Precision Drilling Corporation
Annual Report 2007

Plain-text annual report

07 Precision Drilling Trust 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 1 2 3 4 5 6 7 Overview and Outlook 3 Dynamics of the Oilfield Services Industry 10 Precision’s Development 14 Financial Results 21 Critical Accounting Estimates, New Accounting Standards and Business Risks 32 Disclosure Controls and Procedures 38 Cautionary Statement Regarding Forward-Looking Information and Statements 39 FINANCIAL REPORTING Management’s Report to the Unitholders 41 Auditors’ Report to the Unitholders 43 Report of Independent Registered Public Accounting Firm 44 Consolidated Financial Statements 45 Notes to Consolidated Financial Statements 48 SUPPLEMENTAL INFORMATION 68 MD&A Precision Drilling Trust MANAGEMENT’S DISCUSSION AND ANALYSIS This Management’s Discussion and Analysis (“MD&A”), Canada and the United States are described in Note 16 prepared as at March 20, 2008 focuses on the to the Consolidated Financial Statements. Additional Consolidated Financial Statements, and pertains to information relating to the Trust, including the Annual known risks and uncertainties relating to the oilfield Information Form, has been filed with SEDAR and is services sector. This discussion should not be available at www.sedar.com. 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” on page 39 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 With the conversion of the continuing assets and businesses of Precision Drilling Corporation to an income trust on November 7, 2005 pursuant to a plan of arrangement, the Trust, as the successor in interest to Precision Drilling Corporation, has been accounted for as a continuity of interest. Commencing with the year ended December 31, 2005 the Consolidated Financial Statements of the Trust reflect the financial position, results of operations and cash flows as if the Trust had always carried on the business formerly carried on by Precision Drilling Corporation. P R E C I S I O N D R I L L I N G T R U S T 1 FINANCIAL AND OPERATING HIGHLIGHTS (Stated in thousands of Canadian dollars, except per diluted unit amounts) Years ended December 31, Revenue Operating earnings (1) Earnings from continuing operations Discontinued operations, net of tax (2) Net earnings Cash provided by continuing operations Net capital spending from continuing operations (3) Distributions declared – cash Distributions declared – in-kind Per diluted unit information: Earnings from continuing operations Net earnings Distributions declared – cash Distributions declared – in-kind Drilling rig operating days: Canada United States Service rig operating hours: Canada % Increase (Decrease) 2007 % Increase (Decrease) 2006 % Increase (Decrease) 2005 $ 1,009,201 356,351 342,820 2,956 345,776 484,115 181,239 246,485 30,182 2.73 2.75 1.96 0.24 30,475 1,850 (30) (40) (40) n/m (40) (21) (22) (45) 23 (40) (40) (45) 23 (32) 988 $ 1,437,584 595,279 572,512 7,077 579,589 609,744 233,693 447,001 24,523 4.56 4.62 3.56 0.195 44,768 170 13 28 159 n/m (64) 196 67 n/m n/m 159 (64) n/m n/m (5) n/m $ 1,269,179 465,378 220,848 1,409,715 1,630,563 206,013 140,077 70,510 – 1.76 13.00 0.562 – 46,937 – 355,997 (26) 480,137 1 477,232 23 40 17 n/m 559 (28) 23 n/m – 9 516 n/m – 13 – 1 (1) Non-GAAP measure. See page 38. (2) Includes gain on disposition of discontinued operations. (3) Excludes acquisitions and discontinued operations. n/m – calculation not meaningful. FINANCIAL POSITION AND RATIOS (Stated in thousands of Canadian dollars, except ratios) Years ended December 31, 2007 2006 2005 Working capital Working capital ratio Long-term debt (1) Total assets Enterprise value (2) Long-term debt to long-term debt plus equity (1) Long-term debt to cash provided by continuing operations (1) Long-term debt to enterprise value (1) Interest coverage (3) (1) Excludes current portion of long-term debt which is included in working capital. $ 140,374 2.1 119,826 $ $ 1,763,477 $ 1,877,139 0.08 0.25 0.06 48.7 $ 166,484 1.8 140,880 $ $ 1,761,186 $ 3,369,860 0.10 0.23 0.04 74.1 $ 152,754 1.4 96,838 $ $ 1,718,882 $ 4,759,289 0.08 0.47 0.02 15.9 (2) Unit price as at December 31 multiplied by the number of units outstanding plus long-term debt minus working capital. See page 29. (3) Operating earnings divided by net interest expense. 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 MD&A 1 OVERVIEW AND OUTLOOK Precision’s 2007 results were impacted by the Canadian industry decline in the drilling and servicing of natural gas wells with partial offset from successful growth in the United States. After record profitability in 2006, 2007 was a challenging year with back to basic Canadian business fundamentals. Safety, cost control, competitive bidding and the drive for more efficient operations dominated Precision’s operating focus in 2007. Robust market conditions in 2005 and 2006 led drilling contractors to expand the number of industry land drilling rigs in Canada by approximately 180 drilling rigs or 25% from the number of rigs available at the end of 2004. For Canada, the decline in 2007 activity combined with an increase in industry equipment capacity led to some of the lowest equipment utilization in a decade. The weakness in natural gas prices was substantially the result of an over supply of natural gas as United States storage levels exceeded the five-year average by as much as 20% early in 2007. To exit 2007, storage levels returned to more moderate levels at 6% above the five-year average. Soft natural gas fundamentals resulted in a 24% decrease in Canadian industry drilling operating days over 2006. Crude oil pricing reached record levels in 2007 and created a slight shift in drilling focus from natural gas to oil. However, conventional North American oilfield service activity is dependent on natural gas wells. Generally, natural gas wells account for a range of 70% to 80% of land drilling in Canada and the United States. In September 2007 a report by the Alberta Royalty Review Panel for the Alberta government proposed increased royalties on oil and gas production in the province commencing in 2009. About 75% of conventional oilfield services in the Western Canada Sedimentary Basin (“WCSB”) are conducted in Alberta. In November 2007 the Alberta government accepted certain of the Panel’s recommendations to change the royalty structure effective January 1, 2009. The new structure unsettled producers just as they began to develop 2008 budgets and prompted many to reduce their capital spending until they fully understood the new royalty structure and the impact it would have on drilling economics. Given these challenging conditions, Precision was still able to generate an operating earnings margin of 35% for the year, declare cash distributions to unitholders of $246 million, reinvest $181 million in net capital spending and reduce long-term debt by $21 million. Through the cyclical highs of 2005 and early 2006 and 18 months into the current down cycle in Canada, Precision has maintained a strong financial position. P R E C I S I O N D R I L L I N G T R U S T 3 For Precision fiscal 2007 was a year characterized by reduced customer demand in Canada, growing opportunity in the United States land drilling market and approaching opportunity for global drilling markets. Given this backdrop, Precision acted decisively in 2007: K In August 2007, Kevin Neveu was appointed Chief Executive Officer of Precision. Mr. Neveu has over 25 years of experience in the oilfield services sector in North America and international operations. K Robert Phillips was appointed Chairman of the Board of Directors for Precision Drilling Corporation. K After 22 years as the Chief Executive of Precision, Hank Swartout retired in August 2007. Under Mr. Swartout’s leadership Precision grew from a four drilling rig operation in 1985 to 241 drilling rigs as at December 2006 and expanded continuing operations to include service rigs, camp and catering, snubbing, ancillary equipment, rentals and waste water treatment services. K Continued at year-end to carry low levels of long-term debt and had access to substantial lines of credit to fund future investment. K Achieved the safest year for Precision’s people in its history. K Focused capital expansion efforts toward growing its high performance rig fleet. K Delivered growth in drilling rig operations with 16 new Super Series rigs deployed to drilling projects with customers in Canada and the United States. K Deployed a drilling rig to Latin America. K Improved the underlying cost structure in Canadian operations with staff reduction and asset retirements in the fourth quarter. K Declared cash distributions of $246 million or $1.96 per diluted unit, 71% of net earnings. K Generated a return on unitholders’ equity of 27%. K Monitored the impact of the October 31, 2006 tax measures and subsequent amendments that will change the tax flow-through nature of Precision’s current income trust structure by January 1, 2011. Precision continued to focus on its business strategy and will work to ensure it has the optimal capital structure to maximize unitholder value. In a move to diversify geographic operations and become less dependent on the cyclical nature of oilfield services in Canada, Precision commenced drilling operations in the United States in June 2006 and continued with a strategic deployment of drilling rigs throughout 2007. Precision began 2007 with one drilling rig in the United States and ended with 12 rigs and plans for continued growth. All 12 drilling rigs operating in the United States are working under term contracts and had a combined utilization rate including move days of 99%. Precision’s growth in the United States is focused on providing customers with high performance services to meet rising demand and to displace underperforming competitor rigs. Notwithstanding plans to continue to diversify geographically, Precision is committed to continuing to be a premier oilfield service company in the WCSB. The Canadian oil and gas industry represents an important market for Precision and one in which Precision will continue to upgrade its asset mix. Strong oil prices have maintained a robust international drilling market and for Precision during 2008 the non-compete provision from a 2005 divestiture will expire. This will permit Precision to fully pursue global opportunities and consider certain new business lines. Late in 2007 Precision entered into a contractual arrangement and deployed a drilling rig to Latin America. This has enabled Precision to begin reestablishing the infrastructure for the international market and reflects early marketing efforts to identify available diversification opportunities. 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 Low debt levels have enabled Precision to cope with a weakened operating environment in 2007 and remain opportunistic toward future growth through available debt facilities. A strong balance sheet allows Precision to invest in meaningful growth opportunities, either organic or through industry consolidation, as they may arise. Historic Levels of Long-term Debt $ millions Long-term Debt (LTD) Equity LTD to LTD plus Equity Ratio Ratio 2,500 2,000 1,500 1,000 500 0.50 0.40 0.30 0.20 0.10 With over $750 million in debt facilities available as at December 31, 2007 Precision had borrowing capacity of over $600 million. 1999 2000 2001 2002 2003 2004 2005 2006 2007 In December 2007 Precision announced plans to initiate an estimated 2008 capital expenditure program of $370 million. The proposed investments are comprised of $75 million for upgrade of existing equipment and infrastructure and $295 million for expansion of its equipment fleet. Most of this expansion capital is targeted for the construction of 19 new drilling rigs for the North American market. The first three rigs in this program have been contracted with one customer for work in the Rocky Mountain region of the United States pursuant to a multi-year term with deployment expected to begin in the fourth quarter of 2008. Looking back on fiscal 2007, Precision moved its “High Performance – High Value” business strategy forward through noteworthy performance. Profitability K Precision benefited from strong industry pricing established in 2006 to generate solid earnings from continuing operations in 2007 of $343 million or $2.73 per diluted unit compared to $573 million or $4.56 per diluted unit in 2006. K Precision generated operating earnings of $356 million, a decrease of $239 million or 40% over 2006. As a percent of revenue, operating margins were strong at 35%, a decline of six percentage points over record-setting 2006. Growth K Net capital investment in 2007 for the purchase of property, plant and equipment decreased 22% or $52 million from the prior year to $181 million. Before considering proceeds on asset disposals of $6 million, Precision invested $46 million toward the upgrade of its existing asset base and $141 million on expansionary initiatives. K Favourable year round weather and customer demand in United States natural gas basins provided attractive returns on new capital investment. K Precision grew its contract drilling operation in the United States from one to 12 rigs through the deployment of seven new build Super Series rigs and four rigs from the Canadian rig fleet. K Precision added nine new Super Series drilling rigs to its Canadian fleet, six Super Single™ rigs and three Super Triples. Precision continued to upgrade its asset base and confirm its reputation as a high performance driller through these new rig additions and the decommissioning of 11 low performing rigs. P R E C I S I O N D R I L L I N G T R U S T 5 K Precision mobilized a triple rig from Canada to Latin America late in 2007. K Precision completed the construction of two service rigs under a long-term customer arrangement and decommissioned 16 service rigs. K The camp and catering division continued to broaden its offering towards larger base camp opportunities. K The snubbing division commissioned its first rack and pinion self-contained unit capable of snubbing and providing other well servicing operations pursuant to a long-term customer arrangement. K The wastewater treatment division grew its fleet of equipment by about 25% and diversified its product offering toward smaller capacity wellsite applications. K The rental division shifted equipment towards WCSB oil markets to optimize utilization. Passionately Pursue Target Zero Safety Vision K Precision made significant strides towards its Target Zero safety vision. The year-over-year improvement in safe work practices continued for Precision, resulting in a 15% reduction in workplace recordable incident frequency from the prior year and a 46% reduction in the past five years. Precision’s commitment to its safety programs and education has not only reduced the incident frequency but the severity of injuries was also lower. In the past five years, Precision has experienced a 56% reduction in lost time injury frequency. Build Upon Our Core Group of People K People are Precision’s most important asset; employees deliver high performance and provide customer value. A North American shortage of skilled and experienced oilfield employees carried into 2007. Precision focused on the retention of experienced employees through initiatives that provide a safe and productive work environment, opportunity for advancement and added wage security through initiatives such as the Designated Driller Program. K Precision completed its second year of internal control certification over financial reporting pursuant to Canadian and United States securities regulations. In addition to financial controls, initiatives have reinforced the joint code of business conduct and ethics policy and provided opportunities for Precision’s management to strengthen its skill in identifying and managing risk. K During the fourth quarter, Precision undertook initiatives to align infrastructure with the current operating environment in Canada and expansion in the United States. Cash Distributions to Unitholders K For 2007 Precision declared cash distributions of $246 million or $1.96 per diluted unit compared to $447 million or $3.56 per diluted unit in 2006. K Precision generated distributable cash from operations of $311 million compared to $353 million in the prior year. This calculation started with $484 million in cash provided from continuing operations less $181 million for net capital expenditures and a recovery of $8 million for unfunded long-term incentive plan obligations. 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 SUMMARY OF CONSOLIDATED STATEMENTS OF EARNINGS (Stated in thousands of Canadian dollars) Years ended December 31, Revenue: Contract Drilling Services Completion and Production Services Inter-segment elimination Operating earnings: (1) Contract Drilling Services Completion and Production Services Corporate and Other Interest, net Premium on redemption of bonds Loss on disposal of short-term investments Other Earnings from continuing operations before income taxes Income taxes Earnings from continuing operations Discontinued operations, net of tax Net earnings (1) Non-GAAP measure. See page 38. Revenue and Operating Earnings 2007 2006 2005 $ 694,340 327,471 (12,610) $ 1,009,821 441,017 (13,254) $ 916,221 369,667 (16,709) 1,009,201 1,437,584 1,269,179 284,754 100,596 (28,999) 356,351 7,318 – – – 349,033 6,213 342,820 2,956 473,624 163,119 (41,464) 595,279 8,029 – – (408) 587,658 15,146 572,512 7,077 404,385 121,643 (60,650) 465,378 29,270 71,885 70,992 – 293,231 72,383 220,848 1,409,715 $ 345,776 $ 579,589 $ 1,630,563 $ millions Revenue – Contract Drilling Operating Earnings – Contract Drilling Revenue – Completion & Production Operating Earnings – Completion & Production 1,600 1,400 1,200 1,000 800 600 400 200 2003 2004 2005 2006 2007 Capital Expenditures by Type $ millions Upgrade Expansion 300 250 200 150 100 50 For 2007, industry conditions in Canada have reduced Precision’s operating results from historic highs. In the past two years, Precision has invested more towards expansionary initiatives to grow its fleet of Super Series drilling rigs. 2003 2004 2005 2006 2007 P R E C I S I O N D R I L L I N G T R U S T 7 For the year ended December 31, 2007 Precision’s earnings from continuing operations were $343 million or $2.73 per diluted unit compared to $573 million or $4.56 per diluted unit in 2006. The decrease of $1.83 per diluted unit was due to lower activity and pricing for Precision’s Canadian services in 2007 compared to 2006. The decline in activity was due to decreased demand for natural gas services in the WCSB brought about by lower natural gas pricing in North America and less confidence in the short-term future price of natural gas. For 2007, earnings benefited from a future income tax recovery of $22 million due to enacted Canadian federal tax rate reductions and were lowered by an asset write down charge of $7 million for decommissioned rigs and a $5 million expense for personnel reductions. As a result of these three items plus the tax benefit of $4 million from asset write downs and personnel reductions, net earnings increased by $14 million or $0.11 per diluted unit as compared to tax recoveries in 2006 of $21 million or $0.17 per diluted unit. Fiscal 2007 results were indicative of soft natural gas prices and strong oil prices. West Texas Intermediate (“WTI”) crude oil averaged US$72.45 per barrel in 2007 versus US$66.11 in 2006 and Henry Hub natural gas averaged US$6.94 per MMBtu in 2007 versus US$6.72 in 2006. On Canadian markets the average price for AECO natural gas one-year forward was $7.50 per MMBtu in 2007 compared to $8.49 in 2006. The AECO natural gas price for December 2006 averaged $6.76 per MMBtu and traded as low as $4.69 in September 2007 before increasing steadily to close out December 2007 at $6.12 per MMBtu. The weakening of the U.S. dollar compared with the Canadian dollar has also had a negative impact on the cash flow of many of Precision’s Canadian customers. During 2007 the Canadian dollar appreciated by 18% against the U.S. dollar. During 2007 there were 18,342 wells drilled in western Canada on a rig release basis, a 19% decline from the 22,575 drilled in 2006. With the decline in the number and change in the mix of wells drilled, total industry drilling operating days declined by 24% to 120,961. The average industry drilling operating days per well in 2007 was 6.6 days compared to 7.0 days in 2006. In 2007, higher oil and lower gas prices prompted some customers to shift drilling dollars to oil prospects in lieu of natural gas or natural gas in coal. In the WCSB in 2007 the total number of well licenses issued for oil targets was 6,486 which represented a 10% decline over 2006 and 34% of the total licenses issued compared to 27% in 2006. Well licenses for natural gas prospects declined 30% in 2007 to 12,740. 