40-F 1 o54277e40vf.htm FORM 40-F

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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, 2008
Commission file number 001-14534
PRECISION DRILLING TRUST
(Exact name of registrant as specified in its charter)

Alberta, Canada |  | 1381 |  | Not applicable
(Province or other jurisdiction of incorporation or organization) |  | (Primary Standard Industrial Classification Code Number (if 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, North St. Paul Street, Dallas, Texas 77022
(214) 979-1172
(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: 160,042,065 Trust Units outstanding as at December 31, 2008.
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 documents (or portions thereof) forming part of this Form 40-F are incorporated by reference into the following registration statement under the Securities Act of 1933, as amended:

Form |  | Registration No.
F-10 |  |  | 333-156844 |

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PRINCIPAL DOCUMENTS
The following documents are being filed as part of this Annual Report on Form 40-F:
A. Annual Information Form for the fiscal year ended December 31, 2008 (the “Annual Information Form”).
B. Management’s Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2008 (“Management’s Discussion and Analysis”).
C. Consolidated Financial Statements for the fiscal year ended December 31, 2008 (the “Consolidated Financial Statements”). Note 20 to the Consolidated Financial Statements relates to United States Generally Accepted Accounting Principles. Management’s annual report on internal control over financial reporting and the attestation report of KPMG LLP regarding management’s assessment of internal controls over financial reporting are included in the Consolidated Financial Statements.
UNDERTAKING
The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the staff of the Securities and Exchange Commission (the “Commission”), 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.
DISCLOSURE CONTROLS AND PROCEDURES
For information on disclosure controls and procedures, see “Evaluation of Disclosure Controls and Procedures” in the Annual Information Form and “Disclosure Controls and Procedures” in Management’s Discussion and Analysis.
AUDIT COMMITTEE FINANCIAL EXPERT
The board of directors of Precision Drilling Corporation, the administrator of the registrant, has determined that it has at least one audit committee financial expert serving on its audit committee. Each of Patrick M. Murray, William T. Donovan and Allen R. Hagerman has been designated an audit committee financial expert and is independent, as that term is defined by the New York Stock Exchange’s listing standards applicable to the Registrant. The Commission has indicated that the designation of each of Messrs. Murray and Hagerman as an audit committee financial expert does not make either of them an “expert” for any purpose, impose any duties, obligations or liability on them that is greater than that imposed on members of the audit committee and board of directors who do not carry this designation or affect the duties, obligations or liability of any other member of the audit committee.
CODE OF ETHICS
The Registrant and Precision Drilling Corporation have adopted a Joint Code of Business Conduct and Ethics for their principal executive officer, principal financial officer, principal accounting officer or controller and any person performing similar functions. The Registrant’s code is available on its website at www.precisiondrilling.com. No waivers have been granted from, and there have been no amendments to, any provision of the code during the 2008 fiscal year.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
For information on principal accountant fees and services, see “Audit Committee Information — Audit Fees” in the Annual Information Form.
OFF-BALANCE SHEET ARRANGEMENTS
The Registrant has no off-balance sheet arrangements, as defined in this Form.
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
For information on Tabular Disclosure of Contractual Obligations, see “Liquidity and Capital Resources” in Management’s Discussion and Analysis.

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IDENTIFICATION OF THE AUDIT COMMITTEE
The Registrant has a separately-designated standing Audit Committee. The members of the Audit Committee are:

Chair: |  | Patrick M. Murray
Members: |  | Allen R. Hagerman
|  | Robert J.S. Gibson
|  | William T. Donovan
|  | Robert L. Phillips

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, thereto duly authorized, in the City of Calgary, Province of Alberta, Canada.

| Precision Drilling Corporation, as agent for and on behalf of Precision Drilling Trust |
| By: | /s/ Kevin A. Neveu |
|  | Name: | Kevin A. Neveu |
|  | Title: | President and Chief Executive Officer |

Date: March 30, 2009
EXHIBITS

23.1 |  | Consent of KPMG LLP, Chartered Accountants.
31.1 |  | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 |  | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 |  | Certification of Chief Executive Officer regarding Periodic Report containing Financial Statements.
32.2 |  | Certification of Chief Financial Officer regarding Periodic Report containing Financial Statements.

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PRECISION DRILLING TRUST
ANNUAL INFORMATION FORM
For the fiscal year ended December 31, 2008
Dated March 27, 2009

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TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS |  |  | 1 |
CORPORATE STRUCTURE |  |  | 4 |
The Trust |  |  | 4 |
Precision Drilling Limited Partnership |  |  | 4 |
Precision Drilling Corporation |  |  | 4 |
Administration Agreement |  |  | 4 |
INTERCORPORATE RELATIONSHIPS |  |  | 5 |
GENERAL DEVELOPMENT OF THE BUSINESS |  |  | 6 |
Recent Developments |  |  | 6 |
Three Year History |  |  | 7 |
DESCRIPTION OF THE BUSINESS OF PRECISION |  |  | 10 |
General |  |  | 10 |
Contract Drilling Services |  |  | 12 |
Completion And Production Services |  |  | 15 |
Material Debt |  |  | 18 |
RECORD OF CASH DISTRIBUTIONS/PAYMENTS |  |  | 23 |
DESCRIPTION OF CAPITAL STRUCTURE |  |  | 26 |
Description Of Trust Units |  |  | 26 |
Description Of Exchangeable Units |  |  | 31 |
MARKET FOR SECURITIES |  |  | 34 |
TRUSTEES, DIRECTORS AND EXECUTIVE OFFICERS |  |  | 36 |
Board Of Trustees |  |  | 36 |
CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS |  |  | 37 |
AUDIT COMMITTEE INFORMATION |  |  | 38 |
LEGAL PROCEEDINGS AND REGULATORY ACTIONS |  |  | 40 |
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS |  |  | 40 |
TRANSFER AGENT, REGISTRAR AND VOTING AND EXCHANGE TRUSTEE |  |  | 40 |
MATERIAL CONTRACTS |  |  | 40 |
INTERESTS OF EXPERTS |  |  | 41 |
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES |  |  | 41 |
INTERNAL CONTROL OVER FINANCIAL REPORTING |  |  | 42 |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |  |  | 42 |

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ADDITIONAL INFORMATION |  |  | 42 |
RISK FACTORS |  |  | 42 |
Risks Relating To The Structure Of The Trust |  |  | 43 |
Risks Relating To The Business Currently Conducted By Precision |  |  | 51 |
Risks Relating to the Acquisition |  |  | 58 |
APPENDIX 1 AUDIT COMMITTEE CHARTER AND TERMS OF REFERENCE |  |  | 62 |
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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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 (collectively the “forward-looking information and statements”). Forward-looking information and statements are typically identified by words such as “anticipate”, “could”, “should”, “expect”, “seek”, “may”, “intend”, “likely”, “will”, “plan”, “estimate”, “believe” and similar expressions suggesting future outcomes or statements regarding an outlook.
Forward-looking information and statements are included throughout this Annual Information Form including under the headings “General Development of the Business”, “Description of the Business of Precision” and “Risk Factors” and include, but are not limited to statements with respect to:

• | 2009 expected cash provided by continuing operations;
• | 2009 capital expenditures, including the amount and nature thereof;
• | 2009 distributions on Trust Units (as defined herein) and payments on Exchangeable Units (as defined herein);
• | the global economic crisis and its impact on operations;
• | performance of the oil and natural gas industry, including oil and natural gas commodity prices and supply and demand;
• | expansion, consolidation and other development trends of the oil and natural gas industry;
• | demand for and status of drilling rigs and other equipment in the oil and natural gas industry;
• | costs and financial trends for companies operating in the oil and natural gas industry;
• | world population and energy consumption trends;
• | that continental natural gas will continue to be part of the long-term energy solution for North America;
• | our business strategy, including the 2009 strategy and outlook for our business segments;
• | expansion and growth of our business and operations, including diversification of the Trust’s (as defined herein) earnings base, safety and operating performance, the size and capabilities of the Trust’s drilling and service rig fleet, the Trust’s market share and the Trust’s position in the markets in which it operates;
• | the potential impact and benefits of the Acquisition (as defined herein);
• | the integration of Precision (as defined herein) and Grey Wolf (as defined herein);
• | the opportunities stemming from a focus on global contract drilling through United States expansion;
• | international diversification opportunities and complementary product line expansion;
• | the impact of shale gas drilling in Canada and the United States;
• | that new drilling rigs are expected to be contracted with customers before completion;
• | the number of rigs under daywork term contracts in Canada, the United States and Mexico;
• | the potential rebound in land drilling activity;
• | the timing of completion of rigs in Precision’s rig build program;
• | that unconventional drilling applications will require high performance drilling rigs;
• | that some wells have a steep rate of production decline in the first year necessitating additional drilling to replace rapidly depleting wells;

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• | the demand for the Trust’s products and services;
• | the Trust’s management strategy, including transitions in executive roles;
• | labour shortages;
• | climatic conditions;
• | the maintenance of existing customer, supplier and partner relationships;
• | supply channels;
• | accounting policies and tax liabilities;
• | expected payments pursuant to contractual obligations;
• | the prospective impact of recent or anticipated regulatory changes;
• | that planned asset growth will generally be financed through existing debt facilities or cash retained from continuing operations;
• | financing strategy and compliance with debt covenants;
• | potential downgrades to credit ratings;
• | credit risks; and
• | other such matters.

All such forward-looking information and statements are based on certain assumptions and analyses made by the Trust in light of its experience and perception of historical trends, current conditions and expected future developments, as well as other factors the Trust believes 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 current global financial crisis and the dislocation in the credit markets;
• | fluctuations in the level of oil and natural gas exploration and development activities;
• | fluctuations in the demand for well servicing, contract drilling and ancillary oilfield services;
• | the impact of initiatives by the Organization of Petroleum Exporting Countries and other major petroleum exporting countries;
• | the ability of oil and natural gas companies to access external sources of debt and equity capital;
• | the effect of weather conditions on operations and facilities;
• | the existence of operating risks inherent in well servicing, contract drilling and ancillary oilfield services;
• | the 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;

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• | increased competition;
• | consolidation among the Trust’s customers;
• | risks associated with technology;
• | political uncertainty, including risks of war, hostilities, civil insurrection, instability or acts of terrorism;
• | liabilities under laws and regulations protecting the environment;
• | the impact of purchase accounting;
• | expected outcomes of litigation, claims and disputes and their expected effects on the Trust’s financial condition and results of operations;
• | difficulties and delays in achieving synergies and cost savings;
• | the lack of availability of qualified personnel or management;
• | credit risks;
• | increased costs of operations, including costs of equipment;
• | future capital expenditures and refurbishment, repair and upgrade costs;
• | expected completion times for new equipment manufacture and refurbishment and upgrade projects;
• | sufficiency of funds for required capital expenditures, working capital and debt service;
• | the failure to realize anticipated synergies in the Acquisition;
• | the Trust’s ability to enter into and the terms of future contracts;
• | the adequacy of sources of liquidity;
• | the inability to carry out plans and strategies as expected;
• | loss of “mutual fund trust” status;
• | the effect of the Canadian federal government’s SIFT Rules (as defined herein);
• | the conversion of the Trust into a corporate structure and other unforeseen conditions which could impact the use of services supplied by Precision;
• | fluctuations in interest rates;
• | stock market volatility;
• | safety performance;
• | foreign operations;
• | foreign currency exposure;
• | dependence on third party suppliers;
• | opportunities available to or pursued by the Trust; and
• | other factors, many of which are beyond the Trust’s control.

These risk factors are discussed in this Annual Information Form, the Trust’s Annual Report and Form 40-F on file with the Canadian securities commissions and the United States Securities and Exchange Commission (the ‘‘SEC”) and available on the Canadian System for Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com and the SEC’s Electronic Document Gathering and Retrieval System (“EDGAR”) 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.

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The forward-looking information and statements contained in this Annual Information Form are expressly qualified by this cautionary statement.
Unless otherwise stated, all references in this Annual Information Form to sums of money are expressed in Canadian dollars.
CORPORATE STRUCTURE
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 S.W., Calgary, Alberta, T2P 3Y7, telephone (403) 716-4500, facsimile (403) 264-0251, email info@precisiondrilling.com and website www.precisiondrilling.com. For a discussion of the Declaration of Trust, see “Description of Capital Structure”.
Pursuant to a reorganization of the former Precision Drilling Corporation (“Precision”) into a “mutual fund trust” for purposes of the Tax Act (as defined herein), the Trust issued units (“Trust Units”) to certain former shareholders of Precision in exchange for such holders’ common shares 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”).
Precision Drilling Limited Partnership
Precision Drilling Limited Partnership (“PDLP”) is a limited partnership formed pursuant to the laws of the Province of Manitoba pursuant to a limited partnership agreement dated as of September 28, 2005 (the “Limited Partnership Agreement”). The Trust holds a 99.91% partnership interest in PDLP through its holding of Class A Limited Partnership Units (the ‘‘PDLP A Units”) and the remaining 0.09% limited partnership interest in 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 general partner of PDLP is 1194312 Alberta Ltd. (the “General Partner”) which holds a nominal (0.001%) interest in PDLP. The head and principal offices of PDLP are located at 4200, 150 – 6th Avenue S.W., Calgary, Alberta, T2P 3Y7, telephone (403) 716-4500, facsimile (403) 264-0251 and 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 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: 1195309 Alberta ULC on November 23, 2005; Live Well Service Ltd. (“Live Well Service”) 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 S.W., Calgary, Alberta, T2P 3Y7, telephone (403) 716-4500, facsimile (403) 264-0251, email info@precisiondrilling.com and website www.precisiondrilling.com.
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;

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• | provide or cause to be provided to holders of Trust Units (“Trust Unitholders”) all information to which such Trust Unitholders are entitled under the Declaration of Trust, including relevant information with respect to financial reporting and income taxes;
• | call and hold meetings of Trust Unitholders and distribute required materials, including notices of meetings and information circulars, in respect of all such meetings;
• | assist the Board of Trustees (as defined herein) in calculating distributions to Trust 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.

INTERCORPORATE RELATIONSHIPS
The following table sets forth the names of the material subsidiaries (which includes limited partnerships) of the Trust, the percent of shares (or interest) owned by the Trust and the jurisdiction of incorporation, continuance or formation of each such subsidiary as of December 31, 2008:

|  |  |  |  |  |  | Jurisdiction of Incorporation,
Name of Subsidiary or Partnership |  |  | Percent or Interest Owned |  |  |  | Continuance or Formation
Precision Drilling Limited Partnership |  |  |  | 99.9 | % |  |  | Manitoba
1194312 Alberta Ltd. |  |  |  | 100 | % |  |  | Alberta
Precision Drilling Corporation |  |  |  | 99.9 | % |  |  | Alberta
Precision Drilling Oilfield Services, Inc. (“PDOSI”) |  |  |  | 99.9 | % |  |  | Delaware
Precision Drilling Oilfield Services Corporation (“PDOS”) |  |  |  | 99.9 | % |  |  | Texas
Precision Limited Partnership (“PLP”) |  |  |  | 99.9 | % |  |  | Alberta
Precision Drilling Canada Limited Partnership (“PDCLP”)(1) |  |  |  | 99.9 | % |  |  | Alberta
Grey Wolf Holdings |  |  |  | 99.9 | % |  |  | Texas
Grey Wolf Drilling Corporation LP |  |  |  | 99.9 | % |  |  | Texas

NOTE:

(1) |  | PDCLP was formed pursuant to the Partnership Act (Alberta) on January 2, 2009.

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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:
NOTES:

(1) |  | As of December 31, 2008, there were 125,606,341 PDLP A Units outstanding.
(2) |  | As of December 31, 2008, there were 151,583 Exchangeable Units outstanding.
(3) |  | The interest of 1194312 Alberta Ltd. in PDLP is 0.001%.
(4) |  | Inter-company note owing by PDLP to the Trust.
(5) |  | The Trust holds PDLP A Units and PDLP holds an interest bearing 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 such 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.

GENERAL DEVELOPMENT OF THE BUSINESS
Recent Developments

• | As at March 27, 2009, within the Secured Facility (as defined herein), US$69 million (US$64 million on February 4, 2009 and US$5 million on March 26, 2009) has been reallocated from the Term Loan A Facility (as defined herein) to the Term Loan B Facility (as defined herein). See “Description of the Business of Precision – Material Debt”.
• | As at March 20, 2009, holders of convertible notes of Grey Wolf representing US$262.3 million notified the Trust that they would be accepting the purchase offer made pursuant to the terms thereof and PDOS purchased such notes at the principal balance plus accrued interest of US$2.3 million on March 24, 2009. See “General Development of the Business – Three Year History – Acquisition of Grey Wolf”.
• | On February 19, 2009, the Trust announced that Precision had postponed its previously announced offering of US$250 million principal amount of senior notes due 2015 (the “Senior Note Offering”) due to unfavourable market conditions. See “Risk Factors – Proposed Financing Arrangements”.

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• | On February 18, 2009, the Trust closed an offering of 46 million Trust Units at a price of US$3.75 per Trust Unit for aggregate gross proceeds of US$172.5 million (the “Trust Unit Offering”). As a result of the Trust Unit Offering, the funds available under the Unsecured Facility were reduced to US$235 million.
• | On February 9, 2009, the Trust announced the suspension of cash distributions for an indefinite period for distributions to be paid after February 17, 2009. The suspension was taken in response to lower financial operating performance at the start of 2009 and will allow the Trust to increase debt repayment capability and balance sheet strength. Accordingly, Precision will not pay a distribution in March 2009, or for an indefinite period thereafter, to Trust Unitholders or holders of Exchangeable Units (“Exchangeable Unitholders” and, together with Trust Unitholders, the “Unitholders”). See “Risk Factors – Distributions on Trust Units have been suspended and may not be reinstated”.
• | The Trust’s business depends on the level of spending by oil and natural gas companies for exploration and development activities. Therefore, a sustained increase or decrease in the price of oil or natural gas, which could have a material impact on exploration and development activities, could also materially affect the Trust’s financial position, results of operations and cash flows. The recent decline in commodity prices has primarily been driven by the deterioration of the global economic environment, including, without limitation, volatility in the capital markets and lack of liquidity in the credit markets. Recent commodity price declines for oil and natural gas are expected to reduce funding for drilling and well servicing activity in North America which will likely result in reduced demand for oilfield services in the near term. Subject to the severity of the current winter heating season and demand levels for natural gas in North America, the current economic slowdown could moderate energy consumption growth and may result in lower producer spending for marginal oil and natural gas programs, which may adversely affect the demand for Precision’s services. See “Risk Factors – The operations of Precision are dependent on the price of oil and natural gas”.
• | Precision has experienced a reduction in the demand for its services in late 2008 and early 2009 in correlation with the significant downward trend in oil and natural gas prices over the same period. The following table summarizes the active land-based drilling rigs of Precision and the drilling industry as a whole in Canada and the United States as at the dates indicated:

|  | As at September 30, 2008 |  | As at December 31, 2008
|  | Industry(1) |  | Precision(2)(3) |  | Industry(1) |  | Precision(3)
Canada |  | 416 |  | 123 |  | 277 |  | 61
United States |  | 1,995 |  | 138 |  | 1,721 |  | 115
Total |  | 2,411 |  | 261 |  | 1,998 |  | 176

NOTES:

(1) |  | Source: Canada – Canadian Association of Oilwell Drilling Contractors (“caodc”); United States – Baker Hughes, Inc.
(2) |  | On a pro forma basis after giving effect to the Acquisition.
(3) |  | Does not include Precision’s two active drilling rigs in Mexico.

