478,167 $209,238

Profit Before Income Taxes and Non-Controlling Interest

The income tax expense differs from that expected by applying the combined federal and provincial income tax rate of 26.64% (2010 - 28.21%) to income before income taxes for the following reasons:

(Stated in thousands)For the year ended December 31, 2011 2010Expected combined federal and provincial income tax $127,384 $59,026Statutory and other rate differences 9,297 (2,410)Non-deductible expenses 8,434 6,346Translation of foreign subsidiaries 233 314Adjustments related to prior years 987 (354)Changes to deferred income tax rates (7,354) (4,448)Capital and other foreign tax 643 195Other (93) 207

$139,531 $58,876


(Stated in thousands)For the year ended December 31, 2011 2010Tax losses (capital in nature) $3,236 $1,851Tax losses (income in nature) 1,312 787

$4,548 $2,638

Unrecognized Deferred Tax AssetsDeferred tax assets have not been recognized in respect of the following items

The decrease in the statutory tax rate from 2010 to 2011 was mainly due to a reduction in the 2011 Canadian corporate

tax rates as part of a series of corporate tax rate reductions previously enacted by the Canadian Federal Government.

Deferred tax assets are recognized only to the extent that it is probable that the assets can be recovered. At December 31, 2011, the Company had $25.7 million (2010 - $14.7 million) of capital losses available for carry forward which may only

be used to offset future capital gains. The deferred tax asset not recognized in respect of these losses was $3.2 million (2010 - $1.9 million).

(Stated in thousands) December 31, 2011 December 31, 2010 January 1, 2010Deferred tax assets:

Goodwill $41,778 $43,337 $48,305Non-capital loss carry forwards 31,606 50,089 44,001Deferred financing costs 157 9,399 7,580Property, equipment and other assets (42,682) (29,352) (18,422)Other 2,510 857 326

$33,369 $74,330 $81,790Deferred tax liabilities

Property, equipment and other assets $(35,313) $(33,749) $(32,932)Partnership deferral (100,408) (66,547) (10,860)Other 3,690 2,290 (2,017)

$(132,031) $(98,006) $(45,809)

$(98,662) $(23,676) $35,891

Deferred Tax BalancesThe components of the deferred tax asset and liability are as follows:

Included in the above tax pools are $88.8 million (2010 - $135.8 million) of gross non-capital losses that can be carried forward to reduce taxable income in future years. These losses are predominantly in the United States and expire in 2029 and 2030. Deferred tax assets are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse, and a judgment as to whether or not there will be sufficient taxable profits

available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain.

Deferred tax liabilities of $5.2 million (2010 - $1.5 million) have not been recognized on the unremitted earnings of the Company’s foreign subsidiaries to the extent that the Company is able to control the timing of the reversal of the temporary differences, and it is probable that the temporary differences will not reverse in the foreseeable future.


Movement in Deferred Tax Balances During the Year

Jan. 1, 2010Recognized in

profit or loss

Recognized in other

comprehensive income

Recognized in shareholders’

equityForeign currency

translation Dec. 31, 2010Recognized in

profit or loss

Recognized in other

comprehensive income

Foreign currency

translation Dec. 31, 2011Goodwill $48,305 $(4,969) - - - $43,336 $(1,558)) - - $41,778

Non-capital loss carry forwards 44,001 6,089 - - - 50,090 (17,837) - - 32,253

Deferred financing costs 7,580 1,819 - - - 9,399 (9,242) - - 157

Property and equipment (51,354) (11,747) - - - (63,101) (14,894) - - (77,995)

Partnership deferral (10,860) (55,687) - - - (66,547) (33,861) - - (100,408)

Share issue costs 30 (520) - 2,572 - 2,082 (520) - - 1,562

Unrealized foreign exchange loss (3,270) - (661) - - (3,931) - 3,931 - -

Employee benefits 735 2,746 - - - 3,481 238 - - 3,719

Other 814 3,330 (30) - (2,599) 1,515 737 - (1,980) 272

$35,981 $(58,939) $(691) $2,572 $(2,599) $(23,676) $76,937) $3,931 $(1,980) $(98,662)


Fair Values of Financial Assets and Liabilities

The fair values of cash and cash equivalents, trade and other receivables, and trade and other payables included in the consolidated statement of financial position, approximates their carrying amount due to the short-term maturity of these instruments. The fair value of contingent consideration approximates its carrying value as it reflects the fair value at purchase.