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 OUTLOOK The bearish oilfield services demand that Precision and the Canadian industry faced in 2007 is expected to persist at least through the first half of 2008. Precision expects continued pressure on pricing and an extremely competitive seasonal spring break-up. As capacity to provide services continues to exceed demand and pricing becomes more competitive, any further reductions will have a proportionately greater impact on profit margins. The permanent fleet reductions and fixed expense reductions in the fourth quarter of 2007 were tailored to size Precision more appropriately for this level of activity and competition. Precision is well positioned to manage the existing downturn in the sector due to its strong balance sheet, ability to control costs and solid platform for future growth with its people, technology and an increasingly diversified geographic base. Wages and field crew rates are expected to hold at current levels for 2008. To the end of February 2008, natural gas prices have advanced approximately 25% with storage levels about 10% below the prior year as winter withdrawals are at normal seasonal levels. Strong natural gas consumption coupled with reduced Canadian exports and uncertain liquefied natural gas (“LNG”) imports to the United States may lead to strengthening economic fundamentals for drilling later in 2008 with improved demand for services possible in late third or fourth quarter. United States Working Gas in Underground Storage Compared with 5-Year Range Billion Cubic Feet Period Storage 5-year Historical Range 3,600 3,200 2,800 2,400 2,000 1,600 1,200 800 400 Storage levels are moderating after two years of seasonally adjusted highs. Source: U.S. Energy Information Administration (EIA) Feb 06 May 06 Aug 06 Nov 06 Feb 07 May 07 Aug 07 Nov 07 Feb 08 Precision will continue its focus on value based high performance services where customers recognize and reward superior performance. This presents Precision with significant opportunity, especially in technically demanding unconventional drilling applications. A greater proportion of wells drilled in North America are seeking unconventional resource plays and due to the complexity of these programs high performance drilling rigs and services are required. Precision will remain highly focused on United States expansion. Precision will aggressively exploit organic growth opportunities with customers in Canada and the United States given the continued demand for premium equipment such as Precision’s Super Series rigs. A clear delineation between underperforming rigs and high performance, highly mobile, well designed rigs with exceptional crews has emerged. Precision is finding that its operational execution and safety performance are significant marketing advantages as United States operations grow and its Canadian fleet remains underutilized. Precision converted to an income trust in 2005 as the tax rules of the day allowed the market to place a higher value for unitholders on the flow-through structure than the traditional corporate structure. In light of legislated and proposed changes the Board of Trustees, along with the Board of Directors and management, are examining whether the current legal entity structure and capital structure are appropriate for Precision’s business strategy and in the best interests of unitholders. P R E C I S I O N D R I L L I N G T R U S T 9 MD&A 2 DYNAMICS OF THE OILFIELD SERVICES INDUSTRY Through this report, management is presenting its views of Precision’s business and the industry in which it operates. 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. 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 primary fuel sources for generating heat and electricity and are critical building blocks for countless consumer products. With 6.6 billion people worldwide and the world population expected to rise 1.1% per year, global energy demand is unprecedented and rising. From a reference year of 2004, energy consumption is projected by the United States government Energy Information Administration (“EIA”) to increase 57% by 2030 with oil, natural gas and coal meeting approximately 86% of global demand. World oil consumption is predicted to rise about 1.9% in 2008 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 in this century with security of supply becoming a dominate theme globally. The EIA is forecasting natural gas consumption increases of 1.9% on average per annum to 2030 as rising oil prices increase the demand for natural gas as an alternative fuel in industrial and electrical sectors in developed and developing economies. NORTH AMERICAN MARKETS The economics of the oilfield service industry are aligned with global and regional fundamentals. Important regional drivers for the industry in North America include the underlying hydrocarbon make-up of the varied basins and the existence of established, competitive and efficient service infrastructure. With high service costs per barrel of oil equivalent production in Canada and increased pipeline takeaway capacity within the United States due to infrastructure investment, capital allocation by customers has increasingly favoured unconventional natural gas basins in the United States. The hydrocarbon basins of North America are diverse and conventional oil and natural gas reservoirs exist at a variety of depths. These conventional sources are complemented by more costly and challenging unconventional reservoirs associated with oil sands, heavy oil, natural gas in coal and in shale and in deeper, low permeability formations. About 70% of the proven natural gas reserves in North America are situated in the United States with the remaining 30% in Canada. In 2007, 83% of drilling activity in the United States and 70% in Canada targeted natural gas. 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 Estimated Proved Reserves of Natural Gas Canadian Basins United States Basins Estimated Proved Reserves (Tcf) 4 1 2 5 6 3 8 7 Canada 1 Mackenzie/Beaufort 2 Western Canada 3 Eastern Canada United States 4 Alaska 5 Rocky Mountains 6 Mid-continent/Permian 7 Gulf Region 8 Other Lower-48 Total 9 54 13 76 10 60 44 72 21 207 283 Source: Ziff Energy, as of January 1, 2007 The emergence of LNG as a fungible commodity is an important new source of supply to North America that could offset production declines from mature reservoirs and help meet rising natural gas demand. There are still technical, political and environmental challenges for significant LNG developments to occur in North America, but it is widely projected to be a necessary source of supply as demand for natural gas increases. Less than 5% of the world’s proven reserves of natural gas exist in North America yet more than 25% of worldwide natural gas consumption occurs in North America. With next-door proximity to the world’s biggest energy consumer Canada has become the world’s seventh largest oil producer and third largest producer of natural gas. With oil sands development, Canada is one of the few countries with growing oil production. A highly integrated continental energy transportation system, security of supply and access to United States markets has made Canada one of the largest energy providers to the United States. Currently, over half of Canadian oil and natural gas production is exported to the United States. ECONOMIC DRIVERS OF THE OILFIELD SERVICES INDUSTRY 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, 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. Natural gas is priced in continental markets with supply from LNG a growing factor subject to availability. P R E C I S I O N D R I L L I N G T R U S T 11 There is a narrowing supply-demand balance for natural gas in North America. Many industry observers believe a new pricing floor may be set due to the combination of production declines and demand growth. New hydrocarbon reserves are clearly more costly and difficult to discover and develop and it is becoming increasingly necessary to use high performance drilling rigs and support services to complete well programs. It has taken record drilling activity over the last three years in North America to marginally increase overall natural gas production levels. To a large extent this production growth has been derived from unconventional production with significant first-year decline rates. Number of Producing Wells in Western Canada Oil Wells Natural Gas Wells 200,000 160,000 120,000 80,000 40,000 There has been a steady increase in the number of producing natural gas wells in the WCSB in the last 10 years. Source: 1998–2006 Alberta Energy and Utilities Board, 2007 Precision estimate 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Estimate Rising energy demand coupled with depletion of conventional resource basins has created an historic shift in the oil and natural gas industry in North America to develop unconventional resources such as oil sands, natural gas in shale and in coal and in deeper, low permeability formations. The economics of unconventional resource plays are enhanced by technology such as multi-well pad locations, high performance drilling rigs and advanced reservoir stimulation techniques. Reserves to production ratios, which indicate how quickly reserves are depleting, have flattened after a period of decline starting in the 1990s. This implies that drilling activity must stay level or increase just to maintain current production and producers may need to drill deeper, more remote resource plays to secure large gas fields and extend reserve life. WCSB Well Completions vs AECO Spot Natural Gas Price WCSB Completed Wells Oil Gas Dry Service AECO Spot Price C$/MMBtu The number of natural 25,000 20,000 15,000 10,000 5,000 10.00 gas well completions 8.00 6.00 4.00 2.00 in Canada is directly impacted by natural gas prices. Source: Canadian Association of Oilwell Drilling Contractors (“CAODC”), Ziff Energy 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 The graph above compares WCSB well completions and natural gas pricing over the past 10 years. A decline in the natural gas price in the last two years led to a significant decline in 2007 gas well completions. Soft natural gas prices were the result of low consumption due to mild winters and marginally higher productivity in the United States which placed gas storage above the five-year average. With growing energy demand, the supply of drilling rigs in Canada increased steadily over the past 14 years to an all-time high of about 900. Customer demand, measured by annual drilling rig operating day utilization, peaked at 71% in 1997 and has since ranged between 38% and 60%. Industry utilization for 2007 was 38%. The current excess 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 drilling rig capacity in Canada has prompted some oilfield service providers to consider relocating certain assets in their drilling fleets to the United States land drilling market. As illustrated below, Canadian rig activity fluctuates with the seasons, an event which generally does not occur in the United States. Active and Existing Canadian Drilling Rigs Total Active Total Fleet 900 800 700 600 500 400 300 200 100 Canadian rig activity is seasonal and has declined from record levels in 2005 due to lower natural gas prices. Source: CAODC Q1 Q2 Q3 Q4 Q1 2001 Q2 Q3 Q4 Q1 2002 Q2 Q3 Q4 Q1 2003 Q2 Q3 Q4 Q1 2004 Q2 Q3 Q4 Q1 2005 Q2 Q3 Q4 2006 Q1 Q2 Q3 Q4 2007 The United States land drilling fleet has steadily increased from about 1,500 rigs in 2002 to a recent peak in 2007 of about 2,200 rigs. Active and Existing U.S. Drilling Rigs Total Active Total Fleet 2,500 2,000 1,500 1,000 500 U.S. rig counts have maintained a steady increase in activity in the past six years. Source: RigData Q1 Q2 Q3 Q4 Q1 2001 Q2 Q3 Q4 Q1 2002 Q2 Q3 Q4 Q1 2003 Q2 Q3 Q4 Q1 2004 Q2 Q3 Q4 Q1 2005 Q2 Q3 Q4 2006 Q1 Q2 Q3 Q4 2007 Precision estimates about 1,200 drilling rigs in the United States fleet were constructed prior to 1990 and underperform when tasked with drilling unconventional complex resource plays. With increased exploitation of unconventional resource basins the demand for high performing rigs and crews capturing premium pricing continues to grow, displacing the underperforming rigs. Active U.S. Rigs by Well Type Percentage Vertical Drilling Horizontal and Directional 100 80 60 40 20 The increase in horizontal and directional drilling is indicative of the increasing demand for high performance drilling rigs. Source: Baker Hughes 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 P R E C I S I O N D R I L L I N G T R U S T 13 MD&A 3 PRECISION’S DEVELOPMENT PRECISION’S HISTORY OF CONTINUING OPERATIONS 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 twenty years has expanded fleet capacity and added complementary businesses. For the past decade, Precision has been Canada’s largest oilfield services provider. Contract Drilling Services Segment Precision’s Contract Drilling Services are known within the industry as a part of the upstream sector with operations at the well location to facilitate the drilling of natural gas, oil and, in rare circumstances, geothermal wells. It is the underlying well program requirements that determine which rig is best suited to drill a particular prospect for customers. Precision’s development was founded on the successful integration of acquisitions. In the decade following a 1987 reverse takeover, a series of acquisitions expanded Precision’s Canadian drilling fleet from four to 106 rigs. With the acquisition of Kenting Energy Services Inc. in 1997, Precision essentially doubled its fleet to 200 rigs representing approximately 40% of the drilling fleet in Canada. The acquisitions of coil tubing drilling rigs and other shallow drilling rigs in 2000 rounded out the acquisition history for Precision’s fleet in Canada. To close out fiscal 2007, after upgrading the fleet through strategic new rig builds and decommissions, Precision’s 232 drilling rigs in Canada comprised 26% of the Canadian market, 12 rigs in the United States represented a U.S. market start and share of 1% and one rig in Latin America launched a new global direction for Precision. To better operate ancillary assets and to provide a comprehensive suite of services to customers, Precision acquired and reorganized assets into complementary businesses. In 1993, Precision entered the camp and catering business with the acquisition of LRG Oilfield Services Ltd. Along with camps from drilling rig business acquisitions and the purchase in 2003 of McKenzie Caterers (1984) Ltd., this division now has 102 camps. In 1996 Precision added in-house capabilities for the design, fabrication and maintenance of rig components with the acquisition of Rostel Industries Ltd. The 1997 acquisition of Columbia Oilfield Supply Ltd. led to the integration of purchasing systems and qualitative improvements in product selection and standardization in all of Precision’s businesses. Completion and Production Services Segment Precision’s Completion and Production Services are also known within the oil and gas industry to be a part of the upstream sector with operations at the well location to complete wells that have been drilled and to maintain 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. 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 In 1996 Precision diversified into businesses that became the foundation for the Completion and Production Services segment, specifically Precision Well Servicing, Live Well Service and Precision Rentals, through the acquisition of EnServ Corporation. The acquisition enabled Precision to offer services that tracked the life of a particular oil or natural gas well, build customer relationships and moderate demand volatility associated with the drilling of new wells. In 2000 Precision became fully vested in the Canadian service rig business with the acquisition of CenAlta Energy Services Inc. to create a combined fleet of 257 service rigs and an industry-leading market share at the time of 28%. Through additional acquisitions in the late 1990s the rental businesses grew and in 2002 were combined and branded as Precision Rentals. In 2006, Precision expanded into the business of remote work site wastewater treatment with the acquisition of Terra Water Group Ltd. To close fiscal 2007, after adding two new service rigs and decommissioning 16, Precision’s 223 service rigs and 27 snubbing units comprised 20% and 24% of the Canadian market. In addition to completing and servicing wells, the segment offers snubbing to service natural gas wells while pressurized, rental equipment and wastewater treatment for remote accommodations. 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, automation, advanced control systems, minimal environmental impact, and highly trained crews. A freestanding service rig lowers costs for customers through set up efficiency and minimal ground disturbance which reduces the risk of striking underground utilities. Over the past 12 years Precision has been developing the Super Series drilling rigs and has built 35 Super Single™, seven Super Single™ Light and eight Super Triple rigs. Precision also manufactured 10 freestanding mobile single and six slant service rigs. STRATEGIC DIRECTION Precision is geographically diversifying to the United States and international markets by leveraging its well known Canadian reputation for “High Performance – High Value” on-shore drilling services for oil and natural gas exploration and development. Precision delivers “High Performance” services through excellent people, comprehensive support systems and deploying technically superior equipment. This unique “High Performance” competitive advantage serves to reduce customer cost and minimize the operational risks associated with drilling and servicing oil and gas wells. Precision’s reputation of “High Value” is evident in its leading financial and operational performance, employee retention, safety and environmental performance and specifically its market share growth in the new entry markets. Precision’s business strategy includes the following: K To geographically diversify into markets beyond Canada to reduce seasonality of equipment utilization and dependence on underlying economics of the WCSB; K To capitalize on production growth and resulting drilling opportunities in the United States, especially unconventional natural gas wells; K To pursue global oil drilling opportunities; K To invest in asset growth that renders customer value through enhanced service performance: – New asset deployment results in organic growth and market share gains as onshore oil and gas basins have matured. Precision’s superior equipment technology delivers significantly better operating performance, especially in complex and demanding customer well programs; – Precision seeks consolidation opportunities to implement its core capabilities of employee recruitment, safety, training, environmental footprint, equipment maintenance, equipment manufacturing, supply chain management and cost control to upgrade performance of existing equipment fleets. P R E C I S I O N D R I L L I N G T R U S T 15 Precision’s core capabilities reside with its employees, systems, and technology. These areas of competence provide the operating leverage for organic new asset construction growth and for consolidation based growth. Precision continually reviews assets, retiring those which are less competitive and upgrading others. Precision intends to continue to build high performance “Super Series” drilling rigs targeted to customers who recognize and reward the cost saving benefits of these services. 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 focuses on to monitor its performance are: Safety Management: Precision’s culture is based on the foundation of an all-encompassing Target Zero vision. Precision’s philosophy states that the workplace and organization can be free from injuries, equipment damage and negative environmental impact. Safety performance is a fundamental contributor to operating performance and the financial results Precision generates for unitholders. Safety is tracked through an industry standard recordable frequency statistic which is measured to benchmark successes and illustrate areas for improvement. Operating Efficiency: Precision maximizes the efficiency of its operations through its proximity to work sites, its operating practices and its versatility. Precision’s 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. Key factors which contribute to lower customer well costs are: K Mechanical downtime which is managed through preventative maintenance programs, detailed inspection processes, an extensive fleet of strategically placed spare equipment, an in-house supply chain, and continuous equipment upgrades; and K Non-productive time, or move, rig-up and rig-out time, which is minimized by decreasing the number of move loads per rig, using lighter move loads, and using mechanized equipment for safer and quicker rig component connections. 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 to reduce total well cost increases the value of the rig to the customer. 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 initiatives that provide a safe and productive work environment, opportunity 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. 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. Low debt levels have allowed Precision to manage the cyclical nature of the industry and provide the financial leverage to invest in meaningful growth opportunities. 