Management of the Trust believes that Precision will be able to meet its debt obligations under the Credit Facilities notwithstanding the current and anticipated near-term decline in drilling and well servicing activity. See “Description of the Business of Precision – Material Debt” and “Risk Factors – Deteriorating conditions in the credit markets may adversely affect business”.

• | On January 2, 2009, Precision transferred substantially all of the assets of its Precision Drilling, Rostel Industries (“Rostel Industries”) and Columbia Oilfield Supply (“Columbia”) divisions to PDCLP in consideration for a 99% limited partnership interest in PDCLP. PDCLP carries on Precision’s Contract Drilling Services business. See “Description of the Business of Precision – Contract Drilling Services”.

Three Year History
The Trust is an unincorporated open-ended investment trust established under the laws of the Province of Alberta pursuant to the Declaration of Trust. The beneficiaries of the Trust are the Unitholders. The Trust’s principal

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undertaking is to issue Trust Units and to indirectly carry on the business of the provision of land-based contract drilling, well servicing and ancillary oilfield services to oil and gas exploration and production companies through its direct and indirect subsidiaries. This business is carried out in two segments, Contract Drilling Services and Completion and Production Services.
As of December 31, 2008, Management believes that the Trust is the second largest land driller in North America, based on the number of rigs in its drilling rig fleet. The Trust presently operates in most conventional and unconventional oil and natural gas basins in Canada and the United States and has an emerging presence in Mexico. Management believes that the Trust’s high performance drilling rigs, supply chain management systems and technology, together with its Canadian and United States customer base, deep drilling capabilities and positions in Canadian and United States sedimentary basins, provides it with a substantial foundation for expansion, both in North America and internationally. After giving effect to the Acquisition, the Trust has a high quality fleet consisting of 374 drilling rigs, 229 service rigs and 29 snubbing units. In addition, Precision presently offers its customers a complementary suite of wellsite products and services including camp and catering, wastewater treatment and rental equipment. Most of these complementary operations and the service rig business are located in Canada.
2008
On December 23, 2008, the Trust completed the indirect acquisition of Grey Wolf, Inc. (“Grey Wolf”) (the “Acquisition”) pursuant to an agreement and plan of merger dated August 24, 2008, as amended December 2, 2008 (the “Merger Agreement”) with Grey Wolf, Precision and Precision Lobos Corporation (“Lobos” a subsidiary of the Trust). Pursuant to the Acquisition, Grey Wolf was merged with and into Lobos pursuant to the Texas Business Corporations Act and the Texas Corporation Law. Accordingly, the separate legal existence of Grey Wolf has ceased and Lobos, which was subsequently renamed “Precision Drilling Oilfield Services Corporation”, became the surviving corporation. Upon the closing of the Acquisition, Messrs. Frank M. Brown, William T. Donovan and Trevor M. Turbidy, each of whom was a director of Grey Wolf, were appointed to the Board of Directors of Precision.
Under the terms of the Merger Agreement, shareholders of Grey Wolf elected to receive either cash or Trust Units in exchange for their shares of Grey Wolf common stock. Each share of Grey Wolf common stock was convertible, at the option of the holder, into US$9.02 in cash or 0.4225 Trust Units, subject to proration. The total consideration paid by the Trust to shareholders of Grey Wolf in connection with the Acquisition was approximately US$897.2 million and 34.4 million Trust Units. Costs of approximately US$219.2 million (after accounting for applicable discounts), including a US$25 million break-up fee payable by Grey Wolf to a third party, debt issuance costs, professional services fees, severance costs and other costs were incurred in respect of the Acquisition.
At closing of the Acquisition, Grey Wolf had outstanding US$262.3 million aggregate principal amount of convertible notes. Pursuant to the terms of the convertible notes, during the first quarter of 2009, PDOS, as successor to Grey Wolf, made to the holders thereof a change of control offer to repurchase any or all of the outstanding convertible notes at 100% of the principal amount thereof, plus accrued but unpaid interest to the date of the repurchase, payable in cash. As at March 20, 2009 the holders of such notes representing US$262.3 million have notified the Trust that they will be accepting the purchase offer made pursuant to the terms thereof. PDOS purchased such notes at the principal balance plus accrued interest of approximately US$2.3 million on March 24, 2009.
The Acquisition is described in greater detail in the business acquisition report of the Trust dated January 21, 2009, in respect of the Acquisition (the “BAR”) and the material change report of the Trust dated December 23, 2008, in respect of the Acquisition (the “Grey Wolf MCR”), both the BAR and the Grey Wolf MCR having been filed on SEDAR at www.sedar.com and EDGAR at www.sec.gov. The BAR also contains audited annual financial statements of Grey Wolf for the year ended December 31, 2007, unaudited comparative interim financial statements of Grey Wolf for the nine months ended September 30, 2008 and unaudited pro forma consolidated financial statements of the Trust for the year ended December 31, 2007 and nine months ended September 30, 2008 that give effect to the Acquisition.
On July 31, 2008, Precision also closed the acquisition of six service rigs from a private well servicing company for approximately $16 million. The assets are positioned in south-eastern Saskatchewan and southwestern

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Manitoba and strengthen Precision’s capabilities in these oil regions. Subsequent to this acquisition, Precision moved an additional three service rigs into these regions.
Precision’s Super Seriestm drilling rig build program in 2008 was comprised of 10 Super Singletm rigs and nine Super Triple rigs. Eighteen of these rigs are under signed term customer contracts. Management expects the remaining capital cost of the rig build program for 2009 to be approximately $167 million. Of the 19 rigs, three were completed in 2008 and management expects the remaining contracted rigs to be delivered before the fourth quarter of 2009.
On September 1, 2008, Precision transferred substantially all of the assets of its Precision Well Servicing, Live Well Service, Precision Rentals and LRG Catering (“LRG”) divisions to Terra Water Systems Limited Partnership, which subsequently changed its name to “Precision Limited Partnership”. PLP carries on Precision’s Completion and Production Services business. See “Description of the Business of Precision – Completion and Production Services”.
On August 31, 2008, certain non-compete obligations from a 2005 business divestiture that restricted the Trust’s growth outside of North America and in certain business lines expired. Through its international subsidiaries, the Trust can now pursue global contract drilling opportunities without restriction.
In addition to the Acquisition, Precision’s organic growth in the United States accelerated during 2008 with 18 rigs moved from Canada.
Pursuant to amendments to the Income Tax Act (Canada) (the “Tax Act”) made effective on October 31, 2006 (the “SIFT Rules”, and which, for greater certainty, include all proposed amendments to said rules publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof on the assumption that such proposed amendments will be executed substantially in the form proposed), a trust that is resident in Canada for purposes of the Tax Act, that holds one or more “non-portfolio properties”, and the units of which are listed on a stock exchange or other public market (a “SIFT trust”) will be subject to tax at the prevailing federal corporate income tax rate, plus an additional provincial tax factor, on certain of its income paid, or made payable, to unitholders, and such distributions will be treated as eligible dividends paid by a taxable Canadian corporation. In general terms, a trust that existed on October 31, 2006 and to which the SIFT trust legislation otherwise would apply should not be a SIFT trust until the earlier of January 1, 2011 or the first day after December 15, 2006 that the trust exceeds “normal growth” determined by reference to guidelines first issued on December 15, 2006 by the Minister of Finance (Canada) and amended effective December 31, 2008 (the “Guidelines”). Provided that the Trust does not issue new equity in an amount greater than the “safe-harbour” determined by the market capitalization of the Trust on October 31, 2006, the Trust should not be considered to exceed “normal growth” and should not be a SIFT trust until January 1, 2011. However, no assurances can be provided that the Trust will not become a SIFT trust prior to January 1, 2011. The SIFT Rules (including the Guidelines) may adversely effect the marketablility of the Trust Units and the ability of the Trust to undertake financings and acquisitions, and at such time as the new rules apply to the Trust, the distributions on Trust Units may be materially reduced.
On March 12, 2009 specific proposals to amend the Tax Act that are intended to facilitate the conversion of mutual fund trusts (as defined in the Tax Act) into corporations (the “SIFT Conversion Rules”) on a, generally, tax-deferred basis were enacted. These transition rules are only available to trusts that convert to corporations prior to January 1, 2013.
The Trust, with input from external legal and financial advisors, is carefully assessing the impact of the SIFT Rules on the business and financial outlook of the Trust and its broader effect on the income trust sector as a whole. The Board of Trustees continues to examine 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. See “Risk Factors – A change in the structure of the Trust may have an adverse effect on the Unitholders”.
2007
In 2007, Precision increased capital spending on additions to property, plant and equipment to grow and upgrade its high performance drilling rig fleet in Canada and the United States, significantly expanded its contract drilling operations in the United States and mobilized one drilling rig for a project in Chile.

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Precision invested $141 million in expansion capital for the purchase of property, plant and equipment and $46 million in upgrade capital in 2007. In 2007, Precision commissioned 16 new drilling rigs and two new service rigs and decommissioned 11 drilling and 16 service rigs.
In 2007, Precision deployed an additional seven Super Singletm rigs and four triple diesel-electric rigs for work contracted in Texas, Colorado, Oklahoma and Wyoming. In early 2008, Precision also mobilized one additional Super Singletm rig to Colorado and one additional triple diesel-electric rig to New York, bringing its fleet of high performance drilling rigs operating in the United States to 14, and entered into contracts for the delivery of three additional new Super Singletm rigs to Colorado in 2009.
On January 1, 2007, Precision amalgamated with Terra.
2006
During 2006, Precision focused capital spending on additions to property, plant and equipment to grow and upgrade its rig fleet and initiated contract drilling operations in the United States.
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 expanded the diversity of services Precision offers customers. Also on August 17, 2006, Terra transferred substantially all of its net assets to Terra Water Systems Limited Partnership.
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 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 Singletm drilling rig to Texas. Precision deployed a second drilling rig to the United States from Canada in early 2007 which commenced drilling in Colorado.
On January 1, 2006, Precision amalgamated with Live Well Service.
DESCRIPTION OF THE BUSINESS OF PRECISION
General
Precision’s continuing operations are carried out in two segments: Contract Drilling Services and Completion and Production Services. In Canada, the Contract Drilling Services segment included land drilling services, camp and catering services, procurement and distribution of oilfield supplies and the manufacture and refurbishment of drilling and service rig equipment, and the Completion and Production Services segment included 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. In the United States, the Contract Drilling Services segment includes land drilling services and trucking services for the movement of Precision rigs. Internationally, the Contract Drilling Services segment includes land drilling services. As at December 31, 2008, Precision had over 7,200 employees.

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Precision’s revenue by business segment from continuing operations is illustrated in the following table:
(in thousands of Canadian dollars)

Years ended December 31, |  | 2008(1) |  | 2007 |  | 2006
Contract Drilling Services |  | $809,317 |  | $694,340 |  | $1,009,821
Completion and Production Services |  | 308,624 |  | 327,471 |  | 441,017
Inter-segment Eliminations |  | (16,050) |  | (12,610) |  | (13,254)
Total Revenue |  | $1,101,891 |  | $1,009,201 |  | $1,437,584

NOTE:

(1) |  | Includes PDOS revenue for the eight day period from December 23, 2008 through December 31, 2008.

In North America, the economics of oilfield services align with global and regional fundamentals. Important regional drivers include the underlying hydrocarbon make-up of the sedimentary basins where Precision’s customers explore for and develop natural resources and the existence of an established, competitive and efficient oilfield service infrastructure. Increasingly, natural gas production is driving economics in North America as approximately 60% of new well completions in Canada and 80% of new well completions in the United States in 2008 targeted natural gas.
The hydrocarbon structures in North America are diverse with conventional and unconventional sources of oil and natural gas reservoirs existing at a variety of depths. In Canada, such depths are comparatively shallow by global standards. Conventional sources are complemented by more costly and challenging unconventional reservoirs associated with oil sands, heavy oil and natural gas in coal, in shale and in deeper, low permeability formations. Unconventional reservoirs typically require more complex drilling and completion technologies, including high performance rigs and directional and horizontal drilling techniques, to effectively develop. As between Canada and the United States, approximately 70% of the proven natural gas reserves are situated in the United States with the remaining 30% in Canada. Today, Canada is the world’s seventh 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. In Canada, there are three major areas that are considered unconventional resource plays: the Montney and Horn River shale gas plays in northeastern British Columbia; the Bakken shale play in southern Saskatchewan; and the heavy oil and oil sands in northeastern Alberta. In the United States there are several unconventional resource plays, two of which are believed to present the greatest growth potential for Precision: the Haynesville play in Texas and Louisiana and the Marcellus play in New York and Pennsylvania. Precision has a growing presence in those and the other major unconventional plays in Canada and the United States.
The ability to move heavy equipment in oil and natural gas fields in Canada and the northern United States is dependent on weather conditions. As warm weather returns in the spring, the thawing of ground frost typically renders secondary roads incapable of supporting the weight of heavy equipment until such time as the roads have thoroughly dried. The duration of spring breakup has a direct impact on Precision’s activity levels. In addition, many exploration and production areas in northern Canada are accessible only in winter when the ground is frozen enough to support the transportation of heavy equipment. The timing of winter freeze-up and spring breakup affects Precision’s ability to move equipment in and out of these areas. Wet weather can further defer commencement of drilling or servicing operations on any given day or well location.
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.

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The economics of oilfield services providers are largely driven by current and expected prices 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 through 2008 peaked for natural gas in December 2005 and for oil in July 2008. The price for gas has fluctuated from that time and is currently at lower levels when compared to pricing trends over the past five years.
Contract Drilling Services
In Canada, as at December 31, 2008, the Contract Drilling Services segment comprised:

• | Precision Drilling – 220 land drilling rigs in Canada;
• | LRG – 97 drilling and base camps with food catering in Canada and three drilling camps in the United States;
• | Rostel Industries – engineering, machining, fabrication, component manufacturing and repair services for drilling and service rigs primarily for Precision’s operations; and
• | Columbia – centralized procurement, inventory and distribution of consumable supplies primarily for Precision’s operations.

In the United States, as at December 31, 2008, the Contract Drilling Services segment comprised:

• | PDOS – 121 land drilling rigs in the United States; and
• | PDOSI – 30 land drilling rigs in the United States including one scheduled to be mobilized from Canada.

Internationally, as at December 31, 2008, the Contract Drilling Services segment comprised:

• | A Precision affiliate – two land drilling rigs in Mexico; and
• | A Precision affiliate – one land drilling rig in Chile.

Precision Drilling
The Precision Drilling division owned and operated the largest fleet of land drilling rigs in Canada, with 220 actively marketed drilling rigs located throughout western Canada, accounting for approximately 25% of the industry’s fleet of 884 drilling rigs in Canada at December 31, 2008.
In the United States at December 31, 2008, Precision had a fleet of 151 land drilling rigs representing approximately 7% of the estimated total marketed land drilling rigs, primarily operating in the following drilling markets: Ark-La-Tex (northeast Texas, northern Louisiana and southern Arkansas); United States Gulf Coast in southern Louisiana and the upper Texas Gulf Coast; Mississippi/Alabama; South Texas; Rocky Mountain (Wyoming, Colorado, northwest Utah and northern New Mexico); Mid-Continent (west Texas, southwest New Mexico, the Barnett Shale area in north Texas and the mid-continent region); and Appalachia (New York and Pennsylvania). The 151 land drilling rig fleet in the Unites States comprises the 30 rigs operated by PDOSI and the 121 rigs acquired in connection with the Acquisition.
Internationally, as at December 31, 2008, Precision had two land drilling rigs acquired in connection with the Acquisition operating in Mexico and one Precision land drilling rig racked in Chile.
In 2008, Precision had approximately 450 customers including approximately 250 in Canada and approximately 200 in the United States, which included independent producers and major oil and gas companies. In fiscal 2008, only one customer accounted for more than 10% of Precision’s revenue.
Precision primarily markets its drilling rigs on a regional basis through employee sales personnel and contracts for drilling oil and natural gas wells are obtained either through competitive bidding or as a result of relationships and negotiations with customers. Contract terms offered by Precision are generally dependent on the complexity and risk of operations, on-site drilling conditions, type of equipment used and the anticipated duration of the work to be performed. Drilling contracts can be for a single or multiple wells and may vary in duration from a day or two on shallow single well applications to multiple year, multiple well drilling programs. Term drilling

