form40vf
 

 
 
U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 40-F
     
(Check One) 
 
o    Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934
 
  or       
 
þ    Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2006
Commission file number 001-14534
PRECISION DRILLING TRUST
(Exact name of registrant as specified in its charter)
         
Alberta, Canada
 (Province or other jurisdiction of
incorporation or organization)
  1381
 (Primary Standard Industrial
Classification Code Number
(if applicable)) 		  Not applicable
 (I.R.S. Employer
Identification Number (if applicable))
4200-150 6th Avenue, S.W., Calgary, Alberta, Canada T2P 3Y7
(403) 716-4500
(Address and telephone number of Registrant’s principal executive offices)
CT Corporation System, 811 Dallas Avenue, Houston, Texas 77022
(713) 658-9486
(Name, address (including zip code) and telephone number
(including area code) of agent for service in the United States)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
     
Title of each class   Name of each exchange on which registered
Trust Units
  New York Stock Exchange
Securities registered or to be registered pursuant to Section 12(g) of the Act.   None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.    None
For annual reports, indicate by check mark the information filed with this Form:
     
þ   Annual Information Form
  þ   Audited Annual Financial Statements
     Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:  125,536,329 Trust Units
     Indicate by check mark whether the Registrant by filing the information contained in this form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the file number assigned to the Registrant in connection with such Rule.
     
Yes   o
  No   þ
     Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.
     
Yes   þ
  No   o
     The Annual Report on Form 40-F shall be incorporated by reference into, or as an exhibit to, as applicable, the Registrant’s Registration Statements under the Securities Act of 1933: Form F-10 (File No. 333-115330), Form S-8 (File No. 333-124811, 333-116492 and 333-105648).
 
 

 

 

Principal Documents
The following documents have been filed as part of this Annual Report on Form 40-F and are included immediately after this section:
(a)   Annual Information Form for the fiscal year ended December 31, 2006;
 
(b)   Management’s Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2006; and
 
(c)   Consolidated Financial Statements for the fiscal year ended December 31, 2006 (Note 16 to the Consolidated Financial Statements relates to United States Generally Accepted Accounting Principles (U.S. GAAP)).

 

 

(PRECISION DRILLING LOGO)
PRECISION DRILLING TRUST
ANNUAL INFORMATION FORM
For the fiscal year ended December 31, 2006
Dated March 29, 2007

 

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS
     This Annual Information Form 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. 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 in this Annual Information Form include, but are not limited to statements with respect to:
•   2007 expected cash provided by continuing operations;
•   2007 capital expenditures, including the amount and nature thereof;
•   2007 distributions;
•   performance of the oil and natural gas industry, including 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 2007 strategy and outlook for our business segments;
•   expansion and growth of our business and operations, including diversification of our earnings base, 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;
•   the maintenance of existing customer, supplier and partner relationships;
•   supply channels;
•   accounting policies and tax liability;
•   expected payments pursuant to contractual obligations;
•   the prospective impact of recent or anticipated regulatory changes;
•   financing strategy and compliance with debt covenants;
•   credit risks; and
•   other such matters.
     All such forward-looking information and statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. These statements are, however, subject to known and unknown risks and uncertainties and other factors. As a result, actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking information and statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information and statements will transpire or occur, or if any of them do so, what benefits will be derived therefrom. These risks, uncertainties and other factors include, among others:
•   the impact of general economic conditions in Canada and the United States;
•   world energy prices and government policies;
•   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;
•   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;

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•   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;
•   opportunities available to or pursued by us;
•   and other factors, many of which are beyond our control.
     These risk factors are discussed in this Annual Information Form, our Annual Report and Form 40-F on file with the Canadian securities commission 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 Information Form are expressly qualified by this cautionary statement.

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CORPORATE STRUCTURE
INCORPORATION INFORMATION AND ADDRESS
The Trust
     Precision Drilling Trust (the “Trust”) is an unincorporated open-ended investment trust established under the laws of the Province of Alberta pursuant to a declaration of trust dated September 22, 2005 (the “Declaration of Trust”). The Trust maintains its head office and principal place of business at 4200, 150 — 6th Avenue SW Calgary, Alberta, T2P 3Y7, telephone (403) 716-4500, facsimile (403) 264-0251, email info@precisiondrilling.com and website www.precisiondrilling.com.
     The Trust issued units (“Trust Units”) to certain former shareholders of Precision Drilling Corporation (“Precision”) pursuant to a plan of arrangement which was approved by the former shareholders of Precision at a special meeting held on October 31, 2005 (the “Plan of Arrangement”).
     The notice of meeting and information circular (the “2005 Special Meeting Information Circular”) with respect to the Plan of Arrangement was filed on the Canadian System for Electronic Document Analysis and Retrieval (“SEDAR”) on October 3, 2005 under the SEDAR profile for Precision, and on March 31, 2006 under the SEDAR profile for the Trust, available at www.sedar.com. Specified pages of the 2005 Special Meeting Information Circular are incorporated herein by reference.
Precision Drilling Limited Partnership
     Precision Drilling Limited Partnership (“PDLP”) is a limited partnership formed pursuant to the laws of the Province of Manitoba. The Trust holds a 99.82% interest in PDLP through its holding of Class A Limited Partnership Units (the “PDLP A Units”) and the remaining 0.18% of PDLP is held by former shareholders of Precision who elected to receive Class B Limited Partnership Units (“Exchangeable Units”) which are exchangeable into Trust Units on a one-for-one basis and are the economic equivalent of Trust Units. The head and principal offices of PDLP are located at 4200, 150 — 6th Avenue SW Calgary, Alberta, T2P 3Y7, telephone (403) 716-4500 and facsimile (403) 264-0251, email info@precisiondrilling.com.
Precision Drilling Corporation
     Precision was originally incorporated on March 25, 1985 and carried out amalgamations with wholly-owned subsidiary companies on January 1, 2000, January 1, 2002 and January 1, 2004 pursuant to Articles of Amalgamation and other provisions of the Business Corporations Act (Alberta). On November 7, 2005 Precision became a wholly-owned subsidiary of PDLP. As part of the Plan of Arrangement, Precision amalgamated with a number of its wholly-owned subsidiaries. Precision amalgamated with: 1195309 Alberta ULC on November 23, 2005; Live Well Service Ltd. on January 1, 2006; and Terra Water Group Ltd. (“Terra”) on January 1, 2007. In each amalgamation the name of the amalgamated company remained “Precision Drilling Corporation”. The head and principal offices of Precision are located at 4200, 150 — 6th Avenue SW Calgary, Alberta, T2P 3Y7, telephone (403) 716-4500 and facsimile (403) 264-0251, email info@precisiondrilling.com.
INTERCORPORATE RELATIONSHIPS
     The following table sets forth the names of the material subsidiaries (which includes major limited liability partnerships) of the Trust, the percent of shares (or interest) owned by the Trust and the jurisdiction of incorporation or continuance of each such subsidiary (or partnership) as of December 31, 2006:
                     
                Jurisdiction of
                Incorporation or
Name of Subsidiary or Partnership     Percent or Interest Owned     Continuance
Precision Drilling Limited Partnership
       99.82 %     Manitoba
1194312 Alberta Ltd.
       100 %     Alberta
Precision Drilling Corporation
       99.82 %     Alberta

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Organizational Structure of the Trust
     The following diagram sets forth the organizational structure of the Trust and its material subsidiaries as of the date hereof:
(FLOW CHART)
 
NOTES:
(1)   As of December 31, 2006 there were 125,536,329 PDLP A Units outstanding.
 
(2)   As of December 31, 2006 there were 221,595 Exchangeable Units outstanding.
 
(3)   The interest of 1194312 Alberta Ltd. in PDLP is 0.001%.
 
(4)   Inter-company note owing by Precision to PDLP (the “Promissory Note”).
GENERAL DEVELOPMENT OF THE BUSINESS
THREE YEAR HISTORY
     During 2006, Precision focused capital spending on additions to property, plant and equipment to grow and upgrade its rig fleet, initiated contract drilling operations in the United States and acquired Terra, a privately owned wastewater treatment business operating at remote worksites.
     During 2006, Precision also initiated a plan to establish a full-cycle track record of distributions following conversion to an income trust in November 2005. However, on October 31, 2006, the Government of Canada announced a Tax Fairness Plan containing its intentions to bring about new tax measures including “a Distribution Tax on distributions from publicly traded income trusts and limited partnerships.” The government is proposing a four-year transition period for existing income trusts and limited partnerships whereby the new measures will not apply until their 2011 taxation year. Under the proposals, “flow-through entities” will be taxed more like corporations and their investors will be treated more like shareholders. The proposed new tax measures will impair the flow-through nature of Precision Drilling Trust’s current tax structure. If enacted into law, these tax measures would result in a distribution tax to the Trust which will reduce the cash distributed to Unitholders (as defined below) by the amount of distribution tax paid. Precision originally converted to a trust because the tax rules of the day allowed the market to place a higher value for unitholders on the flow-through structure than the traditional

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corporate structure. In light of proposed tax legislative changes the Trust’s board of trustees (the “Board of Trustees” and each a “Trustee”) will be examining whether changes in the current legal structure are appropriate and in the best interests of unitholders and, if so, when such changes should be implemented.
     Upon Precision’s conversion to an income trust effective November 7, 2005, Precision began making monthly distributions to holders of Trust Units and holders of Exchangeable Units (together “Unitholders”). The Trust has a legal entity structure whereby Precision Drilling Trust, effectively must flow its taxable income to Unitholders pursuant to its Declaration of Trust. Distributions may be reduced, increased or entirely suspended depending on the operations of Precision and the performance of its assets, or legislative changes in tax laws by governments in Canada.
     Precision is a mature organization that operates in a cyclical industry with seasonal swings in revenue levels. The actual cash flow available for distribution to Unitholders is a function of numerous factors, including financial performance, debt covenants and obligations, working capital requirements, as well as maintenance and expansion capital expenditure requirements for the purchase of property, plant and equipment.
     In Canada, Precision is the largest provider of land based contract drilling services to oil and natural gas exploration and production companies, based on the number of wells and metres drilled annually. Precision’s continuing business services during 2006 comprised: contract drilling rigs; well service rigs; snubbing; procurement and distribution of oilfield supplies; camp and catering; manufacture and refurbishment of rig equipment; portable wastewater treatment services; as well as rental of surface oilfield equipment, tubulars, well control equipment and wellsite accommodations.
     Precision invested $171 million in expansion capital for the purchase of property, plant and equipment and $92 million in productive capacity maintenance in 2006. When combined with the $16 million business acquisition of Terra, Precision increased its asset base by $279 million in 2006. A total of 13 new drilling rigs were commissioned in 2006 and two were decommissioned.
     The expansion of Precision’s Contract Drilling Services segment in the United States began in June 2006 with the deployment of one Super Single™ rig drilling to Texas. Precision deployed a second drilling rig to the United States from Canada in early 2007 which has commenced drilling in Colorado. As conditions warrant, Precision may deploy additional rigs from Canada into the United States market.
     Until early 2005, Precision had an aggressive global growth strategy directed toward the supply of oilfield and industrial services to customers in Canada and internationally. Precision grew through a series of acquisitions of related businesses in 2003 and 2004 and through reinvestment in its core businesses to become one of the largest Canadian based international oilfield and industrial services contractors.
     During 2005, Precision underwent a significant shift in its strategic business direction with its decision to realize the value in the international contract drilling, energy services and industrial services segments of its business. This value was realized through the divestiture of three business lines in the third quarter of 2005: Precision Energy Services which was the technology services group providing cased hole and open hole wireline services, drilling and evaluation services and production services; Precision Drilling International which was an international land rig contractor; and CEDA International which provided industrial cleaning, catalyst handling and mechanical services. The dispositions provided shareholders of Precision with proceeds in the form of a special cash payment of $844 million and almost 26 million shares of Weatherford International Ltd. (“Weatherford”) valued at $2.0 billion.
     Those dispositions returned Precision to its original focus on oil and gas contract drilling, service rig and supplemental business lines in western Canada. The continuing business represents Precision’s core expertise and marks a return to Precision’s original business roots which date back more than 20 years as a publicly traded company and over 50 years in operational experience.
     Over the last three years, significant acquisitions, dispositions and reorganizations consisted of the following:

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Significant Acquisitions
•   On August 17, 2006, Precision acquired Terra, a privately owned wastewater treatment business operating at remote worksite locations for an aggregate purchase price of $16 million. Terra had 41 treatment units at the time of the acquisition and closed the year with 51 treatment units. The service provided by Terra complements those provided by the LRG Catering and Precision Rentals divisions and expands the diversity of services Precision offers customers.
•   On May 21, 2004, Precision acquired all of the land drilling business carried on by GlobalSantaFe Corporation for an aggregate purchase price of US$316.5 million. That land drilling business consisted of 31 drilling rigs, then located in Kuwait, Saudi Arabia, Egypt, Oman and Venezuela.
•   Pursuant to an agreement dated May 8, 2004, Precision purchased all of the issued and outstanding shares of Reeves Oilfield Services Ltd. for an aggregate purchase price of £92.4 million (Great Britain Pounds). Reeves Oilfield Services Ltd. was an international provider of open hole wireline logging services to the oil and natural gas industry and carried out field operations in the western and Appalachian regions of the United States, western Canada, Australia, Great Britain, Colombia, Europe, the Middle East and Africa.
Significant Dispositions
•   On August 31, 2005, Precision sold its Energy Services and International Contract Drilling divisions to Weatherford for a purchase price consisting of 26 million common shares of Weatherford and $1.13 billion cash pursuant to a stock purchase agreement dated June 6, 2005 between Precision and Weatherford (the “Weatherford Sale Agreement”). The Energy Services division of Precision consisted of three main business segments: wireline logging services; drilling and evaluation services; and production services. Wireline services included open hole logging, cased hole logging and completion and slick line services. Drilling and evaluation services included measurement-while-drilling, logging-while-drilling, directional drilling and rotary steerable services. Production services included well testing and controlled pressure drilling (which included under balanced drilling services). Precision’s International Contract Drilling division was comprised of 48 land drilling rigs operating in Kuwait, Saudi Arabia, Oman, Iran, Egypt, India, Mexico and Venezuela.
•   On September 13, 2005, Precision sold 100% of the shares of CEDA International Corporation (“CEDA”) to an investment entity of the Ontario Municipal Employees Retirement System for approximately $274 million pursuant to an agreement dated September 13, 2005 between Precision and 1191678 Alberta Inc. (the “CEDA Sale Agreement”). CEDA was a leading provider of industrial maintenance, turnaround services and other specialized services to various production industries in Canada and the United States. Its main areas of operation included industrial cleaning, catalyst handling and mechanical services usually carried out in large facilities operating in the oil and natural gas, petro-chemical and pulp and paper industries.
Significant Reorganizations
•   On July 31, 2005, Precision Limited Partnership (which carried on Precision’s Canadian contract drilling, service rig and snubbing businesses) completed a re-organization whereby substantially all of the assets of the Precision Drilling and Precision Well Servicing divisions of Precision Limited Partnership were transferred to its wholly-owned subsidiary Precision Drilling Ltd. Precision Limited Partnership also transferred its ownership in LRG Catering Ltd. (Precision’s camp and catering business) to Precision Drilling Ltd.
•   On August 25, 2005, Precision Limited Partnership was dissolved, with its partners Precision Diversified Services Ltd. and Precision being allocated their pro rata share of the net assets of Precision Limited Partnership. Precision Diversified Services Ltd. and Precision transferred those net assets to Live Well Service Ltd.
•   On October 31, 2005, the shareholders of Precision approved the Plan of Arrangement which became effective on November 7, 2005. The Plan of Arrangement resulted in the following:

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  •   the former holders of common shares of Precision received, for each share of Precision they owned, at their option, either a Trust Unit or an Exchangeable Unit, in addition to 0.2089 of a Weatherford share and a special cash payment of $6.83;
 
  •   Precision amalgamated with the following wholly-owned subsidiaries: Columbia Oilfield Supply Ltd., Rostel Industries Ltd., Precision Diversified Services Ltd., LRG Catering Ltd., Precision Rentals Ltd., 1181177 Alberta Ltd. and Precision Drilling Ltd., to form Precision Drilling Corporation;
 
  •   1195309 Alberta ULC, a wholly-owned subsidiary of PDLP, became indebted to PDLP;
 
  •   all of the issued and outstanding options issued pursuant to Precision’s various stock option plans were converted into New Options (as defined in the Plan of Arrangement) which became fully vested and were exercisable up to and including November 22, 2005; and
 
  •   all of the PDLP A Units were issued to the Trust, representing 99.12% of the total number of limited partnership units of PDLP (the “Limited Partnership Units”) outstanding, 0.88% of the Limited Partnership Units represented by Exchangeable Units were issued to certain former shareholders of Precision, and 1194312 Alberta Ltd. (the “General Partner”) became a nominal interest holder in PDLP.
•   On November 23, 2005, Precision amalgamated with 1195309 Alberta ULC to form Precision Drilling Corporation.
•   On January 1, 2006, Precision amalgamated with Live Well Service Ltd.
•   On August 17, 2006, Terra transferred substantially all of its net assets to Terra Water Systems Limited Partnership.
•   On January 1, 2007, Precision amalgamated with Terra.
Cash Flow
     The Trust holds PDLP A Units and PDLP holds a promissory note owing by Precision (the “Promissory Note”). Cash generated from the operations of Precision flow to PDLP in settlement of principal and interest owing on the Promissory Note. The cash payable to PDLP is then available to be paid to the limited partners of PDLP which includes holders of Exchangeable Units and indirectly, the holders of Trust Units.
Cash Distributions on Trust Units
     The Trust’s Board of Trustees adopted a policy of making regular cash distributions on or about the 15th day following the end of each calendar month to Unitholders of record on the last business day of each such calendar month or such other date as determined from time to time by the Board of Trustees. In addition, the Declaration of Trust provides that, an amount equal to net income of the Trust not already paid to holders of Trust Units 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. Please refer to “Certain Canadian Federal Income Tax Considerations — Taxation of the Trust” on pages 46 and 47 of the 2005 Special Meeting Information Circular which are incorporated by reference into this Annual Information Form.
     The Board of Trustees reviews the Trust’s distribution policy from time to time. The actual amount distributed is dependent on various economic factors and distributions are declared at the discretion of the Board of Trustees. The actual cash flow available for distribution to Unitholders is a function of numerous factors, including the Trust’s, PDLP’s and Precision’s financial performance; debt covenants and obligations; working capital requirements; productive capacity maintenance expenditures and expansion capital expenditure requirements for the purchase of property, plant and equipment and number of Trust Units and Exchangeable Units issued and outstanding.

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     As a result of the aforementioned factors, distributions may be reduced or suspended entirely. The market value of the Trust Units may deteriorate if the Trust decreases cash distributions in the future. Refer to the heading “Risk Factors” commencing on page 18 hereof.
     Under the terms of the Declaration of Trust, the Trust is required to make distributions to holders of Trust Units in amounts at least equal to its taxable income. Distributions may be monthly or special and in cash or in Trust Units (“in-kind”) at the discretion of the Board of Trustees. To the extent that additional cash distributions are paid and capital expenditure or investment programs are not adjusted, debt levels may increase. In the event that a distribution in the form of Trust Units is declared, the terms of the Declaration of Trust require that the outstanding units be consolidated immediately subsequent to the distribution. The number of outstanding Trust Units would remain at the number outstanding immediately prior to the unit distribution and an amount equal to the distribution would be allocated to the holders of Trust Units. For greater clarity, holders of Trust Units do not receive additional Trust Units during an “in-kind” issuance and consolidation process.
Payments on Exchangeable Units
     Holders of Exchangeable Units will be entitled to receive, and PDLP will make, subject to applicable law, on each date on which the Board of Trustees declares a distribution on the Trust Units, a loan in respect of each Exchangeable Unit in an amount in cash for each Exchangeable Unit equal to the distribution declared on each Trust Unit; or in the case of a distribution declared on the Trust Units in securities or property other than cash or Trust Units, a loan in the amount equal to the value of such type and amount of securities or property which is the same as, or economically equivalent to, the type and amount of property declared as a distribution on each Trust Unit.
     Any amount loaned in respect of Exchangeable Units pursuant to these distribution entitlements will not constitute a distribution of profits or other compensation by way of income in respect of such Exchangeable Units, rather, will constitute a non-interest bearing loan of the amount thereof, or in the case of property, a loan in the amount equal to the fair market value thereof as determined in good faith by the board of directors of the General Partner, which loan is repayable on the first day of January of the calendar year next following the date of the loan or such earlier date as may be applicable as more particularly described in paragraph 3.7 of Appendix D of the 2005 Special Meeting Information Circular which is incorporated into this Annual Information Form by reference.
     On the date on which the loan is repayable, PDLP will make a distribution in respect of each Exchangeable Unit equal to the amount of the loan outstanding in respect thereof. PDLP will set off and apply the amount of any such distribution payment against the obligation of any holder of Exchangeable Units under any loan outstanding in respect thereof.
     In the event that a distribution in the form of Exchangeable Units is declared the outstanding units will be consolidated immediately subsequent to the distribution. The number of outstanding Exchangeable Units would remain at the number outstanding immediately prior to the unit distribution and an amount equal to the distribution would be allocated to the holders of Exchangeable Units. For greater clarity, holders of Exchangeable Units do not receive additional Exchangeable Units during an “in-kind” issuance and consolidation process.
Distribution Reinvestment Plan
     A distribution reinvestment plan (the “DRIP”) was approved by the Board of Trustees on February 14, 2006. The DRIP was implemented on March 31, 2006 and 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. Unless otherwise announced by the Trust, Unitholders who are not residents of Canada are not eligible to participate, directly or indirectly, in the DRIP. Holders of Class B Limited Partnership Units of PDLP are also not eligible to participate in the DRIP. Generally, no brokerage fees or commissions are payable by participants for the purchase of Trust Units under the DRIP, but holders of Trust Units should make inquiries with their broker, investment dealer or financial institution through which their Trust Units are held as to any policies that may result in any fees or commissions being payable. The Trust has reserved the right to amend, terminate or suspend the DRIP at any time provided that such amendment, termination or suspension does not prejudice the interests of holders of Trust Units. Effective December 18, 2006 the DRIP was suspended indefinitely by the Board of Trustees.

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Details of the DRIP are described more fully in the DRIP document available on the Trust’s website at www.precisiondrilling.com.
Board of Trustees
     Pursuant to the terms of the Declaration of Trust, the Board of Trustees consists of three members who are responsible for supervising the activities and managing the affairs of the Trust.
     The Declaration of Trust provides that, subject to its terms and conditions, the Board of Trustees has full, absolute and exclusive power, control, authority and discretion over the Trust assets and the management of the affairs of the Trust to the same extent as if the Board of Trustees were the sole and absolute legal and beneficial owners of the Trust assets.
     Any one or more of the Board of Trustees may resign upon 30 days written notice to the Trust and may be removed by an ordinary resolution and the vacancy created by such removal may be filled at the same meeting, failing which it may be filled by the affirmative vote of a quorum of the Board of Trustees.
     Trustees are elected at each annual meeting of Unitholders to hold office for a term expiring at the close of the next annual meeting. A quorum of the Board of Trustees is a majority of the Trustees then holding office. A majority of the Trustees may fill a vacancy in the Board of Trustees, except a vacancy resulting from an increase in the number of Trustees or from a failure of the Unitholders to elect the required number of Trustees. In the absence of a quorum of Trustees, or if the vacancy has arisen from a failure of the Unitholders to elect the required number of Trustees, the Board of Trustees will promptly call a special meeting of the Unitholders to fill the vacancy. If the Board of Trustees fails to call that meeting or if there are no Trustees then in office, any Unitholder may call the meeting. Except as otherwise provided in the Declaration of Trust, the Board of Trustees may, between annual meetings of Unitholders, appoint one or more additional Trustees to serve until the next annual meeting of Unitholders, but the number of additional Trustees will not at any time exceed one-third of the number of Trustees who held office at the expiration of the immediately preceding annual meeting of Unitholders.
Administration Agreement
     The Trust and Precision are parties to an administration agreement entered into on November 7, 2005 (the “Administration Agreement”). Under the terms of the Administration Agreement, Precision provides administrative and support services to the Trust including, without limitation, those necessary to:
•   ensure compliance by the Trust with continuous disclosure obligations under applicable securities legislation;
•   provide investor relations services;
•   provide or cause to be provided to Unitholders all information to which Unitholders are entitled under the Declaration of Trust, including relevant information with respect to financial reporting and income taxes;
•   call and hold meetings of Unitholders and distribute required materials, including notices of meetings and information circulars, in respect of all such meetings;
•   assist the Board of Trustees in calculating distributions to Unitholders;
•   ensure compliance with the Trust’s limitations on non-resident ownership, if applicable; and
•   generally provide all other services as may be necessary or as may be requested by the Board of Trustees.

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DESCRIPTION OF THE BUSINESS OF PRECISION
GENERAL
     Precision’s continuing operations are carried out in two segments consisting of Contract Drilling Services and Completion and Production Services. The Contract Drilling Services segment includes land drilling services, camp and catering services, procurement and distribution of oilfield supplies and the manufacture and refurbishment of drilling and service rig equipment. The Completion and Production Services segment includes service rig well completion and workover services, snubbing services, wastewater treatment services and the rental of oilfield surface equipment, tubulars and well control equipment and wellsite accommodations. As at December 31, 2006, Precision had approximately 5,500 employees.
     Precision’s revenue by business segment from continuing operations is illustrated in the following table:
(in thousands CDN$)
                               
Years ended December 31,     2006     2005     2004
                   
Contract Drilling Services
     $ 1,009,821       $ 916,221       $ 727,710  
Completion and Production Services
       441,017         369,667         313,386  
Inter-segment Eliminations
       (13,254 )       (16,709 )       (12,608 )
                   
Total Revenue
     $ 1,437,584       $ 1,269,179       $ 1,028,488  
     In Canada, the economics of oilfield services align with global and regional fundamentals. Important regional drivers include the underlying hydrocarbon make-up of the Western Canada Sedimentary Basin (the “WCSB”) and the existence of an established, competitive and efficient oilfield service infrastructure. Increasingly, natural gas production is driving economics within the WCSB as approximately 70% of new well completions in 2006 targeted natural gas. In general, drilling activity in the WCSB is split between three provinces with approximately 75% in Alberta, 15% in Saskatchewan and 10% in British Columbia. Areas in Canada’s north hold significant promise for the expansion of oil and natural gas services but remain as largely untapped frontier opportunities pending government and community support. The Canadian oilfield service industry dates to the 1940s and has given Canada the means to develop its reserves to meet domestic consumption and to provide export capacity, primarily to the United States. Today Canada is the world’s eighth largest producer of oil and third largest producer of natural gas. Approximately half of Canada’s oil and gas production is exported to the United States.
     The hydrocarbon structures of the WCSB are diverse and conventional sources of oil and natural gas reservoirs exist at a variety of depths which are comparatively shallow by global standards. These conventional sources are accompanied by more costly and challenging unconventional sources associated with oil sands, heavy oil, natural gas in coal (coal bed methane), as well as natural gas in deeper formations. The oil sands deposits in northern Alberta are a world-scale resource with an estimated 179 billion barrels of recoverable reserves which are second only to Saudi Arabia in terms of reserves held by an individual country.
     Precision derives essentially 100% of its revenue from the Canadian market. In 2006 an expansion into the United States drilling market was initiated and is expected to become a larger part of Precision’s operations in the future.

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     Providing oilfield services incorporates three main elements: people, technology and equipment. Attracting, training and retaining qualified employees is a challenge for oilfield services providers. As exploration and production activities are taking place in an ever increasing variety of surface and subsurface conditions, developing technology and building equipment that can withstand increasing physical challenges and operate more efficiently is required to maintain and improve the economics of crude oil and natural gas production. The primary economic risk assumed by oilfield service providers relates to the volatility in activity levels which affect utilization rates, investment in people, technology and equipment and cost controls.
     The economics of oilfield services providers are largely driven by current and expected price of crude oil and natural gas which are determined by supply and demand fundamentals on a global and regional level. Crude oil and natural gas prices have historically been volatile. The upward trend in commodity prices since 2002 peaked for natural gas in December 2005 and for oil in July 2006. Prices for both commodities have retreated since then but remain at reasonably high levels when compared to pricing trends over the past five years.
CONTRACT DRILLING SERVICES
Precision’s Contract Drilling Services segment is comprised of the following divisions:
•   Precision Drilling — 240 drilling rigs — approximately 29% of the Canadian industry;
•   LRG Catering (“LRG”) — 101 drilling camps — approximately 16% of the industry;
•   Rostel Industries (“Rostel”) — capabilities that include engineering, machining, fabrication, component manufacturing and repair services for drilling and service rigs; and
•   Columbia Oilfield Supply (“Columbia”) — capabilities that include centralized procurement, inventory and distribution of consumable supplies,
This segment also includes the operations of the following United States subsidiary:
•   Precision Drilling Oilfield Services, Inc. — one drilling rig was deployed to the United States in 2006 and a second rig arrived in the United States in early 2007.
Precision Drilling
     The Precision Drilling division owns and operates the largest fleet of land drilling rigs in Canada with 240 actively marketed drilling rigs located throughout the WCSB, accounting for approximately 29% of the industry’s fleet of 842 drilling rigs in Canada at December 31, 2006.
     Oil and natural gas well drilling contracts are carried out on a daywork, meterage or turnkey basis. Under daywork contracts, Precision charges the customer a fixed rate per day regardless of the number of days needed to drill the well. In addition, daywork contracts usually provide for a reduced day rate (or a lump sum amount) for mobilization of the rig to the well location and for both assembly and dismantling of the rig. Under daywork contracts, Precision ordinarily bears no part of the costs arising from downhole risks (such as time delays for various reasons, including a stuck or broken drill string or blowouts). Other contracts could provide for payment on a meterage basis, whereby Precision would be paid a fixed charge for each metre drilled regardless of the time

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required or the problems encountered in drilling the well. Some contracts are carried out on a meterage basis to a specified depth and on a daywork basis thereafter. Turnkey contracts contemplate the drilling of a well for a fixed price. Compared to daywork contracts, meterage and turnkey contracts involve a higher degree of risk to Precision and, accordingly, normally provide greater profit or loss potential. Over the last five years, Precision’s contracts have been carried out almost exclusively on a daywork basis.
     Contracts with customers vary in duration from a few days for a single well to multiple year, multiple well drilling programs. Precision’s newly built drilling rigs tend to have a three to five year capital payout contract in place at the time construction commences.
     Precision’s drilling rigs have varying configurations and capabilities which enable Precision to provide services in virtually all areas of drilling activity in the WCSB. Precision’s rigs have drilling depth capacities of up to 6,700 metres. All of Precision’s drilling rigs can be winterized, allowing for operations in the harsh weather conditions faced in the Canadian drilling environment. Conventional rigs are configured to handle either one, two or three joints of range 2 drill pipe at one time and are categorized as singles, doubles or triples based on this capability. As well, Precision has coiled tubing drilling rigs which utilize a single strand of pipe coiled around a reel. As a coil tubing drilling rig drills, the tubing is unwound and as the tubing is rewound onto the reel the bit returns to surface.
     Single, double and coiled tubing rigs are generally used in the shallow drilling market, while triple rigs, which have greater hoisting capacity, are used in deeper exploration and development drilling, usually carried out in western Canada’s foothills and Rocky Mountain regions. Precision’s triple rig fleet includes specialized rigs for deep sour natural gas well drilling and for operating in very cold climates.
     Rounding out Precision’s fleet are Super Single™ rigs, the majority of which have slant capability. The Super Single™ rigs are manufactured by Precision and are equipped with top drive drilling systems, range 3 drill pipe and an automated pipe handling system. Slant drilling involves tilting a rig mast from vertical and is primarily used to drill multiple directional wells from one location. Super Single™ rigs allow for drilling to be carried out on a more cost effective basis than using conventional drilling techniques. Drilling multiple wells from one location for instance, improves the economics of developing shallow hydrocarbon reserves. Additionally, the same technique can allow for the exploitation of reserves located in environmentally sensitive areas or inaccessible locations and can reduce or eliminate the cost of building access roads for multiple drilling locations. Precision believes the Super Single™ rig category will continue to offer significant revenue growth. In addition to conventional wells, Precision’s Super Single™ rigs have been adapted to meet a variety of operational needs such as heavy oil, coal bed methane, tight gas, oil sands production and steam assisted gravity drainage (“SAGD”) projects. These multiple well programs are drilled efficiently from a single pad using a centralized mud system and other innovative rig design features. SAGD techniques are used extensively in the production of heavy oil reserves and in-situ bitumen reserves.
     The Super Single™ Light is a smaller capacity, specialized version of the Super Single™. These rigs have been built for drilling shallow wells up to 1,200 metres in depth. Using range 3 drill pipe, the design incorporates proven technology and reliability in a light weight, easily moved load configuration. The Super Single™ Light competes with coiled tubing rigs and offers greater drilling capability over a wider range of well configurations than coiled tubing rigs.
     To facilitate customer requirements Precision also owns 16 mobile top drives. A top drive is used to rotate the drill string and provides greater efficiency in the drilling of a well compared to the traditional rotary table and kelly. A top drive is suspended in the mast of the drilling rig and is powered by a hydraulic or electric motor.
     Precision continually seeks to upgrade and modify its rig fleet to maximize performance. Precision works hard to remain abreast of, and in many cases, lead advances in specialized drilling techniques and technology in order to maximize rig efficiency and minimize environmental impact. A total of 51 of Precision’s drilling rigs are diesel-electric powered, with the remaining rigs mechanically powered. Diesel-electric powered rigs provide more precise control of drilling components and are considered more power efficient than mechanical rigs and are well suited for horizontal and directional drilling. Many of Precision’s mechanically powered rigs are also capable of

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horizontal and directional drilling by reconfiguring the rigs with additional equipment which Precision has readily available.
     The following table lists the drilling depth capabilities of Precision’s drilling rigs and the total Canadian land drilling industry’s rigs in the WCSB as at December 31, 2006:
                                                                       
                Precision Fleet     Industry Fleet (1)
                                           
      Maximum     Number     % of     Market     Number     % of      
Type of Drilling Rig     Depth Rating     of Rigs     Total     Share % (3)     of Rigs     Total     Change (4)
                                           
Single
       1,200m         14         6         10         145         17         21  
Super Single™ (2)
       3,000m         28         12         85         33         4         9  
Double
       3,000m         94         39         26         364         43         20  
Light triple
       3,600m         44         18         38         117         14         3  
Heavy triple
       6,700m         49         20         42         118         14         11  
Coiled tubing
       1,500m         11         5         17         65         8         8  
                                           
TOTAL
                 240         100 %       29 %       842         100 %       72  
                                           
NOTES:
(1)   Source: Daily Oil Bulletin — Rig Locator Report as of January 2007. Precision has allocated the industry rig fleet by rig type.
(2)   Super Single™ excludes single rigs that do not have automated pipe handling systems, do not have a self contained top drive, or cannot run range 3 drill pipe/casing.
(3)   Market share means Precision’s rigs as a percentage of the industry’s rigs.
 