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 OPERATING SEGMENTS In the Contract Drilling Services segment: K Precision Drilling operates 232 land drilling rigs in Canada; K Precision Drilling Oilfield Services operates 12 land drilling rigs in the United States; K A Precision affiliate operates one rig in Latin America; K LRG Catering operates 102 camps, with food catering, in Canada and the United States; K Rostel Industries provides engineering, machining, fabrication, component manufacturing and repair services for drilling and service rigs primarily for Precision’s operations; and K Columbia Oilfield Supply provides centralized procurement, standardized product selection, and coordinated distribution of goods for Precision’s operations. In the Completion and Production Services segment: K Precision Well Servicing operates 223 well completion and workover service rigs in Canada; K Live Well Service operates 27 snubbing units in Canada; K Precision Rentals provides approximately 13,000 rental items in Canada including well control equipment, surface equipment, specialty tubulars and wellsite accommodation units; and K Terra Water Systems provides 63 wastewater treatment units. Precision Drilling The tables below categorize the capacity and positioning of Precision’s drilling rig fleet for the past two years: 2007 Maximum Depth Rating Type of Drilling Rig Metres Feet Horsepower Canada U.S. International Total Single Super Single™ Double Super Triple Light triple Heavy triple Coiled tubing Total 2006 1,200 3,000 3,000 4,000 3,600 6,700 1,500 4,000 10,000 10,000 13,000 12,000 22,000 5,000 250-300 400-800 300-500 1,200 500-750 1,000-2,000 250-300 14 33 87 8 40 39 11 – 8 – – 2 2 – 232 12 – – – – – 1 – 1 14 41 87 8 42 42 11 245 Maximum Depth Rating Type of Drilling Rig Metres Feet Horsepower Canada U.S. International Total Single Super Single™ Double Super Triple Light triple Heavy triple Coiled tubing Total 1,200 3,000 3,000 4,000 3,600 6,700 1,500 4,000 10,000 10,000 13,000 12,000 22,000 5,000 250-300 400-600 300-500 1,200 500-750 1,000-2,000 250-300 14 28 94 5 44 44 11 240 – 1 – – – – – 1 – – – – – – – – 14 29 94 5 44 44 11 241 P R E C I S I O N D R I L L I N G T R U S T 17 The following table lists the drilling depth capability of Precision and industry drilling rigs in western Canada at December 31, 2007: Type of Drilling Rig Single Super Single™ (2) Double Super Triple (5) Light triple Heavy triple Coiled tubing Total Precision Fleet Industry Fleet (1) Maximum Depth Rating (metres) Number of Rigs % of Total % Market Share (3) Number of Rigs 1,200 3,000 3,000 4,000 3,600 6,700 1,500 14 33 87 8 40 39 11 6 14 38 3 17 17 5 232 100 8 89 22 100 34 36 16 26 165 37 393 8 116 109 70 898 % of Total 18 4 44 1 13 12 8 100 Change (4) 20 4 29 3 (1) (4) 5 56 (1) Source: Daily Oil Bulletin – Rig Locator Report as of January 2008. Precision has allocated the industry rig fleet by rig type and removed 11 decommissioned rigs. (2) Super Single™ excludes single rigs that do not have automated pipe-handling, a self-contained top drive or run extended length drill pipe/casing. (3) Market share means Precision’s rigs as a percent of industry rigs estimated by Precision. (4) Change in number of industry rigs as compared to the prior year. (5) Super Triple includes features such as extended length drill pipe, AC power, iron roughneck, mobility without cranes, top drive and an advanced control system. Precision Well Servicing The configuration of Precision Well Servicing’s Canadian fleet for the past four years is illustrated in the following table: Type of Service Rig Singles: Mobile Freestanding mobile Doubles: Mobile Freestanding mobile Skid Slants: Freestanding Total Horsepower 2007 2006 2005 2004 150-400 150-400 250-550 200-550 300-860 250-400 5 94 43 9 55 17 223 12 92 44 9 65 15 237 17 88 44 8 65 15 237 19 86 42 9 67 16 239 CAPACITY TO DELIVER Precision is a major supplier of services to oil and gas companies and its success is dependant on providing a complement of oilfield services that are cost effective to its customers. Precision prides itself on providing quality equipment operated by highly experienced and well trained crews. Maintaining customer relationships is fundamental to Precision’s success and is based in large part upon the ability to deliver. High Performance Drilling Rigs Precision Drilling is focused on providing efficient, cost-reducing drilling technology. Design innovations and technology improvements capture incremental time savings during all phases of the well drilling process, including moving between wells. 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 The versatile Super Single™ design comprises technical innovations in safety and drilling efficiency and outpaces competition in slant or directional drilling on single or multiple well pad locations in shallow to medium depth wells. It is extremely proficient on conventional vertical wells and has drilled in many regions of the world. Super Single™ rigs utilize extended length tubulars, integrated top drive, innovative unitization to facilitate quick moves between well locations, a small footprint to minimize environmental impact and enhanced safety features such as automated pipe handling and remotely operated torque wrenches. A scaled-down version without slant capability, the Super Single™ Light, also features an integrated top drive and automated pipe handling and is unitized and trailer mounted 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 fabricated to keep the 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 systems provides added precision and measurability along with a computerized electronic auto driller feature that precisely controls weight, rotation and torque on the drill bit. These rigs use extended length drill pipe, an integrated top drive, automated pipe handling with iron roughnecks and control automation off the rig floor. Large Diversified Rig Fleets Precision’s large diverse fleet of rigs is strategically deployed across the most active regions of the WCSB, and in targeted basins in the United States. 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 versatility make Precision a premium service provider. 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 and one in British Columbia. Snubbing complements traditional natural gas well servicing by allowing customers to work 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 for LRG Catering and other camp facilities. Precision Rentals supplies customers with an inventory of 13,000 pieces of specialized equipment and wellsite accommodations. Industry Leading Safety Program Safety 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 a fundamental belief that all injuries can be prevented. In 2007, 363 of Precision’s drilling and service rigs achieved Target Zero. Precision is a leader in adopting technological advancements which have made drilling rigs, service rigs and snubbing units safer. P R E C I S I O N D R I L L I N G T R U S T 19 Well-maintained Equipment Precision consistently reinvests capital to sustain and upgrade existing property, plant and equipment. Upgrade Capital Expenditures $/day 1,400 1,200 1,000 800 600 400 200 Upgrade Spending per Drilling Rig Operating Day Upgrade Spending per Service Rig Operating Hour $/hour 50 40 30 20 10 Well maintained equipment minimizes mechanical downtime and non-productive time. 2003 2004 2005 2006 2007 In addition to capital expenditures as illustrated above, equipment repair and maintenance expenses are benchmarked to activity levels in accordance with Precision’s maintenance and certification programs. Precision employs computer 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. Employees As a service company, Precision is as good as its people. An experienced, competent crew is a competitive strength and highly valued by customers. To recruit rig employees, Precision has centralized personnel departments and orientation and training programs. Information Systems Precision’s commitment to invest in a fully integrated enterprise-wide reporting system has improved business performance through real-time access to information across all functional areas. All divisions operate on a common integrated system using standardized business processes across 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 enquires. Rig manufacturing projects benefit from scheduling and budgeting tools as economies of scale can be identified and leveraged as construction demands increase. 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 MD&A 4 FINANCIAL RESULTS CONTRACT DRILLING SERVICES SEGMENT (Stated in thousands of Canadian dollars, except where indicated) Years ended December 31, Revenue Expenses: Operating General and administrative Depreciation Foreign exchange 2007 % of Revenue 2006 % of Revenue 2005 % of Revenue $ 694,340 $ 1,009,821 $ 916,221 345,043 19,946 43,120 1,477 49.7 2.9 6.2 0.2 41.0 470,713 27,225 38,573 (314) $ 473,624 46.6 2.7 3.8 – 46.9 448,930 23,911 39,233 (238) $ 404,385 49.0 2.6 4.3 – 44.1 Operating earnings (1) $ 284,754 % Increase 2007 (Decrease) 245 1.7 30,475 1,850 (31.9) 988.2 2006 241 44,768 170 % Increase (Decrease) 4.8 (4.6) – 2005 230 46,937 – % Increase (Decrease) 0.4 12.8 – $ 19,096 (7.0) $ 20,528 13.8 $ 18,034 9.3 4,718 6.5 5,813 1,232 (23.7) (9.7) (25.6) (2.5) 6,180 7.2 7,810 1,264 (20.4) 20.0 (12.3) 10.3 7,766 6.0 8,901 1,146 3.2 9.1 11.0 7.5 Number of drilling rigs (end of year) Drilling operating days: Canada United States Drilling revenue per operating day: Canada Drilling statistics: (2) Number of wells drilled Average days per well Number of metres drilled (000s) Average metres per well (1) Non-GAAP measure. See page 38. (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 21 2007 Compared to 2006 The Contract Drilling Services segment generated revenue of $694 million in 2007, 31% less than the record revenue of $1.0 billion in 2006. The decrease was due to lower equipment utilization and reduced pricing resulting from lower customer demand for natural gas drilling in Canada, partially offset by additional rigs and strong utilization in the United States. Operating earnings of $285 million decreased $189 million or 40% from $474 million in 2006 and were 41% of revenue in 2007 compared to 47% in 2006 primarily due to lower pricing in the final nine months of 2007. Operating expenses increased from 47% of revenue in 2006 to 50% in 2007. On an operating day basis, costs increased due to crew wage rate increases in October 2006 and an overall increase in the cost of materials. Lower equipment utilization also resulted in increased daily operating costs associated with fixed operating cost components. Capital expenditures for the Contract Drilling Services segment in 2007 were $159 million and included $126 million to expand the underlying asset base and $33 million to upgrade existing equipment. The majority of the expansion capital was associated with new drilling rig construction for operations in the United States and Canada. During 2007 the segment commissioned 16 new rigs backed by customer term arrangements and decommissioned 11 rigs. The Precision Drilling division revenues decreased $337 million or 37% over 2006 to $582 million. This decline was due to a decrease in customer demand resulting in lower utilization for Precision. Precision’s Canadian drilling rig activity in 2007 was down 14,293 operating days or 32% overall compared to 2006 as customers curtailed drilling due to low natural gas prices, changing royalty rates resulting from the Alberta government royalty review, a strong Canadian dollar relative to the U.S. dollar, record industry rig capacity and customer concern over high service costs. Industry operating days in Canada were 120,961, a decline of 24% from 158,416 in 2006. With an industry fleet expanded by 7% to 898 rigs at the end of 2007, the industry operating day utilization declined to 38% in 2007 from 55% in 2006. Average drilling rig operating day rates for Precision in Canada decreased 7% in 2007 from 2006. Rates held up well due to pricing for rigs under term contracts for Precision’s versatile, high performing rigs and strong pricing in the first quarter of 2007. Operating earnings decreased by 45% over 2006 due mainly to the 32% decrease in activity, the 7% decrease in the average operating day rate and 4% crew wage rate increase in October 2006. Depreciation expense for the year was $1 million higher than in 2006 as the impact of lower activity was offset by a $3 million write down charge for decommissioned rigs and a change in rig mix. Precision Drilling Oilfield Services in the United States generated revenue of $51 million in 2007, a ten-fold increase over 2006. The rig fleet grew from one rig at the end of 2006 to 12 rigs at the end of 2007 and operated at 99% utilization including move days. The fleet increase included seven new Super Single™ drilling rigs and four rigs deployed from Canada. United States operations are in the Rocky Mountain region based out of Colorado and the South Central region based out of Texas. LRG Catering experienced activity declines of 51% in 2007 from a record 2006, with revenue decreasing 43%. As a result of the lower industry activity, LRG experienced downward pricing pressure, however increased base camp activity mitigated average day rate declines. 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 allowed Precision to standardize product use and quality. 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 2006 Compared to 2005 The Contract Drilling Services segment generated record financial results in 2006. Revenue was $1.0 billion in 2006, an increase of $94 million or 10% from 2005 due to an increase in average pricing for Precision’s services. Operating earnings increased by $69 million or 17% to $474 million and were 47% of revenue in 2006 compared to 44% in 2005 primarily due to pricing improvements. Operating expenses declined from 49% of revenue in 2005 to 47% in 2006, but increased per operating day due to higher crew wages and cost of materials. Capital expenditures for the segment in 2006 were $220 million and included $158 million to expand the underlying asset base and $62 million to upgrade existing equipment. The majority of the expansion capital expenditure was associated with new drilling rig construction. The Precision Drilling division revenue increased by $73 million or 9% over 2005 to $919 million, with the decrease in activity for 2006 more than offset by increased rates. Operating earnings in the division increased by 17% over 2005 due mainly to a 14% increase in the average operating rate offset by a 5% decline in activity. Depreciation expense for the year was $3 million higher due to the change in rig mix in the year with increased deep rig activity and commissioning of new built rigs. Cost per operating day increased by 7% mainly due to hourly crew labour rate increases in October 2005 and 2006 of 7% and 4%, respectively and cost escalations for third party labour and materials associated with equipment maintenance programs. The division commissioned 13 new rigs under customer term arrangements. Precision spent $203 million in capital expenditures in 2006, nearly twice the spending of 2005. Precision Drilling Oilfield Services, Inc. began operations in the United States in June 2006, with one rig. LRG Catering achieved record growth in 2006 with activity increasing by 11% and revenue by 25% due in part to rate increases implemented in the fourth quarter of 2005. LRG expanded its fleet by 10 to 101 camps in 2006. COMPLETION AND PRODUCTION SERVICES SEGMENT (Stated in thousands of Canadian dollars, except where indicated) Years ended December 31, Revenue Expenses: Operating General and administrative Depreciation Foreign exchange 2007 % of Revenue 2006 % of Revenue 2005 % of Revenue $ 327,471 $ 441,017 $ 369,667 183,661 11,780 31,421 13 56.1 3.6 9.6 – 30.7 231,602 14,242 32,013 41 $ 163,119 52.5 3.2 7.3 – 37.0 209,657 11,021 27,402 (56) $ 121,643 56.7 3.0 7.4 – 32.9 Operating earnings (1) $ 100,596 % Increase 2007 (Decrease) % Increase (Decrease) 2006 % Increase (Decrease) 2005 Number of service rigs (end of year) Service rig operating hours Revenue per operating hour 223 355,997 730 $ (5.9) (25.9) 2.5 237 480,137 712 $ – 0.6 18.7 237 477,232 600 $ (0.8) 1.1 17.0 (1) Non-GAAP measure. See page 38. P R E C I S I O N D R I L L I N G T R U S T 23 2007 Compared to 2006 The Completion and Production Services segment revenue decreased by $114 million to $327 million mainly due to a decline in activity. Operating earnings decreased by $63 million or 38% and were 31% of revenue in 2007 compared to 37% in 2006 due mainly to lower service activity during the year. Operating expenses increased from 53% of revenue in 2006 to 56% in 2007. On a daily or hourly operating basis, costs increased due to crew wage rate increases in October 2006 and an overall increase in the cost of materials. Lower equipment utilization resulted in increased daily or hourly operating costs associated with fixed operating cost components. Reinvestment in equipment in recent years has helped to position the Completion and Production Services segment as an industry leader. Capital spending in 2007 of $27 million, down 32% from $39 million in 2006, included $15 million for the construction of slant service rigs, self-contained snubbing units, storage tanks and wastewater treatment units, and $12 million for replacement transporter trucks, doghouses, snubbing unit trucks, drill pipe for rental, tanks and a new operating facility. The Precision Well Servicing division revenue decreased by $82 million or 24% over 2006 to $260 million as moderately higher hourly operating rates could not offset reduced activity levels. Price increases established in the fourth quarter of 2006 were maintained through most of 2007, with downward adjustments in the second half. A total of 18,540 wells were rig released in 2007, a decrease of 18% from the 22,575 wells the prior year. However, with a lag between the drilling and completion of a well, the industry reported 19,272 well completions in 2007, a decline of 13% from 22,171 completions in 2006. Over the last five years, there were over 100,000 wells completed in western Canada which added to the ongoing maintenance demand to ensure continuous and efficient operation of producing wells. There are currently about 200,000 producing wells within the WCSB. Service rig contractors in western Canada increased the industry fleet capacity by about 5% to about 1,100 rigs at the end of 2007. Increased capacity coupled with fewer well completions due to depressed natural gas prices kept market pricing competitive. Operating earnings decreased by 33% over 2006 due mainly to the 26% decrease in activity and 6% crew wage rate increase in October 2006 offset by a 3% increase in the average operating hourly rate. Depreciation expense for the year decreased $1 million due to lower activity offset by a $4 million write down charge for 16 decommissioned rigs. Capital expenditures in 2007 were $12 million and included $3 million to construct two new service rigs and $9 million to upgrade pump trucks, transporters and mobile doghouses and build a new operating facility due for completion in late 2008. Live Well Service revenue for 2007 was $19 million as activity decreased by 36% over 2006 due to weak natural gas prices and an industry shift from rig-assist snubbing units to lower cost self-contained snubbing units. In 2007, Live Well converted three rig-assist to three self-contained picker style units and one self-contained rack and pinion unit. Precision Rentals revenue decreased to $44 million, which was $18 million or 29% lower than 2006. Each of Precision Rental’s three major product lines, surface equipment, tubulars and well control equipment, and wellsite accommodations, experienced year-over-year declines in revenue due to low utilization from excess industry equipment and lower pricing. Terra Water Systems generated revenue of $5 million in 2007 compared to $2 million in the period following the date of acquisition in 2006. Terra Water had 63 wastewater treatment units at the end of 2007, an increase of 12 units over 2006. 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 2006 Compared to 2005 The Completion and Production Services segment generated revenue of $441 million, an increase of $71 million or 19% over 2005 while operating earnings increased by $41 million or 34% to $163 million. Operating earnings increased to 37% of revenue in 2006 compared to 33% in 2005. The margin increase was mainly attributable to price increases established during the year. Operating expenses declined from 57% of revenue in 2005 to 53% in 2006, but on a per operating hour basis, increased due to higher crew labour costs and higher costs associated with repair and maintenance. During 2006, Precision acquired Terra Water Group Ltd., a wastewater treatment business. Terra Water had 41 treatment units at the time of the acquisition and closed the year with 51. The service provided by Terra Water complements those provided by LRG Catering and Precision Rentals and strengthened the diversity of Precision’s services. Excluding the business acquisition, capital spending in 2006 was $39 million, an increase of 11% over 2005. The total included expansion capital of $13 million for pump trucks, slant service rigs, self-contained snubbing units, wellsite accommodations, storage tanks and wastewater treatment units and upgrade capital of $26 million for replacement pump and transporter trucks, snubbing unit trucks, drill pipe for rental and tanks. The Precision Well Servicing division increased revenue by $56 million or 20% over 2005 to $342 million primarily due to higher hourly rig rates. Operating earnings improved by $36 million or 41% over 2005. Costs per operating hour were higher year-over-year due to increased crew and rig manager labour expenses and equipment repair and maintenance costs. Capital expenditures in 2006 were a continuation of long-term plans to upgrade and standardize equipment. Live Well Service’s activity decreased by 14% over 2005 with revenues for the year of $35 million due to the weakening of natural gas prices in 2006 which led to a cost savings shift by customers away from rig-assist units toward self- contained snubbing services. Precision Rentals generated revenues of $62 million, which was $11 million or 21% higher than in 2005. Each of Precision Rental’s product categories experienced year-over-year revenue increases. Total capital expenditures for 2006 increased 26% from 2005 and included 79 tanks and 10 new wellsite trailers. Terra Water Systems generated revenues of $2 million for the period subsequent to acquisition in August 2006. OTHER ITEMS 2007 Compared to 2006 Corporate and Other Expenses Corporate and other expenses decreased by $12 million or 30% from 2006 to $29 million. This reduction was primarily due to a $4 million recovery of long-term incentive plan accruals in 2007 compared to a $10 million expense in 2006. A portion of the award payable under the long-term incentive plan is dependent on the growth in certain defined financial targets over a three year period. The amounts distributed in 2007 were below the target, resulting in a partial recovery of amounts previously accrued. Additional reductions achieved from lower accruals for recurring near-term incentive plans were offset by one time costs associated with hiring a new Chief Executive Officer and costs associated with workforce restructuring in November 2007. Gains associated with 2006 disposals and increased foreign exchange losses from a weakening U.S. dollar offset by lower support costs in 2007 made up the remaining decrease. Interest Expense Net interest expense of $7 million declined by $1 million or 9% in 2007 compared to 2006. This reduction was primarily attributable to the lower average debt outstanding during 2007 compared to the prior year. P R E C I S I O N D R I L L I N G T R U S T 25 Income Taxes The Trust’s effective income tax rate, before enacted tax rate reductions, on earnings from continuing operations before income taxes was 8% in 2007 compared to 6% in 2006. 