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contracts typically contain early termination penalties while non-term contracts are typically subject to termination by the customer on short notice or with little or no penalty.
Oil and natural gas well drilling contracts are carried out on a daywork, metreage or turnkey basis. On a daywork basis, Precision contracts to provide a drilling rig with required personnel where the customer supervises the drilling of the well and Precision charges the customer a fixed rate per day regardless of the number of days needed to drill the well. Daywork contracts usually also provide for a reduced day rate (or a lump sum amount) for mobilization of the rig to the well location and for both rig-up and rig-down of the rig. On a daywork basis, 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). Under a metreage contract, Precision would be paid a fixed charge for each metre drilled regardless of the time required or the problems encountered in drilling the well or, in some cases, may be carried out on a metreage basis to a specified depth and on a daywork basis thereafter. Under a turnkey contract, Precision contracts to drill a well to an agreed depth, under specified conditions, for a fixed price. Compared to daywork contracts, metreage and turnkey contracts involve a higher degree of risk to Precision and, accordingly, normally provide greater profit or loss potential. See “Risk Factors – Unexpected cost overruns on turnkey drilling jobs could adversely affect Precision’s revenues”. From time to time, Precision may also enter into informal, non-binding commitments with its customers to provide drilling rigs for future periods at agreed upon rates plus fuel and mobilization charges, if applicable, and escalation provisions. In Canada, Precision’s contracts have been carried out almost exclusively on a daywork basis. In the United States, the majority of Precision’s contracts have been carried out on a daywork basis, with only approximately 13% performed on a turnkey basis, subsequent to the Acquisition. Precision’s newly built drilling rigs tend to have term contracts in place prior to the rig being completed and in many cases have a three to five year capital payout contract in place at the time construction commences.
Precision’s rig fleet can drill virtually all types of on-shore conventional and unconventional oil and gas wells in North America. These rigs are particularly adept in developing unconventional resources such as oil sands, natural gas in coal or in shale or tight gas reservoirs. The increase in drilling-intensive unconventional resource plays creates opportunities for technically innovative and operationally efficient drillers like Precision.
Precision’s drilling rigs have varying configurations and capabilities which enable Precision to provide services in virtually all areas of drilling activity in North America, with rig capacities of up to 4,000 horsepower. Conventional rigs are configured to handle either one, two or three joints of standard length 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.
To facilitate customer requirements Precision also utilizes top drives in its drilling operations. A top drive is suspended in the mast of the drilling rig and is powered by a hydraulic or electric motor and is used to rotate the drill string in the place of a traditional rotary table and kelly bushing. Top drives enable the use of 30-metre or 15-metre lengths of drill pipe on triple, double and Super Singletm rigs, respectively, rather than traditional 10-metre lengths thereby reducing the number of required connections in the drill string and generally increasing drilling efficiency. At the end of 2008, Precision had 15 mobile and 58 integrated top drives in its operations in Canada and 37 mobile and 16 integrated top drives in the United States.
Single, double and coiled tubing rigs are generally used in the shallow drilling markets in Canada, while triple rigs, which have greater hoisting capacity, are used in deeper exploration and development drilling applications such as the foothills and Rocky Mountain regions of Canada, and the United States, in Louisiana and in west Texas.
Precision’s rig fleet includes Super Singletm rigs which are manufactured by Precision and are equipped with top drive drilling systems, extended length drill pipe and an automated pipe handling system and generally have slant drilling capability. Precision believes the Super Singletm rig category will continue to offer significant revenue growth. In addition to conventional wells, Precision’s Super Singletm rigs have been adapted to meet a variety of operational needs in Canada, the United States and internationally.
The Super Singletm Light is a scaled-down version of the Super Singletm without slant drilling capabilities. These rigs have been built for drilling shallow wells. Using extended length drill pipe, the design incorporates

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proven technology and reliability in a light weight, easily moved load configuration. The Super Singletm Light competes with coiled tubing rigs and offers greater drilling capability over a wider range of well configurations than coiled tubing rigs.
Rigs built by Precision are designed for greater safety and operating efficiency to deliver well cost savings to customers. High performance drilling rigs combine high mobility, automation, advanced control systems, minimal environmental impact, and highly trained crews. Over the past 13 years Precision has been developing the Super Seriestm drilling rigs and has built 40 Super Singletm, seven Super Singletm Light and ten Super Triple rigs. 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 176 of Precision’s drilling rigs are diesel-electric powered, including 70 in Canada, 103 in the United States and 3 internationally, with the remaining rigs being mechanically powered. Diesel-electric powered rigs provide more precise control of drilling components than mechanical rigs and are well suited for horizontal and directional drilling. Many of the diesel electric rigs are AC power driven which provides more efficient power conversion and smaller component size and weight. Many of Precision’s mechanically powered rigs are also capable of horizontal and directional drilling.
The following table lists the capacity of Precision’s land drilling rigs as at December 31, 2008:

Region |  |  | Rig Capacity |  |  | Total
|  |  | < 500 Hp |  |  | 500 - 999 Hp |  |  | 1,000 - 1,499 Hp |  |  | 1,500 - 1,999 Hp |  |  | >2,000 Hp |  |  |
|  |  | Electrical |  |  | Mechanical |  |  | Electrical |  |  | Mechanical |  |  | Electrical |  |  | Mechanical |  |  | Electrical |  |  | Mechanical |  |  | Electrical |  |  | Mechanical |  |  |
Canada |  |  | 2 |  |  | 105 |  |  | 19 |  |  | 78 |  |  | 12 |  |  | 2 |  |  | 1 |  |  | - |  |  | 1 |  |  | - |  |  | 220
United States |  |  | - |  |  | - |  |  | 3 |  |  | 28 |  |  | 42 |  |  | 15 |  |  | 29 |  |  | 4 |  |  | 30 |  |  | - |  |  | 151
International |  |  | - |  |  | - |  |  | 1 |  |  | - |  |  | - |  |  | - |  |  | - |  |  | - |  |  | 2 |  |  | - |  |  | 3
Total Fleet |  |  | 2 |  |  | 105 |  |  | 23 |  |  | 106 |  |  | 54 |  |  | 17 |  |  | 30 |  |  | 4 |  |  | 33 |  |  | - |  |  | 374

In 2008 there was a net reduction of 14 drilling rigs or approximately 2% in the Canadian industry fleet. Approximately 338 drilling rigs were added to the number of marketed rigs in the United States during 2008, an increase of approximately 15% over 2007. In 2006, customer demand for drilling conventional oil and natural gas wells, in combination with improving commercialization of natural gas in coal and in shale, oil sands, heavy oil and deeper natural gas formations had driven demand for rigs to record levels but the slowdown in drilling activity commencing in the second half of 2006 led to reduced 2007 and 2008 rig utilization rates. In 2008, Precision’s average land drilling rig utilization in Canada was approximately 37% compared to 35% in 2007. In the United States, Precision’s average land drilling rig utilization was approximately 95% in 2008 and 99% in 2007.
During 2008, Precision achieved a utilization rate of 37% for its Canadian drilling rigs compared to the estimated average industry utilization rate in Canada of 42% and a utilization rate of 95% for its United States rigs compared to an estimated industry utilization rate of 77%. Precision strives to balance utilization and optimal profitability given competitive pricing and seasonal reductions in drilling demand during the second and third quarters.
The drilling industry 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 generally comprised of a rig manager, driller, derrickman, motorman, two floormen and possibly a leaseman. Rig crew configuration may vary from three crews working 8-hour shifts to two crews working 12-hour shifts, with varying rotations for days off. The floorman and leaseman 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 and competent crew is a competitive strength, highly valued by Precision’s customers.
The shortage of labour in the oilfield service industry in recent years continues with human resource issues 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

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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. Precision focuses on the retention of existing employees through initiatives that provide a safe and productive work environment and opportunity for advancement and, in some cases, added wage security through programs such as the Designated Driller Program in Canada.
LRG Catering
LRG provides food and accommodation to personnel working at the wellsite, typically in remote locations in western Canada. LRG has 97 drilling camps and base camps representing approximately 10% of the camp and catering business in western Canada and three drilling camps in the United States. In Canada, LRG also provides food service for all field workers on a location. LRG’s mobile camps include five or six units and can accommodate 20 to 25 crew members and individual dormitory units that can accommodate up to 45 workers. 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 per 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 worksite, often in camps, throughout the duration of a project. 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 80% of Rostel Industries’ 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 fleets. In addition to quality construction and repair services, Rostel Industries 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 Industries’ 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. Rostel Industries designs and builds a significant portion of the components for Precision’s Super Singletm drilling rigs and is developing products that can be applied to new rigs and retro-fitted to improve the versatility of many of Precision’s existing rigs. Strategically, Rostel Industries gives Precision the ability to control cost, quality and production schedules that meet customer requirements.
Columbia Oilfield Supply
Columbia 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 Precision. 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
As at December 31, 2008, Precision’s Completion and Production Services segment comprised the following businesses in Canada:

• | Precision Well Servicing – 229 well completion and workover service rigs;
• | Live Well Service – 29 snubbing units;

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• | Precision Rentals – approximately 12,000 rental items including well control equipment, surface equipment, specialty tubulars and wellsite accommodation units; and
• | Terra Water – 76 wastewater treatment units.

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 – completion, workover, abandonment, well maintenance, high pressure and critical sour gas well work and re-entry preparation. Precision’s service rig fleet completes all types of new wells and works over existing wells to optimize oil and natural gas production. The configuration of the Precision Well Servicing fleet as at December 31, 2008 is illustrated in the following table:

Type of Service Rig |  |  |  |  |  | Horsepower |  |  |  | 2008 |  |  |  | 2007 |  |  |  | 2006 |
Singles |  |  | Mobile single |  |  |  | 150-400 |  |  |  |  | 2 |  |  |  |  | 5 |  |  |  |  | 12 |
|  |  | Freestanding mobile |  |  |  | 150-400 |  |  |  |  | 97 |  |  |  |  | 94 |  |  |  |  | 92 |
Doubles |  |  | Mobile |  |  |  | 250-550 |  |  |  |  | 42 |  |  |  |  | 43 |  |  |  |  | 44 |
|  |  | Freestanding mobile |  |  |  | 200-550 |  |  |  |  | 23 |  |  |  |  | 9 |  |  |  |  | 9 |
|  |  | Skid |  |  |  | 300-860 |  |  |  |  | 48 |  |  |  |  | 55 |  |  |  |  | 65 |
Slants |  |  | Freestanding |  |  |  | 250-400 |  |  |  |  | 17 |  |  |  |  | 17 |  |  |  |  | 15 |
Total Fleet |  |  |  |  |  |  |  |  |  |  |  | 229 |  |  |  |  | 223 |  |  |  |  | 237 |

At the end of 2008, Precision Well Servicing had an industry market share of approximately 21% with a rig fleet of 229 rigs after the acquisition of six rigs, while the average registered CAODC industry fleet was approximately 1,100 service rigs in western Canada. Precision Well Servicing continued to upgrade its fleet through initiatives that included freestanding conversions and new transporters along with engines and combination trailers. As at December 31, 2008, Precision Well Servicing had 137 freestanding service rigs representing 60% 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.
Well servicing requires its own unique skill set and – in addition to physical work, harsh weather and other factors – crews must deal with the potential dangers and safety concerns of working with pressurized wellbores. A typical service rig crew has four members: driller, derrickman and two floormen, in addition to the rig manager. Servicing wells often means the customer must coordinate activities of several service companies, so work normally takes place in daylight hours. Jobs are typically shorter in well servicing than contract drilling so the ability of a service rig to move quickly from one site to another is critical. Precision Well Servicing 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.
The Precision Well Servicing rig fleet is deployed throughout western Canada to improve efficiency and reduce travel time to wellsites. Well servicing operations have two distinct functions – completions and workovers. 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. Completions accounted for approximately 32% and workovers accounted for 68% of total activity for Precision Well Servicing in 2008, no change from 2007.

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After a well is initially drilled, the customer contracts a service provider such as Precision Well Servicing to supply the crew and equipment to complete the well. Completion services prepare a newly drilled well for initial production and may involve cleaning out the wellbore and the installation of production tubing, downhole equipment and wellheads. Service rigs work jointly with other services to perforate the wellbore 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 Precision Well Servicing provides a service rig to assist during most or all of this process.
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 wellbore, such as lost tools. Workover activities may require a few days to several weeks to complete. During this time, Precision Well Servicing may work alongside other oilfield service providers on the well location while other services are being directed by the customer.
A typical gas well in western Canada is likely to require one or more workovers during its operating life compared with four or five workovers for some conventional oil wells. Wells for some heavy oil and bitumen production could require many workovers during their lifecycle. Workovers take place over the producing life of the well and involve a variety of activities to restore or enhance production. Well maintenance services are often required to ensure continuous and efficient operation of producing wells. These services include routine mechanical repairs such as repairing failed wellbore pumping equipment or replacing damaged rods and tubing.
Live Well Service
Live Well Service markets 22 portable hydraulic rig-assist snubbing units, six self-contained units and one rack and pinion unit in western Canada for a market share of approximately 24%. Snubbing units are equipped with specialized pressure control devices which allow tubing to be pushed (snubbed) into and pulled out of a wellbore while a well is under pressure and production has been suspended.
Traditional well servicing operations require the pressure in a well to be neutralized prior to performing such operations so they can be conducted safely. Some reservoirs can be damaged if a well is neutralized 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 neutralizing the well.
Live Well Service has three types of snubbing units: rig-assist, self-contained and rack and pinion. Rig-assist units work with a service rig to complete the snubbing activity for a well. Self-contained and rack and pinion units do not require a service rig on site and are capable of snubbing and many other services traditionally completed by a service rig. Snubbing is primarily used to enhance natural gas production on gas wells.
Precision Rentals
Precision Rentals is a provider of oilfield rental equipment with four operating centres and 12 stocking points located throughout western Canada as well as a central technical support centre in Edmonton, Alberta. Most exploration and production companies do not own the specialty equipment used in oil and gas operations and rely on suppliers such as Precision Rentals for access to large inventories of drilling, completion and production equipment.
Precision Rentals’ inventory of equipment is marketed through three product categories: surface equipment; tubulars and well control equipment; and wellsite accommodation units. Surface equipment includes 2,300 drilling and production tanks and other equipment primarily associated with fluid handling. Tubular equipment includes approximately 9,000 joints of specialty-sized drill pipe and collars. Well-control equipment includes handling tools and equipment such as blowout preventers and diverter systems. Wellsite accommodations comprise 250 fully equipped units that provide office and lodging for oil and gas field personnel.

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Precision Rentals also supplies the patented Vapour Tight Oil Battery which allows for single well production of oil with hydrogen sulphide (H2S) content through the use of a 500 barrel NACE (National Association of Corrosion Engineers) certified vessel with gas metering and flaring capabilities.
Terra Water Systems
Terra’s principal role is the provision of portable on-site wastewater handling, treatment, and disposal expertise within a remote worksite environment. Terra’s equipment focuses on reducing environmental impacts from wastewater generated on-site.
The wastewater treatment units are designed and manufactured in-house and are built to industry leading standards. Terra provides regular servicing for all of its equipment and tests treated effluent samples to ensure the units are producing high quality treated effluent with no detectible odours. Terra has 76 portable treatment units comprising approximately 9% of the industry within the remote work site market in western Canada.
Terra’s fleet of 52 large units can accommodate camp sites of up to 50 people and several units can be combined to serve large-scale base camp configurations. To meet specific requests from customers, Terra has also developed a fleet of 24 smaller models which are better suited to lower volume requirements of remote locations that accommodate less than 15 people.
Material Debt
In connection with the Acquisition, Precision entered into a new US$1.2 billion senior secured credit facility with a syndicate of lenders consisting of the Royal Bank of Canada, RBC Capital Markets, Deutsche Bank AG Cayman Islands Branch, Deutsche Bank Securities Inc., HSBC Bank Canada, HSBC Bank USA, National Association and the Toronto-Dominion Bank (the “Commitment Banks”), and certain other lenders (the “Secured Facility”) that is guaranteed by the Trust and is comprised of US$800 million of term loans and a US$400 million revolving credit facility and also entered into a US$400 million unsecured credit facility (sometimes referred to as a bridge loan) with certain of the Commitment Banks (the “Unsecured Facility” and, together with the Secured Facility, the “Credit Facilities”) that is also guaranteed by the Trust. The Credit Facilities funded the cash portion of the Acquisition and refinanced the pre-closing Precision bank debt and certain pre-closing debt obligations of Grey Wolf. On February 18, 2009, the Trust received gross proceeds of US$172.5 million from the Trust Unit Offering. As a result of the Trust Unit Offering, the funds available under the Unsecured Facility were reduced to US$235 million. The Unsecured Facility was used in the repurchase of US$262.3 million principal amount of Grey Wolf convertible notes tendered for repurchase by holders under a change of control offer made by PDOS in the first quarter of 2009. Taking into account upfront issue discount and applicable fees, the all-in cost of capital borrowing under the Credit Facilities at December 31, 2008 was approximately 13%. See “General Development of the Business – Recent Developments” and “Three Year History – 2008”.
In order to complete a successful syndication of the Secured Facility, the Commitment Banks are entitled, prior to March 23, 2009 (extended at Precision’s option to May 22, 2009) in consultation with Precision, to change certain of the terms of the Credit Facilities including, without limitation, to implement additional increases in interest rates, original issue discounts and/or upfront fees, reallocate up to US$250 million between the Term Loan A Facility (as defined herein) and the Term Loan B Facility (as defined herein) (US$69 million (US$64 million on February 4, 2009 and US$5 million on March 26, 2009) of which has been reallocated from the Term Loan A Facility to the Term Loan B Facility as at March 27, 2009), reallocate up to US$150 million between the Secured Facility and the Unsecured Facility and amend certain covenants, financial ratio tests and other provisions for portions of the Secured Facility.
The following is a summary of the material terms of the Secured Facility and the Unsecured Facility. Potential investors may refer to copies of the credit agreements governing such facilities, which are available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.
Secured Facility
Precision (as borrower) and the Trust (as a guarantor) have entered into a credit agreement dated December 23, 2008, as amended, governing the Secured Facility with the lenders parties thereto, Royal Bank

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of Canada, as administrative agent, Deutsche Bank Securities Inc., as syndication agent, and HSBC Bank Canada and The Toronto-Dominion Bank, as co-documentation agents.
The Secured Facility provides senior secured financing of up to approximately US$1.2 billion, consisting of (after giving effect to the reallocation between the Term Loan A Facility and the Term Loan B Facility):

• | a term loan A facility in an aggregate principal amount of US$331 million (the “Term Loan A Facility”);
• | a term loan B facility in an aggregate principal amount of US$469 million (the “Term Loan B Facility”); and
• | a revolving credit facility in the amount of US$400 million (the “Revolving Credit Facility”).

The terms of the Secured Facility include:

• | a blended effective cash interest rate, as at February 4, 2009, of approximately 8% per annum, before original issue discounts and upfront fees;
• | covenants requiring the Trust and Precision to comply with certain financial ratios;
• | limits on distributions based on 20% of the Trust’s operating cash flow before changes in working capital, provided that 50% of operating cash flow generated in excess of certain base case projections will also be permitted to be paid as distributions, subject to an overall cap of 30% of aggregate operating cash flow before changes in working capital; and
• | covenants that will limit the Trust’s capital expenditures above an agreed base-case, allowing for certain exceptions.