(4)   Change in number of industry rigs as compared to the prior year.
     There were 72 new drilling rigs added to the Canadian industry fleet during 2006, a 9% increase over 2005. Customer demand to drill conventional oil and natural gas wells, in combination with improving commercialization of coal bed methane, oil sands, heavy oil and deeper natural gas formations had driven demand for rigs to record levels but the slowdown in drilling activity in the second half of 2006 pushed utilization rates for rigs lower.
     Precision has a balanced drilling rig offering, with a particular weighting in deep drilling. As customers turn to deeper wells to discover new reserves, Precision’s 42% market share in rigs with a depth capacity greater than 3,600 metres is noteworthy.
     The following table lists the drilling rig utilization rates and certain other drilling statistics for Precision compared to the total land drilling industry in the WCSB for the years indicated:
                                                                                 
      Utilization Rates (%)     Metres Drilled (000s)     Wells Drilled(1)
                                                 
                                              % of                         % of
      Precision     Industry(2)     Precision     Industry(2)     Industry     Precision     Industry(2)     Industry
                                                 
2006
       52.1         55.1         7,810         27,373         28.5         6,180         22,575         27.4  
2005
       56.1         59.6         8,901         28,143         31.6         7,766         24,351         31.9  
2004
       50.3         52.9         8,021         23,526         34.1         7,525         21,793         34.5  
2003
       52.0         53.1         8,604         21,802         39.5         8,451         20,694         40.8  
2002
       38.3         39.4         6,222         15,708         39.6         6,315         14,920         42.3  
                                                 
NOTES:
(1)   The number of wells drilled is reported on a rig release basis, compiled by Precision.
 
(2)   Industry numbers exclude drilling rigs not registered with the Canadian Association of Oilwell Drilling Contractors (“CAODC”) and non-reporting CAODC member contractors.
     Precision has consistently been the most active land drilling contractor in Canada in terms of wells and metres drilled, sustaining, since 1997, a market share of greater than approximately 29% of the industry in Canada. During 2006, Precision achieved a utilization rate of 52% for its drilling rigs compared to the average industry

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utilization rate in Canada of 55%. Precision strives to obtain high utilization of its fleet and optimal profitability given competitive pricing and Canada’s seasonal reduction in drilling demand during the second and third quarters.
     In 2006, Precision drilled 6,180 exploration and development wells, accounting for 27% of industry wells drilled in western Canada.
     Precision’s fleet can drill virtually all types of on-shore conventional and unconventional oil and gas deposits in North America. It is particularly adept in developing unconventional resources such as oil sands, coalbed methane or tight gas. The increase in drilling-intensive unconventional “resource plays” is creating opportunities for technically innovative and operationally efficient drillers like Precision.
     The drilling industry in Canada requires specialized skill and knowledge which, due to increased utilization levels over the past decade, has been in short supply. A drilling rig crew is comprised of a rig manager, driller, derrickman, motorman, floor hands and lease hands. The traditional rig crewing configuration is three crews working rotating shifts, two weeks in and one week out, allowing the rig to keep working with one crew off. The floor and lease hand positions are entry level, with the motorman, derrickman and driller positions being more advanced. Each position has certain prerequisite qualifications and training. Well control, H2S, first aid, fall protection, work place hazardous materials and various aspects of Precision’s health, safety and environment management systems are all key training components.
     The provision of an experienced competent crew is a competitive strength, highly valued by Precision’s customers. In order to continually recruit rig employees, Precision has a centralized personnel department and orientation program. In 2006, there were approximately 1,900 candidates given pre-employment rig orientation training. Precision is also active as a member of the Canadian Association of Oilwell Drilling Contractors (the “CAODC”) in implementing a designated trade certification for drilling rig workers in Alberta, the first jurisdiction to recognize the specialized skill and knowledge that a driller must possess.
     The shortage of labour in the oilfield service industry in recent years eased with the decline in activity in the second half of 2006, but human resource issues are expected to remain a priority for the industry for the foreseeable future. For Precision, emphasis is placed on retention of experienced employees in derrickman, driller and rig manager positions. A shortage occurs in high activity periods when most of the rig fleet is working. The service industry loses experienced employees to customers, competitors, other oilfield businesses and to other industries due to the cyclical nature of the work and the resulting uncertainty of continuing employment. During 2006, Precision focused on the retention of existing employees through initiatives that provide a safe and productive work environment, opportunity for advancement and added wage security through programs such as our Designated Driller Program.
     Precision’s ability to work an entire fleet of rigs, given Canadian seasonality, arises from its ability to retain experienced employees in low activity periods, orientate new employees and effectively administer personnel and payroll functions.
Precision Drilling Oilfield Services, Inc.
     Precision Drilling Oilfield Services, Inc. began operations in the United States in June 2006 with one rig operating in Texas. The Super Single TM rig deployed to Texas under contract operated throughout the remainder of the year given that the United States market does not typically experience the same seasonality as in Canada. The primary focus for Precision in the United States market is to provide drilling services to larger exploration and production companies that Precision has had long-term relationships with and that are primarily targeting unconventional natural gas.
     A second rig was deployed to Colorado in early 2007 and Precision currently plans to deliver a total of five new drilling rigs to the United States in 2007 and early 2008. Precision is exploring growth opportunities and as conditions warrant, may deploy additional rigs from Canada into this market. There were approximately 2,300 rigs operating in the United States land market at the end of 2006.

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LRG Catering
     LRG provides food and accommodation to personnel working at the well site, typically in remote locations in western Canada. LRG has 101 conventional and base camps, representing approximately 16% of the camp and catering business in western Canada. LRG’s mobile camps include five or six units and can accommodate 20 to 25 crew members. It can also provide food service for all of the field workers on a location. LRG also has the ability to configure several of its camps and dormitories on a single site to create a base camp for major projects which can house as many as 200 workers and provide up to 1,000 meals a day. As the oil and gas industry in western Canada moves to more remote locations in search of new reserves there is increasing demand for crews to stay near the wellsite throughout the drilling of a well. LRG serves Precision and other companies in the upstream oil and gas sector and periodically secures opportunities to serve other industries that operate in remote locations.
Rostel Industries
     Rostel Industries manufactures and refurbishes custom drilling rig and service rig components. This uniquely positions Precision with in-house rig manufacturing capability. Approximately 70% of Rostel’s activities support Precision business units. The ability to repair or provide new components for either drilling or service rigs in-house improves the efficiency and reliability of Precision’s fleet. In addition to quality construction and repair services, Rostel sustains high plant utilization by providing specialized services, including inspection and certification of critical drilling components such as overhead equipment, well control equipment and handling tools. Rostel’s expertise includes an in-house engineering group as well as an equipment sales group that specializes in the distribution of mud pumps and other imported products. Strategically, Rostel gives Precision the ability to set its own priorities in controlling the work performed on its equipment. Precision has direct control over scheduling and sets delivery objectives that meet customer requirements. Rostel designs and builds over 50% of the components for Precision’s Super Single™ drilling rigs and is developing a new AC-powered top drive that can be applied to new rigs and retro-fitted to improve the versatility of many of Precision’s existing rigs.
Columbia Oilfield Supply
     Columbia Oilfield Supply is a general supply store that procures, packages and distributes large volumes of consumable oilfield supplies for the contract drilling and well servicing industry. Approximately 90% of Columbia’s activities support Precision operations and it plays a key role in supply chain management for the company. Columbia’s key strengths, which contribute to Precision’s competitiveness, are in inventory management, demand anticipation and distribution. Precision and its customers also benefit from Columbia’s purchasing power, standardized product selection, streamlined business processes and coordinated distribution. Strategically, Columbia gives Precision the ability to set its own service level priorities and to standardize products used on its equipment. Through Columbia, Precision has direct control over supply distribution to field destinations which enhances its reliability in the execution of its operations.
COMPLETION AND PRODUCTION SERVICES
Precision’s Completion and Production Services segment is comprised of the following divisions:
•   Precision Well Servicing (“PWS”) — 237 service rigs — approximately 23% of the industry;
 
•   Live Well Service (“Live Well”) — 26 snubbing units — approximately 30% of the industry;
 
•   Precision Rentals — approximately 15,000 pieces of rental equipment items including well-control equipment, surface equipment, specialty tubulars and wellsite accommodation units — approximately 10% of the industry; and
 
•   Terra Water Systems Limited Partnership (“Terra Water”) — is a wastewater treatment business suited for oilfield camps and wellsite accommodation units in remote locations. It operates 51 wastewater treatment units for the traditional drilling rig camp market in western Canada — approximately 10% of the industry

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Precision Well Servicing
     The Precision Well Servicing division is Canada’s largest service rig contractor, providing customers with a complete range of oil and natural gas well services — completions, workovers, abandonments, well maintenance, high pressure and critical sour well work and re-entry preparation. Precision’s service rig fleet completes all types of new wells and works over existing wells to optimize customers’ oil and natural gas production. The configuration of Precision’s Well Servicing fleet is illustrated in the following table:
                               
TYPE OF SERVICE RIG     2006     2005     2004
                   
Singles:
                              
Mobile single
       12         17         19  
Freestanding mobile
       92         88         86  
Doubles:
                              
Mobile
       44         44         42  
Freestanding mobile
       9         8         9  
Skid
       65         65         67  
Slants:
                              
Freestanding
       15         15         16  
                   
TOTAL FLEET
       237         237         239  
     In 2006, PWS maintained an industry market share of almost 23% based on an average registered CAODC industry fleet of approximately 1,050 service rigs in western Canada. PWS continued to upgrade its fleet through initiatives that included freestanding conversions and new five ton transporters along with new pump trucks, engines, combination trailers and mud pumps. As at December 31, 2006, PWS had 116 freestanding service rigs representing 49% of its service rig fleet. A freestanding rig is more efficient to set up, minimizes surface disturbance and, as there is no need for anchors, reduces the possibility of striking underground utilities. However, a majority of the mobile double rigs are not freestanding as the additional weight to convert them would limit movement during restricted road use periods. Skid double rigs are ideal for deeper natural gas wells which require multi-zone completion or re-completion. This type of work usually has the service rig working for a greater length of time so the rig does not need to be moved as often. They also include additional equipment such as circulating pumps, tanks, blowout preventers and tools.
     Service rigs are typically used during the completion phase of a well, instead of larger, more expensive drilling rigs, in order to reduce the cost of completing the well. The demand for well completion services is related to the level of drilling activity in a region whereas the demand for production or workover services is based upon the total number of active wells, their age and their producing characteristics. Consequently, demand for completion services is generally more volatile than workover services. Completion services accounted for 38% of PWS’s well servicing activity in 2006, as compared to 41% in 2005.
     A service rig crew has four members (driller, derrickman and two floor hands) in addition to the rig manager. Jobs are typically shorter in well servicing so the ability of a service rig to move quickly from one site to another is critical. In general, well servicing is conducted during daylight hours to co-ordinate activities of a number of service providers. PWS typically charges its customers an hourly rate for its services based on a number of considerations including market demand in the region, the type of rig and complement of equipment required.
     Completion services prepare a newly drilled well for production and may involve cleaning out the well bore, and the installation of production tubing, downhole equipment and wellheads. Service rigs work jointly with other services to perforate the well bore to open the producing zones and stimulate the producing zones to improve productivity. The well completion process may take one day to many weeks to complete and PWS provides a service rig to assist during most or all of this process.

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     Workover services are generally provided according to preventative maintenance schedules or on a call-out basis when a well needs major repairs or modifications. This can involve operations similar to those conducted during the initial completion of a well. Workovers may also involve restoring or enhancing production in an existing producing zone, changing to a new producing zone, converting the well for use as an injection well for enhanced recovery operations or plugging and abandoning the well. Workover services also include major subsurface repairs such as casing repair or replacement, recovery of tubing and removal of foreign objects from the well bore, such as lost tools. Workover activities may require a few days to several weeks to complete. During this time PWS may work alongside other oilfield services providers on the well location while other services are being directed by its customer.
     Well maintenance services are often required to ensure continuous and efficient operation of producing wells. These services include routine mechanical repairs such as repairing broken pumping equipment in an oil well or replacing damaged rods and tubing. A typical gas well in western Canada is likely to require one or two workovers during its operating life compared with four or five workovers for conventional oil wells. Wells for some heavy oil and bitumen production could require many workovers over their life cycle. Well maintenance activities may require a few hours to several days to complete. While workover and maintenance activities are not directly linked to drilling activities, they are influenced by both the short-term and long-term outlooks for oil and natural gas prices as well as reservoir depletion. Furthermore, an increase in drilling activity leads to more producing wells that require workover and maintenance services in future years.
     As there are close to 190,000 producing wells in western Canada that are potential candidates for workovers and 15,000 to 20,000 new wells drilled each year that must be completed and maintained, well servicing has growth potential for Precision.
Live Well Service
     Live Well Service markets 25 portable hydraulic rig assist snubbing units and one stand alone unit in western Canada. Snubbing units are equipped with specialized pressure control devices which allow tubing to be pushed (snubbed) in and out of a well bore while a well is under pressure and production has been suspended.
     Traditional well servicing operations require the pressure in a well to be neutralized or killed, prior to performing such operations so they can be conducted safely. Some reservoirs can be damaged if a well is killed prior to workover operations, as the fluids used in the process may cause the flow characteristics of the reservoir to be impaired. Consequently, snubbing units have been developed to perform certain workover and completion activities without killing the well.
     A rig assist snubbing unit requires a rig to be on location to hoist it into place. Live Well’s proprietary stand alone snubbing unit does not require a rig to be on the well location. It is designed to be self-sufficient with automated tubular handling and numerous control features to enhance safe, cost effective snubbing operations.
     The trend toward more natural gas well drilling and low pressure production in the WCSB has had a positive effect on demand for Live Well’s services. Snubbing is primarily performed on gas wells in western Canada and the process enables customers to increase or maintain well production rates and to help maximize recoverable reserves.
Precision Rentals
     Precision Rentals is a provider of oilfield rental equipment with operating centres and stocking points located throughout western Canada. Most exploration and production companies do not own the specialty equipment used in oil and gas operations and equipment offered by Precision Rentals covers a range of customer needs throughout the drilling, completion and production process.
     Precision Rentals has an inventory of approximately 15,000 pieces of equipment that is marketed through three product categories: surface equipment; tubulars and well control equipment; and wellsite accommodation

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units. Precision Rentals has five operating centres and 14 stock points in the WCSB and a technical support centre in Nisku, Alberta.
     Surface equipment includes 3,700 drilling and production tanks and other equipment primarily associated with fluid handling. Tubular equipment includes 10,000 joints of specialty-sized drill pipe and collars. Well-control equipment includes 1,100 handling tools and equipment such as blowout preventers and diverter systems. The 315 fully equipped accommodation units provide offices and lodging for senior personnel and are built with heavy-duty skids to facilitate frequent moves.
     Precision Rentals also supplies the patented Vapour Tight Oil Battery™, which allows for single well production of oil with H2S content through the use of a 500-barrel vessel with gas metering and flaring capabilities.
Terra Water
     Precision acquired a complementary business line within the oilfield service sector with the acquisition of Terra Water Group Ltd on August 17, 2006. On August 17, 2006, Terra transferred substantially all of its net assets to Terra Water. Terra Water’s principal role is as provider of portable on-site wastewater handling, treatment, and disposal expertise within the remote worksite environment. Terra Water’s equipment focuses on reducing environmental impacts from wastewater generated on site.
     Terra Water’s treatment units are designed and manufactured in-house. There are numerous small-scale operators in this emerging sector but it is estimated Terra Water’s 51 portable units comprise approximately 10% of the industry within the remote work site market in western Canada.
RISK FACTORS
THE TRUST
     An investment in the Trust Units and Exchangeable Units involves a number of risks including those set forth below.
Nature of Trust Units
     The Trust Units do not represent a traditional investment in the oil and natural gas services business and should not be viewed as shares of Precision. The Trust Units represent a fractional interest in the Trust. Holders of Trust Units do not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions. The Trust’s sole assets are the shares of the General Partner, the PDLP A Units and other investments in securities. The price per Trust Unit is a function of anticipated net earnings, distributable cash, the underlying assets of the Trust and management’s ability to effect long-term growth in the value of Precision and other entities now or hereafter owned directly or indirectly by the Trust. The market price of the Trust Units are sensitive to a variety of market conditions including, but not limited to, interest rates, the growth of the general economy, the price of crude oil and natural gas and changes in law. Changes in market conditions may adversely affect the trading price of the Trust Units.
     The Trust Units are not “deposits” within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that act or any other legislation. Furthermore, the Trust is not a trust company and, accordingly, is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company.
The Trust is Dependent on Precision for All Cash Available for Distributions
     The Trust is dependent on the operations and assets of Precision through its interest in PDLP, which in turn owns 100% of the shares of Precision and the Promissory Note. Distributions to the holders of Trust Units and Exchangeable Units are dependent on the ability of Precision to make principal and interest payments on the Promissory Note, dividends and return of capital payments. The actual amount of cash available for distribution is dependent upon numerous factors relating to the business of Precision including profitability, changes in revenue,

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fluctuations in working capital, capital expenditure levels, applicable laws, compliance with contracts, contractual restrictions contained in the instruments governing its indebtedness, the impact of interest rates, the growth of the general economy, the price of crude oil and natural gas, changes to tax laws, weather, future capital requirements and the number of Trust Units and Exchangeable Units issued and outstanding and potential tax liabilities resulting from any successful reassessments of prior taxation years by taxation authorities.
     Any reduction in the amount of cash available for distribution, or actually distributed, by Precision will reduce or suspend entirely the amount of cash available for distributions to the holders of Trust Units and Exchangeable Units. The market value of the Trust Units may deteriorate if the Trust is unable to meet distribution expectations in the future, and such deterioration may be material.
Possible Restriction on Growth
     The payout of substantially all of Precision’s operating cash flow will make capital and operating expenditures dependent on increased cash flow or additional financing in the future. The lack of these funds could limit Precision’s future growth and cash flow which in turn may affect the amount of distributions. In addition, Precision may be precluded from pursuing acquisitions or investments which may not be accretive on a short-term basis. Proposed rules on undue expansion were clarified by the Government of Canada in 2006 with the result being that Precision can grow its equity by approximately $4.0 billion dollars over the four year transition period before triggering the proposed new tax.
Potential Sales of Additional Trust Units
     The Trust may issue additional Trust Units in the future to directly or indirectly fund capital expenditure requirements of Precision and other entities now or hereafter owned directly or indirectly by the Trust, including to finance acquisitions by those entities. Such additional Trust Units may be issued without the approval of Unitholders. Unitholders have no pre-emptive rights in connection with such additional issues. The Board of Trustees have discretion in connection with the price and the other terms of the issue of such additional Trust Units.
Nature of Distributions
     Unlike interest payments on an interest-bearing security, distributions by income trusts on trust units (including those of the Trust) are, for Canadian tax purposes, composed of different types of payments (portions of which may be fully or partially taxable or may constitute non-taxable “returns of capital”). The composition for tax purposes of those cash distributions may change over time, thus affecting the after-tax return to holders of Trust Units. Therefore, the rate of return for holder’s of Trust Units over a defined period may not be comparable to the rate of return on a fixed-income security that provides a return on capital over the same period. This is because a holder of Trust Units may receive distributions that constitute a return of capital (rather than a return on capital) to some extent during the relevant period. Returns on capital are generally taxed as ordinary income, dividends or taxable capital gains in the hands of a holder of Trust Units, while returns of capital are generally non-taxable to a holder of Trust Units (but reduce the adjusted cost base in a Trust Unit for tax purposes).
Issuance of Additional Trust Units
     The Declaration of Trust provides that an amount equal to the taxable income of the Trust will be payable each year to holders of Trust Units in order to reduce the Trust’s taxable income to zero. Where in a particular year, the Trust does not have sufficient cash to distribute such an amount, the Declaration of Trust provides that additional Trust Units may be distributed in lieu of cash payments. Holders of Trust Units will generally be required to include an amount equal to the fair market value of those Trust Units in their taxable income, notwithstanding that they do not directly receive a cash payment. See “Certain Canadian Federal Income Tax Considerations — Taxation of Trust Unitholders” on pages 47 and 48 of the 2005 Special Meeting Information Circular which are incorporated by reference into this Annual Information Form. See “General Development of the Business — Cash Distributions on Trust Units” for a description of the ability to consolidate Trust Units upon the distribution of Trust Units in lieu of the payment of a cash distribution.

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Variability of Distributions
     The actual cash flow available for distribution to Unitholders is a function of numerous factors including the Trust’s, PDLP’s and Precision’s financial performance; debt covenants and obligations; working capital requirements; future productive capacity maintenance expenditures and future expansion capital expenditure requirements for the purchase of property, plant and equipment; tax obligations; the impact of interest rates, the growth of the general economy; the price of crude oil and natural gas; weather; and number of Trust Units and Exchangeable Units issued and outstanding. Distributions may be reduced or suspended entirely depending on Precision’s operations and the performance of its assets. The market value of the Trust Units may deteriorate if the Trust is unable to meet distribution expectations in the future, and that deterioration may be material.
Changes in Legislation
     There can be no assurance that income tax laws, such as the status of mutual fund trusts, or the taxation of mutual fund trusts, will not be changed in a manner which adversely affects holders of Trust Units.
     Environmental and applicable operating legislation may be changed in a manner which adversely affects holders of Trust Units.
Investment Eligibility
     If the Trust ceases to qualify as a mutual fund trust, the Trust Units will cease to be qualified investments for registered retirement savings plans, registered retirement income funds and deferred profit sharing plans (“Exempt Plans”) which will have adverse tax consequences to Exempt Plans or their annuitants or beneficiaries. The Income Tax Act (Canada) (the “Tax Act”) imposes penalties or other tax consequences for the acquisition or holding of non-qualified investments.
Risks Associated with Trust Units for Non-Resident Holders of Trust Units
     For non-resident holders of Trust Units, there are certain risks associated with holding Trust Units. Non-resident holders of Trust Units should consult their tax advisors with respect to the tax implications of holding Trust Units, including any associated filing requirements in their particular tax jurisdiction. Except as provided under the heading “Certain United States Federal Income Tax Considerations” on pages 51 to 54 of the 2005 Special Meeting Information Circular which are incorporated into this Annual Information Form by reference, neither the Trust nor Precision is providing any representations as to the tax consequences to non-residents of holding Trust Units.
Qualified Dividend Treatment for Individual U.S. Holders of Trust Units
     The Trust expects that distributions it makes to individual U.S. holders of Trust Units that are treated as dividends for U.S. federal income tax purposes will be treated as qualified dividend income eligible for the reduced maximum rate to individuals of 15% (5% for individuals in lower tax brackets). However, if the Trust does not constitute a “qualified foreign corporation” for U.S. federal income tax purposes, and as a result such dividends to individual U.S. holders of Trust Units do not qualify for this reduced maximum rate, such holders will be subject to tax on such dividends at ordinary income rates (currently at a maximum rate of 35%). In addition, under current law, the preferential tax rate for qualified dividend income will not be available for taxable years beginning after December 31, 2010. Neither the Trust nor Precision is providing any representation as to the U.S. tax consequences of holding Trust Units.
Distribution of Assets on Redemption or Termination of the Trust
     It is anticipated that a redemption right will not be the primary mechanism for holders of Trust Units to liquidate their investment. Securities which may be received as a result of a redemption of Trust Units will not be listed on any stock exchange and no market for such securities is expected to develop. The securities so distributed may not be qualified investments for Exempt Plans, depending upon the circumstances existing at that time. On termination of the Trust, the Board of Trustees may distribute the securities directly to holders of Trust Units,

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subject to obtaining all of the necessary regulatory approvals. In addition, there may be resale restrictions imposed by applicable law upon the recipients of securities pursuant to a redemption right.
Debt Service
     Precision and its affiliates may, from time to time, finance a significant portion of their growth (either from acquisitions or capital expenditure additions) through debt. Amounts paid in respect of interest and principal on debt incurred by Precision and its affiliates may impair Precision’s ability to satisfy its obligations under its debt instrument(s). Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to service debt before payment of inter-entity debt. This may result in lower levels of cash for distribution by the Trust. Ultimately, subordination agreements or other debt obligations could preclude distributions altogether.
Taxation of the Trust
     There can be no assurances that Canadian federal income tax laws and administrative policies respecting the treatment of mutual fund trusts will not be changed in a manner which adversely affects the holders of Trust Units. For example, if the Trust ceases to qualify as a “mutual fund trust” under the Tax Act, the income tax considerations described under the heading “Certain Canadian Federal Income Tax Considerations — Taxation of Trust Unitholders” on pages 47 and 48 of the 2005 Special Meeting Information Circular which are incorporated by reference into this Annual Information Form, would be materially and adversely different in certain respects.
     Currently, under a disqualification rule contained in the Tax Act, a trust will not be considered to be a mutual fund trust if it is established or is maintained primarily for the benefit of non-residents of Canada for the purposes of the Tax Act, unless all or substantially all of its property is property other than “taxable Canadian property” as defined in the Tax Act. In an effort to allow the Trust to assert that the foregoing disqualification rule is inapplicable on the basis that the Trust is not now and has never been established or maintained primarily for the benefit of non-residents of Canada, the Declaration of Trust restricts and provides mechanisms to limit the number of Trust Units held by non-residents of Canada and non-Canadian partnerships. Moreover, as a second reason to allow the Trust to assert that the foregoing disqualification rule does not apply to the Trust, the assets of the Trust have been structured to allow the Trust to assert that all or substantially all of its property is property other than “Taxable Canadian property” as defined in the Tax Act.
     On September 16, 2004, the Minister of Finance (Canada) released draft amendments to the Tax Act including draft amendments providing that a trust will lose its status as a mutual fund trust if the aggregate fair market value of all units issued by the trust held by one or more non-residents of Canada or partnerships that are not “Canadian partnerships” (as defined in the Tax Act) is more than 50% of the aggregate fair market value of all the units issued by the trust where more than 10% (based on fair market value) of the trust’s property is certain types of “taxable Canadian property” or certain other types of property. If the draft amendments are enacted as proposed, and if, at any time, more than 50% of the aggregate fair market value of the Trust Units are held by non-residents of Canada and non-Canadian partnerships, the Trust may thereafter cease to be a mutual fund trust. The draft amendments do not currently provide any means of rectifying a loss of mutual fund trust status. On December 6, 2004, the Minister of Finance (Canada) tabled a Notice of Ways and Means Motion to implement certain measures proposed in the September 16, 2004 draft amendments. However, such notice did not include the proposal concerning mutual fund trusts maintained primarily for the benefit of non-residents of Canada. In addition, the Minister of Finance (Canada) announced on December 6, 2004 as well as in the 2005 Budget Proposals that further discussions would be pursued with the private sector in this respect.
     On September 8, 2005, the Department of Finance (Canada) released a consultation paper and launched public consultations on tax and other issues related to flow-through entities (“FTEs”). The focus of the paper was to, among other things, assess whether the tax system should be modified. In the consultation paper, the Department of Finance identified three possible policy responses to issues relating to FTEs: (i) limiting deductibility of interest expense by operating entities, (ii) taxing FTEs in a manner similar to corporations, or (iii) making the income tax system more neutral with respect to all forms of business organization by better integrating the personal and corporate income tax system. On November 23, 2005, the Department of Finance announced that the consultation process was finished and tabled in the House of Commons a Notice of Ways and Means Motion to implement a

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reduction in personal income tax on dividends with a view to establishing a better balance between the integrated tax treatment of large corporations and that of income trusts. No measures were announced with respect to the taxation of FTEs and their investors.
     On October 31, 2006, the Government of Canada announced a Tax Fairness Plan containing its intentions to bring about new tax measures including “a Distribution Tax on distributions from publicly traded income trusts and limited partnerships.” The government is proposing a four-year transition period for existing income trusts and limited partnerships whereby the new measures will not apply until their 2011 taxation year. Under the proposal, “flow-through entities” will be taxed more like corporations and their investors will be treated more like shareholders. The proposed new tax measures will impair the flow-through nature of Precision Drilling Trust’s current tax structure. If enacted into law, these tax measures would result in a distribution tax to the Trust which will reduce the cash distributed to Unitholders by the amount of distribution tax paid.
     If the proposed measures are enacted into law, effective January 1, 2011, the current underlying flow-through status of the Trust’s current income trust structure will be ended. The proposed amendments have negative implications for certain unitholders of the Trust and PDLP commencing in 2011, particularly Canadian tax-exempt investors, foreign investors and tax-exempt entities.
     The Declaration of Trust restricts and provides mechanisms to limit the number of Trust Units held by non-residents of Canada and non-Canadian partnerships such that the Trust expects that the existing imposed non-resident ownership limitations set out in the Tax Act, discussed above, will be satisfied. In an effort to support the assertion that the Trust qualifies as a “mutual fund trust” under the Tax Act and in an effort to support the assertion that the maintenance of such status the Declaration of Trust provides, in part, that:
(a) if determined necessary or desirable by the Trustees, in their sole discretion, the Trust may, from time to time, among other things, take all necessary steps to monitor the activities of the Trust and ownership of the Trust Units. If at any time the Trust or the Trustees become aware that the activities of the Trust and/or ownership of the Trust Units by non-residents may threaten the status of the Trust under the Tax Act as a “unit trust” or a “mutual fund trust”, the Trust, by or through the Trustees on the Trust’s behalf, is authorized to take such action as may be necessary in the opinion of the Trustees to maintain the status of the Trust as a “unit trust” or a “mutual fund trust” including, without limitation, the imposition of restrictions on the issuance by the Trust of Trust Units or the transfer by any Unitholder of Trust Units to a non-resident and/or require the sale of Trust Units by non-residents on a basis determined by the Trustees and/or suspend distribution and/or other rights in respect of Trust Units held by non-residents transferred contrary to the foregoing provisions or not sold in accordance with the requirements thereof; and
(b) in addition to the foregoing, the transfer agent of Trust Units, by or through the Trustees may, if determined appropriate by the Trustees, establish operating procedures for, and maintain, a reservation system which may limit the number of Trust Units that non-residents may hold, limit the transfer of the legal or beneficial interest in any Trust Units to non-residents unless selected through a process determined appropriate by the Trustees, which may either be a random selection process or a selection process based on the first to register, or such other basis as determined by the Trustees. The operating procedures relating to such reservation system shall be determined by the Trustees and, prior to implementation, the Trust shall publicly announce the implementation of the same. Such operating procedures may, among other things, provide that any transfer of a legal or beneficial interest in any Trust Units contrary to the provisions of such reservation system may not be recognized by the Trust.
Taxation of Precision
     Income fund structures often involve significant amounts of inter-entity debt, which may generate substantial interest expense, which serves to reduce earnings and therefore income tax payable. The Board of Trustees expects this to be the case in respect of Precision and its interest expense on the Promissory Note. There can be no assurance that the taxation authorities will not seek to challenge the amount of interest expense deducted. If such a challenge were to succeed against Precision, it could have a materially adverse affect on the amount of distributable cash available.