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. 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. 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, comparable to the $21 million recorded in 2006. 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. Additional consideration on 2004 and 2005 business divestitures resulted in a $7 million gain in 2006. 2006 Compared to 2005 Corporate and Other Expenses Corporate and other expenses decreased by $19 million or 32% in 2006 as compared to 2005. Included in the 2005 expenses were $18 million in costs related to the conversion to an income trust. Excluding these conversion costs, corporate and other expenses decreased $1 million or 4% year-over-year. Incentive plans introduced in 2006 added $7 million in costs over the prior period stock option plan expense. Disposals of corporate property, plant and equipment in 2005 and 2006 contributed to a $2 million reduction in depreciation expense. Significant reductions in Precision’s net foreign currency position related to 2005 divestitures and the repayment of U.S. dollar debentures led to a $3 million reduction in foreign exchange gains in 2006. The remaining $9 million reduction in costs was mostly attributable to the absence of severance and retention bonuses incurred in 2005, lower legal, advisory and support costs in 2006 and the recovery of certain liability provisions expensed in prior periods. Interest Expense Net interest expense of $8 million declined by $21 million or 73% in 2006 compared to 2005. This reduction was primarily attributable to the repayment of the outstanding bonds (debentures) in October 2005 which resulted in lower subsequent debt levels. Precision was in a significant surplus cash position, to the date of trust conversion, which generated $10 million in interest income. Premium on Redemption of Bonds and Loss on Disposal of Short-term Investments In 2005 outstanding bonds were repaid resulting in a charge of $72 million. In 2005 Precision received 26 million shares of Weatherford International Ltd. as part of the consideration for the disposal of the Energy Services and International Contract Drilling divisions. Substantially all of the shares were transferred to shareholders in conjunction with the November 7, 2005 plan of arrangement and a $71 million loss was incurred. Discontinued Operations A $7 million gain, net of tax, on discontinued operations was recorded in 2006 and related to the receipt of contingent consideration and working capital adjustments related to prior year business disposals. The 2005 business divestitures contributed $74 million in net earnings and $1.3 billion in gains on disposition towards the financial results in fiscal 2005. 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 Income Taxes The Trust’s effective income tax rate, before enacted tax rate reductions, on earnings from continuing operations before income taxes was 6% in 2006 compared to 25% in 2005. The comparatively low effective income tax rate was primarily a result of the conversion to an income trust which had the effect of shifting the income tax burden of the Trust to its unitholders. In the second quarter of 2006 the enactment of federal and certain provincial governments tax rate reductions resulted in a $21 million future tax recovery. LIQUIDITY AND CAPITAL RESOURCES The Trust’s liquidity and solvency position remained strong as working capital exceeded long-term debt by $21 million as at December 31, 2007 compared to $26 million as at December 31, 2006. The Trust’s financial position has been sustained despite a decrease in activity as a significant percentage of operating costs are variable in nature and the Trust curtailed spending and distributions in-line with financial performance. In 2007 the Trust generated cash from continuing operations of $484 million and received proceeds related to the disposal of operations discontinued in previous periods of $3 million. The cash was used to repay long-term debt of $21 million and bank indebtedness of $23 million, purchase property, plant and equipment net of disposal proceeds and related non-cash working capital of $194 million and make cash distributions to unitholders of $249 million. The Trust exited 2007 with a long-term debt to long-term debt plus equity ratio of 0.08 compared to 0.10 in 2006 and a ratio of long-term debt to cash provided by continuing operations of 0.25 compared to 0.23 in 2006. Precision has a number of credit facilities available to finance its activities. The committed facilities consist of a $700 million three-year revolving unsecured credit facility with a syndicate led by a Canadian chartered bank. The facility matures in November 2009 and is extendible annually with the consent of lenders. The facility has three financial covenants which are tested quarterly: total liabilities to equity of less than 1:1; total debt to the trailing four quarters’ cash flow of less than 2.75:1; and total distributions to unitholders of less than 100% of consolidated cash flow, as defined in the credit facility agreement. As at December 31, 2007 Precision was well within the financial covenant levels, and is expected to remain so for 2008. There was $120 million outstanding under the committed facilities at December 31, 2007. In addition to the committed facilities, Precision also has a number of uncommitted operating facilities which total approximately $65 million equivalent and are 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 Operating leases Long-term incentive plans (1) Total contractual obligations $ 119,826 22,640 21,147 $ 163,613 $ – 7,754 917 $ 8,671 $ 119,826 11,407 20,230 $ 151,463 $ – 3,479 – $ 3,479 $ $ – – – – (1) Includes amounts not yet accrued at December 31, 2007 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 three-year term. The compensation is comprised of two components, a retention award and a performance award. The retention awards are lump sum amounts determined at the date of commencement in the LTIP. The retention components are accrued evenly over their respective three-year terms. The performance components are accrued based on actual results compared to the targets. There is no assurance that the performance component will be paid. In addition, the Chief Executive Officer has a separate unit-based plan with anticipated payments of $0.9 million annually, based on the year end unit price of Precision, commencing September 2008 and ending September 2010. P R E C I S I O N D R I L L I N G T R U S T 27 Outstanding Unit Data Trust units Exchangeable LP units Total units outstanding February 29, 2008 December 31, 2007 December 31, 2006 December 31, 2005 125,588,717 169,207 125,587,919 170,005 125,536,329 221,595 124,352,921 1,108,382 125,757,924 125,757,924 125,757,924 125,461,303 Deferred Trust units outstanding 18,523 18,280 – – DISTRIBUTIONS Upon Precision’s conversion to an income trust effective November 7, 2005 the Trust adopted a policy of making monthly distributions to holders of Trust units and holders of exchangeable LP units (together “unitholders”). Precision has a legal entity structure whereby the trust entity, Precision Drilling Trust, effectively must flow its taxable income to unitholders pursuant to its Declaration of Trust. Distributions, including special distributions, may be declared in cash or “in-kind” or a combination of both and reduced, increased or suspended entirely depending on the operations of Precision, the performance of its assets, or legislative changes in tax laws. The actual cash flow available for distribution to unitholders is a function of numerous factors, including the Trust’s: financial performance; debt covenants and obligations; working capital requirements; upgrade and expansion capital expenditure requirements for the purchase of property, plant and equipment; and number of units outstanding. The Trust considers these factors on a monthly basis in determining future distributions. In 2007 cash distributions declared, including a special year-end cash distribution, were $246 million or $1.96 per diluted unit, a decrease of $201 million or $1.60 per diluted unit from the previous year. A special year-end “in-kind” distribution, as explained below, payable in Trust units (“units”), of $30 million or $0.24 per diluted unit (2006 – $25 million or $0.195 per diluted unit) was also declared. In the event that a distribution is declared in the form of “in-kind” units, the terms of the Declaration of Trust requires that the outstanding units be consolidated immediately subsequent to the distribution. Accordingly, the number of outstanding units would remain at the number outstanding immediately prior to the distribution. As a result, unitholders would not receive additional units and the declared amount of the “in-kind” distribution would be retained in Precision. Holders of exchangeable LP units receive economic equivalent treatment. Key factors for consideration in determining actual cash flow available for distribution, in an historical context, are disclosed within the consolidated statements of cash flow. In calculating distributable cash Precision makes the following adjustments to cash provided by continuing operations: K Deducts the purchase of property, plant and equipment for upgrade capital as the minimum capital reinvestment required to maintain current operating capacity; K Deducts the purchase of property, plant and equipment for expansion initiatives to grow capacity; K Adds the proceeds on the sale of property, plant and equipment which are incidental transactions occurring within the normal course of operations; and K Deducts long-term incentive plan changes as an unfunded liability resulting from the operating activities in the current period with payments beginning March 2009. 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 A two-year reconciliation of distributable cash from continuing operations follows: Years ended December 31, (Stated in thousands of Canadian dollars, except per diluted unit amounts) Cash provided by continuing operations Deduct: Purchase of property, plant and equipment for upgrade capital Purchase of property plant and equipment for expansion initiatives Add: Proceeds on the sale of property, plant and equipment Standardized distributable cash (1) Unfunded long-term incentive plan compensation Distributable cash from continuing operations (1) Cash distributions declared Per diluted unit information: Cash distributions declared Standardized distributable cash (1) Distributable cash from continuing operations (1) (1) Non-GAAP measure. See page 38. 2007 2006 $ 484,115 $ 609,744 (45,970) (141,003) 5,767 302,909 8,496 311,405 246,485 1.96 2.41 2.48 $ $ $ $ $ (92,123) (170,907) 29,337 376,051 (22,699) 353,352 447,001 3.56 3.00 2.81 $ $ $ $ $ Upgrade capital expenditures allow the Trust to maintain its existing service levels. These expenditures consist of betterments and replacements to existing assets and capitalized costs relating to the underlying support infrastructure. The upgrade capital expenditure strategy of Precision also involves costs that are charged directly to the income statement. These costs are related to the scheduled maintenance and certification processes within the various operating divisions. The level of these expenditures is driven by activity levels and can be scaled back in times of low activity without jeopardizing the long-term productive capacity of Precision and its underlying assets. Years ended December 31, (Stated in thousands of Canadian dollars) Cash provided by continuing operations (A) Net earnings (B) Distributions declared (C) Excess of cash provided by operations over distributions declared (A-C) Excess of net earnings over distributions declared (B-C) 2007 2006 $ $ $ $ $ 484,115 345,776 276,667 207,448 69,109 $ $ $ $ $ 609,744 579,589 471,524 138,220 108,065 The Trust maintains a strong balance sheet and has sufficient debt facilities to manage short-term funding needs as well as planned equipment additions. Part of the debt management strategy involves retaining sufficient funds from available distributable cash to 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. (Stated in thousands of Canadian dollars except per unit amounts) 2007 2006 2005 Units outstanding Year-end unit price Units at market Long-term debt Less: Working capital Enterprise value 125,757,924 15.09 $ $ 1,897,687 119,826 (140,374) 125,757,924 27.00 $ $ 3,395,464 140,880 (166,484) 125,461,303 38.38 $ $ 4,815,205 96,838 (152,754) $ 1,877,139 $ 3,369,860 $ 4,759,289 Precision carried a long-term debt to enterprise value ratio of 0.06 at December 31, 2007. This represents a slight increase over the 2006 ratio of 0.04. P R E C I S I O N D R I L L I N G T R U S T 29 QUARTERLY FINANCIAL SUMMARY (Stated in thousands of Canadian dollars, except per diluted unit amounts) Year ended December 31, 2007 Q1 Q2 Q3 Q4 Year Revenue Operating earnings (1) Earnings from continuing operations Per diluted unit Net earnings Per diluted unit Cash provided by continuing operations Distributions to unitholders – declared $ 410,542 178,179 158,067 1.26 158,067 1.26 156,298 71,682 $ $ 122,005 27,074 25,722 0.20 25,722 0.20 229,073 56,591 $ $ 227,928 73,402 69,702 0.55 72,658 0.58 20,270 49,046 $ $ 248,726 77,696 89,329 0.71 89,329 0.71 78,474 99,348 $ $ 1,009,201 356,351 342,820 2.73 345,776 2.75 484,115 $ 276,667 Year ended December 31, 2006 Q1 Q2 Q3 Q4 Year Revenue Operating earnings (1) Earnings from continuing operations Per diluted unit Net earnings Per diluted unit Cash provided by continuing operations Distributions to unitholders – declared (1) Non-GAAP measure. See page 38. $ 536,408 245,909 224,183 1.79 224,183 1.79 40,940 $ 101,623 $ 223,569 74,543 88,303 0.70 88,303 0.70 339,619 $ 111,681 $ 349,558 142,431 133,552 1.06 139,667 1.11 74,952 $ 116,785 $ 328,049 132,396 126,474 1.01 127,436 1.01 154,233 $ 141,435 $ 1,437,584 595,279 572,512 4.56 579,589 4.62 609,744 $ 471,524 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 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. FOURTH QUARTER DISCUSSION Throughout 2007 Precision has experienced lower equipment utilization resulting in lower quarterly revenues from the prior year comparative quarter. The decline in natural gas well spending by producers has curtailed oilfield service activity at a time when record rig capacity exists in the WCSB. The result for the service sector in Canada was low equipment utilization and increasingly competitive pricing throughout the year. Overall the business environment for oilfield services in western Canada for 2007 was challenging as market conditions and fundamentals were depressed. Precision’s expanding market presence in the United States land drilling market helped to mitigate the lower activity and earnings in Canada. Revenue of $249 million and operating earnings of $78 million in the fourth quarter of 2007 represented decreases of 24% and 41% respectively compared to the same period in 2006. Operating earnings have declined by more than revenue due to a reduction in industry utilization rates and a more competitive customer pricing environment. Net earnings in the fourth quarter of 2007 were $89 million compared with $127 million in 2006, a decrease of $0.30 per diluted unit. Fourth quarter 2007 net earnings benefited from a future income tax recovery of $20 million associated with enacted Canadian federal income tax rate reductions and was lowered by an asset write down charge of $7 million for decommissioned rigs and $5 million expense for salaried personnel reductions. Adjusted for the $12 million increase in net earnings from these items, the current quarter represented a decrease of $0.40 per diluted unit or 39% over the prior year. 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 Contract Drilling Services segment revenue of $175 million and operating earnings of $69 million decreased by 22% and 33% respectively in the fourth quarter of 2007 compared to the same period in 2006. Average customer pricing was 12% lower in 2007 compared to the fourth quarter of 2006. Drilling rig operating days, spud to rig release, for Precision in Canada in the fourth quarter of 2007 were 7,612, a decrease of 20% compared with 9,568 in the same quarter in 2006. Utilization declined to 34% in the fourth quarter of 2007 compared with 43% a year ago. Lower activity and lower average day rates were partially offset by lower daily costs as Precision continued to tightly monitor spending. United States land drilling operations contributed 12% of the segment’s current quarter revenue while LRG Catering followed Canadian industry trends and experienced a decline in revenue of 35% over the prior year. Completion and Production Services segment revenue of $78 million and operating earnings of $17 million decreased by 28% and 57% respectively in the fourth quarter of 2007 compared to the same period in 2006. Precision’s service rig operating hours during the fourth quarter of 2007 were 86,416 compared to 109,737 in 2006, a decrease of 21%. The reduction was a result of lower demand as customers scaled back well completion work in-line with drilling activity and moderated spending on production maintenance of existing wells, particularly natural gas wells. New well completions accounted for 33% of service rig operating hours in the fourth quarter compared to 39% in 2006. Lower customer demand and the resulting competitive bidding environment led to a price reduction of 10% compared to the prior year. Demand for rental equipment followed industry trends as revenue in the quarter was 25% lower than the fourth quarter of 2006 while revenue for the snubbing division was down 27% and the wastewater treatment division was lower by 1%. Total operating costs increased from 47% of revenue in the fourth quarter of 2006 to 51% in 2007 due to lower customer pricing and fixed overhead costs. Operating costs remained highly variable to activity levels and, in the quarter, service rig costs per hour were unchanged while drilling rig costs per day were lower by 7%. General and administrative expense for the fourth quarter was $19 million, a decrease of $4 million from the same period in 2006. The decrease was due primarily to lower employee incentive compensation costs offset by charges associated with workforce reductions in early November 2007. Depreciation and amortization expense in the fourth quarter of 2007 was $25 million, which included a charge of $7 million for decommissioned assets, compared with $18 million in the same period of 2006. Although Canadian rig utilization in the quarter was lower by about 20% compared to 2006 the utilization impact was offset by a higher cost base for active rigs. The Trust’s effective income tax rate on earnings before income taxes for fiscal 2007 was 8%, before enacted tax rate reductions, compared to 6% for 2006. Compared to a corporate income tax rate, the low effective income tax rate is primarily the result of the income trust structure shifting all or a portion of the income tax burden of the Trust to its unitholders. During the fourth quarter of 2007 the Government of Canada enacted legislation reducing federal income tax rates to 15% by 2012. The enacted tax rate reductions resulted in a $20 million future income tax recovery in the fourth quarter of 2007. In the fourth quarter of 2007 capital expenditures were $38 million, a decrease of $35 million over the same period in 2006. Capital spending for the quarter included $9 million in upgrade and $29 million in expansion initiatives. Fourth quarter monthly cash distributions declared were $0.13 per diluted unit for aggregate quarterly cash distributions declared of $49 million or $0.39 per unit. In addition the Trust declared a special year-end distribution of $50 million or $0.40 per unit settled $0.24 per unit “in-kind” and $0.16 per unit in cash. The special “in-kind” distribution was made to minimize debt levels and retain balance sheet strength to fund planned asset growth. P R E C I S I O N D R I L L I N G T R U S T 31 MD&A 5 CRITICAL ACCOUNTING ESTIMATES, NEW ACCOUNTING STANDARDS AND BUSINESS RISKS 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 U.S. GAAP and these differences are described and quantified in Note 16 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 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 2007, Precision completed its assessment and concluded that there was no impairment of the carrying value. 