Up to US$200 million of the Revolving Credit Facility is available for letters of credit in United States dollars and/or Canadian dollars.
The interest rate on loans under the Secured Facility that are denominated in United States dollars is, at the option of Precision, either a margin over an adjusted United States base rate or a margin over a Eurodollar rate. The interest rate on loans denominated in Canadian dollars is, at the option of Precision, a margin over the Canadian prime rate or a margin over the bankers’ acceptance rate. Certain of the margins on the Revolving Credit Facility are subject to reduction based upon a leverage test.
The Revolving Credit Facility provides for: a commitment fee of 0.60% (subject to reduction based on a leverage test) on the unused portion; a fee on the outstanding amount of the letters of credit denominated in United States dollars equal to the margin applicable to the Eurodollar rate; and a fee on the outstanding amount of the letters of credit denominated in Canadian dollars equal to the margin applicable to the bankers’ acceptance rate (subject to reduction for non-financial letters of credit).
The Secured Facility requires the following amounts to be used as prepayments of the term loans: (i) 100% of the net cash proceeds of any incurrence of debt by the Trust, Precision or their subsidiaries (subject to certain exceptions); (ii) 100% of the net cash proceeds of certain sales or other dispositions of any assets belonging to the Trust, Precision or their subsidiaries, except to the extent the Trust, Precision or their subsidiaries use the proceeds from the sale or disposition to acquire, improve or repair assets useful in their business within a specified period; and (iii) 75% of the Trust’s annual excess cash flow, which percentage will be reduced to 50%, 25% and 0% if the Trust achieves and maintains a consolidated leverage ratio of less than 2.00 to 1.00, 1.25 to 1.00, and 0.75 to 1.00, respectively. In addition to mandatory prepayments, the Trust will have the option to prepay the loans under the Secured Facility generally without premium or penalty, other than customary “breakage” costs for Eurodollar rate loans.
The Term Loan A Facility is repayable in quarterly installments in aggregate annual amounts equal to 5% of the original principal amount thereof in the first year following the closing date, 10% of the original principal amount thereof in the second year following the closing date, 10% of the original principal amount thereof in the

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third year following the closing date and 15% of the original principal amount thereof in the fourth and fifth years following the closing date, with the balance payable on the final maturity date thereof, which is December 23, 2013.
The Term Loan B Facility is repayable in quarterly installments in an aggregate annual amount equal to 5% of the original principal amount thereof with the balance payable on the final maturity date thereof, which is September 30, 2014.
The Trust, Precision and their material subsidiaries organized in Canada or the United States (other than certain excluded subsidiaries) and each other subsidiary that becomes a party to the collateral documents (collectively, the “Subsidiary Guarantors”) have pledged substantially all of their tangible and intangible assets (with certain exceptions) that are located in Canada or the United States as collateral, secured by a perfected first priority lien, subject to certain permitted liens. In addition, the Trust and the Subsidiary Guarantors have guaranteed the obligations of Precision under the Secured Facility.
The Secured Facility contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Trust’s, Precision’s and their subsidiaries’ ability to:

• | incur additional indebtedness;
• | sell assets;
• | pay dividends and distributions (including by the Trust to Unitholders) or purchase the Trust’s, Precision’s or their subsidiaries’ capital stock or trust units;
• | make investments or acquisitions;
• | make optional payments or repurchases of any subordinated indebtedness and certain other debt;
• | amend material agreements relating to the Acquisition and the financing thereof;
• | change the Trust’s, Precision’s or their subsidiaries’ lines of business;
• | engage in sale leasebacks;
• | incur liens on their assets;
• | enter into mergers, consolidations or amalgamations;
• | make capital expenditures;
• | enter into transactions with foreign subsidiaries of the Trust or Precision other than wholly-owned subsidiaries that provide guarantees;
• | enter into swap agreements;
• | make changes to their respective fiscal periods;
• | enter into negative pledge clauses; and
• | agree to restrict subsidiary distributions.

The Secured Facility requires the Trust and Precision to comply with the following financial ratios:

• | a maximum total leverage ratio of 3.00 to 1.00 as at the last day of any period of four consecutive fiscal quarters of the Trust beginning March 31, 2009;
• | a minimum interest coverage ratio of 3.00 to 1.00 for any period of four consecutive fiscal quarters of the Trust beginning March 31, 2009; and
• | a minimum fixed charge coverage ratio for any period of four consecutive fiscal quarters of the Trust beginning March 31, 2009 of: (i) 1.00 to 1.00 for any such period ending on or prior to December 31, 2010; and (ii) 1.05 to 1.00 for any such period ending after December 31, 2010.

The Secured Facility also contains customary affirmative covenants and events of default.

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Unsecured Facility
Precision (as the borrower) and the Trust (as a guarantor) entered into a credit agreement dated December 23, 2008 governing the Unsecured Facility with the lenders parties thereto, Royal Bank of Canada, as syndication agent, Deutsche Bank AG Cayman Islands Branch, as administrative agent and HSBC Bank USA, National Association, as documentation agent. The Unsecured Facility originally provided senior unsecured financing of up to US$400 million of which approximately US$137.5 million was drawn after completion of the Acquisition and the related financing transactions. Net proceeds of US$165 million were received by the Trust in connection with the Trust Unit Offering in February 2009, which reduced the amount available under the Unsecured Facility by an equivalent amount. The Unsecured Facility, along with net proceeds from the Trust Unit Offering was used to fund the repurchase of Grey Wolf convertible notes tendered for repurchase by holders under a change of control offer made in the first quarter of 2009. See “General Development of the Business – Recent Developments” and “Three Year History – 2008.”
The loans under the Unsecured Facility bear interest at a fixed rate per annum of 17%, will initially mature on December 23, 2009, and, to the extent unpaid on that date, will be converted into term loans that will mature on December 23, 2016 provided that the loans will not be converted to term loans if an event of default has occurred under the Unsecured Facility or the Secured Facility or certain other conditions are not satisfied.
The loans under the Unsecured Facility are subject to mandatory prepayments from the net cash proceeds from the issuance or sale of any equity interests by the Trust (subject to certain exceptions), and, subject to the prior rights of the lenders under the Secured Facility, are also subject to mandatory prepayments from: (i) 100% of the net cash proceeds of any incurrence of debt by the Trust, Precision or their subsidiaries (subject to certain exceptions); and (ii) 100% of the net cash proceeds of certain sales or other dispositions of any assets belonging to the Trust, Precision or their subsidiaries, except to the extent the Trust, Precision or their subsidiaries use the proceeds from a sale or disposition to acquire, improve or repair assets to be used in their business within a specified period. In addition to mandatory prepayments, the Trust has the option to prepay the loans under the Unsecured Facility, without premium or penalty, prior to the exchange of the loans for exchange notes.
After the initial maturity date of the Unsecured Facility of December 23, 2009, each lender under the Unsecured Facility may request the Trust issue an exchange note bearing interest at a specified interest rate (to be calculated on the date of issuance of such exchange note based on the greater of 16.66% and a market-based interest rate cap) in replacement for the term loan (or a portion thereof) made under the Unsecured Facility. In the event that the Trust receives such a request, the Trust shall, as promptly as practicable after being requested to do so, among other things: (i) enter into an exchange note indenture pursuant to which the exchange notes will be issued and governed; (ii) enter into an exchange and registration rights agreement providing for, among other things, registration rights in respect of the exchange notes in favour of the holders thereof; and (iii) cause to be issued exchange notes in the same principal aggregate amount as the term loan being exchanged.
In addition, after June 30, 2009 (or after April 1, 2009 in certain circumstances), the lenders under the Unsecured Facility may require that debt securities be issued and sold to repay amounts outstanding under the Unsecured Facility, subject to certain specified terms and conditions. Precision has agreed to engage one or more investment banks to publicly sell or privately place debt securities in such circumstances, the proceeds of which will be used to repay outstanding loans under the Unsecured Facility. The Trust may also, at any time, issue equity or debt securities and Precision may, at any time, issue debt securities to repay outstanding loans under the Unsecured Facility.
The Unsecured Facility is unsecured and has been guaranteed by the Trust and each subsidiary of the Trust that guaranteed the Secured Facility.
The Unsecured Facility contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Trust’s, Precision’s and their subsidiaries ability to:

• | make certain restricted payments (which include dividends, distributions (including by the Trust to Unitholders), redemptions and certain investments);
• | make distributions to the Trust;

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• | incur additional indebtedness;
• | sell assets;
• | enter into transactions with affiliates;
• | incur liens on their assets;
• | change the primary business of the Trust;
• | enter into mergers, consolidations or amalgamations; and
• | amend certain material agreements.

The terms of the Unsecured Facility limit (subject to certain exceptions) the Trust’s ability to make distributions in the following circumstances:

• | where a default under the terms of the Unsecured Facility shall have occurred and be continuing or shall occur as a consequence thereof;
• | where the incurrence of at least US$1.00 of additional indebtedness would result in the consolidated interest coverage ratio being less than 2.50 to 1.00;
• | for so long as the Trust is a “mutual fund trust” for Canadian federal income tax purposes, where the consolidated leverage ratio exceeds 3.00 to 1.00; or
• | where the amount of such distribution, when added to the amount of all distributions (subject to certain exceptions) made after the closing date of the Acquisition exceeds certain prescribed amounts specified in Section 8.1(a)(iii) of the credit agreement governing the Unsecured Facility.

The Unsecured Facility also contains customary affirmative covenants and events of default, including customary cross payment defaults.
General
The terms of the documents governing the Credit Facilities contain provisions that in effect ensure that the lenders have priority as to payment over the Unitholders in respect to the assets and income of the Trust and its subsidiaries. Amounts due and owing to the lenders under the Credit Facilities must be paid before any distributions can be made to Unitholders. This relative priority of payments could result in a temporary or permanent interruption of distributions to Unitholders. See “Risk Factors – The Trust’s debt service obligation may limit the amount of cash available for distributions” and “Distributions on the Trust Units have been suspended and may not be reinstated”.
As at December 31, 2008, approximately $1,087 million ($130.5 million plus US$781.1 million) was outstanding under the Secured Facility and approximately US$137.5 million was outstanding under the Unsecured Facility. On March 20, 2009, an additional US$98 million was borrowed under the Unsecured Facility to fund the repurchase of the Grey Wolf convertible notes, bringing the balance outstanding under this facility to US$235 million. The Revolving Credit Facility may be redrawn by Precision in the future to fund capital expenditures or for other corporate purposes.
At the time of the closing of the Acquisition, Grey Wolf had outstanding US$262.3 million aggregate principal amount of convertible notes, the obligations for which were assumed by PDOS. Pursuant to the terms of the convertible notes, during the first quarter of 2009, PDOS, as successor to Grey Wolf, made to the holders thereof a change of control offer to repurchase any or all of the outstanding convertible notes at 100% of the principal amount thereof, plus accrued but unpaid interest to the date of the repurchase, payable in cash. On March 23, 2009, US$262.3 million of Grey Wolf convertible notes were tendered for repurchase.

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RECORD OF CASH DISTRIBUTIONS/PAYMENTS
On February 9, 2009, the Trust announced that it had suspended cash distributions payable on both the Trust Units and Exchangeable Units for an indefinite period. See “General Development of the Business – Recent Developments” and “Risk Factors – Distributions on the Trust Units have been suspended and may not be reinstated”. This measure was taken in response to lower financial operating performance at the start of 2009 and will allow Precision to increase debt repayment capabilities and balance sheet strength. The Trust will continue to monitor its financial situation and evaluate the possibility of the reinstatement of monthly cash distributions based on the relevant factors in effect from time to time.
The following table sets forth the distributions (in Canadian dollars) paid or declared payable by the Trust on each Trust Unit for the three most recently completed financial years:

|  |  |  |  |  |  |  |  | Amount per Trust |
Distribution Type |  |  | Record Date |  |  | Payment Date |  |  | Unit |
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 |
Regular Distribution |  |  | April 30, 2007 |  |  | May 15, 2007 |  |  | $ | 0.190 |
Regular Distribution |  |  | May 31, 2007 |  |  | June 15, 2007 |  |  | $ | 0.130 |
Regular Distribution |  |  | June 29, 2007 |  |  | July 17, 2007 |  |  | $ | 0.130 |
Regular Distribution |  |  | July 31, 2007 |  |  | August 15, 2007 |  |  | $ | 0.130 |
Regular Distribution |  |  | August 31, 2007 |  |  | September 18, 2007 |  |  | $ | 0.130 |
Regular Distribution |  |  | September 28, 2007 |  |  | October 16, 2007 |  |  | $ | 0.130 |
Regular Distribution |  |  | October 31, 2007 |  |  | November 15, 2007 |  |  | $ | 0.130 |
Regular Distribution |  |  | November 30, 2007 |  |  | December 18, 2007 |  |  | $ | 0.130 |
Regular Distribution |  |  | December 31, 2007 |  |  | January 15, 2008 |  |  | $ | 0.130 |
Special Year-end in cash Distribution |  |  | December 31, 2007 |  |  | January 15, 2008 |  |  | $ | 0.160 |
Special Year-end in-kind Distribution(1) |  |  | December 31, 2007 |  |  | January 15, 2008 |  |  | $ | 0.240 |

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|  |  |  |  |  |  |  |  | Amount per Trust |
Distribution Type |  |  | Record Date |  |  | Payment Date |  |  | Unit |
2008 |  |  |  |  |  |  |  |  |  |  |
Regular Distribution |  |  | January 31, 2008 |  |  | February 15, 2008 |  |  | $ | 0.130 |
Regular Distribution |  |  | February 29, 2008 |  |  | March 18, 2008 |  |  | $ | 0.130 |
Regular Distribution |  |  | March 31, 2008 |  |  | April 15, 2008 |  |  | $ | 0.130 |
Regular Distribution |  |  | April 30, 2008 |  |  | May 15, 2008 |  |  | $ | 0.130 |
Regular Distribution |  |  | May 30, 2008 |  |  | June 17, 2008 |  |  | $ | 0.130 |
Regular Distribution |  |  | June 30, 2008 |  |  | July 15, 2008 |  |  | $ | 0.130 |
Regular Distribution |  |  | July 31, 2008 |  |  | August 15, 2008 |  |  | $ | 0.130 |
Regular Distribution |  |  | August 29, 2008 |  |  | September 16, 2008 |  |  | $ | 0.130 |
Regular Distribution |  |  | September 30, 2008 |  |  | October 15, 2008 |  |  | $ | 0.130 |
Regular Distribution |  |  | October 31, 2008 |  |  | November 18, 2008 |  |  | $ | 0.130 |
Regular Distribution |  |  | November 28, 2008 |  |  | December 16, 2008 |  |  | $ | 0.130 |
Regular Distribution |  |  | December 31, 2008 |  |  | January 15, 2009 |  |  | $ | 0.130 |
Special Year-end in-kind Distribution(1) |  |  | December 31, 2008 |  |  | January 15, 2009 |  |  | $ | 0.150 |
2009 |  |  |  |  |  |  |  |  |  |  |
Regular Distribution |  |  | January 30, 2009 |  |  | February 17, 2009 |  |  | $ | 0.040 |

NOTE:

(1) | The special year-end distribution was settled “in-kind” through the issuance of Trust Units rather than the payment of cash in order for Precision to minimize debt levels and retain balance sheet strength. 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. See “Risk Factors – The issuance of additional Trust Units in lieu of cash distributions could negatively affect the value of the Trust Units and result in the payment of taxes”.

The following table sets forth the amount of payments (in Canadian dollars) paid or payable on each Exchangeable Unit for the three most recently completed financial years:

|  |  |  |  |  |  |  |  | Amount |
Payment Type |  |  | Record Date |  |  | Payment Date |  |  | per Exchangeable Unit |
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 |
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 Year-end in-kind Payment(1) |  |  | December 31, 2006 |  |  | January 16, 2007 |  |  | $ | 0.195 |

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|  |  |  |  |  |  |  |  | Amount |
Payment Type |  |  | Record Date |  |  | Payment Date |  |  | per Exchangeable Unit |
2007 |  |  |  |  |  |  |  |  |  |  |
Regular Payment |  |  | January 31, 2007 |  |  | February 15, 2007 |  |  | $ | 0.190 |
Regular Payment |  |  | February 28, 2007 |  |  | March 15, 2007 |  |  | $ | 0.190 |
Regular Payment |  |  | March 30, 2007 |  |  | April 17, 2007 |  |  | $ | 0.190 |
Regular Payment |  |  | April 30, 2007 |  |  | May 15, 2007 |  |  | $ | 0.190 |
Regular Payment |  |  | May 31, 2007 |  |  | June 15, 2007 |  |  | $ | 0.130 |
Regular Payment |  |  | June 29, 2007 |  |  | July 17, 2007 |  |  | $ | 0.130 |
Regular Payment |  |  | July 31, 2007 |  |  | August 15, 2007 |  |  | $ | 0.130 |
Regular Payment |  |  | August 31, 2007 |  |  | September 18, 2007 |  |  | $ | 0.130 |
Regular Payment |  |  | September 28, 2007 |  |  | October 16, 2007 |  |  | $ | 0.130 |
Regular Payment |  |  | October 31, 2007 |  |  | November 15, 2007 |  |  | $ | 0.130 |
Regular Payment |  |  | November 30, 2007 |  |  | December 18, 2007 |  |  | $ | 0.130 |
Regular Payment |  |  | December 31, 2007 |  |  | January 15, 2008 |  |  | $ | 0.130 |
Special Year-end in cash Payment |  |  | December 31, 2007 |  |  | January 15, 2008 |  |  | $ | 0.160 |
Special Year-end in-kind Payment(1) |  |  | December 31, 2007 |  |  | January 15, 2008 |  |  | $ | 0.240 |
2008 |  |  |  |  |  |  |  |  |  |  |
Regular Payment |  |  | January 31, 2008 |  |  | February 15, 2008 |  |  | $ | 0.130 |
Regular Payment |  |  | February 29, 2008 |  |  | March 18, 2008 |  |  | $ | 0.130 |
Regular Payment |  |  | March 31, 2008 |  |  | April 15, 2008 |  |  | $ | 0.130 |
Regular Payment |  |  | April 30, 2008 |  |  | May 15, 2008 |  |  | $ | 0.130 |
Regular Payment |  |  | May 30, 2008 |  |  | June 17, 2008 |  |  | $ | 0.130 |
Regular Payment |  |  | June 30, 2008 |  |  | July 15, 2008 |  |  | $ | 0.130 |
Regular Payment |  |  | July 31, 2008 |  |  | August 15, 2008 |  |  | $ | 0.130 |
Regular Payment |  |  | August 29, 2008 |  |  | September 16, 2008 |  |  | $ | 0.130 |
Regular Payment |  |  | September 30, 2008 |  |  | October 15, 2008 |  |  | $ | 0.130 |
Regular Payment |  |  | October 31, 2008 |  |  | November 18, 2008 |  |  | $ | 0.130 |
Regular Payment |  |  | November 28, 2008 |  |  | December 16, 2008 |  |  | $ | 0.130 |
Regular Payment |  |  | December 31, 2008 |  |  | January 15, 2009 |  |  | $ | 0.130 |
Special Year-end in-kind Payment(1) |  |  | December 31, 2008 |  |  | January 15, 2009 |  |  | $ | 0.150 |
2009 |  |  |  |  |  |  |  |  |  |  |
Regular Payment |  |  | January 30, 2009 |  |  | February 17, 2009 |  |  | $ | 0.040 |

NOTE:

(1) | The special year-end distribution was settled “in-kind” through the issuance of Trust Units rather than cash in order for Precision to minimize debt levels and retain balance sheet strength. Immediately after the payment of the special in-kind payment, the outstanding Trust Units were consolidated so that the number of Trust Units outstanding after the special in-kind payment remained unchanged from the number of Trust Units outstanding immediately prior to the special in-kind payment. Holders of Exchangeable Units received the economic equivalent treatment. See “Risk Factors – The issuance of additional Trust Units in lieu of cash distributions could negatively affect the value of the Trust Units and result in the payment of taxes”.