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Net Asset Value
     The net asset value of the assets of the Trust from time to time will vary depending upon factors which are beyond the control of Precision. The trading price of the Trust Units also fluctuates due to factors beyond the control of Precision and such trading prices may be greater than the net asset value of the Trust’s assets.
Residual Liability of Precision
     Precision, the successor entity to amalgamations involving its predecessor companies, has retained all liabilities of its predecessor companies, including liabilities relating to corporate and income tax matters.
Unitholder Limited Liability
     The Declaration of Trust provides that no holder of Trust Units will be subject to any liability in connection with the Trust or its obligations and affairs and, in the event that a court determines that holders of Trust Units are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of the Trust’s assets. Pursuant to the Declaration of Trust, the Trust will indemnify and hold harmless each holder of Trust Units from any costs, damages, liabilities, expenses, charges and losses suffered by a holder resulting from or arising out of such holder not having such limited liability. The Declaration of Trust provides that all written instruments signed by or on behalf of the Trust must contain a provision to the effect that obligations under those instruments will not be binding upon holders of Trust Units personally. Personal liability may however arise in respect of claims against the Trust that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability of this nature arising is considered unlikely. The Income Trusts Liability Act (Alberta) came into force on July 1, 2004. The legislation provides that a holder of Trust Units will not be, as a beneficiary, liable for any act, default, obligation or liability of the Trustee(s) that arises after the legislation came into force. However, this legislation has not yet been ruled upon by the Courts. The operations of the Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability to the holders of Trust Units for claims against the Trust, including by obtaining appropriate insurance, where available and to the extent commercially feasible.
Deductibility of Expenses
     Although the Trustees, the General Partner of PDLP and management of Precision are of the view that substantially all of the expenses claimed by the Trust, PDLP and Precision, respectively, will be reasonable and deductible, there can be no assurance that the taxation authorities will agree. If the taxation authorities successfully challenge the deductibility of any such expenses, the return to holders of Trust Units may be adversely affected.
Precision Drilling Limited Partnership
     The risks applicable to holders of Exchangeable Units are similar to those for holders of Trust Units, as Exchangeable Units are the voting and economic equivalent of the Trust Units. For a discussion of such risks, refer to the heading “Risk Factors — The Trust” commencing on page 18 hereof.
Risks Associated with Exchangeable Units
     None of the Trust, PDLP or Precision is providing any representations as to the tax consequences of holding Exchangeable Units.
Indemnity of Limited Partners
     While the General Partner has agreed pursuant to the terms of the Limited Partnership Agreement of PDLP, to indemnify PDLP’s limited partners, including holders of the Class A Limited Partnership Units and the Exchangeable Units, the General Partner may not have sufficient assets to honour the indemnity.

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RISKS RELATING TO THE BUSINESS CURRENTLY CONDUCTED BY PRECISION
     Certain activities of Precision are affected by factors that are beyond its control or influence. The drilling rig, camp and catering, service rig, snubbing, rentals, wastewater treatment and related service businesses and activities of Precision in Canada and the drilling rig, camp and catering and rentals business and activities of Precision in the United States are directly affected by fluctuations in exploration, development and production activity carried on by its customers which, in turn, is dictated by numerous factors including world energy prices and government policies. The addition, elimination or curtailment of government regulations and incentives could have a significant impact on the oil and natural gas business in Canada and the United States. These factors could lead to a decline in the demand for Precision’s services, resulting in a material adverse effect on revenues, cash flows, earnings and cash distributions to Unitholders. The majority of Precision’s operating costs are variable in nature which minimizes the impact of downturns on Precision’s operational results.
Operations Dependent on the Price of Oil and Natural Gas
     Precision sells its services to oil and natural gas exploration and production companies. Macro economic and geopolitical factors associated with oil and natural gas supply and demand are prime drivers for pricing and profitability within the oilfield services industry. Generally, when commodity prices are relatively high, demand for Precision’s services are high, while the opposite is true when commodity prices are low. The markets for oil and natural gas are separate and distinct. Oil is a global commodity with a vast distribution network. As natural gas is most economically transported in its gaseous state via pipeline, its market is dependent on pipeline infrastructure and is subject to regional supply and demand factors. Recent developments in the transportation of liquefied natural gas (“LNG”) in ocean going tanker ships has introduced an element of globalization to the natural gas market. However, the volume capability of the world’s LNG infrastructure is not expected to be large enough to influence pricing in North American markets for a number of years. Crude oil and natural gas prices are quite volatile, which accounts for much of the cyclical nature of the oilfield services business. Oilfield service business cycles are muted somewhat in non-North American markets where projects tend to be larger and more long-term and are therefore less susceptible to short-term commodity price fluctuations.
     Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, may affect both the demand for, and the supply of, oil and natural gas. Weather conditions, governmental regulation (both in Canada and elsewhere), levels of consumer demand, the availability of pipeline capacity, 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. This would likely result in a corresponding decline in the demand for Precision’s services and could have a material adverse effect on its revenues, cash flows and profitability. Lower oil and natural gas prices could also cause Precision’s customers to seek to terminate, renegotiate or fail to honour Precision’s drilling contracts which could affect the fair market value of its rig fleet which in turn could trigger a writedown for accounting purposes; which could affect Precision’s ability to retain skilled rig personnel; and which could affect 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 and oilfield services industries will not decline.
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, 2006 there were an estimated 842 industry drilling rigs in Canada, an increase of 9% from December 31, 2005. There is no assurance that the level of demand for drilling rig services will be able to support the expected increase in the size of the industry drilling fleet. Any decline in demand for drilling services within the sector directly or indirectly related to the current drilling rigs available could also lead to a decline in the

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demand for Precision’s services, resulting in a material adverse effect on Precision’s revenues, cash flows, earnings and distributions to Unitholders.
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 employees 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 to attract new workers to the industry as required. Many of Precision’s businesses are currently experiencing manpower shortages in peak operating periods. These shortages are likely to be further challenged by the number of rigs being added to the industry along with the entrance and expansion of newly formed oilfield service companies. In the near-term anticipated declines in activity will offset challenges due to rig expansion.
New Technology
     Technological innovation by oilfield service companies has improved the effectiveness of the entire exploration and production sector over the industry’s more than 140-year history. Drilling time has been reduced due to improvements in drill bits, logging and measurement-while-drilling tools, as well as innovation changes in other areas such as mud systems and top drives. Precision’s ability to deliver services that are more efficient is critical to continued success.
Customer Merger and Acquisition Activity
     Merger and acquisition activity in the oil and natural gas exploration and production sector can impact demand for our services as customers focus on internal reorganization activities prior to committing funds to significant drilling and maintenance projects.
Business Interruption and Casualty Losses
     Precision’s operations are subject to many hazards inherent in the drilling, workover and well-servicing industries, including blowouts, cratering, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage and damage to the property of others. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and Precision seeks to obtain indemnification from its customers by contract for certain of these risks. To the extent that Precision is unable to transfer such risks to customers by contract or indemnification agreements, Precision seeks protection through insurance. However, Precision cannot ensure that such insurance or indemnification agreements will adequately protect it against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, insurance may not be available to cover any or all of these risks, or, even if available, may not be adequate. Insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive or uneconomic. This is particularly of concern in the wake of the September 11, 2001 terrorist attacks in the U.S. and the severe hurricane damage in the U.S. Gulf Coast region in 2005, both of which have resulted in significantly increased insurance costs, deductibles and coverage restrictions. In future insurance renewals, Precision may choose to increase its self insurance retentions (and thus assume a greater degree of risk) in order to reduce costs associated with increased insurance premiums.
Environmental Legislation
     Precision’s operations are subject to numerous laws, regulations and guidelines governing the management, transportation and disposal of hazardous substances and other waste materials and otherwise relating to the

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protection of the environment and health and safety. These laws, regulations and guidelines include those relating to spills, releases, emissions and discharges of hazardous substances or other waste materials into the environment, requiring removal or remediation of pollutants or contaminants and imposing civil and criminal penalties for violations. Some of the laws, regulations and guidelines that apply to Precision’s operations also authorize the recovery of natural resource damages by the government, injunctive relief, and the imposition of stop, control, remediation and abandonment orders. The costs arising from compliance with such laws, regulations and guidelines may be material to Precision.
     The trend in environmental regulation has been to impose more restrictions and limitations on activities that may impact the environment, including the generation and disposal of wastes and the use and handling of chemical substances. These restrictions and limitations have increased operating costs for both Precision and its customers. Any regulatory changes that impose additional environmental restrictions or requirements on Precision or its customers could adversely affect Precision through increased operating costs and potential decreased demand for Precision’s services.
     While Precision maintains liability insurance, including insurance for environmental claims, the insurance is subject to coverage limits and certain of Precision’s policies exclude coverage for damages resulting from environmental contamination. There can be no assurance that insurance will continue to be available to Precision on commercially reasonable terms, that the possible types of liabilities that may be incurred by Precision will be covered by Precision’s insurance, or that the dollar amount of such liabilities will not exceed Precision’s policy limits. Even a partially uninsured claim, if successful and of sufficient magnitude, could have a material adverse effect on Precision’s business, results of operations and prospects.
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 our equipment prior to imposition of the 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. Moreover, once the rigs and other equipment have been moved to a drilling site, they may become stranded or otherwise unable to relocate to another site should the muskeg thaw unexpectedly. Precision’s business results depend, at least in part, upon the severity and duration of the Canadian winter.
Tax Consequences of Previous Transactions Completed by Precision
     The business and operations of Precision prior to completion of the Plan of Arrangement had been 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 and in accordance with generally accepted accounting principles and applicable legislation and regulations. However, there are a number of tax filing positions that can still be the subject of review by taxation authorities who may successfully challenge Precision’s interpretation of the applicable tax legislation and regulations, with the result that additional taxes could be payable by Precision and the amount payable could be up to $300 million. Any increase in Precision’s tax liability would reduce the net assets and funds available for distributions to Unitholders.

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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.
Potential Unknown Liabilities
     There may be unknown liabilities assumed by the Trust through its direct and indirect interests in Precision, including those associated with prior acquisitions and dispositions by Precision as well as environmental issues or tax issues. Specifically, Precision has provided certain indemnities to the respective purchasers under the Weatherford Sale Agreement and the CEDA Sale Agreement. The discovery of any material liabilities could have an adverse affect on the financial condition and results of discontinued operations of Precision and, as a result, the amount of cash available for distribution to Unitholders. Precision is not aware of any undisclosed material liabilities.
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, and in such event, 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 to undertake acquisitions or other business combination transactions. There can be no assurance that additional financing will be available to Precision when needed or on terms acceptable to Precision. Precision’s inability to raise financing to support ongoing operations or to fund capital expenditures or acquisitions could limit Precision’s growth and may have a material adverse effect upon Precision.

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RECORD OF CASH DISTRIBUTIONS/PAYMENTS
     The following table sets forth the distributions (in CDN$) paid or declared payable by the Trust on each Trust Unit since the completion of the Plan of Arrangement:
                   
                  Amount per Trust
Distribution Type     Record Date     Payment Date     Unit
2005
                  
Regular Distribution
     November 30, 2005     December 15, 2005     $0.270
Regular Distribution
     December 31, 2005     January 17, 2006     $0.270
Special Distribution
     December 31, 2005     January 17, 2006     $0.022
2006
                  
Regular Distribution
     January 31, 2006     February 15, 2006     $0.270
Regular Distribution
     February 28, 2006     March 15, 2006     $0.270
Regular Distribution
     March 31, 2006     April 18, 2006     $0.270
Regular Distribution
     April 28, 2006     May 16, 2006     $0.270
Regular Distribution
     May 31, 2006     June 15, 2006     $0.310
Regular Distribution
     June 30, 2006     July 18, 2006     $0.310
Regular Distribution
     July 31, 2006     August 15, 2006     $0.310
Regular Distribution
     August 31, 2006     September 15, 2006     $0.310
Regular Distribution
     September 29, 2006     October 17, 2006     $0.310
Regular Distribution
     October 31, 2006     November 15, 2006     $0.310
Regular Distribution
     November 30, 2006     December 15, 2006     $0.310
Regular Distribution
     December 31, 2006     January 16, 2007     $0.310
Special Year-end in-kind Distribution(1)
     December 31, 2006     January 16, 2007     $0.195
2007
                  
Regular Distribution
     January 31, 2007     February 15, 2007     $0.190
Regular Distribution
     February 28, 2007     March 15, 2007     $0.190
Regular Distribution
     March 30, 2007     April 17, 2007     $0.190
 
NOTE:
(1)   As referenced in the Trust’s press release dated December 18, 2006, the special year-end distribution of $0.195 per unit was not paid in cash and holders of Trust Units did not receive additional Trust Units. The special year-end distribution was settled “in-kind” through Trust Units rather than cash in order for Precision to minimize debt levels and retain balance sheet strength to fund planned asset growth. Immediately after the special in-kind distribution, the outstanding Trust Units were consolidated so that the number of Trust Units outstanding remained unchanged from the number of Trust Units outstanding immediately before the special in-kind distribution.
     The following table sets forth the amount of payments (in CDN$) paid or payable on each Exchangeable Unit since the completion of the Plan of Arrangement:
                   
                  Amount
                  per Exchangeable
Payment Type     Record Date     Payment Date     Unit
2005
                  
Regular Payment
     November 30, 2005     December 15, 2005     $0.270
Regular Payment
     December 31, 2005     January 17, 2006     $0.270
Special Payment
     December 31, 2005     January 17, 2006     $0.022
2006
                  
Regular Payment
     January 31, 2006     February 15, 2006     $0.270
Regular Payment
     February 28, 2006     March 15, 2006     $0.270
Regular Payment
     March 31, 2006     April 18, 2006     $0.270
Regular Payment
     April 28, 2006     May 16, 2006     $0.270
Regular Payment
     May 31, 2006     June 15, 2006     $0.310
Regular Payment
     June 30, 2006     July 18, 2006     $0.310

28

 

                   
                  Amount
                  per Exchangeable
Payment Type     Record Date     Payment Date     Unit
Regular Payment
     July 31, 2006     August 15, 2006     $0.310
Regular Payment
     August 31, 2006     September 15, 2006     $0.310
Regular Payment
     September 29, 2006     October 17, 2006     $0.310
Regular Payment
     October 31, 2006     November 15, 2006     $0.310
Regular Payment
     November 30, 2006     December 15, 2006     $0.310
Regular Payment
     December 31, 2006     January 16, 2007     $0.310
Special 2006 Year-end in-kind Payment(1)
     December 31, 2006     January 16, 2007     $0.195
2007
                  
Regular Distribution
     January 31, 2007     February 15, 2007     $0.190
Regular Distribution
     February 28, 2007     March 15, 2007     $0.190
Regular Distribution
     March 30, 2007     April 17, 2007     $0.190
 
NOTE:
(1)   As referenced in the Trust’s press release dated December 18th, 2006, the special year-end distribution of $0.195 per unit was not paid in cash and holders of Exchangeable Units did not receive additional Exchangeable Units of Precision Drilling Limited Partnership. The special year-end distribution was settled “in-kind” through Exchangeable Units rather than cash in order for Precision to minimize debt levels and retain balance sheet strength to fund planned asset growth. Immediately after the special in-kind distribution, the outstanding Exchangeable Units of PDLP were consolidated so that the number of Exchangeable Units of PDLP outstanding remained unchanged from the number of Exchangeable Units of PDLP outstanding immediately before the special in-kind distribution.
     Historical distributions and payments may not be reflective of future distribution and payments, which will be subject to review by the Board of Trustees taking into account the prevailing financial circumstances of the Trust at the relevant time. The declaration of distributions and the method of settlement (cash or “in-kind”) is within the discretion of the Board of Trustees.
DESCRIPTION OF CAPITAL
GENERAL DESCRIPTION OF CAPITAL STRUCTURE
Trust Units
     An unlimited number of Trust Units may be created and issued pursuant to the Declaration of Trust. Each Trust Unit entitles the holder thereof to one vote at any meeting of Trust Unit holders, or in respect of any written resolution of Trust Unit holders, and represents an equal undivided beneficial interest in any distribution from the Trust (whether from income, net realized capital gains or other amounts) and in any net assets of the Trust in the event of termination or winding up of the Trust. All Trust Units shall rank among themselves equally and rateably without discrimination, preference or priority whatsoever. Each Trust Unit is transferable, is not subject to any conversion or pre-emptive rights and entitles the holder thereof to require the Trust to redeem any or all of the Trust Units held by such holder.
Special Voting Unit
     Pursuant to the provisions of the Declaration of Trust a “Special Voting Unit” was issued to Computershare Trust Company of Canada, as the initial trustee (the “Voting and Exchange Trustee”) under a Voting and Exchange Trust Agreement, which allows the Special Voting Unit to be voted by the Voting and Exchange Trustee for and on behalf of the holders of Exchangeable Units. The Voting and Exchange Trustee is only entitled to the number of votes at meetings of Trust Unit holders which is equal to the number of Exchangeable Units registered and outstanding on the record date in respect of each meeting. The Voting and Exchange Trustee will be obligated to vote the Special Voting Unit at meetings of Trust Unit holders pursuant to instructions of the holders of Exchangeable Units. However, if no instructions are provided by holders of Exchangeable Units, the votes associated therewith in the Special Voting Unit will be withheld from voting.

29

 

     For a more complete description of the Trust Units and the Special Voting Unit please refer to pages 57 to 63 of the 2005 Special Meeting Information Circular under the heading “Declaration of Trust and Description of Units” which are incorporated by reference into this Annual Information Form.
Precision Drilling Limited Partnership
     As a result of the Plan of Arrangement, PDLP issued 122,512,799 Class A Limited Partnership Units to the Trust on November 7, 2005 (the effective date of the reorganization of the business of Precision into the Trust). An additional 1,840,122 Class A Limited Partnership Units were issued between November 7 and November 22, 2005 inclusive (the last date on which holders of New Options could exercise their options pursuant to the Plan of Arrangement). As of December 31, 2006 there were 125,536,329 Class A Limited Partnership Units issued to the Trust. As of March 29, 2007 there were 125,571,374 Class A Limited Partnership Units issued to the Trust.
     Also, as part of the Plan of Arrangement, PDLP issued 1,108,382 Exchangeable Units to certain shareholders of Precision who elected to receive such Exchangeable Units instead of Trust Units. As of December 31, 2006, 221,595 Exchangeable Units remained outstanding. As of March 29, 2007, 186,550 Exchangeable Units remained outstanding. The Exchangeable Units have the economic equivalence of the Trust Units and the principal terms of the Exchangeable Units are:
•   they are exchangeable for Trust Units on a one-for-one basis at the option of the holder;
•   each Exchangeable Unit entitles the holder thereof to receive (in the form of a non-interest bearing loan) cash payments equal to cash distributions made by the Trust on a Trust Unit (and at the beginning of the next calendar year a special distribution will be made on each Exchangeable Unit in an amount equal to the outstanding non-interest bearing loan accumulated during the previous year which will be used to repay such accumulated debt);
•   the holder of each Exchangeable Unit is entitled to direct the Voting and Exchange Trustee to vote the Special Voting Unit at all meetings of Trust Unit holders;
•   the holders of Exchangeable Units are not entitled, as such, to receive notice of or to attend any meeting of the partners of PDLP or to vote at any such meeting, however, such holders of Exchangeable Units are entitled to vote separately as a class in respect of proposals to add to, change or remove any right, privilege, restriction or condition attaching to the Exchangeable Units or in respect of any other amendment to the applicable Partnership Agreement which would have an adverse impact on the holders of such Exchangeable Units; and
•   there are certain restrictions on the transfer of Exchangeable Units.
     A more detailed description of the attributes and restrictions associated with Exchangeable Units is provided on pages 68 through 73 and Appendix D of the 2005 Special Meeting Information Circular and the applicable portions of those pages and that Appendix D are incorporated by reference into this Annual Information Form.
     In addition to the foregoing, on November 7, 2005, the Trust, PDLP, the General Partner and Precision entered into a support agreement (the “Support Agreement”) which requires the Trust or its affiliates to take all actions and do all things as are reasonably necessary or desirable to enable and permit PDLP to meet all of its obligations with respect to the Exchangeable Units and such agreement also provides that the Trust will not, without the prior approval of PDLP and holders of Exchangeable Units:
•   issue or distribute Trust Units to the holders of all, or substantially all, of the then outstanding Trust Units by way of distribution; or
•   issue or distribute rights, options or warrants to the holders of all, or substantially all, of the then outstanding Trust Units entitling them to subscribe for or purchase Trust Units (or securities exchangeable for or converting into or carrying rights to acquire Trust Units); or

30

 

•   issue or distribute to the holders of all, or substantially all, of the then outstanding Trust Units;
  •   securities of the Trust or any class other than Trust Units (other than securities exchangeable for or converting into or carrying rights to acquire Trust Units);
 
  •   rights, options or warrants other than those described in the second bullet above; or
 
  •   evidences of indebtedness of the Trust; or
 
  •   other assets of the Trust,
unless the economic equivalent on a per Exchangeable Unit basis of such rights, options, warrants, securities, shares, evidences of indebtedness or other assets is issued or loaned simultaneously to the holders of Exchangeable Units.
     A more complete description of the Support Agreement is set forth on pages 74 and 75 of the 2005 Special Meeting Information Circular under the heading “Support Agreement” which is incorporated by reference into this Annual Information Form.
The General Partner
     The General Partner of PDLP is a direct wholly-owned subsidiary of the Trust. The General Partner is the managing partner of PDLP and has the exclusive authority to manage the business and affairs of PDLP, to make all decisions regarding the business of PDLP and to bind PDLP.
MARKET FOR SECURITIES
Trading Price and Volume of Trust Units
     The Trust Units were listed for trading on the Toronto Stock Exchange (the “TSX”) and the New York Stock Exchange (the “NYSE”) on November 7, 2005, the date the reorganization of the business of Precision into an income trust became effective. The Trust Units trade under the trading symbols PD.UN and under the trading symbol PDS on the NYSE. The listing of Trust Units denominated in U.S. dollars under the symbol PD.U on the TSX was discontinued effective December 29, 2006. The following tables set forth the monthly and quarterly price range and volume traded for the Trust Units on the TSX and NYSE from January, 2006 to March 27, 2007.

31

 

TSX— PD.UN(1)
(In Canadian dollars, except volume traded amounts)
                                         
Period     High     Low     Close     Volume Traded
                         
January
       40.75         38.00         38.00         13,417,702  
February
       38.95         34.00         35.53         15,792,850  
March
       38.75         33.56         37.66         19,600,919  
                         
Q1 2006
       40.75         33.56         37.66         48,834,244  
                         
April
       43.40         37.52         39.70         16,471,558  
May
       40.74         35.88         37.60         11,463,735  
June
       39.27         33.19         37.10         13,133,745  
                         
Q2 2006
       43.40         33.19         37.10         41,069,038  
                         
July
       39.40         34.90         39.11         8,174,315  
August
       41.80         38.86         40.24         9,384,581  
September
       40.95         33.21         34.33         9,903,090  
                         
Q3 2006
       41.80         33.21         34.33         27,461,986  
                         
October
       34.65         30.19         31.94         19,431,267  
November
       29.31         24.40         28.39         30,123,804  
December
       29.30         26.80         27.00         6,488,988  
                         
Q4 2006
       34.65         24.40         27.00         56,044,059  
                         
January
       28.30         25.30         26.50         9,384,691  
February
       27.90         24.60         27.43         10,003,698  
March (2)
       27.33         25.13         27.13         9,629,950  
                         
Q1 2007
       28.30         24.60         27.13         29,018,339  
                         
NOTES:
(1)   Price and volume information is taken from the website maintained by the TSX.
 
(2)   For the period from March 1, 2007 to March 27, 2007.
TSX — PD.U(1)
(In U.S. dollars, except volume traded amounts)
                                         
Period     High     Low     Close     Volume Traded
                         
January
       36.00         32.50         33.67         34,281  
February
       34.00         29.23         31.38         32,745  
March
       33.00         28.48         31.86         33,631  
                         
Q1 2006
       36.00         28.48         31.86         100,657  
                         
April
       37.06         31.61         35.61         23,878  
May
       36.83         32.00         34.51         26,386  
June
       34.97         29.63         33.02         13,652  
                         
Q2 2006
       37.06         29.63         33.02         63,916  
                         
July
       35.33         29.50         34.85         21,675  
August
       37.28         34.00         35.97         27,100  
September
       36.72         29.57         30.13         42,794  
                         
Q3 2006
       37.28         29.50         30.13         91,569  
                         
October
       31.00         26.80         28.75         192,445  
November
       26.11         21.25         24.81         104,698  
December(2)
       27.38         23.12         23.14         60,909  
                         
Q4 2006
       31.00         21.25         23.14         358,052  
                         

32

 

NOTES:
(1)   Price and volume information is taken from the website maintained by the TSX.
 
(2)   The listing of the Trust Units denominated in U.S. dollars under the symbol PD.U was discontinued effective December 29, 2006.
NYSE — PDS(1)
(In U.S. dollars, except volume traded amounts)
                                         
Period     High     Low     Close     Volume Traded
                         
January
       35.15         33.05         33.53         9,731,600  
February
       34.12         29.78         31.49         11,524,700  
March
       33.24         28.83         32.34         17,474,000  
                         
Q1 2006
       35.15         28.83         32.34         38,730,300  
                         
April
       38.20         32.32         35.54         13,732,300  
May
       36.88         31.77         34.05         14,176,400  
June
       35.63         29.74         33.20         14,627,700  
                         
Q2 2006
       38.20         29.74         33.20         42,536,400  
                         
July
       34.89         30.73         34.71         10,921,100  
August
       37.78         34.61         36.66         10,530,300  
September
       36.88         29.76         30.82         12,028,700  
                         
Q3 2006
       37.78         29.76         30.82         33,480,100  
                         
October
       31.48         26.74         28.66         21,450,600  
November
       28.11         21.46         24.90         39,824,500  
December
       25.48         23.00         23.16         19,262,400  
                         
Q4 2006
       31.48         21.46         23.16         80,537,500  
                         
January
       24.12         21.50         22.59         20,949,100  
February
       24.02         21.06         23.41         13,976,307  
March (2)
       23.57         21.71         23.49         15,773,839  
                         
Q1 2007
       24.12         21.06         23.49         50,699,246  
                         
NOTES:
(1)   Price and volume information is taken from the website maintained by the NYSE.
 
(2)   For the period from March 1, 2007 to March 27, 2007.
ESCROWED SECURITIES
     To the knowledge of the Board of Trustees and Precision’s board of directors (the “Board of Directors” and each a “Director”), no securities of the Trust are held in escrow.
TRUSTEES, DIRECTORS AND EXECUTIVE OFFICERS
     The following table sets forth, for each Trustee of the Trust and Director and officer of Precision: his name; municipality, province or state and country of residence; all positions and offices now held by him; the month and year in which he was first elected a Director or officer; his principal occupation during the preceding five years; and the number and percent of Trust Units and Exchangeable Units that he has advised are beneficially owned by him, directly or indirectly, as of the date hereof.

33

 

                         
                        Trust Units /
                        Exchangeable Units
                        Beneficially Owned,
Name, Municipality, Province or     Position Presently     Director/ Officer     Principal Occupation     Controlled or
State & Country of Residence     Held(1)     Since     During the Preceding 5 Years     Directed(2)
                         
W.C. (Mickey) Dunn(3) (5)
Edmonton, Alberta, Canada
    Director     September 1992     Chairman, True Energy Trust     15,600 / nil
0.012% / nil
 
                        
Brian A. Felesky, CM, Q.C.(3)
Calgary, Alberta, Canada
    Director     December 2005     Counsel, Felesky Flynn LLP from April 1978 through July 2006, Partner at Felesky Flynn LLP.     2,800 / nil
0.002% / nil
 
                        
Robert J.S. Gibson(3) (4)
Calgary, Alberta, Canada
    Trustee
Director 		    June 1996     President, Stuart & Company
Limited 		    63,200(6) / nil
0.050% / nil
 
                        
Allen R. Hagerman
Cochrane, Alberta, Canada
    Director     December 4, 2006     Chief Financial Officer, Canadian Oil Sands Limited since 2003, Vice President and Chief Financial Officer of Fording Canadian Coal Trust 2003, Vice President and Chief Financial Officer of Fording Inc. 2001-2003.     1,000 / nil
0.001% / nil
 
                        
Stephen J.J. Letwin
Houston, Texas, USA
    Director     December 4, 2006     Executive Vice President, Enbridge Inc., Gas Transportation and International     nil / nil
nil / nil
 
                        
Patrick M. Murray(4)
Dallas, Texas, USA
    Trustee
Director 		    July 2002     Chairman and Chief Executive Officer, Dresser, Inc.     40,000 / nil
0.032% / nil
 
                        
Frederick W. Pheasey(5)
Edmonton, Alberta, Canada
    Director     July 2002     Director of Dreco Energy Services Ltd.     44,000 / nil
0.035% / nil
 
                        
Robert L. Phillips(3) (5)
Vancouver, British Columbia, Canada
    Director     May 2004     Corporate Director, President and Chief Executive Officer, BCR Group of Companies, 2001-2004     5,000(7) / nil
0.004% / nil
 
                        
Hank B. Swartout
Calgary, Alberta, Canada
    Executive Chairman
Director 		    July 1987     Executive Chairman of Precision since 2007, Chairman and Chief Executive Officer of Precision 2005-2006, Chairman, President and Chief Executive Officer of Precision 1985-2005     64,888(8) / nil
0.052% / nil
 
                        
H. Garth Wiggins(4) (9)
Calgary, Alberta, Canada
    Trustee
Director 		    September 1997     Principal, Kenway, Mack,
Slusarchuk, Stewart,
Chartered Accountants 		    17,000 / nil
0.014% / nil
 
                        
Gene C. Stahl
Calgary, Alberta, Canada
    President &
Chief Operating
Officer 		    November 2005     Vice President, Precision Rentals 2003 — 2005, General Manager Ducharme Rentals/Big D Rentals 2002 — 2003, Investor Relations Officer, Precision Drilling Corporation 2001 — 2002     30,091 / nil
0.024% / nil
 
                        
Doug J. Strong
Calgary, Alberta, Canada
    Chief Financial
Officer 		    November 2005     Chief Financial Officer, Precision Diversified Services Ltd. 2001 — 2005, Group Controller, Precision Drilling 2001 — 2005, Senior Controller, Precision Drilling 1997 — 2001     24,000 / nil
0.019% / nil
 
                        
Darren J. Ruhr
Calgary, Alberta, Canada
    Vice President,
Corporate Services
& Corporate
Secretary 		    November 2005     Director, Information Technology, Real Estate & Travel, Precision Drilling Corporation 2003 — 2005, Director, Information Technology, Precision Drilling Corporation 2000 - 2003     10,000 / nil
0.008% / nil
 
NOTES:
 
(1)  
Each Director’s term of office expires not later than the close of business at the next annual meeting, or until successors are appointed or Directors vacate their office, and Directors are normally not renominated following the earlier of their fifteenth term or 69th birthday. Mr. Wiggins will not be standing for re-election as a Trustee or Director.
 