Notes payable, including the current portion, have a fair value of approximately $435.5 million as at December 31, 2011 (December 31, 2010 - $105.8 million). The bank loans including the equipment and acquisition loan facility

approximate their carrying amount due to the variable interest rates applied to these loans and credit spreads on the facilities approximate market rates. The fair value of capital lease obligations was determined by calculating the future cash flows, including interest, using market rates. The fair value of the loan to an unrelated third party (described in note 9) has a fair value of $15.8 million (2010 - $23.8 million). The fair value was calculated using a discounted cash flow approach. The discount rate of 6.26% was estimated by assigning a credit rating to the third party and then an industrial yield curve for a time equal to the remaining life of the loan for secured debt using a relevant industrial composite.

(Stated in thousands)December 31,

Cash flow hedging

instrumentsLoans and

receivablesOther financial

liabilitiesTotal carrying

valueTotal fair

value

Cash and cash equivalents - $125,855 - $125,855 $125,855

Trade and other receivables - 607,672 - 607,372 607,672

Cash flow hedge 4,903 - - 4,903 4,903

$4,903 $733,527 - $738,430 $738,430

Trade and other payables - - $287,689 $287,689 $287,689

Contingent consideration - - 2,867 2,867 2,867

Notes payable - - 412,646 412,646 435,461

Finance lease obligations - - 26,766 26,766 28,368

- - $729,968 $729,968 $641,321

Fair Value versus Carrying Value Amounts

(Stated in thousands)December 31,

Loans and receivables

Other financial liabilities

Total carrying value

Total fair value

Cash and cash equivalents $81,058 - $81,058 $81,058

Trade and other receivables 364,986 - 364,986 364,986

$446,044 - $446,044 $446,044

Trade and other payables - $209,305 $209,305 $209,305

Notes payable - 99,460 99,460 105,790

Finance lease obligations - 11,753 11,753 12,833

- $320,518 $320,518 $326,453

NOTE 16 - FINANCIAL INSTRUMENTS


Market RiskMarket risk is the risk that the fair value or future cash flows of financial assets or liabilities will fluctuate due to movements in market rates and is comprised of the following:

Interest Rate RiskAn increase or decrease in interest expense for each one percent change in interest rates on floating rate debt would have been insignificant (2010 - $0.4 million) for the year ended December 31, 2011 based on the average debt balances for the year.

Foreign Exchange Rate RiskAs the Company operates primarily in North America and Russia, fluctuations in the exchange rate between the U.S.

dollar/Canadian dollar and Russian ruble/Canadian dollar can have a significant effect on the operating results and the fair value or future cash flows of the Company’s financial assets and liabilities.

The Company manages risk to foreign currency exposure by monitoring financial assets and liabilities denominated in foreign currency and foreign currency rates on an on-going basis. Exposures to the U.S. Dollar and Russian ruble are mitigated by on-going operations within foreign entities as assets, liabilities, revenue and expenses are denominated primarily in local currencies. The Company also mitigates exposure to fluctuations in the U.S. Dollar by maintaining a mix of both Canadian and U.S. dollar debt.

During the second quarter of 2011, Trican entered into two distinct hedges, each with the purpose of hedging the

Fair Values Hierarchy The table below analyses financial instruments carried at fair value, by valuation method. The different levels have been defined as follows:

n Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities;

n Level 2: inputs other than quoted prices included within level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices); or

n Level 3: inputs for the asset or liability that are not based on observable market data (unobservable inputs).