The historical distributions described above may not be reflective of future distributions, which are subject to review by the Board of Trustees taking into account the prevailing circumstances at the relevant time. See “Risk Factors – Distributions on the Trust Units are variable” and “Distribution on the Trust Units have been suspended and may not be reinstated.”
The terms of the documents governing the Credit Facilities contain provisions that in effect ensure that the lenders have priority as to payment over the Unitholders in respect to the assets and income of the Trust and its subsidiaries. Amounts due and owing to the lenders under the Credit Facilities must be paid before any distributions can be made to Unitholders. This relative priority of payments could result in a temporary or permanent interruption of distributions to Unitholders. See “Risk Factors – The Trust’s debt service obligations may limit the amount of cash available for distributions” and “Distribution on the Trust Units have been suspended and may not be reinstated”.

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DESCRIPTION OF CAPITAL STRUCTURE
Description Of Trust Units
As of March 27, 2009, there were 206,065,086 Trust Units and 128,562 Exchangeable Units issued and outstanding. Each Exchangeable Unit can be exchanged into Trust Units at any time at the option of the holder based on the exchange ratio in effect at the date of exchange. Each Trust Unit entitles the holder thereof to one vote at any meeting of Unitholders, or in respect of any written resolution of Unitholders, 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 the termination or winding up of the Trust. All Trust Units 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.
The Trust Units do not represent a traditional investment and should not be viewed by investors as “shares” in either the Trust or Precision. As holders of Trust Units, Unitholders 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 market price of the Trust Units will be sensitive to, among other things, the anticipated distributable income from the Trust, as well as a variety of market conditions including, but not limited to, interest rates, commodity prices and the ability of the Trust to maintain and grow revenues. Changes in market conditions may adversely affect the trading price of the Trust Units. See “Risk Factors – Trust Units have certain risks not associated with traditional investments in the oil and natural gas services business”.
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 not a legally recognized entity within the relevant definitions of the Bankruptcy and Insolvency Act (Canada), the Companies’ Creditors Arrangement Act (Canada) and, in some cases, the Winding Up and Restructuring Act (Canada). As a result, in the event a restructuring of the Trust were necessary, the Trust would not be able to access the remedies available thereunder. In the event of a restructuring, the position of Unitholders may be different than that of the shareholders of a corporation.
Issuance of Trust Units
The Declaration of Trust provides that Trust Units, including rights, warrants, options or other securities convertible into or exchangeable for Trust Units, may be created, issued, sold and delivered on such terms and conditions and at such times as the Trustees (as defined herein) may determine. The Declaration of Trust also provides that the Trustees may authorize the creation and issuance of any type of debt securities or convertible debt securities of the Trust from time to time on such terms and conditions to such persons and for such consideration as the Trustees may determine.
Purchase of Trust Units
The Trust may from time to time purchase for cancellation some or all of the Trust Units (or other securities of the Trust which may be issued and outstanding from time to time) in the market, by private agreement or upon any recognized stock exchange on which such Trust Units are traded or pursuant to tenders received by the Trust upon request for tenders addressed to all holders of record of Trust Units, provided in each case that the Trustees have determined that such purchases are in the best interests of the Trust. Any such purchases may constitute an “issuer bid” under Canadian provincial securities legislation and must be conducted in accordance with the applicable requirements thereof.

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Cash Distributions on Trust Units and Exchangeable Units
On February 9, 2009, the Trust announced that it had suspended cash distributions for an indefinite period. This measure was taken in response to lower financial operating performance at the start of 2009. The previously announced distribution of $0.04 per unit payable on February 17, 2009 to Trust and PDLP Unitholders of record on January 30, 2009 was unaffected by the suspension. The Trust will continue to monitor its financial situation and evaluate the possibility of the reinstatement of monthly cash distributions based on the relevant factors in effect from time to time. See “Risk Factors – Distributions on Trust Units have been suspended and may not be reinstated”.
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 Trust Units be consolidated immediately subsequent to the distribution. The number of outstanding Trust Units would remain at the number outstanding immediately prior to the Trust 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.
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.
Distribution Reinvestment Plan
Effective December 18, 2006, the distribution reinvestment plan (the “DRIP”), outlined below, was suspended indefinitely by the Board of Trustees. Details of the DRIP are described more fully in the DRIP document available on the Trust’s website at www.precisiondrilling.com.
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, Trust Unitholders who are not residents of Canada are not eligible to participate, directly or indirectly, in the DRIP. Exchangeable Unitholders also are 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 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.
Trust Unit Redemption Right
Trust Units are redeemable at any time on demand by the holders thereof upon delivery to the Trust of a duly completed and properly executed notice requesting the Trust to redeem Trust Units. Upon receipt of the notice to redeem Trust Units by the Trust, the holder thereof shall thereafter cease to have any rights with respect to the Trust Units tendered for redemption (other than to receive the redemption payment therefor unless the redemption payment is not made as required) including the right to receive any distributions thereon which are declared payable on a date subsequent to the day of receipt by the Trust of the notice requesting redemption.

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Cash Redemption
Upon receipt by the Trust of the notice to redeem Trust Units, the tendering Unitholder will thereafter be entitled to receive a price per Trust Unit (the “Market Redemption Price”) equal to the lesser of: (a) 90% of the market price per Trust Unit on the principal stock exchange on which the Trust Units are listed (or, if the Trust Units are not listed on any such exchange, on the principal market on which the Trust Units are quoted for trading) during the period of the last ten trading days immediately prior to the date on which the Trust Units were tendered for redemption; and (b) the closing market price per Trust Unit on the principal stock exchange on which the Trust Units are listed (or, if the Trust Units are not listed on any such exchange, on the principal market on which the Trust Units are quoted for trading) on the date that the Trust Units were tendered for redemption.
The aggregate Market Redemption Price payable by the Trust in respect of the Trust Units tendered for redemption during any calendar month shall be satisfied by way of a cash payment on the last day of the calendar month following the month in which the Trust Units were tendered for redemption.
Unitholders will not receive cash upon the redemption of their Trust Units if:

| (a) | the total amount payable by the Trust in respect of such Trust Units and all other Trust Units tendered for redemption in the same calendar month exceeds $50,000; provided that the Trustees may, in their sole discretion, waive such limitation in respect of all Trust Units tendered for redemption in any calendar month. If this limitation is not so waived, the Trust Units tendered for redemption in such calendar month shall be redeemed for cash based on the Market Redemption Price and, unless any applicable regulatory approvals are required, by a distribution in specie of the Trust’s assets, which may include Redemption Notes (as defined below) or other assets held by the Trust, on a pro-rata basis;

| (b) | at the time such Trust Units are tendered for redemption, the outstanding Trust Units are not listed for trading on the Toronto Stock Exchange or traded or quoted on any stock exchange or market which the Trustees consider, in their sole opinion, provides representative fair market value prices for the Trust Units;

| (c) | the normal trading of the Trust Units is suspended or halted on any stock exchange on which the Trust Units are listed for trading or, if not so listed, on any market on which the Trust Units are quoted for trading, on the date that such Trust Units tendered for redemption were tendered to the Trust for redemption or for more than five trading days during the ten day trading period prior to the date on which such Trust Units were tendered for redemption; or

| (d) | the redemption of Trust Units will result in the delisting of the Trust Units on the principal stock exchange on which the Trust Units are listed.

In Specie Redemption
If a Unitholder is not entitled to receive cash upon the redemption of Trust Units as a result of one or more of the foregoing limitations, then each Trust Unit tendered for redemption will, subject to any applicable regulatory approvals, be redeemed by way of a distribution in specie. In such circumstances, the support agreement dated November 7, 2005, among the Trust, PDLP, the General Partner and Precision (the “Support Agreement”) provides that, upon the direction of the Trustees, PDLP will request partial repayment of the debt incurred by Precision in connection with its conversion into a trust structure and use the funds received therefrom to subscribe for new notes from Precision (the “Redemption Notes”) with a 15 year maturity and that will bear interest at a market rate to be determined by the Board of Directors of Precision, payable monthly in arrears on the 15th day of each calendar month that such Redemption Note is outstanding.
Pursuant to the terms of the Support Agreement, PDLP will distribute the Redemption Notes to the Trust as the holder of Class A limited partnership units of PDLP and the Trust will distribute these Redemption Notes to the redeeming Unitholders in satisfaction of the Market Redemption Price.
Pursuant to the terms of the Support Agreement, Precision has agreed to enter into a note indenture, prior to issuance of the Redemption Notes, that will set out the definitive terms of the Redemption Notes and provide for a note trustee. The Support Agreement provides that the Redemption Notes will be direct, subordinated obligations of

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Precision ranking subordinate to all senior unsecured indebtedness. The Support Agreement further provides that the note indenture governing the Redemption Notes must contain events of default that are market standard for notes of this nature, the occurrence of which will result in the principal and any accrued and unpaid interest on the Redemption Notes being immediately due and payable.
Rather than distributing Redemption Notes in satisfaction of the Market Redemption Price for Trust Units tendered for redemption in the circumstances described above, the Trustees may, provided certain conditions have been met, determine to satisfy the Market Redemption Price by way of an alternate distribution in specie to redeeming Unitholders. In order to make an in specie distribution other than Redemption Notes to redeeming Unitholders or for the Trust to redeem Trust Units with its own indebtedness, the Trustees must have received both a written opinion of tax counsel that such a distribution of Trust assets does not have a material adverse effect on other Unitholders and a written opinion from a financial advisor that such Trust assets being distributed in lieu of Redemption Notes would be reasonably considered to be financially equivalent in value to Redemption Notes.
Where the Trust makes a distribution in specie of any assets of the Trust on the redemption of Trust Units by a Unitholder, the Trustees retain the discretion to designate to the account of such Unitholder any capital gains realized by the Trust or income of the Trust arising as a result of such redemption and distribution. It is anticipated that the redemption right described above will not be the primary mechanism for holders of Trust Units to dispose of their Trust Units. Redemption Notes or other Trust assets that may be distributed in specie to Unitholders in connection with a redemption will not be listed on any stock exchange, no market is expected to develop in Redemption Notes or other Trust assets and they may be subject to resale restrictions under applicable securities laws. Redemption Notes or other Trust assets so distributed may not be qualified investments for Exempt Plans (as defined herein) depending on the circumstances at the time. See “Risk Factors – Risks Relating to the Structure of the Trust”.
The aggregate Market Redemption Price payable by the Trust in respect of the Trust Units tendered for redemption during any calendar month shall be paid by the transfer, to or to the order of the Unitholder who exercised the right of redemption, on the last day of the calendar month following the month in which the Trust Units were tendered for redemption, of Redemption Notes or Trust assets, as the case may be.
Meetings of Unitholders
The Declaration of Trust provides that meetings of Unitholders must be called and held for, among other matters, the election of Trustees, the appointment or removal of the auditors of the Trust, the approval of amendments to the Declaration of Trust (except as described below under “Amendments to the Declaration of Trust”), the sale of all or substantially all of the Trust’s assets and the dissolution or termination of the Trust. Meetings of Unitholders will be called and held annually for, among other things, the election of Trustees and the appointment of the auditors of the Trust.
A meeting of Unitholders may be convened at any time and for any purpose by the Trustees and must be convened, except in certain circumstances, if requisitioned by the holders of not less than 5% of all votes entitled to be voted at a meeting of Unitholders (including the votes attached to Exchangeable Units (as defined herein) by virtue of the special voting unit (the “Special Voting Unit”) of the Trust issued pursuant to the Voting and Exchange Trust Agreement dated November 7, 2005, among the Trust, PDLP and Computershare Trust Company of Canada (the “Voting and Exchange Trust Agreement”)) by a written requisition. A requisition must, among other things, state in reasonable detail the business purpose for which the meeting is to be called.
Subject to the Voting and Exchange Trust Agreement, only Unitholders of record may attend and vote at meetings of Unitholders either in person or by proxy and a proxyholder need not be a Unitholder. Two persons present in person or represented by proxy and representing in the aggregate at least 5% of the votes attaching to all outstanding Trust Units shall constitute a quorum for the transaction of business at all such meetings. For the purposes of determining such quorum, the Special Voting Unit shall be regarded as representing outstanding Trust Units equivalent in number to the number of Exchangeable Units represented by proxy by Computershare Trust Company of Canada at such meeting.

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The Declaration of Trust contains provisions as to the notice required and other procedures with respect to the calling and holding of meetings of Unitholders in accordance with the requirements of applicable laws.
Limitation on Non-Resident Ownership
It is in the best interest of Unitholders that the Trust always qualify as a “mutual fund trust” under the Tax Act and in order to ensure 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 of Canada 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 of Canada and/or require the sale of Trust Units by non-residents of Canada on a basis determined by the Trustees and/or suspend distribution and/or other rights in respect of Trust Units held by non-residents of Canada 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 the 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 of Canada may hold, limit the transfer of the legal or beneficial interest in any Trust Units to non-residents of Canada 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.

Amendments to the Declaration of Trust
The Trustees may, without the consent, approval or ratification of any of the Unitholders, amend the Declaration of Trust at any time:

| (a) | for the purpose of ensuring the Trust’s continuing compliance with applicable laws, regulations or policies of any governmental authority having jurisdiction over the Trustees or the Trust;

| (b) | in a manner which, in the opinion of the Trustees, provides additional protection for the Unitholders;

| (c) | in a manner which, in the opinion of the Trustees, is necessary or desirable as a result of changes in Canadian tax laws;

| (d) | to remove any conflicts or inconsistencies in the Declaration of Trust or to make minor corrections which are, in the opinion of the Trustees, necessary or desirable and not prejudicial to the Unitholders; or

| (e) | to change the situs of, or the laws governing, the Trust which, in the opinion of the Trustees is desirable in order to provide Unitholders with the benefit of any legislation limiting their liability.

Term of the Trust
The Unitholders may vote by special resolution to terminate the Trust at any meeting of the Unitholders duly called for that purpose, following which the Trustees shall commence to wind-up the affairs of the Trust (and shall thereafter be restricted to only such activities).

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Unless the Trust is earlier terminated or extended by vote of the Unitholders, the Trustees shall commence to wind-up the affairs of the Trust on such date as may be determined by the Trustees, being not more than two years prior to the earlier of September 21, 2105 and the date which is one day prior to the date, if any, the Trust would otherwise be void by virtue of any applicable rule against perpetuities then in force in Alberta. In the event that the Trust is wound-up, the Trustees will sell and convert into money the assets of the Trust in one transaction or in a series of transactions at public or private sales and do all other acts appropriate to liquidate the property of the Trust, and shall in all respects act in accordance with the directions, if any, of the Unitholders (in respect of termination authorized pursuant to a special resolution). After paying, retiring or discharging or making provision for the payment, retirement or discharge of all known liabilities and obligations of the Trust and providing for indemnity against any other outstanding liabilities and obligations, the Trustees shall, subject to obtaining all necessary regulatory approvals, distribute the remaining part of the proceeds of the sale of the assets together with any cash forming part of the Trust’s assets pro-rata among the Unitholders.
Take-Over Bids
The Declaration of Trust contains provisions to the effect that if a take-over bid, as defined under the Securities Act (Alberta), is made for the Trust Units and not less than 90% of the Trust Units (including Trust Units issuable upon the conversion, exercise or exchange of any securities exchangeable into Trust Units but not including any Trust Units held at the date of the take-over bid by or on behalf of, or issuable to, the offeror or an affiliate or associate of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Trust Units and Exchangeable Units held by Unitholders who did not accept the take-over bid on the terms offered by the offeror.
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.
Description Of Exchangeable Units
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, 2008, there were 125,606,341 Class A Limited Partnership Units issued to the Trust. As of March 27, 2009 there were 125,629,362 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, 2008, 151,583 Exchangeable Units remained outstanding. As of March 27, 2009, 128,562 Exchangeable Units remained outstanding. The Exchangeable Units have the economic equivalence of the Trust Units and the principal terms of the Exchangeable Units are:

| (a) | they are exchangeable for Trust Units on a one-for-one basis at the option of the holder;

| (b) | each Exchangeable Unit entitles the holder thereof to receive (in the form of a non-interest bearing loan) cash payments equal to cash payments 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

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|  | equal to the outstanding non-interest bearing loan accumulated during the previous year which will be used to repay such accumulated debt);

| (c) | 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;

| (d) | 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

| (e) | there are certain restrictions on the transfer of Exchangeable Units.

In addition to the foregoing, the Support Agreement 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:

| (a) | issue or distribute Trust Units to the holders of all, or substantially all, of the then outstanding Trust Units by way of distribution; or

| (b) | 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

| (c) | issue or distribute to the holders of all, or substantially all, of the then outstanding Trust Units:

| (i) | 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);

| (ii) | rights, options or warrants other than those described above; or

| (iii) | evidences of indebtedness of the Trust; or

| (iv) | 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.
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.
On February 9, 2009, the Trust announced that it had suspended cash distributions for an indefinite period. This measure was taken in response to lower financial operating performance at the start of 2009. The previously announced distribution of $0.04 per unit payable on February 17, 2009 to Trust and PDLP unitholders of record on January 30, 2009 was unaffected by the suspension. The Trust will continue to monitor its financial situation and evaluate the possibility of the reinstatement of monthly cash distributions based on the relevant factors in effect from time to time. See “Risk Factors – Distributions on Trust Units have been suspended and may not be reinstated”.