(2)  
Percentage of Trust Units and Exchangeable Units beneficially owned is calculated based on an aggregate of 125,757,924 Trust Units and Exchangeable Units outstanding as of the Effective Date.
 
(3)  
Member of the Corporate Governance and Nominating Committee.
 
(4)  
Member of the Audit Committee.
 
(5)  
Member of the Compensation Committee.
 
(6)  
8,000 of the Trust Units are held by Stuart & Company Limited, a company controlled by Mr. Gibson, and 10,000 Trust Units are held in a registered retirement savings plan for the benefit of Mr. Gibson.

34

 

(7)  
2,000 Trust Units are held by R.L. Phillips Investments Inc., a company controlled by Mr. Phillips.
 
(8)  
The Trust Units are held by 1201112 Alberta Ltd., a company controlled by Mr. Swartout.
 
(9)  
As Mr. Wiggins will not be standing for re-election at the Trust’s Annual and Special Meeting, it is proposed that Mr. Hagerman will replace him on the Audit Committee
     At March 29, 2007, the Trustees, the Directors and the executive officers of Precision, as a group, beneficially owned, directly or indirectly, or exercised control over 317,579 Trust Units and nil Exchangeable Units or approximately 0.25% of the issued and outstanding Trust Units and Exchangeable Units.
CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS
     No Trustee, Director or officer of Precision has, within the last 10 years, been a director or officer of any reporting issuer that, while such person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied the reporting issuer access to any statutory exemption for a period of more than 30 consecutive days or was declared a bankrupt or made a voluntary assignment in bankruptcy, made a proposal under any legislation relating to bankruptcy or been subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver-manager or trustee appointed to hold assets of that person.
AUDIT COMMITTEE INFORMATION
Audit Committee Charter
     The Audit Committee Charter and Terms of Reference (the “Audit Committee Charter”) of Precision is set forth in Appendix 1 of this Annual Information Form.
Composition of the Audit Committee
     The Audit Committee of Precision currently consists of Patrick M. Murray (Chairman), H. Garth Wiggins and Robert J. S. Gibson. As Mr. Wiggins will not be standing for re-election at the Trust’s Annual and Special Meeting it is proposed that Mr. Allen R. Hagerman will replace him on the Audit Committee. The Audit Committee is a standing committee appointed by the Board of Directors to assist the Board of Directors in fulfilling its oversight responsibilities with respect to financial reporting by Precision and the Trust, in its own capacity and in its capacity as the administrator of the Trust. Each member and the proposed member of the Audit Committee is independent and none received, directly or indirectly, any compensation from Precision or the Trust other than for services as a member of the Board of Trustees of the Trust or the Board of Directors of Precision and its committees. All members and the proposed member of the Audit Committee are financially literate as defined in Multilateral Instrument 52-110 (4.1) — Audit Committees. In addition, the Board of Directors has determined that each of Messrs. Murray, Wiggins and Hagerman qualify as “audit committee financial experts” as that term is defined under the United States Sarbanes-Oxley Act of 2002.
Relevant Education and Experience
     In addition to each member’s general business experience, the education and experience of each Audit Committee member that is relevant to the performance of his responsibilities as an Audit Committee member are as follows: Patrick M. Murray (Chair) is the Chairman, President and Chief Executive Officer of Dresser, Inc. Mr. Murray received a B.Sc. degree in Accounting in 1964 from Seton Hall University and an MBA in 1973. Mr. Murray has been a member of Precision’s Audit Committee since April 2003. H. Garth Wiggins received his Bachelor of Electrical Engineering from the University of Saskatchewan in 1970 and his Chartered Accountant designation in 1974. Mr. Wiggins is a Principal at Kenway, Mack, Slusarchuk, Stewart, Chartered Accountants. Mr. Wiggins has been a member of the Audit Committee since September 1997. Robert J.S. Gibson was educated at the University of Calgary and the University of Alberta. Mr. Gibson is the President of Stuart & Company Limited and has been a member of the Audit Committee since June 1997. Mr. Hagerman is the Chief Financial Officer of Canadian Oil Sands Limited. Mr. Hagerman received a B. Comm. from the University of Alberta in 1973 and his

35

 

Chartered Accountant designation in 1975. Mr. Hagerman also received an MBA from the Harvard School of Business in 1977.
Pre-approval Policies and Procedures
     Under the Audit Committee Charter, the Audit Committee is required to approve the terms of the engagement and the compensation to be paid to the external auditor of the Trust. In addition, the Audit Committee is required to review and pre-approve all permitted non-audit services to be provided to the Trust or any affiliated entities by the external auditors or any of their affiliates subject to any de minimus exception allowed by applicable law. The Audit Committee may delegate to one or more designated members of the Audit Committee the authority to pre-approve non-audit services. Non-audit services that have been pre-approved by any such delegate must be presented to the Audit Committee at its first scheduled meeting following such pre-approval.
     The Audit Committee implemented specific procedures regarding the pre-approval of services to be provided by Precision’s external auditor commencing in 2003. These procedures specify certain prohibited services that are not to be performed by the external auditor. In addition, these procedures require that at least annually, prior to the period in which the services are proposed to be provided, Precision’s management will, in conjunction with the Trust’s external auditor, prepare and submit to the Audit Committee a complete list of all proposed services to be provided to Precision and the Trust by the external auditor. Under the Audit Committee pre-approval procedures, for those services proposed to be provided by the external auditor that have not been previously approved by the Audit Committee, the Chairman of the Audit Committee has the authority to grant pre-approvals of such services. The decision to pre-approve a service covered under this procedure is required to be presented to the full Audit Committee at the next scheduled meeting. At each of the Audit Committee’s regular meetings, the Audit Committee is to be provided with an update as to the status of services previously pre-approved.
     Pursuant to these procedures, since their implementation in 2003, 100% of each of the services provided by the Trust’s external auditor relating to the fees reported as audit, audit-related, tax and all other fees were pre-approved by the Audit Committee or its delegate.
Audit Fees
     The following table provides information about fees billed to the Trust and its affiliates for professional services rendered by KPMG LLP, the Trust’s external auditor, during fiscal 2006 and 2005:
                     
(in thousands CDN$)            
Years ended December 31,     2006     2005
             
Audit fees
     $ 1,813       $ 2,108  
Audit-related fees
       —         —  
Tax fees
       579         753  
All other fees
       —         54  
             
Total
     $ 2,392       $ 2,915  
             
     Audit fees consist of fees for the audit of the Trust’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements and include fees related to Sarbanes-Oxley Section 404 compliance in 2006. The decrease in audit fees from 2005 to 2006 was primarily due to the providing of services for discontinued businesses in 2005.
     Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of the Trust’s financial statements and are not reported as audit fees. There were no such fees incurred in 2005 or 2006.
     Tax fees consist of fees for tax compliance services, tax advice and tax planning. During fiscal 2006 and 2005, the services provided in this category included assistance and advice in relation to the preparation of corporate

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income tax returns for the Trust and its subsidiaries, tax advice and planning, commodity tax and property tax consultation.
     In 2005, other fees related to translation of financial statements and due diligence assistance with respect to a disposition. In 2006, there were no such fees.
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
     None of the Trust, PDLP or Precision is involved in any legal proceedings that it believes might have a material adverse effect on its business or results of operations of any of the Trust, PDLP or Precision.
     During the course of the year ended December 31, 2006, none of the Trust, PDLP or Precision has been subject to any penalties or sanctions imposed by a court in relation to securities legislation or by securities regulatory authority, has not entered into a settlement agreement with a regulatory authority or been a subject of any other penalties or sanctions imposed by court or regulatory authority and has not entered into any settlement agreements with a court relating to securities legislation or with a securities regulatory authority.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
     There were no material interests, direct or indirect, of the Trustees, Directors and executive officers of Precision, any Unitholder who beneficially owns more than 10% of the outstanding Trust Units or Exchangeable Units, or any known associate or affiliate of such persons, in any transaction within the last fiscal year and in any proposed transaction which has materially affected or would materially affect the Trust, PDLP or Precision.
TRANSFER AGENT, REGISTRAR AND VOTING AND EXCHANGE TRUSTEE
     Computershare Trust Company of Canada, located in Calgary, Alberta, is the transfer agent and registrar of the Trust Units and the Special Voting and Exchange Trustee for the holders of Exchangeable Units. In the United States, the co-transfer agent for the Trust is Computershare Trust Company, Inc. located in New York, New York.
MATERIAL CONTRACTS
     The only material contracts entered into by Precision, the Trust or PDLP during the most recently completed financial year, or before the most recently completed financial year that are still in effect, other than contracts during the ordinary course of business, are as follows:
1.  
Weatherford Sale Agreement;
 
2.  
CEDA Sale Agreement;
 
3.  
Declaration of Trust;
 
4.  
Limited Partnership Agreement;
 
5.  
Voting and Exchange Trust Agreement;
 
6.  
Support Agreement; and
 
7.  
Administration Agreement.
     Copies of the material agreements described as 1 and 2 above have been filed by Precision and the remainder of the material agreements described above have been filed by the Trust on SEDAR and are available online at www.sedar.com.
INTERESTS OF EXPERTS
     KPMG LLP, the Trust’s external auditor, has prepared an opinion with respect to the Trust’s consolidated financial statements as at and for the year ended December 31, 2006. In connection with the audit of the Trust’s annual financial statements for the year ended December 31, 2006, the auditors confirmed that they are independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

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EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
     As of the fiscal year ended December 31, 2006, an evaluation of the effectiveness of the Trust’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was carried out by the Trust’s management with the participation of the principal executive officer and principal financial and accounting officer of Precision on behalf of the Trust. Based upon that evaluation, the principal executive officer and the principal financial and accounting officer of Precision have concluded that as of the end of that fiscal year, the Trust’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Trust in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms and is accumulated and communicated to the Trust’s management, including the principal executive officer and principal financial and accounting officer of Precision, to allow timely decisions regarding required disclosure.
     It should be noted that while Precision’s principal executive officer and principal financial and accounting officer believe that the Trust’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Trust’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
     During the fiscal year ended December 31, 2006, there were no changes in the Trust’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
     Management’s Discussion and Analysis relating to the consolidated financial statements for the fiscal year ended December 31, 2006 forms part of the Trust’s 2006 Annual Report and is incorporated by reference in this Annual Information Form. Management’s Discussion and Analysis appears on pages 29 to 66 of the 2006 Annual Report.
ADDITIONAL INFORMATION
     Additional information concerning the Trust is available through the Internet on SEDAR which may be accessed at www.sedar.com. Copies of such information may also be obtained without charge, on the Trust’s website at www.precisiondrilling.com or by request to the Vice President, Corporate Services and Corporate Secretary, at the offices of Precision at 4200, 150 — 6th Avenue S.W., Calgary, Alberta, Canada T2P 3Y7; by email at corporatesecretary@precisiondrilling.com; by telephone at (403) 716-4500; and by facsimile at (403) 264-0251.
     Additional information, including information regarding Precision’s Directors’ and officers’ remuneration, is contained in the Management Information Circular of the Trust provided for the Annual Meeting of Unitholders of the Trust to be held on May 9, 2007. Additional financial information is provided in the Trust’s annual consolidated financial statements and management’s discussion and analysis for the year ended December 31, 2006, which are contained in the Annual Report. Copies of such documents may be obtained in the manner set forth above.

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Appendix 1 Audit Committee Charter and Terms Of Reference
General
The purpose of this document is to establish the terms of reference of the Audit Committee (the “Committee”) of Precision Drilling Corporation (the “Corporation”). The Committee is a standing committee of the Board of Directors of the Corporation (the “Board of Directors”) appointed to assist the Board of Directors in fulfilling its oversight responsibilities with respect to financial reporting by the Corporation, in its own capacity and as the administrator for Precision Drilling Trust (the “Trust”).
It is critical that the external audit function, a mechanism that promotes reliable, accurate and clear financial reporting to unitholders of the Trust, is working effectively and efficiently, and that financial information is being relayed to the Board of Directors, and ultimately by the Board of Directors to the Board of Trustees (the “Board of Trustees”) of the Trust, in a timely fashion. The activities of the Committee are fundamental to the process.
The requirement to have an audit committee is established in Section 171 of the Business Corporations Act (Alberta) and, in addition, is required pursuant to the Securities Act (Alberta) and the United States Securities Exchange Act of 1934 for issuers listed on the New York Stock Exchange (the “NYSE”).
Committee Structure and Authority
  (a)   Composition
The Committee shall consist of no fewer than three members 1 , at least a majority of whom must be resident Canadians. Each member of the Committee shall be “independent” under the requirements or guidelines for audit committee service under applicable securities laws and the rules of any stock exchange on which the units of the Trust are listed for trading. 2
Each member of the Committee must be “financially literate” as such term is interpreted by the Board of Directors in its business judgment in light of, and in accordance with, the requirements or guidelines for audit committee service under applicable securities laws and the rules of any stock exchange 3 on which the Trust’s units are listed for trading. At least one of the members of the Committee must also have “accounting or related management financial expertise” as such term is defined from time to time under the requirements or guidelines for audit committee service under applicable securities laws and the rules of any stock exchange on which the Trust’s units are listed for trading. 4
No Committee member shall serve on the audit committees of more than three other issuers without prior determination by the Board of Directors that such simultaneous service would not impair the ability of such member to serve effectively on the Committee. 5
  (b)   Appointment and Replacement of Committee Members
Each member of the Committee shall serve at the pleasure of the Board of Directors. Any member of the Committee may be removed or replaced at any time by the Board of Directors, and shall automatically cease to be a member of the Committee upon ceasing to be a director of the Corporation. The Board of Directors may fill vacancies on the Committee by appointment from among its number. The Board of Directors shall fill any vacancy if the membership of the Committee is less than three directors. If and whenever a vacancy shall exist on the Committee, the remaining members may exercise all their power so long as a quorum remains in office. Subject to the foregoing, the members of the Committee shall be appointed by the Board of Directors annually and each member of the
 
1   NYSE s. 303A.07(a)
 
2   MI 52-110 ss. 1.4, 1.5, 3.1(2) and 3.1(3); SO s. 301; SEC Final Rule on Standards Relating to Listed Company Audit Committees; NYSE s. 303A.02, s. 303A.06 and 303A.07(6)
 
3   MI 52-110 ss. 1.1 and 3.1(4); NYSE s. 303.01(B)(i)(b); NYSE s. 303A.07(a)
 
4   SO s. 407; NYSE s. 303.01; NYSE s. 303A.07(a)
 
5   NYSE s. 303A.07(a)

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Committee shall hold office until the next annual meeting of the unitholders of the Trust after his or her election or until his or her successor shall be duly qualified and appointed.
  (c)   Quorum
The Committee shall have a quorum of not less than a majority of its members.
  (d)   Review of Charter and Terms of Reference
The Committee shall review and reassess the adequacy of this Charter and Terms of Reference at least annually and otherwise as it deems appropriate, and recommend changes to the Board of Directors. The Committee shall evaluate its performance with reference to this Charter and Terms of Reference annually. 6 The Committee will approve the form of disclosure of this Charter and Terms of Reference on the Trust’s website and, where required by applicable securities laws or regulatory requirements, in the annual management information circular or annual report of the Trust.
  (e)   Delegation
The Committee may delegate from time to time to any person or committee of persons any of the Committee’s responsibilities that lawfully may be delegated.
  (f)   Reporting to the Board of Directors
The Committee will report through the Chair of the Committee to the Board of Directors following meetings of the Committee on matters considered by the Committee, its activities and compliance with this Charter and Terms of Reference. 7
  (g)   Committee Chair Responsibilities
The Board of Directors shall appoint a Chair of the Committee. The primary responsibility of the Chair of the Committee is to provide leadership to the Committee to enhance its effectiveness. In such capacity, the Chair of the Committee will perform the duties and responsibilities set forth in the “Position Description for the Audit Committee Chair”.
  (h)   Other Authority
The Committee may request any officer or employee of the Corporation, or the Corporation’s or the Trust’s legal counsel, or any external or internal auditors to attend a meeting of the Committee or to meet with any members of, or consultants to the Committee. The Committee shall also have the authority to communicate directly with the internal auditor and external auditor.
The Committee may retain special legal, accounting, financial or other consultants to advise the Committee at the Corporation’s expense. 8
Purpose
The Committee shall have responsibility for overseeing the development and maintenance of the Corporation’s and the Trust’s systems for financial reporting. Responsibility for accounting for transactions and internal control over financial reporting lies with senior management of the Corporation with oversight responsibilities vested in the Board of Directors. The Committee is a permanent committee of the Board of Directors whose purpose is to assist the Board of Directors by overseeing:
 
6   NYSE s. 303A.07(c)(ii)
 
7   NYSE s. 303A.07 (c)(iii)(H)
 
8   MI 52-110 s. 4.1(a) and (b); SO s. 301(5) and (6); NYSE s. 303A.07(c) (iii)

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  •   the integrity of financial reporting to the holders of units of the Trust (“Unitholders”) and the investment community; 9
 
  •   the integrity of the financial reporting process, including the audit process; 10
 
  •   the Corporation’s and the Trust’s compliance with legal and regulatory requirements as they relate to financial reporting matters; 11
 
  •   the external auditor’s qualifications and independence; 12
 
  •   the integrity of the system of internal accounting and financial reporting controls implemented by management; 13
 
  •   the work and performance of the Corporation’s and the Trust’s financial management, internal audit function and its external auditor; and 14
 
  •   any other matter specifically delegated to the Committee by the Board of Directors.
Committee Responsibilities
The Committee shall:
  •   review the interim and annual financial statements of the Corporation and make any comments or recommendations to the Board of Directors;
 
  •   review the annual financial statements of the Trust and related notes and management’s discussion and analysis (“MD&A”) components and make recommendations to the Board of Directors, and ultimately, once approved by the Board of Directors, to the Board of Trustees, for their approval;
 
  •   review the interim financial statements of the Trust and related notes and MD&A components prepared for distribution to the Unitholders and the investment community;
 
  •   be satisfied that adequate procedures are in place for the review of the Trust’s public disclosure of financial information extracted or derived from the Trust’s financial statements, other than the public disclosure referred to above, and must periodically assess the adequacy of those procedures 15 ;
 
  •   report, through the Chair of the Committee, to the Board of Directors following each meeting of the Committee, including an outline of the nature of discussions, major decisions reached by the Committee, and its activities and compliance with this Charter and Terms of Reference;
 
  •   approve the terms of the external auditor’s engagement letter as agreed between the external auditor and financial management of the Corporation, and the compensation to be paid by the Corporation to the external auditor; 16
 
9   NYSE s. 303A.07(c)(i)(A)
 
10   NYSE s. 303A.07(c)(i)(A)
 
11   NYSE s. 303A.07(c)(i)(A)
 
12   NYSE s. 303A.07(c)(i)(A)
 
13   NYSE s. 303A.07(c)(i)(A)
 
14   NYSE s. 303A.07(c)(i)(A)
 
15   MI 52-110 s. 2.3(6)
 
16   SO s. 301(2); NYSE s. 303A.07(c)(iii)

41

 

  •   review the reasons for any proposed change in the external auditor which is not initiated by the Committee or the Board of Directors and any other significant issues related to the change, including the response of the incumbent external auditor, and enquire as to the qualifications of the proposed external auditor before making its recommendations to the Board of Directors; 17
 
  •   be directly responsible for overseeing the work of the external auditor engaged for the purpose of preparing or issuing an auditor’s report or performing other audit or review services for the Corporation or the Trust, including the resolution of disagreements between management and the external auditor regarding financial reporting 18 or the application of any accounting principles or practices;
 
  •   require the external auditor and internal auditor to report directly to the Committee; 19
 
  •   provide the external auditor with notice of every meeting of the Committee and, at the expense of the Corporation, the opportunity to attend and be heard thereat, and if so requested by a member of the Committee, shall attend every meeting of the Committee held during the term of the office of the external auditor. The external auditor of the Corporation or any member of the Committee may call a meeting of the Committee;
pre-approve all permitted 20 non-audit services to the Corporation or any affiliated entities by the external auditor or any of their affiliates 21 subject to any de minimus exception allowed by applicable law. The Committee may delegate to one or more designated members of the Committee the authority to pre-approve non-audit services, however any non-audit services that have been pre-approved by any such delegate of the Committee must be presented to the Committee at its first scheduled meeting following such pre-approval;
  •   review the disclosure with respect to its pre-approval of audit and non-audit services provided by the external auditors; 22
 
  •   review and discuss with management and the external auditor, as applicable, (a) all critical accounting policies and practices to be used in the annual audit, (b) major issues regarding accounting principles and financial statement presentations, including any significant changes in the Trust’s or the Corporation’s selection or application of accounting principles, and major issues as to the adequacy of the Trust’s or the Corporation’s respective internal controls and any special audit steps adopted in light of material control deficiencies; (c) analyses prepared by management or the external auditor setting forth significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including analyses of the effects of alternative Canadian Generally Accepted Accounting Principles (“GAAP”) methods on the financial statements 23 of the Trust and any other opinions sought by management from an independent or other audit firm or advisor with respect to the accounting treatment of a particular item; (d) any management letter or schedule of unadjusted differences provided by the external auditor and
 
17   NI 51-102 s. 4.11
 
18   SO s.301; SEC Final Rule on Standards Relating to Listed Company Audit Committees; MI 52-110 s.2.3(3)
 
19   NI 52-110 s. 2.2
 
20   The following non-audit services are prohibited under SO s.201(a), the SEC Final Rule on Strengthening the Commission’s Requirements Regarding Auditor Independence and the CICA’s proposed Auditor Independence Standards:
  •   bookkeeping services and other services related to accounting records or financial statements;
 
  •   financial information systems design and implementation;
 
  •   appraisal or valuation services, fairness opinions or contribution-in-kind reports;
 
  •   actuarial services;
 
  •   internal audit outsourcing services;
 
  •   management functions or human resources;
 
  •   broker dealer, investment advisor or investment banking services;
 
  •   legal services and expert services unrelated to the audit.
In addition, the SEC Final Rule prohibits providing expert services unrelated to the audit for advocacy purposes unless limited to a factual account of the work performed and conclusions reached in respect of an audit performed.
 
21   SO s. 201 and 202; SEC Final Rule on Strengthening the Commission’s Requirements Regarding Independence; SEC Regulation S-X 2-01(c)(7)
 
22   SO s. 202; SEC Final Rule on Strengthening the Commission’s Requirements Regarding Auditor Independence
 
23   SO s.204; NYSE s.303A.07(c) (General Commentary)

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the Trust’s response to that letter and other material written communication between the external auditor and management; 24 (e) any problems, difficulties or differences encountered in the course of the audit work including any disagreements with management or restrictions on the scope of the external auditor’s activities or on access to requested information and management’s response thereto; 25 (f) the effect of regulatory and accounting initiatives, as well as any off-balance sheet structures on the financial statements of the Trust and other financial disclosures; 26 (h) any reserves, accruals, provisions or estimates that may have a significant effect upon the financial statements of the Trust; (i) the use of special purpose entities and the business purpose and economic effect of off balance sheet transactions, arrangements, obligations, guarantees and other relationships of the Trust or the Corporation and their impact on the reported financial results of the Trust; 27 and (j) the use of any “pro forma” or “adjusted” information not in accordance with generally accepted accounting principles; 28
  •   reviewing earnings press releases (paying particular attention to any use of “pro forma” or “adjusted” “non-GAAP” information) as well as financial information and earnings guidance provided to analysts and rating agencies, it being understood that such review may in the discretion of the Committee, be done generally (i.e., by discussing the types of information to be disclosed and the type of presentation to be made); 29
 
  •   review with the external auditor and management the general audit approach and scope of proposed audits of the financial statements of the Trust, the objectives, staffing, locations, co-ordination and reliance upon management in the audit, the overall audit plans, the audit procedures to be used and the timing and estimated budgets of the audits; 30
 
  •   review any legal matter, claim or contingency that could have a significant impact on the financial statements of the Trust, the Corporation’s or the Trust’s compliance policies and any material reports, inquiries or other correspondence received from regulators or governmental agencies and the manner in which any such legal matter, claim or contingency has been disclosed in the Trust’s financial statements;
 
  •   review the treatment for financial reporting purposes of any significant transactions which are not a normal part of the Corporation’s operations;
 
  •   review the interim review engagement report of the external auditor before the release of interim financial statements of the Trust;
 
  •   review and discuss with management the Corporation’s major financial risk exposures and the steps management has taken to monitor and control such exposures, including the Corporation’s risk assessment and risk management policies such as financial derivatives and hedging activities; 31
 
  •   annually request and review a report from the external auditor regarding (a) the external auditor’s quality-control procedures, (b) any material issues raised by the most recent quality-control review or peer review of the external auditor, or by any inquiry or investigation by governmental or professional authorities within the preceding five years respecting one or more independent audits carried out by the firm, 32 and (c) any steps taken to deal with any such issues;
 
24   SO s. 204; SEC Final Rule on Strengthening the Commission’s Requirements Regarding Auditor Independence
 
25   NYSE s. 303A.07(c)(iii)(F); CICA Handbook Section 5751.23
 
26   NYSR s. 303A.07(c)(General Commentary)
 
27   NYSE s.303A.07(c) (General Commentary); SO s.401; SEC Final Rule on Disclosure in Management’s Discussion and Analysis About Off – Balance Sheet Arrangements and Aggregate Contractual Obligations
 
28   SO s.401; SEC Regulation G; NYSE s. 303A.07(c); SEC Final Rule on Conditions for Use of Non-GAAP Financial Measures; CSA Notice 52-306
 
29   NP 51-201 s.6.4; MI 52-110 s.2.3(5); NYSE s.303A.07(c)(iii)(C) and 303A.07(c) (General Commentary)
 
30   CICA Handbook Section 5751.14; MI 52-110 s. 2.3(3)(c)(i)(A)
 
31   NYSE s. 303A.07(c)(iii)(D)
 
32   NYSE s. 303A.07(c)(iii)(A); CICA Handbook Section 5751.31

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  •   evaluate the qualifications and performance of the external auditor, including a written review and evaluation of the lead partner of the external auditor 33 , review and approve hiring policies for partners, employees or former employees of the external auditor 34 and make recommendations to the Board of Directors as to the appointment or reappointment of the external auditor to be proposed for approval by the Board of Trustees and Unitholders; 35
 
  •   review the independence of the external auditor, 36 annually request and review a written report from the external auditor respecting its independence, including a list of all relationships between the external auditor and each of the Corporation and the Trust, 37 and consider applicable auditor independence standards; 38
 
  •   ensure that the lead audit partner of the external auditor and the audit partner responsible for reviewing the audit are rotated at least every five years as required by the Sarbanes-Oxley Act of 2002, and further consider rotation of the external auditor’s firm itself;
 
  •   discuss with management and the external auditors any accounting adjustments that were noted or proposed by the external auditors but were not adopted (as immaterial or otherwise);
 
  •   review the adequacy and effectiveness of the Corporation’s and the Trust’s internal accounting and financial controls based on recommendations from management and the external auditor for the improvement of accounting practices and internal controls; 39
 
  •   establish and periodically review procedures for (a) the receipt, retention and treatment of complaints received by the Corporation or the Trust regarding accounting, internal controls or auditing matters, and (b) the confidential, anonymous submission by employees of the Corporation of concerns regarding questionable accounting or auditing matters or other matters that could negatively affect the Corporation or the Trust such as violations of the Joint Code of Business Conduct and Ethics; 40
 
  •   review periodically with management and the external auditors any significant complaints received;
 
  •   review other financial information included in the Trust’s Annual Report to ensure that it is consistent with the Board of Directors’ knowledge of the affairs of the Corporation and the Trust and is unbiased and non-selective;
 
  •   if requested by the Board of Directors, receive from the Executive Chair or the Chief Executive Officer and Chief Financial Officer of the Corporation a certificate certifying in respect of each annual and interim report of the Trust the matters such officers are required to certify in connection with the filing of such reports under applicable securities laws and receive and review disclosures made by such officers about any significant deficiencies in the design or operation of internal controls or material weaknesses therein and any fraud involving management or persons who have a significant role in the Corporation’s internal controls;
 
  •   prepare any report required by law, regulations or stock exchange requirement to be included in the Trust’s periodic reports;
 
33   Commentary to NYSE s. 303A.07(c)(iii)(A)
 
34   MI 52-110 s. 2.3(8); NYSE s. 303A.07(c)(iii)(G); SO s. 206; SEC Final Rule on Strengthening the Commission’s Requirements Regarding Auditor Independence; Independence Standards Board Independence Standard No. 3
 
35   SO s. 301(2); MI 52-110 s. 2.3(2); NYSE s. 303A.07(c)(i)(A) and 303A.07(c)(iii)
 
36   NYSE s. 303A.07(c)(i)(A)
 
37   NYSE s. 303A.07(c)(iii)(A); CICA Handbook Section 5751.12, .25, .29 and .32
 
38   SO s. 203; NYSE s. 303A.07(c)(iii)(A); CICA Proposed Independence Standards s. 204.4(20)
 
39   NYSE s. 303A.07(c)(General Commentary); CICA Handbook Section 5751.16
 
40   SO s. 301; SEC Final Rule on Standards Relating to Listed Company Audit Committees; MI 52-110 s. 2.3(7)

44

 

  •   meet at least four times a year on a quarterly basis or more frequently as circumstances require, with the Chief Financial Officer of the Corporation, the head of the internal audit function of the Corporation, if other than the Chief Financial Officer, and the external auditor in separate executive sessions to discuss any matters that the Committee or each of these groups believes should be discussed privately;
 
  •   review annually the Corporation’s insurance programs and pension plans, not including the Directors and Officers insurance program;
 
  •   review the results of the annual external audit, including the audit report to the Trust’s Unitholders and any other reports prepared by the external auditors and the informal reporting from the external auditor on accounting systems and internal controls, including management’s response;
 
  •   review and evaluate the scope, risk assessment, and nature of the internal audit plan and any subsequent changes; 41
 
  •   consider and review the following issues with management and the head of the internal audit group:
  •   significant findings of the internal audit group as well as management’s response to them;
 
  •   any difficulties encountered in the course of their internal audits, including any restrictions on the scope of their work or access to required information;
 
  •   the internal auditing budget and staffing;
 
  •   the internal Audit Services Charter; and
 
  •   compliance with The Institute of Internal Auditors’ Standards for the Professional Practice of Internal Auditing;
  •   approve the appointment, replacement or dismissal of the head of the internal audit group; and
 
  •   direct the head of the internal audit group to review any specific areas the Committee deems necessary; and
 
  •   ensure that the obligations of the Corporation pursuant to the Administration Agreement are met and that good corporate governance procedures are used in connection therewith.
In addition, the Committee shall hold in-camera meetings with representatives of the external auditor and internal auditor to discuss audit related issues, including the quality of accounting personnel.
The Committee shall have such other powers and duties as may from time to time by resolution be assigned to it by the Board of Directors.
Limitation of Committee’s Role
While the Committee has the responsibilities and powers set forth in its Charter and Terms of Reference, it is not the duty of the Committee to prepare financial statements, plan or conduct audits or to determine that the Trust’s or the Corporation’s financial statements and disclosures are complete and accurate and are in accordance with GAAP and applicable rules and regulations. These are the responsibilities of the management of the Corporation and the external auditor.
 