(Stated in thousands)December 31, 2011 Level 1 Level 2 Level 3 Total

Cash flow hedge - $4,903 - $4,903Loan to unrelated third party - 15,837 - 15,837Total assets - 20,740 - 20,740

Notes payable - 325,178 - 325,178Finance lease obligations 28,368 - - 28,368

Total liabilities $26,368 $325,178 - $353,546

(Stated in thousands)December 31, 2010 Level 1 Level 2 Level 3 Total

Loan to unrelated third party - $23,774 - $23,774

Total assets - $23,774 - $23,774

Notes payable - 105,790 - 105,790

Finance lease obligations 12,833 - - 12,833

Total liabilities $12,833 $105,790 - $118,623


gains and losses incurred on U.S. dollar debt balances. The first hedge consists of cross-currency swap agreements, which hedges U.S.$95 million of the U.S.$250 million private placement of senior unsecured notes (the “Notes”) which were issued during the quarter ended June 30, 2011. This hedge has been assessed as a highly effective cash-flow hedge. The foreign exchange loss on the hedged portion of the Notes has been recorded in other comprehensive income. The fair value of the cross-currency swap agreements at December 31, 2011 is $4.9 million and has been recorded net of long-term debt on the consolidated statement of financial position and as a gain in other comprehensive income. There was no tax impact recorded

in other comprehensive income related to the cross currency swap agreements.

The second hedge is a net investment hedge in foreign operations. The Company utilizes the foreign denominated long-term debt to hedge its exposure to changes in the carrying values of the Company’s net investment in its U.S. operations. At December 31, 2011 the hedge was highly effective resulting in no gains or losses recognized in profit or loss.

For the years ended December 31, 2011, fluctuations in the value of foreign currencies would have had the following impact on profit and other comprehensive income.

Impact to profit Impact to other comprehensive income

(Stated in thousands) 2011 2010 2011 2010

1% increase in the value of the U.S. dollar (2,265) (687) 389 1,404

1% decrease in the value of the U.S. dollar 2,265 687 (389) (1,404)

1% increase in the value of the Russian ruble 15 184 1,568 1,599

1% increase in the value of the Russian ruble (15) (184) (1,568) (1,599)

Credit RiskCredit risk refers to the possibility that a customer or counterparty will fail to fulfill its obligations and as a result, create a financial loss for the Company.

Customer

The Company’s accounts receivables are predominantly with customers who explore for and develop natural gas and petroleum reserves and are subject to normal industry credit risks that include fluctuations in oil and natural gas prices and the ability to secure adequate debt or equity financing. The Company assesses the credit worthiness of

its customers on an ongoing basis as well as monitoring the amount and age of balances outstanding. Accordingly, the Company views the credit risks on these amounts as normal for the industry. The carrying amount of accounts receivable represents the maximum credit exposure on this balance.

Payment terms with customers vary by region and contract; however, standard payment terms are 30 days from invoice date. Historically, industry practice allows for payment up to 70 days from invoice date. The Company considers its accounts receivable excluding doubtful accounts to be aged as follows:

(Stated in thousands) December 31, 2011 December 31, 2010 January 1, 2010

Current (0-30 days from invoice date) $234,420 $185,201 $106,413

1-30 days past due 221,635 116,394 49,106

31-60 days past due 94,924 33,643 13,090

Greater than 60 days past due 61,221 34,336 18,031

Total $612,200 $369,574 $186,640

Provision for doubtful accounts $4,528 $4,588 $5,157


(Stated in thousands)For the years ended December 31, 2011 2010Provision for doubtful accounts at January 1 $4,588 $5,157

Decrease in provision (60) (569)

Provision for doubtful accounts at December 31 $4,528 $4,588

Movement in Provision

The Company’s allowance for doubtful accounts decreased $0.1 million compared to December 31, 2010. The Company’s objectives, processes and policies for managing credit risk have not changed from the previous year.

Counterparties

Counterparties to financial instruments expose the Company to credit losses in the event of non-performance. Counterparties to cash transactions are limited to high credit quality financial institutions. The Company does not anticipate non-performance that would materially impact the Company’s financial statements.

Liquidity RiskLiquidity risk is the risk the Company will encounter difficulties in meeting its financial liability obligations. The Company manages its liquidity risk through cash and debt management, which includes monitoring forecasts of the Company’s cash and cash equivalents and borrowing

facilities on the basis of projected cash flow. This is generally carried out at the geographic region level in accordance with practices and policies established by the Company.

