Precision Drilling Corporation
Annual Report 2009

Plain-text annual report

PD 09AR Cover Mar24SJ_Layout 1 24/03/10 9:22 AM Page 1 4200, 150 – 6th Avenue SW Calgary, Alberta, Canada T2P 3Y7 Telephone: 403-716-4575 Email: info@precisiondrilling.com www.precisiondrilling.com P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T N O I S I C E R P W E N E C N E I L I S E R 9 0 0 2 T R O P E R L A U N N A H T W O R G 9 0 0 2 G N I L L I R D N O I S I C E R P E U L A V H G I H E C N A M R O F R E P H G I H PD 09AR Cover Mar24SJ_Layout 1 24/03/10 9:22 AM Page 2 PRECISION DRILLING TRUST 2009 ANNUAL REPORT From the Horn River shale play in British Columbia to the natural gas fields at the southern tip of Mexico…from the Bakken Shale in North Dakota to the Marcellus Shale in Pennsylvania, Precision is a leading provider of safe, high performance energy services to the North American oil and gas industry. Precision provides customers with access to a fleet of 352 contract drilling rigs, 200 service rigs, camps, snubbing units, wastewater treatment units and rental equipment backed by a comprehensive mix of technical support services and skilled, experienced personnel. 2009 ACHIEVEMENTS (cid:2) Aggressively implemented cost saving 2010 OUTLOOK (cid:2) Execute high performance, high value and cost reduction measures to sustain service model for North American strong margins and international growth (cid:2) Strengthened the capital structure and (cid:2) Seize market opportunities aligned balance sheet through decisive steps to with our diverse fleet and vertically conserve cash and reduce debt by integrated service mix $565 million (cid:2) Utilize financial flexibility and strength (cid:2) Achieved the best safety record in to facilitate growth strategy, including company history, advancing toward conversion of trust to a corporation the Target Zero goal of no reportable incidents (cid:2) Integrated U.S. operations, delivered 16 new rig builds under term contract, and took the industry lead to rationalize less productive assets while high- grading the rig fleet CORPORATE INFORMATION TRUSTEES Robert J. S. Gibson Allen R. Hagerman, FCA Patrick M. Murray DIRECTORS Frank M. Brown William T. Donovan W.C. (Mickey) Dunn Brian A. Felesky, CM, Q.C. Robert J. S. Gibson Allen R. Hagerman, FCA Stephen J. J. Letwin Patrick M. Murray Kevin A. Neveu Frederick W. Pheasey Robert L. Phillips Trevor M. Turbidy OFFICERS Kevin A. Neveu President and Chief Executive Officer Gene C. Stahl President, Drilling Operations Douglas J. Strong Chief Financial Officer David W. Wehlmann Executive Vice President, Investor Relations Joanne L. Alexander Vice President, General Counsel and Corporate Secretary Kenneth J. Haddad Vice President, Business Development Darren J. Ruhr Vice President, Corporate Services LEAD BANK Royal Bank of Canada Calgary, Alberta AUDITORS KPMG LLP Calgary, Alberta HEAD OFFICE 4200, 150 – 6th Avenue SW Calgary, Alberta, Canada T2P 3Y7 Telephone: 403-716-4575 Email: info@precisiondrilling.com www.precisiondrilling.com Super Single®, Super Triple® and Super Series® are registered trademarks of Precision Drilling Corporation in Canada. 2009 AnnuAlRepoRt MANAGEMENT’S DISCUSSION & ANALYSIS 3 Cautionary Statement Regarding Forward- Looking Information and Statements 4 Business Overview 4 Select Financial and Operating Information 5 Overview 6 Vision and Strategy 7 Outlook 8 About Precision 9 Resources Needed to Succeed in a Cyclical Business 9 Fundamentals of the Energy Services Industry 14 Operating Capabilities 17 Key Performance Drivers 19 Capital and Liquidity Management 24 Consolidated Financial Results 24 Consolidated Overview 27 Fourth Quarter 2009 29 Business Segment Results 30 Contract Drilling Services 34 Completion and Production Services 36 Corporate and Other Items 37 Results by Geographic Segment 38 Critical Accounting Estimates 39 New Accounting Standards 39 Transition to International Financial Reporting Standards 43 Overview of Business Risks 47 Evaluation of Disclosure Controls and Procedures 48 Non-GAAP Measures 49 Consolidated Financial Statements 55 Notes to Consolidated Financial Statements 83 Supplemental Information P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 1 E C N E I L I S E R A & D M H T W O R G T S U R T G N I L L I R D N O I S I C E R P Precision Drilling Trust MAnAgeMent’sDiscussionAnDAnAlysis MD&A This Management’s Discussion and Analysis (“MD&A”), prepared as at March 10, 2010 focuses on the Consolidated Financial Statements, and pertains to known risks and uncertainties relating to the oilfield services sector. This discussion should not be considered all-inclusive, as it does not include all changes regarding general economic, political, governmental and environmental events. Additionally, other events may or may not occur which could affect Precision Drilling Trust (the “Trust” or “Precision”) in the future. In order to obtain an overall perspective, this discussion should be read in conjunction with the “Cautionary Statement Regarding Forward- Looking Information and Statements” and the audited Consolidated Financial Statements and related Notes. The effects on the Consolidated Financial Statements arising from differences in generally accepted accounting principles (“GAAP”) between Canada and the United States are described in Note 21 to the Consolidated Financial Statements. Additional information relating to the Trust, including the Annual Information Form, has been filed with SEDAR and is available at www.sedar.com. 2 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S cAutionARystAteMentRegARDingFoRWARD-looKing inFoRMAtionAnDstAteMents This Annual Report contains certain forward-looking information and statements, including statements relating to matters that are not historical facts and statements of our beliefs, intentions and expectations about developments, results and events which will or may occur in the future, which constitute “forward-looking information” within the meaning of applicable Canadian securities legislation and “forward-looking statements” within the meaning of the “safe harbor” provisions of the United States Private Securities Litigation Reform Act of 1995 (collectively the “forward-looking information and statements”). Forward-looking information and statements are typically identified by words such as “anticipate”, “could”, “should”, “expect”, “seek”, “may”, “intend”, “likely”, “will”, “plan”, “estimate”, “believe” and similar expressions suggesting future outcomes or statements regarding an outlook. Forward-looking information and statements are included throughout this Annual Report including under the headings “Business Overview”, “Vision and Strategy”, “Outlook”, “Resources Needed to Succeed in a Cyclical Business”, “Operating Capabilities”, “Key Performance Drivers”, “Capital and Liquidity Management”, “Consolidated Financial Results”, “Critical Accounting Estimates, New Accounting Standards and International Financial Reporting Standards”, “Overview of Business Risks”, “Evaluation of Disclosure Controls and Procedures” and include, but are not limited to statements with respect to: 2010 expected cash provided by continuing operations; 2010 capital expenditures, including the amount and nature thereof; suspension of distributions on Trust Units and payments on Exchangeable Units; performance of the oil and natural gas industry, including oil and natural gas commodity prices and supply and demand; expansion, consolidation and other development trends of the oil and natural gas industry; demand for and status of drilling rigs and other equipment in the oil and natural gas industry; costs and financial trends for companies operating in the oil and natural gas industry; energy consumption trends; our business strategy, including the 2010 strategy, growth plans and outlook for our business segments; expansion and growth of our business and operations, including diversification of our earnings base, safety and operating performance, the size and capabilities of our drilling and service rig fleet, our market share and our position in the markets in which we operate; demand for our products and services; our management strategy; labour shortages; climatic conditions; the maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies and tax liabilities; statements regarding our proposed conversion to a corporation; the anticipated benefits of conversion; timing of the conversion; expected payments pursuant to contractual obligations; the prospective impact of recent or anticipated regulatory changes; financing strategy and compliance with debt covenants; credit risks; and other such matters. All such forward-looking information and statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. These statements are, however, subject to known and unknown risks and uncertainties and other factors. As a result, actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking information and statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information and statements will transpire or occur, or if any of them do so, what benefits will be derived therefrom. These risks, uncertainties and other factors include, among others: the impact of general economic conditions in Canada and the United States; world energy prices and government policies; the availability of credit and equity globally to both Precision and the oil and gas companies that are its customers; consumer confidence and the duration of any recessionary period; industry conditions, including capital spending decisions; priority placed on high-performance rigs in resource plays; the adoption of new environmental, taxation and other laws and regulations and changes in how they are interpreted and enforced; the impact of initiatives by the Organization of Petroleum Exporting Countries and other major petroleum exporting countries; the effect of weather conditions on operations and facilities; fluctuations in the demand for well servicing, contract drilling and ancillary oilfield services; the existence of operating risks inherent in well servicing, contract drilling and ancillary oilfield services; volatility of oil and natural gas prices; oil and natural gas product supply and demand; fluctuations in the level of oil and natural gas exploration and development activities; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; our ability to enter into, and the terms of future contracts; consolidation among our customers; risks associated with technology; political uncertainty, including risks of war, hostilities, civil insurrection, instability or acts of terrorism; the lack of availability of qualified personnel or management; credit risks; increased costs of operations, including costs of equipment; the effect of the Canadian federal government’s SIFT rules; failure to realize the anticipated benefits of our proposed conversion to a corporation; fluctuations in interest rates; stock market volatility; safety performance; foreign operations; foreign currency exposure; dependence on third party suppliers; opportunities available to or pursued by us; and other factors, many of which are beyond our control. These risk factors are discussed in the Annual Information Form and Form 40-F on file with the Canadian securities commissions and the United States Securities and Exchange Commission and available on SEDAR at www.sedar.com and the website of the U.S. Securities and Exchange Commission at www.sec.gov, respectively. Except as required by law, Precision Drilling Trust, Precision Drilling Limited Partnership and Precision Drilling Corporation disclaim any intention or obligation to update or revise any forward-looking information or statements, whether as a result of new information, future events or otherwise. The forward-looking information and statements contained in this Annual Report are expressly qualified by this cautionary statement. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 3 Precision Drilling Trust BusinessoveRvieW MD&A SELECT FINANCIAL AND OPERATING INFORMATION (Stated in thousands of Canadian dollars, except per unit amounts) % Increase % Increase % Increase Years ended December 31, 2009 (Decrease) 2008 (Decrease) 2007 (Decrease) Revenue $1,197,446 8.7 $1,101,891 9.2 $1,009,201 (29.8) EBITDA (1) 407,001 (6.8) 436,536 (0.1) 437,075 (34.6) Net earnings 161,703 (46.6) 302,730 (12.4) 345,776 (40.3) Cash provided by continuing operations 504,729 46.8 343,910 (29.0) 484,115 (20.6) Capital spending: (2) Upgrade capital expenditures 30,303 (49.0) 59,454 29.3 45,970 (50.1) Expansion capital expenditures 163,132 (4.1) 170,125 20.7 141,003 (17.5) Proceeds on sale (15,978) 53.0 (10,440) 81.0 (5,767) (80.3) Net capital spending 177,457 (19.0) 219,139 20.9 181,206 (22.5) Distributions declared – cash 6,408 (96.8) 200,659 (18.6) 246,485 (44.9) Distributions declared – in-kind – (100.0) 24,029 (20.4) 30,182 23.1 Earnings per unit: Basic 0.65 (70.9) 2.23 (13.2) 2.57 (40.4) Diluted 0.63 (71.7) 2.23 (13.2) 2.57 (40.4) Distributions declared per unit – cash 0.04 (97.4) 1.56 (20.4) 1.96 (44.9) Distributions declared per unit – in-kind – (100.0) 0.15 (37.5) 0.24 23.1 Drilling rig utilization days: Canada 21,229 (38.4) 34,488 (0.2) 34,572 (32.3) United States 22,672 183.2 8,006 281.6 2,098 n/m International 710 346.5 159 n/m – n/m Service rig operating hours: Canada 207,361 (38.1) 335,127 (5.9) 355,997 (25.9) (1) EBITDA is a non-GAAP measure and is defined as earnings before interest, taxes, loss on asset decommissioning, depreciation and amortization and foreign exchange. See page 48. (2) Excludes acquisitions. n/m calculation not meaningful. 4 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S Financial Position and Ratios (Stated in thousands of Canadian dollars, except ratios) Years ended December 31, 2009 2008 2007 Working capital $ 320,860 $ 345,329 $ 140,374 Working capital ratio 3.5 2.0 2.1 Long-term debt (1) $ 748,725 $ 1,368,349 $ 119,826 Total long-term financial liabilities $ 775,418 $ 1,399,300 $ 133,722 Total assets $ 4,191,713 $ 4,833,702 $ 1,763,477 Enterprise value (2) $ 2,536,477 $ 2,636,170 $ 1,877,139 Long-term debt to long-term debt plus equity (1) 0.22 0.37 0.08 Long-term debt to cash provided by continuing operations (1) 1.48 3.98 0.25 Long-term debt to enterprise value (1) 0.30 0.52 0.06 (1) Excludes current portion of long-term debt which is included in working capital and is net of unamortized debt issue costs. (2) Unit price as listed on the Toronto Stock Exchange as at December 31 multiplied by the number of units outstanding plus long-term debt minus working capital. See page 23. OVERVIEW For the first time in Precision’s operating history, which stretches back over five decades, 2009 revenues and assets in the United States exceed those in Canada. This is the result of Precision’s strategy to grow and diversify its operating presence into growth markets that reward high performance capabilities. Precision is now positioned in most of the emerging resource or shale plays throughout North America. Through steps taken over the past two years, Precision is positioned to benefit from rising customer demand brought about through industry advances in horizontal drilling and multi-stage completion techniques. Precision entered 2009 having just closed the acquisition of Grey Wolf, Inc. (“Grey Wolf”). The Trust’s long-term debt was substantially increased due to the acquisition. Because of the then deteriorating market conditions, Precision’s priorities for 2009 were to: 1. improve the balance sheet; 2 integrate Grey Wolf; and 3. continue to provide high performance, high value service to customers. Fiscal 2009 was a very difficult year for the oil and gas service sector. The global banking and general economic distress that started in 2008 continued into 2009, leading to significantly reduced oil and gas commodity prices. This resulted in reduced spending by Precision’s customers and led to the sharpest decline in drilling and well service activity since the early 1980s. Despite improvements in late 2009, demand for oilfield services throughout the year was significantly below the peak levels seen in 2007 and early 2008. Nevertheless, Precision was able to deliver on all three of its priorities during the year. 1. First, with regard to the balance sheet, Precision was able to reduce long-term debt throughout the year and lowered the Trust’s debt to total capitalization ratio to 0.22 at December 31, 2009 from 0.37, a year earlier. This improvement was accomplished through a series of measures that included Trust unit issuances, debt refinancing and through internally generated cash flow that was used to reduce debt. These transactions were accomplished in spite of some of the toughest times in the equity and debt markets in the past two decades. These transactions were necessary to improve the capital structure of the Trust and to position the Trust for growth in 2010 and beyond. 2. The integration of Grey Wolf was substantially completed during 2009. Personnel were realigned, and information and operating system decisions and implementations were planned and executed during the year. Precision’s supply chain support system was expanded into the United States with the opening of Grey Wolf Supply mid-year which is now supplying all of the United States rigs. Maintenance and manufacturing processes and systems are being established in the United States and 2010 should provide additional cost savings from these activities. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 5  3. The people of Precision continue to perform at a very high level. Precision continues to deliver our customers the high performance, high value service that they have come to expect. Safety of our people is the top core value for Precision, and 2009 produced the best safety record in Precision’s history. Precision is not resting on our 2009 results and the Trust continues to move towards “Target Zero” which is Precision’s goal of no work place incidents. Precision is proud to be one of the contractors of choice for several major and large independent exploration and production companies in North America. In fact, Precision earned “Contractor of the Year” honours from a major oil company for its United States operations during 2009. HISTORIC LEVELS OF LONG-TERM DEBT Debt to capitalization is within historic corporate levels. Equity Long-term Debt (LTD) LTD to LTD plus Equity Ratio 3,000 2,500 2,000 1,500 1,000 500 s n o i l l i m $ 0.50 0.40 0.30 0.20 0.10 o i t a R Source: Precision 2001 2002 2003 2004 2005 2006 2007 2008 2009 VISION AND STRATEGY Precision’s vision is to be recognized as the high performance, high value provider of services for global energy exploration and development. Precision’s people, systems and rigs are capable of drilling and servicing customer requirements with consistent results which reduces the cost and risk for our customers. Precision’s unique combination of superior people, critical size, drilling technology, vertical integration and superior business systems provides a strong competitive advantage for the Canadian and United States markets and for international expansion. Precision’s strategy is aligned for and dedicated to growth. The organic growth into the United States in 2007 and 2008 was the first step in the growth outside of Canada. This was followed by the acquisition of Grey Wolf in late 2008. The improvement of the balance sheet and debt restructuring during 2009 was the next step. The proposed conversion to a corporation will help facilitate Precision’s growth plans. Priorities for 2010 are changed from 2009 as Precision is in a position to again seize market growth opportunities. Those opportunities are expected to come in the form of new build Super Series® rigs, existing rig upgrades, international deployment of assets and the potential acquisition of additional assets. Precision’s corporate and competitive growth strategies are designed to optimize resource allocation and differentiate Precision from the competition. Precision also expects that during 2010 the Trust will be able to generate sufficient cash flow from operations to allow it to have the financial flexibility to manage its growth plan going forward. This flexibility is expected to be in the form of cash on the balance sheet as well as access to the Trust’s debt facilities. Precision is very cognizant of the cyclicality of the oilfield services industry and will be prudent in the use of financial resources. In terms of business segments, Precision sees growth for its Contract Drilling Services’ land drilling rig fleet. The growth opportunities are less obvious for the Completion and Production Services’ service rig fleet due to excess equipment capacity in the Western Canada Sedimentary Basin (“WCSB”) and throughout North America. However, with challenge comes opportunity to consolidate smaller, less efficient competitors and to seize opportunities to expand services to address rig-less completions and production work associated with many horizontal wells. 6 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S During 2010, Precision will continue to build on its high performance, high value vision. Further improvements in safety, assets and systems are planned, as customers demand ever increasing performance as they develop the technically challenging unconventional shale plays. Precision will continue to internally develop and challenge its people to seize opportunities. OUTLOOK The effects of a weak global economy and resulting low energy commodity prices continued throughout most of 2009. While the economy has begun to show initial signs of stabilization and oil pricing has recovered from its low, there remains considerable demand uncertainty for both oil and natural gas and this has led to low underlying customer demand for oilfield services. There are signs in the market that these trends may be reversing as Precision is seeing higher customer demand in all of its service areas. However, the rate and duration of this improvement in demand cannot be determined at this time. Moving into the first quarter of 2010, industry fundamentals for natural gas are beginning to show modest improvements. Storage levels for natural gas in the United States have moved down into the range of the last five year’s storage levels and natural gas prices are slightly higher than they were a year ago and considerably higher than the third quarter of 2009. Supplies of natural gas, especially from unconventional resource plays in Texas and Louisiana, came on line in late 2008 and early 2009 from drilling activity which peaked in 2008. A significant portion of these wells, and the associated gas production gains, are subject to high depletion rates and the reduction in drilling is beginning to show in the decreases in recently reported production levels. WORKING GAS IN UNDERGROUND STORAGE COMPARED WITH FIVE-YEAR RANGE The shaded area indicates the range between the historical minimum and maximum values for the weekly series from 2008 through February 2010. The dashed vertical lines indicate current and year-ago weekly periods. Five-year Historical Range Period Storage 4,000 3,000 2,000 1,000 t e e f c i b u c n o i l l i B Source: U.S. Energy Information Administration (EIA) Feb 08 May 08 Aug 08 Nov 08 Feb 09 May 09 Aug 09 Nov 09 Feb 10 Despite this recent improvement, uncertainty remains for the United States natural gas markets, as concerns over consumption and the global economy continue to overshadow lower Canadian imports and the drop in active North American rigs drilling for natural gas. Based upon the latest available data, United States natural gas supply has declined modestly from peak levels achieved in mid 2009 and Precision expects the supply of natural gas to show additional declines over the next several quarters as active gas rig counts remain relatively low. Subject to demand volatility, this should lead to higher commodity prices and support a continued recovery in gas drilling activity. While equipment utilization levels are beginning to improve for both of Precision’s business segments, Contract Drilling and Completion and Production Services, there still remains competitive price pressure on all of Precision’s service offerings. During the last nine months in the United States, there has been a steady increase in the number of drilling rigs operating and as such Precision is seeing modest dayrate increases on recent spot market contracts. In Canada, there has been a recent seasonal increase in rigs working that is exceeding early 2009 levels. In both Canada and the United States, virtually all of Precision’s Tier I rigs are working as compared with about 60% of the Tier II rigs and 20% of the Tier III rigs. Precision expects low Tier III utilization to persist into 2010 and potentially longer depending on natural gas pricing recovery. Customers have provided very little visibility regarding their oilfield service plans and expenditures for the summer 2010 drilling season in Canada. In the United States, Precision expects the working rig count to continue to modestly improve as we move through 2010, subject to changes in commodity prices. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 7 Precision continues to carry a strong portfolio of term customer contracts that help mitigate the effects of the downturn. Precision expects to have an average of approximately 75 drilling rigs under day work term contracts in North America in the first quarter of 2010 and an average of 71 for the second quarter. These term contract totals include four rigs in the United States that are currently not working but receiving margin revenue from customers. In Canada, a term contracted rig generates about 200 to 250 utilization days a year due to the seasonal nature of well access whereas in most regions of the United States Precision expects about 350 utilization days per year from a term contract drilling rig. For 2010, Precision expects to have an average of approximately 34 drilling rigs in Canada under term contracts, 31 in the United States and one in Mexico, for a total of 66 for the full year. For the 2011 calendar year, Precision expects an average of approximately 37 drilling rigs to be generating revenue under existing term contracts, with 20 in Canada and 17 in the United States. Precision’s contracts continue to be honoured by its customers although in some cases, term revisions have been negotiated within original economic terms or paid out. Precision currently expects that additional term contracts for existing equipment will be entered into during 2010 as there are current negotiations with several customers in Canada and the United States. Precision expects to keep non-expansion capital expenditures at low levels. For 2010, Precision expects to have capital expenditures of $75 million, which includes $50 million in sustaining, upgrade and infrastructure expenditures and $25 million is planned for performance enhancements to improve the Tier classification of 10 to 15 drilling rigs during the year. Currently, there are potential market opportunities to construct several new rigs and Precision may allot new expansion capital subject to customer term contract economics. Despite persistent market uncertainty and near term challenges, the future of the global oilfield service industry remains promising. Precision has positioned its rig fleet in most of the onshore growth basins in North America and this is expected to provide an opportunity to demonstrate its value to customers through delivery of high performance, high value services that deliver lower customer well costs and strong relative margins to Precision. ABOUT PRECISION Precision is a provider of safe, high performance energy services to the North American oil and gas industry. Precision provides customers with access to an extensive fleet of contract drilling rigs, service rigs, camps, snubbing units, wastewater treatment units and a wide array of rental equipment backed by a comprehensive mix of technical support services and skilled, experienced personnel. Precision is headquartered in Calgary, Alberta, Canada and is listed on the Toronto Stock Exchange under the trading symbol “PD.UN” and on the New York Stock Exchange under the trading symbol “PDS”. PRECISION DRILLING TRUST Contract Drilling Services Completion and Production Services Drilling Rig Operations: Service Rigs and Snubbing Operations (cid:0) Canada (cid:0) United States (cid:0) Mexico & Chile Camps and Catering Equipment Rentals Wastewater Treatment (cid:0) Procurement & Distribution (cid:0) Manufacture & Repair (cid:0) Engineering & Technology (cid:0) Technical Vertical Business Support Systems Corporate Support (cid:0) Governance (cid:0) Operations (cid:0) Functions 8 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S Precision Drilling Trust ResouRcesneeDeDtosucceeDinAcyclicAlBusiness MD&A Precision operates in an inherently challenging cyclical industry; the energy services business. There are a number of business risks associated with the volatility of an industry that is dependent on global oil economics and the more regional energy source, natural gas. The key risks are referenced later in this report. To excel in this environment, Precision operates through a business model to control risk and optimize performance. The model is directly linked to competitive strategy and is evidenced by Precision’s operating capabilities. Both business segments deploy assets and services that are capital intensive, technology oriented and people dependant. The combination thereof provides a level of service to customers that dictates a company’s brand and reputation. The essential elements of service also include safety and environmental considerations. These factors in combination lead to operating proficiency and profitability throughout the business cycle. Invariably they also lead to growth opportunities to diversify and increase market share. Through this section, management is presenting its views of Precision’s business and the resources needed to succeed. Understanding the oil and gas industry and the factors that impact demand for oilfield services is important to assess risk factors that affect Precision’s long-term strategy and financial performance. FUNDAMENTALS OF THE ENERGY SERVICES INDUSTRY Management believes that hydrocarbon energy sources, oil and natural gas, are low cost energy sources and there is a continuing global dependency to replace existing production levels which will remain viable for decades. Alternate energy sources are necessary, but will take time and technology for improved economics and infrastructure to develop. The shift from conventional to unconventional oil and natural gas production requires higher capacity equipment and technical expertise. The gradual steady shift in the drilling of more horizontal wells and fewer vertical wells is evidence of this trend. Multi-stage horizontal completion techniques are re-opening many basins to renewed drilling in North America. This is an emerging development that is gaining credibility, an exciting opportunity for industry to extract greater production from known resource regions previously thought to be uneconomical. Global Markets Global economic growth and prosperity drives energy consumption. Crude oil and to a lesser extent natural gas are the most dominant and versatile sources of energy in developed countries while crude oil and coal are the dominant sources of energy in developing countries. Oil and its by-products are currently the most important fuel for the transportation industry as there are few alternatives that can compete economically. Oil and natural gas are major fuel sources for generating heat and electricity and are critical building blocks for countless consumer products. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 9 The impact of the recent economic recession in many economies has led to a decrease in global energy demand and oil and natural gas commodity pricing for most of 2009. As a result, there has been a significant decline in capital investment directed towards energy exploration and development. Looking longer term, the worldwide population continues to grow and is expected to rise 1.0% per year causing higher energy demand into the future. From a reference year of 2006, energy consumption is projected by the United States government Energy Information Administration (“EIA”) to increase 44% by 2030 with oil, natural gas and coal meeting approximately 83% of global demand, as depicted in the graphs below. World oil consumption is predicted to rise about 1.0% per year during this period due largely to growing demand in China, India and other developing countries. Delivering reliable and affordable energy for these fast-growing and upwardly mobile populations is a major challenge, with security of supply an important theme. The EIA is forecasting natural gas consumption increases of 1.6% on average per annum to 2030 as rising oil prices and environmental considerations increase the demand for natural gas as an alternative fuel in industrial and electrical sectors in developed and developing economies. WORLD ENERGY CONSUM PTION, 2006- 2030 Energy demand growth will be led by India, China and other developing countries. Non-OECD OECD Source: EIA 2006 2010 2015 2020 2025 2030 WORLD ENERGY SOURCES , 198 0 -2030 Oil and natural gas remain essential energy sources to meet rising consumpion. History Projections Liquids (including biofuels) Coal Natural Gas Renewables (excluding biofuels) Nuclear Source: EIA 1980 1995 2006 2015 2030 800 600 400 200 250 200 150 100 50 t u B n o i l l i r d a u Q t u B n o i l l i r d a u Q Commodity prices over the last two years have moved lower with the economic crisis of 2008 and have staged a recovery as demand and supply fundamentals tightened. As highlighted in the following chart, oil prices have recovered since the first quarter of 2009 while natural gas has languished until very recently. This has partially mitigated the steep decline in customer demand associated with natural gas wells as natural gas pricing continues to be relatively low due to high United States underground storage levels and domestic production. 10 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S WTI OIL AND HEN RY HUB NATU RAL G AS PRI CES Commodity prices have recovered from their recent lows. Henry Hub Natural Gas West Texas Intermediate Oil 14 12 10 8 6 4 t u B M M / $ S U 140 120 100 80 60 40 l e r r a b / $ S U Source: Precision Jan 05 Jul 05 Jan 06 Jul 06 Jan 07 Jul 07 Jan 08 Jul 08 Jan 09 Jul 09 Jan 10 Natural gas prices in North America have been below most global price points for liquefied natural gas (“LNG”) and LNG imports to the United States market have remained at relatively low levels. LNG is a fungible commodity the movement of which is subject to demand fluctuations with supply trending to high priced markets, such as Europe and Asia. In North America, LNG is an important future source of supply that could offset production declines from mature reservoirs and help meet future natural gas demand. However, higher domestic natural gas production from shale gas reservoirs, such as the Barnett in Texas, has reduced the need for LNG and Canadian imports. North American Markets The economics of the oilfield service industry are linked to these global fundamentals in combination with regional opportunities. Important regional drivers for the industry in North America include the underlying hydrocarbon make-up of the various basins and the existence of established, competitive and efficient service infrastructure. As commodity prices vary so does industry cash flow to fund exploration and development, especially the pace of investment in unconventional production. Increasingly, the benefits of new drilling and completion technology, along with improved economics, have driven customers to drill more complex wells in emerging and well-known basins throughout North America. Precision has expanded its rig count in many of these areas and is poised to benefit from further improvements as fundamentals strengthen and customer demand increases. As depicted in the map of North America, Precision’s drilling rig fleet is positioned in virtually every resource play from northern Canada to the southern United States. :NOITACIFISREVID D IVE RS IFICAT IO N : UN CO N VEN T I O N AL R E SO URCE COVERAGE :NOITACIFISREVID CECRUOSERLANOITNEVNOCNU: CECRUOSERLANOITNEVNOCNU: EGAREVOC EGAREVOC reviRnroH Horn River yeeyntnoM Montney danaCnretseW nisaByratnemideSad nisaBreviRneerG nisaBatniU nisaBniuqaoJnaS nekkaB Bakken ecnaeciP Piceance Woodford droffodooW ttenraB t Barnett droffoelgaE Eagleford Source: Precision Source: Precision iRreedwoP e e r isaBreev e n ns s n r isaBnauJnaS n n n n okradanA AA Bkk isaB nisaBhtroWtroF saxeThtuoS niisBaBBasoolacsuT in s tsaoCfluG Basins Basins Precision’’s Rig Locations s Rig Locations Precision’s Rig Locations s Rig Locations Marcellus sullecraM nisaBnaihcalappA nisaBroirraWkcalB Fayetteville elliveevtteyaF ellivsenyaH Haynesville P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 11 Economic Drivers Providing oil and natural gas products to consumers involves a number of players, each taking on different risks in the exploration, production, refining and distribution processes. Exploration and production companies, Precision’s customers, assume the risk of finding hydrocarbons in reservoirs of sufficient size to economically develop and produce. The economics are dictated by the current and expected future margin between the cost to find and develop hydrocarbons and the eventual price of these products; the wider the margin, the greater the incentive to undertake these risks. Exploration and development activities include acquiring access to prospective lands, seismic surveying to detect hydrocarbon bearing structures as well as faults and traps within the structure, drilling wells and completing successful wells for production. Exploration and production companies hire oilfield service companies to perform the majority of these tasks. The revenue of an oilfield service company is part of the finding and development costs for an exploration and production company. The economics of an oilfield service company are largely driven by the price of crude oil and natural gas realized by its customers. Since oil can be transported relatively easily, it is priced in a global market influenced by an array of economic and political factors while natural gas continues to be priced in continental markets. As previously noted, drilling dynamics have changed with recent technological advancements in fracturing, stimulation and horizontal drilling that have brought about a paradigm shift from the development of conventional to the development of unconventional natural gas and oil reservoirs in North America. This is especially prevalent in the exploitation of existing and emerging shale gas plays in the United States where pipeline takeaway capacity improvements have occurred. The application of these new technologies in unconventional drilling in North America has provided significant productivity gains in certain United States shale gas plays. These technological improvements are evident in the proportion of wells drilled using directional and horizontal well programs. As shown in the graph below, the trend in Canada away from vertical wells to the more demanding requirements of directional/horizontal well programs is very consistent. Precision’s rig fleet in Canada has been engaged by customers on these wells to a greater degree than industry, demonstrating Precision’s high performance capabilities. GRO WTH OF RIGS DRILLING DI RE CTI ONAL/ HORI ZONTAL WELLS IN CA NA DA Precision’s capabilities are demonstrated by the high proportion of rigs drilling complex well programs. Precision Industry Less Precision 80 60 40 s l l e l t W a n o z i r o H / a n o l i t c e r i D t f o e g a n e c r e P Source: Whelby Data 2006 2007 2008 2009 2010 Technological innovations have been a major factor in the natural gas production increase for the United States. These productivity gains have reduced the reliance on Canada as a source of natural gas supply. The following graph reflects the natural gas production increases realized since early 2006 in the United States as new technologies have been employed to enhance and bring forward the productive life of unconventional natural gas wells. 12 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S U.S . LOWER 48 N ATURAL GA S PR ODUC TION Reduced drilling in 2009 has halted production growth. 65 60 55 50 ) D / F C B ( n o i t c u d o r P U.S. Lower 48 Natural Gas Production Source: EIA Jan 2006 Jan 2007 Jan 2008 Jan 2009 Jan 2010 However, lower Canadian drilling levels for natural gas targets have been in play for a longer period and the decline in production is clearly evident. The lower drilling activity in Canada was influenced by reduced consumption in the United States and by low cost new production growth from shale gas basins in the United States. The graph below depicts the decline in Canadian natural gas production due to factors previously discussed and compounded by Alberta government royalty changes. CANAD IA N NATURAL G AS P ROD UC TION Due to a lack of drilling, Canadian natural gas production has dropped. 20.0 17.5 15.0 12.5 ) D / F C B ( n o i t c u d o r P Canadian Natural Gas Production Source: First Energy Capital Jan 2006 Jan 2007 Jan 2008 Jan 2009 Jan 2010 Drilling Rig Activity in Canada and the United States The United States active drilling rig count increased from about 1,400 rigs in 2005 to a peak of about 1,950 rigs in late 2008. The economic downturn led to a low in 2009 of about 800 active drilling rigs before recovering to about 1,200 by year-end. With recent economic stability and improving commodity prices, Precision’s high performance drilling rig fleet in the United States has been the first to experience a recovery in activity. Within Canada, the cyclical nature of the oilfield services business due to seasonality factors and low commodity pricing continues to affect the demand for drilling rig services. Due to declining volumes of natural gas exports to the United States, higher pipeline transportation costs have further deteriorated producer economics. Here again, customers require cost efficiency in all aspects of their finding and development costs and lead toward increased demand for high performing assets. The demand for premium rigs is further supported by a higher level of operating specifications associated with increased exploitation of unconventional resource basins in North America. Demand for high performing drilling rigs continues to grow and garner premium pricing while displacing underperforming rigs in the process. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 13 U.S . LAND DRILLING RIG AC TIVI TY Gas drilling has recovered to only 60% of peak levels while oil drilling has returned to peak levels. Gas Rigs Oil Rigs 1,600 1,200 800 400 i s g R e v i t c A Source: Baker Hughes, Inc. Jan 2006 Jan 2007 Jan 2008 Jan 2009 Jan 2010 CANAD IA N DRILLIN G RIG ACTIVI TY Drilling in Canada in 2009 was at historic lows. 800 600 400 200 s g R i e v i t c A Rigs Working Source: Baker Hughes, Inc. Jan 2006 Jan 2007 Jan 2008 Jan 2009 Jan 2010 As the charts above demonstrate, seasonal volatility in drilling rig activity is far greater in Canada. OPERATING CAPABILITIES Precision’s operating capabilities provide cost effective services and solutions to our customers. Precision prides itself on providing quality equipment operated by highly experienced and well trained crews. Additionally, Precision strives to align its capabilities with evolving technical requirements associated with more complex well bore programs. Customer relationships are fundamental to Precision’s success and the recognition of our high performance, high value capability is based largely on our ability to deliver. High Performance Drilling Rigs Precision Drilling is focused on providing more cost efficient drilling technologies. Design innovations and technology improvements capture incremental time savings throughout all phases of the well drilling process, including multi-well pad capability and rig mobility between wells. The versatile Super Single® design utilizes technical innovations in safety and drilling efficiency for slant or directional drilling on single or multiple well pad locations in shallow to medium depth wells. It has proven to be extremely efficient on conventional vertical wells and has drilled in many regions of the world. Super Single® rigs utilize extended length tubulars, an integrated top drive and innovative unitization to facilitate quick moves between well locations. A small footprint minimizes environmental impact. Enhanced safety features such as remote control tubular handling reduce the exposure of employees to potentially hazardous operations. 14 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S A scaled-down version without slant capability, the Super Single® Light, also features an integrated top drive and remotely controlled tubular handling and is unitized within a trailer to reduce the load count for efficient moving, rig up and tear down for the shallow well depth market. Triple rigs have greater hoisting capacity and are used in deeper exploration and development drilling. The Super Triple® electric rigs are designed to keep the truck load count as low as possible using widely available conventional rig moving equipment. Power capabilities are a major design criterion for the new Super Triple® rigs. Drilling productivity and reliability with AC power drive and electronic control systems provide added precision and measurability that precisely control weight, rotation and torque on the drill bit. These rigs use extended length drill pipe, an integrated top drive and remotely controlled tubular handling equipment. Large Diversified Rig Fleets Precision’s large diverse fleet of rigs is strategically deployed across the most active regions in North America including most of the major unconventional oil and gas fields. When an oil and gas company needs a specific type or size of rig in a given area, there is a high likelihood that a Precision rig will be readily available. Geographic proximity and fleet capability make Precision a versatile provider of high performance, high value services to its customers. Precision’s fleet can drill virtually all types of on-shore conventional and unconventional oil and natural gas wells in North America. Precision’s service rigs provide completion, workover, abandonment, well maintenance, high pressure and critical sour gas well work and well re-entry preparation across the WCSB. The rigs are supported by three field locations in Alberta, two in Saskatchewan, one in Manitoba and one in British Columbia. Snubbing units complement traditional natural gas well servicing by allowing customers to have work done on wells while they are pressurized and production has been suspended. Precision has two types of snubbing units – rig assist and self-contained. Self-contained units do not require a service rig on site and are capable of snubbing and performing many other well servicing procedures. Inventory of Ancillary Equipment Precision has a large inventory of equipment, including portable top drives, loaders, boilers, tubulars and well control equipment, to support its fleet of drilling and service rigs to meet customer requirements. Precision also maintains an inventory of key rig components to minimize downtime in the event of equipment failures. In support of drilling rig operations, LRG Catering supplies meals and provides accommodation for rig crews at remote worksites. Terra Water Systems plays an essential role in providing wastewater treatment services as well as potable water production plants for LRG Catering and other camp facilities. Precision Rentals supplies customers with an inventory of specialized equipment and wellsite accommodations. Safety, Environmental and Employee Wellness Programs Safety, environmental stewardship and employee wellness is critical for Precision and its customers. The focus on working safely is one of Precision’s most enduring values. The goal of Target Zero – Precision’s safety vision for eliminating workplace incidents – is derived from a fundamental belief that all injuries can be prevented. In 2009, 331 of Precision’s drilling rigs and 209 of Precision’s service rigs achieved Target Zero. Precision continues to embrace technological advancements which make operations safer. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 15 Well-maintained Equipment Precision reinvests capital to sustain and upgrade existing property, plant and equipment. Equipment repair and maintenance expenses are benchmarked to activity levels in accordance with Precision’s maintenance and certification programs. Precision employs systems to track key preventative maintenance indicators for major rig components to record equipment performance history, schedule equipment certifications, reduce downtime and allow for better asset management. Precision benefits from internal services for equipment certifications and component manufacturing provided by Rostel Industries and for standardization and distribution of consumable oilfield products through Columbia Oilfield Supply in Canada and Grey Wolf Supply in the United States. U P G R A D E C AP ITA L S P EN DIN G Upgrade capital spending is tied to utilization levels. Upgrade Spending per Service Rig Utilization Hour Upgrade Spending per Drilling Rig Operating Day 1,200 1,000 800 600 400 200 y a d n o i t a z i l i t u g i r g n i l l i r D / $ 50 40 30 20 10 r u o h g n i t a r e p o g i r e c i v r e S / $ Source: Precision 2005 2006 2007 2008 2009 Upgrade capital spending has been reduced over the past three years as activity has been overweighted to high capability equipment and challenging conditions have limited economics associated with upgrade opportunities. Precision continues to upgrade essential elements like tubulars and engines on drilling rigs and the freestanding of certain service rigs. Employees As a service company, Precision is only as good as its people. An experienced, competent crew is a competitive strength and is highly valued by customers. To recruit field employees, Precision uses centralized personnel hiring, orientation and training programs in Canada. In the United States, these functions are managed on a more decentralized basis to align with regional labour and customer service requirements. Precision works to ensure its ability to meet future field personnel requirements through programs like its “Toughnecks” recruiting program. Information Systems Precision’s commitment to maintain a fully integrated enterprise-wide reporting system has improved business performance through real-time access to information across all functional areas. All of Precision’s divisions operate on a common integrated system using standardized business processes for finance, payroll, equipment maintenance, procurement and inventory control. Precision continues to invest in information systems that provide competitive advantages. Electronic links between field and financial systems provide accuracy and timely processing. This repository of rig data improves response time to customer enquiries. Rig manufacturing projects benefit from scheduling and budgeting tools as economies of scale can be identified and leveraged as construction demands increase. 16 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S KEY PERFORMANCE DRIVERS Customer economics are dictated by the current and expected margin between the price at which hydrocarbons are sold and the cost to find and develop those products. Some of the key business, customer and industry indicators that Precision monitors are: Safety Management Precision’s culture is built on the foundation of a Target Zero attitude. Precision believes that the workplace and organization can be free from injuries, equipment damage and adverse environmental impact. Safety performance is a fundamental contributor to operating performance and the financial results Precision generates. Safety is tracked through an industry standard recordable frequency statistic which is measured to benchmark successes and identify areas for improvement. Precision has continued to improve its safety management by tracking and measuring all injuries regardless of severity. Even minor injuries can be a leading indicator for the potential of a more serious incident. Environmental Management Precision has long been aware of the necessity to develop key solutions in order to minimize energy waste and, through the use of AC Electric power generation and variable frequency drive technologies, Precision achieves efficiency over conventional methods. Precision’s rigs are equipped with heat generation equipment which allows a higher energy of heat output per amount of energy used, in accordance with more efficient heat distribution during winter months, while providing flexible heat dissipation in warmer months. Precision has always been a leader in vertical integration and committed to improving operations. This includes retrofit power applications which are equipped with higher efficiency engines for maximum effectiveness. Precision’s equipment, supplies, and technology are continually reviewed to improve life cycles, reduce energy, and lessen the impact of disposal. Management of byproducts in daily operations is essential to the quality of lives for all individuals, and as part of its “down to earth” approach, Precision is aware of the critical importance that must be placed on the issues of climate change and atmospheric disturbance. Precision is addressing this issue of climate change through feasibility studies on the use of natural gas injection and exhaust treatment systems on diesel engines, which effectively reduces the CO2 levels released into the atmosphere. At the same time, we participate in the recycling of all oils used, and have implemented our own spill containment devices for use under equipment and around areas of high exposure. Our electric rigs can also be modified to function on “high-line power” allowing for zero local emissions. Precision is committed to developing solutions that support a sustainable society, which includes research on alternative methods for fuel types in power and heat generation, “reduced footprint” and “zero disturbance” rig designs, developing waste energy recovery systems and reduced move loads per rig. Operating Efficiency Precision maximizes the efficiency of operations through equipment proximity to work sites, operating practices and versatility. Reliable and well maintained equipment minimizes downtime and non-productive time during operations. Information is gathered from daily drilling log records stored in a database and analyzed to measure productivity, efficiency and effectiveness. This analysis of downtime is integral as a measure of operating effectiveness. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 17 Key factors which contribute to lower customer well costs are: (cid:0) Mechanical downtime is minimized through preventative maintenance programs, detailed inspection processes, an extensive fleet of strategically placed spare equipment, an in-house supply chain, and regular equipment upgrades; and (cid:0) Non-productive time, or move, rig-up and rig-out time, which is minimized by decreasing the number of truck loads per rig, using lighter truck loads, and using mechanized equipment for safer and quicker rig operations. Customer Demand Precision’s fleet is geographically dispersed to meet customer demands. Relationships with customers, industry knowledge and new well licenses provide Precision with the information necessary to evaluate its marketing strategies. The ability to provide customers with some of the most innovative and advanced rigs in the industry increases the value of the rig to the customer as they can reduce total well cost. Industry rig utilization statistics are also tracked to evaluate Precision’s performance against competitors. Workforce Precision closely monitors crew availability for field operations. Precision focuses on providing a safe and productive work environment, opportunities for advancement and added wage security through programs to retain employees. Precision relies heavily on its safety record and reputation to attract and retain employees as industry manpower shortages are often experienced in peak operating periods. In 2008, the successful recruiting program, Toughnecks, was initiated to help mitigate these issues. Financial Performance Precision maximizes revenue without sacrificing operating margins. Key financial information is unitized on a per day or per hour basis and compared to established benchmarks and past performance. Precision evaluates the relative strength of its financial position by monitoring its working capital and debt ratios. The Company’s 2009 focus was to reduce long-term debt while preserving strong profit margins. Returns on capital employed are monitored and incentive compensation is linked to returns generated compared to established benchmarks. Specific measures, which represent in summary form the effectiveness of the factors above, are used to reward executives and eligible employees through incentive compensation plans. These measures include: (cid:0) Safety performance – total recordable incident frequency per 200,000 man-hours: Measure against prior year performance and current year industry performance in Canada and the United States, as applicable. (cid:0) Operational performance – rig down time for repair as measured by time not billed to customer: Measure against predetermined target of available billable time. (cid:0) Key field employee retention – senior field employee retention rates: Measure against predetermined target of retention. (cid:0) Financial performance – return on capital employed calculated as a percentage of operating earnings (before non- cash decommissioning charges) divided by total assets less current liabilities: Measure against predetermined target percentage. (cid:0) Financial performance – unit value performance for year against industry peer group, adjusted for dividends or distributions. Measure against predetermined selection of competitors in peer group. 18 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S CAPITAL AND LIQUIDITY MANAGEMENT The oilfield services business is inherently cyclical in nature. Precision employs a disciplined approach to minimize costs through operational management practices and a variable cost structure, and to maximize revenues through term contract positions with a focus of maintaining a strong balance sheet. This operational discipline provides Precision with the financial flexibility to capitalize on strategic acquisition and internal growth opportunities at all points in the business cycle. Operating within a highly variable cost structure, Precision’s upgrade and maintenance capital expenditures are tightly governed by and highly responsive to activity levels with additional cost savings leverage provided through Precision’s internal manufacturing and supply divisions. Expansion capital for new rig build programs require 2 – 5 year term contracts in order to mitigate capital recovery risk. Until Precision has better visibility of a recovery within the oilfield services sector capital expenditures will be limited to $75 million in 2010. In managing foreign exchange risk, Precision matches the currency of its debt obligations with the currency of the supporting operations cash flows. Interest rate risk is minimized through hedging activities and by reducing debt. Precision expects to remain in compliance with financial covenants under its secured facility and expects to have complete access to credit lines during 2010. As at December 31, 2009 the Trust complied with the covenants under the secured facility. Precision successfully amended certain financial covenant terms of the secured facility to provide greater flexibility. Due to the fact that attractively priced term contracts are expiring and the spot market and utilization, while improving, have not returned to prior levels, rolling 12 month EBITDA performance may be lower over coming quarters, Precision expects to carry significant cash to preserve optimal liquidity. The Trust will consider further voluntary long-term debt reduction as industry fundamentals stabilize and operating cash flow forecasts become clear. Access to certain capital markets, especially the United States high yield debt market, have opened considerably over the past three quarters and Precision may consider opportunities to gain greater financial flexibility and lower cost of debt over the current blended cost of approximately 8.4%. Precision began 2009 with a US$1.2 billion senior secured credit facility (the “Secured Facility”) that was guaranteed by the Trust and was comprised of US$800 million of term loans and a US$400 million revolving facility and a US$400 million unsecured bridge credit facility (the “Unsecured Facility” and, together with the Secured Facility, the “Credit Facilities”) that was also guaranteed by the Trust. The Credit Facilities funded the cash portion of the acquisition and refinanced the pre-closing Precision bank debt and certain pre-closing debt obligations of Grey Wolf. The Unsecured Facility was used in the repurchase of US$262 million principal amount of Grey Wolf convertible notes tendered for repurchase by holders under a change of control offer made in the first quarter of 2009. In April 2009, Precision completed a private placement of $175 million principal amount of 10% senior unsecured notes (the “Senior Notes”). The proceeds from the issuance of the Senior Notes were used to reduce the obligations of Precision under the Unsecured Facility. During the second quarter of 2009, Precision fully repaid the Unsecured Facility and completed syndication of the Secured Facility. As at December 31, 2009 after giving effect to payments, prepayments, commitment reductions and reallocations between the Term Loan A Facility and the Term Loan B Facility during the year the Secured Facility consisted of: (cid:0) a term loan A facility in an aggregate principal amount of $289 million (the “Term Loan A Facility”); (cid:0) a term loan B facility in an aggregate principal amount of $422 million (the “Term Loan B Facility”); and (cid:0) a revolving credit facility in the amount of US$260 million (the “Revolving Credit Facility”). P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 19 Secured Facility The Secured Facility contains a number of affirmative covenants as well as a number of covenants that, among other things, restrict, subject to certain exceptions, the Trust’s, Precision’s and their subsidiaries’ ability to: (i) incur additional indebtedness; (ii) sell assets; (iii) pay dividends and distributions (including by the Trust to Unitholders) or purchase the Trust’s, Precision’s or their subsidiaries’ capital stock or trust units; (iv) make investments or acquisitions; (v) incur liens on their assets; (vi) enter into mergers, consolidations or amalgamations; and (vii) make capital expenditures. The following is a summary of the material terms of the Secured Facility: (cid:0) a maximum total leverage ratio of 3.00 to 1.00 as at the last day of any period of four consecutive fiscal quarters of the Trust, except that such maximum ratio is 3.50 to 1.00 for any such period ending after December 31, 2009 and on or prior to December 31, 2011; (cid:0) a minimum interest coverage ratio of 3.00 to 1.00 for any period of four consecutive fiscal quarters of the Trust, except that such minimum ratio is 2.75 to 1.00 for any such period ending after December 31, 2009 and on or prior to December 31, 2011; (cid:0) a minimum fixed charge coverage ratio for any period of four consecutive fiscal quarters of the Trust beginning March 31, 2009 of: (i) 1.00 to 1.00 for any such period ending on or prior to December 31, 2010; and (ii) 1.05 to 1.00 for any such period ending after December 31, 2010; (cid:0) the following amounts are required to be used as prepayments of the term loans: (i) 100% of the net cash proceeds of any incurrence of debt by the Trust, Precision or their subsidiaries (subject to certain exceptions); (ii) 100% of the net cash proceeds of certain sales or other dispositions of any assets belonging to the Trust, Precision or their subsidiaries, except to the extent the Trust, Precision or their subsidiaries use the proceeds from the sale or disposition to acquire, improve or repair assets useful in their business within a specified period; and (iii) 75% of the Trust’s annual excess cash flow, which percentage will be reduced to 50%, 25% and 0% if the Trust achieves and maintains a consolidated leverage ratio of less than 2.00 to 1.00, 1.25 to 1.00, and 0.75 to 1.00, respectively. In addition to mandatory prepayments, Precision has the option to prepay the loans under the Secured Facility generally without premium or penalty, other than customary “breakage” costs for Eurodollar rate loans; (cid:0) limits on distributions based on 20% of the Trust’s operating cash flow before changes in working capital, provided that 50% of operating cash flow generated in excess of certain base case projections will also be permitted to be paid as distributions, subject to an overall cap of 30% of aggregate operating cash flow before changes in working capital; (cid:0) covenants that limit the Trust’s capital expenditures above an agreed base-case, allowing for certain exceptions; and (cid:0) the Trust, Precision and their material subsidiaries organized in Canada or the United States (other than certain excluded subsidiaries) and each other subsidiary that becomes a party to the collateral documents (collectively, the “Subsidiary Guarantors”) have pledged substantially all of their tangible and intangible assets (with certain exceptions) that are located in Canada or the United States as collateral, secured by a perfected first priority lien, subject to certain permitted liens. In addition, the Trust and the Subsidiary Guarantors have guaranteed the obligations of Precision under the Secured Facility. The Secured Facility also contains customary affirmative covenants and events of default. The interest rate on loans under the Secured Facility denominated in United States dollars is, at the option of Precision, either a margin over an adjusted United States base rate (the “ABR rate”) or a margin over a Eurodollar rate (“libor”). The interest rate on loans denominated in Canadian dollars is, at the option of Precision, a margin over the Canadian prime rate or a margin over the bankers’ acceptance rate. Certain of the margins on the Revolving Credit Facility are subject to reduction based upon a leverage test. 20 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S The Revolving Credit Facility provides for a commitment fee of 0.60% (subject to reduction based on a leverage test) on the unused portion; a fee on the outstanding amount of the letters of credit denominated in United States dollars equal to the margin applicable to the Eurodollar rate; and a fee on the outstanding amount of the letters of credit denominated in Canadian dollars equal to the margin applicable to the bankers’ acceptance rate (subject to reduction for non-financial letters of credit). Up to US$200 million of the Revolving Credit Facility is available for letters of credit in United States dollars and/or Canadian dollars. During the second quarter of 2009, Precision entered into an interest rate swap arrangement to fix the libor rate at 1.7% on US$250 million of the Term Loan A Facility (with scheduled reductions in the balance through September 2013) and paid US$2.1 million for a libor interest rate cap of 3.25% on US$350 million of the Term Loan B Facility (with scheduled reductions in the balance through December 2013). The net amount owing under the interest rate derivative contracts is settled quarterly. At December 31, 2009 the change in fair value of these interest rate derivative contracts was $0.4 million. The Term Loan A Facility is repayable in quarterly installments in aggregate annual amounts equal to 10% of the principal amount in 2010 and 2011, 15% of the principal amount in 2012 and 2013, with the balance payable on December 23, 2013, the final maturity date. Due to prepayments made in 2009 the required principal payment for 2010 is nominal. The Term Loan B Facility is repayable in quarterly installments in an aggregate annual amount equal to 5% of the principal amount (after giving effect to reallocations of amounts between the Term Loan A Facility and the Term Loan B Facility) with the balance payable on September 30, 2014, the final maturity date. Due to the prepayments made in 2009 the required principal payment for 2010 is nil. Unsecured Senior Notes The unsecured Senior Notes, issued on April 22, 2009, have an eight-year term, with one-third of the initial outstanding principal amount payable on each of the 6th, 7th and 8th anniversaries of the closing date of the private placement. Interest on the Senior Notes is 10% per annum, payable quarterly in arrears, provided that Precision is able, in certain circumstances, to defer the payment of that interest for as much as two years, in which case the interest rate is increased to 12% and interest becomes payable on both the principal amount of the Senior Notes and the amount of the deferred interest, until the deferred interest is paid in full. The Senior Notes are unsecured and have been guaranteed by the Trust and each subsidiary of the Trust that guaranteed the Secured Facility. The terms of the Senior Notes contain a number of covenants that, among other things, restrict, subject to certain exceptions, the Trust’s, Precision’s and their subsidiaries’ ability to: (i) incur additional indebtedness; (ii) sell assets; (iii) pay dividends and distributions (including by the Trust to Unitholders) or purchase the Trust’s, Precision’s or their subsidiaries’ capital stock or trust units; (iv) make investments or acquisitions; (v) incur liens on their assets; (vi) enter into mergers, consolidations or amalgamations; and (vii) make capital expenditures. The Senior Notes also contain customary affirmative covenants and events of default. Terms of the Senior Notes also require Precision to use a specified percentage of excess cash flow to repay indebtedness under the Secured Facility in circumstances where the Trust’s consolidated debt to capitalization ratio (following the conversion of the Trust to a corporation) as at the last day of any fiscal year is in excess of 0.30 to 1.00, in addition to the prepayments from excess cash flow required to be made under the Secured Facility. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 21 General The terms of the documents governing the Credit Facilities contain provisions that in effect ensure that the lenders have priority as to payment over the unitholders in respect to the assets and income of the Trust and its subsidiaries. Therefore, under certain conditions, amounts due and owing to the lenders under the Credit Facilities must be paid before any distributions can be made to unitholders. As at December 31, 2009, approximately $711 million was outstanding under the Secured Facility and approximately $175 million was outstanding under the Senior Notes. The Revolving Credit Facility may be redrawn by Precision in the future to fund capital expenditures or for other corporate purposes. During 2009 the Trust generated cash from continuing operations of $505 million and the issuance of Trust units for net proceeds of $413 million. The cash generated was used to purchase property plant and equipment net of disposal proceeds and related non-cash working capital of $204 million, repay long-term debt of $565 million, pay additional finance charges of $22 million, pay an income tax reassessment of $7 million, and make cash distributions to unitholders of $27 million. This was offset by a $24 million unrealized foreign exchange loss on holding foreign cash. The Trust exited 2009 with a long-term debt to long-term debt plus equity ratio of 0.22 compared to 0.37 in 2008 and a ratio of long-term debt to cash provided by continuing operations of 1.48 compared to 3.98 in 2008. In addition to the Secured Facility and the Senior Notes, Precision also has an uncommitted operating facility of $25 million which is utilized for working capital management and the issuance of letters of credit. Precision’s contractual obligations are outlined in the following table: Payments Due by Period (Stated in thousands of Canadian dollars) Total Less Than 1 Year 1 – 3 Years 4 – 5 Years After 5 Years Long-term debt $ 885,984 $ 223 $ 108,580 $ 602,181 $ 175,000 Interest on long-term debt 350,367 74,619 144,825 109,060 21,863 Rig construction 32,963 – 32,963 – – Operating leases 27,665 11,034 11,879 3,190 1,562 Contractual incentive plans (1) 23,606 9,028 14,578 – – Total contractual obligations $ 1,320,585 $ 94,904 $ 312,825 $ 714,431 $ 198,425 (1) Includes amounts not yet accrued at December 31, 2009 but payable at the end of the contract term. Unit based compensation amounts disclosed at year-end unit price. Precision has multiple long-term incentive plans (“LTIP”) which compensate officers and key employees through cash payments at the end of a stated term. Outstanding unit data March 10, December 31, December 31, December 31, 2010 2009 2008 2007 Trust units 275,516,778 275,516,778 160,042,065 125,587,919 Exchangeable LP units 118,820 118,820 151,583 170,005 Total units outstanding 275,635,598 275,635,598 160,193,648 125,757,924 Deferred Trust units outstanding 290,732 290,732 54,543 18,280 Warrants outstanding 15,000,000 15,000,000 – – Trust unit options outstanding 3,641,200 1,787,700 – – In 2009 cash distributions declared were $6.4 million or $0.04 per diluted unit, a decrease of $194 million or $1.52 per diluted unit from the previous year. 22 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S In February 2009 Precision announced the suspension of cash distributions for an indefinite period. The suspension of distributions was taken in response to lower financial operating performance and allowed Precision to increase debt repayment capability and balance sheet strength. Precision initiated a number of cost reduction and cash generation plans in 2009 designed to strengthen its capability to reduce net long-term debt and improve its underlying credit quality and capital structure. The near-term management strategy involves retaining sufficient funds from available distributable cash to repay debt and finance upgrade capital expenditures as well as working capital needs. Planned asset growth will generally be financed through existing debt facilities or cash retained from continuing operations. In February 2010, Precision announced its intention to convert to a growth-oriented corporation (the “Conversion”) pursuant to a plan of arrangement under the Business Corporations Act (Alberta). Precision anticipates seeking approval from unitholders in conjunction with its 2010 annual and special meeting of unitholders (the “Meeting”) to be held May 11, 2010, and, if approved by the unitholders, expects to complete the Conversion by May 31, 2010. Years ended December 31, (Stated in thousands of Canadian dollars) 2009 2008 2007 Cash provided by continuing operations (A) $ 504,729 $ 343,910 $ 484,115 Net earnings (B) $ 161,703 $ 302,730 $ 345,776 Distributions declared (C) $ 6,408 $ 224,688 $ 276,667 Excess of cash provided by operations over distributions declared (A-C) $ 498,321 $ 119,222 $ 207,448 Excess of net earnings over distributions declared (B-C) $ 155,295 $ 78,042 $ 69,109 (Stated in thousands of Canadian dollars except per unit amounts) 2009 2008 2007 Units outstanding 275,635,598 160,193,648 125,757,924 Year-end unit price (1) $ 7.65 $ 10.07 $ 15.09 Units at market $ 2,108,612 $ 1,613,150 $ 1,897,687 Long-term debt 748,725 1,368,349 119,826 Less: Working capital (320,860) (345,329) (140,374) Enterprise value $ 2,536,477 $ 2,636,170 $ 1,877,139 (1) As per the Toronto Stock Exchange. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 23 Precision Drilling Trust consoliDAteDFinAnciAlResults MD&A CONSOLIDATED OVERVIEW Summary of Consolidated Statements of Earnings (Stated in thousands of Canadian dollars) Years ended December 31, 2009 2008 2007 Revenue: Contract Drilling Services $ 1,030,852 $ 809,317 $ 694,340 Completion and Production Services 176,422 308,624 327,471 Inter-segment elimination (9,828) (16,050) (12,610) 1,197,446 1,101,891 1,009,201 EBITDA: (1) Contract Drilling Services 397,467 359,137 329,351 Completion and Production Services 42,499 109,054 132,030 Corporate and Other (32,965) (31,655) (24,306) 407,001 436,536 437,075 Depreciation and amortization 138,000 83,829 71,604 Loss on asset decommissioning 82,173 – 6,722 Operating earnings (1) 186,828 352,707 358,749 Foreign exchange (122,846) (2,041) 2,398 Finance charges 147,401 14,174 7,318 Earnings from continuing operations before income taxes 162,273 340,574 349,033 Income taxes 570 37,844 6,213 Earnings from continuing operations 161,703 302,730 342,820 Discontinued operations, net of tax – – 2,956 Net earnings $ 161,703 $ 302,730 $ 345,776 (1) Non-GAAP measure. See page 48. 24 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S REVENUE A ND EBITDA (1) Precision operates in an inherently cyclical business. Revenue – Completion & Production Revenue – Contract Drilling EBITDA (1) – Completion & Production EBITDA (1) – Contract Drilling Source: Precision 2005 2006 2007 2008 2009 (1) Non-GAAP measure see page 48. CAPI TAL SPEND ING – TOTAL Precision has built 37 new Super Series® rigs over the past three years. Expansion Upgrade 1,600 1,200 800 400 s n o i l l i m $ 300 250 200 150 100 50 s n o i l l i m $ Source: Precision 2005 2006 2007 2008 2009 For the year ended December 31, 2009, net earnings were $162 million or $0.63 per diluted unit, a decrease of $141 million or 47% compared to $303 million or $2.23 per diluted unit for the year ended December 31, 2008. Net earnings decreased due to the loss from decommissioning rigs, increased financing charges and lower utilization rates throughout North America partially offset by growth in Precision’s rig fleet in the United States. Earnings were supported by high-margin term contracts and a $123 million foreign exchange gain, but these favourable factors did not offset lower earnings from the sharp reduction in equipment utilization and customer pricing compared to 2008 results. Rig utilization days for 2009 were 5% higher than the prior year due to fourth quarter 2008 acquisition growth in Precision’s United States operations. EBITDA for 2009 totaled $407 million, a 7% decrease from $437 million in 2008. The industry and Precision experienced declining utilization during 2009 as customer spending was dramatically reduced because of lower oil and natural gas prices. For the year, West Texas Intermediate (“WTI”) crude oil averaged US$61.83 per barrel versus US$99.67 in 2008 and Henry Hub natural gas averaged US$3.92 per MMBtu versus US$8.84 in 2008. On Canadian markets the average price for AECO natural gas one-year forward was $5.26 per MMBtu in 2009 compared to $8.74 in 2008. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 25 Currency exchange rates can impact commodity prices and have always had an impact on industry fundamentals in the Canadian market. Precision reports its financial results in Canadian dollars and currency translation can result in significant foreign exchange gains or losses on operations outside Canada and United States dollar denominated monetary positions. At December 31, 2009 Precision reported a U.S. dollar net monetary liability position of $570 million. During 2009 Precision reported a $123 million foreign exchange gain as a result of the Canadian dollar appreciating 17% against the U.S. dollar. During 2009 there were about 8,250 wells drilled in western Canada on a rig release basis, a 50% decline from the 16,441 drilled in 2008, while total industry drilling operating days decreased by 42% to about 78,000. The average industry drilling operating days per well in 2009 was 9.5 compared to 8.2 in 2008. In the United States, for 2009, a total of approximately 36,250 industry wells were drilled representing a 38% decrease from the 58,229 wells drilled in 2008. Quarterly Financial Summary (Stated in thousands of Canadian dollars, except per diluted unit amounts) Year ended December 31, 2009 Q1 Q2 Q3 Q4 Year Revenue $ 448,445 $ 209,597 $ 253,337 $ 286,067 $ 1,197,446 EBITDA (1) 169,387 59,260 85,739 92,615 407,001 Net earnings 57,417 57,475 71,696 (24,885) 161,703 Per diluted unit (2) 0.28 0.22 0.25 (0.09) 0.63 Cash provided by operations 201,596 212,554 19,948 70,631 504,729 Distributions to unitholders – declared $ 6,408 $ – $ – $ – $ 6,408 Year ended December 31, 2008 Q1 Q2 Q3 Q4 Year Revenue $ 342,689 $ 138,514 $ 285,639 $ 335,049 $ 1,101,891 EBITDA (1) 147,347 35,574 118,820 134,795 436,536 Net earnings 106,266 21,739 82,349 92,376 302,730 Per diluted unit (2) 0.79 0.16 0.61 0.66 2.23 Cash provided by operations 57,307 200,458 3,241 82,904 343,910 Distributions to unitholders – declared $ 49,046 $ 49,045 $ 49,046 $ 77,551 $ 224,688 (1) Non-GAAP measure. See page 48. (2) Net earnings per diluted unit have been adjusted to reflect the rights offering completed in the second quarter of 2009. See Note 18 to the audited consolidated financial statements. The Canadian drilling industry is subject to seasonality with activity peaking during the winter months in the fourth and first quarters. As temperatures rise in the spring, the ground thaws and becomes unstable. Government road bans severely restrict activity in the second quarter in Canada before equipment is moved for summer drilling programs in the third quarter. These seasonal trends typically lead to quarterly fluctuations in operating results and working capital requirements. In contrast the activity in the United States is not subject to the same level of seasonal interruptions and therefore operating results and working capital fluctuations are more subtle. 26 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S FOURTH QUARTER 2009 For the fourth quarter ended December 31, 2009 Precision recorded a net loss of $25 million or $0.09 per diluted unit compared to net earnings of $92 million or $0.66 per diluted unit in the fourth quarter of 2008. During the fourth quarter Precision decommissioned 38 drilling rigs, 30 well servicing rigs and nine snubbing units resulting in a non-cash loss on asset decommissioning of $82 million and a net loss per diluted unit after tax of $0.20. Revenue of $286 million in the fourth quarter was 15% lower than the prior year period. The decrease was due to low natural gas prices that led to a sharp reduction in the demand for drilling and servicing of natural gas wells. The decrease was partially mitigated by Precision’s 2008 expansion initiatives through organic and acquisition growth in the United States onshore contract drilling rig market. Precision marketed an average United States fleet of 159 drilling rigs during the fourth quarter of 2009 as compared to a fleet of 40 drilling rigs in 2008. Revenue in Precision’s Canadian Contract Drilling Services division decreased 37% while revenue declined 38% in the Canadian-based Completion and Production Services segment compared to the fourth quarter of 2008. The mix of drilling rigs under term contracts and on technically advanced well-to-well programs supported relatively strong average rig dayrate results in the fourth quarter of 2009. Drilling rig utilization days (spud to rig release plus move days) in Canada during the fourth quarter of 2009 were 6,595, a decrease of 27% compared to 9,066 in 2008. Drilling rig activity for Precision in the United States was 82% higher than the same quarter of 2008 due to acquisition growth in December 2008. Prior to the acquisition of Grey Wolf, Precision did not have any drilling rigs operating internationally in the fourth quarter of 2008 compared to 172 utilization days in the current quarter from operations in Mexico. Service rig activity declined 24% from the prior year period, with the service rig fleet generating 60,108 operating hours in the fourth quarter of 2009 compared with 79,507 hours in 2008 for utilization of 29% and 38%, respectively. The reduction was the result of lower service rig demand due to decreased drilling activity and spending on production maintenance of existing wells. The Trust reported EBITDA for the fourth quarter of $93 million compared with $135 million for the fourth quarter of 2008. Consistent with the previous quarter, Precision’s term contract position, a highly variable operating cost structure and economies achieved through vertical integration of the supply chain and maintenance facilities served to limit the declines. In the Contract Drilling Services segment, revenue for the fourth quarter of 2009 decreased by 8% to $239 million while EBITDA decreased by 24% to $89 million compared to the same period in 2008. The decrease in revenue was due to lower activity and dayrates partially offset by acquisition growth in late December 2008. Accordingly, the decline in EBITDA was due to lower rig utilization and lower customer pricing, partially mitigated by Precision’s strong term contract position. The reduction was further mitigated through fixed cost reductions and vertical business support in Canada, aided by the addition of supply chain management in United States operations during the second half of 2009. During the fourth quarter the Contract Drilling Services segment recognized a loss of $68 million related to the decommissioning of 38 drilling rigs. Depreciation for the quarter was $14 million higher than 2008 due to the increase in United States activity and asset mix associated with higher performance Tier I and II rig utilization and acquisition growth. The segment applies the unit of production method in calculating rig depreciation expense. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 27 In the Completion and Production Services segment, revenue for the fourth quarter of 2009 decreased by 38% from the comparable quarter of 2008 to $49 million while EBITDA declined by 51% to $13 million. The decrease in revenue and EBITDA is attributed to the decline in industry activity as customers reduced spending in response to sharply lower oil and natural gas commodity prices. Service rig activity declined 24% from the prior year period, with the service rig fleet generating 60,108 operating hours in the fourth quarter of 2009 compared with 79,507 hours in 2008 for utilization of 29% and 38%, respectively. The reduction was the result of lower service rig demand due to decreased drilling activity and spending on maintenance of existing wells. New well completions accounted for 28% of service rig operating hours in the fourth quarter compared to 36% in the same quarter in 2008. Well completions in Canada in the fourth quarter were down 75% from the same quarter in 2008. In the fourth quarter the Completion and Production Services segment recorded a $14 million loss related to the decommissioning of 30 well servicing rigs and nine snubbing units. Depreciation in the fourth quarter of 2009 was higher than the prior year period due to a gain on disposal of property recorded in 2008. The segment applies the unit of production method in calculating well servicing rig depreciation expense. Total operating costs increased from 54% of revenue in the fourth quarter of 2008 to 59% in 2009 due to an increase in United States based turnkey operations where the drilling contractor is responsible for a larger scope of costs with a commensurate increase in revenue, and the impact of fixed costs and lower average dayrates. General and administrative expense for the fourth quarter of 2009 was $24 million, an increase of $5 million over the prior year. The increase was due to the growth in the United States operation. Depreciation and amortization expense in the fourth quarter of 2009 was $35 million compared with $23 million in the same period on 2008. The increase is attributable to the increased United States contract drilling operation and depreciation recorded on a higher asset base. Net financing charges of $34 million for the fourth quarter of 2009 were $27 million higher than the prior year. Included in financing charges is $14 million for the amortization of deferred financing costs which includes an $8 million charge associated with the voluntary debt prepayments in the fourth quarter of 2009. Interest on long-term debt in the quarter was $21 million and reflected reduced debt levels that resulted from refinancing activities throughout the year. The increase in interest expense over the prior year is attributable to higher long-term debt associated with the acquisition of Grey Wolf. In the fourth quarter of 2009 capital expenditures were $14 million, a decrease of $85 million over the same period in 2008 and included $6 million on expansionary initiatives and $8 million on the upgrade of existing assets. 28 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S Precision Drilling Trust BusinesssegMentResults MD&A Precision’s operations are carried out in two segments: Contract Drilling Services and Completion and Production Services. The Contract Drilling Services segment includes land drilling services, camp and catering services, procurement and distribution of oilfield supplies and the manufacture and refurbishment of drilling and service rig equipment. The Completion and Production Services segment includes service rigs for well completion and workover services, snubbing services, wastewater treatment services and the rental of oilfield surface equipment, tubulars, well control equipment and wellsite accommodations. The Contract Drilling Services segment comprises a number of vertically integrated subsidiaries operating in the United States, Canada and internationally. These subsidiaries are engaged primarily in providing onshore well drilling services to exploration and production companies in the oil and natural gas industry. At December 31, 2009, the Contract Drilling Services segment comprised: (cid:0) 203 land drilling rigs in Canada; (cid:0) 146 land drilling rigs in the United States; (cid:0) two land drilling rigs in Mexico; (cid:0) one land drilling rig in Chile; (cid:0) 96 drilling and base camps in Canada; (cid:0) engineering, manufacturing and repair services primarily for Precision’s operations; and (cid:0) centralized procurement, inventory and distribution of consumable supplies primarily for Precision’s Canadian, United States and Mexico operations. The Completion and Production Services segment operates primarily in Canada, providing completion, workover and ancillary services to oil and natural gas exploration and production companies. At December 31, 2009, Precision’s Completion and Production Services segment comprised: (cid:0) 200 well completion and workover service rigs; (cid:0) 20 snubbing units; (cid:0) approximately 11,300 oilfield rental items including well control equipment, surface equipment, specialty tubulars and wellsite accommodation units; and (cid:0) 78 wastewater treatment units. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 29 Business lines are organized in two segments to align with the dynamics of customer markets and processes. This encompasses the initial drilling of oil and natural gas wells, Contract Drilling Services, and the subsequent completion and workover of wells to optimize production volumes, Completion and Production Services. These segments have been integrated with internal support infrastructure to optimize customer service delivery and lower costs. An integral element in Precision’s North American operations is vertical integration through internal supply procurement and distribution that supports rig operations and all other Precision businesses. This support serves to efficiently handle a high volume of transactions and channel supplier relationships to enhance product quality selection and standardization. Information system automation has streamlined the procurement, supply distribution and decision making process. Precision also has an equipment manufacturing, repair and certification division that supports rig operations. This division provides rig manufacturing capabilities and engineering to facilitate new rig construction and the upkeep of operating assets. Specialized machining, skilled tradesmen and management has allowed Precision to optimize its capital allocation through quality workmanship, project planning, retention of intellectual property and cost savings. Precision’s vertical integration is further complemented by rig manufacturing engineering in the drilling division. Rigs built by Precision are designed for greater safety and operating efficiency to deliver well cost savings to customers. High performance drilling rigs combine high mobility, automated pipe handling, advanced control systems, minimal environmental impact, and highly trained crews. CONTRACT DRILLING SERVICES Precision began operating in western Canada as a land drilling contractor in the 1950s. A combination of new equipment purchases and acquisitions over the last 21 years has expanded fleet capacity and added complementary businesses. For the past decade, Precision has been Canada’s largest oilfield services provider and with the acquisition of Grey Wolf in 2008 is the second largest North American land drilling contractor. Precision currently comprises 25% of the Canadian land drilling market, about 6% of the United States market and has an emerging international presence. Precision’s rigs are marketed in three classes: Tier I, Tier II and Tier III. Tier I drilling rigs are high performance, of newer design and manufacture, capable of drilling directionally or horizontally more efficiently, are highly mobile requiring fewer trucking loads and often include the following capabilities: highly mechanized tubular handling equipment; integrated top drive or top drive adaptability; advanced mechanical, silicone controlled rectifier (SCR), and AC power distribution and control efficiencies; electronic control of the majority of operating parameters; specialized drilling tubular; and high-capacity mud pumps. Tier I drilling rigs are better suited to meet the challenges of complex customer resource exploitation requirements in the North American shale and unconventional plays. Tier II drilling rigs are high performance rigs where new equipment and modifications have been applied to improve performance and enhance directional and horizontal drilling capability. Improvements include: some mechanization of tubular handling equipment; top drive adaptability; mechanical or SCR type power systems; increased hook load and or racking capabilities; upgraded power generating, control systems and other major components; and high-capacity mud pumps. Tier II rigs are usually less mobile than Tier I rigs. Tier III includes rigs which still provide an acceptable level of performance but would require major equipment upgrades to meet the criteria of a Tier II or Tier I rig. Tier III rigs are typically conventional mechanical rigs with limited mechanization and limited directional capability and are particularly well suited for less challenging drilling programs. 30 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S Rig tiers are not an indication that a rig from a different tier does not have the capabilities to provide an acceptable level of service but rather to distinguish among rigs where improvements have been effectively applied to provide an increased level of performance through the application of various advanced equipment and associated technologies. Following is a chart of Precision drilling rigs by tier classification as at December 31, 2009: Horsepower < 1000 1000-1500 >1500 Total Tier I 55 45 9 109 Tier II 72 44 24 140 Tier III 80 17 6 103 Total 207 106 39 352 Contract Drilling Financial Results (Stated in thousands of Canadian dollars, except where indicated) % of % of % of Years ended December 31, 2009 Revenue 2008 Revenue 2007 Revenue Revenue $1,030,852 $ 809,317 $ 694,340 Expenses: Operating 578,225 56.1 425,051 52.5 345,043 49.7 General and administrative 55,160 5.3 25,129 3.1 19,946 2.9 EBITDA (1) 397,467 38.6 359,137 44.4 329,351 47.4 Depreciation and amortization 118,889 11.5 57,076 7.1 40,660 5.9 Loss on asset decommissioning 67,794 6.6 – – 2,460 0.3 Operating earnings (1) $ 210,784 20.4 $ 302,061 37.3 $ 286,231 41.2 % Increase % Increase % Increase 2009 (Decrease) 2008 (Decrease) 2007 (Decrease) Number of drilling rigs (end of year) 352 (5.9) 374 52.7 245 1.7 Drilling utilization days (operating and moving): Canada 21,229 (38.4) 34,488 (0.2) 34,572 (32.3) United States 22,672 183.2 8,006 281.6 2,098 n/m International 710 346.5 159 n/m – – Drilling revenue per utilization day: Canada $ 17,824 8.6 $ 16,420 (2.5) $ 16,833 (6.5) United States (in US$) $ 19,882 (8.0) $ 21,610 (7.9) $ 23,473 (8.5) Drilling statistics: (2) Number of wells drilled 2,198 (45.9) 4,061 (13.9) 4,718 (23.7) Average days per well 8.6 13.2 7.6 16.9 6.5 (9.7) Number of metres drilled (000s) 3,316 (39.0) 5,440 (6.4) 5,813 (25.6) Average metres per well 1,509 12.6 1,340 8.8 1,232 (2.5) (1) Non-GAAP measure. See page 48. (2) Canadian operations only. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 31 2009 Compared to 2008 The Contract Drilling Services segment generated revenue of $1,031 million in 2009, 27% more than the $809 million in 2008. An increase in drilling activity resulting mainly from Precision’s acquisition in December 2008 of Grey Wolf was offset by lower customer demand on an industry wide basis and corresponding lower average day rates in both Canada and the United States. Operating earnings of $211 million decreased by $92 million or 30% from $302 million in 2008 and was 20% of revenue in 2009 compared to 37% in 2008. The decrease is primarily due to lower revenue and the decommissioning of 38 drilling rigs during the fourth quarter resulting in a non-cash charge to earnings of $68 million. Operating expenses were 56% of revenue in 2009 compared to 53% in 2008 mainly due product mix and the associated higher percentage of United States activity. General and administrative expense was higher in the year due to the full year impact of the Grey Wolf acquisition. Depreciation expense, most of which is calculated on the unit of production method, doubled over the prior year due to slightly higher overall utilization days and a mix towards Tier I and Tier II drilling rigs with a significantly higher cost base. Capital expenditures for the Contract Drilling Services segment in 2009 were $183 million and included $163 million to expand the underlying asset base and $20 million to upgrade existing equipment. The majority of the expansion capital was associated with Precision’s 2008 rig build program where 16 rigs were completed for operations in the United States and Canada. Canadian Drilling division revenues decreased $188 million or 33% to $378 million from $566 million in 2008. Low oil prices in the first quarter and depressed natural gas price throughout 2009 resulted in about 8,250 wells drilled in Canada, its lowest wells drilled since 1992. Although industry total well count fell by 50% last year, horizontal drilling held up as operators exploited tight oil and natural gas plays with horizontal well bores and multi-stage fractures. Precision’s Canadian 2009 year end rig count declined to 203 from 220 in 2008 due in part to the decommissioning of 26 Tier III rigs at year end. The industry drilling rig fleet was reduced to about 800 drilling rigs at the end of 2009 and operating day utilization decreased to 25%, a 17 percentage point decline. Industry operating days in Canada decreased to 78,005 mainly due to continued uncertainty about future natural gas commodity prices. Average drilling rig utilization day rates for Precision rigs in Canada increased by 9% in 2009. Proportionately more activity from Precision’s contract rigs and Tier I rigs which typically receive a dayrate premium was offset by competitive pricing in the spot market. Canadian Drilling operating earnings as a percent of revenue decreased by 12 percentage points to 25% of revenue in 2009 primarily due to the decommissioning of 26 rigs and lower customer demand. Normalized for the loss on asset decommissioning, higher dayrates combined with costs saving initiatives allowed for Canadian Drilling operating earnings percentage to be maintained. The United States drilling division revenues increased $418 million or 220% over 2008 to $608 million. Drilling rig activity was 183% higher in 2009 due to the acquisition growth in December 2008. Average drilling rig utilization day rates in the United States decreased 8% in 2009 from 2008. The decrease in rates was marginal due to a reduction in term contracted rigs and margin contributions from idle but contracted rigs. 32 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S EBITDA generated from United States operating activities of $216 million increased $124 million or 134% from $92 million in 2008 primarily due to an increase in activity from the rig fleet growth during 2008, primarily with the acquisition of Grey Wolf in December 2008. Operating expenses increased from 49% of revenue in 2008 to 59% in 2009. The increase was mainly due to higher maintenance and repair costs for the rig fleet compared to the relatively new rig fleet during 2008, fixed costs spread over lower activity levels and a decrease in average drilling rates due to a more competitive environment. LRG Catering activity and revenue fell by 44% and 40% respectively in 2009 as operators sought economic alternatives to on-site accommodations. To achieve greater cost control, LRG brought the purchasing and warehousing of its grocery items in-house. Rostel Industries and Columbia Oilfield Supply divisions provided valuable support, best measured by the efficiencies and contributions made to Precision through cost savings. Rostel’s expertise provided Precision control over rig construction and enhanced cost control. Columbia leveraged its volume purchasing advantage and supplier relationships to provide timely and reliable supplies to keep Precision’s rigs operating and allows Precision to standardize product use and quality. 2008 Compared to 2007 The Contract Drilling Services segment generated revenue of $809 million in 2008, 17% more than the $694 million in 2007. The increase was due to a nearly four-fold increase in our United States rig activity that was partially offset by lower than average day rates in both Canada and the United States. Operating earnings of $302 million increased $16 million or 6% from $286 million in 2007 and were 37% of revenue in 2008 compared to 41% in 2007. The increase is mainly due to greater United States activity. Capital expenditures for the Contract Drilling Services segment in 2008 were $203 million and included $163 million to expand the underlying asset base and $40 million to upgrade existing equipment. The majority of the expansion capital was associated with Precision’s 2008 rig build program where 18 rigs were being constructed for operations in the United States and Canada. Canadian Drilling division revenues decreased $16 million or 3% over 2007 to $566 million due to a decrease in customer demand mainly in the fourth quarter as the global economic slowdown took hold. Canadian Drilling operating earnings decreased by 14% over 2007 due to lower activity and pricing in the first half of 2008 and higher depreciation expense for the year due to a change in rig mix and higher cost base associated with high performance deeper rigs. The United States drilling division revenues increased $139 million or 273% over 2007 to $190 million. The increase was due to strong utilization and the addition of 17 rigs through organic growth and the inclusion of Grey Wolf for eight days in 2008. Drilling rig activity in 2008 was up 5,908 utilization days or 282% overall compared to 2007. United States operating earnings of $73 million increased $48 million or 192% from $25 million in 2007 primarily due to an increase in activity from the rig fleet growth during 2008. Operating expenses increased from 42% of revenue in 2007 to 49% in 2008. The increase was mainly due to higher maintenance and repair costs for the rig fleet compared to the relatively new rig fleet during 2007. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 33 COMPLETION AND PRODUCTION SERVICES Precision’s Completion and Production Services completes wells that have been drilled and provides maintenance services to wells that have been placed into production. The underlying well program parameters determine the type of service rig and ancillary services best suited to workover a particular well. Service rigs are versatile and capable of working on both oil and natural gas wells. Design and technological improvements have made equipment offerings more competitive through efficiency gains and wide market appeal to a broad range of well requirements. Precision’s service rigs and snubbing units each comprise about 20% of their respective Canadian markets. In addition to completing and servicing wells with rigs, the segment offers snubbing services to wells while pressurized, a broad mix of rental equipment and wastewater treatment for remote accommodations. The configuration of Precision Well Servicing’s Canadian fleet as at December 31 for the past four years is illustrated in the following table: Type of Service Rig Horsepower 2009 2008 2007 2006 Singles: Mobile 150-400 – 2 5 12 Freestanding mobile 150-400 94 97 94 92 Doubles: Mobile 250-550 28 42 43 44 Freestanding mobile 200-550 30 23 9 9 Skid 300-860 30 48 55 65 Slants: Freestanding 250-400 18 17 17 15 Total 200 229 223 237 A freestanding service rig lowers costs for customers through set up efficiency and minimal ground disturbance which reduces the risk of striking underground utilities. Completion and Production Services Financial Results (Stated in thousands of Canadian dollars, except where indicated) % of % of % of Years ended December 31, 2009 Revenue 2008 Revenue 2007 Revenue Revenue $ 176,422 $ 308,624 $ 327,471 Expenses: Operating 123,846 70.2 188,705 61.2 183,661 56.1 General and administrative 10,077 5.7 10,865 3.5 11,780 3.6 EBITDA (1) 42,499 24.1 109,054 35.3 132,030 40.3 Depreciation and amortization 17,186 9.7 22,966 7.4 27,159 8.3 Loss on asset decommissioning 14,379 8.2 – – 4,262 1.3 Operating earnings (1) $ 10,934 6.2 $ 86,088 27.9 $ 100,609 30.7 % Increase % Increase % Increase 2009 (Decrease) 2008 (Decrease) 2007 (Decrease) Number of service rigs (end of year) 200 (12.7) 229 2.7 223 (5.9) Service rig operating hours 207,361 (38.1) 335,127 (5.9) 355,997 (25.9) Revenue per operating hour $ 652 (7.9) $ 708 (3.0) $ 730 2.5 (1) Non-GAAP measure. See page 48. 34 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S 2009 Compared to 2008 The Completion and Production Services segment revenue decreased by $132 million to $176 million mainly due to the decline in industry activity as customers reduced spending in response to sharply lower oil and natural gas prices. Operating earnings decreased by $75 million or 87% and was 6% of revenue in 2009 compared to 28% in 2008 due mainly to lower service activity during the year and a $14 million charge for the decommission of 30 service rigs and nine snubbing units. Operating expenses increased from 61% of revenue in 2008 to 70% in 2009. On an hourly operating basis, costs increased due to higher crew wages and lower equipment utilization resulted in increased daily or hourly operating costs associated with fixed operating cost components. Depreciation expense for the year decreased 25% from the prior year due to lower operating activity. Capital spending in 2009 of $3 million, down 88% from $24 million in 2008, included capital to complete the construction of a service rig and two wastewater treatment units, and for service rig and snubbing unit upgrades. The Precision Well Servicing division revenue decreased by $102 million or 43% over 2008 to $135 million as operating rates moved downward in conjunction with reduced activity levels. Price decreases established in the first quarter of 2009 impacted operating rates for all of 2009. With a lag between the drilling and completion of a well, the industry reported 9,348 well completions in 2009, 52% lower than the 19,340 well completions in 2008. There are currently about 180,000 producing wells within the WCSB which has sustained an ongoing maintenance demand to ensure continuous and efficient production. Industry fleet capacity in 2009 was slightly lower with approximately 1,050 compared to about 1,100 rigs at the end of 2008. High industry capacity coupled with a significant decrease in well completions and lower workover activity kept market pricing competitive. There was also a rising number of wells where rig-less or coiled tubing methods are employed. Live Well Service division revenue for 2009 was $10 million as activity decreased by 52% over 2008 due to weak natural gas prices and a shift from customer demand away from rig-assist units to self-contained snubbing units. Precision Rentals division revenue decreased to $26 million, which was $15 million or 37% lower than 2008 as activity was impacted by lower drilling and well servicing activity. Each of Precision Rental’s three major product lines; surface equipment, tubulars equipment, and wellsite accommodations, experienced year-over-year declines in rates which was brought on by excess industry equipment and pricing pressures. The Terra Water Systems division generated revenue of $5 million in 2009 compared to $6 million in 2008, a decrease of 18%. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 35 2008 Compared to 2007 The Completion and Production Services segment revenue decreased by $19 million to $309 million mainly due to a decline in industry completion and production activity. Operating earnings decreased by $15 million or 14% and was 28% of revenue in 2008 compared to 31% in 2007 due mainly to lower service activity during the year. Operating expenses increased from 56% of revenue in 2007 to 61% in 2008. The margin decrease was primarily attributed to crew wage rate increases in October 2008 and lower equipment utilization which resulted in higher daily or hourly operating costs associated with fixed operating cost components. Capital spending in 2008 of $24 million, down 11% from $27 million in 2007, included $7 million for expansion capital and $17 million for the replacement of transporter trucks, doghouses, snubbing unit trucks, drill pipe for rental tanks and a new operating facility. Additionally, in the third quarter of 2008 six service rigs and support equipment were acquired from a third party for $16 million. The Precision Well Servicing division revenue decreased by $23 million or 9% over 2007 to $237 million as operating rates moved downward in conjunction with reduced activity levels. Price decreases established in the fourth quarter of 2007 impacted most of 2008 with an upward adjustment in the fourth quarter. Operating earnings decreased by 25% over 2007. Costs were higher due to increased crew wages and fuel costs. Capital expenditures in 2008 included the construction a new service rig, continuation of long-term plans to upgrade and standardize equipment and completion of a new operating facility. Live Well Service activity increased by 10% over 2007 with revenues of $24 million due to higher activity from self-contained units which generate higher operating rates than rig-assist snubbing units. In 2008, Live Well added a self-contained unit and a rack and pinion unit to the fleet. Precision Rentals generated revenues of $42 million, which was $3 million or 6% lower than 2007. Each of Precision Rental’s three major product lines experienced year-over-year revenue declines due to low utilization from excess industry capacity and lower pricing. The Terra Water Systems division generated revenue of $6 million in 2008 compared to $5 million in 2007, an increase of 28%. CORPORATE AND OTHER ITEMS 2009 Compared to 2008 Corporate and Other Expenses Corporate and other expenses were in-line with the prior year at $35 million. Foreign Exchange The foreign exchange gain for the current year was $123 million compared to a gain of $2 million in the prior year. The increase was the result of translation gains on United States dollar denominated debt and the weakening of the U.S. dollar relative to the Canadian dollar offset marginally by losses on the translation of foreign dollar denominated monetary assets. At the start of 2009, 92% of the long-term debt was denominated in U.S. dollars whereas as a result of repayments and refinancing through the year as at the end of 2009, 78% of the debt was denominated in U.S. dollars. Financing Charges Net financing charges of $147 million increased by $133 million compared to 2008. This increase was attributable to the higher average debt outstanding during 2008 compared to the prior year and the interest associated with the new credit facilities as part of the Grey Wolf acquisition completed December 23, 2008. Included in financing charges is the amortization of debt issue costs for $26 million compared to $1 million in 2008. 36 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S Income Taxes The Trust’s effective income tax rate, before enacted tax rate reductions, on earnings from continuing operations before income taxes was nil in 2009 compared to 11% in 2008. The year-over-year decrease in the effective income tax rate was largely due to a foreign exchange gains and income taxed at lower rates. The Trust incurs taxes to the extent there are certain provincial capital taxes, as well as taxes on the taxable income, of its underlying subsidiaries. In addition, future income taxes arise from differences between the accounting and tax basis of the Trust and its operating entities’ assets and liabilities. 2008 Compared to 2007 Corporate and Other Expenses Corporate and other expenses increased by $7 million or 43% from 2007 to $35 million. This increase was primarily due to a $4 million long-term incentive plan accrual in 2008 compared to a $4 million recovery in 2007. Increased foreign exchange losses on the translation of United States dollar denominated debt resulting from a strengthening United States dollar were incurred in 2008. Finance Charges Net finance charges of $14 million increased by $7 million compared to 2007. This reduction was primarily attributable to the higher average debt outstanding during 2008 compared to 2007 and the interest associated with the credit facilities as part of the Grey Wolf acquisition. Income Taxes The Trust’s effective income tax rate, before enacted tax rate reductions, on earnings from continuing operations before income taxes was 11% in 2008 compared to 8% in 2007. The comparatively low effective income tax rate was primarily a result of the shifting of the income tax burden of the Trust to its unitholders. The year-over-year increase in the effective income tax rate was largely a result of taxes associated with Precision’s United States operations. During 2007 the Government of Canada passed legislation to reduce the federal income tax rates to 15% by 2012. These enacted tax rate reductions resulted in a $22 million future tax recovery in 2007, with no comparable recovery in 2008. Discontinued Operations A $3 million gain, net of tax, on discontinued operations was recorded in 2007. The gain arose on the receipt of additional consideration associated with a 2005 business divestiture. RESULTS BY GEOGRAPHIC SEGMENT (Stated in thousands of Canadian dollars) Years ended December 31, 2009 2008 2007 Revenue: Canada $ 569,013 $ 909,001 $ 958,937 United States 608,109 189,796 51,082 International 23,748 4,686 – Inter-segment elimination (3,424) (1,592) (818) $ 1,197,446 $ 1,101,891 $ 1,009,201 Total Assets: Canada $ 1,639,046 $ 1,741,462 $ 1,651,920 United States 2,498,909 3,033,378 108,683 International 53,758 58,862 2,874 $ 4,191,713 $ 4,833,702 $ 1,763,477 P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 37 Precision Drilling Trust cRiticAlAccountingestiMAtes,neWAccountingstAnDARDs AnDinteRnAtionAlFinAnciAlRepoRtingstAnDARDs MD&A CRITICAL ACCOUNTING ESTIMATES This Management’s Discussion and Analysis of Precision’s financial condition and results of operations is based on Precision’s consolidated financial statements which are prepared in accordance with Canadian GAAP. These principles differ in certain respects from United States GAAP and these differences are described and quantified in Note 21 to the consolidated financial statements. The Trust’s significant accounting policies are described in Note 2 to the consolidated financial statements. The preparation of the financial statements requires that certain estimates and judgments be made that affect the reported assets, liabilities, revenues and expenses. These estimates and judgments are based on historical experience and on various other assumptions that are 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 and as the Trust’s operating environment changes. Following are the accounting estimates believed to require the most difficult, subjective or complex judgments and which are the most critical to Precision’s reporting of results of operations and financial positions. Allowance for Doubtful Accounts Receivable Precision performs ongoing credit evaluations of its customers and grants credit based upon past payment history, financial condition and anticipated industry conditions. Customer payments are regularly monitored and a provision for doubtful accounts is established based upon specific situations and overall industry conditions. Precision’s history of bad debt losses has been within expectations and generally limited to specific customer circumstances. However, given the cyclical nature of the oil and natural gas industry in Canada, the current state of debt and equity markets and the inherent risk of successfully finding hydrocarbon reserves, a customer’s ability to fulfill its payment obligations can change suddenly and without notice. In cases where creditworthiness is uncertain, services are provided on receipt of cash in advance, on receipt of a letter of credit, on deposit of monies in trust or services are declined. Impairment of Long-lived Assets Long-lived assets, which include property, plant and equipment, intangibles and goodwill, comprise the majority of Precision’s assets. The carrying value of these assets is periodically reviewed for impairment or whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. This requires Precision to forecast future cash flows to be derived from the utilization of these assets based upon assumptions about future business conditions and technological developments. Significant, unanticipated changes to these assumptions could require a provision for impairment in the future. During the fourth quarter of 2009, Precision completed its assessment and concluded that there was no impairment of the carrying value of goodwill. 38 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S Depreciation and Amortization Precision’s property, plant and equipment and its intangible assets are depreciated and amortized based upon estimates of useful lives and salvage values. These estimates may change as more experience is gained, market conditions shift or new technological advancements are made. Income Taxes The Trust and its subsidiaries follow the liability method which takes into account the differences between financial statement treatment and tax treatment of certain transactions, assets and liabilities. Future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Valuation allowances are established to reduce future tax assets when it is more likely than not that some portion or all of the asset will not be realized. Estimates of future taxable income and the continuation of ongoing prudent tax planning arrangements have been considered in assessing the utilization of available tax losses. Changes in circumstances and assumptions and clarifications of uncertain tax regimes may require changes to the valuation allowances associated with Precision’s future tax assets. The business and operations of Precision are complex and Precision has executed a number of significant financings, business combinations, acquisitions and dispositions over the course of its history. The computation of income taxes payable as a result of these transactions involves many complex factors as well as Precision’s interpretation of relevant tax legislation and regulations. Precision’s management believes that the provision for income tax is adequate. NEW ACCOUNTING STANDARDS New Canadian accounting standards were released in 2009 with an effective date of January 1, 2011 with early adoption permitted: (cid:0) Section 1582 “Business Combinations” will require most assets acquired and liabilities assumed, including contingent consideration to be measured at fair value and that all acquisition costs to be expensed. (cid:0) Section 1602 “Non-controlling Interests” will require that non-controlling interests be recognized as a separate component of equity and that net earnings be calculated without a deduction for non-controlling interest. (cid:0) Section 1601 “Consolidated Financial Statements” establishes standards for the preparation of consolidated financial statements. The Trust is currently evaluating the impact of the new Sections, 1582, 1602, and 1601 and will consider if the standards should be adopted in 2010. These new Canadian standards are aligned with International Financial Reporting Standards (IFRS) therefore early adoption would eliminate adjustments in the transition to IFRS. TRANSITION TO INTERNATIONAL FINANCIAL REPORTING STANDARDS Precision is required to report its financial results in accordance with IFRS from January 1, 2011, the changeover date set by Accounting Standards Board (AcSB). IFRS compliant comparative financial information for one year will be required on the effective date, therefore the transition date for adoption of IFRS is January 1, 2010. Good project management practices are essential for a successful transition. Precision has established an IFRS project team and a Steering Committee to oversee the work performed by the project team. The project team provides quarterly status updates to the Steering Committee and the Audit Committee of the Board of Directors. Key stakeholders within the company are kept informed of the project status via project reports and an internal newsletter. Training to the various groups impacted by the transition is being imparted on a formal and informal basis throughout the course of the project. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 39 A preliminary diagnostic assessment conducted by Precision had highlighted five key areas of impact to financial reporting namely; capital asset componentization; financial statement disclosure; provisions; asset impairments; and IFRS 1 “First Time Adoption of International Financial Reporting Standards” (“IFRS 1”). Additional assessments performed by the project team, determined that differences between Canadian GAAP and IFRS with respect to provisions does not have a significant impact to Precision’s financial reporting process as the IFRS standards exist at this time. It was further established that income tax standards under IFRS will have a relatively greater impact on Precision’s financial reporting process. With respect to the key areas of impact to Precision’s financial reporting process, following is a status update: Capital Assets Componentization Under IFRS, each separate component of an item of property, plant and equipment with a cost that is significant in relation to the total cost of the item shall be depreciated separately. Canadian GAAP provides no guidance on the cost of a component and the replacement of components, and is less specific than IFRS about the level at which component accounting is required. Under Canadian GAAP, Precision depreciated each major asset as one item. As an example, under Canadian GAAP Precision depreciates an entire drilling rig as one item whereas under IFRS Precision has identified three separate components which will be depreciated using the unit of production method but with separate and distinct lives. To accommodate the new component accounting requirement, modifications were made to the Precision’s Enterprise Resource Planning (ERP) system. All changes to the ERP system have been completed and tested. Precision will also implement a new idle asset depreciation policy to depreciate assets that are idle for a period of time. The parameters of the policy are currently being established. The change to componentization and an idle asset depreciation policy will result in an increase to depreciation and amortization expense which is currently being quantified. Accounting policy choice Under IFRS, an entity can choose either the cost model or the revaluation model as its accounting policy and shall apply that policy to an entire class of property, plant and equipment. Precision has opted for the cost model for recognition and measurement of ongoing asset transactions after its adoption of IFRS in 2011. In addition to the above accounting policy choice, IFRS 1 grants an optional election, whereby an entity can measure the carrying amount of an item of property, plant and equipment at the date of transition on the basis of fair value, to alleviate the need to rebuild historical records of property, plant and equipment as if IFRS provisions had always been used by Precision. Precision has opted to not use the fair value election and is rebuilding historical cost records under IFRS provisions. Asset qualification criteria Under IFRS, the qualification criterion for capital expenditure has now been expanded beyond betterment to include all material costs whereby future economic benefits will flow to the entity. Effectively, this requirement redefines Precision’s policy with respect to capital versus repairs and maintenance. The existing policy prohibits the replacement of existing equipment unless it qualifies as betterment. IFRS will require Precision to capitalize replacement parts and service costs except those that pertain to the day-to-day operation of the asset. 40 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S Financial Statement Disclosure With IFRS and Canadian GAAP both being principle based frameworks, there are minimal differences in the general principles for preparation of financial statements. However there are differences between classification of items and nature and extent of notes disclosures required under IFRS. IFRS prescribes minimum content requirements for balance sheet (called Statement of Financial Position) and also requires classification of expenses as either by nature or by function. Precision is currently reviewing the detailed requirements for presentation of financial statements under IFRS. Sample financial statements will be drafted thereafter and reviewed by the Steering Committee. Income Taxes In October 2009, after reviewing the numerous comment letters received from the constituents, the International Accounting Standards Board (IASB) decided not to finalize the income tax exposure draft into a new Income Taxes standard. Therefore, it is currently anticipated that the existing IAS 12 – Income Taxes standard will be applicable to Precision at adoption of IFRS. An impact assessment of differences between incomes taxes under Canadian GAAP and IFRS has been completed and is currently being analyzed to address the identified differences. Impairments The definition of an asset group under Canadian GAAP and IFRS is a key difference between the two standards. Under IFRS, a cash-generating unit (CGU) is the smallest group of assets that generates cash inflows from continuing use that largely are independent of the cash inflows of other assets or groups thereof. As a result of this, impairment testing under IFRS will be performed at a lower level in the entity as compared to Canadian GAAP. Precision’s individual assets do not have independent cash flows and there is a high degree of interchangeability between individual assets. Therefore, under IFRS Precision anticipates assessing impairment by grouping assets in various categories with each category defined as a CGU. There are a number of other differences between the actual impairment test under Canadian GAAP and IFRS. The most significant difference is that the asset impairment under IFRS test is one step based and it is discounted. The IFRS project team is finalizing Precision’s impairment test model, considering the requirements under IFRS. The new impairment model will first be used for testing asset impairment at the date of transition. IFRS 1 – First Time Adoption Generally on first time adoption of IFRS, an entity is required to retrospectively apply all IFRS standards. The process to restate all Canadian GAAP accounting records since inception of the entity into IFRS would be an enormous task. Recognizing this major impediment to adopting IFRS, the standard setters developed IFRS 1. This standard provides some relief from the full retrospective application in the form of mandatory and optional exemptions. Precision has identified the IFRS 1 elections and is completing the calculations to estimate the impact on the financial statements. A potentially significant election available relates to business combinations (IFRS 3). IFRS 1 allows Precision not to restate business combinations prior to the date of transition to IFRS or an earlier date as elected by Precision. There are a number of other optional elections available to Precision that are being assessed as part of the transition to IFRS. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 41 A summary of significant activities and deadlines within the plan along with their current status is as follows: Key Activity Deadlines/Milestones Status at December 31, 2009 Financial Statement Preparation: (cid:0) Identify differences in Canadian GAAP/IFRS accounting policies. (cid:0) Identify Canadian GAAP/IFRS (cid:0) IFRS 1 elections have been differences Q1 2009. (cid:0) Select entity’s continuing IFRS (cid:0) Identify and evaluate IFRS 1 options policies. Q1 2009. (cid:0) Select entity’s IFRS 1 choices. (cid:0) Identify disclosure requirements (cid:0) Develop financial statement format. (cid:0) Identify IFRS 1 disclosures for 2010. under IFRS Q4 2009. (cid:0) Ready for complete IFRS reporting in 2011 financial year including comparative financial statements for 2010 financial year. Infrastructure: (cid:0) Determine and develop IFRS (cid:0) Identify and train IFRS project team expertise needed at all levels within the entity. (cid:0) Determine and implement information technology changes needed to be fully IFRS compliant. Q1 2009. (cid:0) Ready for parallel processing of 2010 general ledger using IFRS accounting procedures, Q1 2010. evaluated. Detailed calculations are underway to establish impact on financial statements. (cid:0) Disclosure requirements have been established. Processes are currently being implemented to gather additional information where applicable. (cid:0) Transition statements are being drafted. Collection of information for comparative financial statements has begun. (cid:0) IFRS project team was established and trained in Q1, 2009. Formal training was imparted to Finance team and IFRS project team in February and September 2009. (cid:0) Configuration of Precision’s Enterprise Resource System for capital assets has been completed and tested. Business Policy Assessment: (cid:0) Identify impact on financial (cid:0) Impact of IFRS on debt covenants to (cid:0) Assessment of impact of IFRS covenants and renegotiate/redefine as needed. (cid:0) Identify impact on compensation plans and change as required. (cid:0) Evaluate impact on customer and supplier contracts. be identified. (cid:0) Review compensation plans by Q4, 2010. (cid:0) Renegotiate and amend customer and supplier contracts by Q3, 2010 if needed. conversion on compensation plans, debt covenants and customer and supplier contracts is in progress. Control Environment: (cid:0) Assess impact on design and (cid:0) Update business process and (cid:0) Documentation of revised business effectiveness of internal control over financial reporting. information technology controls documentation by end of Q4, 2010. (cid:0) Assess impact on design and effectiveness of disclosure controls and procedures. (cid:0) Update CEO/CFO certifications process by end of Q4, 2010 for SOX 302. process and information technology controls as a result of IFRS changes has commenced. It is expected to be completed by Q4, 2010. (cid:0) Assessment of impact to the CEO/CFO certification process is in progress. The above disclosure is made keeping in mind the Trust’s circumstances as of today in order to help stakeholders understand the impact of the transition on various aspects of financial reporting. The Trust’s circumstances may change during the course of the project resulting in the need to change some or all of the key activities and deadlines/milestones disclosed above. 