41   NYSE s. 303A.07(c)(i)(A) and s. 303A.07(c)(iii)(E); s. 303A.07(d)

45

 

The Committee, the Chair of the Committee and any Committee members identified as having accounting or related financial expertise are members of the Board of Directors, appointed to the Committee to provide broad oversight of the financial, risk and control-related activities of the Corporation and the Trust, and are specifically not accountable or responsible for the day-to-day operation or performance of such activities.
Although the designation of a Committee member as having accounting or related financial expertise for disclosure purposes is based on that individual’s education and experience, which that individual will bring to bear in carrying out his or her duties on the Committee, such designation does not impose on such person any duties, obligations or liabilities that are greater than the duties, obligations and liabilities imposed on such person as a member of the Committee and Board of Directors in the absence of such designation. Rather, the role of a Committee member who is identified as having accounting or related financial expertise, like the role of all Committee members, is to oversee the process, not to certify or guarantee the internal or external audit of the Trust’s financial information or public disclosure.
[Approved on July 26, 2006]

46

 

Precision Drilling Trust
MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (“MD&A”), prepared as at March 9, 2007, focuses on key statistics from the Consolidated Financial Statements, and pertains to known risks and uncertainties relating to the oilfield services sector. This discussion should not be considered all-inclusive, as it does not include all changes that may occur in general economic, political and environmental conditions. 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 material contained in other parts of this annual report, including the “Cautionary Statement Regarding Forward-Looking Information and Statements” on page 1, the audited Consolidated Financial Statements and the related notes. The effects on the Consolidated Financial Statements arising from differences in generally accepted accounting principles (GAAP) between Canada and the United States are described in Note 16 to the Consolidated Financial Statements. Additional information relating to the Trust, including the Annual Information Form, has been filed with SEDAR and is available at www.sedar.com.
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 and the comparables for the quarterly and annual periods for the years ended December 31, 2005 and 2004, 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.
HIGHLIGHTS
(Stated in thousands of Canadian dollars, except per diluted unit/share amounts)
                                                 
            % Increase             % Increase             % Increase  
Years ended December 31,   2006     (Decrease)     2005     (Decrease)     2004     (Decrease)  
 
Revenue
   $ 1,437,584       13     $ 1,269,179       23     $ 1,028,488       12  
Operating earnings (1)
     595,279       28       465,378       40       331,313       31  
Earnings from continuing operations
     572,512       159       220,848       17       188,131       31  
Discontinued operations, net of tax (2)
     7,077       n/m       1,409,715       n/m       59,273       n/m  
Net earnings
     579,589       (64 )     1,630,563       559       247,404       37  
Cash provided by continuing operations
     609,744       196       206,013       (28 )     286,437       43  
Net capital spending from continuing operations (3)
     233,693       67       140,077       23       113,897       34  
Distributions declared – cash
     447,001       n/m       70,510       n/m       —       —  
Distributions declared – in-kind
     24,523       n/m       —       —       —       —  
Per diluted unit/share information:
                                                
Earnings from continuing operations
     4.56       159       1.76       9       1.61       23  
Net earnings
     4.62       (64 )     13.00       516       2.11       29  
Distributions declared – cash
     3.56       n/m       0.56       n/m       —       —  
Distributions declared – in-kind
     0.195       n/m       —       —       —       —  
 
(1)   Non-GAAP measure. See page 66.
 
(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,   2006     2005     2004  
 
Working capital
   $ 166,484     $ 152,754     $ 557,311  
Working capital ratio
     1.8       1.4       2.5  
Long-term debt (1)
   $ 140,880     $ 96,838     $ 718,850  
Total assets
   $ 1,761,186     $ 1,718,882     $ 3,852,049  
Long-term debt to long-term debt plus equity (1)
     0.10       0.08       0.24  
Long-term debt to cash provided by continuing operations (1)
     0.23       0.47       2.51  
Interest coverage (2)
     74.1       15.9       7.2  
 
(1)   Excludes current portion of long-term debt which is included in working capital.
 
(2)   Operating earnings divided by net interest expense.
OVERVIEW AND OUTLOOK
Fiscal 2006 marked a new chapter in Precision’s development. During the second half of 2005 there were certain events that changed the course of our company. Precision sold 55% of its asset base, agreed to non-compete provisions restricting certain operational scope to Canada and the United States through August 2008, realized a gain of $1.3 billion and used the proceeds to eliminate $0.7 billion in public debt and to return $2.9 billion in cash and marketable securities to its shareholders. Following these strategic transactions, Precision converted its continuing Canadian operations into an income trust structure, pursuant to shareholder approval, on November 7, 2005.
After more than 50 years of operating as either a private or public corporation with no regular dividends to its owners, Precision commenced 2006 with a new capital structure geared toward the flow-through of cash pursuant to a distribution policy managed by its Trustees. After almost a decade of reinvesting a substantial amount of retained earnings toward growth in international markets and certain downhole technologies, Precision returned to its core business segment, contract drilling, and its dominant market position in Canada.
(PRIOR PERIOD GRAPH 1)
The strategy for the continuing business platform in Canada is an affirmation of Precision’s prior operational model and for the near term sets the focus on the Canadian marketplace. The emphasis is to build upon our core group of people, augment the services we provide our customers, passionately pursue our Target Zero safety vision and continue to grow and be profitable. Precision set its growth objectives with a view to participate in market opportunities throughout North America with a long-term objective to consolidate higher cost, less efficient competitors and those with a common operational philosophy of providing safe customer solutions through superior technology, process and personnel.
For 2006 this strategy took root with many noteworthy developments.
Profitability
•   Precision benefited from strong industry fundamentals carried over from a banner 2005 to generate record earnings from continuing operations for 2006 of $573 million or $4.56 per unit.
 
•   Precision generated operating earnings of $595 million, an increase of $130 million or 28% over 2005.
Growth
•   Net capital spending in 2006 for the purchase of property, plant and equipment increased 67% or $94 million over the prior year to $234 million. Before considering proceeds on asset disposals of $29 million, Precision spent $92 million toward the productive capacity maintenance of its existing asset base and $171 million on expansionary initiatives.
  —    Precision established a contract drilling operation in the United States and currently operates two rigs.
 
  —    Precision added 13 new and decommissioned two drilling rigs in its Canadian fleet. By the end of the first quarter of 2008, Precision expects to be operating a North American drilling fleet of 260 rigs, 13% more than at the end of 2005.
 
  —    Precision commenced the construction of two service rigs under a long-term customer arrangement, for deployment in the first half of 2007.
 
  —    The snubbing, camp and catering and rental divisions grew existing product lines in response to market conditions.
 

 

Augment Customer Services
•   On August 17, 2006 Precision acquired a wastewater treatment business for remote work sites which complements our camp and catering and wellsite rental businesses and enhances our level of customer service.
Passionately Pursue Target Zero Safety Vision
•   Precision moved closer to its safety vision with a renewed focus on the basic elements of its health, safety and environmental program. The improvement in safe work practices continued for Precision, resulting in a 28% reduction in workplace injuries.
Build Upon Our Core Group of People
•   A North American shortage of skilled and experienced oilfield employees carried into 2006. Precision focused on the retention of existing employees through initiatives that provide a safe and productive work environment, opportunity for advancement and added wage security through programs such as our Designated Driller Program.
 
•   The Canadian drilling industry has taken an important step forward with the 2006 commencement of a compulsory journeyman trade program through the Alberta government, the rig technician designation, the first of its kind in the world. Precision has been involved in the development of this initiative from the beginning.
 
•   Precision continued to transition executive roles through a succession process that began in September 2005. Precision announced in October 2006 that its founder, Hank Swartout, would relinquish his position as Chief Executive Officer and assume the role of Executive Chairman effective January 1, 2007. Precision has initiated and continues to develop a more involved strategic planning process.
 
•   Precision completed its internal control certification over financial reporting pursuant to Canadian and United States securities regulations. The initiative was led through internal efforts that sharpened our awareness of the joint code of business conduct and ethics policy and provided numerous opportunities for Precision’s management to build upon its skill in identifying and managing risk.
Cash Distributions to Unitholders
•   With its conversion to an income trust on November 7, 2005 Precision converted from a cash retention to a cash flow-through model. For 2006, Precision’s first full year as an income trust, Precision declared cash distributions of $447 million or $3.56 per unit.
 
•   Distributable cash from operations of $495 million resulted in a cash distribution declared payout ratio of 90% for 2006. This calculation starts with $610 million in cash provided from operations less $92 million for productive capacity maintenance capital expenditures and $23 million for unfunded long-term incentive plan obligations. The remaining $48 million was retained to fund other investing and financing activities.
In summary, 2006 was a very successful year for Precision. We delivered record-setting financial and safety results through our industry leading market position and operational processes. We generated growth opportunities in our core Canadian market area and we established a new growth platform in the United States drilling market.
In form, our new capital structure as an income trust had an excellent start in 2006. Strong operating cash flow performance led to $472 million declared distributions to unitholders. At this level, the maximum flow-through potential of Precision’s underlying pre-tax income was obtained. The remaining taxable income in the subsidiaries of Precision Drilling Trust led to a 2006 current income tax expense of $35 million.
By the fourth quarter of 2006, strong business fundamentals were showing clear signs of being eroded as the volatility and declining trend in natural gas pricing slowed customer demand from record levels and downward pressure on pricing for the oilfield service industry was experienced. While customer pricing for Precision has held at record rates, declining demand and the additional supply of new industry equipment resulted in lower utilization to begin 2007 and lower pricing is expected to follow once the seasonal “spring break-up” begins in March. Through the first two months of 2007 drilling rig operating days were 19% lower than 2006 even though Precision’s fleet was

 

 

5% larger. For Precision’s service rig fleet in the Western Canada Sedimentary Basin (“WCSB”), operating hours for the first two months of 2007 were 15% lower.
Deteriorating business conditions in Canada were compounded by the Government of Canada’s tax announcements on October 31, 2006 and its clarification regarding normal growth for income trusts on December 15, 2006.
•   If the proposed measures are enacted into law, effective January 1, 2011, the current underlying flow-through status of Precision’s current income trust structure will be ended. The proposed amendments have negative implications for certain unitholders of Precision commencing in 2011, particularly Canadian tax-exempt investors, foreign investors and tax-exempt entities.
 
•   Nonetheless, Precision’s operational business model remains intact.
 
•   Precision originally converted to a trust because 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 the proposed legislative changes, it is incumbent on the Board of Trustees to examine whether changes in the current legal structure and capital structure are appropriate and in the best interests of unitholders and, if so, when such changes should be implemented.
Monitoring of the current operating environment in North America is also warranted as a significant quantity of new equipment is under construction and Precision’s level of customer demand uncertainty is higher than it has been in the past five years. This shift in momentum is not new. Precision operates in the cyclical energy sector and our business model has evolved to ensure that we are in a position to take advantage of opportunities through all stages. Given the competitiveness and inherent risk factors involved, Precision’s strategy is patience, flexibility, financial prudence and opportunism.
A strong balance sheet has been a key performance driver for Precision over the years. Low debt levels at the peak and bottom of a cycle enabled Precision to cope with lower operating cash flows and provided the financial leverage to invest in meaningful growth as opportunities arose. The Canadian oilfield service sector has undergone significant growth in equipment supply due to a surge in natural gas well drilling over the past five years. Declining demand conditions in 2007 have created excess drilling rig capacity and a severe drop, or persistent decline in demand, may result in opportunities for industry consolidation.
(HISTORIC LEVELS GRAPH 2)
Currently, Precision’s financial performance is heavily dependant on industry fundamentals within Canada. These fundamentals are 70% weighted towards natural gas wells and the volatility that exists with seasonal shifts and customer spending associated with the WCSB.
For 2007, Precision’s strategy remains focused on opportunities in Canada and the United States and 2006 developments are expected to move Precision forward in a more competitive marketplace.
Precision’s growth strategy is to diversify our earnings base so that Precision is active in many of the significant oil and natural gas basins in North America. Our participation in these basins is focused on providing our customers with a level of service and capability that sets our performance apart from the competition. Just as Precision has become a prominent SAGD driller for major projects in Canada’s oil sands, our participation in the United States through two drilling rigs is setting the stage for further opportunity.
For the past two years, growth has been achieved through the construction of new drilling rigs. The type of rig being built by Precision is a long-term investment geared toward performance and the lowering of customer well costs. These versatile rigs are of a type and design that is capable of drilling in North America’s unconventional resource areas and in many other areas of the world.
The U.S. drilling rig count is about three times larger than Canada’s. At present, Precision is a substantial Canadian oilfield service company and the dominant player with 29% and 23% of the drilling and service rig markets, respectively. For Precision, the United States is an untapped growth area that has been renewed by unconventional natural gas production. For the first time in Precision’s history, the company is working to establish permanent operations in the United States, a market that today has approximately 2,300 drilling rigs. We are moving in this

 

 

direction even though we expect rig demand in the United States to moderate. If this occurs, we believe that rigs with poor mobility and old components will find it difficult to compete. This high grading of equipment plays into Precision’s operational strategy.
Drilling and service rigs make up approximately 90% of Precision’s revenue and have always been the core business platform and areas of expertise for the company. Precision is planning to work within core customer relationships to broaden market opportunities in North America. We are focused on equipment that moves technology and processes forward to minimize costs and enable customers to exploit the full oil and natural gas potential of their land holdings.
SUMMARY OF CONSOLIDATED STATEMENTS OF EARNINGS
(Stated in thousands of Canadian dollars)
                         
Years ended December 31,   2006     2005     2004  
 
Revenue:
                        
Contract Drilling Services
   $ 1,009,821     $ 916,221     $ 727,710  
Completion and Production Services
     441,017       369,667       313,386  
Inter-Segment Elimination
     (13,254 )     (16,709 )     (12,608 )
 
 
     1,437,584       1,269,179       1,028,488  
 
Operating earnings (loss):
                        
Contract Drilling Services
     473,624       404,385       282,315  
Completion and Production Services
     163,119       121,643       77,074  
Corporate and Other
     (41,464 )     (60,650 )     (28,076 )
 
 
     595,279       465,378       331,313  
 
Interest, net
     8,029       29,270       46,280  
Premium on redemption of bonds
     —       71,885       —  
Loss on disposal of short-term investments
     —       70,992       —  
Other
     (408 )     —       (4,899 )
 
Earnings from continuing operations before income taxes
     587,658       293,231       289,932  
Income taxes
     15,146       72,383       101,801  
 
Earnings from continuing operations
     572,512       220,848       188,131  
Discontinued operations, net of tax
     7,077       1,409,715       59,273  
 
Net earnings
   $ 579,589     $ 1,630,563     $ 247,404  
 
(REVENUE AND OPERATING GRAPH 3)
For the year ended December 31, 2006, Precision’s earnings from continuing operations were a record $573 million or $4.56 per diluted unit compared to $221 million or $1.76 per diluted unit in 2005. In the prior year, earnings from continuing operations were reduced by one-time charges of $160 million or $1.04 per diluted unit, net of tax. The lower effective income tax rate as an income trust and enacted tax rate reductions contributed an increase over the prior year of $1.21 per diluted unit. The remaining increase of $0.55 per diluted unit was due in large part to pricing and activity strength in the first half of 2006. West Texas Intermediate (“WTI”) crude oil averaged US$66.11 per barrel in 2006 versus US$56.49 in 2005 and Henry Hub natural gas averaged US$6.73 per MMBtu in 2006 versus US$8.95 in 2005.
Natural gas prices in North America peaked in December 2005 at US$15.39 per MMBtu and declined to about half that level by December 2006. There were 7% fewer wells (22,575) drilled in western Canada from the record in 2005 and only the first quarter showed a year-over-year increase from 2005 drilling.
Despite a decline in wells drilled, the 158,416 industry operating days were slightly higher than 2005 and established a new record for Canada’s drilling contractors. Deeper drilling and fewer shallow gas and coal bed methane wells increased the average operating days per well by 8% from 6.5 to 7.0 in 2006.

 

 

Higher oil prices and lower gas prices prompted some customers to shift drilling dollars to oil prospects in 2006 which led to the most oil completions since 1997. The increase in well licenses issued for oil targets was not enough to offset a decline in conventional gas permits and an even bigger drop for coal bed methane wells. Oil licenses reached 6,770, the most since 2000, while permits to drill for gas declined 15% to 18,270.
The year ended on a weak note as the spot price for natural gas decreased amid concerns over high gas storage levels and expectations of a warm winter in North America. Oil prices also retreated in the fourth quarter from a record high in July but remained relatively strong. Henry Hub natural gas spot prices ranged from a fourth quarter high of US$8.45 per MMBtu to a low of US$3.62 on September 29, 2006, compared to a range of US$15.39 to US$8.79 in the same quarter of the prior year. The one-year forward price for North American natural gas weakened to trade in a range of approximately $6.50 to $8.50 on Canadian and U.S. exchanges in the quarter. During 2006, the persistent downward trend in commodity prices, natural gas in particular, led to lower demand in the fourth quarter for all of Precision’s services in western Canada.
OUTLOOK
The oil and gas industry in Canada lost momentum as 2006 progressed after four years of growth in operating and financial results. The hurricane devastation in the U.S. Gulf Coast in September 2005 created a strong pricing environment for 2006 natural gas drilling activity, however, a persistent downward trend in natural gas pricing adversely affected second half activity levels in the WCSB. The backlog of drilling work quickly depleted and fourth quarter activity was the lowest since 2002.
Fundamentally, we believe there is too much gas in storage in the short term and not enough supply in the long term which should ultimately lead to a recovery in drilling activity.
Clearly, there is negative sentiment toward anticipated drilling levels in 2007. The year is likely to yield far more uncertainty as companies reduce spending because lower cash flows in conjunction with higher finding and development costs are undermining the economics of gas drilling in the WCSB.
Increasingly, Precision’s results are driven by the fundamentals for natural gas production and consumption in North America. Moderate gas consumption during the past two winters has left storage levels in the United States trending higher than the five-year average. This has caused natural gas commodity prices to decline and generally customer cash flows have followed, with significant declines reported in the fourth quarter of 2006 as compared to the fourth quarter of 2005. This downward trend has reduced drilling economics and many of Precision’s large customers with global operations have reduced their 2007 Canadian drilling budgets.
For 2007, the operating environment for Precision will be challenging. While customer pricing for drilling rigs has held to begin the first quarter, there are signs of market deterioration. For January and February 2007, industry gas well licensing in western Canada is down approximately 30% over 2006. In this same period, Precision’s drilling and service rigs have been less active by 19% and 15%, respectively. Customer pricing in the spot market for available equipment is lower than winter 2006/2007 rates. The commissioning of previously announced new equipment will increase industry capacity. With lower 2007 drilling budgets for many of Precision’s large customers, Precision will have a higher proportion of its drilling rig fleet available for spot market work than it has had for the previous three years. Further, inflationary pressures from Alberta’s strong economy and an active U.S. drilling industry are expected to increase operating costs and maintenance capital expenditures per drilling operating day.
The shallow gas market was the most affected by the slowdown in activity but it also has the potential to recover quickly in response to higher natural gas prices. Deeper drilling programs tend to require more lead time and will typically react more slowly to a recovery in commodity prices.
Drilling activity trends influence well completion work and commodity prices influence the servicing or workover of existing oil and natural gas wells in production. For Precision’s service rigs in 2007, reduced drilling rig activity is expected to lower completion work. Early indications are that workovers for conventional oil and heavy oil wells are reasonably firm, however, Precision does not expect this to be enough to compensate for lower activity for producing gas wells.

 

 

As of March 9, 2007, the supply and demand fundamentals for North American natural gas are beginning to show cause for optimism. Winter consumption of gas over the first two months of 2007 has lowered United States natural gas storage from prior year levels by approximately 10%. The AECO spot price for Alberta natural gas was 18% higher than a year ago at $7.44 per Mcf and the NYMEX 12-month strip natural gas price of US$8.09 was essentially flat.
While these developments are positive, Precision believes it will take time for its customers to realize higher cash flows and increase their drilling and well servicing expenditures over prior year levels. Looking ahead, high natural gas consumption for summer cooling, weather related natural gas supply disruptions in the Gulf of Mexico and a slowing of U.S. gas drilling could have a favourable impact on natural gas commodity prices and result in higher Canadian drilling activity. To the extent that these events are unfavourable, the increasing rate of decline for new producing wells in North America lowers the supply of gas and eventually should result in higher drilling activity.
Precision remains positive on the medium to long term fundamentals for the North American onshore drilling industry. With a strategy to broaden its market presence and diversify into the United States, Precision intends to deploy rigs from its Canadian fleet for core customers to the major producing basins.
As producers struggle to increase output and growth in oil and gas consumption exceeds new supply, capital spending cutbacks will have a material impact on field productivity and set the stage for recovery. With a recovery as early as winter 2007/2008, a continuing trend in deep natural gas plays and expanding in-situ oil sands development, Precision is well positioned with its large, versatile fleet of rigs and support services.
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 Precision’s long-term strategy, opportunities, financial performance and distribution potential.
GLOBAL MARKETS
For more than a century, global economic growth and prosperity has been largely driven by energy consumption. In that time, crude oil and natural gas have proven to be the cheapest and most versatile sources of energy. Oil and its by-products provide fuel for virtually all of the world’s automobiles while oil and natural gas are primary fuel sources for generating heat and electricity and are critical building blocks for countless consumer products.
With 6 billion people worldwide and the population expected to rise by another 1.5 billion in the next 20 years, global energy demand is unprecedented and rising. Energy consumption is predicted to rise 50% to 60% by 2030, as illustrated below, with oil, natural gas and coal meeting approximately 80% of demand. World oil consumption is predicted to rise 1.6% in 2007 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 one of the major challenges society faces in this century.
(WORLD MARKETED PERIOD GRAPH 4)
There is growing concern about the connection between burning fossil fuels and climate change. In February 2007, the United Nation’s Intergovernmental Panel on Climate Change reiterated calls for action on fossil fuel consumption citing the links to hotter temperatures and rising sea levels. As environmental concerns over carbon dioxide emissions increase, natural gas becomes a more appealing fuel choice, particularly for electricity generation as it is less carbon intensive than traditional fuel sources such as coal. Despite the environmental challenges, crude oil and natural gas are the world’s primary energy sources. History has proven it takes decades, if not centuries, to displace energy sources and hydrocarbon production will remain crucial to the world’s energy needs for the foreseeable future.
NORTH AMERICAN MARKETS
Economics of the oilfield service industry are aligned with global and regional fundamentals. Important regional drivers for the industry in Canada include the underlying hydrocarbon make-up of the WCSB and the existence of an established, competitive and efficient service infrastructure. Natural gas production increasingly drives
 

 

economics in the WCSB as approximately 70% of new well completions in 2006 targeted natural gas. Drilling activity in the WCSB is split between the provinces with approximately 75% in Alberta, 15% in Saskatchewan and 10% in British Columbia. Areas of Canada’s north hold significant future promise but remain largely untapped frontier opportunities pending government and community support.
The hydrocarbon structure of the WCSB is diverse. Conventional oil and natural gas reservoirs exist at a variety of depths which are comparatively shallow by global standards. These conventional sources are accompanied by more costly and challenging unconventional reservoirs associated with oil sands, heavy oil, coal bed methane and natural gas in deeper, low permeability formations.
A vast natural resource base and next-door proximity to the world’s biggest energy consumer have helped Canada to become the world’s eighth largest oil producer and third largest producer of natural gas. With oil sands development, Canada is one of the few countries with growing petroleum production.
A highly integrated continental energy transportation system and free-market access to U.S. markets has made Canada one of the largest energy providers to the United States. Approximately half of Canadian oil and gas production is exported to the United States.
ECONOMIC DRIVERS OF THE OILFIELD SERVICES BUSINESS
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 jobs. The revenue for 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 due to restrictions on overseas transportation capabilities.
The emergence of liquefied natural gas (“LNG”) is an important new source of supply to North America that could offset production declines from mature reservoirs and help meet rising 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.
Over the past two years, rising demand, tight supply and concern over political and weather factors disrupting supply have driven commodity pricing to record levels. The dramatic price rise over a relatively short period has created uncertainty over the sustainability of high cash flows in the industry. Cash flows are critical to replacing production in the upstream sector.
(WTI OIL GRAPH 5)
Oil prices, which rose above US$78 per barrel in July 2006, are impacted by global factors such as worldwide economic growth, political and social unrest in major producing regions, global weather patterns, policies of the Organization of Petroleum Exporting Countries, commodity market speculation and industrialization in developing countries.
Natural gas, which peaked in North America at US$15.39 per MMBtu in December 2005, is impacted by factors such as regional economic activity, oil prices, commodity market speculation and, most significantly, the severity of weather in the major population centres across North America.

 

 

There is currently a narrow supply-demand balance. Many industry observers believe a new pricing floor is being set due to the combination of production declines and demand growth. New hydrocarbon reserves are clearly more costly and difficult to discover and develop. It has taken record drilling activity over the last three years in North America to maintain overall natural gas production levels. The following illustration demonstrates declines in WCSB new well productivity.
(WCSB NEW NATURAL GAS GRAPH 6)
The graph for western Canada above suggests more wells will be required to meet supply needs. In the WCSB, incremental new gas well production has decreased with the development of shallow gas reservoirs. With record drilling in the last two years (17,769 gas wells in 2005 and 15,640 in 2006) new gas wells only produced an average 215 Mcf per day in 2006 compared with 740 Mcf per day in 1996. In the 1990s the industry drilled approximately 10,000 wells per year in Canada. In this decade the number of wells has averaged approximately 20,000 per year. Natural gas drilling represented approximately 38% of the wells drilled in the 1990s compared to 67% of the wells drilled in the current decade.
Onshore North America is characterized by mature conventional oil and natural gas basins that require substantial activity to maintain or enhance production.
(NUMBER OF PRODUCING GRAPH 7)
Rising energy demand coupled with depletion of conventional resource basins has created an historic shift in the oil and gas industry in North America to develop “unconventional” resources such as oil sands, natural gas in shale and coal bed methane. Unconventional reservoirs tend to be more challenging and expensive to develop than conventional oil and gas reservoirs and generate more service activity. The biggest unconventional resource in Canada is the estimated 179 billion barrels of oil reserves in northern Alberta’s oil sands. There are also large reserves of coal bed methane and shale gas in Canada and the United States. The economics of unconventional resource plays require significant dependence upon technology such as multi-well pad locations, slant 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. The result is drilling activity must stay level or increase just to maintain current production and it is leading producers to drill deeper resource plays looking for large gas fields to extend reserve life.
(WESTERN CANADIAN GRAPH 8)
The graph above depicts the increase in natural gas completions over the past 10 years and the correlation to gas pricing. Two successive mild winters have led to high levels of gas in storage and a corresponding decline in price.
With growing energy demand, the supply of drilling rigs in Canada increased steadily over the past 13 years to an all-time high of approximately 850. Customer demand, measured by drilling rig operating day utilization, peaked at 71% in 1997 and has since ranged between 38% and 60%. Industry utilization was 55% for 2006. Higher utilization levels in 2005 and early 2006 prompted drilling contractors to add rigs. Many of the new rigs are telescopic doubles, singles or hybrid coil tubing rigs which are geared to shallow drilling and peak winter demand. In the long term, the larger fleet provides capacity to drill more wells through better year-round utilization. In order to sustain an industry operating day utilization rate of 55%, assuming seven operating days per well and 850 available rigs, there would need to be almost 24,500 wells drilled in the WCSB in 2007. The CAODC is currently estimating that only 19,023 wells will be drilled in 2007.
(ACTIVE GRAPH 9)
Approximately 72 drilling rigs were added to the Canadian fleet during 2006, a 9% increase to the total. Despite market softness expected for much of 2007, long-term customer demand to drill conventional oil and gas wells, in combination with improving commercialization of coal bed methane, oil sands and tight gas formations will drive future rig demand.
Just as natural gas is a North American commodity so too are drilling rigs. Many rigs are able to work in Canada or the United States and it is notable that the Canadian drilling rig count is at an all time high and the U.S. rig count is approximately half the capacity of the early 1980s. As illustrated above, Canadian rig activity fluctuates with the seasons, a phenomenon which generally does not occur in the United States.

 

 

PRECISION’S DEVELOPMENT
PRECISION’S HISTORY OF CONTINUING OPERATIONS
Precision’s history began in western Canada as a land drilling contractor in the 1950s. Through a series of acquisitions over the years, along with organic growth in its service lines, Precision has established itself as Canada’s largest oilfield services provider.
Precision Drilling Corporation was founded in 1985 as Cypress Drilling Ltd. and grew from four drilling rigs to 19 with the reverse takeover in 1987 of Precision Drilling Ltd., the company originally formed in 1952.
In the decade following the takeover, a series of acquisitions expanded Precision’s Canadian drilling fleet 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 drilling rig fleet. Today, after strategic new rig builds and decommissioning, Precision’s 240 drilling rigs in Canada comprise approximately 29% of the market.
To support the expanded rig fleet Precision acquired a number of complementary businesses. In 1993, Precision entered the camp and catering business with the acquisition of LRG Oilfield Services Ltd. Along with camps from the drilling rig business acquisitions and the purchase in 2003 of McKenzie Caterers (1984) Ltd., this division now has 101 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 acquisitions of Columbia Oilfield Supply Ltd. and a number of other oilfield equipment companies followed in 1997.
Diversification into businesses that would become Precision Well Servicing, Live Well Service and Precision Rentals began in 1996 with the acquisition of EnServ Corporation that set the stage for a broadened asset base and future growth. 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 of 28%. Today, Precision has 237 service rigs and 26 snubbing units that account for approximately 23% and 30% of their respective markets. 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.
(RIG GROWTH GRAPH 10)
STRATEGIC DIRECTION
Precision is tightly integrated in terms of operations, safety, engineering, information technology, accounting and senior management. Each segment has experienced asset growth and performs a lead market role. Communication is a skill that has been refined and ingrained in Precision’s operating culture while continuously focusing on safety initiatives to eliminate workplace incidents. These attributes provide Precision with the ability to pursue the following strategic initiatives as key factors in maximizing the value proposition for its unitholders:
•   maintain a flexible business that is responsive to market conditions;
•   exploit technological advances where markets dictate;
•   focus on organic growth opportunities to enhance and diversify service offerings;
•   capitalize on strategic and accretive acquisitions both geographically and operationally;
•   develop and enhance employee safety, recruitment and retention initiatives;
•   upgrade equipment with customer needs and regulatory requirements in mind; and
•   apply operational and financial discipline throughout all areas of the business.
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:
      Commodity Prices: Precision monitors the spot and forward prices for oil and natural gas as these prices impact customer cash flow and funds for capital programs which govern land acquisition, well licensing and future drilling, and well servicing activities.

 

 

      Customer Demand: Precision matches the availability of its equipment with customer budgets and drilling programs. Precision’s fleet is geographically dispersed to meet customer demands. Relationships with its customers, industry knowledge and new well licenses provide Precision with the necessary information to evaluate its marketing strategies. Industry rig utilization statistics are tracked to evaluate Precision’s performance against competitors.
      Workforce: Precision’s employees are its most important asset. 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. Target Zero reinforces Precision’s safety vision and safety statistics are used to benchmark its performance. Precision relies heavily on its safety record to attract new employees.
      Operating Efficiency: Precision’s revenue is a component of an oil and gas company’s finding and development costs. 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 during operations. These factors contribute to lower customer well costs.
      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.
      Expansion Capital Spending: Precision evaluates growth opportunities based on internally established rate of return targets. New drilling rig expansion is typically based on predetermined activity levels over a fixed term operating contract.
OPERATING SEGMENTS
Precision is divided into two operating segments to effectively manage its business, Contract Drilling Services and Completion and Production Services.
The Contract Drilling Services segment is comprised of the following:
•   Precision Drilling which provides land drilling services utilizing 240 drilling rigs, approximately 29% of the Canadian industry;
 
•   Precision Drilling Oilfield Services, Inc. which provides land drilling services in the United States and established operations in June 2006 with one rig;
 
•   LRG Catering which supplies camp and catering services with 101 camps, approximately 16% of the industry;
 
•   Rostel Industries which provides engineering, machining, fabrication, component manufacturing and repair services for drilling and service rigs; and
 
•   Columbia Oilfield Supply which provides centralized procurement, standardized product selection, and coordinated distribution of goods for Precision’s operations.
 
The Completion and Production Services segment is comprised of the following:
 
•   Precision Well Servicing which provides well completions and workovers with 237 rigs, approximately 23% of the industry service rigs;
 
•   Live Well Service which performs well completions and workovers with 26 snubbing units, approximately 30% of the industry;
 
•   Precision Rentals which supplies approximately 15,000 rental equipment items including well control equipment, surface equipment, specialty tubulars and wellsite accommodation units representing approximately 10% of the industry; and

 

 

•   Terra Water Systems Limited Partnership which operates 51 wastewater treatment units, representing approximately 10% of the industry.
Precision Drilling
The following table lists the drilling depth capability of Precision’s and industry’s Canadian drilling rigs in the WCSB as at December 31, 2006:
                                                         
            Precision Fleet     Industry Fleet(1)  
    Maximum                     %                    
    Depth Rating     Number     % of     Market     Number     % of        
Type of Drilling Rig   (metres)     of Rigs     Total     Share (3)     of Rigs     Total     Change(4)  
 
Single
     1,200       14       6       10       145       17       21  
Super SingleTM (2)
     3,000       28       12       85       33       4       9  
Double
     3,000       94       39       26       364       43       20  
Light triple
     3,600       44       18       38       117       14       3  
Heavy triple
     6,700       49       20       42       118       14       11  
Coiled tubing
     1,500       11       5       17       65       8       8  
 
Total
             240       100       29       842       100       72  
 
(1)   Source: Daily Oil Bulletin – Rig Locator Report as of January 2007. Precision has allocated the industry rig fleet by rig type.
 