In managing liquidity risk, the Company has access to a wide range of funding at competitive rates through capital markets and banks. As at December 31, 2011, the Company had available unused committed bank credit facilities in the amount of $450.0 million (2010 - $250.0 million) plus cash and trade and other receivable of $125.9 million (2010 - $81.1 million) and $607.7 million (2010 - $364.5 million) respectively, for a total of $1,183.6 million (2010 - $696.1 million) available to fund the cash outflows relating to its financial liabilities. The Company believes it has sufficient funding through the use of these sources to meet foreseeable borrowing requirements.

The timing of cash outflows relating to financial liabilities are outlined in the table below:

(Stated in thousands)December 31, 2011

Carrying value

Less than 1 year

1 to 3 years

4 to 5 years

Greater than 5

years Total

Trade and other payables $278,860 $278,860 - - - $278,860Contingent consideration 2,867 2,867 - - - 2,867Notes payable 412,646 25,425 76,275 111,105 203,145 415,950Interest on notes payable - 22,335 40,814 31,136 38,932 133,217Finance lease obligations (including interest) 26,766 9,641 15,842 2,885 - 28,368

$339,128 $132,931 $145,126 $242,077 $859,262

(Stated in thousands)December 31, 2010

Carrying value

Less than 1 year

1 to 3 years

4 to 5 years

Greater than 5

years Total

Trade and other payables $209,305 $209,305 - - - $209,305Notes payable 99,460 - 24,865 74,595 - 99,460Interest on notes payable - 6,183 12,397 2,326 - 20,906Finance lease obligations (including interest) 11,753 2,957 6,580 3,296 - 12,833

$218,445 $43,842 $80,217 - $342,504


The Company’s strategy is to carry a capital base to maintain investor, creditor and market confidence and to sustain future development of the business. The Company seeks to maintain a balance between the level of long-term debt and shareholders’ equity to ensure access to capital markets to fund growth and working capital given the

cyclical nature of the oilfield services sector. On a historical basis, the Company maintained and continues to maintain a conservative ratio of long-term debt to total capitalization. The Company may occasionally need to increase these levels to facilitate acquisition or expansionary activities. These ratios were as follows:

(Stated in thousands, except ratios) December 31, 2011 December 31, 2010 January 1, 2010

Loans and borrowings $400,256 $107,152 $176,918

Shareholders’ equity 1,365,389 999,401 638,387

Total capitalization $1,765,645 $1,106,553 $815,305

Long-term debt to total capitalization 0.23 0.10 0.22

The Company is subject to various financial and non financial covenants associated with existing debt facilities. The covenants are monitored on a regular basis and controls

are in place to maintain compliance with these covenants. The Company complied with all financial covenants for the year ended December 31, 2011.

NOTE 18 - OPERATING LEASESThe Company has commitments for operating lease agreements, primarily for office space, with minimum payments due as of December 31, as follows:

(Stated in thousands) Within 1 year 1 to 5 years After 5 years Total2011 $6,211 $20,312 $607 $27,1302010 5,341 19,826 1,770 26,937

Lease payments recognized as an expense during the period amounted to $6.0 million (2010- $4.4 million).

NOTE 19 - CONTRACTUAL OBLIGATIONSAs at December 31, 2011, the Company has commitments totaling approximately $505.0 million (2010 - $97.5 million) relating to the construction of fixed assets in 2012.:

NOTE 20 - RELATED PARTY TRANSACTIONS

Transactions with Key Management PersonnelIn addition to their salaries, the Company also provides non-cash benefits to directors and executive officers. Executive officers also participate in the Company’s share option program and performance share unit program (see note 14). Key management personnel’s compensation is comprised of:

(Stated in thousands) 2011 2010Salaries $1,732 $1,265

Share-based awards 1,302 2,006

Option-based awards 1,128 6,785

Non-equity annual incentive plans 2,269 1,742

All other compensation 187 214

$6,618 $12,012

NOTE 17 - CAPITAL MANAGEMENT


The Company operates in Canada and the U.S. along with a number of international operations. The international regions include Russia, Algeria, Kazakhstan, Saudi Arabia and Australia. Each geographic region has a General Manager that is responsible for the operation and strategy of their region’s business. Personnel working within the particular geographic region report to the General Manager; the General Manager reports to the corporate executive.