42 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S oveRvieWoFBusinessRisKs The discussion of risk that follows is not a complete representation. Additional information related to risks is disclosed in the 2009 Annual Information Form filed with SEDAR and available at www.sedar.com. Also refer to the “Cautionary Statement Regarding Forward-Looking Information and Statements” on page 3. Certain activities of Precision are affected by factors that are beyond its control or influence. The drilling rig, camp and catering, service rig, snubbing, rentals, wastewater treatment and related service businesses and activities of Precision in Canada and the drilling rig, camp and catering and rentals business and activities of Precision in the United States are directly affected by fluctuations in exploration, development and production activity carried on by its customers which, in turn, is dictated by numerous factors including world energy prices and government policies. The addition, elimination or curtailment of government regulations and incentives could have a significant impact on the oil and natural gas business in Canada and the United States. These factors could lead to a decline in the demand for Precision’s services, resulting in a material adverse effect on revenues, cash flows, earnings and cash distributions to unitholders. Crude Oil and Natural Gas Prices Precision sells its services to oil and natural gas exploration and production companies. Macroeconomic and geopolitical factors associated with oil and natural gas supply and demand are prime drivers for pricing and profitability within the oilfield services industry. Generally, when commodity prices are relatively high, demand for Precision’s services are high, while the opposite is true when commodity prices are low. The markets for oil and natural gas are separate and distinct. Oil is a global commodity with a vast distribution network. As natural gas is most economically transported in its gaseous state via pipeline, its market is dependent on pipeline infrastructure and is subject to regional supply and demand factors. However, recent developments in the transportation of LNG in ocean going tanker ships have introduced an element of globalization to the natural gas market. Crude oil and natural gas prices are quite volatile, which accounts for much of the cyclical nature of the oilfield services business. To partially mitigate the risk associated with demand for our services Precision maintains as variable a cost structure as it can while continuing to enable it to provide the level of service expected of its customers. Business is Seasonal and Highly Variable In Canada and the northern part of the United States, the level of activity in the oilfield service industry is influenced by seasonal weather patterns. During the spring months, wet weather and the spring thaw make the ground unstable. Consequently, municipalities and counties and provincial and state transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels and placing an increased level of importance on the location of Precision’s equipment prior to imposition of the road bans. The timing and length of road bans is dependent upon the weather conditions leading to the spring thaw and the weather conditions during the thawing period. Additionally, certain oil and natural gas producing areas are located in areas of western Canada that are inaccessible, other than during the winter months, because the ground surrounding or containing the drilling sites in these areas consists of terrain known as muskeg. Until the muskeg freezes, the rigs and other necessary equipment cannot cross the terrain to reach the drilling site. Moreover, once the rigs and other equipment have been moved to a drilling site, they may become stranded or otherwise unable to relocate to another site should the muskeg thaw unexpectedly. Precision’s business results depend, at least in part, upon the severity and duration of the winter season. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 43 Customer Merger and Acquisition Activity Merger and acquisition activity in the oil and natural gas exploration and production sector can impact demand for Precision’s services as customers focus on internal reorganization activities prior to committing funds to significant drilling and capital maintenance projects. To partially mitigate the risk associated with customer dependency, Precision strives to maintain a broad client base and diversified geographic positioning. Workforce Availability Precision may not be able to find enough skilled labour to meet its needs, which could limit its growth. As a result, Precision may have problems finding enough skilled and unskilled laborers in the future if demand for its services increases. If Precision is not able to increase its service rates sufficiently to compensate for similar wage rate increases, its operating results may be adversely affected. To mitigate labour risk Precision closely monitors crew availability for field operations. To retain and attract field personnel Precision focuses on initiatives that provide a safe and productive work environment, opportunity for advancement and added wage security. Precision works to ensure future field personnel requirements through programs like its “Toughnecks” recruiting program. Credit Market Conditions May Adversely Affect Business The ability to make scheduled payments on or to refinance debt obligations depends on the financial condition and operating performance of the Trust, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond its control. The credit markets have recently experienced and continue to experience adverse conditions. Continuing volatility in the credit markets may increase costs associated with debt instruments due to increased spreads over relevant interest rate benchmarks, or affect the Trust’s, or third parties it seeks to do business with, ability to access those markets. The Trust may be unable to maintain a level of cash flow from operating activities sufficient to permit it to pay the principal, premium, if any, and interest on its indebtedness. In addition, there has been substantial uncertainty in the capital markets and access to financing is uncertain. These conditions could have an adverse effect on the industry in which the Trust operates and its business, including future operating results. Precision’s customers may curtail their drilling programs, which could result in a decrease in demand for drilling rigs and a reduction in dayrates, reduction in the number and profitability of turnkey jobs and/or utilization. In addition, certain customers could experience an inability to pay suppliers, including the Trust, in the event they are unable to access the capital markets to fund their business operations. Access to Additional Financing Precision may find it necessary in the future to obtain additional debt or equity financing through the Trust to support ongoing operations, to undertake capital expenditures, to repay existing indebtedness or to undertake acquisitions or other business combination transactions. There can be no assurance that additional financing will be available to Precision when needed or on terms acceptable or favourable to Precision. Precision’s inability to raise financing to support ongoing operations or to fund capital expenditures, acquisitions, debt repayments or other business combination transactions could limit Precision’s growth and may have a material adverse effect upon Precision. To mitigate credit and financing risks Precision regularly assesses its credit policies and capital structure. Management believes Precision currently maintains sufficient liquidity as described in its liquidity and capital management earlier in this report. 44 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S Technology Complex drilling programs for the exploration and development of remaining conventional and unconventional oil and natural gas reserves in North America demand high performance drilling rigs. The ability of drilling rig service providers to meet this demand will depend on continuous improvement of existing rig technology such as drive systems, control systems, automation, mud systems and top drives to improve drilling efficiency. Precision’s ability to deliver equipment and services that are more efficient is critical to continued success. There is no assurance that competitors will not achieve technological improvements that are more advantageous, timely or cost effective than improvements developed by Precision. To attempt to mitigate this risk Precision has an experienced internal engineering department that works closely with operations and marketing on equipment design and improvements. Competitive Industry The contract drilling business is highly competitive with numerous industry participants, and the drilling contracts Precision competes for are usually awarded on the basis of competitive bids. Management believes pricing and rig availability are the primary factors considered by Precision’s potential customers in determining which drilling contractor to select. Management believes other factors are also important. Among those factors are: (cid:0) the drilling capabilities and condition of drilling rigs; (cid:0) the quality of service and experience of rig crews; (cid:0) the safety record of the contractor and the particular rig; (cid:0) the offering of ancillary services; (cid:0) the ability to provide equipment adaptable to, and personnel familiar with, new technologies and drilling techniques; and (cid:0) the mobility and efficiency of rigs. Capital Overbuild in the Drilling Industry Because of the long life nature of drilling equipment and the lag between the moment a decision to build a rig is made and the moment the rig is placed into service, the number of rigs in the industry does not always correlate to the level of demand for those rigs. Periods of high demand often spur increased capital expenditures on rigs, and those capital expenditures may exceed actual demand. Management believes that there is currently an excess of rigs in the North American oil and gas industry in relation to current levels of demand. This capital overbuild could cause Precision’s competitors to lower their rates and could lead to a decrease in rates in the oilfield services industry generally, which would have an adverse effect on the revenues, cash flows and earnings of the Trust. To mitigate the risk associated with industry competitiveness and capital overbuild, Precision has comprehensive strategic planning to align resource allocation, investment and competitiveness. Tax Consequences of Previous Transactions Completed by Precision The business and operations of Precision are complex and Precision has executed a number of significant financings, business combinations, acquisitions and dispositions over the course of its history. The computation of income taxes payable as a result of these transactions involves many complex factors as well as Precision’s interpretation of relevant tax legislation and regulations which Precision believes to be correct. Management also believes that the provision for income tax is adequate and in accordance with generally accepted accounting principles and applicable legislation and regulations. However, there are a number of tax filing positions that can still be the subject of review by taxation authorities who may successfully challenge Precision’s interpretation of the applicable tax legislation and regulations, with the result that additional taxes could be payable by Precision and the amount payable without penalties could be up to $400 million as of December 31, 2009. Any increase in tax liability would reduce the net assets of and funds available to the Trust. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 45 Environmental There is growing concern about the apparent connection between the burning of fossil fuels and climate change. The issue of energy and the environment has created intense public debate in Canada and around the world in recent years that is likely to continue for the foreseeable future and could potentially have a significant impact on all aspects of the economy including the demand for hydrocarbons and resulting in lower demand for Precision’s services. Precision maintains a comprehensive insurance and risk management program to protect its assets and operations. Precision monitors and complies with current environmental requirements. United States Dollar Exchange Exposure Precision’s operations in the United States have revenue, expenses, assets and liabilities denominated in United States dollars. As a result Precision’s income statement, balance sheet and statement of cash flow are impacted by changes in exchange rates between Canadian and United States currencies. (cid:0) Translation of United States Subsidiaries Precision’s United States operations are considered self-sustaining operations and are translated into Canadian dollars using the current rate method. Under this method, the assets and liabilities of Precision’s operations in the United States are recorded in the consolidated financial statements at the exchange rate in effect at the balance sheet dates and the unrealized gains and losses are included in other comprehensive income, a component of Unitholders’ equity. As a result, changes in the Canadian to United States dollar exchange rates could materially increase or decrease Precision’s United States dollar denominated net assets on consolidation which increase or decrease Unitholders’ equity. In addition, under certain circumstances Canadian GAAP requires foreign exchange gains and losses that are accumulated in other comprehensive income to be recorded as a foreign exchange gain or loss in the statement of earnings. Precision’s United States operations generate revenue and incur expenses in United States dollars and the United States dollar based earnings are converted into Canadian dollars for purposes of financial statement consolidation and reporting. The conversion of the United States dollar based revenue and expenses to a Canadian dollar basis does not result in a foreign exchange gain or loss but does result in lower or higher net earnings from United States operations than would have occurred had the exchange rate not changed. If the Canadian dollar strengthens versus the United States dollar, the Canadian dollar equivalent of net earnings from United States operations will be negatively impacted. Precision does not currently hedge any of its exposure related to the translation of United States dollar based earnings into Canadian dollars. (cid:0) Transaction Exposure Precision has long-term debt denominated in United States dollars. This debt is converted at the exchange rate in effect at the balance sheet dates with the resulting gains or losses included in the statement of earnings as “foreign exchange”. If the Canadian dollar strengthens versus the United States dollar, Precision will incur a foreign exchange gain from the translation of this debt. Currently, Precision has not designated any of this debt as a hedge against the net asset position of its self-sustaining United States operations. The vast majority of Precision’s United States operations are transacted in United States dollars. Transactions for Precision’s Canadian operations are primarily transacted in Canadian dollars. However, Precision occasionally purchases goods and supplies in United States dollars for Canadian operations. These types of transactions and foreign exchange exposure would not typically have a material impact on the Canadian operations’ financial results. When Precision acquired Grey Wolf the debt was drawn in U.S. dollars which provided a natural hedge for the U.S. dollar settled operations. Other than natural hedges that arise from day-to-day operations, Precision monitor’s foreign exchange changes but does not currently maintain an active foreign currency hedge program. 46 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S Safety Risk 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. Management believes that Precision’s drilling and well servicing businesses are highly competitive with numerous competitors. A key factor considered by Precision’s customers in selecting oilfield service providers is safety. Deterioration in Precision’s safety performance could result in a decline in the demand for Precision’s services and could have a material adverse effect on its revenues, cash flows and earnings of the Trust. Through its Target Zero program Precision maintains a comprehensive training and assessment program designed to work towards a vision of no work place incidents resulting in injury. Dependence on Third Party Suppliers Precision sources certain key rig components, raw materials, equipment and component parts from a variety of suppliers located in Canada, the United States and overseas. Precision also outsources some or all services for the construction of drilling and service rigs. While alternate suppliers exist for most of these components, materials, equipment, parts and services, cost increases, delays in delivery due to high activity or other unforeseen circumstances may be experienced. Precision maintains relationships with a number of key suppliers and contractors, maintains an inventory of key components, materials, equipment and parts and orders long lead time components in advance. However, if the current or alternate suppliers are unable to provide or deliver the necessary components, materials, equipment, parts and services, any resulting delays by Precision in the provision of services to its customers may have a material adverse effect on Precision’s business, revenues, cash flows, prospects and earnings of the Trust. To mitigate this risk Precision maintains relationships with a number of key suppliers and uses internal procurement operations when appropriate. evAluAtionoFDisclosuRecontRolsAnDpRoceDuRes Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and United States securities laws. The information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure. As of December 31, 2009, an evaluation was carried out, under the supervision of and with the participation of management, including the President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of Precision’s disclosure controls and procedures as defined under the rules adopted by the Canadian securities regulatory authorities and by the United States Securities and Exchange Commission. Based on that evaluation, the President and Chief Executive Officer and Chief Financial Officer concluded that the design and operation of Precision’s disclosure controls and procedures were effective as at December 31, 2009. During the fourth quarter of 2009, there were no changes in internal control over financial reporting that materially affected, or are reasonably likely to materially affect, Precision’s internal control over financial reporting. It should be noted that while Precision’s President and Chief Executive Officer and Chief Financial Officer believe that the Trust’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Trust’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 47 non-gAApMeAsuRes Precision uses certain measures that are not recognized under Canadian generally accepted accounting principles to assess performance and believe these non-GAAP measures provide useful supplemental information to investors. Following are the non-GAAP measures Precision uses in assessing performance. EBITDA Management believes that in addition to net earnings, earnings before interest, taxes, loss on asset decommissioning, depreciation and amortization and foreign exchange (“EBITDA”) as derived from information reported in the Consolidated Statements of Earnings and Retained Earnings (Deficit) is a useful supplemental measure as it provides an indication of the results generated by Precision’s principal business activities prior to consideration of how those activities are financed, the impact of foreign exchange, how the results are taxed, how funds are invested, how non-cash depreciation and amortization charges or how non-cash decommissioning charges affect results. The following table provides a reconciliation of net earnings under GAAP as disclosed in the Consolidated Statement of Earnings and Retained Earnings (Deficit) to EBITDA. (Stated in thousands of Canadian dollars) 2009 2008 2007 EBITDA $ 407,001 $ 436,536 $ 437,075 Add (deduct): Depreciation and amortization (138,000) (83,829) (71,604) Loss on asset decommissioning (82,173) – (6,722) Foreign exchange 122,846 2,041 (2,398) Financing charges (147,401) (14,174) (7,318) Income taxes (570) (37,844) (6,213) Earnings from continuing operations $ 161,703 $ 302,730 $ 342,820 Operating Earnings Management believes that in addition to net earnings, operating earnings as reported in the Consolidated Statements of Earnings and Retained Earnings (Deficit) is a useful supplemental measure as it provides an indication of the results generated by Precision’s principal business activities prior to consideration of how those activities are financed, the impact of foreign exchange or how the results are taxed. Operating earnings as calculated by Precision was changed in the year and it now excludes the effects of foreign exchange. The revised calculation is a better reflection of results from operations without consideration as to how results were impacted by foreign exchange. (Stated in thousands of Canadian dollars) 2009 2008 2007 Operating earnings $ 186,828 $ 352,707 $ 358,749 Add (deduct): Foreign exchange 122,846 2,041 (2,398) Financing charges (147,401) (14,174) (7,318) Income taxes (570) (37,844) (6,213) Earnings from continuing operations $ 161,703 $ 302,730 $ 342,820 48 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S Precision Drilling Trust MAnAgeMent’sRepoRttotheunitholDeRs The accompanying consolidated financial statements and all information in the Annual Report are the responsibility of management. The consolidated financial statements have been prepared by management in accordance with the accounting policies in the notes to the consolidated financial statements. When necessary, management has made informed judgments and estimates in accounting for transactions which were not complete at the balance sheet date. In the opinion of management, the consolidated financial statements have been prepared within acceptable limits of materiality, and are in accordance with Canadian generally accepted accounting principles (“GAAP”) appropriate in the circumstances. The financial information elsewhere in the Annual Report has been reviewed to ensure consistency with that in the consolidated financial statements. Management has prepared Management’s Discussion and Analysis (“MD&A”). The MD&A is based upon Precision Drilling Trust’s (the “Trust”) financial results prepared in accordance with Canadian GAAP. The MD&A compares the audited financial results for the years ended December 31, 2009 to December 31, 2008 and the years ended December 31, 2008 to December 31, 2007. Note 21 to the consolidated financial statements describes the impact on the consolidated financial statements of significant differences between Canadian and United States GAAP. Management is responsible for establishing and maintaining adequate internal control over the Trust’s financial reporting and is supported by an internal audit function who conducts periodic testing of these controls. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external reporting purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with direction from our principal executive officer and principal financial and accounting officer, management conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting. Management’s evaluation of internal control over financial reporting was based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2009. Also management determined that there were no material weaknesses in the Trust’s internal control over financial reporting as of December 31, 2009. KPMG LLP, an independent firm of Chartered Accountants, was engaged, as approved by a vote of unitholders at the Trust’s most recent annual meeting, to audit the consolidated financial statements and provide an independent professional opinion. KPMG LLP completed an audit of the design and effectiveness of the Trust’s internal control over financial reporting as of December 31, 2009, as stated in their report included herein and expressed an unqualified opinion on design and effectiveness of internal control over financial reporting as of December 31, 2009. The Audit Committee of the Board of Directors, which is comprised of five independent directors who are not employees of the Trust, provides oversight to the financial reporting process. Integral to this process is the Audit Committee’s review and discussion with management and the external auditors of the quarterly and annual financial statements and reports prior to their respective release. The Audit Committee is also responsible for reviewing and discussing with management and the external auditors major issues as to the adequacy of the Trust’s internal controls. The external auditors have unrestricted access to the Audit Committee to discuss their audit and related matters. The consolidated financial statements have been approved by the Board of Trustees on the recommendation of the Board of Directors of Precision Drilling Corporation and its Audit Committee. Kevin A. Neveu Doug J. Strong Chief Executive Officer Chief Financial Officer Precision Drilling Corporation, Precision Drilling Corporation, Administrator to Precision Drilling Trust Administrator to Precision Drilling Trust March 10, 2010 March 10, 2010 P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 49 Precision Drilling Trust AuDitoRs’RepoRttotheunitholDeRs To the Unitholders of Precision Drilling Trust We have audited the consolidated balance sheets of Precision Drilling Trust (the “Trust”) as at December 31, 2009 and 2008 and the consolidated statements of earnings and retained earnings (deficit), comprehensive income (loss) and cash flow for each of the years in the three-year period ended December 31, 2009. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2009 and 2008 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009 in accordance with Canadian generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 10, 2010, expressed an unqualified opinion on the effectiveness of the Trust’s internal control over financial reporting. Chartered Accountants Calgary, Alberta March 10, 2010 50 C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S Precision Drilling Trust RepoRtoFinDepenDentRegisteReDpuBlicAccountingFiRM To the Board of Directors of Precision Drilling Corporation, as Administrator of Precision Drilling Trust and the Unitholders of Precision Drilling Trust We have audited Precision Drilling Trust’s (the “Trust”) internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trust’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report to the Unitholders. Our responsibility is to express an opinion on the Trust’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Trust as of December 31, 2009 and 2008, and the related consolidated statements of earnings and retained earnings (deficit), comprehensive income (loss) and cash flow for each of the years in the three-year period ended December 31, 2009, and our report dated March 10, 2010 expressed an unqualified opinion on those consolidated financial statements. Chartered Accountants Calgary, Alberta March 10, 2010 P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 51 Precision Drilling Trust consoliDAteDBAlAncesheets As at December 31, (Stated in thousands of Canadian dollars) 2009 2008 ASSETS Current assets: Cash $ 130,799 $ 61,511 Accounts receivable (Note 25) 283,899 601,753 Income tax recoverable 25,753 13,313 Inventory 9,008 8,652 449,459 685,229 Income tax recoverable 64,579 58,055 Property, plant and equipment (Note 4) 2,913,966 3,243,213 Intangibles (Note 5) 3,156 5,676 Goodwill (Note 6) 760,553 841,529 $ 4,191,713 $ 4,833,702 LIABILITIES AND UNITHOLDERS’ EQUITY Current liabilities: Accounts payable and accrued liabilities (Note 25) $ 128,376 $ 270,122 Distributions payable (Note 8) – 20,825 Current portion of long-term debt (Note 10) 223 48,953 128,599 339,900 Long-term liabilities (Note 9) 26,693 30,951 Long-term debt (Note 10) 748,725 1,368,349 Future income taxes (Note 11) 703,195 770,623 1,607,212 2,509,823 Commitments and contingencies (Notes 17 and 26) Subsequent event (Notes 10 and 29) Unitholders’ equity: Unitholders’ capital (Note 12(b)) 2,770,708 2,355,590 Contributed surplus (Note 12(d)) 4,063 998 Retained earnings (deficit) 107,227 (48,068) Accumulated other comprehensive income (loss) (Note 13) (297,497) 15,359 2,584,501 2,323,879 $ 4,191,713 $ 4,833,702 See accompanying notes to consolidated financial statements. Approved by the Board of Trustees: Robert J.S. Gibson Patrick M. Murray Trustee Trustee 52 C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S Precision Drilling Trust consoliDAteDstAteMentsoFeARningsAnDRetAineD eARnings(DeFicit) Years ended December 31, (Stated in thousands of Canadian dollars, except per unit amounts) 2009 2008 2007 Revenue $ 1,197,446 $ 1,101,891 $ 1,009,201 Expenses: Operating 692,243 598,181 516,094 General and administrative 98,202 67,174 56,032 Depreciation and amortization 138,000 83,829 71,604 Loss on asset decommissioning (Note 4) 82,173 – 6,722 Foreign exchange (122,846) (2,041) 2,398 Finance charges (Note 15) 147,401 14,174 7,318 Earnings from continuing operations before income taxes 162,273 340,574 349,033 Income taxes: (Note 11) Current (14,901) 6,102 (737) Future 15,471 31,742 6,950 570 37,844 6,213 Earnings from continuing operations 161,703 302,730 342,820 Gain on disposal of discontinued operations, net of tax (Note 28) – – 2,956 Net earnings 161,703 302,730 345,776 Deficit, beginning of year (48,068) (126,110) (195,219) Distributions declared (Note 8) (6,408) (224,688) (276,667) Retained earnings (deficit), end of year $ 107,227 $ (48,068) $ (126,110) Earnings per unit from continuing operations: (Note 18) Basic $ 0.65 $ 2.23 $ 2.54 Diluted $ 0.63 $ 2.23 $ 2.54 Net earnings per unit: (Note 18) Basic $ 0.65 $ 2.23 $ 2.57 Diluted $ 0.63 $ 2.23 $ 2.57 See accompanying notes to consolidated financial statements. consoliDAteDstAteMentsoFcoMpRehensiveincoMe(loss) Years ended December 31, (Stated in thousands of Canadian dollars) 2009 2008 2007 Net earnings $ 161,703 $ 302,730 $ 345,776 Unrealized gain (loss) on translation of assets and liabilities of self-sustaining operations denominated in foreign currency (Note 13) (312,856) 11,222 – Comprehensive income (loss) $ (151,153) $ 313,952 $ 345,776 See accompanying notes to consolidated financial statements. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 53 Precision Drilling Trust consoliDAteDstAteMentsoFcAshFloW Years ended December 31, (Stated in thousands of Canadian dollars) 2009 2008 2007 Cash provided by (used in): Continuing operations: Earnings from continuing operations $ 161,703 $ 302,730 $ 342,820 Adjustments and other items not involving cash: Long-term compensation plans 3,310 2,163 (8,496) Depreciation and amortization 138,000 83,829 71,604 Loss on asset decommissioning 82,173 – 6,722 Future income taxes 15,471 31,742 6,950 Unrealized foreign exchange (113,649) 7,219 – Amortization of debt issue costs and debt settlement (Note 15) 43,893 798 – Other 655 – 112 Changes in non-cash working capital balances (Note 25) 173,173 (84,571) 64,403 504,729 343,910 484,115 Investments: Purchase of property, plant and equipment (193,435) (229,579) (186,973) Proceeds on sale of property, plant and equipment 15,978 10,440 5,767 Business acquisitions, net of cash acquired (Note 20) – (768,392) – Changes in income tax recoverable (6,524) (55,148) – Proceeds on disposal of discontinued operations (Note 28) – – 2,956 Purchase of intangibles – – (33) Changes in non-cash working capital balances (Note 25) (26,250) 22,583 (13,119) (210,231) (1,020,096) (191,402) Financing: Distributions paid (Note 8) (27,233) (216,304) (249,000) Repayment of long-term debt (974,271) (179,826) (99,700) Debt issue costs (21,628) (160,098) – Increase in long-term debt 408,893 1,308,040 78,646 Issuance of Trust units, net of issue costs 413,223 – – Change in bank indebtedness – (14,115) (22,659) (201,016) 737,697 (292,713) Effect of exchange rate changes on cash and cash equivalents (24,194) – – Increase in cash and cash equivalents 69,288 61,511 – Cash and cash equivalents, beginning of year 61,511 – – Cash and cash equivalents, end of year $ 130,799 $ 61,511 $ – See accompanying notes to consolidated financial statements. 54 C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S Precision Drilling Trust notestoconsoliDAteDFinAnciAlstAteMents (Tabular amounts are stated in thousands of Canadian dollars except unit numbers and per unit amounts) NOTE 1. DESCRIPTION OF BUSINESS Precision Drilling Trust (the “Trust”) is a provider of contract drilling and completion and production services primarily to oil and natural gas exploration and production companies in Canada and the United States. The Trust is an unincorporated open-ended investment trust governed by the laws of Alberta and created pursuant to the Declaration of Trust dated September 22, 2005. NOTE 2. SIGNIFICANT ACCOUNTING POLICIES (a) Basis of presentation The Trust’s accounting policies are in accordance with Canadian generally accepted accounting principles (“GAAP”). These policies are consistent with accounting principles generally accepted in the United States in all material respects except as outlined in Note 21. The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingencies. Significant estimates used in the preparation of the financial statements include, but are not limited to, depreciation of property, plant and equipment, valuation of long-lived assets and goodwill, allowance for doubtful accounts, accruals for employee based incentive plans, accruals for uninsured workers’ compensation and general liability claims and income taxes. Actual results could differ from these and other estimates, the impact of which would be recorded in future periods. Certain of the prior period’s figures have been reclassified to conform to current year’s presentation. (b) Principles of consolidation The consolidated financial statements include the accounts of the Trust and all of its subsidiaries and partnerships substantially all of which are wholly-owned. All significant intercompany balances and transactions have been eliminated. The Trust does not hold investments in any companies where it exerts significant influence and does not hold interests in any variable interest entities. (c) Cash and cash equivalents Cash and cash equivalents consist of cash and short-term investments with original maturities of three months or less. (d) Inventory Inventory is primarily comprised of operating supplies and is carried at the lower of average cost, being the cost to acquire the inventory, and net realizable value. Inventory is charged to operating expenses as items are sold or consumed at the amount of the average cost of the item. (e) Property, plant and equipment Property, plant and equipment are carried at cost, including costs of direct material and labour. Where costs are incurred to extend the useful life of property, plant and equipment or to upgrade its capabilities, the amounts are capitalized to the related asset. Costs incurred to repair or maintain property, plant and equipment are expensed as incurred. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 55 Property, plant, and equipment are depreciated as follows: Expected life Salvage value Basis of depreciation Drilling rig equipment Drill pipe and drill collars Service rig equipment Drilling rig spare equipment Service rig spare equipment Rental equipment Other equipment Light duty vehicles Heavy duty vehicles Buildings (f) Intangibles 5,000 utilization days 1,500 operating days 24,000 service hours 15 years 10 years 10 to 15 years 3 to 10 years 4 years 7 to 10 years 10 to 20 years 20% – 20% – – – – – – – unit-of-production unit-of-production unit-of-production straight-line straight-line straight-line straight-line straight-line straight-line straight-line Intangibles with determinable lives are amortized using the straight-line method based on the estimated useful lives of the respective assets as follows: Customer relationships 1 to 5 years Patents 10 years (g) Goodwill Goodwill is the amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the assets acquired, less liabilities assumed, based on their fair values. Goodwill is allocated as of the date of the business combination to the Trust’s reporting segments that are expected to benefit from the business combination. Goodwill is not amortized and is tested for impairment annually in the fourth quarter, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount of the reporting segment is compared with its fair value. When the fair value of a reporting segment exceeds its carrying amount, goodwill of the reporting segment is considered not to be impaired and the second step of the impairment test is unnecessary. The second step is carried out when the carrying amount of a reporting segment exceeds its fair value, in which case the implied fair value of the reporting segment’s goodwill is compared with its carrying amount to measure the amount of the impairment loss, if any. The implied fair value of goodwill is determined in the same manner as the value of goodwill is determined in a business combination using the fair value of the reporting segment as if it was the purchase price. When the carrying amount of a reporting segment’s goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess. (h) Long-lived assets On a periodic basis, management assesses the carrying value of long-lived assets for indications of impairment. Indications of impairment include an ongoing lack of profitability and significant changes in technology. When an indication of impairment is present, the Trust tests for impairment by comparing the carrying value of the asset to its net recoverable amount. If the carrying amount is greater than the net recoverable amount, the asset is written down to its estimated fair value. (i) Income taxes The Trust and its subsidiaries follow the liability method of accounting for future income taxes. Under the liability method, future income tax assets and liabilities are determined based on “temporary differences” (differences between the accounting basis and the tax basis of the assets and liabilities), and are measured using current or substantively enacted tax rates and laws expected to apply when these differences reverse. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs. Future tax assets are recognized if it is considered more likely than not that the tax asset will be realized. 56 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S Currently, income earned directly by Precision Drilling Limited Partnership (“PDLP”) is not subject to income taxes as its income is taxed directly to the PDLP partners. The Trust is a taxable entity under the Income Tax Act (Canada) and income earned is taxable only to the extent it is not distributed or distributable to its holders of Trust units and exchangeable LP units (together “unitholders”). In June 2007, the government of Canada’s Bill C-52 Budget Implementation Act, 2007 was enacted and included legislative provisions that impose a tax on certain distributions from publicly traded specified income flow-through (“SIFT”) trusts at a rate equal to the applicable federal corporate tax rate plus a provincial SIFT factor. Precision will be a SIFT trust on the earlier of January 1, 2011 or the first day after it exceeds the normal growth guidelines announced by the federal Department of Finance on December 15, 2006. The enacted SIFT tax had no significant impact on Precision’s future tax liability. (j) Revenue recognition The Trust’s services are generally sold based upon service orders or contracts with a customer that include fixed or determinable prices based upon daily, hourly or job rates. Customer contract terms do not include provisions for significant post-service delivery obligations. Revenue is recognized when services and equipment rentals are rendered and only when collectability is reasonably assured. The Trust also provides services under turnkey contracts whereby it drills a well to an agreed upon depth under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. Revenue from turnkey drilling contracts is recognized using the percentage-of-completion method based upon costs incurred to date and estimated total contract costs. Anticipated losses, if any, on uncompleted contracts are recorded at the time the estimated costs exceed the contract revenue. (k) Employee benefit plans At December 31, 2009, approximately 42% (2008 – 43%) of the employees of the Trust’s subsidiaries were enrolled in defined contribution retirement plans. Employer contributions to defined contribution plans are expensed as employees earn the entitlement and contributions are made. (l) Long-term incentive plan 2010 is the final year of an annual long-term incentive plan (the “LTIP”) which compensates officers and other key employees through cash payments at the end of a three-year term. The compensation is comprised of two components, a retention award and a performance award. The retention award is a lump sum amount determined in equivalent notional Trust units at the date of commencement in the LTIP and is accrued and charged to earnings on a straight-line basis over the three-year term. The values of the notional Trust units are adjusted monthly based on the period-end trading price of Trust units and the resulting gains or losses are included in earnings. The performance components are based on the operational and financial targets as determined by the Compensation Committee of Precision and is accrued over the three-year term of the plans. (m) Unit-based compensation plans An equity settled deferred trust unit plan has been established whereby non-management directors of Precision can elect to receive all or a portion of their compensation in fully-vested deferred trust units. Under this plan, the number of deferred trust units are adjusted for cash distributions to unitholders declared prior to redemption by issuing additional trust units based on the weighted average trading price of Precision’s Trust units on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. Compensation expense is recognized based on the current trading price of the Trust units at the date of grant with a corresponding increase to contributed surplus. Upon redemption of the deferred trust units into Trust units, the amount previously recognized in contributed surplus is recorded as an increase to unitholders’ capital. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 57 A cash settled Performance Trust Unit incentive plan has been established for officers and other eligible employees. Under this plan notional performance trust units (“PTU”) are granted upon commencement in the plan and vest at the end of a three year term. The vested PTUs are automatically paid out in cash in the first quarter following vesting at a value determined by the fair market value of Trust units at December 31 of the vesting year and based on the number of PTUs held multiplied by a performance factor that ranges from zero to two times. The performance factor is based on Precision achieving a predetermined return on capital employed and unit price performance compared to a peer group over the three year period. The intrinsic value of the PTUs is accrued in accounts payable and charged to earnings on a straight- line basis over the three year term. This estimated value is adjusted monthly based on the period-end trading price of Trust units and an estimated performance factor with the resulting gains or losses included in earnings. A cash settled Restricted Trust Unit incentive plan has been established for officers and other eligible employees. Under this plan notional restricted trust units (“RTU”) are granted upon commencement in the plan and vest annually over a three year term. The vested RTUs are automatically paid out in cash in the first quarter following vesting at a value determined by the fair market value of Trust units at December 31 of the vesting year and based on the number of RTUs held. The intrinsic value of the RTUs is accrued in accounts payable and charged to earnings on a straight-line basis over the three year term. This estimated value is adjusted monthly based on the period-end trading price of Trust units with the resulting gains or losses included in earnings. A cash settled deferred trust unit plan has been established whereby eligible participants of Precision’s Performance Savings Plan could elect to receive a portion of their annual performance bonus in the form of deferred trust units (“DTU”). These notional units are adjusted for each cash distribution to unitholders by issuing additional DTUs based on the weighted average trading price of Precision’s Trust units on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. The values of these DTUs are adjusted monthly based on the period-end trading price of Trust units and the resulting amount is included in accounts payable and accrued liabilities. Gains or losses resulting from these adjustments are charged to earnings. A cash settled Deferred Signing Bonus Unit Plan has been established for the Chief Executive Officer. Under this plan deferred trust units are vested on the date of grant and are redeemable over a three-year period. These notional units are adjusted for each cash distribution to unitholders by issuing additional DTUs based on the weighted average trading price of Precision’s Trust units on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. The values of these DTUs are adjusted monthly based on the period-end trading price of Trust units and the resulting amount that is redeemable in the current year is included in accounts payable and accrued liabilities and the remainder is included in long-term liabilities. Gains or losses resulting from these adjustments are charged to earnings. A cash settled unit appreciation rights plan (“UAR”) has been established for certain eligible participants. This plan uses notional units that are valued based on the Trust’s unit price on the New York Stock Exchange. Compensation costs are accrued over the vesting periods when the market price of the trust units exceeds the strike price under the plan adjusted by unit distributions. The recorded liability is revalued at the end of each reporting period to reflect changes in the market price of the trust units with the net change recognized in earnings. When the UARs are exercised, the accrued liability is reduced. The accrued compensation cost for a UAR that is forfeited or cancelled is adjusted by decreasing the compensation cost in the period of forfeiture or cancellation. A unit option plan has been established for certain eligible employees. Under this plan the fair value of unit purchase options is calculated at the date of grant using the Black-Scholes option pricing model and that value is recorded as compensation expense on a straight-line basis over the grant’s vesting period with an offsetting credit to contributed surplus. Upon exercise of the equity purchase option, the associated amount is reclassified from contributed surplus to unitholders’ capital. Consideration paid by employees upon exercise of the equity purchase options is credited to unitholders’ capital. 58 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S (n) Foreign currency translation Accounts of the Trust’s integrated foreign operations are translated to Canadian dollars using average exchange rates for the month of the respective transaction for revenue and expenses. Monetary assets and liabilities are translated at exchange rates in effect at the balance sheet date and non-monetary assets and liabilities are translated using historical rates of exchange. Gains or losses resulting from these translation adjustments are included in net earnings. Accounts of the Trust’s self-sustaining foreign operations are translated to Canadian dollars using average exchange rates for the month of the respective transaction for revenue and expenses. Assets and liabilities are translated at exchange rates in effect at the balance sheet date. Gains or losses resulting from these translation adjustments are included in other comprehensive income (loss) and accumulated other comprehensive income (loss) in unitholders’ equity. Transactions in foreign currencies are translated at rates in effect at the time of the transaction. Monetary assets and liabilities are translated at current rates. Gains and losses are included in net earnings. Coinciding with the acquisition of Grey Wolf, Inc. (“Grey Wolf” – see Note 20) Precision determined its existing United States based contract drilling operations had changed from integrated to self-sustaining and accordingly prospectively changed its method of foreign currency translation for these operations. (o) Exchangeable LP units Exchangeable LP units are presented as equity of the Trust as their features make them economically equivalent to Trust units. (p) Per unit amounts Basic per unit amounts are calculated using the weighted average number of Trust units outstanding during the year. Diluted per unit amounts are calculated by using the treasury stock method for equity based compensation arrangements and the “if-converted” method for the convertible notes. The treasury stock method assumes that any proceeds obtained on exercise of equity based compensation arrangements would be used to purchase Trust units at the average market price during the period. The weighted average number of units outstanding is then adjusted by the difference between the number of units issued from the exercise of equity based compensation arrangements and units repurchased from the related proceeds. Under the “if-converted” method, the after-tax effect of interest expense related to the convertible notes is added back to net earnings, and the convertible notes are assumed to have been converted to trust units at the beginning of the period and are added to the weighted average number of units outstanding. (q) Financial instruments Cash and cash equivalents are classified as “held for trading” and any change in fair value is recorded through net income. Accounts receivable are classified as “loans and receivables”. After their initial fair value measurement, they are measured at amortized cost using the effective interest rate method. For the Trust, the measured amount generally corresponds to historical cost. Accounts payable and accrued liabilities, bank indebtedness, distributions payable, long-term debt and other long-term liabilities, except for the long-term incentive plans, are classified as “other financial liabilities”. After their initial fair value measurement, they are measured at amortized cost using the effective interest rate method. For the Trust, the measured amount generally corresponds to historical cost. Derivative financial instruments such as interest rate swaps and caps are recorded at estimated fair value with changes in fair value each period included in earnings. Transaction costs incurred on the issuance of debt are classified with the related debt instrument. These costs are amortized using the effective interest rate method over the life of the related debt instrument. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 59 NOTE 3. CHANGES IN ACCOUNTING POLICIES (a) 2009 changes Effective January 1, 2009 the Trust adopted new Canadian accounting standards relating to goodwill and intangible assets (Section 3064), replacing Section 3062, goodwill and other intangible assets and Section 3450, research and development costs. This new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. This new standard did not have a material impact on the Trust’s financial statements. In June 2009 the CICA amended the accounting standards relating to the disclosure of financial instruments (Section 3862) to align Canadian standards with amendments issued by the International Accounting Standards Board. The amendment, which is effective for fiscal year ends ending after September 30, 2009, requires the disclosure of fair values based on a fair value hierarchy as well as enhanced discussion and quantitative disclosure related to liquidity risk. This amendment did not have a material impact on the disclosures in the Trust’s financial statements. (b) 2008 changes Effective January 1, 2008 the Trust adopted new accounting standards issued by the Canadian Institute of Chartered Accountants (“CICA”) relating to inventories (Section 3031) and capital disclosures (Section 1535). Section 3031 requires inventories to be measured at the lower of cost or net realizable value and provides guidance on the determination of cost and its subsequent recognition as an expense, including any write-downs to net realizable value and circumstances for their subsequent reversal. This new standard did not have a material impact on the Trust’s financial statements. Section 1535 requires the Trust to provide additional quantitative and qualitative information regarding its objectives, policies and processes for managing its capital. (c) Future accounting pronouncements Canadian GAAP for publicly accountable enterprises will be converged with International Financial Reporting Standards (“IFRS”) for fiscal years beginning on or after January 1, 2011. The conversion from Canadian GAAP to IFRS will be applicable to the Trust’s reporting for the first quarter of 2011 for which the current and comparative information will be prepared under IFRS. At this time, the Trust is not able to quantify the impact of conversion to IFRS on the financial statements. In January 2009 the CICA issued new standards relating to business combinations (Section 1582), consolidated financial statements (Section 1601) and non-controlling interests (Section 1602). Section 1582 is harmonized with IFRS 3, “Business Combinations” and will require most assets acquired and liabilities assumed, including contingent liabilities to be measured at fair value and that all acquisition costs to be expensed. Section 1602 harmonizes Canadian GAAP with the requirements of International Accounting Standard 27, “Consolidated and Separate Financial Statements” and requires that non-controlling interests be recognized as a separate component of equity and that net earnings be calculated without a deduction for non-controlling interest. Section 1601 in combination with Section 1602 replaces the former consolidated financial statements standard (Section 1600) and establishes standards for the preparation of consolidated financial statements. These standards are effective January 1, 2011 with early adoption permitted. The Trust is currently evaluating the impact of these new sections on the consolidated financial statements. 60 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S NOTE 4. PROPERTY, PLANT AND EQUIPMENT Accumulated Net Book 2009 Cost Depreciation Value Rig equipment $ 3,308,987 $ 612,826 $ 2,696,161 Rental equipment 87,410 47,357 40,053 Other equipment 112,862 78,403 34,459 Vehicles 82,658 36,032 46,626 Buildings 43,312 15,452 27,860 Assets under construction 49,641 – 49,641 Land 19,166 – 19,166 $ 3,704,036 $ 790,070 $ 2,913,966 Accumulated Net Book 2008 Cost Depreciation Value Rig equipment $ 3,444,120 $ 548,380 $ 2,895,740 Rental equipment 89,433 44,240 45,193 Other equipment 122,795 76,841 45,954 Vehicles 86,260 30,817 55,443 Buildings 43,048 12,775 30,273 Assets under construction 151,003 – 151,003 Land 19,607 – 19,607 $ 3,956,266 $ 713,053 $ 3,243,213 In 2009 the Trust incurred $82.2 million (2008 – $nil; 2007 – $6.7 million) as a loss associated with the reduction in the carrying amounts of assets decommissioned during the year. The assets were decommissioned due to the inefficient nature of the asset and the high cost to maintain. The charge was allocated $67.8 million (2008 – $nil; 2007 – $2.4 million) to the Contract Drilling Services segment and $14.4 million (2008 – $nil; 2007 – $4.3 million) to the Completion and Production Services segment. NOTE 5. INTANGIBLES Accumulated Net Book 2009 Cost Amortization Value Customer relationships $ 4,488 $ 1,464 $ 3,024 Patents 931 799 132 $ 5,419 $ 2,263 $ 3,156 Accumulated Net Book 2008 Cost Depreciation Value Customer relationships $ 5,585 $ 134 $ 5,451 Patents 931 706 225 $ 6,516 $ 840 $ 5,676 Amortization expense for the year ended December 31, 2009 was $2.0 million (2008 – $0.2 million). P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 61 NOTE 6. GOODWILL Balance, December 31, 2007 $ 280,749 Acquisitions (Note 20) 557,165 Exchange adjustment 3,615 Balance, December 31, 2008 841,529 Exchange adjustment (80,976) Balance, December 31, 2009 $ 760,553 NOTE 7. BANK INDEBTEDNESS At December 31, 2009, the Trust had available $25.0 million (2008 – $50.0 million) under a secured credit facility, of which no amounts had been drawn. Availability of this facility was reduced by outstanding letters of credit in the amount of $0.1 million (2008 – $35.4 million). The current facility is primarily secured by charges on substantially all present and future property of the Trust and its material subsidiaries. Advances under the facility are available at the banks’ prime lending rate, U.S. base rate, libor rate or Banker’s Acceptance plus, in each case, the applicable margin, or in combination. NOTE 8. DISTRIBUTIONS The beneficiaries of the Trust are the holders of Trust units and the partners of PDLP are the holders of exchangeable LP units of the Trust. The distributions made by the Trust to unitholders are determined by the Trustees. PDLP earns interest income from a promissory note issued by its subsidiary Precision Drilling Corporation at a rate which is determined by the terms of the promissory note. PDLP in substance paid distributions to holders of exchangeable LP units in amounts equal to the distributions paid to the holders of Trust units. All declared distributions were made to unitholders of record on the last business day of each calendar month. The Declaration of Trust provides that an amount equal to the taxable income of the Trust not already paid to unitholders in the year will become payable on December 31 of each year such that the Trust will not be liable for ordinary income taxes for such year. A summary of the distributions is as follows: 2009 2008 Declared $ 6,408 $ 224,688 Paid $ 27,233 $ 216,304 Payable in cash at December 31 $ – $ 20,825 Payable in units at December 31 $ – $ 24,029 Included in the 2008 distributions declared was a special non-cash in-kind distribution of $24.0 million ($0.15 per unit). This special distribution was settled on January 15, 2009 through the issuance of units. Immediately following the issuance of these units, the Trust consolidated the units such that the number of Trust units and exchangeable LP units remained unchanged from the number outstanding prior to the special non-cash in-kind distribution. On February 9, 2009 the Trust announced the suspension of cash distributions for an indefinite period for distributions to be paid after February 17, 2009. 