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 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. Long-term Incentive Plan Compensation The Trust instituted an annual long-term incentive plan which compensates officers and key employees through cash payments at the end of a three-year term. The compensation includes two components, a retention award and a performance award. The performance component is based on growth over the three-year term measured against targets as determined by the Compensation Committee of Precision. As a result of actual results in the subsequent years, the accrued amount for the performance component may be reduced or increased. NEW ACCOUNTING STANDARDS The Canadian Institute of Chartered Accountants issued certain new accounting standards which will be in effect for fiscal years beginning on or after January 1, 2008 for recognition and measurement of inventories and disclosure of information regarding capital management. K Section 3031, “Inventories”, provides guidance on measurement and disclosure of inventories. This section also provides guidance on the determination of cost and recognition in the financial statements. K Section 1535, “Capital Disclosures”, establishes standards for disclosing quantitative and qualitative information regarding objectives, policies and processes for managing capital. The Trust does not expect that the adoption of these standards will have a material impact on the 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 33 In January 2006 the Canadian Accounting Standards Board (“AcSB”) announced its decision to replace Canadian GAAP with International Financial Reporting Standards (“IFRS”) for all Canadian Publicly Accountable Enterprises (“PAE”). PAE include listed companies and any other organizations that are responsible to large or diverse groups of stakeholders, including non-listed financial institutions, securities dealers and many cooperative enterprises. The goal of IFRS is to improve financial reporting internationally by establishing a single set of high quality, consistent, and comparable reporting standards. To allow affected companies sufficient time to prepare for the transition, the AcSB announced a five-year transition period, with a changeover date of January 1, 2011, effective for fiscal years beginning on or after that date. Although many elements of Canadian GAAP and IFRS are similar, Precision expects its transition to IFRS to take considerable effort. Precision has commenced its assessment of and planning for the impacts of IFRS on its financial reporting processes. BUSINESS RISKS The discussion of risk that follows is not a complete representation. Additional information related to risks are disclosed in the 2007 Annual Information Form with SEDAR and available at www.sedar.com. Refer to the “Cautionary Statement Regarding Forward-Looking Information and Statements” on page 39. Certain activities of Precision are affected by factors that are beyond its control or influence. The drilling rig, camp and catering, service rig, snubbing, wastewater treatment, rentals, and related service businesses and activities of Precision in Canada and the drilling rig, camp and catering and rentals businesses and activities of Precision in the United States are directly affected by fluctuations in the levels of 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 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. The majority of Precision’s operating costs are variable in nature which minimizes the impact of downturns on its operational results. Crude Oil and Natural Gas Prices Precision’s revenue, cash flow and earnings are substantially dependent upon, and affected by, the level of activity associated with oil and natural gas exploration and production. Both short-term and long-term trends in oil and natural gas prices affect the level of such activity. Oil and natural gas prices and, therefore, the level of drilling, exploration and production activity have been volatile over the past few years and likely will continue to be volatile. Military, political, weather, economic and other events in certain parts of the world, including initiatives by the Organization of Petroleum Exporting Countries or other major petroleum exporting countries, may affect both the demand for, and the supply of, oil and natural gas. North American petroleum service activity is largely focused on natural gas. Weather conditions, governmental regulation (both in Canada and elsewhere), levels of consumer demand, the availability of pipeline capacity, storage levels and other factors beyond Precision’s control may also affect the supply of and demand for oil and natural gas and thus lead to future price volatility. Precision believes that any prolonged reduction in oil and natural gas prices would depress the level of exploration and production activity. Lower oil and natural gas prices could also cause Precision’s customers to seek to terminate, renegotiate or fail to honour drilling contracts with Precision which could affect the fair market value of its rig fleet which in turn could trigger a write down for accounting purposes, Precision’s ability to retain skilled rig personnel, and Precision’s ability to obtain access to capital to finance and grow its businesses. There can be no assurance that the future level of demand for Precision’s services or future conditions in the oil and natural gas industry will not decline. 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 Workforce Availability Precision’s ability to provide reliable services is dependent upon the availability of well-trained, experienced crews to operate its field equipment. Precision must also balance the requirement to maintain a skilled workforce with the need to establish cost structures that fluctuate with activity levels. Within Precision, the most experienced people are retained during periods of low utilization by having them fill lower level positions on field crews. Precision has established training programs for employees new to the oilfield service sector and works closely with industry associations to ensure competitive compensation levels and to attract new workers to the industry as required. Many of Precision’s businesses regularly experience manpower shortages in peak operating periods. Business is Seasonal In Canada, 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 provincial 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 road bans. The timing and length of road bans is dependant 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 sections of the WCSB 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. Precision’s business results depend, at least in part, upon the severity and duration of the Canadian winter. 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 which are more advantageous, timely or cost effective than improvements developed by Precision. 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 maintenance projects. Competitive Industry The oilfield services industry in which Precision operates is, and will continue to be, very competitive. There is no assurance that Precision will be able to continue to compete successfully or that the level of competition and pressure on pricing will not affect its margins. Capital Overbuild in the Drilling Industry As at December 31, 2007 there were about 900 industry drilling rigs in Canada and about 2,160 marketed drilling rigs in the United States. There is no assurance that the level of demand for drilling rigs in the future will be able to support the size of the current industry drilling rig fleet in Canada and the United States. Any decline in demand for drilling services within the services industry, directly or indirectly related to the current drilling rigs available, could also lead to a decline in the demand for Precision’s services, resulting in a material adverse effect on Precision’s revenues, cash flows, earnings and cash distributions to unitholders. P R E C I S I O N D R I L L I N G T R U S T 35 Tax Consequences of Previous Transactions Completed by Precision The business and operations of Precision prior to completion of the Plan of Arrangement were 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 those 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 and in accordance with GAAP 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, before interest and penalties, could be up to $300 million. Any increase in Precision’s tax liability would reduce the funds available for distributions. Subsequent to year end Precision received, from a provincial taxing authority, Notices of Reassessment relating to a prior period tax filing position for $55 million. The income tax related portion of the reassessments is $36 million and is included in the $300 million tax contingency disclosed in Note 20 to the financial statements. Precision is of the opinion that the provincial tax authority’s position is without merit and will be challenging these reassessments. Credit Risk Precision’s accounts receivable are with customers involved in the oil and natural gas industry, whose revenues may be impacted by fluctuations in commodity prices. Although collection of these receivables could be influenced by economic factors affecting this industry, management considers the risk of a significant loss due to uncollectible receivables to be remote at this time. Capital Expenditures The timing and amount of capital expenditures by Precision will directly affect the amount of cash available for distribution to unitholders. The cost of equipment has escalated over the past several years as a result of, among other things, high input costs. There is no assurance that Precision will be able to recover higher capital costs through rate increases to its customers, in which case cash distributions may be reduced. 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 or 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 to Precision. Precision’s inability to raise financing to support ongoing operations or to fund capital expenditures or acquisitions or other business combination transactions could limit Precision’s growth and may have a material adverse effect upon Precision. Taxation of Distributions 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 investment flow-through (“SIFT”) trusts at a rate equal to the applicable federal corporate tax rate plus a provincial SIFT tax factor. After the enactment of federal tax rate reductions in December 2007 the combined SIFT tax would be 29.5% in 2011, reducing to 28% in 2012. 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. 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 the resulting lower demand for Precision’s services. 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 U.S. Dollar Exchange Exposure Precision’s operations in the United States have revenue, expenses, assets and liabilities denominated in U.S. 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 U.S. currencies in three main aspects. K Translation of U.S. Currency Assets and Liabilities to Canadian Dollars For Precision’s integrated operations, non-monetary assets and liabilities are recorded in the financial statements at the exchange rate in effect at the time of the acquisition or expenditure. As a result the book value of these assets and liabilities are not impacted by changes in exchange rates. Monetary assets and liabilities are converted at the exchange rate in effect at the balance sheet dates, and the unrealized gains and losses are shown on the statements of earnings as “Foreign exchange”. Precision has a net monetary asset position for its U.S. operations, which are U.S. dollar based. As a result, if the Canadian dollar strengthens versus the U.S. dollar, Precision will incur a foreign exchange loss from translation of net monetary assets; K Translation of U.S. Currency Statement of Earnings Items to Canadian Dollars Precision’s United States operations generate revenue and incur expenses in U.S. dollars and the U.S. dollar based earnings are converted into Canadian dollars for purposes of financial statement consolidation and reporting. The conversion of the U.S. 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 against the U.S. 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 based earnings into Canadian dollars; and K Transaction Exposure The majority of Precision’s United States operations are transacted in U.S. dollars. Transactions for Precision’s Canadian operations are primarily transacted in Canadian dollars. However, Precision occasionally purchases goods and supplies in U.S. dollars. These transactions and foreign exchange exposure would not typically have a material impact on the Canadian operation’s financial results. 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. The safety policies and procedures adopted by Precision meet or exceed those imposed by industry, customers or legislation. Precision maintains a safety program which reinforces workplace safety through training, observation and communication. 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. Precision’s safety record in North America, backed by the experience of its employees and the quality of its equipment, differentiates Precision from its oilfield service competitors. 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, profitability and funds available for cash distributions. 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 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, results of operations, prospects and funds available for cash distributions. P R E C I S I O N D R I L L I N G T R U S T 37 MD&A 6 DISCLOSURE CONTROLS AND PROCEDURES EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES 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 principal executive officer and principal financial and accounting officer, to allow timely decisions regarding required disclosure. As of December 31, 2007, an evaluation was carried out, under the supervision of and with the participation of management, including the principal executive officer and principal financial and accounting 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 principal executive officer and principal financial and accounting officer concluded that the design and operation of Precision’s disclosure controls and procedures were effective as at December 31, 2007. During the fourth quarter of 2007, 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. NON-GAAP MEASURES 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. 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 or how the results are taxed. Standardized Distributable Cash, Distributable Cash from Continuing Operations, Standardized Distributable Cash per Diluted Unit and Distributable Cash from Continuing Operations per Diluted Unit Management believes that in addition to cash provided by continuing operations, standardized distributable cash and distributable cash from continuing operations are useful supplemental measures. They provide an indication of the funds available for distribution to unitholders after consideration of the impacts of capital expenditures and long-term unfunded contractual obligations. In prior years, instead of deducting total capital expenditures in the calculation of distributable cash, Precision only excluded upgrade capital but as a result of new guidance expansion capital is now also deducted. Precision’s method of calculating these measures may differ from other entities and, accordingly, may not be comparable to measures used by other entities. Investors should be cautioned that these measures should not be construed as an alternative to measures determined in accordance with GAAP as an indicator of Precision’s performance. 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 MD&A 7 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS 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 “Overview and Outlook”, “Dynamics of the Oilfield Services Industry”, “Precision’s Development”, “Financial Results”, “Critical Accounting Estimates, New Accounting Standards and Business Risks” and “Disclosure Controls and Procedures” and include, but are not limited to statements with respect to: 2008 expected cash provided by continuing operations; 2008 capital expenditures, including the amount and nature thereof; 2008 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; world population and energy consumption trends; our business strategy, including the 2008 strategy 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, including transitions in executive roles; labour shortages; climatic conditions; the maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies and tax liabilities; 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. P R E C I S I O N D R I L L I N G T R U S T 39 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; industry conditions, including 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 ability of oil and natural gas companies to access external sources of debt and equity capital; the effect of weather conditions on operations and facilities; 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; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; 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; 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. 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 Reporting Precision Drilling Trust FINANCIAL REPORTING MANAGEMENT’S REPORT TO THE UNITHOLDERS 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 the 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, 2007 to December 31, 2006 and the years ended December 31, 2006 to December 31, 2005. Note 16 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. 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. P R E C I S I O N D R I L L I N G T R U S T 41 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, 2007. Also management determined that there were no material weaknesses in the Trust’s internal control over financial reporting as of December 31, 2007. 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 assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2007 as stated in their report included herein and expressed an unqualified opinion on the effectiveness of internal control over financial reporting as of December 31, 2007. The Audit Committee of the Board of Directors, which is comprised of three 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 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 Chief Executive Officer Precision Drilling Corporation, Administrator to Precision Drilling Trust Doug J. Strong Chief Financial Officer Precision Drilling Corporation, Administrator to Precision Drilling Trust March 20, 2008 March 20, 2008 42 C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Precision Drilling Trust AUDITORS’ REPORT TO THE UNITHOLDERS To the Unitholders of Precision Drilling Trust We have audited the consolidated balance sheets of Precision Drilling Trust (“the Trust”) as at December 31, 2007 and 2006 and the consolidated statements of earnings and retained earnings (deficit) and cash flow for each of the years in the three-year period ended December 31, 2007. 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. With respect to the consolidated financial statements for the years ended December 31, 2007 and 2006, we also conducted our audits in accordance with 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, 2007 and 2006 and the results of its operations and its cash flow for each of the years in the three-year period ended December 31, 2007 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, 2007, 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 20, 2008 expressed an unqualified opinion on the effectiveness of the Trust’s internal control over financial reporting. Chartered Accountants Calgary, Canada March 20, 2008 P R E C I S I O N D R I L L I N G T R U S T 43 Precision Drilling Trust REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Precision Drilling Corporation, as Administrator to Precision Drilling Trust and the Unitholders of Precision Drilling Trust We have audited Precision Drilling Trust (“the Trust”)’s internal control over financial reporting as of December 31, 2007, 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 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, 2007, 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 conducted our audits on the consolidated financial statements in accordance with Canadian generally accepted auditing standards. With respect to the years ended December 31, 2007 and 2006, we also have conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our report dated March 20, 2008 expressed an unqualified opinion on those consolidated financial statements. Chartered Accountants Calgary, Canada March 20, 2008 44 C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Precision Drilling Trust CONSOLIDATED BALANCE SHEETS As at December 31, (Stated in thousands of Canadian dollars) ASSETS Current assets: Accounts receivable Income taxes recoverable Inventory Property, plant and equipment, net of accumulated depreciation Intangibles, net of accumulated amortization of $593 (2006 – $503) Goodwill LIABILITIES AND UNITHOLDERS’ EQUITY Current liabilities: Bank indebtedness Accounts payable and accrued liabilities Distributions payable Long-term incentive plan payable Long-term debt Future income taxes 2007 2006 (Note 19) $ (Note 4) 256,616 5,952 9,255 271,823 1,210,587 318 280,749 $ 354,671 8,701 9,073 372,445 1,107,617 375 280,749 $ 1,763,477 $ 1,761,186 $ (Note 5) (Note 19) (Note 6) (Note 7) (Note 8) 14,115 80,864 36,470 131,449 13,896 119,826 181,633 446,804 $ 36,774 130,202 38,985 205,961 22,699 140,880 174,571 544,111 Commitments and contingencies (Notes 12 and 20) Unitholders’ equity: Unitholders’ capital Contributed surplus Deficit See accompanying notes to consolidated financial statements. Approved by the Board of Trustees: (Note 9(b)) (Note 9(c)) 1,442,476 307 (126,110) 1,316,673 1,412,294 – (195,219) 1,217,075 $ 1,763,477 $ 1,761,186 Robert J.S. Gibson Trustee Patrick M. Murray Trustee P R E C I S I O N D R I L L I N G T R U S T 45 Precision Drilling Trust CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS (DEFICIT) Years ended December 31, (Stated in thousands of Canadian dollars, except per unit amounts) 2007 2006 2005 Revenue Expenses: Operating General and administrative Depreciation and amortization Foreign exchange Reorganization costs Operating earnings Interest: Long-term debt Other Income Premium on redemption of bonds Loss on disposal of short-term investments Other Earnings from continuing operations before income taxes Income taxes: Current Future (Note 4) (Note 23) (Note 7) (Note 24) (Note 8) Earnings from continuing operations Gain on disposal of discontinued operations, net of tax Discontinued operations, net of tax (Note 24) (Note 24) Net earnings Retained earnings (deficit), beginning of year Adjustment on cash purchase of employee stock options, net of tax of $22,060 Reclassification from contributed surplus on cash buy-out of employee stock options Distribution of disposal proceeds Repurchase of common shares of dissenting shareholders Distributions declared Deficit, end of year (Note 23(c)) (Note 23(c)) (Note 24) (Note 23(a)) (Note 6) Earnings per unit from continuing operations: (Note 13) $ 1,009,201 $ 1,437,584 $ 1,269,179 516,094 56,032 78,326 2,398 – 652,850 356,351 7,767 106 (555) – – – 688,207 81,217 73,234 (353) – 842,305 595,279 8,800 171 (942) – – (408) 641,805 76,397 71,561 (3,474) 17,512 803,801 465,378 38,735 558 (10,023) 71,885 70,992 – 349,033 587,658 293,231 (737) 6,950 6,213 342,820 2,956 – 345,776 (195,219) – – – 34,526 (19,380) 15,146 572,512 7,077 – 579,589 (303,284) – – – 241,402 (169,019) 72,383 220,848 1,335,382 74,333 1,630,563 1,041,683 (42,087) 23,215 (2,851,784) – (276,667) – (471,524) (34,364) (70,510) $ (126,110) $ (195,219) $ (303,284) Basic Diluted Earnings per unit: Basic Diluted (Note 13) $ $ $ $ 2.73 2.73 2.75 2.75 $ $ $ $ 4.56 4.56 4.62 4.62 $ $ $ $ 1.79 1.76 13.22 13.00 See accompanying notes to consolidated financial statements. 