(2)   Super SingleTM excludes single rigs that do not have automated pipe-handling systems, or do not have a self-contained top drive, or cannot run range 3 drill pipe/casing.
 
(3)   Market share means Precision’s rigs as a percent of the industry’s rigs.
 
(4)   Change in number of industry rigs as compared to the prior year.
The table below summarizes the capabilities of Precision Drilling’s North American drilling rig fleet for the past four years:
                                                         
    Maximum Depth Rating                                
Type of Drilling Rig   Metres     Feet     Horsepower     2006     2005     2004     2003  
 
Single
     1,200       4,000       250-300       14       17       16       18  
Super SingleTM
     3,000       10,000       400-600       29       21       21       15  
Double
     3,000       10,000       300-500       94       94       95       96  
Light triple
     3,600       12,000       500-750       44       44       45       47  
Heavy triple
     6,700       22,000       1,000-2,000       49       43       41       39  
Coiled tubing
     1,500       5,000       250-300       11       11       11       10  
 
Total
                             241       230       229       225  
 
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   Horsepower     2006     2005     2004     2003  
 
Singles:
                                        
Mobile
     150-400       12       17       19       30  
Freestanding mobile
     150-400       92       88       86       75  
Doubles:
                                        
Mobile
     250-550       44       44       42       46  
Freestanding mobile
     200-550       9       8       9       6  
Skid
     300-860       65       65       67       66  
Slants:
                                        
Freestanding
     250-400       15       15       16       16  
 
Total
             237       237       239       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 based in large part upon the ability to deliver.
Large Diversified Rig Fleets
Precision’s large diverse fleet of rigs is strategically deployed across the most active regions of the WCSB. When an oil and gas company needs a specific type and 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 drilling rigs have varying configurations and capabilities, with drilling depth capacities of up to 6,700 metres. Rig categories where Precision dominates correlate well with future drilling opportunities. Deeper depth rigs target foothills natural gas, while Super SingleTM rigs are effective in shallow to medium depths including oil sands and heavy oil drilling.
Precision’s service rigs provide completion, workover, abandonment, well maintenance, high pressure and critical sour 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 stand alone. Stand alone 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 due to 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 15,000 pieces of specialized equipment and wellsite accommodations.
Industry-leading Safety Program
Safety is critical for Precision and its customers. In 2006, almost 300 rigs and four Precision business units achieved Target Zero, Precision’s safety vision for eliminating workplace incidents. Precision is a leader in adopting technological advancements which have made drilling rigs, service rigs and snubbing units safer.
Well-maintained Equipment
Precision consistently reinvests capital to sustain and upgrade existing property, plant and equipment – its productive capacity maintenance.
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 technology 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 only 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 accounting system has improved business performance through real-time access to information across all functional areas of the company. All divisions operate on a common integrated system using standardized business processes across finance, payroll, equipment maintenance, procurement and inventory control.

 

 

FINANCIAL RESULTS

CONTRACT DRILLING SERVICES SEGMENT
(Stated in thousands of Canadian dollars, except where indicated)
                                                 
            % of             % of             % of  
Years ended December 31,   2006     Revenue     2005     Revenue     2004     Revenue  
 
Revenue
   $ 1,009,821             $ 916,221             $ 727,710          
Expenses:
                                                
Operating
     470,713       46.6       448,930       49.0       382,886       52.6  
General and administrative
     27,225       2.7       23,911       2.6       19,190       2.6  
Depreciation
     38,573       3.8       39,233       4.3       42,245       5.8  
Foreign exchange
     (314 )     —       (238 )     —       1,074       0.2  
 
Operating earnings (1)
   $ 473,624       46.9     $ 404,385       44.1     $ 282,315       38.8  
 
                                                 
            % Increase             % Increase             % Increase  
    2006     (Decrease)     2005     (Decrease)     2004     (Decrease)  
 
Number of drilling rigs (end of year)
     241       4.8       230       0.4       229       1.8  
Drilling operating days
     44,938       (4.3 )     46,937       12.8       41,625       (1.5 )
Drilling revenue per operating day ($/day)
     20,518       13.8       18,034       9.3       16,494       11.5  
Drilling statistics: (2)
                                               
Number of wells drilled
     6,180       (20.4 )     7,766       3.2       7,525       (11.0 )
Average days per well
     7.2       20.0       6.0       9.1       5.5       10.0  
Number of metres drilled (000s)
     7,810       (12.3 )     8,901       11.0       8,021       (6.8 )
Average metres per well
     1,264       10.3       1,146       7.5       1,066       4.7  
 
(1)   Non-GAAP measure. See page 66.
 
(2)   Canadian operations only.
2006 Compared to 2005
The Contract Drilling Services segment, in 2006, generated record financial results on the strength of improved pricing and the third highest total drilling days in company history. Revenue increased by $94 million or 10% over 2005 to $1.0 billion while operating earnings increased by $69 million or 17% to $474 million. Operating earnings increased to 47% of revenue in 2006 as compared to 44% in 2005. The operating earnings margin increase was primarily attributable to pricing established in the fourth quarter of 2005 and other pricing increases which held throughout 2006.
Operating costs declined from 49% of revenue in 2005 to 47% in 2006. On a per operating day basis, costs increased slightly due to higher crew wages and cost of materials. Lower equipment utilization increased the per operating day cost associated with fixed operating cost components. Variable costs are controlled through extensive analysis and cost awareness. This combined with the ability to mitigate cost escalations through volume purchasing and relationships with suppliers further enhanced profitability.
The momentum in activity that started to build at the beginning of the third quarter of 2005 continued through the winter drilling season and the start of the 2006 spring break-up. The first half of 2006 was one of the strongest drilling periods on record for the WCSB. However, a persistent downward trend in the natural gas price over the second half of 2006 adversely affected activity levels as the backlog of drilling work quickly depleted and the fourth quarter saw the lowest fourth quarter activity since 2002.
Activity for drilling rigs was down 1,999 operating days, a 4% decline from the prior year. The first half of 2006 showed increases in drilling levels over 2005 with the third quarter only marginally lower due largely to wet weather in September. At the end of the third quarter, Precision was on track to surpass the record drilling activity established in 1997. That would not happen, however, as operators rig released only 5,484 wells in the final quarter of 2006, down 25% from a year earlier.

 

 

The decline in natural gas prices contributed to lower active rig counts in the second half of 2006 compared with 2005. Coupled with the expanded industry fleet of 9%, to approximately 842 at year end, the drilling rig operating day utilization fell to 43% in the fourth quarter of 2006 from 68% in the same period of 2005.
During the year, Precision commenced operations in the U.S. land based contract drilling market. In June, Rig 297 was mobilized from the Canadian fleet to Texas to begin work under contract.
Capital expenditures for the Contract Drilling Services segment in 2006 were $220 million and included $158 million to grow and expand the underlying asset base and $62 million to sustain and upgrade existing equipment. The majority of the expansion capital expenditure was associated with new drilling rig construction.
The Precision Drilling division set new financial benchmarks in 2006. Revenue increased by $73 million or 9% over 2005 to $919 million. The decrease in activity for 2006 was more than offset by increased rates. Precision commenced 2006 with 170 rigs drilling as operators shortened the Christmas shutdown period to get an early start on winter drilling programs. The first quarter provided the industry with ideal winter drilling conditions as cool temperatures kept the frost in the ground but it was not cold enough to hinder field operations. This unprecedented rig demand and near perfect weather conditions provided an excellent start to the year.
Cold weather in the latter part of March 2006 prolonged the winter drilling season. This enabled rigs to spud late in March and allowed deeper-rated rigs to work into the spring. The first sign of a slowing shallow gas market appeared in the second quarter, particularly with coil tubing and single rigs in southeastern Alberta. The demand for triples was able to offset the shortfall in shallow gas drilling as operating days in the second quarter reached the third highest level in the last 10 years. The triple rig activity in the second quarter was more than 50% higher than the prior year. Strength in the triple rig market at that time reflected customer commitment to deeper gas drilling.
Warm dry weather in western Canada in the third quarter allowed drilling operations to run as scheduled for most of the summer allowing the backlog of wells to be drilled. Drilling days for July and August were 169 days ahead of the previous year’s pace going into September 2006. Wet weather in September reduced the rig count and dampened drilling momentum. Precision still reported its third highest activity level in any third quarter in the last 10 years.
Fourth quarter 2006 results were hampered by activity declines attributable to commodity price uncertainties and constraints on customer’s 2006 exploration and production budgets. Rising costs and lower cash flows meant many customers had spent their entire 2006 budget by the start of the fourth quarter and they did not move 2007 drilling programs forward. The urgency to put rigs to work diminished as cautious spending developed despite increased rig availability.
Operating earnings in the Precision Drilling division increased by 17% over 2005 due mainly to a 14% increase in the average 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 new rig builds going into the field. Precision Drilling’s 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. There were also cost escalations for third party labour and materials associated with equipment maintenance programs. An important component of the success of the division is the degree to which cost structures were developed to be as variable as possible with activity levels. This flexibility allowed the division to respond quickly to sudden changes in equipment utilization and produce superior returns in periods of high or low activity.
The Precision Drilling division continued its organic growth strategy with the addition of 13 versatile rigs backed by customer arrangements. Precision spent $203 million in capital expenditures in 2006, close to twice the spending in 2005.
LRG Catering achieved a new record for activity and revenue in 2006. Activity grew by 11%, while revenue increased 25% due in part to rate increases implemented in the fourth quarter of 2005. Over the first eight months of 2006 activity remained at record levels then slowed in the last four months as commodity prices softened and deeper drilling programs were completed. LRG experienced a higher average day rate as a result of increased base camp activity. LRG is becoming a larger drilling camp and catering provider in western Canada, having expanded its fleet by 10 camps in 2006 to end the year with 101, representing about 16% of the market in western Canada.

 

 

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 is an essential extension of the purchasing process and provided timely, reliable and consistent quality supplies to keep Precision’s rigs operating and allowed Precision to standardize product use and quality.
Precision Drilling Oilfield Services, Inc. began operations in the United States in June 2006, with one rig. The rig was active 100% of the time. Growth is planned in the U.S. market through the construction of new rigs and by deploying additional rigs from Canada through customer arrangements.
2005 Compared to 2004
The Contract Drilling Services segment generated record financial results in 2005 on the strength of unprecedented drilling activity in western Canada and improved pricing for related services. The rise in activity strengthened on a comparative quarterly basis year over year for the prior three years. That demand enabled the Contract Drilling Services segment to steadily increase revenue and underlying operating margins.
The segment reported revenues of $916 million, $189 million more than 2004, an increase of 26%. These results were generated with an equipment fleet size that was relatively unchanged from the prior year. Revenue growth in 2005 was due to a combination of increased activity and pricing. Operating earnings increased by $122 million or 43% to $404 million. Operating earnings increased to 44% of revenue in 2005 as compared to 39% in 2004. The margin increase was primarily attributable to pricing improvements.
Operating expenses declined from 53% of revenue in 2004 to 49% in 2005, and on a per operating day basis, remained flat despite crew wage rate increases. Higher equipment utilization lowered the daily cost associated with fixed operating cost components.
Capital expenditures for the Contract Drilling Services segment in 2005 were $107 million and included $54 million to expand the underlying asset base and $53 million to sustain and upgrade existing equipment. The majority of the expansion capital expenditure was associated with new drilling rig construction.
For the Precision Drilling division revenue increased by $160 million or 23% over 2004 to $846 million. Just over half of the revenue growth was due to increased activity and the remainder to increased rates. The division entered the year with great anticipation as rig demand exceeded rig availability by a wide margin. Disappointing activity results for the first half of the year were strictly weather related. These activity levels caused customer drilling programs to fall behind. As ground conditions dried in July, the impact of the pent-up demand led to an outstanding third and fourth quarter in 2005.
Rig demand continued to build momentum through to the end of 2005. Overall, the industry benefited from the pricing leverage established from strong third quarter activity. Accordingly, increased pricing was established in the fourth quarter for the winter drilling season. Rig shortages also created a large spot market for operators who did not have equipment booked for the winter, enabling the division to raise rates.
Operating earnings for the Precision Drilling division increased by 46% due in part to the 13% increase in operating activity combined with the 9% increase in revenue per operating day. Depreciation expense for the year was $11 million lower due to the effects of a change in the estimated life of rig assets to 5,000 utilization days in 2005 from 4,150 in 2004. Precision Drilling was able to maintain its cost per operating day at its 2004 rate. Crew labour costs in 2005 comprised 52% of operating costs, up 2% from 2004. The 2005 cost of drilling, maintenance and overhead on a per day basis was consistent with 2004.
In the fourth quarter, two Super SingleTM Light rigs were added to the fleet and one rig was sold resulting in a rig count of 230 at the end of 2005.
LRG Catering experienced a 26% increase in camp days and a 40% increase in revenue over the prior year. The growing number of field personnel in the industry put overwhelming pressure on other accommodation sources, such as hotels. Customers compensated by utilizing camps in areas where crews would normally have returned to town for lodging. LRG grew its fleet in 2005 by adding five new six-unit camps.

 

 

COMPLETION AND PRODUCTION SERVICES SEGMENT
(Stated in thousands of Canadian dollars, except where indicated)
                                                 
            % of             % of             % of  
Years ended December 31,   2006     Revenue     2005     Revenue     2004     Revenue  
 
Revenue
   $ 441,017             $ 369,667             $ 313,386          
Expenses:
                                                
Operating
     231,602       52.5       209,657       56.7       196,113       62.6  
General and administrative
     14,242       3.2       11,021       3.0       12,708       4.0  
Depreciation
     32,013       7.3       27,402       7.4       27,508       8.8  
Foreign exchange
     41       —       (56 )     —       (17 )     —  
 
Operating earnings (1)
   $ 163,119       37.0     $ 121,643       32.9     $ 77,074       24.6  
 
                                                 
            % Increase             % Increase             % Increase  
    2006     (Decrease)     2005     (Decrease)     2004     (Decrease)  
 
Number of service rigs (end of year)
     237       —       237       (0.8 )     239       —  
Service rig operating hours
     480,137       0.6       477,232       1.1       472,008       7.4  
Revenue per operating hour ($/hour)
     712       18.7       600       17.0       513       11.0  
 
(1)   Non-GAAP measure. See page 66.
2006 Compared to 2005
The Completion and Production Services segment generated another year of record results on the strength of robust industry activity in western Canada and stronger pricing for services. Improved pricing resulted in a revenue increase of $71 million or 19% over 2005 to $441 million 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.
The number of wells rig released in 2006 was 22,575, a decrease of 7% from the record of 24,351 established in 2005. However, with a lag between the drilling and completion of a well, the industry reported a record 22,171 well completions for the year, an increase of 1% from 21,980 in 2005. The total well count for completions in western Canada was 97,164 for the last five years adding to the ongoing maintenance demand to ensure continuous and efficient operation of producing wells. There are currently about 190,000 producing wells within the WCSB.
Service rig contractors in western Canada have maintained the industry rig fleet count relatively constant over the past several years at approximately 1,050 service rigs as market pricing remained competitive.
The Completion and Production Services segment is also affected by seasonality in Canada. The first and fourth quarters of the year are the most active as colder weather allows for the unrestricted movement of heavy equipment on county and provincial roads. The first quarter traditionally produces the highest utilization as customers are able to work in northern areas that are only accessible at that time.
During 2006, Precision acquired Terra Water Systems, 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 the LRG Catering and Precision Rentals divisions and strengthened the diversity of Precision’s services.
Reinvestment in equipment in recent years has helped to position the Completion and Production Services segment as an industry leader. Excluding the business acquisition of Terra Water Systems, capital spending in 2006 was $39 million, an increase of 11% over 2005. The total included expansion capital of $13 million for new pump trucks, new slant service rigs, stand alone snubbing unit fabrication, wellsite accommodations, storage tanks and wastewater treatment units. Productive capacity maintenance expenditures of $26 million were incurred in the year and included 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. Higher rig rates and marginally improved activity levels over the prior year contributed to the higher revenue. Price increases established in the fourth quarter of 2005 were maintained with a slight upward adjustment in the fourth quarter of 2006.
Service rig activity was at record levels for the first three quarters of 2006 due to continued strong industry activity carried over from 2005 and the backlog of new well completions. However, wet weather in September and declining natural gas prices caused customers to reassess natural gas completion and workover programs. Oil well servicing was steady throughout the year as crude oil prices remained above US$50 per barrel. The strong first half of the year offset the activity decline in the fourth quarter resulting in 2006 exceeding 2005 by 2,905 operating hours, for 56% utilization.
Operating earnings for the division improved by $36 million, or 41%, over 2005, due mainly to service price increases. 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. Pump trucks, transporters and mobile doghouse replacements were completed primarily to replace aging units. The electronic upgrade of engines to include the latest emission control and fuel conservation standards was also undertaken. Carrier modifications were completed to reduce rig weights for travel during road ban periods. The construction of two new slant service rigs under long-term contract commenced in 2006 and, when commissioned in 2007, will bring the fleet to 239 rigs.
Live Well Service’s activity decreased by 14% over 2005 with revenues for the year of $35 million. The decrease was due to the weakening of natural gas prices in 2006 which led to a cost savings shift by customers away from rig assist and to stand alone snubbing services. Live Well’s snubbing fleet consists of 26 units of which 25 are rig assist with one stand alone unit. In the fourth quarter of 2006, construction started on four stand alone units, two under long-term customer contract, which will bring the total snubbing fleet to 30 units in 2007.
Precision Rentals generated revenues of $62 million, which was $11 million or 21% higher than in 2005. Each of Precision Rental’s three product categories; surface equipment, tubulars and well control equipment, and wellsite accommodations, 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 August 17, 2006. Growth is expected through product and market diversification, leveraging its synergies with LRG Catering’s remote camp business and Precision Rental’s wellsite accommodations.
2005 Compared to 2004
The Completion and Production Services segment generated revenue of $370 million, 18% higher than the $313 million in 2004 with operating earnings increasing by $45 million or 58% to $122 million. Operating earnings increased to 33% of revenue in 2005 as compared to 25% in 2004. The margin increase was attributable to the enhanced operating performance of the service rig fleet as the division was able to increase rates throughout the year. Equipment demand provided the ability to establish pricing levels based on possession rather than just usage.
Operating expenses declined from 63% of revenue in 2004 to 57% in 2005 and increased marginally per operating hour due to higher labour costs. Centralization of personnel, accounting, purchasing, and equipment management provided economies of scale and more effective deployment of segment resources.
Capital spending in 2005 was $35 million, an increase of 9% over 2004. This included expansion capital of $8 million for a stand alone snubbing unit, additional pump trucks, wellsite accommodations and storage tanks. Maintenance capital included replacement trucks for transporters, snubbing units and pump trucks as well as drill pipe for rental, snubbing equipment and a facility upgrade in Grande Prairie, Alberta.
The Precision Well Servicing division increased revenue by $44 million or 18% over 2004 to $286 million due to a slight increase in activity and higher rates. Precision Well Servicing achieved 55% utilization, a nominal

 

 

improvement over the prior year. Operating earnings improved by $38 million, a 79% improvement over the prior year due mainly to price increases. In addition, operating costs were marginally higher per operating hour year over year due to higher labour costs. Cost efficiencies were achieved by the consolidation of operating centres in the latter part of the prior year. Capital expenditures in 2005 emphasized the upgrading and standardization of equipment.
Live Well Service’s activity decreased slightly in 2005. The demand for snubbing, while finishing strong, slowed early in the year. However, revenue increased by $4 million or 12% over 2004 to $32 million. The improvement was attributable to higher hourly operating and standby rates established in the last half of the year. Live Well upgraded its fleet of hydraulic rig assist snubbing units through scheduled truck chassis replacement and introduced its first stand alone unit.
Precision Rentals reported a revenue increase of $8 million or 19% over 2004 to $51 million. The increase was attributable to higher drilling activity which led to higher demand and improved pricing for rental equipment. Operating earnings increased by 37% over the prior year. The division expanded its wellsite accommodation fleet in 2005 by 8% with the purchase of 24 units.
OTHER ITEMS
2006 Compared to 2005
Corporate and Other Expenses
Corporate and other expenses decreased by $19 million or 32% 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. The introduction of the long-term incentive plan (“LTIP”) added an additional $4 million of costs during 2006 over the prior period stock option plan expense, while increased accruals for recurring near-term incentive plans added another $3 million. 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 were 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. Also in 2005, Precision was in a significant surplus cash position, to the date of trust conversion, which generated $10 million in interest income. Monthly debt, net of cash, averaged $164 million in 2006.
Income Taxes
The Trust’s effective tax rate, before enacted tax rate reductions, on earnings from continuing operations before income taxes was 6% in 2006 compared to 25% in 2005. This comparatively low effective 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.
The Trust incurs taxes to the extent there are certain provincial capital taxes, as well as taxes on any taxable income, of its underlying subsidiaries, not distributed to unitholders. In addition, future income taxes arise from differences between the accounting and tax basis of the operating entities assets and liabilities.
During 2006 the federal and certain provincial governments enacted various reductions to corporate income tax rates. The Government of Canada passed legislation to eliminate the corporate capital tax, reduce the federal

 

 

income tax rate from 21% to 19% over the next four years and eliminate the federal corporate surtax in 2008. The Province of Alberta reduced the corporate income tax rate by 1.5% effective April 1, 2006. Enacted tax rate reductions resulted in a $21 million future tax recovery in the second quarter of 2006.
Discontinued Operations
A $7 million gain, net of tax, on discontinued operations was recorded in 2006. A $2 million gain was recorded on the final payment of contingent consideration associated with the 2004 disposal of United Diamond Ltd. Gains of $4 million and $1 million were recorded for working capital adjustments related to the 2005 disposals of CEDA International Corporation (“CEDA”) and the Energy Services and International Contract Drilling divisions, respectively. 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.
2005 Compared to 2004
Corporate and Other Expenses
Corporate and other expenses increased by $33 million or 116% in 2005 as compared to 2004. Included in these expenses are $18 million in costs associated with the conversion to an income trust comprising a one-time severance payment of $13 million to a senior executive and $5 million in legal, accounting and advisory fees. Excluding those costs, corporate and other expenses increased by $15 million or 53% year over year of which $6 million was attributable to a reduction in foreign exchange gains and the remaining $9 million to severance and retention bonus payments, increased legal and advisory fees related to other internal reorganization activities, examining strategic and financing alternatives, and increased internal and external audit costs to comply with financial reporting requirements.
Interest Expense
Net interest expense of $29 million declined by 37% in 2005 compared to 2004. This reduction was attributable to the repayment of the outstanding bonds (debentures) in October 2005 and from being in a surplus cash position, to the date of trust conversion, which generated $10 million in interest income.
Premium on Redemption of Bonds
In October 2005, the outstanding bonds were repaid, resulting in a charge of $72 million that was absent in 2004.
Loss on Disposal of Short-term Investments
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
During the third quarter of 2005, Precision completed two significant business divestitures. These businesses contributed $74 million in net earnings which have been included in discontinued operations. Combined with the gains on disposition in the amount of $1.3 billion, discontinued operations contributed net earnings of $1.4 billion towards the financial results in fiscal 2005. First, Precision disposed of its Energy Services and International Contract Drilling divisions, resulting in an after tax gain of $1.2 billion. Second, Precision disposed of the industrial services business carried on by CEDA for an after tax gain of $132 million.
Income Taxes
Precision’s effective tax rate on earnings from continuing operations before income taxes was 25% in 2005 compared to 35% in 2004. The decrease in the tax rate was primarily a result of the conversion to an income trust in November 2005 which had the effect of shifting the income tax burden of the Trust to its unitholders.

 

 

LIQUIDITY AND CAPITAL RESOURCES
In 2006, strong operating results combined with lower net debt levels provided the Trust with cash flows from operations of $610 million. Issuances of Trust units through the distribution reinvestment plan and increases in long-term debt and bank indebtedness added $70 million. An additional $7 million was provided from the settlement of matters relating to prior year dispositions. Offsetting these sources of cash, the Trust incurred capital expenditures, net of dispositions of capital assets and changes in related non-cash working capital, of $226 million and spent $16 million to purchase all the outstanding shares of Terra Water Group Ltd. Total cash distributions paid to unitholders during 2006 were $445 million.
The Trust exited 2006 with a long-term debt to long-term debt plus equity ratio of 10% and a ratio of long-term debt to cash from operations of 23%.
In the 2005 MD&A, the Trust gave guidance as to the expected 2006 amounts for certain balance sheet and cash flow items. Lower 2006 fourth quarter activity, which resulted in a reduction of $184 million to the expected working capital and profitability, was the primary factor leading to a positive variance of $260 million over estimated 2006 cash provided by continuing operations of $350 million. This positive variance combined with lower net productive capacity maintenance capital expenditures, which includes disposal proceeds of $29 million, led to long-term debt being $294 million lower than the $435 million estimate.
Precision has a number of committed and uncommitted lines of credit 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 borrowing capacity of the facility was increased by $150 million in 2006 to assist in financing the expansionary growth plans of Precision. 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, 2006, Precision was well within the financial covenant levels, and is expected to remain so for 2007. There was $141 million outstanding under the committed facilities at December 31, 2006. In addition to the committed facilities, Precision also has a number of uncommitted operating facilities which total approximately $66 million equivalent and are utilized for working capital management and the issuance of letters of credit.
The Corporation’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
   $ 140,880     $ —     $ 140,880     $ —     $ —  
Operating leases
     26,538       7,858       11,371       7,309       —  
Long-term incentive plan
     22,699       —       22,699       —       —  
 
Total contractual obligations
   $ 190,117     $ 7,858     $ 174,950     $ 7,309     $ —  
 
The Trust instituted the LTIP in 2006 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. The retention component is accrued evenly over the three-year term and is estimated to total $11 million with anticipated payment to occur in March 2009. The performance component is based on the growth in cash distributions measured against a base distribution rate as determined by the Compensation Committee of Precision. The performance component is accrued based on actual distributions compared to target distributions. There is no assurance that the performance component will be paid.

 

 

Outstanding Unit Data
                         
    February 28     December 31     December 31  
    2007     2006     2005  
 
Trust units
     125,570,432       125,536,329       124,352,921  
Exchangeable LP units
     187,492       221,595       1,108,382  
 
Total units outstanding
     125,757,924       125,757,924       125,461,303  
 
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 may be reduced, increased or suspended entirely depending on the operations of Precision and the performance of its assets, or legislative changes in tax laws by governments in Canada. 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; productive capacity maintenance expenditures 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 2006 cash distributions declared were $447 million or $3.56 per diluted unit. In December 2006, a special year-end in-kind distribution, as explained below, payable in Trust or exchangeable LP units (together “Units”), of $25 million or $0.195 per diluted unit was declared.
In the event that a distribution is declared in the form of in-kind Units, the terms of the Declaration of Trust and the Limited Partnership Agreement require 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 Unit distribution. As a result, Unitholders would not receive additional Units and the declared amount of the in-kind distribution would be retained in Precision.
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. A reconciliation of distributable cash from operations in 2006 is as follows:
                             
(Stated in thousands of Canadian dollars, except per unit amounts)   2006       2005       2004  
         
Cash provided by continuing operations
   $ 609,744       $ 206,013       $ 286,437  
Less:
                            
Productive capacity maintenance capital expenditures
     (92,123 )       (92,214 )       (82,014 )
Unfunded long-term incentive plan obligation
     (22,699 )       —         —  
         
Distributable cash from operations (A) (1)
     494,922       $ 113,799       $ 204,423  
                 
Cash retained
     (47,921 )                  
               
Cash distributions declared (B)
   $ 447,001  
                 
 
                        
Payout ratio (B)/(A)
     90.3%  
 
        
Distributable cash from operations per basic and diluted unit
   $ 3.94  
 
(1)   Non-GAAP measure. See page 66.
Fiscal 2006 was Precision’s first full year as an income trust. Management believes that any retained cash or payout ratio calculation for prior years would not be meaningful given the Trust’s November 2005 conversion.
Productive capacity maintenance 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 productive capacity maintenance 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.

 

 

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 productive capacity maintenance 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)   2006     2005  
 
Units outstanding
     125,757,924       125,461,303  
Year end unit price
   $ 27.00     $ 33.00  
 
Units at market
   $ 3,395,464     $ 4,140,223  
Long-term debt
     140,880       96,838  
Less: Working capital
     (166,484 )     (152,754 )
 
Enterprise value
   $ 3,369,860     $ 4,084,307  
 
Precision carried a long-term debt to unit market value ratio of 4% at December 31, 2006. This represents a slight increase over the 2005 ratio of 2%.

 

 

QUARTERLY FINANCIAL SUMMARY
(Stated in thousands of Canadian dollars except per diluted unit/share amounts)
                                         
Year ended December 31, 2006   Q1     Q2     Q3     Q4     Year  
 
Revenue
   $ 536,408     $ 223,569     $ 349,558     $ 328,049     $ 1,437,584  
Operating earnings (1)
     245,909       74,543       142,431       132,396       595,279  
Earnings from continuing operations
     224,183       88,303       133,552       126,474       572,512  
Per diluted unit/share
     1.79       0.70       1.06       1.01       4.56  
Net earnings
     224,183       88,303       139,667       127,436       579,589  
Per diluted unit/share
     1.79       0.70       1.11       1.01       4.62  
Cash provided by (used in) continuing operations
     40,940       339,619       74,952       154,233       609,744  
Distributions to unitholders – declared
   $ 101,623     $ 111,681     $ 116,785     $ 141,435     $ 471,524  
 
                                         
Year ended December 31, 2005   Q1     Q2     Q3     Q4     Year  
 
Revenue
   $ 383,407     $ 157,895     $ 300,016     $ 427,861     $ 1,269,179  
Operating earnings (1)
     153,020       24,505       111,956       175,897       465,378  
Earnings from continuing operations
     88,281       9,308       2,382       120,877       220,848  
Per diluted unit/share
     0.71       0.07       0.08       0.96       1.76  
Net earnings
     138,518       25,851       1,382,648       83,546       1,630,563  
Per diluted unit/share
     1.11       0.21       11.00       0.66       13.00  
Cash provided by (used in) continuing operations
     95,902       116,719       46,978       (53,587 )     206,013  
Distributions to unitholders – declared
   $ —     $ —     $ —     $ 70,510     $ 70,510  
 
     
(1)   Non-GAAP measure. See page 66.
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
During 2006, the persistent downward trend in commodity prices, natural gas in particular, led to lower fourth quarter demand for all of Precision’s services in western Canada. For the first time in five quarters, Precision’s operating results were down from the comparable quarter in the prior year as overall customer demand decreased due to the decline in natural gas prices.
Revenue of $328 million and operating earnings of $132 million in the fourth quarter of 2006 represented decreases of 23% and 25% respectively, compared to the same period in 2005. Despite the decline in equipment activity, firm pricing helped maintain operating earnings at 40% of revenue in the fourth quarter of 2006 versus 41% in the fourth quarter of 2005.
Earnings from continuing operations in the fourth quarter of 2006 were $126 million compared with $121 million in 2005, an increase of $0.05 per diluted unit. Adjusted for the impact of one-time charges against the prior year fourth quarter earnings from continuing operations of $75 million, the current quarter represented a decrease of $0.48 per diluted unit, or 32%. These one-time charges included $18 million for the reorganization of Precision into an income trust, $51 million for the loss on a short-term investment in Weatherford International Ltd., and $6 million for the repayment of outstanding debentures. Precision realized the benefit of a lower effective tax rate for the full quarter in 2006.
Activity for the quarter was down 33% for drilling rigs and 23% for service rigs from the prior year, consistent with industry declines in the quarter of approximately 25% in the number of wells rig released and the number of rigs working. Drilling rig operating days for the fourth quarter of 2006 were also 18% lower than the third quarter of 2006.