The Company provides a comprehensive array of specialized products, equipment, services and technology to customers through three operating divisions:

n Canadian Operations provides cementing, fracturing, coiled tubing, nitrogen, geological, and acidizing services, which are performed on new and existing oil and gas wells, and industrial services.

n U.S. Operations provides cementing, fracturing, coiled tubing, nitrogen, and acidizing services which are performed on new and existing oil and gas wells.

n International Operations provides cementing, fracturing, coiled tubing, and nitrogen services which are performed on new and existing oil and gas wells.

Information regarding the results of each geographic region is included below. Performance is measured based on Revenue and Gross profit as included in the internal management reports which are reviewed by the Company’s executive management team. Each region’s Gross profit is used to measure performance as management believes that such information is most relevant in evaluating regional results relative to other entities that operate within the industry.


For the year ended December 31, 2011 Canadian operations

United States operations

International operations Corporate Total

Revenue $1,282,684 $738,916 $288,047 $- $2,309,647Gross profit / (loss) 448,895 150,311 13,923 (22,667) 590,462Finance income 3,624 178 94 - 3,896Finance costs - - - (20,041) (20,041)Tax expense 93,704 43,997 1,814 16 139,531Depreciation and amortization 47,687 54,274 23,935 680 126,576Assets 911,635 882,391 257,441 165,716 2,217,183Goodwill 22,690 - 21,016 - 43,706Property and equipment 505,781 573,548 88,287 10,794 1,178,410Capital expenditures 183,156 374,768 18,848 1,685 578,457Goodwill expenditures - - 6,551 - 6,551

Year ended December 31, 2010

Revenue $858,201 $361,055 $259,089 - $1,478,345

Gross profit / (loss) 263,667 38,417 7,729 (15,688) 294,125

Finance income 2,857 29 106 - 2,992

Finance costs - - - (9,332) (9,332)

Tax expense 53,844 4,303 611 118 58,876

Depreciation and amortization 47,243 38,182 26,470 194 112,089

Assets 587,747 460,905 263,106 102,128 1,413,886

Goodwill 22,690 - 14,226 - 36,916

Property and equipment 370,365 236,832 90,611 2,947 700,755

Capital expenditures 126,920 116,388 16,234 1,724 261,266

NOTE 21 - CONTRACTUAL OBLIGATIONS


The Corporate division does not represent an operating segment and is included for informational purposes only. Corporate division expenses consist of salary expenses, stock-based compensation and office costs related to corporate employees, as well as public company costs.

Revenue reported above represents revenue generated from external customers. There are no intersegment sales. Revenue from one external customer for the year ended December 31, 2011 amounted individually to greater than 10% of the Company’s total revenue. The customer’s revenue is exclusively within the U.S. and totals $359.7 million (2010 - $237.9 million).

(Stated in thousands)For the years ended December 31, 2011 2010Wages and salaries $160,094 $102,677

Government funded social programs 13,806 9,452

Equity-settled share-based transactions (note 14) 12,253 11,660

Cash-settled share-based transactions (note 14) 10,182 9,170

Total $196,335 $132,959

NOTE 23 - EMPLOYEE BENEFIT EXPENSE

NOTE 24 - EXPLANATION OF TRANSITION TO IFRS

As stated in note 1, these are the Company’s first annual consolidated financial statements prepared in accordance with IFRS. The accounting policies set out in note 2 have been applied in preparing the financial statements for the year ended December 31, 2011, the comparative information presented in these financial statements for the year ended December 31, 2010 and in the preparation of the opening IFRS balance sheet at January 1, 2010 (the Company’s date of transition).

In preparing the opening IFRS balance sheet, the Company has adjusted amounts reported previously in financial statements prepared in accordance with Canadian GAAP. An explanation of how the transition from previous Canadian GAAP to IFRS has affected the Company’s financial position, financial performance and cash flows is set out in the following tables and notes that accompany the tables.

Material Adjustments to the Statement of Cash Flows for 2010Consistent with the Company’s accounting policy choice under IAS 7, Statement of Cash Flows, interest paid and income taxes paid have moved into the body of the Statement of Cash Flows. There are no other material differences between the statement of cash flows presented under IFRS and the statement of cash flows presented under Canadian GAAP.