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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.
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 payment in the form of Trust Units is declared the outstanding units will be consolidated immediately subsequent to the payment. The number of outstanding Exchangeable Units would remain at the number outstanding immediately prior to the Exchangeable Unit payment and an amount equal to the payment 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.
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.
Partnership Units
PDLP is authorized to issue an unlimited number of PDLP A Units and Exchangeable Units. The General Partner may, in respect of PDLP, also issue at any time units of any class or series or secured and unsecured debt obligations, debt obligations convertible into any class or series of units, or options, warrants, rights, appreciation rights or subscription rights relating to any class or series of units, to the General Partner, to limited partners or any other person who is not a non-resident of Canada and is not exempt from tax under Part I of the Tax Act (as defined herein). Each unit ranks equally with each other unit of the same class or series and entitles the holder thereof to the same rights and obligations as the holder of any other unit of the same class or series and no limited partner is entitled to any privilege, priority or preference in relation to any other limited partner holding units of the same class or series.
In addition, on a distribution of assets in the event of the liquidation, dissolution or winding-up of PDLP, whether voluntary or involuntary, or any other distribution of the assets of PDLP among its Partners for the purpose of winding-up its affairs: (a) the holders of PDLP A Units will be distributed an amount equal to the aggregate of all liabilities of the Trust; and (b) the balance of the assets of PDLP will be distributed: (i) as to that proportion of such assets equal to the result obtained by dividing the amount of such assets by the sum of the number of Exchangeable Units and the number of Trust Units, in each case as outstanding on the date of such distribution, in respect of each Exchangeable Unit outstanding; and (ii) as to the remaining portion of such assets, to the holders of PDLP A Units rateably in accordance with the number of PDLP A Units held thereby.
Amendment and Approval
An amendment to the Limited Partnership Agreement may be proposed by the General Partner and, subject to the following limitations, will be deemed to be effective if approved by the General Partner:

| (a) | the amendment provisions themselves may not be amended without the unanimous consent of the holders of the PDLP A Units and Exchangeable Units (together, the “Unitholders”);

| (b) | no amendments shall be made to the Limited Partnership Agreement which would have the effect of, among other things; (i) preventing the loans or distributions to the Unitholders or adversely affecting the rights of the Unitholders under the Support Agreement (as defined herein); (ii) changing the provisions in the Limited Partnership Agreement requiring that the business of PDLP be conducted

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|  | solely through its investment in Precision or any associate or affiliate thereof, or in any other corporation, partnership, trust or other person involved, directly or indirectly, in any business which involves the provision of contract drilling, service rigs, snubbing, rentals and related services to oil and gas exploration and production companies, (iii) changing the liability of a limited partner; (iv) allowing any limited partner to exercise control over the business of PDLP; (v) changing the right of a limited partner to vote on resolutions; (vi) changing PDLP from a limited partnership to a general partnership, or (vii) causing the Trust to lose its status as a “mutual fund trust” under the Tax Act, without such amendment being passed by way of an extraordinary resolution;

| (c) | no amendment shall be made to the Limited Partnership Agreement which would have the effect of adding, changing or removing any right, privilege, restriction or condition attaching to the Exchangeable Units, or which would have an adverse impact on the holders of Exchangeable Units unless such amendment is approved by class vote of 662/3% of the holders of Exchangeable Units; and

| (d) | no amendment shall be made which would have the effect of adversely affecting the rights and obligations of the General Partner becoming effective before 45 days after the resolution approving such amendment.

Partners must be notified of the full details of any amendment to the Limited Partnership Agreement within 30 days of the effective date of such amendment.
MARKET FOR SECURITIES
Trading Price and Volume of Trust Units
The Trust Units are listed for trading under the symbol “PD.UN” on the Toronto Stock Exchange (the “TSX”) and under the symbol “PDS” on the New York Stock Exchange (the “NYSE”). The following table sets forth the price range and trading volumes for the Trust Units on each of the TSX and NYSE, as reported by each of the TSX and NYSE, for the periods indicated:

|  | TSX |  |  | NYSE |  |  |  |
Period |  | High |  |  | Low |  |  | Volume |  |  | High |  |  | Low |  |  | Volume |  |  |  |
|  | ($) |  |  | ($) |  |  |  |  |  | (US$) |  |  | (US$) |  |  |  |  |  |  |
2008 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
January |  |  | 18.01 |  |  |  | 15.13 |  |  |  | 11,591,630 |  |  |  | 17.70 |  |  |  | 15.15 |  |  |  | 11,208,759 |  |  |  |  |
February |  |  | 22.53 |  |  |  | 17.15 |  |  |  | 15,377,467 |  |  |  | 22.91 |  |  |  | 17.10 |  |  |  | 12,326,070 |  |  |  |  |
March |  |  | 24.00 |  |  |  | 19.61 |  |  |  | 9,855,413 |  |  |  | 23.53 |  |  |  | 19.46 |  |  |  | 15,556,649 |  |  |  |  |
April |  |  | 27.46 |  |  |  | 22.55 |  |  |  | 15,213,996 |  |  |  | 27.25 |  |  |  | 21.89 |  |  |  | 17,653,251 |  |  |  |  |
May |  |  | 28.39 |  |  |  | 24.50 |  |  |  | 10,295,190 |  |  |  | 28.38 |  |  |  | 24.03 |  |  |  | 12,249,342 |  |  |  |  |
June |  |  | 28.93 |  |  |  | 26.05 |  |  |  | 13,594,223 |  |  |  | 28.59 |  |  |  | 25.76 |  |  |  | 17,063,854 |  |  |  |  |
July |  |  | 28.09 |  |  |  | 21.30 |  |  |  | 15,022,653 |  |  |  | 28.15 |  |  |  | 21.01 |  |  |  | 18,697,742 |  |  |  |  |
August |  |  | 23.45 |  |  |  | 20.53 |  |  |  | 19,241,508 |  |  |  | 22.89 |  |  |  | 19.30 |  |  |  | 25,311,531 |  |  |  |  |
September |  |  | 22.32 |  |  |  | 16.00 |  |  |  | 20,876,778 |  |  |  | 21.05 |  |  |  | 15.42 |  |  |  | 31,944,785 |  |  |  |  |
October |  |  | 17.84 |  |  |  | 9.99 |  |  |  | 22,501,020 |  |  |  | 16.82 |  |  |  | 8.41 |  |  |  | 42,647,176 |  |  |  |  |
November |  |  | 13.90 |  |  |  | 8.10 |  |  |  | 14,143,561 |  |  |  | 12.06 |  |  |  | 6.36 |  |  |  | 34,439,385 |  |  |  |  |
December |  |  | 11.77 |  |  |  | 7.07 |  |  |  | 14,588,829 |  |  |  | 9.65 |  |  |  | 5.57 |  |  |  | 44,416,102 |  |  |  |  |

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Prior Sales
The following table summarizes the issuances of Trust Units within the twelve month period ending December 31, 2008(1).

|  |  |  | Number of Trust Units or |  |
Date of Issuance |  | Description of Transaction |  | Securities |  | Price per Security
December 23, 2008 |  | Acquisition(2) |  | 34,435,724 |  | US$21.22

NOTES:

(1) |  | On February 18, 2009, the Trust issued 46 million Trust Units pursuant to the Trust Unit Offering. See “General Development of the Business – Recent Developments”.
(2) |  | Pursuant to the Acquisition, each share of Grey Wolf common stock was convertible, at the option of the holder, into US$9.02 in cash or 0.4225 Trust Units, subject to proration. The total consideration paid by the Trust to shareholders of Grey Wolf in connection with the Acquisition was approximately US$897.2 million and 34.4 million Trust Units. Cash consideration elections exceeded the amount of cash available for cash elections. Accordingly, former Grey Wolf shareholders who properly chose to receive all-cash merger consideration received a prorated amount of cash consideration in the amount of US$5.39 and 0.17 Trust Units for each share of Grey Wolf common stock. Grey Wolf shareholders who elected to receive Trust Units or did not make a timely and valid merger consideration election received 0.4225 Trust Units for each share of Grey Wolf common stock.

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TRUSTEES, DIRECTORS AND EXECUTIVE OFFICERS
Board of Trustees
Pursuant to the terms of the Declaration of Trust, the board of trustees of the Trust (the “Board of Trustees” and, each member thereof, a “Trustee”) 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.
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.
Any one or more of the Trustees may resign upon 30 Days written notice to the Trust and may be removed by an ordinary resolution of the Unitholders 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.
The following table sets forth, for each Trustee and Director and each officer of Precision: his or her name; municipality, province or state and country of residence; all positions and offices now held by him or her; the month and year in which he or she was first elected a Trustee, Director or officer; and his or her principal occupation during the preceding five years.

|  |  | Position |  |  |  |  |  |
Name, Municipality, Province or |  |  | Presently |  |  | Trustee/Director/Officer |  |  | Principal Occupation
State & Country of Residence |  |  | Held |  |  | Since(1) |  |  | During the Preceding 5 Years
Frank M. Brown (3)(5) Anchorage, Alaska, USA |  |  | Director |  |  | December 2008 |  |  | Director of Precision since December 2008; Director of Grey Wolf since May 2000. Private consultant in the Alaskan oil and gas industry 2006-Present; Chief Executive Officer of ZRB Resources, LLC, since 2006.
William T. Donovan (2)(5) Milwaukee, Wisconsin, USA |  |  | Director |  |  | December 2008 |  |  | Director of Precision since December 2008; Director of Grey Wolf, 1997-2008; Chairman of the board of Rockland Industrial Holdings, LLC, since 2006.
W.C. (Mickey) Dunn(3)(4) Edmonton, Alberta, Canada |  |  | Director |  |  | September 1992 |  |  | Chairman, True Energy Trust.
Brian A. Felesky, CM, Q.C.(4) Calgary, Alberta, Canada |  |  | Director |  |  | December 2005 |  |  | Counsel, Felesky Flynn LLP. From April 1978 through July 2006, Partner at Felesky Flynn LLP.
Robert J.S. Gibson(2)(4) Calgary, Alberta, Canada |  |  | Trustee Director |  |  | June 1996 |  |  | President, Stuart & Company Limited.
Allen R. Hagerman, FCA(2) Calgary, Alberta, Canada |  |  | Trustee Director |  |  | December 2006 |  |  | Executive Vice President, Canadian Oil Sands Limited, Oil Sands Mining and Upgrading; Chief Financial Officer, Canadian Oil Sands Limited 2003 – 2007.
Stephen J.J. Letwin(3) Houston, Texas, USA |  |  | Director |  |  | December 2006 |  |  | Managing Director, Enbridge Energy Partners and Executive Vice President, Gas Transportation & International, Enbridge Inc. since May 2006; Group Vice President, Gas Strategy & Corporate Development, Enbridge Inc., April 2003 to May 2006; Group Vice President, Distribution & Services, Enbridge Inc., September 2000 to April 2003.
Patrick M. Murray(2) Dallas, Texas, USA |  |  | Trustee Director |  |  | July 2002 |  |  | Corporate Director; Chairman and Chief Executive Officer, Dresser, Inc. from 2001 until retiring in May 2007.
Kevin A. Neveu Calgary, Alberta, Canada |  |  | President, Chief Executive Officer Director |  |  | August 2007 |  |  | President and Chief Executive Officer since January 13, 2009. Chief Executive Officer, Precision Drilling Corporation from August 2007 to January 13, 2009; President, Rig Solutions Group, National Oilwell Varco 2002 to 2007.

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|  |  | Position |  |  |  |  |  |
Name, Municipality, Province or |  |  | Presently |  |  | Trustee/Director/Officer |  |  | Principal Occupation
State & Country of Residence |  |  | Held |  |  | Since(1) |  |  | During the Preceding 5 Years
Frederick W. Pheasey(3) Edmonton, Alberta, Canada |  |  | Director |  |  | July 2002 |  |  | Director of Dreco Energy Services Ltd.
Robert L. Phillips(2)(3)(4) Vancouver, British Columbia, Canada |  |  | Director Chairman |  |  | May 2004 |  |  | Corporate Director; President and Chief Executive Officer, BCR Group of Companies 2001-2004.
Trevor M. Turbidy (4)(5) Houston, Texas, USA |  |  | Director |  |  | December 2008 |  |  | Director of Precision since December 2008; Director of Grey Wolf 2005-2008; Energy Industry Advisor with Avista Capital Partners 2007-Present; President and Chief Executive Officer of Trico Marine Services, Inc., 2005-2007.
Joanne L. Alexander Calgary, Alberta, Canada |  |  | Vice President, General Counsel and Corporate Secretary |  |  | April 2008 |  |  | Vice-President, General Counsel and Corporate Secretary since January 13, 2009; Vice President and General Counsel, Precision Drilling Corporation from April 2008 to January 13, 2009; General Counsel, Marathon Oil Canada Corporation 2007-2008; General Counsel, Western Oil Sands Inc. 2007; General Manager, Stakeholder Engagement & Regulatory Affairs, ConocoPhillips Canada Ltd. 2006; Vice President, Legal and Regulatory Affairs, Burlington Resources Canada Ltd. 2000-2006.
David J. Crowley Houston, Texas, USA |  |  | President, U.S. Operations |  |  | January 2009 |  |  | President, U.S. Operations since January 13, 2009. Executive Vice President and Chief Operating Officer, Grey Wolf 2007-2008; Senior Vice President of Operations, The Offshore Drilling Company 2003-2007.
Kenneth J. Haddad Houston, Texas, USA |  |  | Vice President, Business Development |  |  | March 2008 |  |  | Vice President, Business Development, Precision Drilling Corporation since March 2008; Director, Mergers and Acquisitions, Halliburton Company 2002-2008.
Darren J. Ruhr Calgary, Alberta, Canada |  |  | Vice President, Corporate Services |  |  | November 2005 |  |  | Vice-President, Corporate Services since January 13, 2009, Vice President, Corporate Services & Corporate Secretary, Precision Drilling Corporation from November 2005 to January 13, 2009; Director, Information Technology, Real Estate & Travel, Precision Drilling Corporation 2003-2005; Director, Information Technology, Precision Drilling Corporation 2000-2003.
Gene C. Stahl Calgary, Alberta, Canada |  |  | President, Canadian Operations |  |  | November 2005 |  |  | President, Canadian Operations since January 13, 2009, President & Chief Operating Officer, Precision Drilling Corporation from November 2005 to January 13, 2009; Vice President, Precision Rentals 2003-2005; General Manager, Ducharme Rentals/Big D Rentals 2002-2003.
Douglas J. Strong Calgary, Alberta, Canada |  |  | Chief Financial Officer |  |  | November 2005 |  |  | Chief Financial Officer, Precision Drilling Corporation since 2005; Chief Financial Officer, Precision Diversified Services Ltd. 2001-2005, Group Controller, Precision Drilling 2001- 2005.
David W. Wehlmann Houston, Texas, USA |  |  | Executive Vice President, Investor Relations |  |  | January 2009 |  |  | Executive Vice President, Investor Relations since January 13, 2009. Executive Vice President and CFO, Grey Wolf 2003-2008; Senior Vice President, Chief Financial Officer and Secretary, Grey Wolf 1998-2003; Vice President, Controller, Grey Wolf 1996-1998.

NOTES:

(1) |  | Each Trustee’s or Director’s term of office expires not later than the close of business at the next annual meeting, or until successors are appointed or Trustees or Directors vacate their office.
(2) |  | Member of the Audit Committee.
(3) |  | Member of the Compensation Committee.
(4) |  | Member of the Corporate Governance and Nominating Committee.
(5) |  | Nominated by Grey Wolf and appointed by Precision.

At March 27, 2009, the Trustees, Directors and officers of Precision, as a group, beneficially owned, directly or indirectly, or controlled or directed over 1,062,577 Trust Units and no Exchangeable Units, or approximately 0.516% of the issued and outstanding Trust Units and Exchangeable Units, which aggregate number includes a total of 73,536 Trust Units credited to the accounts of non-management Directors pursuant to a deferred trust unit plan approved by Unitholders on May 7, 2008.
CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS
Corporate Cease Trade Orders
To the knowledge of the Trust, no Trustee, Director or executive officer of the Trust or Precision, as applicable, is as at the date hereof or has been, within the 10 years before the date hereof, a director, chief executive officer or chief financial officer of any company that: (i) was subject to an order that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer; or (ii) was subject to an order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer.

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Corporate Bankruptcies
To the knowledge of the Trust, no Trustee, Director, executive officer or controlling securityholder of the Trust or Precision, as applicable, is, as of the date hereof, or has been within the 10 years before the date hereof, a director or executive officer of any company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.
Personal Bankruptcies
To the knowledge of the Trust, no Trustee, Director, executive officer or controlling securityholder of the Trust or Precision, as applicable, has, within the 10 years before the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or became subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold such person’s assets.
Penalties or Sanctions
To the knowledge of the Trust, no Trustee, Director, executive officer or controlling securityholder of the Trust or Precision, as applicable, has been subject to: (i) any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or (ii) any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.
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), Robert L. Phillips, Allen R. Hagerman, Robert J.S. Gibson and William T. Donovan. 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 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 or the Board of Directors and its committees. All members of the Audit Committee are “financially literate” (as that term is defined in Multilateral Instrument 52-110 – Audit Committees). In addition, the Board of Directors has determined that each of Messrs. Murray, Hagerman and Donovan qualify as “audit committee financial experts” (as that term is defined in 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 retired 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. Robert L. Phillips’ experience includes executive level positions at several corporations and board membership on several public corporations. Mr. Phillips received a B.Sc. in Chemical Engineering in 1971 and a LLB in 1976 from the University of Alberta. Mr. Phillips was appointed to the Audit Committee in December, 2008. Allen R. Hagerman is the Executive Vice

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President, Canadian Oil Sands Limited and was Chief Financial Officer of Canadian Oil Sands Limited from 2003 to 2007. Mr. Hagerman received a B. Comm. from the University of Alberta in 1973, his Chartered Accountant designation in 1975 and his FCA designation in 1996 from the Institute of Chartered Accountants of Alberta. Mr. Hagerman also received an MBA from the Harvard School of Business in 1977. Mr. Hagerman was appointed to the Audit Committee in May 2007. Robert J. S. Gibson is the President of Stuart & Company Limited and has been a member of the Audit Committee since June 1997. William T. Donovan is the Chairman of Rockland Industrial Holdings LLC of Milwaukee, Wisconsin and was a director of Grey Wolf from 1997 until the date of the Acquisition. Mr. Donovan has a B.Sc (1974) and an MBA (1976) from the University of Notre Dame. Mr. Donovan was appointed to the Audit Committee in December 2008.
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 2008 and 2007:
(in thousands of Canadian dollars)

Years ended December 31, |  |  | 2008 |  |  |  | 2007 |
Audit fees |  |  | $ | 2,248 |  |  |  | $ | 990 |
Audit-related fees |  |  |  | - |  |  |  |  | - |
Tax fees |  |  |  | 442 |  |  |  |  | 73 |
All other fees |  |  |  | 40 |  |  |  |  | - |
Total |  |  | $ | 2,730 |  |  |  | $ | 1,063 |

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. The increase in audit fees from 2007 to 2008 was primarily due to the Acquisition.

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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 2007 or 2008.
Tax fees consist of fees for tax compliance services, tax advice and tax planning. During fiscal 2008 and 2007 the services provided in this category included assistance and advice in relation to the preparation of income tax returns for the Trust and its subsidiaries, expatriate tax compliance matters, tax advice and planning, commodity tax and property tax consultation.
All other fees consist of fees for those services provided to the Trust. In 2008, these fees were for services rendered with respect to the Trust’s International Financial Reporting Standards conversion project. There were no such fees in 2007.
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
Except as described herein under the heading “Risk Factors – Risks Relating to the Acquisition – PDOS, as the successor to Grey Wolf, is subject to litigation regarding the Acquisition”, the Trust is not involved in any legal proceedings that it believes might have a material adverse effect on its business or results of operations.
During the course of the year ended December 31, 2008, the Trust was not subject to any penalties or sanctions imposed by a court in relation to securities legislation or by securities regulatory authority, was not the subject of any other penalties or sanctions imposed by a court or regulatory authority and did not enter 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 is reasonably expected to materially affect the Trust.
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 NA located in Golden, Colorado.
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:
Declaration of Trust
See “Corporate Structure – The Trust” and “Description of Capital Structure”.
Limited Partnership Agreement
See “Corporate Structure – Precision Drilling Limited Partnership” and “Description of Capital Structure”.
Voting and Exchange Trust Agreement
See “Description of Capital Structure”.