46 C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Precision Drilling Trust CONSOLIDATED STATEMENTS OF CASH FLOW Years ended December 31, (Stated in thousands of Canadian dollars) Cash provided by (used in): Continuing operations: Earnings from continuing operations Adjustments and other items not involving cash: Long-term incentive plan compensation Depreciation and amortization Future income taxes Stock-based compensation Write-off of deferred financing costs Loss in market value of short-term investments Amortization of deferred financing costs Unrealized foreign exchange gain on long-term monetary items Other Changes in non-cash working capital balances (Note 19) Discontinued operations: (Note 24) Funds provided by discontinued operations Changes in non-cash working capital balances of discontinued operations 2007 2006 2005 $ 342,820 $ 572,512 $ 220,848 (8,496) 78,326 6,950 – – – – – 112 64,403 22,699 73,234 (19,380) – – – – – (408) (38,913) 484,115 609,744 – – – – – – – 71,561 (169,019) 11,229 7,664 70,992 1,453 (4,740) – (3,975) 206,013 183,330 (86,310) 97,020 (Notes 15 and 24) (Note 24) – (186,973) 5,767 2,956 – (16,428) (263,030) 29,337 7,337 510 (30,421) (155,231) 15,174 1,306,799 14,569 Investments: Business acquisitions, net of cash acquired Purchase of property, plant and equipment Proceeds on sale of property, plant and equipment Proceeds on disposal of discontinued operations Proceeds on disposal of investments Purchase of property, plant and equipment of discontinued operations Proceeds on sale of property, plant and equipment of discontinued operations Purchase of intangibles Changes in non-cash working capital balances Financing: Distributions paid Repayment of long-term debt Increase in long-term debt Issuance of Trust units Issuance of Trust units on exercise of options Issuance of Trust units on purchase of options Distribution of disposal proceeds Cash buy-out of employee stock options Repurchase of common shares of dissenting shareholders Issuance of common shares on exercise of options Changes in non-cash working capital balances Change in bank indebtedness (Note 19) (Note 6) (Note 24) – – (128,214) – (33) (13,119) – – 7,551 17,785 (20) (2,912) (191,402) (234,723) 1,037,529 (249,000) (99,700) 78,646 – – – – – – – – (22,659) (292,713) (444,651) (204,910) 248,338 9,896 – – – – – – – 16,306 (375,021) – – – (33,875) (703,970) 96,826 – 8,263 5,504 (844,334) (64,147) (43,299) 73,930 22,060 20,468 (1,462,574) (122,012) 122,012 $ – P R E C I S I O N D R I L L I N G T R U S T 47 Decrease in cash and cash equivalents Cash and cash equivalents, beginning of year Cash and cash equivalents, end of year $ – – – $ See accompanying notes to consolidated financial statements. Precision Drilling Trust NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts are stated in thousands of Canadian dollars except unit/share numbers and per unit/share amounts) NOTE 1. DESCRIPTION OF BUSINESS Precision Drilling Trust (the “Trust”) is a provider of contract drilling and completion and production services 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. On September 29, 2005 the Trust, Precision Drilling Limited Partnership (“PDLP”), 1194312 Alberta Ltd., 1195309 Alberta ULC., and Precision Drilling Corporation (“Precision”) entered into an Arrangement Agreement (“Plan of Arrangement” or the “Plan”) to convert Precision to an income trust. As part of the Plan of Arrangement, on November 7, 2005 Precision Drilling Corporation and certain of its subsidiaries amalgamated, and continued as one corporation (“PDC”). After giving effect to the Plan, and related transactions, all of the shares of PDC are owned by PDLP and indirectly by the Trust. Prior to the Plan of Arrangement effective date of November 7, 2005 the consolidated financial statements included the accounts of Precision, its subsidiaries and its partnerships, substantially all of which were wholly-owned. The conversion to a trust has been accounted for on a continuity of interest basis and accordingly, the consolidated financial statements reflect the financial position, results of operations and cash flows as if the Trust had always carried on the business formerly carried on by Precision. Pursuant to the Plan of Arrangement, shareholders ultimately received either Trust units or a combination of Trust units and exchangeable LP units of PDLP for each previously held common share of Precision (other than dissenting shareholders, who received cash equal to the fair value of their shares). After giving effect to the Plan, the consolidated financial statements include the accounts of the Trust and its subsidiaries. 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 16. 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, accrual for long-term incentive plan, and income taxes. Actual results could differ from these and other estimates, the impact of which would be recorded in future periods. (b) Principles of consolidation The consolidated financial statements include the accounts of the Trust and its subsidiaries 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 replacement cost. Inventory is charged to operating expenses as items are sold or consumed at the amount of the average cost of the item. 48 C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S (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. 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 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 (f) Intangibles Intangibles, which are comprised primarily of patents, are recorded at cost and amortized by the straight-line method over their useful lives of 10 years. Amortization over the next five years is anticipated to be $93,000 per year for years one through three, $13,000 for year four and $5,000 for year five. (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. For 2007 income earned directly by 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. 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 investment flow-through (“SIFT”) trusts at a rate equal to the applicable federal corporate tax rate P R E C I S I O N D R I L L I N G T R U S T 49 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. (k) Employee benefit plans At December 31, 2007, approximately 42% (2006 – 37%) 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 In 2006 the Trust instituted an annual long-term incentive plan (the “LTIP”) which compensates officers and 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 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 performance components are based on the growth targets as determined by the Compensation Committee of Precision and is accrued over the three-year term of the plans. (m) 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 the year- end current exchange rate 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. 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. (n) 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 distributions to unitholders declared prior to redemption by issuing additional trust units based on the closing market price of Precision’s Trust units on the Toronto Stock Exchange on the immediately prior trading day. 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. A cash settled deferred trust unit plan has been established whereby eligible participants of Precision’s Performance Savings Plan may 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 distribution to unitholders by issuing additional DTUs based on the weighted average trading price of 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 distribution to unitholders by issuing additional DTUs based on the weighted average trading price of 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 incentive plan payable. Gains or losses resulting from these adjustments are charged to earnings. 50 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S (o) Stock-based compensation plans The Trust had equity incentive plans in 2005 and prior periods, which are described in Note 23(c). The fair value of common share purchase options was calculated at the date of grant using the Black-Scholes option pricing model and that value was 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 was reclassified from contributed surplus to unitholders’ capital as appropriate. Consideration paid by employees upon exercise of equity purchase options was credited to unitholders’ capital as appropriate. (p) Exchangeable LP units Exchangeable LP units are presented as equity of the Trust as their features make them economically equivalent to Trust units. (q) 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 based on the treasury stock method, which 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. NOTE 3. CHANGES IN ACCOUNTING POLICIES (a) 2007 changes Effective January 1, 2007 the Trust adopted new accounting standards issued by The Canadian Institute of Chartered Accountants (“CICA”). The standards regarding the disclosure of comprehensive income (Sections 1530 and 3251) require a statement of comprehensive income, which is comprised of net earnings and other comprehensive income. The Trust does not have any amounts that would be included in comprehensive income, therefore, comprehensive income is equivalent to net earnings and no statement of comprehensive income is presented. The adoption of the standards relating to the recognition, measurement, disclosure and presentation of financial instruments (Sections 3855 and 3861), and hedge accounting (Section 3865) did not have a material impact on the consolidated financial statements. Upon adoption of Sections 3855 and 3861 the Trust has designated its financial instruments into the following classifications: • Cash and cash equivalents are classified as “held for trading” and any period change in fair value is recorded through net earnings; • 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; and • Accounts payable and accrued liabilities, bank indebtedness, distributions payable and long-term debt 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. In addition, the Trust early adopted new accounting standards related to the disclosure and presentation of financial instruments (Sections 3862 and 3863). These standards, which replace Section 3861, provide enhanced disclosure around the nature and extent of risks arising from financial instruments to which the entity is exposed and how the entity manages those risks. Adoption of these standards did not have a material impact on the consolidated financial statements. (b) Future accounting pronouncements Effective January 1, 2008 the Trust is required to adopt new Canadian accounting standards relating to inventories (Section 3031) and capital disclosures (Section 1535). Section 3031 will require inventories to be measured at the lower of cost or net realizable value and the reversal of previously recorded write downs to realizable value when the circumstances that caused the write down no longer exist. This new standard is not expected to have a material impact on the Trust’s financial statements. Section 1535 will require the Trust to provide additional quantitative and qualitative information regarding its objectives, policies and processes for managing its capital. P R E C I S I O N D R I L L I N G T R U S T 51 NOTE 4. PROPERTY, PLANT AND EQUIPMENT 2007 Rig equipment Rental equipment Other equipment Vehicles Buildings Assets under construction Land 2006 Rig equipment Rental equipment Other equipment Vehicles Buildings Assets under construction Land Cost Accumulated Depreciation $ 1,464,145 95,435 97,397 76,387 30,614 77,096 10,121 $ 485,822 45,917 69,483 27,892 11,494 – – $ Net Book Value 978,323 49,518 27,914 48,495 19,120 77,096 10,121 $ 1,851,195 $ 640,608 $ 1,210,587 Cost Accumulated Depreciation $ 1,294,289 94,184 95,137 78,675 29,583 76,239 10,110 $ 434,491 40,658 61,317 24,461 9,673 – – $ Net Book Value 859,798 53,526 33,820 54,214 19,910 76,239 10,110 $ 1,678,217 $ 570,600 $ 1,107,617 In 2007 the Trust incurred $6.7 million of additional depreciation expense 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 is allocated $2.4 million to the Contract Drilling segment and $4.3 million to the Completion and Production segment. NOTE 5. BANK INDEBTEDNESS At December 31, 2007 and 2006 the Trust had available $60.0 million and US$5.0 million under unsecured credit facilities, of which $14.1 million had been drawn (2006 – $36.8 million). Availability of these facilities were reduced by outstanding letters of credit in the amount of $2.0 million (2006 – $4.0 million). Advances under the facilities are available at the bank’s prime lending rate, U.S. base rate, U.S. Libor plus applicable margin or Banker’s Acceptance plus applicable margin, or in combination. As at December 31, 2007 and 2006 the amounts drawn under these facilities were at the bank’s prime lending rate of 6% . NOTE 6. DISTRIBUTIONS The beneficiaries of the Trust are the holders of Trust units and the partners of PDLP are the holders of exchangeable LP units exchangeable into units (together “unitholders”) of the Trust. The monthly distributions made by the Trust to unitholders are determined by the Trustees. PDLP earns interest income from a promissory note issued by its subsidiary PDC at a rate which is determined by the terms of the promissory note. PDLP in substance pays distributions to holders of exchangeable LP units in amounts equal to the distributions paid to the holders of Trust units. All distributions are 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 distribution reinvestment plan (the “DRIP”) was approved by the Board of Trustees in February 2006, and implemented in March 2006. The DRIP allows certain holders of Trust units, at their option, to reinvest monthly cash distributions to acquire additional Trust units at the average market price as defined in the DRIP. Unitholders who are not resident in Canada or hold exchangeable LP units are not eligible to participate in the DRIP. The Trust reserved the right to amend, suspend, or terminate the DRIP at any time. The DRIP was suspended in December 2006. 52 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S A summary of the distributions is as follows: Declared Paid Payable in cash at December 31 Payable in units at December 31 2007 2006 $ $ $ $ 276,667 249,000 36,470 30,182 $ $ $ $ 471,524 444,651 38,985 24,523 $ $ $ $ 2005 70,510 33,875 36,635 – Included in the 2007 distributions declared is a special non-cash distribution of $30.2 million ($0.24 per unit) (2006 – $24.5 million or $0.195 per unit). This special distribution was settled on January 15, 2008 through the issuance of units. Immediately following the issuance of these units, the Trust consolidated the units such that the number of Trust units remained unchanged from the number outstanding prior to the special distribution. The exchangeable LP units received equivalent economic treatment. NOTE 7. LONG-TERM DEBT Extendible revolving unsecured facility: At December 31, 2007 and 2006 PDC, a subsidiary of the Trust, has available a three-year revolving unsecured facility of $700.0 million (or U.S. equivalent) with a syndicate led by a Canadian chartered bank, which is guaranteed by the Trust. The facility matures on November 2, 2009 and is renewable annually at the option of the lenders. Advances are available to PDC under this facility either at the bank’s prime lending rate, U.S. base rate, U.S. Libor plus applicable margin or Bankers’ Acceptance plus applicable margin or in combination. The applicable margin is dependent on the Trust’s consolidated debt to cash flow ratio and the percentage of the total facility outstanding, which at December 31, 2007 and 2006 was 75 basis points. The facility requires that the Trust maintain a ratio of total liabilities to total equity of less than 1:1, a trailing 12 month ratio of consolidated debt to cash flow of less than 2.75:1 and total distributions to unitholders of less than 100% of consolidated cash flow as defined in the facility agreement. As at December 31, 2007, the Trust had drawn $119.8 million (2006 – $140.9 million) under this facility. Unsecured debentures and notes: During the fourth quarter of 2005 Precision repaid all of its outstanding debentures and notes pursuant to the early redemption provisions of the related agreements. The difference between the $766.7 million redemption price and the carrying value of the debentures was charged to income. NOTE 8. INCOME TAXES The provision for income taxes differs from that which would be expected by applying Canadian statutory income tax rates as follows: Earnings from continuing operations before income taxes Federal and provincial statutory rates Tax at statutory rates Adjusted for the effect of: Non-deductible expenses Non-deductible stock-based compensation Income to be distributed to unitholders, not subject to tax in the Trust Utilization of losses and surcharge credits Other Income tax expense before tax rate reductions Reduction of future income tax balances due to enacted tax rate reductions Income tax expense 2007 2006 2005 $ $ 349,033 33% 115,181 $ $ 587,658 33% 193,927 $ $ 293,231 34% 99,699 1,080 – (91,013) – 3,426 28,674 297 – (155,354) – (2,896) 35,974 2,795 3,216 (23,980) (10,550) 1,203 72,383 (22,461) (20,828) – $ 6,213 $ 15,146 $ 72,383 Effective income tax rate before enacted tax rate reductions 8% 6% 25% P R E C I S I O N D R I L L I N G T R U S T 53 In 2007 the federal government enacted various reductions to corporate income tax rates, that when fully implemented over the next five years will decrease the federal corporate income tax rate to 15% in 2012. These reductions were in addition to those introduced in 2006 that were to reduce the federal corporate income tax rates from 21% to 18.5% by 2011.The federal corporate capital tax was eliminated effective January 1, 2006 and the federal corporate surtax will be eliminated in 2008. In 2006 the Province of Alberta reduced the corporate income tax rate by 1.5% effective April 1, 2006. 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: 2007 2006 Future income tax liability: Property, plant and equipment and intangibles $ 209,772 $ 213,281 Future income tax assets: Bond redemption premium Losses Share issue costs Long-term incentive plan Accrued liabilities 9,185 9,128 817 5,743 3,266 28,139 13,314 9,879 1,966 10,614 2,937 38,710 Net future income tax liability $ 181,633 $ 174,571 PDC and its subsidiaries have available net capital losses of $33.8 million of which, after valuation allowances, the benefit of $33.8 million (2006 – $33.4 million) has been recognized. Net capital losses can be carried forward indefinitely. NOTE 9. UNITHOLDERS’ CAPITAL (a) Authorized – unlimited number of voting Trust units – unlimited number of voting exchangeable LP units (b) Unitholders’ capital Trust units Balance, November 7, 2005 Issued pursuant to the Plan Options exercised – cash consideration – reclassification from contributed surplus Issued for cash Balance, December 31, 2005 Issued pursuant to distribution reinvestment plan (Note 6) Issued on retraction of exchangeable LP units Issued and consolidated pursuant to special distribution (Note 6) Balance, December 31, 2006 Issued on retraction of exchangeable LP units Issued and consolidated pursuant to special distribution (Note 6) Number Amount – 122,512,799 1,676,616 – 163,506 124,352,921 296,621 886,787 – 125,536,329 51,590 – $ – 1,339,646 8,263 12,342 5,504 1,365,755 9,896 9,697 24,480 1,409,828 574 30,141 Balance, December 31, 2007 125,587,919 $ 1,440,543 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. 