NOTES TO THE RECONCILIATIONSA - Business CombinationsThe Company elected not to restate business combinations that occurred before the date of transition to IFRS of January 1, 2010. During 2010, the Company increased its ownership

From time to time, Trican is subject to costs and other effects of legal and administrative proceedings, settlements, investigations, claims and actions. Trican may in the future be involved in disputes with other parties which could result in litigation or other actions, proceedings or related matters. The results of litigation or any other proceedings or related matters cannot be predicted with certainty. Amounts involved in such matters are not reasonably determinable due to uncertainty as to the final outcome. Trican’s assessment of the likely outcome of these matters is based on its judgment of a number of factors including experience with similar matters, past history, precedents, relevant

financial and other evidence and facts specific to the matter. Notwithstanding the uncertainty as to the final outcome, based upon the information currently available to it, Trican does not currently believe these matters in aggregate will have a material adverse effect on its consolidated financial position or results of operations.

The tax regulations and legislation in the various jurisdictions that the Company operates in are continually changing. As a result, there are usually some tax matters under review. Management believes that it has adequately met and provided for taxes based on the Company’s interpretation of the relevant tax legislation and regulations.

NOTE 22 – CONTINGENCIES


in R-Can Services Limited by 0.6% to 100%; this transaction must be restated in accordance with IFRS as it occurred after the date of transition. Under Canadian GAAP, goodwill was increased by $5.5 million and the non controlling interest was reduced to nil. Under IFRS the non controlling interest is reduced to nil and the remaining adjustment is recorded as an adjustment in equity.

B - Property and EquipmentTrican did not choose the option to restate each item of property and equipment at its fair value and use that fair value as its new deemed historical cost going forward as from January 1, 2010. Instead Trican restated the property and equipment balance to the historic cost basis that would have existed if IFRS policies had been in place since the inception by recreating the fixed asset sub ledger for every historical reporting period back to the original inception of operations by Trican.

Under Canadian GAAP, depreciation was based on the useful life of an asset as a whole. IFRS requires a componentization approach to accounting for fixed assets, separately identifying and measuring significant individual components of assets which have different useful lives. Significant components will be depreciated based on their individual useful lives. Some equipment held by the Company has significant components that will be depreciated over a different useful life to the remainder of the equipment. The historic cost basis requires that the assets are held at a net book value as if IFRS had been in existence since the inception of the company and therefore, the Company has recalculated accumulated depreciation at January 1, 2010 and December 31, 2010. The cumulative adjustment at the date of transition is to reduce the carrying amount of property and equipment as follows:

(Stated in thousands) January 1, 2010 December 31, 2010Decrease in property plant and equipment $(4,327) $(3,462)

Increase in deferred tax asset 1,050 843

Decrease in retained earnings $(3,277) $(2,619)

Consolidated Statement of Financial Position

C - LeasesUnder Canadian GAAP, leases of the Canadian truck fleet were classified as operating leases. Under IFRS, the fleet is classified as a finance lease. The effect of this change in classification, is to increase property and equipment and trade and other payables, and account for the related

depreciation charge on finance leases in cost of sales ($2.0 million for the year ended December 31, 2010) and to decrease lease expense also in cost of sales ($2.1 million for the year ended December 31, 2010) booked on the operating leases under Canadian GAAP.

The impact arising from the change is summarized below:

(Stated in thousands)Year ended

December 31, 2010Cost of sales:

Increase in depreciation expense $2,413

Decrease in lease expense (2,629)

Administration expenses:

Increase in management fee 41

Finance costs:

Increase in lease interest 173

Adjustment before income tax $-

Consolidated Statement of Comprehensive Income


D - Borrowing CostsIn accordance with IFRS 1, the Company has elected to prospectively apply IAS 23 effective January 1, 2010. This election had no impact on the consolidated financial statements.

E - Share-Based PaymentsIn accordance with IFRS 1, the Company has elected not to apply IFRS 2 for its share options that have vested by the date of transition to IFRS. The Company will only apply IFRS 2 retrospectively to options that have not vested at January 1, 2010.