62 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S NOTE 9. LONG-TERM LIABILITIES 2009 2008 Long-term incentive plans (Note 14) $ 6,602 $ 7,489 Long-term workers compensation and other liabilities 20,091 23,462 $ 26,693 $ 30,951 NOTE 10. LONG-TERM DEBT 2009 2008 Secured facility: Term Loan A $ 288,887 $ 489,215 Term Loan B 422,097 489,840 Revolving credit facility – 107,981 Unsecured senior notes 175,000 – Unsecured facility – 168,352 Unsecured convertible notes: 3.75% notes – 168,413 Floating rate notes – 152,801 885,984 1,576,602 Less net unamortized debt issue costs (137,036) (159,300) 748,948 1,417,302 Less current portion (223) (48,953) $ 748,725 $ 1,368,349 (a) Secured facility During 2008 Precision established a Secured Facility (“Facility”) which provides senior secured financing through two Term Loan Facilities and includes a revolving credit facility. The Facility is primarily secured by charges on substantially all present and future property of the Trust and its material subsidiaries. The Trust and its material subsidiaries have also guaranteed the obligations of Precision under the Facility. The Facility requires the Trust comply with certain financial covenants including a leverage ratio of total debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (“EBITDA”) of less than 3:1; an interest coverage ratio of EBITDA to cash interest expense of greater than 3:1; and a fixed charge coverage ratio of EBITDA less cash distributions to scheduled principal repayments plus cash interest expense plus current tax expense plus upgrade capital expenditures of greater than 1:1 in 2009 and 2010 and 1.05:1 thereafter. As well, the Facility contains certain covenants that places limits on Trust distributions and limits the Trusts’ capital expenditures above an agreed base-case. At December 31, 2009 the Trust complied with the covenants of the credit facility. During the fourth quarter of 2009 and January 2010 Precision successfully negotiated with lenders to amend certain covenants and terms contained in the loan Facility. These amendments included an increase in the leverage ratio test to 3.5:1 through December 31, 2011, a decrease in the interest coverage ratio test to 2.75:1 through December 31, 2011 and the removal of the restrictions on expansion related capital expenditures (limitations on total capital expenditures remained unchanged). The Secured Facility was not fully syndicated by the underwriting banks that funded borrowings by Precision at December 31, 2008. As a result these banks retained certain provisions that were available to facilitate syndication which could result in further increases in any or a combination of interest rates, original issue discounts or fees, all subject to certain market based indexing including the re-allocation of debt between the Term Loan A and Term Loan B and between the Term Loan A and B loans and the unsecured facility. On February 4, 2009, syndication was completed and the provisions noted above resulted in US$64.0 million ($78.5 million) being reallocated from the Term Loan A to the Term Loan B and a further US$5.0 million ($6.2 million) was reallocated on March 25, 2009. These re-tranches of debt between Term Loan A and Term Loan B facilities led to additional debt issue costs through original issue discounts of US$12.7 million ($15.2 million). P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 63 The Secured Facility requires mandatory prepayments upon the occurrence of certain events, including, the incurrence of debt, certain sales or other dispositions of assets and when cash flows exceed certain base-case projections. In addition to mandatory prepayments, the Trust has the option to prepay the loans under the Secured Facility generally without premium or penalty, other than customary “breakage” costs for Eurodollar rate loans. The interest rate on loans under the Secured Facility that are denominated in U.S. dollars is, at the option of Precision, either a margin over an adjusted United States base rate (the “ABR rate”) or a margin over a Eurodollar (“libor”) rate. The interest rate on loans denominated in Canadian dollars is, at the option of Precision, a margin over the Canadian prime rate or a margin over the bankers’ acceptance rate. Certain of the margins on the Revolving Credit Facility are subject to reduction based upon a leverage test and these margins range from 3% to 4% for Eurodollar and bankers acceptance loans and 2% to 3% for ABR and Canadian prime rate loans based on leverage ratios ranging from greater than 1.5:1 to 1:1. Under the terms of the Secured Facility Precision was required to enter into interest rate contracts if necessary, on or before June 23, 2009, to ensure that at least 50% of the aggregate amounts borrowed under the Secured and Unsecured Facilities are subject to fixed interest rates. During the second quarter of 2009 Precision entered into an interest rate swap arrangement to fix the libor rate at 1.7% on US$250 million of the Term A-1 facility (with scheduled reductions in the balance through September 2012) and paid US$2.1 million ($2.5 million) for a libor interest rate cap of 3.25% on US$350 million of the Term B Facilities (with scheduled reductions in the balance through December 2013). The net amount owing under the interest rate derivative contracts is settled quarterly. At December 31, 2009, the estimated fair value of the contracts was $2.9 million and the change in fair value of these interest rate derivative contracts of $0.4 million was included in financing charges. At December 31, 2009 the Term Loan A Facility consists of a term loan A-1 facility denominated in U.S. dollars in the amount of US$257.5 million (2008 – US$381.1 million) and a term loan A-2 facility denominated in Canadian dollars in the amount of $19.3 million (2008 – $22.5 million). The Term Loan A Facility is repayable in quarterly installments in aggregate annual amounts equal to 5% of the original principal amounts (after re-tranches) of US$312.1 million and $22.5 million in 2009, 10% of the original principal amounts in each of the 2010 and 2011 and 15% of the original principal amounts in 2012 and 2013, with the balance payable on the final maturity date of December 23, 2013. During 2009 Precision made optional principal repayments of US$39.0 million on the term loan A-1 facility and $2.0 million on the term loan A-2 facility which substantially eliminates scheduled principal repayments in 2010. As of December 31, 2009, the Term Loan A Facility had an interest rate of approximately 5.6% (2008 – 6.3%) per annum, before amortization of original issue discounts and upfront fees. At December 31, 2009 the Term Loan B Facility consists of a term loan B-1 facility denominated in U.S. dollars in the amount of US$314.3 million (2008 – US$325 million) and a term loan B-2 facility denominated in U.S. dollars in the amount of US$89 million (2008 – US$75 million). The Term Loan B Facility is repayable in quarterly installments in aggregate annual amounts equal to 5% of the original principal amount (after re-tranches) of US$469.0 million with the balance payable on the final maturity date of September 30, 2014. During 2009 Precision made optional principal repayments of US$42.2 million on the Term Loan B Facility which eliminates scheduled principal repayments in 2010. As of December 31, 2009, the Term Loan B Facility had an interest rate of approximately 9.7% (2008 – 9.6%) per annum, before amortization of original issue discounts and upfront fees. The Revolving Credit Facility is available to Precision to finance working capital needs and for general corporate purposes up to a maximum of US$260 million. Under the Revolving Credit Facility amounts can be drawn in U.S. dollars and/or Canadian dollars and was undrawn as at December 31, 2009 (2008 – $108 million). Up to US$200 million of the Revolving Credit Facility is available for letters of credit denominated in United States and/or Canadian dollars and as at December 31, 2009 outstanding letters of credit amounted to US$28.0 million (2008 – nil). As of December 31, 2009, the Revolving Credit Facility had an interest rate of approximately 5.25% (2008 – 6.5%) per annum, before amortization of original issue discounts, upfront fees and commitment fees. 64 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S (b) Unsecured senior notes On April 22, 2009 the Trust completed a private placement of $175.0 million of Senior Unsecured Notes. These notes which bear interest at a fixed rate of 10% per annum, have an eight year term with one-third of the initial principal amount payable on the 6th, 7th and 8th anniversaries of the closing date of the private placement. These notes are unsecured and have been guaranteed by the Trust and each subsidiary of the Trust that guaranteed the Secured Facility. The terms of the notes contain customary negative and affirmative covenants and events of default. At December 31, 2009 the Trust complied with the terms of the note agreement. Terms of the Senior Unsecured Notes also require Precision to use a specified percentage of excess cash flow to repay indebtedness under the Secured Facility in circumstances where the Trust’s consolidated debt to capitalization ratio (following the conversion of the Trust to a corporation) as at the last day of any fiscal year is in excess of 0.30 to 1.00, in addition to the prepayments from excess cash flow required to be made under the Secured Facility. (c) Unsecured facility In connection with the acquisition of Grey Wolf, Inc. (“Grey Wolf”) Precision established the Unsecured Facility which provided senior unsecured financing of up to US$400 million. The facility had been guaranteed by the Trust and each subsidiary of the Trust that had guaranteed the Secured Facility. Loans under the Unsecured Facility bore interest at a fixed rate per annum of 17% and were scheduled to mature on December 23, 2009, and, to the extent unpaid on that date, would be converted into term loans that would mature on December 23, 2016. Loans under the Unsecured Facility were subject to mandatory prepayments from the net cash proceeds from the issuance or sale of any equity securities by the Trust (subject to certain exceptions). During the second quarter of 2009 Precision fully repaid the facility. (d) Unsecured convertible notes The US$137.5 million principal amount of 3.75% Contingent Convertible Notes (“3.75% Notes”) due May 2023 bore interest at 3.75% per annum. These notes were convertible into Trust units, upon the occurrence of certain events, including a change of control, at a conversion price of US$15.27 per Trust unit, which is equal to a conversion rate of 65.4879 Trust units per US$1,000 principal amount of 3.75% Notes, subject to adjustment. The 3.75% Notes were general unsecured senior obligations and were fully and unconditionally guaranteed, on a joint and several basis, by all wholly- owned United States subsidiaries. The 3.75% Notes ranked equally with the Floating Rate Notes described below. During the first quarter of 2009, as a result of the Grey Wolf acquisition (which constitutes a change of control under the terms of the indenture governing the 3.75% Notes), Precision was required to provide holders of the 3.75% Notes with an offer to purchase all or a portion of their 3.75% Notes at 100% of the principal amount of the 3.75% Notes, plus accrued but unpaid interest to the date of purchase, payable in cash. The US$124.8 million principal amount of Contingent Convertible Floating Rate Notes (“Floating Rate Notes”) due April 2024 bore interest at a per annum rate equal to 3-month libor, adjusted quarterly, minus a spread of 0.05% to a maximum limit rate of interest of 6%. The Floating Rate Notes were convertible into Trust units, upon the occurrence of certain events, including a change of control at a conversion price of US$15.41 per Trust unit, which is equal to a conversion rate of 64.8929 Trust units per US$1,000 principal amount of the Floating Rate Notes, subject to adjustment. The Floating Rate Notes were general unsecured senior obligations and were fully and unconditionally guaranteed, on a joint and several basis, by all wholly-owned United States subsidiaries. The Floating Rate Notes ranked equally with the 3.75% Notes. During the first quarter of 2009, as a result of the Grey Wolf acquisition (which constituted a change of control under the terms of the indenture governing the Floating Rate Notes), Precision was required to provide holders of the Floating Rate Notes with an offer to purchase all or a portion of their Floating Rate Notes at 100% of the principal amount of the Floating Rate Notes, plus accrued but unpaid interest to the date of purchase, payable in cash. During the first quarter of 2009, holders of 3.75% Notes and Floating Rate Notes representing US$137.5 million and US$124.8 million, respectively, accepted the purchase offer described above and Precision purchased these Notes at the principal balance plus accrued interest on March 24, 2009. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 65 Mandatory principal repayments after 2009 are as follows: 2010 $ 223 2011 31,663 2012 76,917 2013 234,039 2014 368,142 Thereafter 175,000 NOTE 11. INCOME TAXES The provision for income taxes differs from that which would be expected by applying Canadian statutory income tax rates as follows: 2009 2008 2007 Earnings from continuing operations before income taxes $ 162,273 $ 340,574 $ 349,033 Federal and provincial statutory rates 29% 30% 33% Tax at statutory rates $ 47,059 $ 102,172 $ 115,181 Adjusted for the effect of: Non-deductible expenses 7,562 372 1,080 Non- taxable capital gains (20,136) – – Income taxed at lower rates (30,983) – – Income to be distributed to unitholders, not subject to tax in the Trust (2,771) (67,463) (91,013) Other (161) 2,763 3,426 Income tax expense before tax rate reductions 570 37,844 28,674 Reduction of future income tax balances due to enacted tax rate reductions – – (22,461) Income tax expense $ 570 $ 37,844 $ 6,213 Effective income tax rate before enacted tax rate reductions 0% 11% 8% In 2007 the Canadian federal government enacted various reductions to corporate income tax rates, that when fully implemented will decrease the federal corporate income tax rate to 15% by 2012. The federal corporate surtax was eliminated in 2008. These and other provincial corporate income tax rate reductions have been reflected as a reduction of future tax expense. The net future tax liability is comprised of the tax effect of the following temporary differences: 2009 2008 Future income tax liability: Property, plant and equipment and intangibles $ 747,779 $ 783,945 Partnership deferrals 37,674 4,716 Other 14,296 – Debt issue costs – 3,352 799,749 792,013 Future income tax assets: Losses (expire from time to time up to 2029) 84,365 7,416 Debt issue costs 3,769 – Long-term incentive plan 4,407 5,664 Other 4,013 8,310 Net future income tax liability $ 703,195 $ 770,623 Included in the net future tax liability is $468.2 million (2008 – $560.9 million) of tax effected temporary differences related to the Trusts’ United States operations. 66 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S NOTE 12. UNITHOLDERS’ CAPITAL (a) Authorized – unlimited number of voting Trust units – unlimited number of voting exchangeable LP units (b) Unitholders’ capital Trust units Number Amount Balance, December 31, 2006 125,536,329 $ 1,409,828 Issued on retraction of exchangeable LP units 51,590 574 Issued and consolidated pursuant to special distribution (Note 8) – 30,141 Balance, December 31, 2007 125,587,919 1,440,543 Issued on the acquisition of Grey Wolf 34,435,724 889,085 Issued on retraction of exchangeable LP units 18,422 209 Issued and consolidated pursuant to special distribution (Note 8) – 24,006 Balance, December 31, 2008 160,042,065 2,353,843 Issued for cash on February 18, 2009 46,000,000 217,281 Issued for cash pursuant to private placement 35,000,000 70,181 Issued upon exercise of rights on June 4, 2009 34,441,950 103,326 Issued on retraction of exchangeable LP units 32,763 377 Unit issue costs, net of related tax effect of $1.9 million – (10,489) 275,516,778 2,734,519 Warrants issued pursuant to private placement – 34,819 Balance, December 31, 2009 275,516,778 $ 2,769,338 Trust units are redeemable at the option of the holder, at which time all rights with respect to such units are cancelled. Upon redemption, the unitholder is entitled to receive a price per unit equal to the lesser of 90% of the average market price of the Trust’s units for the 10 trading days just prior to the date of redemption, and the closing market price of the Trust’s units on the date of redemption. The maximum value of units that can be redeemed for cash is $50,000 per month. Redemptions, if any, in excess of this amount are satisfied by issuing a note from PDC to the unitholder, payable over 15 years and bearing interest at a market rate set by the Board of Directors. Exchangeable LP units Number Amount Balance, December 31, 2006 221,595 $ 2,466 Redeemed on retraction of exchangeable LP units (51,590) (574) Issued and consolidated pursuant to special distribution (Note 8) – 41 Balance, December 31, 2007 170,005 1,933 Redeemed on retraction of exchangeable LP units (18,422) (209) Issued and consolidated pursuant to special distribution (Note 8) – 23 Balance, December 31, 2008 151,583 1,747 Redeemed on retraction of exchangeable LP units (32,763) (377) Balance, December 31, 2009 118,820 $ 1,370 Exchangeable LP units have voting rights and have been exchangeable since May 7, 2006, for Trust units on a one-for- one basis at the option of the holder. Holders are entitled to distributions equal to those paid to holders of Trust units. Summary as at December 31, Number Amount Number Amount Trust units 275,516,778 $ 2,769,338 160,042,065 $ 2,353,843 Exchangeable LP units 118,820 1,370 151,583 1,747 Unitholders’ capital 275,635,598 $ 2,770,708 160,193,648 $ 2,355,590 2009 2008 P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 67 (c) Warrants On April 22, 2009 the Trust issued 15,000,000 purchase warrants pursuant to a private placement. Each warrant is exercisable into a unit of the Trust at a price of $3.22 per trust unit for a period of five years from the date of issue. No warrants have been exercised as at December 31, 2009. (d) Contributed surplus Balance, December 31, 2007 $ 307 Unit based compensation expense (Note 14(c)) 691 Balance, December 31, 2008 998 Unit based compensation expense (Notes 14(c) and 14(d)) 3,065 Balance, December 31, 2009 $ 4,063 NOTE 13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Balance, December 31, 2007 $ – Foreign currency translation adjustment upon change in translation methods 4,137 Unrealized foreign currency translation gains 11,222 Balance, December 31, 2008 15,359 Unrealized foreign currency translation losses (312,856) Balance, December 31, 2009 $ (297,497) NOTE 14. UNIT BASED COMPENSATION PLANS (a) Officers and employees During 2009 Precision introduced two new unit based incentive plans to replace the Performance Saving Plan and the Long-Term Incentive Plan. Under the Restricted Trust Unit incentive plan units granted to eligible employees vest annually over a three year term. Vested units are automatically paid out in cash in the first quarter of the year following vesting at a value determined by the fair market value of the units as at December 31 of the vesting year. Under the Performance Trust Unit incentive plan units granted to eligible employees vest at the end of a three year term. Vested units are automatically paid out in cash in first quarter following the vested term at a value determined by the fair market value of the units at December 31 of the vesting year and based on the number of performance units held multiplied by a performance factor that ranges from zero to two times. The performance factor is based on Precision achieving a predetermined return on capital employed and unit price performance compared to a peer group over the three year period. As at December 31, 2009 $2.5 million is included in accounts payable and accrued liabilities and $4.6 million in long-term liabilities for the plans. Included in net earnings for the year ended December 31, 2009 is an expense of $7.1 million (2008 – $nil). Notwithstanding that the Performance Savings Plan was replaced effective January 1, 2009 certain liabilities continue to exist as eligible participants were able to elect to receive a portion of their annual performance bonus in the form of deferred trust units (“DTUs”). These notional units are redeemable in cash and are adjusted for each distribution to unitholders by issuing additional DTUs based on the weighted average trading price on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. All DTUs must be redeemed within 60 days of ceasing to be an employee of Precision or by the end of the second full calendar year after receipt of the DTUs. A summary of the DTUs outstanding under this unit based incentive plan is presented below: 68 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S Deferred Trust Units Outstanding Balance, December 31, 2007 76,729 Issued, including as a result of distributions 31,006 Redeemed on employee resignations and withdrawals (24,300) Balance, December 31, 2008 83,435 Issued, including as a result of distributions 211,156 Redeemed on employee resignations and withdrawals (48,675) Balance, December 31, 2009 245,916 As at December 31, 2009 $1.9 million (2008 – $0.8 million) is included in accounts payable and accrued liabilities for outstanding DTUs. Included in net earnings for the year ended December 31, 2009 is an expense of $1.0 million (2008 – $0.4 million expense recovery; 2007 – $0.8 million expense recovery). In conjunction with the acquisition of Grey Wolf (see Note 20) the Trust instituted a Unit Appreciation Rights (“UAR”) plan. Under the plan eligible participants were granted UARs that entitle the rights holder to receive cash payments calculated as the excess of the market price over the exercise price per unit on the exercise date. The exercise price of the UAR is adjusted by the aggregate unit distributions paid or payable on Trust units from the grant date to the exercise date. The UARs vest over a period of 5 years and expire 10 years from the date of grant. Weighted Range of Average Unit Appreciation Rights Outstanding Exercise Price Exercise Price Exercisable Outstanding at December 31, 2007 − $ − $ − − Granted 925,746 9.69 – 18.76 15.56 Outstanding at December 31, 2008 925,746 9.69 – 18.76 15.56 469,267 Forfeitures (128,206) 9.69 – 18.19 16.02 Outstanding at December 31, 2009 797,540 $ 9.69 – 18.76 $ 15.48 607,168 Total UARs Outstanding Exercisable UARs Weighted Average Weighted Remaining Weighted Average Contractual Average Range of Exercise Prices: Number Exercise Price Life (Years) Number Exercise Price $ 9.69 – 12.99 76,109 $ 9.70 4.24 76,109 $ 9.70 13.00 – 15.99 420,471 15.35 7.29 274,098 15.12 16.00 – 18.76 300,960 17.13 6.74 256,961 17.23 $ 9.69 – 18.76 797,540 $ 15.48 6.79 607,168 $ 15.33 No amounts relating to the UAR plan have been recorded as compensation expense or accrued liability as at December 31, 2009 and 2008 as the intrinsic value of the awards was nil. (b) Executive In 2007 Precision instituted a Deferred Signing Bonus Unit Plan for its Chief Executive Officer. Under the plan 178,336 notional DTUs were granted on September 1, 2007. The units are redeemable one-third annually beginning September 1, 2008 and are settled for cash based on the Trust unit trading price on redemption. The number of notional DTUs is adjusted for each cash distribution to unitholders by issuing additional notional DTUs based on the weighted average trading price on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. As at December 31, 2009 $0.5 million (2008 – $0.7 million) is included in accounts payable and accrued liabilities and $nil (2008 – $0.7 million) in long-term incentive plan payable for the 68,250 (2008 – 133,780) outstanding DTUs. Included in net earnings for the year ended December 31, 2009 is an expense recovery of $0.4 million (2008 – $21,000 expense; 2007 – $2.8 million expense). P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 69 (c) Non-management directors The Trust has a deferred trust unit plan for non-management directors. Under the plan fully vested deferred trust units are granted quarterly based upon an election by the non-management director to receive all or a portion of their compensation in deferred trust units. Cash distributions to unitholders declared by the Trust prior to redemption are reinvested into additional deferred trust units on the date of distribution. These deferred trust units are redeemable into an equal number of Trust units any time after the director’s retirement. A summary of this unit based incentive plan is presented below: Deferred Trust Units Outstanding Balance, December 31, 2007 18,280 Granted 33,058 Issued as a result of distributions 3,205 Balance, December 31, 2008 54,543 Granted 234,142 Issued as a result of distributions 2,047 Balance, December 31, 2009 290,732 For the year ended December 31, 2009 the Trust expensed $1.3 million (2008 – $0.7 million; 2007 – $0.3 million) as unit based compensation, with a corresponding increase in contributed surplus. (d) Option plan During 2009 the Trust implemented a unit option plan under which a combined total of 11,103,253 options to purchase units are reserved to be granted to employees. Of the amount reserved, 1,929,200 options have been granted. Under this plan, the exercise price of each option equals the fair market value of the option at the date of grant determined by the weighted average trading price for the five days preceding the grant. The options vest over a period of three years from the date of grant as employees render continuous service to the Trust and have a term of seven years. A summary of the status of the equity incentive plan is presented below: Weighted Options Range of Average Options Outstanding Exercise Price Exercise Price Exercisable Outstanding as at December 31, 2008 Granted 1,929,200 $ 5.18 – 7.35 $ 5.52 – Forfeitures (141,500) $ 5.18 – 5.85 $ 5.23 – Outstanding as at December 31, 2009 1,787,700 $ 5.18 – 7.35 $ 5.63 – The per unit weighted average fair value of the unit options granted during 2009 was $2.57 estimated on the grant date using the Black-Scholes option pricing model with the following assumption: average risk-free interest rate 2%, average expected life of four years, expected forfeiture rate of 5% and expected volatility of 56%. Included in net earnings for the year ended December 31, 2009 is an expense of $1.7 million. NOTE 15. FINANCE CHARGES 2009 2008 2007 Interest: Long-term debt $ 101,108 13,680 7,767 Other 2,883 151 106 Income (483) (455) (555) Amortization of debt issue costs 25,681 798 – Accelerated amortization of debt issue costs from voluntary debt repayments 8,313 – – Loss on settlement of unsecured facility (Note 10) 9,899 – – $ 147,401 $ 14,174 $ 7,318 70 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S NOTE 16. EMPLOYEE BENEFIT PLANS The Trust has a defined contribution pension plan covering a significant number of its employees. Under this plan, the Trust matches individual contributions up to 5% of the employee’s eligible compensation. Total expense under the defined contribution plan in 2009 was $4.4 million (2008 – $5.7 million; 2007 – $5.3 million). NOTE 17. COMMITMENTS The Trust has commitments for operating lease agreements, primarily for vehicles and office space, in the aggregate amount of $27.7 million. Additionally, the Trust has commitments with a drilling rig manufacturer for the construction, or partial construction, of three drilling rigs in the amount of $33.0 million (US$31.5 million). Expected payments over the next five years are as follows: 2010 $ 11,034 2011 41,904 2012 2,938 2013 1,877 2014 1,313 Rent expense included in the statements of earnings is as follows: 2009 $ 6,937 2008 3,636 2007 3,838 NOTE 18. PER UNIT AMOUNTS The following tables reconcile the net earnings and weighted average units outstanding used in computing basic and diluted net earnings per unit: (Stated in thousands) 2009 2008 2007 Net earnings – basic $ 161,703 $ 302,730 $ 345,776 Impact of assumed conversion of convertible debt, net of tax 1,229 164 – Net earnings – diluted $ 162,932 $ 302,894 $ 345,776 (Stated in thousands) 2009 2008 2007 Weighted average units outstanding – basic 243,748 126,507 125,758 Effect of rights offering 6,177 9,061 9,007 Weighted average units outstanding – basic 249,925 135,568 134,765 Effect of trust unit warrants 5,261 – – Effect of stock options and other equity compensation plans 181 33 2 Effect of convertible debt 3,896 372 – Effect of rights offering 342 29 – Weighted average units outstanding – diluted 259,605 136,002 134,767 Per unit amounts and the weighted average units outstanding – basic for prior years have been restated to reflect the effect of the 2009 rights offering. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 71 NOTE 19. SIGNIFICANT CUSTOMERS During the years ended December 31, 2009, 2008 and 2007 one customer accounted for approximately 12% (2008 – 13%; 2007 – 10%) of the Trust’s revenue and year end trade accounts receivable balance. NOTE 20. BUSINESS ACQUISITIONS Acquisitions have been accounted for by the purchase method with results of operations acquired included in the consolidated financial statements from the closing date of acquisition. On December 23, 2008 Precision acquired all the issued and outstanding shares of Grey Wolf, Inc. Grey Wolf provided land based daywork and turnkey contract drilling services to the oil and gas industry in the United States and Mexico. The acquisition facilitated and accelerated Precision’s organic expansion into the United States market and provided a foundation for future international expansion. Intangible assets acquired relate to customer relationships. The Grey Wolf operations have been included in the Contract Drilling Services segment. On July 31, 2008, Precision acquired six service rigs and related equipment from Rick’s Well Servicing Ltd. (“RWS”) a privately owned well servicing company based in Virden, Manitoba. The acquisition represented all of the operating assets of RWS and Precision will maintain and operate out of the RWS facility. The acquisition strengthened Precision’s product offering in south-eastern Saskatchewan and south-western Manitoba. Intangible assets acquired relate to customer lists. The operations of RWS have been included in the Completion and Production Services segment. The details of these acquisitions are as follows: Grey Wolf RWS Total Net assets at assigned values: Working capital $ 470,586 (1) $ 19 $ 470,605 Property, plant and equipment 1,869,875 10,542 1,880,417 Intangible assets 4,428 1,128 5,556 Goodwill (no tax basis) 553,335 3,830 557,165 Long-term liabilities (23,308) – (23,308) Long-term debt (319,115) – (319,115) Future income taxes (553,682) – (553,682) $ 2,002,119 $ 15,519 $ 2,017,638 Consideration: Cash $ 1,113,034 $ 15,519 $ 1,128,553 Trust units 889,085 – 889,085 $ 2,002,119 $ 15,519 $ 2,017,638 (1) Working capital includes cash of $360,161 NOTE 21. UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES These financial statements have been prepared in accordance with Canadian GAAP which conform with United States generally accepted accounting principles (U.S. GAAP) in all material respects, except as follows: (a) Income taxes On December 31, 2009 Precision had $48.7 million (2008 – $56.6 million) of unrecognized tax benefits that, if recognized, would have a favourable impact on Precision’s effective income tax rate in future periods. Precision classifies interest accrued on unrecognized tax benefits and income tax penalties as income tax expense. Included in the unrecognized tax benefit as at December 31, 2009 is interest and penalties of $8.7 million (2008 – $9.6 million). Under FIN 48, unrecognized tax benefits are classified as current or long-term liabilities as opposed to future income tax liabilities. 72 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S Reconciliation of unrecognized tax benefits Year ended December 31, 2009 2008 Unrecognized tax benefits, beginning of year $ 56,563 $ 44,407 Additions: Prior year’s tax positions 2,514 2,822 Assumed on acquisition of Grey Wolf, Inc. – 9,696 Reductions: Prior year’s tax positions (10,425) (362) Unrecognized tax benefits, end of year $ 48,652 $ 56,563 It is anticipated that approximately $23.9 million (2008 – $9.0 million) of an unrecognized tax position that relates to prior year activities will be realized during the next 12 months and has been classified as a current liability. Subject to the results of audit examinations by taxing authorities and/or legislative changes by taxing jurisdictions, Precision does not anticipate further adjustments of unrecognized tax positions during the next 12 months that would have a material impact on the financial statements of Precision. There is no difference between the amounts recorded for tax exposures under Canadian and U.S. GAAP. (b) Equity settled unit based compensation As described in Note 14(c), the Trust has an equity settled unit based compensation plan for non-management directors. Trust units issued upon settlement of this plan are redeemable (see Note 21(d)) therefore under U.S. GAAP are accounted for as a liability based award. The liability is re-measured, until settlement, at the end of each reporting period with the resultant change being charged or credited to the statement of earnings as compensation expense. As described in Note 14(d), the Trust has an equity settled unit option plan for employees. Trust units issued upon settlement of this plan are redeemable (see Note 21(d)) therefore under U.S. GAAP are accounted for as a liability based award. The liability is re-measured at fair value, until settlement, at the end of each reporting period with the resultant change being charged or credited to the statement of earnings as compensation expense. Additional disclosures required by U.S. GAAP with respect to Precision’s equity settled unit based compensation plans are as follows: Trust Unit Directors’ As at December 31, 2009 Options DTUs Number vested and expected to vest 1,698,315 290,732 Weighted average exercise price per unit (1) $ 5.63 $ – Aggregate intrinsic value (2) $ 3,425 $ 2,224 Weighted average remaining life (years) 6.3 – Trust Unit Directors’ As at December 31, 2008 Options DTUs Number vested and expected to vest – 54,543 Weighted average exercise price per unit (1) $ – $ – Aggregate intrinsic value (2) $ – $ 549 Weighted average remaining life (years) – – (1) No proceeds are received upon exercise of Directors DTUs. (2) Based on December 31 closing price for Precision’s Trust units on the Toronto Stock Exchange. No Trust unit options were exercisable at December 31, 2009 and 2008 and all of the Directors’ DTUs were vested. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 73 (c) Cash settled unit based compensation As described in Note 14(a), the Trust has a cash settled unit appreciation rights plan. Under Canadian GAAP this plan is treated as a liability based compensation plan and recorded at its intrinsic value. Under U.S. GAAP rights issued under this plan would be measured at their fair value, and re-measured at fair value at each reporting date with the change in the obligation charged as unit based compensation. None of the rights were exercised during 2009 and 2008. At December 31, 2008 and 2009 the fair value and intrinsic value of these rights were insignificant. Additional disclosures required by U.S. GAAP with respect to the unit appreciation rights plan: As at December 31, 2009 UARs Number vested and expected to vest 757,663 Weighted average exercise price per unit $ 15.48 Aggregate intrinsic value (1) $ – Weighted average remaining life (years) 6.8 Number exercisable 607,168 Weighted average exercise price per unit $ 15.33 Aggregate intrinsic value (1) $ – Weighted average remaining life (years) 6.5 As at December 31, 2008 UARs Number vested and expected to vest 879,459 Weighted average exercise price per unit $ 15.56 Aggregate intrinsic value (1) $ – Weighted average remaining life (years) 7.8 Number exercisable 469,267 Weighted average exercise price per unit $ 15.43 Aggregate intrinsic value (1) $ – Weighted average remaining life (years) 7.4 (1) Based on December 31 closing price for Precision’s Trust units on the Toronto Stock Exchange. (d) Redemption of Trust units Under the Declaration of Trust, Trust units are redeemable at any time on demand by the unitholder for cash and notes (see Note 12). Under U.S. GAAP, the amount included on the consolidated balance sheet for Unitholders’ equity would be moved to temporary equity and recorded at an amount equal to the redemption value of the Trust units as at the balance sheet date. The same accounting treatment would be applicable to the exchangeable LP units. The redemption value of the Trust units and the exchangeable LP units is determined with respect to the trading value of the Trust units as at each balance sheet date, and the amount of the redemption value is classified as temporary equity. Changes (increases and decreases) in the redemption value during a period results in a change to temporary equity and is charged to retained earnings. (e) Debt issuance costs Under U.S. GAAP debt issuance costs are recorded as a deferred charge and amortized over the term of the debt instrument. Canadian GAAP requires that such costs be presented as a reduction of the related debt, resulting in a $137.0 million reclassification from long-term debt to other noncurrent assets at December 31, 2009 (2008 – $159.3 million). 