54 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Exchangeable LP units Balance, November 7, 2005 Issued pursuant to the Plan Balance, December 31, 2005 Redeemed on retraction of exchangeable LP units Issued and consolidated pursuant to special distribution (Note 6) Balance, December 31, 2006 Redeemed on retraction of exchangeable LP units Issued and consolidated pursuant to special distribution (Note 6) $ Number – 1,108,382 1,108,382 (886,787) – 221,595 (51,590) – Balance, December 31, 2007 170,005 $ Amount – 12,120 12,120 (9,697) 43 2,466 (574) 41 1,933 Exchangeable LP units have voting rights and were exchangeable, after May 6, 2006, for Trust units on a one-for-one basis at the option of the holder. Holders are entitled to monthly cash distributions equal to those paid to holders of Trust units. Summary as at December 31, Number Amount Number Amount 2007 2006 Trust units Exchangeable LP units Unitholders’ capital (c) Contributed surplus Balance, December 31, 2006 Unit based compensation expense (Note 10(c)) Balance, December 31, 2007 125,587,919 170,005 $ 1,440,543 1,933 125,536,329 221,595 $ 1,409,828 2,466 125,757,924 $ 1,442,476 125,757,924 $ 1,412,294 $ $ – 307 307 NOTE 10. UNIT BASED COMPENSATION PLANS (a) Officers and Employees Eligible participants of Precision’s Performance Savings Plan may 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 the receipt of the DTUs. During 2007, Precision issued 87,340 DTUs, including additional DTUs issued in lieu of cash distributions and redeemed 10,611 DTUs on employee resignations and employee withdrawals. As at December 31, 2007 $1.2 million is included in accounts payable and accrued liabilities for outstanding DTUs. Included in net earnings for the year ended December 31, 2007 is a recovery of $0.8 million. (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 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, 2007 $0.9 million is included in accounts payable and accrued liabilities and $1.9 million in long-term incentive plan payable for the 182,372 outstanding DTUs. Included in net earnings for the year ended December 31, 2007 is an expense of $2.8 million. (c) Non-management directors In 2007 a deferred trust unit plan was established 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. 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. P R E C I S I O N D R I L L I N G T R U S T 55 A summary of this unit based incentive plan is presented below: Balance, December 31, 2006 Granted Issued as a result of distributions Balance, December 31, 2007 Deferred Trust Units Outstanding – 17,855 425 18,280 For the year ended December 31, 2007 the Trust expensed $307,000 as unit based compensation, with a corresponding increase in contributed surplus. NOTE 11. EMPLOYEE BENEFIT PLANS The Trust has registered pension plans covering a significant number of its employees. (a) Defined contribution plan Under the defined contribution plan, the Trust matches individual contributions up to 5% of the employee’s compensation. Total expense under the defined contribution plan in 2007 was $5.3 million (2006 – $5.5 million; 2005 – $8.5 million), of which $nil (2006 – $nil; 2005 – $3.2 million) relates to discontinued operations. (b) Retirement allowance The Trust had entered into an employment agreement with a senior officer, which provided for a one-time payment upon retirement. The amount of this retirement allowance increased by a fixed amount for each year of service over a ten year period commencing April 30, 1996. The estimated cost of this benefit was being accrued and charged to earnings on a straight-line basis over the ten year period. During the year ended December 31, 2005, the Trust charged $201,000 and paid $2.9 million as final settlement of this liability. NOTE 12. COMMITMENTS The Trust has commitments for operating lease agreements, primarily for vehicles and office space, in the aggregate amount of $22.6 million. Payments over the next five years are as follows: 2008 2009 2010 2011 2012 Rent expense included in the statements of earnings is as follows: 2007 2006 2005 $ $ 7,754 6,329 5,078 3,463 16 Total 3,838 4,189 15,819 Continuing Operations Discontinued Operations $ $ 3,838 4,189 3,836 – – 11,983 NOTE 13. PER UNIT AMOUNTS The following table summarizes the units, adjusted retroactively for a 2 for 1 stock split on May 18, 2005, used in calculating earnings per unit: (Stated in thousands) Weighted average units outstanding – basic Effect of stock options and other equity compensation plans Weighted average units outstanding – diluted 2007 2006 2005 125,758 2 125,760 125,545 – 125,545 123,304 2,108 125,412 56 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S NOTE 14. SIGNIFICANT CUSTOMERS During the year ended December 31, 2007 one customer (2006 and 2005 – no customers) accounted for approximately 10% of the Trust’s revenue and year-end trade accounts receivable balance. NOTE 15. 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. Acquisitions relating to discontinued operations are reflected in Note 24. On August 17, 2006, the Trust acquired all of the shares of Terra Water Group Ltd. (“Terra”), a privately owned provider of wastewater treatment units for the traditional drilling rig camp market in western Canada. The Terra operations are included in the Completion and Production Services segment. The details of the acquisition are as follows: Net assets acquired at assigned values: Working capital (1) Property, plant and equipment Goodwill (no tax basis) Long-term debt Future income taxes Consideration: Cash (1) Working capital includes cash of $43 $ $ $ 207 3,168 13,922 (614) (212) 16,471 16,471 NOTE 16. 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 Precision adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48 (“FIN 48”) Accounting for Uncertainty in Income Taxes, for the fiscal year beginning January 1, 2007. The implementation of FIN 48 did not have a material impact on Precision’s U.S. GAAP reconciliation and no adjustment has been made to the January 1, 2007 deficit balance. On December 31, 2007 Precision had $44.4 million (2006 – $40.0 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, 2007 is interest and penalties of $7.0 million (2006 – $3.2 million). Under FIN 48, unrecognized tax benefits are classified as current or long-term liabilities as opposed to future income tax liabilities. Reconciliation of unrecognized tax benefits Year ended December 31, Unrecognized tax benefits, beginning of year Additions: Prior year’s tax positions Reductions: Prior year’s tax positions Unrecognized tax benefits, end of year 2007 $ 40,047 5,770 (1,410) $ 44,407 It is anticipated that approximately $8.4 million of an unrecognized tax position that relates to past reorganization 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 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 57 Precision and its subsidiaries are subject to federal, regional and local taxes in Canada, the United States and other international jurisdictions. Precision has substantially settled all Canadian, U.S. and international income tax matters for taxation years ending before 2000. In 2000 the Trust adopted the 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 liability method prescribed in the Statement of Financial Accounting Standards (SFAS) No. 109, 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 2006 and 2007 the U.S. GAAP financial statements reflect an increase in goodwill of $63.0 million and a corresponding increase in retained earnings. (b) Equity settled unit based compensation As described in Note 10(c), the Trust has initiated an equity settled unit based compensation plan for non-management directors. Trust units issued upon settlement of this plan are redeemable (see Note 16(d)) therefore under U.S. GAAP the plan is 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. (c) Stock-based compensation In 2004, under Canadian GAAP, the Trust adopted the fair value of accounting for stock-based compensation with restatement of prior years for share purchase options granted after January 1, 2002. U.S. GAAP allows the use of either the intrinsic method, as prescribed by Accounting Principles Board (“APB”) Opinion 25, or the fair value method as prescribed by SFAS 123. Where companies elect to use the intrinsic method, disclosure of the impact of using the fair value method is required. Application of the intrinsic method in accordance with APB Opinion 25 would have resulted in an increase in net earnings of $21.3 million for 2005 with a corresponding increase in unitholders’ equity. Had the Trust determined compensation based on the fair value at the date of grant for its options under SFAS 123, net earnings in accordance with U.S. GAAP would have decreased to $1,588.5 million in 2005. Basic earnings per unit/share would have been $12.88 in 2005. Under Financial Accounting Standards Board (“FASB”) Interpretation No. 44 (“FIN 44”) Accounting for Certain Transactions Involving Stock Compensation, compensation expense is required to be recognized on certain modifications to stock-based compensation plans. During the year ended December 31, 2005, employee stock options (“options”) were subjected to a variety of changes or restructurings which included accelerated vesting, repricing on the date of conversion to an income trust to reflect the distribution of disposal consideration to Precision’s shareholders just prior to conversion, or repurchase for cash depending on elections made by the option holders. Under Canadian GAAP, even with repricing, the options were treated as equity awards and were not accounted for under a variable accounting method. However, under U.S. GAAP, the accelerated vesting represents a restructuring in the form of a modification that would result in a new measurement of compensation expense on the date of the modification to the date of exercise using the intrinsic method. For award repricing, this restructuring only results in additional expense provided that the aggregate intrinsic value of the awards immediately after the change is not greater than that immediately before, and the ratio of exercise price per unit/share to the market value per unit/share is not reduced. To the extent that both criteria are not met, the awards are accounted for under ABP Opinion 25 as a variable award from the date of restructuring to the date the award was exercised. For restructuring in the form of cash buy-out of the options, the intrinsic value was charged to retained earnings under Canadian GAAP, however, under U.S. GAAP the amount was charged to earnings. (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 9). 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. 58 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S (e) Recently issued accounting pronouncements In December 2007, FASB issued SFAS 160, 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 statement is effective for fiscal years beginning after December 15, 2008, and will be effective for the Trust’s December 31, 2009 year end. At this time management does not expect this statement to have a material impact on the consolidated financial statements. In December 2007, FASB issued SFAS 141(R), 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 statement is applicable for all business combinations occurring in fiscal years beginning after December 15, 2008 and will be effective for the Trust’s December 31, 2009 year end. In February 2007 FASB issued SFAS 159, The Fair Value Option for Financial Assets and Liabilities – including an amendment of FASB Statement No. 115. The statement provides entities with an irrevocable option to report selected financial assets and liabilities at fair value. The objective is to improve financial reporting by reducing both the complexity in accounting and the volatility in earnings caused by differences in existing accounting rules. The new standard is effective for fiscal years beginning after November 15, 2007 and will be effective for the Trust’s December 31, 2008 year end. The effective date for SFAS 157 as it relates to fair value measurement requirements for non-financial assets and liabilities that are not re-measured at fair value on a recurring basis has been deferred to fiscal years beginning after December 31, 2008. Management does not expect this statement to have a material impact on the consolidated financial statements. On September 15, 2006 FASB issued SFAS 157, Fair Value Measurements. The statement provides enhanced guidance for using fair value to measure assets and liabilities, but does not expand the use of fair value in any new circumstances. The new standard is effective for fiscal years beginning after November 15, 2007 and will be effective for the Trust’s December 31, 2008 year end. Management does not expect this statement to have a material impact on the consolidated financial statements. 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, Earnings from continuing operations under Canadian GAAP Adjustments under U.S. GAAP: Equity-based compensation expense Cash buy-out of options Intrinsic value recognized on options exercised and/or repriced Earnings from continuing operations under U.S. GAAP Earnings from discontinued operations under Canadian GAAP Adjustments under U.S. GAAP: Stock-based compensation expense Cash buy-out of options Intrinsic value recognized on options exercised and/or repriced Earnings from discontinued operations under U.S. GAAP Net earnings and comprehensive income under U.S. GAAP Earnings from continuing operations per unit under U.S. GAAP: Basic Diluted Earnings per unit under U.S. GAAP: Basic Diluted 2007 2006 2005 $ 342,820 $ 572,512 $ 220,848 35 – – 342,855 2,956 – – – 2,956 345,811 2.73 2.73 2.75 2.75 $ $ $ $ $ – – – 572,512 7,077 – – – 11,229 (22,119) (2,270) 207,688 1,409,715 10,109 (19,968) (11,796) 7,077 1,388,060 579,589 $ 1,595,748 4.56 4.56 4.62 4.62 $ $ $ $ 1.68 1.66 12.94 12.72 $ $ $ $ $ P R E C I S I O N D R I L L I N G T R U S T 59 Consolidated Statements of Retained Earnings (Deficit) Years ended December 31, 2007 2006 2005 Retained earnings (deficit) under U.S. GAAP, beginning of year Net earnings under U.S. GAAP Distributions declared Distribution of disposal proceeds Repurchase of common shares of dissenting shareholders Opening temporary equity on conversion to an income trust Change in redemption value of temporary equity $ (1,873,490) 345,811 (276,667) – – – 1,453,448 $ (3,167,045) 579,589 (471,524) – – – 1,185,490 $ 1,133,030 1,595,748 (70,510) (2,851,784) (34,364) (2,560,709) (378,456) Deficit under U.S. GAAP, end of year $ (350,898) $ (1,873,490) $ (3,167,045) Consolidated Balance Sheets As at December 31, As reported U.S. GAAP As reported U.S. GAAP 2007 2006 Current assets Property, plant and equipment Intangibles Goodwill Current liabilities Long-term incentive plan payable Long-term debt Future income taxes Other long-term liabilities Temporary equity Unitholders’ capital Contributed surplus Deficit $ 271,823 1,210,587 318 280,749 $ 271,823 1,210,587 318 343,778 $ 372,445 1,107,617 375 280,749 $ 372,445 1,107,617 375 343,778 $ 1,763,477 $ 1,826,506 $ 1,761,186 $ 1,824,215 $ 131,449 13,896 119,826 181,633 – – 1,442,476 307 (126,110) $ 140,117 13,896 119,826 137,226 36,011 1,730,328 – – (350,898) $ 205,961 22,699 140,880 174,571 – – 1,412,294 – (195,219) $ 205,961 22,699 140,880 174,571 – 3,153,594 – – (1,873,490) $ 1,763,477 $ 1,826,506 $ 1,761,186 $ 1,824,215 NOTE 17. SEGMENTED INFORMATION The Trust operates primarily in Canada, 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. 2007 Revenue Operating earnings Depreciation and amortization Total assets Goodwill Capital expenditures Contract Drilling Services Completion and Production Services $ 694,340 284,754 43,120 1,282,865 172,440 159,004 $ 327,471 100,596 31,421 457,587 108,309 26,772 Corporate and Other Inter-segment Eliminations $ – (28,999) 3,785 23,025 – 1,230 $ (12,610) – – – – – Total $ 1,009,201 356,351 78,326 1,763,477 280,749 187,006 60 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 2006 Revenue Operating earnings Depreciation and amortization Total assets Goodwill Capital expenditures* * Excludes business acquisitions 2005 Revenue Operating earnings Depreciation and amortization Total assets Goodwill Capital expenditures* * Excludes business acquisitions Contract Drilling Services Completion and Production Services $ 1,009,821 473,624 38,573 1,198,284 172,440 220,397 $ 441,017 163,119 32,013 507,510 108,309 39,273 Contract Drilling Services Completion and Production Services $ 916,221 404,385 39,233 1,159,687 172,440 106,986 $ 369,667 121,643 27,402 486,701 94,387 34,576 $ $ Corporate and Other Inter-segment Eliminations – (41,464) 2,648 55,392 – 3,360 $ (13,254) – – – – – Corporate and Other Inter-segment Eliminations – (60,650) 4,926 72,494 – 13,689 $ (16,709) – – – – – Total $ 1,437,584 595,279 73,234 1,761,186 280,749 263,030 Total $ 1,269,179 465,378 71,561 1,718,882 266,827 155,251 NOTE 18. FINANCIAL INSTRUMENTS (a) Fair value The carrying value of 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 long-term debt approximates its carrying value as it bears floating rates. (b) Credit risk Accounts receivable includes balances from a large number of customers primarily operating in the oil and gas industry. The Trust assesses the creditworthiness of its customers on an ongoing basis as well as monitoring the amount and age of balances outstanding. Accordingly, the Trust views the credit risks on these amounts as normal for the industry. As at December 31, 2007 the Trust’s allowance for doubtful accounts was $6.4 million (2006 – $5.6 million). Included in net earnings for the year ended December 31, 2007 is a charge for $1.2 million (2006 – $0.7 million) related to a provision for doubtful accounts. (c) Interest rate risk The Trust is exposed to interest rate risk with respect to interest expense on its credit facilities. If interest rates applying to long-term debt during the year had been one percent lower or higher, with all other variables held constant, earnings from continuing operations would have changed by approximately $1.1 million (2006 – $1.0 million), net of income tax. (d) Foreign currency risk The Trust was exposed to foreign currency fluctuations in relation to its international operations prior to their disposal in 2005 (see Note 24). To manage a portion of this exposure, the Trust designated US$300.0 million notes as a hedge against foreign currency fluctuations of its investment in self-sustaining foreign operations. A net foreign exchange gain of $10.1 million associated with these notes was included in the cumulative translation account during 2005. The cumulative translation account at August 31, 2005 of $24.8 million was charged to the gain on disposal of discontinued operations in 2005. P R E C I S I O N D R I L L I N G T R U S T 61 NOTE 19. SUPPLEMENTAL INFORMATION Interest paid: – continuing operations – discontinued operations Income taxes paid: – continuing operations – discontinued operations Components of change in non-cash working capital balances: Accounts receivable Inventory Accounts payable and accrued liabilities Income taxes The components of accounts receivable are as follows: Trade Accrued trade Prepaids and other The components of accounts payable and accrued liabilities are as follows: Accounts payable Accrued liabilities: Payroll Other 2007 2006 2005 $ $ $ $ $ 7,870 – 7,870 4,307 – 4,307 98,055 (182) (49,338) 2,749 $ $ $ $ $ 8,929 – 8,929 207,160 – 207,160 148,046 (2,038) (4,736) (172,634) $ $ $ $ $ 43,232 304 43,536 91,496 35,176 126,672 (171,363) 699 13,871 149,906 $ 51,284 $ (31,362) $ (6,887) 2007 2006 $ 144,468 96,869 15,279 $ 220,623 93,308 40,740 $ 256,616 $ 354,671 2007 2006 $ 36,742 $ 60,650 28,527 15,595 80,684 47,001 22,551 $ 130,202 $ NOTE 20. CONTINGENCIES 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. The Trust’s management 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 payable, before interest and penalties, could be up to $300 million. Subsequent to year end Precision received, from a provincial taxing authority, Notices of Reassessment relating to prior period tax filing positions for $55 million. The income tax related portion of the reassessments is $36 million and is included in the tax contingency noted above. Precision is of the opinion that the provincial tax authority’s position is without merit and will be challenging these reassessments. 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. The Trust maintains a level of insurance coverage deemed appropriate by management for matters for which insurance coverage can be acquired. 62 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S NOTE 21. 