Under Canadian GAAP, the Company calculated the fair value of stock-based awards with graded vesting as one

grant, and the resulting fair value was recognized on a straight-line basis over the vesting period. Under IFRS, each tranche of an award with different vesting dates is considered a separate grant for the calculation of fair value, and the resulting fair value is amortized over the vesting period of the respective tranches. In addition, under Canadian GAAP, forfeitures were recognized as they occurred. Under IFRS the forfeiture estimates are recognized on the grant date. The effect of this change has been to accelerate the stock-based compensation expense relating to the Company’s share option scheme thereby increasing the contributed surplus balance and reducing retained earnings.

(Stated in thousands) January 1, 2010 December 31, 2010Increase in property and equipment $2,272 $7,606

Increase in trade and other payables 2,272 7,606

Related tax effect - -

Increase in retained earnings $- $-



December 31, 2010Increase / (decrease) in administrative expenses:

Stock based compensation $702

Adjustment before income tax $702


(Stated in thousands) January 1, 2010 December 31, 2010Increase in contributed surplus $4,353 $5,055

Decrease in retained earnings $4,353 $5,055


F - Foreign Currency Translation Reserve

In accordance with IFRS 1, the Company has elected to deem all foreign currency translation differences that arose prior

to the date of transition in respect of all foreign operations to be nil at the date of transition.

The impact arising from the change is summarized as follows:

(Stated in thousands) January 1, 2010 December 31, 2010Increase in translation reserve $74,506 $74,968

Decrease in retained earnings $74,506 $74,968



G - Foreign Exchange Treatment of Algerian OperationsUnder Canadian GAAP, the functional currency of the Company’s Algerian operations was considered to be the Canadian dollar and therefore the temporal method of translation was applied. Under IFRS, the primary indicators of functional currency indicate that the functional currency for the Algerian operations is the Algerian Dinar and

therefore the current rate method of translation is used (monetary and non-monetary items are translated at the current rate with exchange gains and losses included in other comprehensive income). The Company has restated the 2010 Algerian statement of financial position and statement of comprehensive income and the impact on the opening statement of financial position and financial performance is as follows:


December 31, 2010Increase in revenue $52

Increase in cost of sales 259

Decrease in foreign exchange gain / loss (1,499)

Increase in other comprehensive income 85

Adjustment before income tax $(1,104)


(Stated in thousands) January 1, 2010 December 31, 2010Decrease in inventory $(52) $(111)

Decrease in equipment (324) (992)

Decrease in retained earnings $(376) $(1,103)


H - Retained EarningsThe above changes decreased/ (increased) retained earnings (each net of related tax) as follows:

(Stated in thousands) Note January 1, 2010 December 31, 2010Business combinations A - (5,542)

Property and equipment B (3,277) (2,619)

Leases C - -

Share based payments E (4,353) (5,055)

Foreign currency translation reserve F (74,506) (74,968)

Foreign exchange treatment of Algerian operations G (376) (1,103)

Decrease in retained earnings (82,512) (89,287)


January 1, 2010 December 31, 2010

(Stated in thousands)Canadian

GAAP

Effect of transition to

IFRS IFRSCanadian

GAAP

Effect of transition to

IFRS IFRSASSETSCurrent assets

Cash and cash equivalents $26,089 - $26,089 $81,058 - $81,058Trade and other receivables 181,483 - 181,483 364,986 - 364,986Prepaid expenses 8,568 - 8,568 9,257 - 9,257Current tax assets - - - 6,024 22 6,046Inventory 91,249 (52) 91,197 106,719 (112) 106,607

307,389 (52) 307,337 568,044 (90) 567,954Property and equipment 534,696 (2,379) 532,317 697,601 3,153 700,755Intangible assets 28,082 - 28,082 20,816 - 20,816Deferred tax assets 84,003 (2,213) 81,790 74,330 - 74,330Other assets 17,918 - 17,918 13,115 - 13,115Goodwill 36,916 - 36,916 42,458 (5,542) 36,916

$1,009,004 $(4,898) $1,004,359 $1,416,364 $(2,479) $1,413,886

LIABILITIES AND SHAREHOLDERS’ EQUITYCurrent liabilities

Bank loans $27,997 - $27,997 - - -Trade and other payables 104,933 1,632 106,565 206,788 2,517 209,305Deferred consideration 1,882 - 1,882 - - -Current tax liabilities 6,505 - 6,505 - 22 22