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Support Agreement
See “Description of Capital Structure”.
Administration Agreement
See “Corporate Structure – Administration Agreement”.
Merger Agreement
See “General Development of the Business – Three Year History”.
Secured Facility Agreement
See “Description of the Business of Precision – Material Debt”.
Unsecured Facility Agreement
See “Description of the Business of Precision – Material Debt”.
Copies 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, 2008. In connection with the audit of the Trust’s annual financial statements for the year ended December 31, 2008, the auditors confirmed that they are independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
As of the fiscal year ended December 31, 2008, 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.
With the Acquisition occurring close to the fiscal year end, management of Precision is not required to conclude as to the effectiveness of disclosure controls and procedures within Grey Wolf. As such, the principal executive officer and principal financial accounting officer have not concluded as to the design and effectiveness of disclosure controls and procedures in Grey Wolf.

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INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”) including reconciliation to United States generally accepted accounting principles (“U.S. GAAP”).
Under the supervision and with the participation of management, including the principal executive officer and principal financial and accounting officer, Precision conducted an evaluation of the design and effectiveness of our internal control over financial reporting as of the end of the fiscal year based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. On December 23, 2008, Precision acquired Grey Wolf and began consolidating the operations from that date. Based on the proximity of this acquisition to year end, management has excluded this business from its evaluation of the effectiveness of Precision’s internal control over financial reporting as of December 31, 2008. The net earnings attributable to this business represented approximately 1% of the Trust’s consolidated net earnings for the year ended December 31, 2008, and its aggregate total assets represented approximately 56% of the consolidated total assets as at December 31, 2008.
Based on this evaluation, management concluded that as of December 31, 2008, the Trust did maintain effective 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, 2008 forms part of the Trust’s 2008 Annual Report and is incorporated by reference in this Annual Information Form. Management’s Discussion and Analysis appears on pages 2 to 53 of the 2008 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, General Counsel 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 Trustees’, Directors’ and officers’ remuneration, will be contained in the Management Information Circular of the Trust provided for the Annual and Special Meeting of Unitholders of the Trust to be held on May 6, 2009, and filed on SEDAR. 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, 2008 which are contained in the Annual Report. Copies of such documents may be obtained in the manner set forth above.
RISK FACTORS
An investment in the Trust Units and Exchangeable Units is subject to certain risks. Investors should carefully review and consider the risks described below and all other information contained in this Annual Information Form before making an investment decision and consult their own experts where necessary.

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Risks Relating To The Structure Of The Trust
Precision may be unable to obtain access to additional financing.
Precision may find it necessary in the future to obtain additional debt or equity financing through the Trust to support ongoing operations, to undertake capital expenditures, to repay existing indebtedness or to undertake acquisitions or other business combination transactions. There can be no assurance that additional financing will be available to Precision when needed or on terms acceptable or favourable to Precision. Precision’s inability to raise financing to support ongoing operations or to fund capital expenditures, acquisitions, debt repayments or other business combination transactions could limit Precision’s growth and may have a material adverse effect upon Precision. See “Description of the Business of Precision – Material Debt”.
The Trust may not be able to obtain financing or obtain financing on acceptable terms because of the deterioration of the credit and capital markets.
On February 19, 2009, the Trust announced that the Senior Note Offering had been postponed due to currently unfavourable market conditions. Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. The re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding on acceptable terms, if at all. In particular, the cost of raising money in the debt and equity capital markets has increased substantially, while the availability of funds from those markets has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to the Trust’s current debt and reduced and, in some cases, ceased to provide funding to borrowers.
If the Trust’s business does not generate sufficient cash flow from operations to enable it to pay its indebtedness or to fund its other liquidity needs, then, as a consequence of these changes in the credit markets, the Trust cannot assure that future borrowings will be available to it under its credit facilities in sufficient amounts, either because the Trust’s lending counterparties may be unwilling or unable to meet their funding obligations or because the Trust’s borrowing base may decrease as a result of lower asset valuations, operating difficulties, lending requirements or regulations, or for any other reason. Moreover, even if lenders and institutional investors are willing and able to provide adequate funding, interest rates may rise in the future and therefore increase the cost of borrowing the Trust incurs on any of its floating rate debt. Finally, the Trust may need to refinance all or a portion of its indebtedness on or before maturity, sell assets, reduce or delay capital expenditures, seek additional equity financing or seek third-party financing to satisfy such obligations. The Trust cannot assure that it will be able to refinance any of its indebtedness on commercially reasonable terms or at all. There can be no assurance that the Trust’s business, liquidity, financial condition, or results of operations will not be materially and adversely impacted in the future as a result of the existing or future credit market conditions. See “General Development of the Business – Recent Developments”.
The Trust’s debt service obligations may limit the amount of cash available for distributions.
The Trust and its affiliates may, from time to time, finance a significant portion of their growth (either from acquisitions or capital expenditure additions) and operations 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 instruments. 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 available for distribution by the Trust. Ultimately, subordination agreements or other debt obligations (including the terms of the Credit Facilities, see “Description of the Business of Precision – Material Debt”) could preclude distributions altogether. See “Risk Factors – Risks Relating to the Acquisition”.
The terms of the documents governing the Credit Facilities contain provisions that in effect ensure that the lenders have priority as to payment over the Unitholders in respect to the assets and income of the Trust and its subsidiaries. Amounts due and owing to the lenders under the Credit Facilities must be paid before any distributions

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can be made to Unitholders. This relative priority of payments could result in a temporary or permanent interruption of distributions to Unitholders. See “Risk Factors – Distributions on the Trust Units have been suspended and may not be reinstated”.
Sales of additional Trust Units could negatively affect the value of the Trust Units.
The Trust may issue additional Trust Units in the future to fund the requirements of Precision and other entities now or hereafter owned directly or indirectly by the Trust. 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 has discretion in connection with the price and the other terms of the issue of such additional Trust Units. See “General Development of the Business – Recent Developments”.
The price of Trust Units may experience volatility.
The price of Trust Units may be volatile. Some of the factors that could affect the price of the Trust Units are increases or decreases in revenue or earnings, changes in cash distributions made by the Trust, changes in revenue or earnings estimates by the investment community, the ability of the Trust to implement its integration strategy and to realize the expected benefits from the Acquisition and speculation in the press or investment community about the Trust’s financial condition or results of operations. General market conditions and Canadian, United States or international economic factors and political events unrelated to the performance of the Trust may also affect the price of Trust Units. For these reasons, investors should not rely on past trends in the price of Trust Units to predict the future price of Trust Units or the Trust’s financial results. Precision has experienced a reduction in the demand for its services in late 2008 and early 2009 in correlation with the significant downward trend in oil and natural gas prices over the same period. See “General Development of the Business – Recent Developments”.
Distributions on the Trust Units have been suspended and may not be reinstated.
On February 9, 2009, the Trust announced that it had suspended cash distributions for an indefinite period. The Trust’s ability to resume making cash distributions, if any, in the future and the actual cash flow available for distribution to Unitholders is a function of numerous factors including, among other things, the Trust’s, Precision’s and PDLP’s financial performance; debt covenants and obligations; working capital requirements; future upgrade capital expenditures and future expansion capital expenditure requirements for the purchase of property, plant and equipment; tax obligations; the impact of interest rates and/or foreign exchange 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. Cash distributions may or may not be reinstated, may be reinstated at amounts different than historical or recent amounts (and subsequently increased or reduced) or may be eliminated entirely depending on the Trust’s operations and the performance of its assets. The market value of the Trust Units may deteriorate if the Trust is unable to reinstate its cash distributions or otherwise meet cash distribution expectations in the future, and that deterioration may be material. See “Risk Factors – The Trust is dependent on Precision and its subsidiaries for the amount of cash available for distributions” and “Distributions on the Trust Units are variable”.
Asset valuation variability could negatively affect the value of the Trust Units.
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 the Trust. The trading price of the Trust Units also fluctuates due to factors beyond the control of the Trust and such trading prices may be greater than the net asset value of the Trust’s assets.
The Trust could face negative tax consequences for previous transactions.
The business and operations of Precision prior to completion of the Plan of Arrangement pursuant to which former shareholders of Precision were issued Trust Units 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 these transactions involves many complex factors as well as Precision’s interpretation of relevant tax legislation and regulations. Management believes that the provision for income tax is adequate and in accordance with generally accepted accounting principles and applicable legislation

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and regulations. However, there are a number of tax filing positions that can still be the subject of review by taxation authorities who may successfully challenge Precision’s interpretation of the applicable tax legislation and regulations, with the result that additional taxes could be payable by Precision and the amount payable without penalties could be up to $382 million as of December 31, 2008. Any increase in tax liability would reduce the net assets of and funds available to the Trust.
The Trust received Notices of Reassessment from a provincial taxing authority relating to a prior period tax filing position in the total amount of $58 million as of December 31, 2008. This $58 million has been paid, recorded as a long-term receivable and included in the $382 million tax contingency disclosed in the preceding paragraph. The income tax-related portion of the applicable reassessments and the interest portion is $38 million and $20 million, respectively.
The Trust is dependent on Precision and its subsidiaries for the amount of cash available for distributions.
To receive cash available for distribution, the Trust is dependent on the operations and assets of Precision (as well as its direct and indirect subsidiaries, including PDOS, the former Grey Wolf) through its interest in PDLP, which in turn owns 100% of the shares of Precision and the Promissory Note. Distributions to Unitholders 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, 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, industry activity, 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 to the Trust will adversely impact or limit the amount of cash available for distributions by the Trust to Unitholders. 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. See “Risk Factors – Distributions on the Trust Units are variable” and “Distributions on the Trust Units have been suspended and may not be reinstated”.
Risks associated with the taxation of the Trust and Precision could negatively affect the value of the Trust Units.
There can be no assurance that Canadian federal income tax laws and administrative policies respecting the treatment of “mutual fund trusts” will not be changed in a manner that adversely affects Unitholders. For example, if the Trust ceases to qualify as a “mutual fund trust” under the Tax Act, certain Canadian income tax considerations would be materially and adversely different in certain respects.
To qualify as a “mutual fund trust” for purposes of the Tax Act the Trust must continuously satisfy certain requirements as to the nature of its undertakings (primarily that it must restrict its activities to the investment of funds), its ability to distribute Trust Units to the public, the dispersal of ownership of its Trust Units and the requirement that, unless it meets certain exceptions, it must not be reasonable to consider that it was established or is maintained primarily for the benefit of Non-Canadian Holders (as defined herein).
As noted above, the Tax Act provides that a trust will not be considered to be a “mutual fund trust” for purposes of the Tax Act if it is established or is maintained primarily for the benefit of non-residents of Canada. However, this disqualification rule does not apply if all or substantially all of the trust’s property is property other than “taxable Canadian property” as defined in the Tax Act. Although no assurances can be provided, all or substantially all of the assets of the Trust should be property other than “taxable Canadian property” as defined in the Tax Act.
Relevant specific proposals to amend the Tax Act that have been publicly announced by the Minister of Finance (Canada) prior to the date of this Annual Information Form (the “Proposed Amendments”) provide that the Trust will lose its status as a “mutual fund trust” if the aggregate fair market value of all Trust Units issued by the

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Trust and 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 of the Trust Units issued by the Trust and if more than 10% (based on fair market value) of the Trust’s property consists of certain types of “taxable Canadian property”, “Canadian resource property” or “timber resource property”, all as defined in the Tax Act. Since no more than 10% of the Trust’s property should be “taxable Canadian property”, “Canadian resource property” or “timber resource property” these Proposed Amendments should not adversely affect the Trust’s status as a “mutual fund trust”. However, no assurances can be provided that no more than 10% of the Trust’s property will be “taxable Canadian property”, “Canadian resource property” or “timber resource property” and, therefore, that, if enacted, these Proposed Amendments would not adversely affect the Trust’s status as a “mutual fund trust” under the Tax Act.
Provided the Trust satisfies the foregoing requirements it should be a “mutual fund trust” for purposes of the Tax Act. If the Trust ceased to qualify as a “mutual fund trust” under the Tax Act, certain Canadian federal income tax considerations would be materially and adversely different in certain respects.
Moreover, if the Trust were to cease to qualify as a “mutual fund trust”, Trust Units held by Unitholders who are not resident in Canada for the purposes of the Tax Act (“Non-Canadian Holders”) would become “taxable Canadian property” under the Tax Act. These Non-Canadian Holders would be subject to Canadian income tax on any gains realized on a disposition of the Trust Units held by them unless they were exempt under an income tax convention, and Non-Canadian Holders may be subject to certain notification and withholding requirements on a disposition of their Trust Units. In addition, the Trust would be taxed on certain types of income distributed to Unitholders (apart from under the specified investment flow-through legislation discussed below). Payment of this tax may have adverse consequences for some Unitholders, particularly Non-Canadian Holders and residents of Canada that are otherwise exempt from Canadian income tax.
The SIFT Rules apply to trusts that are resident in Canada for purposes of the Tax Act, that hold one or more “non-portfolio properties”, and the trust units of which are listed on a stock exchange or other public market. A SIFT trust effectively is subject to tax on its income from non-portfolio properties and taxable capital gains from dispositions of non-portfolio properties paid, or made payable, to unitholders at a rate comparable to the combined federal and provincial corporate income tax rate.
In general terms, a trust that existed on October 31, 2006 and to which the SIFT Rules otherwise would apply (i.e., the Trust), should not become a SIFT trust until the earlier of January 1, 2011 or the first day after December 15, 2006 that the trust exceeds “normal growth” determined by reference to the Guidelines. The Guidelines provide that a trust should not be considered to exceed “normal growth” if the trust does not issue new equity (including convertible debentures or other equity substitutes) that exceeds the greater of $50 million per year or certain specified “safe harbour” amounts based on the market capitalization of the trust on October 31, 2006.
Provided that the Trust does not issue new equity (including debt that is convertible into equity) in an amount greater than the “safe-harbour” amount of $4 billion determined by reference to the market capitalization of the Trust on October 31, 2006, the Trust should not be considered to exceed “normal growth” as set forth in the Guidelines. No assurances can be provided that the Trust will not otherwise become a SIFT trust prior to January 1, 2011.
As part of its ongoing strategic planning, the Trust will continue to examine and evaluate its various strategic alternatives, including its ability to reorganize its legal and tax structure to mitigate the expected impact of the SIFT Rules. While no assurances can be provided regarding the strategic alternatives, if any, that may be available, the strategic alternatives considered will recognize that on March 12, 2009 the federal government enacted the SIFT Conversion Rules.
There can be no assurance that the Trust will not cease to qualify as a “mutual fund trust” under the Tax Act or that it will not become a SIFT trust prior to January 1, 2011.

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If the Trust does not constitute a “qualified foreign corporation” for United States federal income tax purposes, individual U.S. Holders (as defined below) may be taxed at a higher rate on distributions.
Management expects that distributions it makes to non-corporate U.S. Holders (including individual U.S. Holders) that are treated as dividends for United States 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 United States federal income tax purposes, and as a result such dividends to non-corporate U.S. Holders 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.
For the purposes of this Annual Information Form, the term “U.S. Holder” means a beneficial owner of Trust Units that for United States federal income tax purposes is:

| (a) | an individual citizen or resident of the United States;

| (b) | a corporation or other entity treated as a corporation for federal income tax purposes, created or organized in or under the laws of the United States or any State or the District of Columbia;

| (c) | an estate that is subject to United States federal income tax on its income regardless of is source; or

| (d) | a trust, the substantial decisions of which are controlled by one or more United States persons and which is subject to the primary supervision of a United States court, or a trust that validly has elected under applicable Treasury regulations to be treated as a United States person for United States federal income tax purposes.

Changes in legislation may have an adverse effect on Unitholders.
There can be no assurance that income tax laws related to the status of “mutual fund trusts”, the taxation of “mutual fund trusts”, or other matters will not be changed in a manner which adversely affects Unitholders. Environmental and applicable operating legislation may be changed in a manner which adversely affects Unitholders.
Precision has retained liabilities as a consequence of prior reorganizations.
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.
A successful challenge by the tax authorities of the amount of interest expense deducted by Precision on its payments of Promissory Note interest could negatively affect the value of the Trust Units.
Income fund structures often involve significant amounts of inter-entity debt, which may generate substantial interest expense and which serves to reduce earnings and therefore income tax payable. This is 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 or the Trust, it could have a material adverse affect on the amount of distributions paid by the Trust to Unitholders.
A successful challenge by the tax authorities of the amount of expenses deducted by the Trust or its subsidiaries could negatively affect the value of the Trust Units.
There can be no assurance that the applicable taxation authorities will agree with the classification of expenses claimed by the Trust or its subsidiaries. If the taxation authorities successfully challenge the deductibility of any such expenses, the return to Unitholders may be adversely affected.