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 22. RELATED PARTY TRANSACTIONS During the year ended December 31, 2005 the Trust incurred a total of $6.1 million in legal fees with a law firm for various legal matters where a director of Precision Drilling Corporation was a partner. These transactions were incurred in the normal course of business and were recorded at the exchange amounts. NOTE 23. REORGANIZATION INTO A TRUST To effect the reorganization into a trust, for the year ended December 31, 2005, the Trust incurred $17.5 million of reorganization costs comprised as follows: Severance Legal, accounting, financial advisory services and other $ $ 12,600 4,912 17,512 Share capital of Precision prior to reorganization into the Trust included: (a) Common shares On November 7, 2005, Precision converted to an unincorporated, open-ended investment trust pursuant to the Plan, which resulted in shareholders receiving one Trust unit or one exchangeable LP unit or a combination thereof, for each previously held common share. Common shares held by shareholders who dissented to the Plan were repurchased and cancelled on the effective date of the Plan. All outstanding common share purchase options were converted to options to acquire Trust units. The holder then had three options; exercise the options, have the Trust repurchase them for cash using the closing market price of the Trust one day prior to cash-out, or have the Trust repurchase the options as set-out above and use the proceeds to purchase an equivalent number of Trust units. Balance, December 31, 2004 Options exercised – cash consideration – reclassification from contributed surplus Balance, May 18, 2005 Issued on 2:1 stock split Options exercised – cash consideration – reclassification from contributed surplus Adjustment to number of shares outstanding Cancellation of shares owned by dissenting shareholders Balance, November 7, 2005, before conversion to units Conversion to Trust units Conversion to exchangeable LP units Number Amount 60,790,212 578,346 – 61,368,558 61,368,558 1,679,110 – 21,960 (817,005) 123,621,181 (122,512,799) (1,108,382) $ 1,274,967 24,516 1,521 1,301,004 – 49,414 10,284 – (8,936) 1,351,766 (1,339,646) (12,120) Balance, November 7, 2005, after conversion to units – $ – Pursuant to the Plan, any shareholders of Precision could dissent and be paid the fair value of the shares, being the trading price at the close of business on the last business day prior to the Special Meeting of Securityholders on October 31, 2005. As a result, the Trust repurchased for cancellation a total of 817,005 shares for $43.3 million, of which a premium of $34.4 million over the stated capital was charged to retained earnings. P R E C I S I O N D R I L L I N G T R U S T 63 (b) Contributed surplus: Balance, December 31, 2004 Stock-based compensation expense Accelerated vesting of options on disposal of discontinued operations Reclassification to common shares on exercise of options prior to the Plan Accelerated vesting of options pursuant to the Plan Reclassification to Trust units on exercise of options Reclassification to retained earnings on cash buy-out of options Balance, December 31, 2005 $ 26,024 13,077 5,205 (11,805) 3,056 (12,342) (23,215) $ – (c) Equity incentive plans Prior to conversion to a Trust, Precision had equity incentive plans under which the exercise price of each option equaled the market value of the Corporation’s share on the date of grant and an option’s maximum term was 10 years. Options vested over a period of 1 to 4 years from the date of grant as employees or directors rendered continuous service to Precision. Options held by employees of the Energy Services and International Contract Drilling Divisions and of CEDA International Corporation (“CEDA”) became fully vested when these businesses were sold during the third quarter of 2005 (see Note 24). Pursuant to the Plan, the remaining outstanding options were exchanged for newly vested options to acquire Trust units. The exercise prices of the options to acquire Trust units were adjusted downward to reflect the value of the distribution of certain assets to shareholders as part of the Plan. The options to acquire Trust units expired on November 22, 2005. Upon acceleration of the vesting of options, options holders were given the choice to pay the exercise price and receive a common share or Trust unit, as applicable, or to surrender their option for a cash payment equal to the difference between the closing market value of the common share or Trust unit one day prior to cash buy-out and the exercise price. All outstanding options were exercised prior to December 31, 2005. A summary of the equity incentive plans, adjusted retroactively to reflect the 2 for 1 stock split on May 18, 2005 as at December 31, 2005 and changes during the period then ended is presented below: Common Share Purchase Options Outstanding at December 31, 2004 Granted Exercised Cancelled Purchased Exchanged for Trust unit purchase options Options Outstanding 6,695,120 696,200 (2,835,802) (141,650) (1,105,018) (3,308,850) Range of Exercise Price $ 15.53 – 36.32 37.76 – 48.29 15.53 – 48.29 15.53 – 31.87 15.53 – 45.25 15.53 – 48.29 Weighted Average Exercise Price $ 27.44 41.42 26.07 30.26 31.30 30.14 Options Exercisable 2,580,302 Outstanding at December 31, 2005 – $ – $ – – Trust Unit Purchase Options Options Outstanding Range of Exercise Price Weighted Average Exercise Price Options Exercisable Outstanding at November 7, 2005 – $ – $ – – Granted in exchange for common share purchase options pursuant to the Plan Granted on repricing of common share options Exercised Purchased 3,308,850 5,600 (1,676,616) (1,637,834) nil – 27.25 nil nil – 27.25 nil – 27.25 9.16 nil 4.93 13.46 3,308,850 Outstanding at December 31, 2005 – $ – $ – – In accordance with the Trust’s common share purchase option plans, options had an initial exercise price equal to the market price at date of grant. The per share weighted average fair value of stock options granted during the year ended December 31, 2005 was $8.30 based on the date of grant valuation using the Black-Scholes option pricing model with the following assumptions: average risk-free interest rate of 3.28%, average expected life of 2.92 years and expected volatility of 28.04%. For the year ended December 31, 2005 stock-based compensation costs included in net earnings totaled $21.3 million, of which $10.1 million related to discontinued operations. 64 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S NOTE 24. DISCONTINUED OPERATIONS A summary of discontinued operations is presented below including: disposal transactions; financial information with respect to amounts included in the statements of earnings and statements of cash flows; significant accounting policies relating specifically to discontinued operations; and business acquisitions included in discontinued operations. The details of disposals of discontinued operations are as follows: 2007 In September 2007 the Trust received $3.0 million as partial settlement of an outstanding matter associated with a previous business divestiture. 2006 In January 2007, the Trust received $21.3 million as payment of the working capital adjustment related to the 2005 disposition of its Energy Services and International Contract Drilling divisions to Weatherford International Ltd. (“Weatherford”). This amount had been recorded in accounts receivable at December 31, 2006 (2005 – $20.0 million). In August 2006, the Trust received $4.8 million as settlement of the working capital adjustment arising from the 2005 disposal of CEDA and $2.5 million as final payment of the contingent consideration associated with the 2004 disposal of United Diamond Ltd. In total these amounts resulted in a gain of $8.3 million ($7.1 million net of tax). 2005 On August 31, 2005, the Trust sold its Energy Services and International Contract Drilling divisions to Weatherford for proceeds of approximately $1.13 billion cash and 26 million common shares of Weatherford, valued at $2.1 billion. In conjunction with the Plan of Arrangement, the Trust then distributed a total of $2.9 billion of this consideration to unitholders, being $844.3 million in cash and 25.7 million Weatherford common shares, valued at $2.0 billion which represented the fair value of the shares at the date of distribution. Included in the statement of earnings for the year ended December 31, 2005 was a loss on disposal of these shares of $71.0 million. In conjunction with this sale, a working capital adjustment was included as part of the purchase and sale agreement. This adjustment was substantially settled in January 2007. In addition on September 13, 2005 the Trust sold its industrial plant maintenance business carried on by CEDA to Borealis Investments Inc., an investment entity of the Ontario Municipal Employees Retirement System, for proceeds of approximately $274.0 million. Included in the CEDA proceeds was $26.8 million for the purchase of CASCA Electric Ltd. and CASCA Tech Inc., a transaction undertaken by CEDA on July 29, 2005. A working capital adjustment relating to this disposal was received in August 2006. The Energy Services, International Contract Drilling and CEDA assets were included in the Energy Services, Contract Drilling and Rental and Production segments respectively and were disposed in accordance with an extensive process undertaken by the Trust’s Board of Directors to investigate avenues of value creation for the Trust’s unitholders. Results of the operations of these businesses have been classified as results of discontinued operations. P R E C I S I O N D R I L L I N G T R U S T 65 The following table provides additional information with respect to amounts included in the statements of earnings related to discontinued operations: Revenue: Energy services International contract drilling Industrial plant maintenance Gain on disposal: Gain on disposal of United Diamond Gain on disposal of Energy services and International contract drilling Gain on disposal of Industrial plant maintenance Results of operations before income taxes: Energy services International contract drilling Industrial plant maintenance Other Income tax expense Results of operations 2007 2006 2005 $ $ $ – – – – – 2,956 – 2,956 – – – – – – – $ $ $ – – – – $ 689,319 204,987 149,371 $ 1,043,677 2,070 962 4,045 7,077 $ – 1,203,309 132,073 1,335,382 – – – – – – – 76,607 41,171 18,135 (22,298) 113,615 39,282 74,333 Net earnings of discontinued operations $ 2,956 $ 7,077 $ 1,409,715 The following table provides additional information with respect to amounts included in the statements of cash flow related to discontinued operations: Net earnings of discontinued operations Items not affecting cash: Gain on disposal of discontinued operations Depreciation and amortization Stock-based compensation Future income taxes Unrealized foreign exchange loss on long-term monetary items 2007 2006 2005 $ 2,956 $ 7,077 $ 1,409,715 (2,956) – – – – (7,077) – – – – (1,335,382) 95,794 10,109 (1,735) 4,829 Funds provided by discontinued operations $ – $ – $ 183,330 Components of changes in non-cash working capital balances of discontinued operations: Accounts receivable Inventory Accounts payable and accrued liabilities Income taxes payable 2007 2006 2005 $ $ – – – – – $ $ – – – – – $ (60,912) (23,463) 1,688 (3,623) $ (86,310) Significant accounting policies relating to discontinued operations included: 66 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S (a) Employee benefit plans Employer contributions to defined contribution plans were expensed as employees earned the entitlement and contributions were made. The Trust accrued the cost of pensions earned by employees under its defined benefit plan, which was actuarially determined using the projected benefit method pro-rated on services and management’s best estimate of expected plan investment performance, salary escalation and retirement ages of employees. For the purpose of calculating the expected return on plan assets, those assets were valued at quoted market value at the balance sheet date. The discount rate used to calculate the interest cost on the accrued benefit obligation was the long-term market rate at the balance sheet date. Past service costs from plan amendments were amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment (“EARSL”). The excess of the net cumulative unamortized actuarial gain or loss over 10% of the greater of the accrued benefit obligation and the market value of plan assets was amortized over EARSL. (b) Foreign currency translation Accounts of the Trust’s self-sustaining operations were translated to Canadian dollars using average exchange rates for the year for revenue and expenses. Assets and liabilities were translated at the year-end current exchange rate. Gains or losses resulting from these translation adjustments were included in the cumulative translation account in unitholders’ equity. Gains and losses arising on translation of long-term debt designated as a hedge of self-sustaining foreign operations were deferred and included in the cumulative translation account in unitholders’ equity on a net of tax basis. (c) Hedging relationships The Trust utilized foreign currency long-term debt to hedge its exposure to changes in the carrying values of the Trust’s net investment in certain self-sustaining foreign operations as a result of changes in foreign exchange rates. To be accounted for as a hedge, the foreign currency long-term debt must be designated and documented as a hedge, and must be effective at inception and on an ongoing basis. The documentation defined the relationship between the foreign currency long-term debt and the net investment in the foreign operations, as well as the Trust’s risk management objective and strategy for undertaking the hedging transaction. The Trust formally assessed, both at the hedge’s inception and on an ongoing basis, whether the changes in fair value of the foreign currency long-term debt was highly effective in offsetting changes in the fair value of the net investment in the foreign operations. If the hedging relationship was terminated or ceased to be effective, hedge accounting was not applied to subsequent gains or losses. Any previously deferred amounts were carried forward and recognized in earnings in the same period as the hedged item. (d) Research and engineering Research and engineering costs were charged to income as incurred. Costs associated with the development of new operating tools and systems were expensed during the period unless the recovery of these costs could be reasonably assured given the existing and anticipated future industry conditions. Upon successful completion and field testing of the tools, any deferred costs were transferred to the related capital asset accounts. The details of business acquisitions completed in 2005 that have been included in discontinued operations are as follows: On July 29, 2005, the Trust completed the acquisition of all the issued and outstanding shares of CASCA Electric Ltd. and CASCA Tech Inc. for $30.4 million. No value was assigned to intangibles or goodwill. P R E C I S I O N D R I L L I N G T R U S T 67 Supplemental Information PD.UN Volume 3.0 2.5 2.0 1.5 1.0 0.5 Precision Drilling Trust SUPPLEMENTAL INFORMATION UNIT TRADING SUMMARY – 2007 The Toronto Stock Exchange (TSX) Unit Price (Cdn$) Volume (millions) $35 $30 $25 $20 $15 $10 $5 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec The New York Stock Exchange (NYSE) Unit Price (US$) Volume (millions) $30 $25 $20 $15 $10 $5 PDS Volume 3.0 2.5 2.0 1.5 1.0 0.5 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 68 S U P P L E M E N T A L I N F O R M A T I O N Precision Drilling Trust CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS (DEFICIT) Years ended December 31, (Stated in millions of Canadian dollars, except per unit/share amounts) Revenue Expenses: Operating General and administrative Depreciation and amortization Foreign exchange Reorganization costs Operating earnings Interest, net Premium on redemption of bonds Loss on disposal of short-term investments Other Earnings from continuing operations before income taxes Income taxes Earnings from continuing operations Discontinued operations, net of tax Net earnings Retained earnings (deficit), beginning of year Adjustment on cash purchase of employee stock options, net of tax Reclassification from contributed surplus on cash buy-out of employee stock options Distribution of disposal proceeds Repurchase of common shares of dissenting shareholders Distributions declared 2007 2006 2005 2004 2003 $ 1,009.2 $ 1,437.6 $ 1,269.2 $ 1,028.5 $ 915.2 516.1 56.0 78.3 2.4 – 356.4 7.4 – – – 349.0 6.2 342.8 3.0 345.8 688.2 81.2 73.2 (0.3) – 595.3 8.0 – – (0.4) 587.7 15.2 572.5 7.1 579.6 641.8 76.4 71.6 (3.5) 17.5 465.4 29.3 71.9 71.0 – 293.2 72.4 220.8 1,409.8 1,630.6 566.3 64.2 74.8 (8.1) – 331.3 46.3 – – 544.2 42.7 78.1 (2.2) – 252.4 34.0 – – (4.9) (1.5) 289.9 101.8 188.1 59.3 247.4 219.9 75.7 144.2 36.3 180.5 (195.2) (303.3) 1,041.7 794.3 613.8 – – – – – – – – (276.7) (471.5) (42.1) 23.2 (2,851.8) (34.4) (70.5) – – – – – – – – – – Retained earnings (deficit), end of year $ (126.1) $ (195.2) $ (303.3) $ 1,041.7 $ 794.3 Earnings per unit/share from continuing operations: Basic Diluted Earnings per unit/share: Basic Diluted $ $ $ $ 2.73 2.73 2.75 2.75 $ $ $ $ 4.56 4.56 4.62 4.62 $ $ $ $ 1.79 1.76 13.22 13.00 $ $ $ $ 1.63 1.61 2.14 2.11 $ $ $ $ 1.33 1.31 1.66 1.63 P R E C I S I O N D R I L L I N G T R U S T 69 Precision Drilling Trust ADDITIONAL SELECTED FINANCIAL INFORMATION Years ended December 31, (Stated in millions of Canadian dollars, except per unit/share amounts) Return on sales – % (1) Return on assets – % (2) Return on equity – % (3) Working capital Current ratio PP&E and intangibles Total assets Long-term debt Unitholders’ equity Long-term debt to long-term debt plus equity Interest coverage (4) Net capital expenditures from continuing operations excluding business acquisitions EBITDA (5) EBITDA – % of revenue Operating earnings Operating earnings – % of revenue Cash flow from continuing operations Cash flow from continuing operations per unit/share Basic Diluted Book value per unit/share (6) Price earnings ratio (7) Basic weighted average units/shares 2007 34.0 19.9 27.0 140.4 2.1 1,210.9 1,763.5 119.8 1,316.7 0.08 48.7 181.2 434.7 43.1 356.4 35.3 484.1 3.85 3.85 10.47 5.49 $ $ $ $ $ $ $ $ $ $ $ $ 2006 39.8 33.6 49.4 166.5 1.81 1,108.0 1,761.2 140.9 1,217.1 0.10 74.1 233.7 668.5 46.5 595.3 41.4 609.7 4.86 4.86 9.68 5.84 $ $ $ $ $ $ $ $ $ $ $ $ 2005 17.4 43.3 66.1 152.8 1.43 944.4 1,718.9 96.8 1,074.6 0.08 15.9 140.1 536.9 42.3 465.4 36.7 206.0 1.67 1.64 8.57 2.90 $ $ $ $ $ $ $ $ $ $ $ $ 2004 18.3 7.3 12.3 557.3 2.47 898.1 3,852.0 718.9 2,321.7 0.24 7.2 113.9 406.1 39.5 331.3 32.2 286.4 2.48 2.44 19.10 17.6 $ $ $ $ $ $ $ $ $ $ $ $ 2003 15.8 6.3 11.0 249.0 1.57 887.7 2,932.0 399.4 1,745.3 0.19 7.4 84.9 330.6 36.1 252.4 27.6 200.9 1.85 1.82 15.91 17.1 $ $ $ $ $ $ $ $ $ $ $ $ outstanding (000’s) 125,758 125,545 123,304 115,654 108,860 (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) Earnings before net interest, taxes, depreciation, amortization, non-controlling interest, premium on redemption of bonds, gain/loss on disposal of investments and discontinued operations. EBITDA is not a recognized measure under Canadian GAAP. Management believes that in addition to net earnings, EBITDA is a useful supplemental measure as it provides an indication of the results generated by the Trust’s principal business activities prior to consideration of how those activities are financed or how the results are taxed in various jurisdictions and prior to the impact of depreciation and amortization. Investors should be cautioned, however, that EBITDA should not be construed as an alternative to net earnings determined in accordance with GAAP as an indicator of Precision’s performance. Precision’s method of calculating EBITDA may differ from other companies and, accordingly, EBITDA may not be comparable to measures used by other companies. (6) Book value per unit/share was calculated by dividing unitholders’ equity by units/shares outstanding. (7) Year end closing price divided by basic earnings per unit/share. 70 S U P P L E M E N T A L I N F O R M A T I O N Precision Drilling Trust UNITHOLDER INFORMATION STOCK EXCHANGE LISTINGS Or you can email Precision’s Transfer Agent at: Units of Precision Drilling Trust are listed on the Toronto service@computershare.com Stock Exchange under the trading symbol PD.UN and on the New York Stock Exchange under the trading symbol PDS. VOTING RIGHTS Unitholders receive one vote for each Trust unit or Precision Drilling Limited Partnership Class B limited partnership unit held. TRUST UNIT TRADING PROFILE Toronto (TSX: PD.UN) January 1, 2007 to December 31, 2007: High: $30.93, Low: $14.82 Volume Traded: 145,535,269 New York (NYSE: PDS) January 1, 2007 to December 31, 2007: High: US$27.89, Low: US$14.91 Volume Traded: 174,780,109 ACCOUNT QUESTIONS As a Precision Drilling Trust unitholder or as a holder of Class B limited partnership units of Precision Drilling Limited Partnership which are exchangeable on a one for one basis with units of the Trust, you are invited to take advantage of unitholder services or to request more information about Precision. Precision’s Transfer Agent can help you with a variety of unitholder related services, including: K Change of address K Lost unit certificates K Transfer of trust units to another person K Estate settlement You can call Precision’s Transfer Agent toll free at: 1-800-564-6253 You can write to Precision’s Transfer Agent at: Computershare Trust Company of Canada 100 University Avenue, 9th Floor Toronto, Ontario M5J 2Y1 Unitholders of record who receive more than one copy of this annual report can contact Precision’s Transfer Agent and arrange to have their accounts consolidated. Unitholders who own Precision Drilling Trust units through a brokerage firm can contact their broker to request consolidation of their accounts. QUARTERLY UPDATES If you would like to receive interim reports but are not a registered unitholder, please write or call Precision with your name and address. To receive news releases by fax, please forward your fax number to Precision. ONLINE INFORMATION To receive Precision’s news releases by email, or to view this annual report online, please visit Precision’s website at www.precisiondrilling.com and refer to the Investor Relations section. PUBLISHED INFORMATION If you wish to receive copies of the 2007 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: Vice President, Corporate Services and Corporate Secretary Precision Drilling Corporation 4200, 150 – 6th Avenue SW Calgary, Alberta, Canada T2P 3Y7 Telephone: 403-716-4500 Facsimile: 403-264-0251 ESTIMATED INTERIM RELEASE DATES 2008 First Quarter – April 24, 2008 2008 Second Quarter – July 24, 2008 2008 Third Quarter – October 23, 2008 P R E C I S I O N D R I L L I N G T R U S T 71 SENIOR MANAGEMENT Doug Evasiuk Vice President, Sales and Marketing Grant Hunter Vice President, USA Operations Rolly Marks Vice President, Operations Ross Pickering Vice President, Operations Steve James Vice President, Health, Safety and Environment and Human Resources Len Gambles Chief Accounting Officer Terry Sakamoto Vice President, Finance, Operations Wane Stickland Vice President, Finance LEAD BANK Royal Bank of Canada Calgary, Alberta AUDITORS KPMG LLP Calgary, Alberta TRANSFER AGENT AND REGISTRAR Computershare Trust Company of Canada Calgary, Alberta TRANSFER POINT Computershare Trust Company NA Denver, Colorado Precision Drilling Trust CORPORATE INFORMATION HEAD OFFICE Precision Drilling Trust 4200, 150 – 6th Avenue SW Calgary, Alberta, Canada T2P 3Y7 Telephone: 403-716-4500 Facsimile: 403-264-0251 Email: info@precisiondrilling.com www.precisiondrilling.com TRUSTEES Robert J.S. Gibson Patrick M. Murray Allen R. Hagerman, FCA DIRECTORS 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 OFFICERS Kevin A. Neveu Chief Executive Officer Gene C. Stahl President and Chief Operating Officer Douglas J. Strong Chief Financial Officer Darren J. Ruhr Vice President, Corporate Services and Corporate Secretary Kenneth J. Haddad Vice President, Business Development 72 C O R P O R A T E I N F O R M A T I O N TSX PD.UN NYSE PDS Precision Drilling Trust www.precisiondrilling.com 

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