 

 

Compared to 2005, Canadian industry drilling rig operating days decreased by approximately 27% in the fourth quarter of 2006 to 35,682. Industry wells drilled, on a rig release basis, decreased by 24% to 5,339 and the available rig count increased by 9% to approximately 842 compared to the fourth quarter of 2005. New rig capacity in the industry adversely impacted overall equipment utilization rates.
Contract Drilling Service’s segment revenue of $223 million and operating earnings of $104 million decreased by 28% and 33%, respectively, in the fourth quarter of 2006 compared to the same period in 2005. The decline in equipment activity was offset somewhat by an increase in average day rates for contract drilling of 8%. LRG experienced an activity decrease, achieving 3,730 camp days for a 39% decline over the prior year.
Completion and Production Service’s segment revenue of $108 million and operating earnings of $40 million decreased by 13% and 22%, respectively, in the fourth quarter of 2006 compared to the same period in 2005. Precision’s service rig operating hours during the fourth quarter of 2006 were 109,737 compared to 142,122 in 2005, a decrease of 23%. Well service rig operating hours were down over the prior year due to the general decline in industry activity related to natural gas. The decline in activity was somewhat offset by an increase in hourly service rig rates of 14% for the fourth quarter year over year. Demand for rental equipment followed downward industry trends and was 15% lower than the prior year. For Precision’s snubbing division, activity was down 27% in the quarter over the prior year as a result of lower natural gas well activity.
Operating costs increased from 45% of revenue in the fourth quarter of 2005 to 47% in 2006. The increase was mainly caused by a 13% rise in costs per operating day for contract drilling and 15% per operating hour in well servicing including crew wage increases of 4% implemented in the fourth quarter of 2006. There were also increases in third party labour and material costs. Historically, on October 1, a winter rate adjustment for these costs is passed on to customers. This year, in many cases Precision was unable to increase rates to absorb these costs. In addition, equipment repair and maintenance costs were higher per day and per hour as scheduled equipment maintenance was deferred from earlier in 2006 due to a shortage of maintenance infrastructure. Further, lower activity in the fourth quarter of 2006 contributed to increase fixed operating costs per day in contract drilling and per hour in well servicing.
The Trust’s effective income tax rate before enacted tax rate reductions on earnings from continuing operations before income taxes was 3% in the fourth quarter and 6% for the 2006 fiscal year. The comparatively low effective income tax rate was primarily a result of the conversion to an income trust part way through the comparative quarter of 2005 which had the effect of shifting all or a portion of the income tax burden of the Trust to its unitholders.
In the fourth quarter, capital expenditures amounted to $72 million of which $44 million was for the construction of new drilling rigs and an additional $2 million for expansion capital in the Completions and Production Services segment. During the fourth quarter of 2006, four new drilling rigs were released into the field. The remaining $26 million was spent to sustain and upgrade existing equipment and infrastructure.
Fourth quarter monthly cash distributions declared were $0.31 per diluted unit for aggregate distributions declared of $117 million or $0.93 per diluted unit. A special year-end in-kind distribution of $25 million or $0.195 per diluted unit was also declared bringing total declared distributions for the quarter to $141 million or $1.125 per diluted unit. The special in-kind distribution was made to minimize debt levels and retain balance sheet strength to fund planned asset growth. The distribution reinvestment plan generated cash of $4 million and on December 18, 2006 was suspended. Long-term debt decreased by $25 million during the quarter to $141 million for a long-term debt to long-term debt plus equity ratio of 10%. Working capital decreased by $51 million during the quarter to $166 million as lower activity levels reduced revenue and corresponding accounts receivable, while capital expenditures increased.
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 generally accepted

 

 

accounting principles (GAAP). These principles differ in certain respects from U.S. generally accepted accounting principles, 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 its consolidated financial statements. The preparation of these 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 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 for cash in advance.
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 2006, Precision completed its assessment and concluded that there was no impairment of the carrying value.
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.
Effective January 1, 2005, Precision changed the useful life of its drilling rigs for purposes of determining depreciation expense to 5,000 utilization days from 4,150 utilization days (3,650 operating days), and its drill strings to 1,500 from 1,100 operating days. Utilization days include both operating and rig move days. This change in accounting estimate has been applied prospectively and resulted in an $11 million reduction of depreciation expense or $0.09 per diluted unit for the year ended December 31, 2005.
Income Taxes
The corporate subsidiaries of the Trust use the liability method which takes into account the differences between financial statement treatment and tax treatment of certain transactions, assets and liabilities. The Trust, itself, does not have any significant temporary tax differences. 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.
During 2006, the Government of Canada released for comment draft legislation which would result in a tax structure for trusts similar to that of corporate entities. If the proposed legislation is implemented, the Trust would be required to recognize, on a prospective basis, future income taxes on temporary differences in the Trust.
Long-term Incentive Plan Compensation
The Trust instituted a 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 component and a performance award. The performance component is based on growth in distributions measured against a distribution rate as determined by the Compensation Committee of Precision. As a result of actual distributions in the subsequent two years, the accrued amount for the performance component may be reduced or increased depending on the actual amounts distributed.
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 October 1, 2006 for recognition and measurement of financial instruments, disclosure of comprehensive income, and hedge accounting.
• Section 3855, “Financial Instruments – Recognition and Measurement”, provides guidance on when a financial instrument must be recognized on the balance sheet and how it must be measured. It also provides guidance on the presentation of gains and losses on financial instruments.
• Section 3865, “Hedges”, provides guidance on the application of hedge accounting and related disclosures.
• Section 1530, “Comprehensive Income”, requires an entity to recognize certain gains and losses in a separate statement, until such gains and losses are recognized in the statement of income.
The Trust does not expect that the adoption of these standards will have a material impact on the consolidated financial statements.
BUSINESS RISKS
The discussion of risk that follows is not a complete representation. Refer to the “Cautionary Statement Regarding Forward-Looking Information and Statements” on page 1.
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. WTI crude oil prices in 2006 ranged from a low of US$56 per barrel to a high of US$78 per barrel. Military, political, weather, economic and other events in certain parts of the world, including initiatives by the Organization of 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. In 2006 the natural gas spot price, as measured at Henry Hub, averaged almost US$7 per MMBtu and ranged from an approximate low and high of US$4 to US$10 per MMBtu, respectively. 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 Precision’s drilling contracts which: could affect the fair market value of its rig fleet which in turn could trigger a write-down for accounting purposes; could affect Precision’s ability to retain skilled rig personnel; and could affect 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.
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. These shortages are likely to be further challenged by the number of rigs being added to the industry along with the entrance and expansion of start-up oilfield service companies. In the near-term, anticipated declines in activity will offset challenges due to rig expansion.
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. Moreover, once the rigs and other equipment have been moved to a drilling site, they may become stranded or otherwise be unable to relocate to another site should the muskeg thaw unexpectedly. Precision’s business results depend, at least in part, upon the severity and duration of the Canadian winter.
Technology
Technological innovation by oilfield service companies has improved the effectiveness of the entire exploration and production sector over the industry’s more than 140-year history. Drilling time has been reduced due to improvements in drill bits, logging and measurement while drilling tools, as well as innovative changes in other areas such as mud systems and top drives. Precision’s ability to deliver services that are more efficient in reducing customer development costs is critical to continued success.

 

 

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, 2006 there were an estimated 842 industry drilling rigs in Canada, an increase of 9% from December 31, 2005. 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. 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.
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 could be up to $300 million. Any increase in Precision’s tax liability would reduce the funds available for distributions on Trust units.
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
On October 31, 2006, the Government of Canada announced a Tax Fairness Plan containing its intentions to bring about new tax measures including “a Distribution Tax on distributions from publicly traded income trusts and limited partnerships.” The government is proposing a four-year transition period for existing income trusts and limited partnerships whereby the new measures will not apply until their 2011 taxation year. Under the proposals, “flow-through entities” will be taxed more like corporations and their investors will be treated more like shareholders. The proposed new tax measures will impair the flow-through nature of Precision Drilling Trust’s current tax structure. If enacted into law, these tax measures would result in a distribution tax to the Trust which will reduce the cash distributed to unitholders by the amount of distribution tax paid.
Environmental
There is growing concern about the apparent correlation between the burning of fossil fuels and climate change. In February 2007, the United Nations Intergovernmental Panel on Climate Change released a report reiterating calls for action on the basis that man-made activities, particularly burning fossil fuels, were very likely behind global warming. 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.
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, 2006, 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, 2006.
During the 2006 fiscal year, there have been no changes in internal control over financial reporting that have 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 believes these non-GAAP measures provide useful supplemental information to investors. Following are the non-GAAP measures Precision uses in assessing performance.
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.

 

 

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.
DISTRIBUTABLE CASH FROM OPERATIONS
Management believes that in addition to cash provided by (used in) continuing operations, distributable cash from operations is a useful supplemental measure. It provides an indication of the funds available for distribution to unitholders after consideration of the impacts of capital expenditures to maintain the existing productive capacity of Precision’s assets and other operational related funding requirements.

 

 

Precision Drilling Trust
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 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, 2006 to December 31, 2005 and the years ended December 31, 2005 to December 31, 2004. 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.
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, 2006.
The Trust has documented its assessment of internal control over financial reporting and has made this assessment available to our auditors KPMG LLP. Management’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2006, has been audited by KPMG LLP, as stated in their report included herein, which expresses an unqualified opinion on management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006.
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.
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.
     
(Signed)   (Signed)
 
    
Gene C. Stahl
  Doug J. Strong
President and Chief Operating Officer
  Chief Financial Officer
Precision Drilling Corporation,
  Precision Drilling Corporation,
Administrator to Precision Drilling Trust
  Administrator to Precision Drilling Trust
March 9, 2007
  March 9, 2007

 

 

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, 2006 and 2005 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, 2006. 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 year ended December 31, 2006, we also 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 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, 2006 and 2005 and the results of its operations and its cash flow for each of the years in the three-year period ended December 31, 2006 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 effectiveness of the Trust’s internal control over financial reporting as of December 31, 2006, 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 February 13, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
(Signed: KPMG LLP)
Chartered Accountants
Calgary, Alberta
February 13, 2007

 

 

Precision Drilling Trust
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Precision Drilling Corporation, as Administrator of Precision Drilling Trust and the Unitholders of Precision Drilling Trust
We have audited management’s assessment, included in the accompanying management’s report, that Precision Drilling Trust (the “Trust”) maintained effective internal control over financial reporting as of December 31, 2006, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and 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 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, management’s assessment that the Trust maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control– Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, 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 year ended December 31, 2006, we also have conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our report dated February 13, 2007, expressed an unqualified opinion on those consolidated financial statements.
(Signed: KPMG LLP)
Chartered Accountants
Calgary, Alberta
February 13, 2007

 

 

Precision Drilling Trust
CONSOLIDATED BALANCE SHEETS
                         
As at December 31,                    
(Stated in thousands of Canadian dollars)           2006     2005  
 
ASSETS
                        
Current assets:
                        
Accounts receivable
   (Note 19)   $ 354,671     $ 500,655  
Income taxes recoverable
             8,701       —  
Inventory
             9,073       7,035  
 
 
             372,445       507,690  
Property, plant and equipment, net of accumulated depreciation
   (Note 5)     1,107,617       943,900  
Intangibles, net of accumulated amortization of $503 (2005 – $413)
             375       465  
Goodwill
             280,749       266,827  
 
 
           $ 1,761,186     $ 1,718,882  
 
 
                        
LIABILITIES AND UNITHOLDERS’ EQUITY
                        
Current liabilities:
                        
Bank indebtedness
   (Note 6)   $ 36,774     $ 20,468  
Accounts payable and accrued liabilities
   (Note 19)     130,202       134,303  
Incomes taxes payable
             —       163,530  
Distributions payable
   (Note 7)     38,985       36,635  
 
 
             205,961       354,936  
Long-term incentive plan payable
             22,699       —  
Long-term debt
   (Note 8)     140,880       96,838  
Future income taxes
   (Note 9)     174,571       192,517  
 
 
             544,111       644,291  
 
 
                        
Commitments and contingencies
   (Notes 12 and 20)                
 
                        
Unitholders’ equity:
                        
Unitholders’ capital
   (Note 10)     1,412,294       1,377,875  
Deficit
             (195,219 )     (303,284 )
 
 
             1,217,075       1,074,591  
 
 
           $ 1,761,186     $ 1,718,882  
 
See accompanying notes to consolidated financial statements.
 
Approved by the Board of Trustees:
         
(Signed)   (Signed)    
 
Robert J.S. Gibson
  Patrick M. Murray    
Trustee
  Trustee    

 

 

Precision Drilling Trust
CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS (DEFICIT)
                                 
Years ended December 31,                          
(Stated in thousands of Canadian dollars, except per unit/share amounts)           2006     2005     2004  
 
Revenue
           $ 1,437,584     $ 1,269,179     $ 1,028,488  
Expenses:
                                
Operating
             688,207       641,805       566,297  
General and administrative
             81,217       76,397       64,149  
Depreciation and amortization
             73,234       71,561       74,829  
Foreign exchange
             (353 )     (3,474 )     (8,100 )
Reorganization costs
   (Note 23)     —       17,512       —  
 
 
             842,305       803,801       697,175  
 
Operating earnings
             595,279       465,378       331,313  
Interest:
                                
Long-term debt
             8,800       38,735       46,575  
Other
             171       558       246  
Income
             (942 )     (10,023 )     (541 )
Premium on redemption of bonds
   (Note 8)     —       71,885       —  
Loss on disposal of short-term investments
   (Note 24)     —       70,992       —  
Other
             (408 )     —       (4,899 )
 
Earnings from continuing operations before income taxes
             587,658       293,231       289,932  
Income taxes:
   (Note 9)                        
Current
             34,526       241,402       53,698  
Future
             (19,380 )     (169,019 )     48,103  
 
 
             15,146       72,383       101,801  
 
Earnings from continuing operations
             572,512       220,848       188,131  
Gain (loss) on disposal of discontinued operations, net of tax
   (Note 24)     7,077       1,335,382       (616 )
Discontinued operations, net of tax
   (Note 24)     —       74,333       59,889  
 
Net earnings
             579,589       1,630,563       247,404  
Retained earnings (deficit), beginning of year
   (Note 4)     (303,284 )     1,041,683       794,279  
Adjustment on cash purchase of employee stock options, net of tax of $22,060
   (Note 23(c))     —       (42,087 )     —  
Reclassification from contributed surplus on cash buy-out of employee stock options
   (Note 23(c))     —       23,215       —  
Distribution of disposal proceeds
   (Note 24)     —       (2,851,784 )     —  
Repurchase of common shares of dissenting shareholders
   (Note 23(a))     —       (34,364 )     —  
Distributions declared
   (Note 7)     (471,524 )     (70,510 )     —  
 
Retained earnings (deficit), end of year
           $ (195,219 )   $ (303,284 )   $ 1,041,683  
 
Earnings per unit/share from continuing operations:
   (Note 13)                        
Basic
           $ 4.56     $ 1.79     $ 1.63  
Diluted
           $ 4.56     $ 1.76     $ 1.61  
 
Earnings per unit/share:
   (Note 13)                        
Basic
           $ 4.62     $ 13.22     $ 2.14  
Diluted
           $ 4.62     $ 13.00     $ 2.11  
 
See accompanying notes to consolidated financial statements.

 

 

Precision Drilling Trust
CONSOLIDATED STATEMENTS OF CASH FLOW
                                 
Years ended December 31,                          
(Stated in thousands of Canadian dollars)           2006     2005     2004  
 
Cash provided by (used in):
                                
Continuing operations:
                                
Earnings from continuing operations
           $ 572,512     $ 220,848     $ 188,131  
Adjustments and other items not involving cash:
                                
Long-term incentive plan compensation
             22,699       —       —  
Depreciation and amortization
             73,234       71,561       74,829  
Future income taxes
             (19,380 )     (169,019 )     48,103  
Stock-based compensation
             —       11,229       8,190  
Write-off of deferred financing costs
             —       7,664       —  
Loss in market value of short-term investments
             —       70,992       —  
Amortization of deferred financing costs
             —       1,453       1,579  
Unrealized foreign exchange gain on long-term monetary items
             —       (4,740 )     (4,284 )
Other
             (408 )     —       (4,899 )
Changes in non-cash working capital balances
   (Note 19)     (38,913 )     (3,975 )     (25,212 )
 
 
             609,744       206,013       286,437  
Discontinued operations:
   (Note 24)                        
Funds provided by discontinued operations
             —       183,330       187,018  
Changes in non-cash working capital balances of discontinued operations
             —       (86,310 )     (26,797 )
 
 
             —       97,020       160,221  
Investments:
                                
Business acquisitions, net of cash acquired
   (Notes 15 and 24)     (16,428 )     (30,421 )     (679,814 )
Purchase of property, plant and equipment
             (263,030 )     (155,231 )     (122,692 )
Proceeds on sale of property, plant and equipment
             29,337       15,174       8,795  
Proceeds on disposal of discontinued operations
   (Note 24)     7,337       1,306,799       49,299  
Proceeds on disposal of investments
             510       14,569       8,665  
Purchase of property, plant and equipment of discontinued operations
             —       (128,214 )     (159,532 )
Proceeds on sale of property, plant and equipment of discontinued operations
             —       17,785       21,145  
Purchase of intangibles
             —       (20 )     —  
Purchase of intangibles of discontinued operations
             —       —       (320 )
Investments
             —       —       (90 )
Changes in non-cash working capital balances
   (Note 19)     7,551       (2,912 )     1,384  
 
 
             (234,723 )     1,037,529       (873,160 )
Financing:
                                
Distributions paid
   (Note 7)     (444,651 )     (33,875 )     —  
Repayment of long-term debt
             (204,910 )     (703,970 )     (173,260 )
Increase in long-term debt
             248,338       96,826       522,136  
Issuance of Trust units
             9,896       —       —  
Issuance of Trust units on exercise of options
             —       8,263       —  
Issuance of Trust units on purchase of options
             —       5,504       —  
Distribution of disposal proceeds
   (Note 24)     —       (844,334 )     —  
Cash buy-out of employee stock options
             —       (64,147 )     —  
Repurchase of common shares of dissenting shareholders
             —       (43,299 )     —  
Issuance of common shares on exercise of options
             —       73,930       55,361  
Issuance of common shares, net of costs
             —       —       276,428  
Deferred financing costs on long-term debt
             —       —       (5,612 )
Changes in non-cash working capital balances
             —       22,060       —  
Change in bank indebtedness
             16,306       20,468       (147,909 )
 
 
             (375,021 )     (1,462,574 )     527,144  
 
Increase (decrease) in cash and cash equivalents
             —       (122,012 )     100,642  
Cash and cash equivalents, beginning of year
             —       122,012       21,370  
 
Cash and cash equivalents, end of year
           $ —     $ —     $ 122,012  
 
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, service rig and ancillary 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. Due to the conversion to a trust, certain information included in the financial statements for prior periods may not be directly comparable.
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, its subsidiaries and its partnerships.
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.
Certain of the prior period’s figures have been reclassified to conform to the current year’s presentation.
(b) Principles of consolidation
The consolidated financial statements include the accounts of the Trust and all of its subsidiaries and partnerships substantially all of which are wholly-owned. All significant intercompany balances and transactions have been eliminated.
The Trust does not hold investments in any companies where it exerts significant influence and does not hold interests in any variable interest entities.
(c) Cash and cash equivalents
Cash and cash equivalents consist of cash and short-term investments with original maturities of three months or less.

 

 

(d) Inventory
Inventory is primarily comprised of operating supplies and is carried at the lower of average cost, being the cost to acquire the inventory, and replacement cost. Inventory is charged to operating expenses as items are sold or consumed at the amount of the average cost of the item.
(e) Property, plant and equipment
Property, plant and equipment are carried at cost, including costs of direct material and labour. Where costs are incurred to extend the useful life of property, plant and equipment or to increase 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
  5,000 (1) utilization days   20%   unit-of-production
Drill pipe and drill collars
  1,500 (1) operating days   —   unit-of-production
Service rig equipment
  24,000 service hours   20%   unit-of-production
Drilling rig spare equipment
  15 years   —   straight-line
Rental equipment
  10 to 15 years   —   straight-line
Other equipment
  3 to 10 years   —   straight-line
Light duty vehicles
  4 years   —   straight-line
Heavy duty vehicles
  7 to 10 years   —   straight-line
Buildings
  10 to 20 years   —   straight-line
 
(1)   See note 3.
(f) Intangibles
Intangibles, which are comprised primarily of patents, are recorded at cost and amortized by the straight-line method over their useful lives ranging from 10 to 12 years. The weighted average amortization period is 12 years, and amortization over the next five years is anticipated to be $90,000 per year for years one through four and $9,000 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, as described in the preceding paragraph, 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
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 and exchangeable LP units (together “Unitholders”). As the Trust

 

 

distributes all of its taxable income to its respective Unitholders pursuant to the requirements of the Declaration of Trust, it does not make a provision for future income taxes.
PDC 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.
During 2006 the Government of Canada released for comment draft legislation which would result in a tax structure for trusts similar to that of corporate entities. If the proposed legislation is implemented, the Trust would be required to recognize, on a prospective basis, future income taxes on temporary differences in the Trust.
(j) Revenue recognition
The Trust’s services are generally sold based upon purchase 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, 2006, approximately 37% (2005 — 44%) 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 a 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 component is based on the growth in cash distributions measured against a base distribution rate as determined by the Compensation Committee of Precision. The estimated cost of the performance component is accrued over the three-year term of the plan.
(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) 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.
(o) Exchangeable LP units
Exchangeable LP units are presented as equity of the Trust as their features make them economically equivalent to Trust units.
(p) Per unit amounts
Basic per unit amounts are calculated using the weighted average number of Trust units outstanding during the year. Diluted per unit amounts are calculated based on the treasury stock method, which assumes that any proceeds obtained

 

 

on exercise of options 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 options and units repurchased from the related proceeds.
The Trust had no dilutive instruments outstanding during the year ended December 31, 2006.
NOTE 3. ACCOUNTING ESTIMATES
Effective January 1, 2005, the Trust changed the useful life of its drilling rigs for purposes of determining depreciation expense to 5,000 utilization days from 4,150 utilization days (3,650 operating days), and its drill string to 1,500 from 1,100 operating days. Utilization days include both operating and rig move days. This change in accounting estimate was applied prospectively and resulted in a $10.7 million reduction in depreciation expense, or $0.09 per diluted unit/share, for the year ended December 31, 2005.
NOTE 4. ACCOUNTING CHANGES
Stock-based compensation plans
Effective January 1, 2004, the Trust adopted the revised Canadian accounting standards with respect to accounting for stock-based compensation. Under those standards, the fair value of common share purchase options is calculated at the date of the grant and that value is recorded as compensation expense over the vesting period of those grants. Under the previous standard, no compensation expense was recorded when stock options were issued with any consideration received upon exercise credited to share capital.
The Trust has retroactively applied this standard, with restatement of prior years, to all common share purchase options granted since January 1, 2002. This has resulted in a charge to net earnings for the year ended December 31, 2004 of $13.8 million or $0.11 diluted earnings per share and a reduction to opening retained earnings of $14.5 million at January 1, 2004.
NOTE 5. PROPERTY, PLANT AND EQUIPMENT
                         
            Accumulated     Net Book  
2006   Cost     Depreciation     Value  
 
Rig equipment
   $ 1,294,289     $ 434,491     $ 859,798  
Rental equipment
     94,184       40,658       53,526  
Other equipment
     95,137       61,317       33,820  
Vehicles
     78,675       24,461       54,214  
Buildings
     29,583       9,673       19,910  
Assets under construction
     76,239       —       76,239  
Land
     10,110       —       10,110  
 
 
   $ 1,678,217     $ 570,600     $ 1,107,617  
 
                         
            Accumulated     Net Book  
2005   Cost     Depreciation     Value  
 
Rig equipment
   $ 1,143,786     $ 386,191     $ 757,595  
Rental equipment
     81,099       35,307       45,792  
Other equipment
     102,727       62,852       39,875  
Vehicles
     68,911       20,703       48,208  
Buildings
     32,830       9,580       23,250  
Assets under construction
     20,184       —       20,184  
Land
     8,996       —       8,996  
 
 
   $ 1,458,533     $ 514,633     $ 943,900  
 

 

 

NOTE 6. BANK INDEBTEDNESS
At December 31, 2006 and 2005, the Trust had available $60.0 million and US$5.0 million under uncommitted, unsecured credit facilities, of which $36.8 million had been drawn (2005 - $20.5 million). Availability of these facilities were reduced by outstanding letters of credit in the amount of $4.0 million (2005 — $8.4 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, 2006, the amounts drawn under these facilities were at the bank’s prime lending rate of 6% (2005 — 5%).
NOTE 7. DISTRIBUTIONS
The beneficiaries of the Trust are the holders of Trust units and the partners of PDLP are the holders of exchangeable LP units and 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 net 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.
A summary of the distributions is as follows:
                 
    2006     2005  
 
Declared
   $ 471,524     $ 70,510  
Paid
   $ 444,651     $ 33,875  
Payable in cash at December 31
   $ 38,985     $ 36,635  
Payable in units at December 31
   $ 24,523     $ —  
 
Included in the 2006 distributions declared is a special non-cash distribution of $24.5 million ($0.195 per unit). This special distribution was settled on January 16, 2007 through the issuance of units. Immediately following the issuance of these units, the Trust consolidated the units such that the number of Trust units and exchangeable LP units remained unchanged from the number outstanding prior to the special distribution.
NOTE 8. LONG-TERM DEBT
Extendible revolving unsecured facility:
At December 31, 2006, PDC, a subsidiary of the Trust, has available a three-year revolving unsecured facility of $700.0 million (or U.S. equivalent) (2005 — $550.0 million) 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, 2006 and 2005 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, 2006, the Trust had drawn $140.9 million (2005 — $96.8 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 9. INCOME TAXES
The provision for income taxes differs from that which would be expected by applying Canadian statutory income tax rates as follows:
                         
    2006     2005     2004  
 
Earnings from continuing operations before income taxes
   $ 587,658     $ 293,231     $ 289,932  
Federal and provincial statutory rates
     33 %     34 %     36 %
 
Tax at statutory rates
   $ 193,927     $ 99,699     $ 104,375  
Adjusted for the effect of:
                        
Non-deductible expenses
     297       2,795       4,965  
Non-deductible stock-based compensation
     —       3,216       2,948  
Income to be distributed to Unitholders, not subject to tax in the Trust
     (155,354 )     (23,980 )     —  
Utilization of losses and surcharge credits
     —       (10,550 )     —  
Other
     (2,896 )     1,203       (7,600 )
 
Income tax expense before tax rate reductions
     35,974       72,383       104,688  
Reduction of future income tax balances due to enacted tax rate reductions
     (20,828 )     —       (2,887 )
 
Income tax expense
   $ 15,146     $ 72,383     $ 101,801  
 
Effective income tax rate before enacted tax rate reductions
     6 %     25 %     36 %
 
In 2006 the federal and certain provincial governments enacted various reductions to corporate income tax rates. The Government of Canada introduced tax rate reductions to be implemented over the next four years that will decrease the federal corporate income tax rate from 21% to 19%. The federal corporate capital tax was eliminated effective January 1, 2006 and the federal corporate surtax will be eliminated in 2008. The Province of Alberta reduced the corporate income tax rate by 1.5% (2004 — 1.0%) 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:
                 
    2006     2005  
 
Future income tax liability:
                
Property, plant and equipment and intangibles
   $ 213,281     $ 232,277  
 
Future income tax assets:
                
Bond redemption premium
     13,314       20,820  
Losses carried forward
     9,884       14,586  
Share issue costs
     1,966       3,039  
Long-term incentive plan
     10,614       —  
Accrued liabilities
     2,937       1,910  
Valuation allowance
     (5 )     (595 )
 
 
     38,710       39,760  
 
Net future income tax liability
   $ 174,571     $ 192,517  
 
PDC and its subsidiaries have available net capital losses of $33.6 million of which, after valuation allowances, the benefit of $33.6 million has been recognized. These capital losses can be carried forward indefinitely.
During 2004, $7.5 million representing future tax expense on foreign exchange gains associated with the Trust’s U.S.$300 million unsecured notes was charged to the cumulative translation account in Unitholders’ equity. This amount was related to the Trust’s discontinued operations.

 

 

NOTE 10. UNITHOLDERS’ CAPITAL
(a) Authorized — unlimited number of voting Trust units
— unlimited number of voting exchangeable LP units
(b) Unitholders’ capital
                 
Trust units   Number     Amount  
 
Balance, November 7, 2005
     —     $ —  
Issued pursuant to the Plan
     122,512,799       1,339,646  
Options exercised — cash consideration
     1,676,616       8,263  
 — reclassification from contributed surplus
     —       12,342  
Issued for cash
     163,506       5,504  
 
Balance, December 31, 2005
     124,352,921       1,365,755  
Issued pursuant to distribution reinvestment plan (Note 7)
     296,621       9,896  
Issued on retraction of exchangeable LP units
     886,787       9,697  
Issued and consolidated pursuant to special distribution (Note 7)
     —       24,480  
 
Balance, December 31, 2006
     125,536,329     $ 1,409,828  
 
Trust units are redeemable at the option of the holder, at which time all rights with respect to such units are cancelled. Upon redemption, the unitholder is entitled to receive a price per unit equal to the lesser of 90% of the average market price of the Trust’s units for the 10 trading days just prior to the date of redemption, and the closing market price of the Trust’s units on the date of redemption. The maximum value of units that can be redeemed for cash is $50,000 per month. Redemptions, if any, in excess of this amount are satisfied by issuing a note from PDC to the unitholder, payable over 15 years and bearing interest at a market rate set by the Board of Directors.
                 
Exchangeable LP units   Number     Amount  
 
Balance, November 7, 2005
     —     $ —  
Issued pursuant to the Plan
     1,108,382       12,120  
 
Balance, December 31, 2005
     1,108,382       12,120  
Redeemed on retraction of exchangeable LP units
     (886,787 )     (9,697 )
Issued and consolidated pursuant to special distribution (Note 7)
     —       43  
 
Balance, December 31, 2006
     221,595     $ 2,466  
 
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.
                                 