74 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S (f) Goodwill In 2000 the Trust adopted the asset and liability method of accounting for future income taxes without restatement of prior years. As a result, the Trust recorded an adjustment to retained earnings and future tax liability in the amount of $70.0 million at January 1, 2000. U.S. GAAP requires the use of the asset and liability method which substantially conforms to the Canadian GAAP accounting standard adopted in 2000. Application of U.S. GAAP in years prior to 2000 would have resulted in $70.0 million of additional goodwill being recognized at January 1, 2000 as opposed to an implementation adjustment to retained earnings allowed under Canadian GAAP. Prior to 2002 goodwill was amortized under Canadian and U.S. GAAP. As a result, $7.0 million of amortization was recorded on the additional goodwill in 2000 and 2001 under U.S. GAAP. In 2008 and 2009 the U.S. GAAP financial statements reflect an increase in goodwill of $63.0 million and a corresponding increase in retained earnings. (g) Business acquisitions Supplemental pro forma disclosure is required under U.S. GAAP for significant business combinations occurring during the year. On December 23, 2008 Precision completed the business acquisition of Grey Wolf, with results of operations acquired included in the consolidated financial statements from this date. The following unaudited pro forma information provides an indication of what the Trust’s results of operations might have been under U.S. GAAP, had the Grey Wolf acquisition taken place on January 1, 2008: Pro Forma (unaudited) 2008 2007 Revenue $ 2,038,828 $ 1,983,046 Net earnings $ 289,892 $ 437,239 Net earnings per unit: Basic $ 1.81 $ 2.73 Diluted $ 1.81 $ 2.73 (h) New accounting policies adopted On January 1, 2009 Precision adopted new U.S. GAAP standards with respect to non-controlling interest in consolidated financial statements. The statement clarifies the classification of non-controlling interests in the financial statements and the accounting for and reporting of transactions between the reporting entity and the holders of the non-controlling interests. The adoption of this standard had no effect on the consolidated financial statements. Beginning January 1, 2009 Precision adopted new U.S. GAAP standards with respect to business combinations. The statement requires most identifiable assets, liabilities, non-controlling interests and goodwill acquired in a business combination be recorded at fair value. In addition the new standard requires all business combinations be accounted for by applying the acquisition method and that all transaction costs be expensed as incurred. The adoption of this standard had no effect on the consolidated financial statements. Effective January 1, 2009 Precision adopted new U.S. GAAP disclosure standards with respect to derivative instruments and hedging activities. This standard requires enhanced disclosures about an entity’s derivative and hedging activities. Entities are required to provide enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The standard increases convergence with IFRS, as it relates to disclosures of derivative instruments. The adoption of this standard had no significant effect on the consolidated financial statements. (i) Fair value disclosure On January 1, 2008, Precision adopted U.S. GAAP disclosure standards with respect to the classification of fair value measures into the fair value hierarchy except as it relates to the deferral for certain non-financial assets and liabilities. Precision adopted the provisions for non-financial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis on January 1, 2009. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 75 This U.S. GAAP standard defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. The fair value disclosures required under U.S. GAAP are not significantly different than Canadian GAAP (see Note 23) except Canadian GAAP requires fair value disclosures for only certain financial assets and liabilities. In 2009, Precision recorded an impairment charge of $82.2 million on decommissioning certain assets. The estimated fair value of the decommissioned assets was based on level III inputs. An assessment was made of the condition, life expectancy and potential repair costs of useable components from these assets. Fair value was based on estimated replacement costs in both domestic and international markets for components of similar likeness, condition, age and remaining life. The application of U.S. GAAP accounting principles would have the following impact on the consolidated financial statements: Consolidated Statements of Earnings Years ended December 31, 2009 2008 2007 Earnings from continuing operations under Canadian GAAP $ 161,703 $ 302,730 $ 342,820 Adjustments under U.S. GAAP: Equity-based compensation expense (1,610) 183 35 Earnings from continuing operations under U.S. GAAP 160,093 302,913 342,855 Earnings from discontinued operations under Canadian and U.S. GAAP – – 2,956 Net earnings under U.S. GAAP $ 160,093 $ 302,913 $ 345,811 Earnings from continuing operations per unit under U.S. GAAP: Basic $ 0.64 $ 2.23 $ 2.54 Diluted $ 0.62 $ 2.23 $ 2.54 Net earnings per unit under U.S. GAAP: Basic $ 0.64 $ 2.23 $ 2.57 Diluted $ 0.62 $ 2.23 $ 2.57 Consolidated Statements of Comprehensive Income (Loss) Years ended December 31, 2009 2008 2007 Net earnings under U.S. GAAP $ 160,093 $ 302,913 $ 345,811 Unrealized gain (loss) on translation of assets and liabilities of self-sustaining operations denominated in foreign currency (312,856) 11,222 – Comprehensive income (loss) under U.S. GAAP $ (152,763) $ 314,135 $ 345,811 Consolidated Statements of Retained Earnings (Deficit) Years ended December 31, 2009 2008 2007 Retained earnings (deficit) under U.S. GAAP, beginning of year $ 1,060,802 $ (350,898) $ (1,873,490) Net earnings under U.S. GAAP 160,093 302,913 345,811 Distributions declared (6,408) (224,688) (276,667) Change in redemption value of temporary equity (173,658) 1,333,475 1,453,448 Retained earnings (deficit) under U.S. GAAP, end of year $ 1,040,829 $ 1,060,802 $ (350,898) 76 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S Consolidated Balance Sheets 2009 2008 As at December 31, As reported U.S. GAAP As reported U.S. GAAP Current assets $ 449,459 $ 449,459 $ 685,229 $ 685,229 Income taxes recoverable 64,579 64,579 58,055 58,055 Other long-term assets – 137,036 – 159,300 Property, plant and equipment 2,913,966 2,913,966 3,243,213 3,243,213 Intangibles 3,156 3,156 5,676 5,676 Goodwill 760,553 823,582 841,529 904,558 $ 4,191,713 $ 4,391,778 $ 4,833,702 $ 5,056,031 Current liabilities $ 128,599 $ 158,482 $ 339,900 $ 349,780 Long-term liabilities 26,693 26,693 30,951 30,951 Long-term debt 748,725 885,761 1,368,349 1,527,649 Future income taxes 703,195 654,056 770,623 713,918 Other long-term liabilities – 24,711 – 47,605 Temporary equity – 1,898,743 – 1,309,967 Unitholders’ capital 2,770,708 – 2,355,590 – Contributed surplus 4,063 – 998 – Accumulated other comprehensive income (loss) (297,497) (297,497) 15,359 15,359 Retained earnings (deficit) 107,227 1,040,829 (48,068) 1,060,802 $ 4,191,713 $ 4,391,778 $ 4,833,702 $ 5,056,031 NOTE 22. SEGMENTED INFORMATION The Trust operates primarily in Canada and the United States, in two industry segments; Contract Drilling Services and Completion and Production Services. Contract Drilling Services includes drilling rigs, procurement and distribution of oilfield supplies, camp and catering services, and manufacture, sale and repair of drilling equipment. Completion and Production Services includes service rigs, snubbing units, wastewater treatment units, and oilfield equipment rental. Contract Completion and Drilling Production Corporate Inter-segment 2009 Services Services and Other Eliminations Total Revenue $ 1,030,852 $ 176,422 $ – $ (9,828) $ 1,197,446 Segment profit (loss) (1) 210,784 10,934 (34,890) – 186,828 Depreciation and amortization 118,889 17,186 1,925 – 138,000 Total assets 3,566,078 388,245 237,390 – 4,191,713 Goodwill 648,414 112,139 – – 760,553 Capital expenditures 182,855 2,897 7,683 – 193,435 Contract Completion and Drilling Production Corporate Inter-segment 2008 Services Services and Other Eliminations Total Revenue $ 809,317 $ 308,624 $ – $ (16,050) $ 1,101,891 Segment profit (loss) (1) 302,061 86,088 (35,442) – 352,707 Depreciation and amortization 57,076 22,966 3,787 – 83,829 Total assets 4,289,517 448,697 95,488 – 4,833,702 Goodwill 729,390 112,139 – – 841,529 Capital expenditures* 202,863 23,713 3,003 – 229,579 * Excludes business acquisitions P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 77  Contract Completion and Drilling Production Corporate Inter-segment 2007 Services Services and Other Eliminations Total Revenue $ 694,340 $ 327,471 $ – $ (12,610) $ 1,009,201 Segment profit (loss) (1) 286,231 100,609 (28,091) – 358,749 Depreciation and amortization 40,660 27,159 3,785 – 71,604 Total assets 1,282,865 457,587 23,025 – 1,763,477 Goodwill 172,440 108,309 – – 280,749 Capital expenditures 159,004 26,772 1,230 – 187,006 (1) Segment profit (loss) is defined as revenue less operating, general and administrative, loss on asset decommissioning and depreciation and amortization. A reconciliation of segment profit (loss) to earnings from continuing operations before income taxes is as follows: 2009 2008 2007 Total segment profit (loss) $ 186,828 $ 352,707 $ 358,749 Add (deduct): Foreign exchange 122,846 2,041 (2,398) Finance charges (147,401) (14,174) (7,318) Earnings from continuing operations before income taxes $ 162,273 $ 340,574 $ 349,033 The Trust’s operations are carried on in the following geographic locations: Inter-segment 2009 Canada United States International Eliminations Total Revenue $ 569,013 $ 608,109 $ 23,748 $ (3,424) $ 1,197,446 Total assets 1,639,046 2,498,909 53,758 – 4,191,713 Inter-segment 2008 Canada United States International Eliminations Total Revenue $ 909,001 $ 189,796 $ 4,686 $ (1,592) $ 1,101,891 Total assets 1,741,462 3,033,378 58,862 – 4,833,702 Inter-segment 2007 Canada United States International Eliminations Total Revenue $ 958,937 $ 51,082 $ – $ (818) $ 1,009,201 Total assets 1,651,920 108,683 2,874 – 1,763,477 NOTE 23. FINANCIAL INSTRUMENTS (a) Fair value The carrying value of cash, accounts receivable, bank indebtedness, accounts payable and accrued liabilities and distributions payable approximate their fair value due to the relatively short period to maturity of the instruments. The fair value of the secured credit facilities and the unsecured facility approximate their face value at December 31, 2009. Financial assets and liabilities recorded at fair value in the consolidated balance sheet are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels based on the amount of subjectivity associated with the inputs in the fair determination of these assets and liabilities are as follows: Level I – Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. Level II – Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. 78 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S Level III – Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. The estimated fair value of the secured and unsecured credit facilities was estimated considering the risk free interest rates on government debt instruments of similar maturities, adjusted for estimated credit risk, industry risk and market risk premiums and considering the debt holders ability to demand redemption of the debt (level II inputs). The fair value of the interest rate swap and cap (see Note 10) are based on level II inputs. The estimated fair value is based on established interest rate curves and volatility rates. The following table presents Precision’s fair value hierarchy for those financial assets and liabilities carried at fair value at December 31, 2009. There were no transfers between level I and level II during the year. Quoted Prices Significant in Active Other Significant Carrying Amount Markets for Observable Observable of Asset at Identical Assets Inputs Inputs Description December 31, 2009 (Level I) (Level II) (Level III) Interest rate swap $ 2,378 $ – $ 2,378 $ – Interest rate cap 493 – 493 – Fair Value Measurements at Reporting Date Using: (b) Credit risk Accounts receivable includes balances from a large number of customers primarily operating in the oil and gas industry. The Trust manages credit risk by assessing the creditworthiness of its customers before providing services and on an ongoing basis as well as monitoring the amount and age of balances outstanding. In some instances the Trust will take additional measures to reduce credit risk including obtaining letters of credit and prepayments from customers. When indicators of credit problems appear the Trust takes appropriate steps to reduce its exposure including negotiating with the customer, filing liens and entering into litigation. The Trust views the credit risks on these amounts as normal for the industry. The Trust does not have any significant accounts receivable at December 31, 2009 that are past due and uncollectible. As at December 31, 2009 the Trust’s allowance for doubtful accounts was $16.3 million (2008 – $6.2 million). Included in net earnings for the year ended December 31, 2009 is an expense of $12.0 million (2008 – $0.6 million) related to a provision for doubtful accounts. (c) Interest rate risk As at December 31, 2009 approximately 90% of Precision’s $886 million long-term debt balance is subject to fixed interest rates after taking into consideration interest rate derivatives entered into during the second quarter of 2009. As a result Precision is not exposed to significant fluctuations in interest expense as a result of changes in interest rates. If interest rates applying to long-term debt during the year had been one percent or 100 basis points lower or higher, with all other variables held constant, earnings from continuing operations would have changed by approximately $2.6 million (2008 – $2.1 million), net of income tax. Applying a 100 basis points change in interest rates to the Trust’s long-term debt balance at December 31, 2009, with all other variables held constant, would impact earnings from continuing operations, on a go forward basis, by approximately $0.3 million. (d) Foreign currency risk The Trust is exposed to foreign currency fluctuations in relation to the working capital and long-term debt of its United States operations and certain long-term debt facilities of its Canadian operations. The Trust has no significant exposures to foreign currencies other than the U.S. dollar. The Trust monitors its foreign currency exposure and attempts to minimize the impact by aligning appropriate levels of U.S. denominated debt with cash flows from United States based operations. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 79 The following financial instruments were denominated in U.S. dollars at December 31, 2009: Canadian U.S. Operations Operations Cash $ 4,466 $ 35,491 Accounts receivable 2,368 127,992 Accounts payable and accrued liabilities (1,735) (58,093) Long-term liabilities, excluding long-term incentive plans – (19,196) Long-term debt, including current portion (660,840) – Net foreign currency exposure $ (655,741) $ 86,194 Impact of $0.01 change in the U.S. dollar to Canadian dollar exchange rate on net earnings $ 6,557 $ – Impact of $0.01 change in the U.S. dollar to Canadian dollar exchange rate on comprehensive income $ – $ 862 (e) Liquidity risk Liquidity risk is the exposure of the Trust to the risk of not being able to meet its financial obligations as they become due. The Trust manages liquidity risk by monitoring and reviewing actual and forecasted cash flows to ensure there are available cash resources to meet these needs. The following are the contractual maturities of the Trust’s financial liabilities as at December 31, 2009: 2010 2011 2012 2013 2014 Thereafter Total Long-term debt $ 223 $ 31,663 $ 76,917 $ 234,039 $ 368,142 $ 175,000 $ 885,984 Interest on long-term debt (1) 74,619 74,219 70,606 65,320 43,740 21,863 350,367 Commitments 11,034 41,904 2,938 1,877 1,313 1,562 60,628 Total $ 85,876 $ 147,786 $ 150,461 $ 301,236 $ 413,195 $ 198,425 $1,296,979 (1) Interest has been calculated based upon debt balances, interest rates and foreign exchange rates in effect as at December 31, 2009 and excludes amortization of long-term debt issue costs. NOTE 24. CAPITAL MANAGEMENT The Trust’s strategy is to carry a capital base to maintain investor, creditor and market confidence and to sustain future development of the business. The Trust seeks to maintain a balance between the level of long-term debt and unitholders’ 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 Trust has maintained a conservative ratio of long-term debt to long-term debt plus equity. The Grey Wolf acquisition in 2008 caused the Trust to increase these levels. As at December 31, 2009 and 2008 these ratios were as follows: 2009 2008 Long-term debt $ 748,725 $ 1,368,349 Unitholders’ equity 2,584,501 2,323,879 Total capitalization $ 3,333,226 $ 3,692,228 Long-term debt to long-term debt plus equity ratio 0.22 0.37 The increase in long-term debt for Precision coincided with the severe contraction in global debt and equity markets. The limited availability of capital created a challenging economic environment at December 31, 2008 and during 2009 and Precision expects demand for its drilling and other oilfield services to remain at low to moderate levels in the short term. Accordingly, Precision undertook a debt reduction plan to reduce long-term debt levels and strengthen its capital structure. Included in this management plan were initiatives to keep capital expenditures for the purchase of property, plant and equipment at efficient levels, limit and suspend cash distributions to unitholders and raise additional unitholder capital through the issuance of Trust units, as described in greater detail in Note 12. 80 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S During the second quarter of 2009, Precision pursued market opportunities to set in place permanent cost of debt terms associated with long-term debt facilities as outlined in Note 10. As at December 31, 2009, management believes that Precision has sufficient liquidity as Precision has $130.8 million in cash and complete access to available debt facilities. The US$260 million Revolver in the Secured Facility remains undrawn except for US$28 million in outstanding letters of credit and, in addition, Precision has access to a $25 million operating facility. Precision continues to focus on debt reduction and further strengthening of its capital structure. Subject to unitholder vote, Precision intends to convert its capital structure from an income trust to a traditional corporate structure during the second quarter of 2010 (see Note 29). The conversion is in response to legislated Canadian tax changes scheduled for January 1, 2011. In addition, the conversion aligns with Precision’s stated strategy to reduce debt and grow its energy service businesses in North America and international markets. The Trust is bound by debt covenants that may limit the Trust’s ability to make distributions to unitholders and incur additional indebtedness as described in Note 10. NOTE 25. SUPPLEMENTAL INFORMATION 2009 2008 2007 Interest paid $ 103,109 $ 13,394 $ 7,870 Income taxes paid $ 23,697 $ 764 $ 4,307 Components of change in non-cash working capital balances: Accounts receivable $ 295,844 $ (114,444) $ 98,055 Inventory (467) 603 (182) Accounts payable and accrued liabilities (133,419) 56,299 (49,338) Income taxes (15,035) (4,446) 2,749 $ 146,923 $ (61,988) $ 51,284 Pertaining to: Operations $ 173,173 $ (84,571) $ 64,403 Investments $ (26,250) $ 22,583 $ (13,119) The components of accounts receivable are as follows: 2009 2008 Trade $ 185,144 $ 387,004 Accrued trade 67,918 178,946 Prepaids and other 30,837 35,803 $ 283,899 $ 601,753 The components of accounts payable and accrued liabilities are as follows: 2009 2008 Accounts payable $ 53,546 $ 136,054 Accrued liabilities: Payroll 35,926 78,143 Other 38,904 55,925 $ 128,376 $ 270,122 P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 81 NOTE 26. CONTINGENCIES AND COMMITMENTS The business and operations of the Trust are complex and the Trust has executed a number of significant financings, business combinations, acquisitions and dispositions over the course of its history. The computation of income taxes payable as a result of these transactions involves many complex factors as well as the Trust’s interpretation of relevant tax legislation and regulations which the Trust’s management believes to be correct. The Trust’s management also believes that the provision for income tax is adequate and in accordance with generally accepted accounting principles and applicable legislation and regulations. However, there are a number of tax filing positions that can still be the subject of review by taxation authorities who may successfully challenge the Trust’s interpretation of the applicable tax legislation and regulations, with the result that additional taxes could be payable by the Trust and the amount owed, with estimated interest but without penalties, could be up to $400 million, including the estimated amount pertaining to the long-term income tax recoverable. The Trust, through the performance of its services, product sales and business arrangements, is sometimes named as a defendant in litigation. The outcome of such claims against the Trust is not determinable at this time, however, their ultimate resolution is not expected to have a material adverse effect on the Trust. NOTE 27. GUARANTEES The Trust has entered into agreements indemnifying certain parties primarily with respect to tax and specific third party claims associated with businesses sold by the Trust. Due to the nature of the indemnifications, the maximum exposure under these agreements cannot be estimated. No amounts have been recorded for the indemnities as the Trust’s obligations under them are not probable or estimable. NOTE 28. DISCONTINUED OPERATIONS In September 2007 the Trust received $3.0 million as partial settlement of an outstanding matter associated with a previous business divestiture. This amount was recorded as a gain on disposal of discontinued operations. The following table provides additional information with respect to amounts included in the statements of cash flow related to discontinued operations: 2009 2008 2007 Net earnings of discontinued operations $ – $ – $ 2,956 Items not affecting cash: Gain on disposal of discontinued operations – – (2,956) Funds provided by discontinued operations $ – $ – $ – NOTE 29. SUBSEQUENT EVENT On February 12, 2010 the Trust announced its intention to convert to a corporation (the “Conversion”) pursuant to a plan of arrangement under the Business Corporations Act (Alberta). The Trust anticipates seeking approval from unitholders in conjunction with its 2010 annual and special meeting of unitholders (the “Meeting”) and, if approved, is scheduled to complete the Conversion by May 31, 2010. To be implemented, the Conversion must be approved by not less than two-thirds of the votes cast by unitholders at the Meeting and customary court and regulatory approvals must be obtained. 82 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S Precision Drilling Trust suppleMentAlinFoRMAtion unittRADingsuMMARy– 2009 THE TO RONTO S TOCK EXCHAN GE ( TSX ) $10 PD.UN Volume (millions) Unit Price (Cdn$) e c i r P t i n U $8 $6 $4 $2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec THE NEW YORK STOCK EXCHAN GE ( NYS E ) $10 PDS Volume (millions) Unit Price (US$) e c i r P t i n U $8 $6 $4 $2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 8.0 6.0 4.0 2.0 12.0 10.0 8.0 6.0 4.0 2.0 e m u o V l e m u o V l P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 83 Precision Drilling Trust consoliDAteDstAteMentsoFeARningsAnDRetAineD eARnings(DeFicit) Years ended December 31, (Stated in millions of Canadian dollars, except per unit amounts) 2009 2008 2007 2006 2005 Revenue $ 1,197.4 $ 1,101.9 $ 1,009.2 $ 1,437.6 $ 1,269.2 Expenses: Operating 692.2 598.2 516.1 688.2 641.8 General and administrative 98.2 67.2 56.0 81.2 76.4 Reorganization costs – – – – 17.5 EBITDA 407.0 436.5 437.1 668.2 533.5 Depreciation and amortization 138.0 83.8 71.6 73.2 71.6 Loss on asset decommissioning 82.1 – 6.7 – – Operating earnings 186.9 352.7 358.8 595.0 461.9 Foreign exchange (122.8) (2.0) 2.4 (0.3) (3.5) Finance charges 147.4 14.1 7.4 8.0 29.3 Premium on redemption of bonds – – – – 71.9 Loss on disposal of short-term investments – – – – 71.0 Other – – – (0.4) – Earnings from continuing operations before income taxes 162.3 340.6 349.0 587.7 293.2 Income taxes 0.6 37.9 6.2 15.2 72.4 Earnings from continuing operations 161.7 302.7 342.8 572.5 220.8 Discontinued operations, net of tax – – 3.0 7.1 1,409.8 Net earnings 161.7 302.7 345.8 579.6 1,630.6 Retained earnings (deficit), beginning of year (48.1) (126.1) (195.2) (303.3) 1,041.7 Adjustment on cash purchase of employee stock options, net of tax – – – – (42.1) Reclassification from contributed surplus on cash buy-out of employee stock options – – – – 23.2 Distribution of disposal proceeds – – – – (2,851.8) Repurchase of common shares of dissenting shareholders – – – – (34.4) Distributions declared (6.4) (224.7) (276.7) (471.5) (70.5) Retained earnings (deficit), end of year $ 107.2 $ (48.1) $ (126.1) $ (195.2) $ (303.3) Earnings per unit from continuing operations: Basic $ 0.65 $ 2.23 $ 2.54 $ 4.26 $ 1.67 Diluted $ 0.63 $ 2.23 $ 2.54 $ 4.26 $ 1.64 Net earnings per unit: Basic $ 0.65 $ 2.23 $ 2.57 $ 4.31 $ 12.34 Diluted $ 0.63 $ 2.23 $ 2.57 $ 4.31 $ 12.13 84 S U P P L E M E N TA L I N F O R M AT I O N Precision Drilling Trust ADDitionAlselecteDFinAnciAlinFoRMAtion Years ended December 31, (Stated in millions of Canadian dollars, except per unit amounts) 2009 2008 2007 2006 2005 Return on sales – % (1) 13.5 27.5 34.0 39.8 17.4 Return on assets – % (2) 3.6 12.4 19.9 33.6 43.3 Return on equity – % (3) 6.2 19.6 27.0 49.4 66.1 Working capital $ 320.9 $ 345.3 $ 140.4 $ 166.5 $ 152.8 Current ratio 3.5 2.0 2.1 1.81 1.43 PP&E and intangibles $ 2,917.1 $ 3,248.9 $ 1,210.9 $ 1,108.0 $ 944.4 Total assets $ 4,191.7 $ 4,833.7 $ 1,763.5 $ 1,761.2 $ 1,718.9 Long-term debt $ 748.7 $ 1,368.3 $ 119.8 $ 140.9 $ 96.8 Unitholders’ equity $ 2,584.5 $ 2,323.9 $ 1,316.7 $ 1,217.1 $ 1,074.6 Long-term debt to long-term debt plus equity 0.22 0.37 0.08 0.10 0.08 Interest coverage (4) 1.3 24.9 49.0 74.1 15.9 Net capital expenditures from continuing operations excluding business acquisitions $ 177.5 $ 219.1 $ 181.2 $ 233.7 $ 140.1 EBITDA $ 407.0 $ 436.5 $ 437.1 $ 668.2 $ 533.5 EBITDA – % of revenue 34.0 39.6 43.3 46.5 42.0 Operating earnings $ 186.9 $ 352.7 $ 358.8 $ 595.0 $ 461.9 Operating earnings – % of revenue 15.6 32.0 35.6 41.4 36.4 Cash flow from continuing operations $ 504.7 $ 343.9 $ 484.1 $ 609.7 $ 206.0 Cash flow from continuing operations per unit Basic $ 2.02 $ 2.54 $ 3.59 $ 4.53 $ 1.56 Diluted $ 1.94 $ 2.53 $ 3.59 $ 4.53 $ 1.53 Book value per unit (5) $ 9.38 $ 14.51 $ 10.47 $ 9.68 $ 8.57 Price earnings ratio (6) 11.77 4.52 5.87 6.26 3.11 Basic weighted average units outstanding (000s) 249,925 135,568 134,765 134,537 132,135 (1) Return on sales was calculated by dividing earnings from continuing operations by total revenues. (2) Return on assets was calculated by dividing net earnings by quarter average total assets. (3) Return on equity was calculated by dividing net earnings by quarter average total unitholders’ equity. (4) Interest coverage was calculated by dividing operating earnings by net interest expense. (5) Book value per unit was calculated by dividing unitholders’ equity by units outstanding. (6) Year end closing price from the TSX divided by basic earnings per unit. P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T 85 pRecisionDRillingtRust STOCK EXCHANGE LISTINGS ACCOUNT QUESTIONS ONLINE INFORMATION Units of Precision Drilling Trust are Precision’s Transfer Agent can help To receive news releases by email, listed on the Toronto Stock Exchange you with a variety of unitholder or to view this report online, under the trading symbol PD.UN and related services, including: please visit the Trust’s website at on the New York Stock Exchange (cid:0) Change of address www.precisiondrilling.com and refer under the trading symbol PDS. (cid:0) Lost unit certificates to the Investor Relations section. (cid:0) Transfer of trust units to Additional information relating to another person (cid:0) Estate settlement You can contact Precision’s Transfer Agent at: Computershare Trust Company of Canada 100 University Avenue, 9th Floor, North Tower Toronto, Ontario, Canada M5J 2Y1 Telephone: 1-800-564-6253 (toll free in Canada and the United States) 1-514-982-7555 (international direct dialing) Email: service@computershare.com TRANSFER AGENT AND REGISTRAR Computershare Trust Company of Canada Calgary, Alberta TRANSFER POINT Computershare Trust Company NA Denver, Colorado 2009 TRADING PROFILE Toronto (TSX: PD.UN) High: $10.44 Low: $2.51 Close: $7.65 Volume Traded: 353,969,175 New York (NYSE: PDS) High: US$8.54 Low: US$2.00 Close: US$7.25 Volume Traded: 523,247,973 the Trust, including the Annual Information Form, Annual Report and Management Information Circular is available under our profile on the SEDAR website at www.sedar.com and on the EDGAR website at www.sec.gov. PUBLISHED INFORMATION If you wish to receive copies of the 2009 Annual Information Form as filed with the Canadian securities commissions and as filed under Form 40-F with the United States Securities and Exchange Commission, or additional copies of this annual report, please contact: Investor Relations Precision Drilling Corporation 4200, 150 – 6th Avenue SW Calgary, Alberta, Canada T2P 3Y7 Telephone: 403-716-4575 86 S U P P L E M E N TA L I N F O R M AT I O N PD 09AR Cover Mar24SJ_Layout 1 24/03/10 9:22 AM Page 2 PRECISION DRILLING TRUST 2009 ANNUAL REPORT From the Horn River shale play in British Columbia to the natural gas fields at the southern tip of Mexico…from the Bakken Shale in North Dakota to the Marcellus Shale in Pennsylvania, Precision is a leading provider of safe, high performance energy services to the North American oil and gas industry. Precision provides customers with access to a fleet of 352 contract drilling rigs, 200 service rigs, camps, snubbing units, wastewater treatment units and rental equipment backed by a comprehensive mix of technical support services and skilled, experienced personnel. 2009 ACHIEVEMENTS (cid:2) Aggressively implemented cost saving 2010 OUTLOOK (cid:2) Execute high performance, high value and cost reduction measures to sustain service model for North American strong margins and international growth (cid:2) Strengthened the capital structure and (cid:2) Seize market opportunities aligned balance sheet through decisive steps to with our diverse fleet and vertically conserve cash and reduce debt by integrated service mix $565 million (cid:2) Utilize financial flexibility and strength (cid:2) Achieved the best safety record in to facilitate growth strategy, including company history, advancing toward conversion of trust to a corporation the Target Zero goal of no reportable incidents (cid:2) Integrated U.S. operations, delivered 16 new rig builds under term contract, and took the industry lead to rationalize less productive assets while high- grading the rig fleet CORPORATE INFORMATION TRUSTEES Robert J. S. Gibson Allen R. Hagerman, FCA Patrick M. Murray DIRECTORS Frank M. Brown William T. Donovan W.C. (Mickey) Dunn Brian A. Felesky, CM, Q.C. Robert J. S. Gibson Allen R. Hagerman, FCA Stephen J. J. Letwin Patrick M. Murray Kevin A. Neveu Frederick W. Pheasey Robert L. Phillips Trevor M. Turbidy OFFICERS Kevin A. Neveu President and Chief Executive Officer Gene C. Stahl President, Drilling Operations Douglas J. Strong Chief Financial Officer David W. Wehlmann Executive Vice President, Investor Relations Joanne L. Alexander Vice President, General Counsel and Corporate Secretary Kenneth J. Haddad Vice President, Business Development Darren J. Ruhr Vice President, Corporate Services LEAD BANK Royal Bank of Canada Calgary, Alberta AUDITORS KPMG LLP Calgary, Alberta HEAD OFFICE 4200, 150 – 6th Avenue SW Calgary, Alberta, Canada T2P 3Y7 Telephone: 403-716-4575 Email: info@precisiondrilling.com www.precisiondrilling.com Super Single®, Super Triple® and Super Series® are registered trademarks of Precision Drilling Corporation in Canada. PD 09AR Cover Mar24SJ_Layout 1 24/03/10 9:22 AM Page 1 4200, 150 – 6th Avenue SW Calgary, Alberta, Canada T2P 3Y7 Telephone: 403-716-4575 Email: info@precisiondrilling.com www.precisiondrilling.com P R E C I S I O N D R I L L I N G T R U S T 2 0 0 9 A N N U A L R E P O R T N O I S I C E R P W E N E C N E I L I S E R 9 0 0 2 T R O P E R L A U N N A H T W O R G 9 0 0 2 G N I L L I R D N O I S I C E R P E U L A V H G I H E C N A M R O F R E P H G I H 

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