141,317 1,632 142,949 206,788 2,539 209,327Loans and borrowings 176,279 639 176,918 102,063 5,089 107,152Deferred tax liabilities 43,919 1,890 45,809 98,848 (842) 98,006

Non-controlling interest 296 - 296 - - -Shareholders’ equity

Share capital 246,854 - 246,854 486,594 - 486,594Contributed surplus 28,458 4,353 32,811 37,864 5,055 42,919Accumulated other comprehensive income (69,353) 69,353 - (94,241) 74,968 (19,273)Retained earnings 441,234 (82,512) 358,722 578,448 (89,287) 489,161

647,193 (8,806) 638,387 1,008,665 (9,265) 999,401$1,009,004 $(4,898) $1,004,359 $1,416,364 $(2,479) $1,413,886

Reconciliation of Equity


Twelve Months Ended December 31, 2010

(Stated in thousands, except per share amounts) Canadian GAAPEffect of transition to

IFRS IFRS

Revenue $1,478,293 $52 $1,478,345

Cost of sales 1,185,560 (1,341) 1,184,220

Gross profit 292,733 1,393 294,125

Administrative expenses 73,114 746 73,860

Other (income)/expense (886) - (886)

Results from operating activities 220,505 647 221,151

Finance income (2,992) - (2,992)

Finance costs 9,159 173 9,332

Foreign exchange (gain) / loss 4,074 1,499 5,573

Profit before income tax 210,264 (1,026) 209,238

Income tax expense 58,667 209 58,876

Profit for the year $151,597 $(1,234) $150,362

Earnings per share (basic and diluted)

Basic $1.10 - $1.09

Diluted $1.09 - $1.09

Dividend per share - - $0.05

Weighted average shares outstanding - basic 137,400 - 137,400

Weighted average shares outstanding - diluted 138,571 - 138,571

Other comprehensive income

Foreign currency translation differences (19,050) 86 (18,964)

Total comprehensive income for the year $132,547 $(1,149) $131,398

Total comprehensive income attributable to:

Owners of the Company 132,567 (1,149) 131,418

Non-controlling interest (20) - (20)

Total comprehensive income for the year $132,547 $(1,149) $131,398

Reconciliation of Comprehensive Income

CORPORATE INFORMATION

BOARD OF DIRECTORS

Kenneth M. Bagan (1) (2) (4)

Independent Businessman

G. Allen Brooks (1) (3) (5)

PresidentG. Allen Brooks, LLC

Murray L. CobbeChairman

Dale M. DusterhoftChief Executive Officer

Donald R. Luft (4)

President and Chief Operating Officer

Kevin L. Nugent (1) (2) (3)

PresidentLivingstone Energy Management Ltd.

Douglas F. Robinson (2) (3) (4)

Independent Businessman

OFFICERS


Donald R. LuftPresident and Chief Operating Officer

Michael A. Baldwin, C.A.Vice President, Finance and Chief Financial Officer

Michael G. Kelly, C.A.Senior Vice President, EAME and CIS

Bonita M. CroftVice President, Legal, General Counsel and Corporate Secretary

Robert J. CoxVice President, Canadian Geographic Region

CORPORATE OFFICE

Trican Well Service Ltd.2900, 645 – 7th Avenue S.W.Calgary, Alberta T2P 4G8Telephone: 403.266.0202Facsimile: 403.237.7716Website: www.trican.ca

AUDITORS

KPMG LLP, Chartered AccountantsCalgary, Alberta

BANKERS

HSBC Bank CanadaCalgary, AB

REGISTRAR AND TRANSFER AGENT

Computershare Trust Company of CanadaCalgary, Alberta

STOCK EXCHANGE LISTING

The Toronto Stock ExchangeTrading Symbol: TCW

INVESTOR RELATIONS INFORMATION

Requests for information should be directed to:


Michael A. Baldwin, C.A.Vice President, Finance and Chief Financial Officer_________________________(1) Member of the Audit Committee(2) Member of the Compensation Committee(3) Member of the Corporate Governance Committee(4) Member of the Health, Safety and Environment Committee(5) Lead Director

operational excellence technical solutionstechnical solutions annual report 2011 corporate profile...

Documents