    2006     2005  
Summary as at December 31,   Number     Amount     Number     Amount  
 
Trust units
     125,536,329     $ 1,409,828       124,352,921     $ 1,365,755  
Exchangeable LP units
     221,595       2,466       1,108,382       12,120  
 
Unitholders’ capital
     125,757,924     $ 1,412,294       125,461,303     $ 1,377,875  
 
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 2006 was $5.5 million (2005 — $8.5 million; 2004 — $7.3 million), of which $nil (2005 — $3.2 million; 2004 — $3.0 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 (2004 — $335,000) 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 $26.5 million. Payments over the next five years are as follows:
         
    Total  
 
2007
   $ 7,858  
2008
     6,551  
2009
     4,820  
2010
     4,044  
2011
     3,265  
 
Rent expense included in the statements of earnings is as follows:
                         
    Continuing     Discontinued        
    Operations     Operations     Total  
 
2006
   $ 4,189     $ —     $ 4,189  
2005
     3,836       11,983       15,819  
2004
     5,874       17,284       23,158  
 
NOTE 13. PER UNIT/SHARE 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/share:
                         
(Stated in thousands)   2006     2005     2004  
 
Weighted average units/shares outstanding — basic
     125,545       123,304       115,654  
Effect of stock options
     —       2,108       1,556  
 
Weighted average units/shares outstanding — diluted
     125,545       125,412       117,210  
 
NOTE 14. SIGNIFICANT CUSTOMERS
During the year ended December 31, 2006 no customers (2005 — no customers; 2004 — one customer) accounted for more than 10% of the Trust’s revenue.
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 acquisition has been accounted for by the purchase method with the results of operations included in the financial statements from the date of acquisition. The details of the acquisition are as follows:

 

 

         
Net assets acquired at assigned values:
        
Working capital (1)
   $ 207  
Property, plant and equipment
     3,168  
Goodwill (no tax basis)
     13,922  
Long-term debt
     (614 )
Future income taxes
     (212 )
 
 
   $ 16,471  
 
Consideration:
        
Cash
   $ 16,471  
 
(1)   Working capital includes cash of $43
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
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 required 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 2005 and 2006 the U.S. GAAP financial statements would reflect an increase in goodwill of $63.0 million and a corresponding increase in retained earnings.
(b) 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 (2004 — $13.8 million) 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 (2004 — decreased to $247.8 million). Basic earnings per unit/share would have been $12.88 in 2005 (2004 — $2.14).
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.
(c) 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 10). 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.
(d) Acquisitions
Under U.S. GAAP, when significant acquisitions have occurred, supplemental disclosure is required on a pro forma basis of the results of operations for the current prior periods as though the business combination had occurred at the beginning of the period unless it is not practicable to do so. At December 31, 2005, the Trust did not have access to sufficient information to provide this disclosure for acquisitions completed in 2004. No significant acquisitions occurred in 2006.
(e) Recently issued accounting pronouncements
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.
In June 2006, FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109. The interpretation clarifies the accounting for uncertainty in income taxes by prescribing a consistent recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken on a tax return. The interpretation is effective for fiscal years beginning after December 15, 2006, and will be effective for the Trust’s December 31, 2007 year end. The impact of this interpretation is yet to be determined by management.
On February 16, 2006, FASB issued SFAS 155, Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements no. 133 and 140. The statement clarifies and simplifies the financial reporting of certain hybrid financial instruments by requiring more consistent accounting that eliminates exemptions. The new standard is effective for financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006, and will be effective for the Trust’s first quarter of the December 31, 2007 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,   2006     2005     2004  
 
Earnings from continuing operations under Canadian GAAP
   $ 572,512     $ 220,848     $ 188,131  
Adjustments under U.S. GAAP:
                        
Stock-based compensation expense
     —       11,229       8,190  
Cash buy-out of options
     —       (22,119 )     —  
Intrinsic value recognized on options exercised and/or repriced
     —       (2,270 )     —  
 
Earnings from continuing operations under U.S. GAAP
     572,512       207,688       196,321  
 
Earnings from discontinued operations under Canadian GAAP
     7,077       1,409,715       59,273  
Adjustments under U.S. GAAP:
                        
Stock-based compensation expense
     —       10,109       5,647  
Cash buy-out of options
     —       (19,968 )     —  
Intrinsic value recognized on options exercised and/or repriced
     —       (11,796 )     —  
 
Earnings from discontinued operations under U.S. GAAP
     7,077       1,388,060       64,920  
 
Net earnings under U.S. GAAP
     579,589       1,595,748       261,241  
Cumulative translation adjustment
     —       —       (20,933 )
 
Comprehensive income under U.S. GAAP
   $ 579,589     $ 1,595,748     $ 240,308  
 

 

 

                         
Years ended December 31,   2006     2005     2004  
 
Earnings from continuing operations per unit/share under U.S. GAAP:
                        
Basic
   $ 4.56     $ 1.68     $ 1.70  
Diluted
   $ 4.56     $ 1.66     $ 1.67  
Earnings per unit/share under U.S. GAAP:
                        
Basic
   $ 4.62     $ 12.94     $ 2.26  
Diluted
   $ 4.62     $ 12.72     $ 2.23  
 
Consolidated Statements of Retained Earnings (Deficit)
                         
Years ended December 31,   2006     2005     2004  
 
Retained earnings (deficit) under U.S. GAAP, beginning of year
   $ (3,167,045 )   $ 1,133,030     $ 871,789  
Net earnings under U.S. GAAP
     579,589       1,595,748       261,241  
Distributions declared
     (471,524 )     (70,510 )     —  
Distribution of disposal proceeds
     —       (2,851,784 )     —  
Repurchase of common shares of dissenting shareholders
     —       (34,364 )     —  
Opening temporary equity on conversion to an income trust
     —       (2,560,709 )     —  
Change in redemption value of temporary equity
     1,185,490       (378,456 )     —  
 
Retained earnings (deficit) under U.S. GAAP, end of year
   $ (1,873,490 )   $ (3,167,045 )   $ 1,133,030  
 
Consolidated Balance Sheets
                                 
    2006     2005  
As at December 31,   As reported     U.S. GAAP     As reported     U.S. GAAP  
 
Current assets
   $ 372,445     $ 372,445     $ 507,690     $ 507,690  
Property, plant and equipment
     1,107,617       1,107,617       943,900       943,900  
Intangibles
     375       375       465       465  
Goodwill
     280,749       343,778       266,827       329,856  
 
 
   $ 1,761,186     $ 1,824,215     $ 1,718,882     $ 1,781,911  
 
Current liabilities
   $ 205,961     $ 205,961     $ 354,936     $ 354,936  
Long-term incentive plan payable
     22,699       22,699       —       —  
Long-term debt
     140,880       140,880       96,838       96,838  
Future income taxes
     174,571       174,571       192,517       192,517  
Temporary equity
     —       3,153,594       —       4,304,665  
Unitholders’ capital
     1,412,294       —       1,377,875       —  
Deficit
     (195,219 )     (1,873,490 )     (303,284 )     (3,167,045 )
 
 
   $ 1,761,186     $ 1,824,215     $ 1,718,882     $ 1,781,911  
 
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.
                                         
    Contract     Completion and                    
    Drilling     Production     Corporate     Inter-segment        
2006   Services     Services     and Other     Eliminations     Total  
 
Revenue
   $ 1,009,821     $ 441,017     $ —     $ (13,254 )   $ 1,437,584  
Operating earnings
     473,624       163,119       (41,464 )     —       595,279  
Depreciation and amortization
     38,573       32,013       2,648       —       73,234  
Total assets
     1,198,284       507,510       55,392       —       1,761,186  
Goodwill
     172,440       108,309       —       —       280,749  
Capital expenditures*
     220,397       39,273       3,360       —       263,030  
 
* Excludes business acquisitions

 

 

                                         
    Contract     Completion and                    
    Drilling     Production     Corporate     Inter-segment        
2005   Services     Services     and Other     Eliminations     Total  
 
Revenue
   $ 916,221     $ 369,667     $ —     $ (16,709 )   $ 1,269,179  
Operating earnings
     404,385       121,643       (60,650 )     —       465,378  
Depreciation and amortization
     39,233       27,402       4,926       —       71,561  
Total assets
     1,159,687       486,701       72,494       —       1,718,882  
Goodwill
     172,440       94,387       —       —       266,827  
Capital expenditures*
     106,986       34,576       13,689       —       155,251  
 
                                         
    Contract     Completion and                    
    Drilling     Production     Corporate     Inter-segment        
2004   Services     Services     and Other     Eliminations     Total  
 
Revenue
   $ 727,710     $ 313,386     $ —     $ (12,608 )   $ 1,028,488  
Operating earnings
     282,315       77,074       (28,076 )     —       331,313  
Depreciation and amortization
     42,245       27,508       5,076       —       74,829  
Total assets
     971,863       461,191       180,009       —       1,613,063  
Goodwill
     172,440       94,387       —       —       266,827  
Capital expenditures*
     74,975       31,759       15,958       —       122,692  
 
* Excludes business acquisitions
NOTE 18. FINANCIAL INSTRUMENTS
(a) Fair value
 
The carrying value of cash and cash equivalents, accounts receivable, income taxes recoverable, bank indebtedness, accounts payable and accrued liabilities, income tax payable and distributions payable approximate their fair value due to the relatively short period to maturity of the instruments.
(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, 2006 the Trust’s allowance for doubtful accounts was $5.6 million (2005 – $5.1 million).
(c) Interest rate risk
 
The Trust is exposed to interest rate risk with respect to interest expense on its credit facilities.
(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 (2004 – gain of $43.1 million). The cumulative translation account at August 31, 2005 of $24.8 million was charged to the gain on disposal of discontinued operations in 2005.

 

 

NOTE 19. SUPPLEMENTAL INFORMATION
                         
    2006     2005     2004  
 
Interest paid:
                        
– continuing operations
   $ 8,929     $ 43,232     $ 45,338  
– discontinued operations
     —       304       997  
 
 
   $ 8,929     $ 43,536     $ 46,335  
 
                         
                   
 
Income taxes paid:
                        
– continuing operations
   $ 207,160     $ 91,496     $ 38,759  
– discontinued operations
     —       35,176       35,935  
 
 
   $ 207,160     $ 126,672     $ 74,694  
 
 
                        
Components of change in non-cash working capital balances:
                        
Accounts receivable
   $ 148,046     $ (171,363 )   $ (42,714 )
Inventory
     (2,038 )     699       (2,017 )
Accounts payable and accrued liabilities
     (4,736 )     13,871       5,964  
Income taxes
     (172,634 )     149,906       14,939  
 
 
   $ (31,362 )   $ (6,887 )   $ (23,828 )
 
The components of accounts receivable are as follows:
                 
    2006     2005  
 
Trade
   $ 220,623     $ 306,264  
Accrued trade
     93,308       148,537  
Prepaids and other
     40,740       45,854  
 
 
   $ 354,671     $ 500,655  
 
The components of accounts payable and accrued liabilities are as follows:
                 
    2006     2005  
 
Accounts payable
   $ 60,650     $ 71,027  
Accrued liabilities:
                
Payroll
     47,001       30,351  
Other
     22,551       32,925  
 
 
   $ 130,202     $ 134,303  
 
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 could be up to $300 million.
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.
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
   $ 12,600  
Legal, accounting, financial advisory services and other
     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.
                 
    Number     Amount  
 
Balance, December 31, 2003
     54,845,678     $ 936,744  
Issuance of common shares, net of costs and related tax effect
     4,400,000       280,783  
Options exercised – cash consideration
     1,544,534       55,361  
– reclassification from contributed surplus
     —       2,079  
 
Balance, December 31, 2004
     60,790,212       1,274,967  
Options exercised – cash consideration
     578,346       24,516  
– reclassification from contributed surplus
     —       1,521  
 
Balance, May 18, 2005
     61,368,558       1,301,004  
Issued on 2:1 stock split
     61,368,558       —  
Options exercised – cash consideration
     1,679,110       49,414  
– reclassification from contributed surplus
     —       10,284  
Adjustment to number of shares outstanding
     21,960       —  
Cancellation of shares owned by dissenting shareholders
     (817,005 )     (8,936 )
 
Balance, November 7, 2005, before conversion to units
     123,621,181       1,351,766  
Conversion to Trust units
     (122,512,799 )     (1,339,646 )
Conversion to exchangeable LP units
     (1,108,382 )     (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.
In the third quarter of 2004, the Trust issued 4,400,000 common shares at US $49.80 for net proceeds of approximately $276.5 million.

 

 

(b) Contributed surplus:
         
Balance, December 31, 2003
   $ 14,266  
Stock-based compensation expense
     13,837  
Reclassification to common shares on exercise of options
     (2,079 )
 
Balance, December 31, 2004
     26,024  
Stock-based compensation expense
     13,077  
Accelerated vesting of options on disposal of discontinued operations
     5,205  
Reclassification to common shares on exercise of options prior to the Plan
     (11,805 )
Accelerated vesting of options pursuant to the Plan
     3,056  
Reclassification to Trust units on exercise of options
     (12,342 )
Reclassification to retained earnings on cash buy-out of options
     (23,215 )
 
Balance, December 31, 2005
   $ —  
 
(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 stock 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, 2004 and 2005 and changes during the periods then ended is presented below:
                                 
                    Weighted        
    Options     Range of     Average     Options  
Common Share Purchase Options   Outstanding     Exercise Price     Exercise Price     Exercisable  
 
Outstanding at December 31, 2003
     6,786,388     $ 6.75 – 32.95     $ 20.85       4,076,396  
Granted
     3,381,000       20.13 – 36.32       31.77          
Exercised
     (3,089,068 )     6.75 – 28.78       17.92          
Cancelled
     (383,200 )     15.53 – 32.95       25.68          
 
Outstanding at December 31, 2004
     6,695,120       15.53 – 36.32       27.44       2,580,302  
Granted
     696,200       37.76 – 48.29       41.42          
Exercised
     (2,835,802 )     15.53 – 48.29       26.07          
Cancelled
     (141,650 )     15.53 – 31.87       30.26          
Purchased
     (1,105,018 )     15.53 – 45.25       31.30          
Exchanged for Trust unit purchase options
     (3,308,850 )     15.53 – 48.29       30.14          
 
Outstanding at December 31, 2005
     —     $ —     $ —       —  
 
                                 
                    Weighted        
    Options     Range of     Average     Options  
Trust Unit Purchase Options   Outstanding     Exercise Price     Exercise Price     Exercisable  
 
Outstanding at November 7, 2005
     —     $ —     $ —       —  
Granted in exchange for common share purchase options pursuant to the Plan
     3,308,850     nil – 27.25     9.16       3,308,850  
Granted on repricing of common share options
     5,600     nil     nil          
Exercised
     (1,676,616 )   nil – 27.25     4.93          
Purchased
     (1,637,834 )   nil – 27.25     13.46          
 
Outstanding at December 31, 2005
     —     $ —     $ —       —  
 

 

 

In accordance with the Trust’s stock 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 (2004 – $7.83) 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% (2004 – 3.44%), average expected life of 2.92 years (2004 – 2.97 years) and expected volatility of 28.04% (2004 – 32.33%).
For the year ended December 31, 2005 stock-based compensation costs included in net earnings totaled $21.3 million (2004 – $13.8 million), of which $10.1 million (2004 – $5.6 million) related to discontinued operations.
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:
2006
 
In January 2007, the Trust received $21.3 million as final 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 International Ltd. 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 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.
2004
 
On February 12, 2004, the Trust sold substantially all of the assets of Fleet Cementers, Inc. for proceeds of $25.7 million. On May 7, 2004, the Trust sold the assets of the Polar Completions division for proceeds of $15.0 million, subject to working capital adjustments. On August 31, 2004, the Trust sold its 65% interest in United Diamond Ltd. for proceeds of $8.5 million. Additional proceeds in the amount of up to $9.5 million was receivable with respect to the sale of United Diamond Ltd., contingent upon the extent of future business undertaken between the Trust and United Diamond Ltd. In August 2006 this adjustment was finalized. These assets were included in the Energy Services segment and were disposed of as they were not a core component, at that time, to the energy services globalization strategy.

 

 

Results of the operations of these businesses have been classified as results of discontinued operations.
The following table provides additional information with respect to amounts included in the statements of earnings related to discontinued operations:
                         
    2006     2005     2004  
 
Revenue:
                        
Energy services
   $ —     $ 689,319     $ 898,199  
International contract drilling
     —       204,987       246,612  
Industrial plant maintenance (CEDA)
     —       149,371       175,802  
 
 
   $ —     $ 1,043,677     $ 1,320,613  
 
 
                        
Gain (loss) on disposal:
                        
Loss on disposal of Fleet Cementers’ assets
   $ —     $ —     $ (362 )
Gain (loss) on disposal of United Diamond
     2,070       —       (254 )
Gain on disposal of Energy services and International contract drilling
     962       1,203,309       —  
Gain on disposal of Industrial plant maintenance
     4,045       132,073       —  
 
 
     7,077       1,335,382       (616 )
 
 
                        
Results of operations before income taxes:
                        
Energy services
     —       76,607       33,060  
International contract drilling
     —       41,171       65,043  
Industrial plant maintenance
     —       18,135       19,658  
Other
     —       (22,298 )     (20,251 )
Writedown of assets held for sale
     —       —       (6,117 )
 
 
     —       113,615       91,393  
Income tax expense
     —       39,282       28,824  
 
Results of operations, before non-controlling interest
     —       74,333       62,569  
Non-controlling interest
     —       —       2,680  
 
Results of operations
     —       74,333       59,889  
 
Net earnings of discontinued operations
   $ 7,077     $ 1,409,715     $ 59,273  
 
The following table provides additional information with respect to amounts included in the statements of cash flow related to discontinued operations:
                         
    2006     2005     2004  
 
Net earnings of discontinued operations
   $ 7,077     $ 1,409,715     $ 59,273  
Items not affecting cash:
                        
(Gain) loss on disposal of discontinued operations
     (7,077 )     (1,335,382 )     616  
Depreciation and amortization
     —       95,794       130,163  
Writedown of assets of discontinued operations
     —       —       3,293  
Stock-based compensation
     —       10,109       5,647  
Future income taxes
     —       (1,735 )     (17,383 )
Unrealized foreign exchange loss on long-term monetary items
     —       4,829       2,729  
Non-controlling interest
     —       —       2,680  
 
Funds provided by discontinued operations
   $ —     $ 183,330     $ 187,018  
 
Components of changes in non-cash working capital balances of discontinued operations:
                         
    2006     2005     2004  
 
Accounts receivable
   $ —     $ (60,912 )   $ (93,743 )
Inventory
     —       (23,463 )     5,725  
Accounts payable and accrued liabilities
     —       1,688       52,861  
Income taxes payable
     —       (3,623 )     8,360  
 
 
   $ —     $ (86,310 )   $ (26,797 )
 

 

 

Significant accounting policies relating to discontinued operations included:
(a) Employee benefit plans
 
At December 31, 2004, approximately 36% of employees of discontinued operations were enrolled in retirement plans. Of that, approximately 6% of participating employees were enrolled in the defined benefit plan and approximately 94% in the defined contribution plan.
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 included in discontinued operations are as follows:
2005
 
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.
2004
 
During the year ended December 31, 2004, in accordance with the Trust’s then globalization and technology advancement strategies, the Trust completed several acquisitions, the most significant of which were:

 

 

(a) On May 14, 2004, the Trust acquired all of the issued and outstanding shares of Reeves Oilfield Services Ltd. (Reeves), including a 56.5% interest in Allegheny Wireline Services, Inc. (Allegheny). On October 14, 2004, the Trust acquired the remaining 43.5% interest in Allegheny. In the intervening period from the date of acquisition of Reeves to the acquisition of the remaining interest in Allegheny, earnings attributable to non-controlling interest totaled $1.3 million. Reeves provided open hole and cased hole logging services to the oil and gas industry with operations in Canada, the United States, Australia, Africa, Europe and the Middle East. Intangible assets acquired relate entirely to intellectual property.
(b) On May 21, 2004, the Trust acquired land drilling assets, located in Venezuela and the Middle East, from GlobalSantaFe Corporation (GlobalSantaFe). Intangible assets acquired relate to non-competition agreements and customer contracts.
                                 
    Reeves     GlobalSantaFe     Other     Total  
 
Net assets acquired at assigned values:
                                
Working capital
   $ 23,000 (1)   $ 12,463     $ 60     $ 35,523  
Intangible assets
     106,900       33,138       —       140,038  
Property, plant and equipment
     41,730       296,655       1,547       339,932  
Goodwill (no tax basis)
     118,531       103,956       130       222,617  
Non-controlling interest in earnings of intervening period
     1,298       —       —       1,298  
Future income taxes
     (37,732 )     (9,720 )     —       (47,452 )
 
 
   $ 253,727     $ 436,492     $ 1,737     $ 691,956  
 
 
                                
Consideration:
                                
Cash
   $ 253,727     $ 436,492     $ 1,737     $ 691,956  
 
(1) Includes cash of $12,142

 

 

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)   2006     2005     2004     2003  
 
Revenue
   $ 1,437.6     $ 1,269.2     $ 1,028.5     $ 915.2  
Expenses:
                                
Operating
     688.2       641.8       566.3       544.2  
General and administrative
     81.2       76.4       64.2       42.7  
Depreciation and amortization
     73.2       71.6       74.8       78.1  
Foreign exchange
     (0.3 )     (3.5 )     (8.1 )     (2.2 )
Reorganization costs
     —       17.5       —       —  
 
Operating earnings
     595.3       465.4       331.3       252.4  
Interest, net
     8.0       29.3       46.3       34.0  
Premium on redemption of bonds
     —       71.9       —       —  
Loss on disposal of short-term investments
     —       71.0       —       —  
Other
     (0.4 )     —       (4.9 )     (1.5 )
 
Earnings from continuing operations before income taxes
     587.7       293.2       289.9       219.9  
Income taxes
     15.2       72.4       101.8       75.7  
 
Earnings from continuing operations
     572.5       220.8       188.1       144.2  
Discontinued operations, net of tax
     7.1       1,409.8       59.3       36.3  
 
Net earnings
     579.6       1,630.6       247.4       180.5  
Retained earnings (deficit), beginning of year
     (303.3 )     1,041.7       794.3       613.8  
Adjustment on cash purchase of employee stock options, net of tax
     —       (42.1 )     —       —  
Reclassification from contributed surplus on cash buy-out of employee stock options
     —       23.2       —       —  
Distribution of disposal proceeds
     —       (2,851.8 )     —       —  
Repurchase of common shares of dissenting shareholders
     —       (34.4 )     —       —  
Distributions declared
     (471.5 )     (70.5 )     —       —  
 
Retained earnings (deficit), end of year
   $ (195.2 )   $ (303.3 )   $ 1,041.7     $ 794.3  
 
Earnings per unit/share from continuing operations:
                                
Basic ($)
     4.56       1.79       1.63       1.33  
Diluted ($)
     4.56       1.76       1.61       1.31  
Earnings per unit/share:
                                
Basic ($)
     4.62       13.22       2.14       1.66  
Diluted ($)
     4.62       13.00       2.11       1.63  
 

 

 

Precision Drilling Trust
 
ADDITIONAL SELECTED FINANCIAL INFORMATION
Years ended December 31,
                                 
(Stated in millions of Canadian dollars,                        
except per unit/share amounts)   2006     2005     2004     2003  
 
Return on sales —% (1)
     39.8       17.4       18.3       15.8  
Return on assets —% (2)
     33.6       43.3       7.3       6.3  
Return on equity —% (3)
     49.4       66.1       12.3       11.0  
Working capital
   $ 166.5     $ 152.8     $ 557.3     $ 249.0  
Current ratio
     1.81       1.43       2.47       1.57  
PP&E and intangibles
   $ 1,108.0     $ 944.4     $ 898.1     $ 887.7  
Total assets
   $ 1,761.2     $ 1,718.9     $ 3,852.0     $ 2,932.0  
Long-term debt
   $ 140.9     $ 96.8     $ 718.9     $ 399.4  
Unitholders’ equity
   $ 1,217.1     $ 1,074.6     $ 2,321.7     $ 1,745.3  
Long-term debt to long-term debt plus equity
     0.10       0.08       0.24       0.19  
Interest coverage (4)
     74.1       15.9       7.2       7.4  
Net capital expenditures from continuing operations excluding business acquisitions
   $ 233.7     $ 140.1     $ 113.9     $ 84.9  
EBITDA (5)
   $ 668.5     $ 536.9     $ 406.1     $ 330.6  
EBITDA —% of revenue
     46.5       42.3       39.5       36.1  
Operating earnings
   $ 595.3     $ 465.4     $ 331.3     $ 252.4  
Operating earnings —% of revenue
     41.4       36.7       32.2       27.6  
Cash flow from continuing operations
   $ 609.7     $ 206.0     $ 286.4     $ 200.9  
Cash flow from continuing operations per unit/share
                                
Basic
   $ 4.86     $ 1.67     $ 2.48     $ 1.85  
Diluted
   $ 4.86     $ 1.64     $ 2.44     $ 1.82  
Book value per unit/share (6)
   $ 9.68     $ 8.57     $ 19.10     $ 15.91  
Price earnings ratio (7)
     5.84       2.90       17.6       17.1  
Basic weighted average units/shares outstanding (000’s)
     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.

 

 

ADDITIONAL DISCLOSURE
Certifications and Disclosure Regarding Controls and Procedures.
(a)   Certifications. See Exhibits 99.1 and 99.2 to this Annual Report on Form 40-F.
 
(b)   Disclosure Controls and Procedures. As of the end of the Registrant’s fiscal year ended December 31, 2006, an evaluation of the effectiveness of the registrant’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was carried out by the registrant’s management with the participation of the principal executive officer and principal financial officer. Based upon that evaluation, the Registrant’s principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, the registrant’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (ii) accumulated and communicated to the Registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
 
    It should be noted that while the Registrant’s principal executive officer and principal financial officer believe that the Registrant’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Registrant’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
 
(c)   Management’s Annual Report on Internal Control Over Financial Reporting. The required disclosure is included in the “Management Report” that accompanies the registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2006, filed as part of this Annual Report on Form 40-F.
 
(d)   Attestation Report of the Registered Public Accounting Firm. The required disclosure is included in the “Auditors’ Report” that accompanies the registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2006, filed as part of this Annual Report on Form 40-F.
 
(e)   Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2006, there were no changes in the Registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Registrant’s internal control over financial reporting.
Notices Pursuant to Regulation BTR.
None.
Audit Committee Financial Expert.
     Precision Drilling Corporation (“Precision”), administrator of the Registrant, has determined that Patrick M. Murray and H. Garth Wiggins, members of Precision’s audit committee both qualify as an “audit committee financial expert” (as such term is defined in Form 40-F). Precision’s board of directors has determined that each of Mr. Murray and Mr. Wiggins is “independent” as that term is defined in the New York Stock Exchange (“NYSE”) listing standards. For a description of the relevant experience in financial matters of Mr. Murray and Mr. Wiggins, see the section “Relevant Education and Experience” under the heading “Audit Committee Information” in the Registrant’s Annual Information Form for the fiscal year ended December 31, 2006, which is filed as part of this Annual Report on Form 40-F.

 

 

Code of Ethics.
     The registrant has adopted a “code of ethics” (as that term is defined in Form 40-F), entitled the “Joint Code of Business Conduct and Ethics” (the “Code of Ethics”), that applies to its directors, officers and employees, including its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.
     The Code of Ethics is available for viewing on the registrant’s website at www.precisiondrilling.com, and is available in print to any unit holder who requests it. Requests for copies of these documents should be made by contacting: Darren Ruhr, Vice President Corporate Services and Corporate Secretary, 4200, 150 – 6th Avenue S.W., Calgary, Alberta, Canada T2P 3Y7. Since the adoption of the Code of Ethics, there have not been any amendments to the Code of Ethics or waivers, including implicit waivers, from any provision of the Code of Ethics.
Principal Accountant Fees and Services.
     The following table provides information about the fees billed to the Registrant for professional services rendered by KPMG LLP during fiscal years 2006 and 2005:
                 
(CANADIAN $000)   2006     2005
 
Audit Fees
   $ 1,813     $ 2,108  
Audit-Related Fees
     —       —  
Tax Fees
   $ 579     $ 753  
All Other Fees
     —     $ 54  
 
TOTAL
   $ 2,392     $ 2,915  
 
Audit Fees.
     Audit fees consist of fees for the audit of the Registrant’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements and include fees related to the Sarbanes-Oxley Act of 2002 Section 404 compliance in 2006. The decrease in audit fees from 2005 to 2006 was primarily due to the providing of services for discontinued businesses in 2005.
Audit-Related Fees.
     Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of the Registrant’s financial statements and are not reported as audit fees. There were no such fees incurred in 2005 or 2006.
Tax Fees.
     Tax fees consist of fees for tax compliance services, tax advice and tax planning. During fiscal 2006 and 2005, the services provided in this category included assistance and advice in relation to the preparation of corporate income tax returns for the Registrant and its subsidiaries, tax advice and planning, commodity tax and property tax consultation.
All Other Fees.
     In 2005, other fees related to translation of financial statements and due diligence assistance with respect to a disposition. In 2006, there were no such fees.

 

 

Pre-Approval Policies and Procedures.
     Under the Audit Committee Charter, the Audit Committee is required to approve the terms of engagement and the compensation to be paid to the external auditor of the Registrant. In addition, the Audit Committee is required to review and pre-approve all permitted non-audit services to be provided to the Registrant or any affiliated entities by the external auditors or any of their affiliates subject to any de minimus exception allowed by applicable law. The Audit Committee may delegate to one or more designated members of the Audit Committee the authority to pre-approve non-audit services. Non-audit services that have been pre-approved by any such delegate must be presented to the Audit Committee at its first scheduled meeting following such pre-approval.
     The Audit Committee implemented specific procedures regarding the pre-approval of services to be provided by Precision’s external auditor commencing in 2003. These procedures specify certain prohibited services that are not to be performed by the external auditor. In addition, these procedures require that at least annually, prior to the period in which the services are proposed to be provided, Precision’s management will, in conjunction with Precision’s external auditor, prepare and submit to the Audit Committee a complete list of all proposed services to be provided to Precision and the Registrant by the external auditor. Under the Audit Committee pre-approval procedures, for those services proposed to be provided by the external auditor that have not been previously approved by the Audit Committee, the Chairman of the Audit Committee has the authority to grant pre-approvals of such services. The decision to pre-approve a service covered under this procedure is required to be presented to the full Audit Committee at the next scheduled meeting. At each of the Audit Committee’s regular meetings, the Audit Committee is to be provided with an update as to the status of services previously pre-approved.
     Pursuant to these procedures, since their implementation in 2003, 100% of each of the services provided by the Registrant’s external auditor relating to the fees reported as audit, audit-related, tax and all other fees were pre-approved by the Audit Committee or its delegate.
Off-Balance Sheet Arrangements.
     The Registrant does not have any off-balance sheet arrangements.
Tabular Disclosure of Contractual Obligations.
     The required disclosure is included under the heading “Liquidity and Capital Resources” in the Registrant’s Management’s Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2006, included in this Annual Report on Form 40-F.
Identification of the Audit Committee.
     Precision has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Robert J.S. Gibson, Patrick M. Murray and H. Garth Wiggins.
     DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NYSE.
Presiding Director at Meetings of Non-Management Directors
     Precision schedules regular executive sessions in which Precision’s “non-management directors” (as that term is defined in the rules of the NYSE) meet without management participation. The board of directors of Precision appoints a presiding director (the “Presiding Director”) from the independent and unrelated directors present at each regularly held in-camera session of the board of directors. The Presiding Director is responsible for developing the agenda for, and presiding over, in-camera sessions and acting as principal liaison between the non-management directors and the Chief Executive Officer on matters dealt with during the in-camera session. Each of Precision’s non-management directors is “unrelated” as such term is used in the rules of the NYSE.

 

 

Communication with Non-Management Directors
     The Registrant’s unit holders may send communications to Precision’s non-management directors by writing to the Presiding Director, c/o Darren Ruhr, Vice President Corporate Services and Corporate Secretary, 4200, 150 – 6th Avenue S.W., Calgary, Alberta, Canada, T2P 3Y7. Communications will be referred to the Presiding Director for appropriate action. The status of all outstanding concerns addressed to the Presiding Director will be reported to the board of directors as appropriate.
Corporate Governance Guidelines
     According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt and disclose a set of corporate governance guidelines with respect to specified topics. Such guidelines are required to be posted on the listed company’s website. The Registrant and Precision have adopted the required guidelines, and the guidelines are available for viewing on the Registrant’s website at www.precisiondrilling.com, and are available in print to any unit holder who requests them. Requests for copies of these documents should be made by contacting: Darren Ruhr, Vice President Corporate Services and Corporate Secretary, 4200, 150 – 6th Avenue S.W., Calgary, Alberta, Canada T2P 3Y7.
Board Committee Mandates
     The Registrant’s board of trustees mandate and Precision’s board of directors mandate, audit committee charter and terms of reference, compensation committee mandate and corporate governance and nominating committee mandate are each available for viewing on the Registrant’s website at www.precisiondrilling.com, and are available in print to any unit holder who requests them. Requests for copies of these documents should be made by contacting: Darren Ruhr, Vice President Corporate Services and Corporate Secretary, 4200, 150 – 6th Avenue S.W., Calgary, Alberta, Canada T2P 3Y7.

 

 

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A.   Undertaking.
 
    The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Securities and Exchange Commission (the “Commission”) staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.
 
B.   Consent to Service of Process.
 
    The Registrant has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.
 
    Any change to the name or address of the agent for service of process of the Registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement.
SIGNATURES
Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
   
 
Precision Drilling Corporation, as agent for
and on behalf of Precision Drilling Trust
 
 		  
  By:   /s/  Gene C. Stahl    
    Name:   Gene C. Stahl   
    Title:   President and Chief Operating Officer   
 
Date: March 29, 2007

 

 

EXHIBIT INDEX
     
Exhibit   Description
99.1
  Certification of President and Chief Operating Officer pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934
 
    
99.2
  Certification of Chief Financial Officer pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934
 
    
99.3
  Certification of President and Chief Operating Officer pursuant to 18 U.S.C. 1350
 
    
99.4
  Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350
 
    
99.5
  Consent of KPMG LLP