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A change in the structure of the Trust may have an adverse effect on Unitholders.
As a result of the adoption of the SIFT Rules, management of the Trust may, from time to time, evaluate the organizational and capital structure of the Trust and its subsidiaries to ensure that it remains appropriate and efficient for the business of the Trust and the benefit of Unitholders. Such evaluation and review may result in the recommendation that Unitholders approve a conversion of the Trust to a corporation.
In the event that such a recommendation were to be made, approved and implemented, the Trust’s income trust structure could be reorganized into a corporation and the Unitholders may become shareholders of that corporation which would own all of the Trust Units of the Trust. Under this form of reorganization, each Unitholder would exchange its Trust Units for shares of the successor corporation. Such reorganization would be subject to a review of all possible reorganization alternatives as well as approval of the Unitholders and to such other approvals as may be required, including regulatory, stock exchange and court approvals.
In connection with any such reorganization, the current distribution policies of the Trust would be replaced by the dividend policy of the successor corporation which may result in a decrease in the cash amount distributed compared with the current or prior distributions of the Trust. Furthermore, the reorganization would result in the conversion of the Trust into an entity that would be subject to Canadian federal and provincial income tax.
Any such reorganization may occur prior to January 1, 2011 and may have an adverse impact on the market price of the Trust Units.
Trust Units have certain risks not associated with traditional investments in the oil and natural gas services business.
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 a corporation. The Trust Units represent a fractional interest in the Trust. Unitholders 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 Class A Limited Partnership Units of PDLP and other investments in securities. The price per Trust Unit is a function of anticipated net earnings, the amount of cash distributions paid by the Trust to Unitholders, 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 not a legally recognized entity within the relevant definitions of the Bankruptcy and Insolvency Act (Canada), the Companies’ Creditors Arrangement Act (Canada) and, in some cases, the Winding Up and Restructuring Act (Canada). As a result, in the event a restructuring of the Trust were necessary, the Trust would not be able to access the remedies available thereunder. In the event of a restructuring, the position of Unitholders may be different than that of the shareholders of a corporation.
The composition for Canadian federal income tax purposes of distributions on Trust Units may change over time, and such changes could negatively affect the return on the Trust Units.
Unlike interest payments on an interest-bearing security, distributions by income trusts on trust units (including the Trust Units) are, for Canadian federal income 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 Canadian federal income tax purposes of distributions may change over time, thus affecting the after-tax return to Unitholders who are resident in Canada for purposes of the Tax Act (“Canadian Holders”). Therefore, the rate of return for Canadian Holders over a defined period may not be comparable to the rate of return

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on a fixed-income security that provides a return on capital over the same period. This is because a Canadian Holder 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 Canadian Holder (but reduce the adjusted cost base in a Trust Unit for Canadian federal income tax purposes).
If the Trust ceases to qualify as a “mutual fund trust” under the Tax Act, the Trust Units will cease to be qualified investments for a variety of plans, which could have negative tax consequences.
If the Trust ceases to qualify as a “mutual fund trust”, the Trust Units will cease to be qualified investments for trusts governed by “registered retirement savings plans”, “registered retirement income funds”, “deferred profit sharing plans” and “registered education savings plans”, each as defined in the Tax Act (collectively, “Exempt Plans”) and for trusts governed by “tax-free savings accounts”, as defined in the Tax Act. Where, at the end of any month, an Exempt Plan holds trust units that are not qualified investments, the Exempt Plan must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to 1% of the fair market value of the trust units at the times such trust units were acquired by the Exempt Plan. In addition, where a trust governed by a “registered retirement savings plan” or “registered retirement income fund” holds trust units that are not qualified investments, such trust will become taxable on its income attributable to the trust units while they are not qualified investments, including the full amount of any capital gain realized on a disposition of trust units while they are not qualified investments. Where a trust governed by a “registered education savings plan” holds trust units that are not qualified investments, the plan’s registration may be revoked. Where a trust governed by a “tax-free savings account” holds trust units that cease to be qualified investments, the holder of that “tax-free savings account” may be required to pay a tax under Part XI.01 of the Tax Act equal to 50% of the fair market value of such trust units at the time the trust units ceased to be a qualified investment.
Canadian withholding tax may exceed allowable United States foreign tax credits and reduce effective yield to United States investors.
Withholding of Canadian tax is imposed at a 25% rate (reduced to 15% for recipients that are residents of the United States eligible for benefits under the Canada-United States Tax Convention) both on cash and non-cash distributions by the Trust to persons that are not Canadian residents. However, as certain non-cash distributions by the Trust generally will not be included in income for United States federal income tax purposes, such Canadian withholding tax may exceed a U.S. Holder’s allowable foreign tax credit for the taxable year of the distribution, potentially resulting in a reduced after-tax cash yield to United States investors for the year of such distribution.
The Trust expects to maintain its status as a “foreign private issuer” in the United States and thus will be exempt from a number of rules under the Exchange Act and will be permitted to file less information with the SEC than a company incorporated in the United States.
As a “foreign private issuer” the Trust is exempt from certain rules under the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”) that impose disclosure requirements, as well as procedural requirements, for proxy solicitations under Section 14 of the Exchange Act. The officers, Trustees and principal Unitholders of the Trust are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act. Moreover, the Trust is not required to file periodic reports and financial statements with the SEC as frequently or as promptly as United States companies whose securities are registered under the Exchange Act, nor is it generally required to comply with Regulation FD, which restricts the selective disclosure of material nonpublic information. Accordingly, there may be less information concerning the Trust publicly available than there is for United States public companies and such information may not be provided as promptly. In addition, the Trust is permitted, under a multi-jurisdictional disclosure system adopted by the United States and Canada, to prepare its disclosure documents in accordance with Canadian disclosure requirements, including preparing its financial statements in accordance with Canadian GAAP, which differs in some respects from U.S. GAAP.

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Issuance of additional Trust Units in lieu of cash distributions could negatively affect the value of the Trust Units and result in the payment of taxes.
The Declaration of Trust provides that an amount equal to the taxable income of the Trust will be payable each year to Unitholders 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. Such “in kind” distributions have been declared by the Trust in each of 2006, 2007 and 2008. In such a case, Unitholders will generally be required to include an amount equal to the fair market value of those Trust Units in their taxable income in the year declared, notwithstanding that they do not directly receive a cash payment.
Distributions on the Trust Units are variable.
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 upgrade capital expenditures and future expansion capital expenditure requirements for the purchase of property, plant and equipment; tax obligations; the impact of interest rates and/or foreign exchange 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. Cash distributions may be increased, reduced or suspended or eliminated entirely depending on the Trust’s operations and the performance of its assets. The market value of the Trust Units may deteriorate if the Trust is unable to meet cash distribution expectations in the future, and that deterioration may be material. See “Risk Factors — The Trust is dependent on Precision and its subsidiaries for the amount of cash available for distributions” and “Distributions on the Trust Units have been suspended and may not be reinvested”.
There are risks associated with the indemnification of the limited partners of PDLP.
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 of PDLP and the Exchangeable Units, the General Partner may not have sufficient assets to honour the indemnity.
The Trust may become a passive foreign investment company (“PFIC”), which could result in adverse United States tax consequences to United States investors.
Management does not believe that the Trust is, or will be treated as, a PFIC for United States tax purposes. Since PFIC status is determined on an annual basis and will depend on the composition of the Trust’s income and assets from time to time, it is possible that the Trust could be considered a PFIC in 2008 or a future taxable year. Such characterization could result in adverse United States tax consequences to a United States investor. In particular, a United States investor would be subject to United States federal income tax at ordinary income rates, plus a possible interest charge, in respect of any gain derived from a disposition of the Trust Units, as well as certain distributions by the Trust. In addition, a step-up in the tax basis of the Trust Units would not be available upon the death of an individual holder.
Unitholders face a possibility of personal liability in connection with the obligations and affairs of the Trust.
The Declaration of Trust provides that no Unitholder 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 Unitholders 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 Unitholder from any costs, damages, liabilities, expenses, charges and losses suffered by a Unitholder resulting from or arising out of such Unitholder 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 Unitholders 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.

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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 unitholder will not be, as a beneficiary, liable for any act, default, obligation or liability of the trustee(s) of the trust 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 Unitholders for claims against the Trust, including by obtaining appropriate insurance, where available and to the extent commercially feasible.
If an investor acquires 10% or more of the Trust Units it may be subject to taxation under the CFC rules.
Under certain circumstances, a United States person who directly or indirectly owns 10% or more of the voting power of a foreign corporation that is a controlled foreign corporation (“CFC”) (generally, a foreign corporation in which 10% United States shareholders own more than 50% of the voting power of the foreign corporation) for an uninterrupted period of 30 days or more during a taxable year and who holds any shares of the foreign corporation on the last day of the corporation’s tax year must include in gross income for United States federal income tax purposes its pro rata share of certain income of the CFC even if such share is not distributed to such person. The Trust is not presently a CFC, but this could change in the future.
The terms of the documents governing the Credit Facilities contain provisions that in effect ensure that the lenders have priority as to payment over the Unitholders in respect to the assets and income of the Trust and its subsidiaries. Amounts due and owing to the lenders under the Credit Facilities must be paid before any distributions can be made to Unitholders. This relative priority of payments could result in a temporary or permanent interruption of distributions to Unitholders.
The distribution of assets on redemption or termination of the Trust may have adverse consequences.
It is anticipated that a redemption right will not be the primary mechanism for Unitholders 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 Unitholders, 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.
Risks Relating To The Business Currently Conducted By Precision
The operations of Precision are 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. However, recent developments in the transportation of liquefied natural gas (“LNG”) in ocean going tanker ships have introduced an element of globalization to the natural gas market. Crude oil and natural gas prices are quite volatile, which accounts for much of the cyclical nature of the oilfield services business.
Worldwide military, political and economic events, including initiatives by the Organization of the Petroleum Exporting Countries and other major petroleum exporting countries, for instance, 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, United States and Canadian natural gas 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. A prolonged reduction in oil and natural gas prices would likely depress the level of exploration and production activity. This would likely result in a corresponding decline in

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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 write down for accounting purposes, Precision’s ability to retain skilled rig personnel and Precision’s ability to obtain access to capital to finance and grow its businesses. There can be no assurance that the future level of demand for Precision’s services or future conditions in the oil and natural gas and oilfield services industries will not decline.
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. The collection of receivables may be adversely affected by any prolonged weakness in oil and natural gas prices.
The intense price competition and cyclical nature of the contract drilling industry could have an adverse effect on revenue and profitability.
The contract drilling business is highly competitive with numerous industry participants, and the drilling contracts Precision competes for are usually awarded on the basis of competitive bids. Management believes pricing and rig availability are the primary factors considered by Precision’s potential customers in determining which drilling contractor to select. Management believes other factors are also important. Among those factors are:

| • | the drilling capabilities and condition of drilling rigs;
| • | the quality of service and experience of rig crews;
| • | the safety record of the contractor and the particular drilling rig;
| • | the offering of ancillary services;
| • | the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques; and
| • | the mobility and efficiency of rigs.

The contract drilling industry historically has been cyclical and has experienced periods of low demand, excess rig supply, and low dayrates, followed by periods of high demand, short rig supply and increasing dayrates. Periods of excess drilling rig supply intensify the competition in the industry and often result in rigs being idle. There are numerous contract drilling competitors in each of the markets in which Precision competes. In all of those markets, an oversupply of drilling rigs can cause greater price competition. Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services is better in a region where Precision operates, its competitors might respond by moving in suitable drilling rigs from other regions, by reactivating previously stacked rigs or purchasing new drilling rigs. An influx of drilling rigs into a market area from any source could rapidly intensify competition and make any improvement in demand for drilling rigs short-lived.
The number of drilling rigs competing for work in the market areas Precision serves has increased due to the entry into those markets of newly-built or newly-refurbished rigs. Management expects that more of these newer rigs may enter Precision’s market areas over the next year. The addition of these drilling rigs in 2008 has and could continue to intensify price competition and possibly reduce customer demand for term drilling contracts, which would have an adverse effect on the revenues, cash flows and earnings of the Trust.
Deteriorating conditions in the credit markets may adversely affect business.
The ability to make scheduled payments on or to refinance debt obligations depends on the financial condition and operating performance of the Trust, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond its control. The credit markets have recently experienced and continue to experience adverse conditions. Continuing volatility in the credit markets may increase costs associated with debt instruments due to increased spreads over relevant interest rate benchmarks, or affect the Trust’s, or third parties it seeks to do business with, ability to access those markets. The Trust may be unable to

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maintain a level of cash flow from operating activities sufficient to permit it to pay the principal, premium, if any, and interest on its indebtedness.
In addition, there has been substantial uncertainty in the capital markets and access to financing is uncertain. These conditions could have an adverse effect on the industry in which the Trust operates and its business, including future operating results. Precision’s customers may curtail their drilling programs, which could result in a decrease in demand for drilling rigs and a reduction in dayrates, reduction in the number and profitability of turnkey jobs and/or utilization. In addition, certain customers could experience an inability to pay suppliers, including the Trust, in the event they are unable to access the capital markets to fund their business operations.
The results of the Trust’s annual assessment of goodwill may result in a non-cash charge against the consolidated net income of the Trust.
In general, Canadian GAAP requires that the Trust assess its goodwill balance at least annually for impairment and that any permanent impairment writedown be charged to net income. The calculation of any impairment is subject to management estimates and assumptions. Factors that may be considered in such a calculation include, but are not limited to, declines in Trust Unit price and market capitalization, reduced future cash flow and earnings estimates, significantly reduced or depressed markets in the industry in which the Trust and its subsidiaries operate and general economic conditions. Any impairment would result in a writedown of the goodwill value and a non-cash charge against net income. If any impairment writedown to goodwill is required under Canadian GAAP, such writedown may be material.
Precision completed its annual assessment of goodwill effective December 31, 2008 and concluded that there was no impairment of the carrying value for long-lived assets and goodwill. Future impairment analysis of goodwill and long-lived assets may be required and at intervals more frequent than in the past due to declines in economic conditions. These impairment analyses may result in impairment charges being recorded and such charges could be material.
Capital overbuild in the drilling industry could lead to a decline in demand for Precision’s services.
Because of the long life nature of drilling equipment and the lag between the moment a decision to build a rig is made and the moment the rig is placed into service, the number of rigs in the industry does not always correlate to the level of demand for those rigs. Periods of high demand often spur increased capital expenditures on rigs, and those capital expenditures may exceed actual demand. Management believes that there is currently an excess of rigs in the North American oil and gas industry in relation to current levels of demand. This capital overbuild could cause Precision’s competitors to lower their rates and could lead to a decrease in rates in the oilfield services industry generally, which would have an adverse effect on the revenues, cash flows and earnings of the Trust.
Customer merger and acquisition activity could lead to a decline in the demand for services.
Merger and acquisition activity in the oil and natural gas exploration and production sector can impact demand for Precision’s services as customers focus on internal reorganization activities prior to committing funds to significant drilling and capital maintenance projects.
Business acquisitions entail numerous risks and may disrupt Precision’s business or distract management attention.
The Trust contemplates that as part of its business strategy, it will continue to consider and evaluate acquisitions of, or significant investments in, businesses and assets that are complementary to it. Any acquisition that the Trust completes could have a material adverse effect on the Trust’s operating results and/or the price of its securities. Acquisitions involve numerous risks, including:

| • | unanticipated costs and liabilities;
| • | difficulty of integrating the operations and assets of the acquired business;

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| • | the ability to properly access and maintain an effective internal control environment over an acquired company in order to comply with public reporting requirements;
| • | potential loss of key employees and customers of the acquired companies; and
| • | an increase in Precision’s expenses and working capital requirements.

The Trust may incur substantial indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with any such acquisitions. Debt service requirements could represent a significant burden on the Trust’s results of operations and financial condition and the issuance of additional equity could be dilutive to Unitholders. The Trust will also be required to meet certain financial covenants in order to borrow money under its credit agreements to fund future acquisitions. Acquisitions could also divert the attention of management and other employees from Precision’s day-to-day operations and the development of new business opportunities. Even if the Trust is successful in integrating its current or future acquisitions into its existing operations, the Trust may not derive the benefits, such as operational or administrative synergies, that the Trust expected from such acquisitions, which may result in the commitment of the Trust’s capital resources without the expected returns on such capital. In addition, the Trust may not be able to continue to identify attractive acquisition opportunities or successfully acquire identified targets.
Business in Precision’s industry is seasonal and highly variable.
In Canada and the northern part of the United States, the level of activity in the oilfield service industry is influenced by seasonal weather patterns. During the spring months, wet weather and the spring thaw make the ground unstable. Consequently, municipalities and counties and provincial and state transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels and placing an increased level of importance on the location of Precision’s equipment prior to imposition of the road bans. The timing and length of road bans is 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 areas of western Canada that are inaccessible, other than during the winter months, because the ground surrounding or containing the drilling sites in these areas consists of terrain known as muskeg. Until the muskeg freezes, the rigs and other necessary equipment cannot cross the terrain to reach the drilling site. Moreover, once the rigs and other equipment have been moved to a drilling site, they may become stranded or otherwise unable to relocate to another site should the muskeg thaw unexpectedly. Precision’s business results depend, at least in part, upon the severity and duration of the winter season.
New technology could place Precision at a disadvantage versus competitors.
Complex drilling programs for the exploration and development of remaining conventional and unconventional oil and natural gas reserves in North America demand high performance drilling rigs. The ability of drilling rig service providers to meet this demand will depend on continuous improvement of existing rig technology such as drive systems, control systems, automation, mud systems and top drives to improve drilling efficiency. Precision’s ability to deliver equipment and services that are more efficient is critical to continued success. There is no assurance that competitors will not achieve technological improvements that are more advantageous, timely or cost effective than improvements developed by Precision.
Unexpected cost overruns on turnkey drilling jobs could adversely affect Precision’s revenues.
Grey Wolf historically derived a portion of its revenues from turnkey drilling contracts and management of Precision expects that turnkey drilling will continue to represent a part of Precision’s revenue. The occurrence of operating cost overruns on turnkey jobs could have a material adverse effect on the Trust’s financial position and results of operations. Under a typical turnkey drilling contract, Precision would agree to drill a well for a customer to a specified depth and under specified conditions for a fixed price. As part of this arrangement, Precision would typically provide technical expertise and engineering services, as well as most of the equipment required for the drilling of turnkey wells. Precision would use subcontractors for related services. In the typical turnkey drilling arrangement, Precision would not receive progress payments and would be entitled to be paid by the customer only after the terms of the drilling contract have been performed in full. In addition, from time to time, Grey Wolf had

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encountered difficulties on wells being drilled under turnkey contracts and has incurred related costs, not all of which have been covered by Grey Wolf’s insurance. For these reasons, the risk under turnkey drilling contracts is substantially greater than for wells drilled on a daywork basis, because under such contracts Precision must assume most of the risks associated with drilling operations that are generally assumed by the customer under a daywork contract.
Any difficulty Precision experiences retaining, replacing or adding personnel could adversely affect its business.
Precision may not be able to find enough skilled labor to meet its needs, which could limit its growth. As a result, Precision may have problems finding enough skilled and unskilled laborers in the future if demand for its services increases. If Precision is not able to increase its service rates sufficiently to compensate for similar wage rate increases, its operating results may be adversely affected.
Although Precision, and prior to the Acquisition, Grey Wolf, have not historically encountered material difficulty in hiring and retaining qualified rig crews, shortages of qualified personnel have occurred in the past in its industry during periods of high demand. The demand for qualified rig personnel has increased as a result of overall stronger demand for land drilling services over the last few years. Management believes the demand for qualified rig personnel could increase further as new and refurbished rigs are brought into service by the Trust and its competitors.
Other factors may also inhibit the Trust’s ability to find enough workers to meet its employment needs. The work currently performed by the employees of the Trust requires skilled workers who can perform physically demanding work. As a result of that industry’s volatility and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with Precision’s. Management believes that its success is dependent upon its ability to continue to employ and retain skilled technical personnel and qualified rig personnel. The Trust’s inability to employ or retain skilled technical personnel and qualified rig personnel generally could have a material adverse effect on its operations.
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. 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.
The business of Precision is affected by governmental regulations and policies.
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 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.
Precision’s operations subject it to currency translation risk, which could cause results to fluctuate significantly from period to period.
Precision’s operations in the United States have revenue, expenses, assets and liabilities denominated in United States dollars. As a result Precision’s income statement, balance sheet and statement of cash flow are impacted by changes in exchange rates between Canadian and United States currencies.

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| • | Translation of United States Subsidiaries. Precision’s United States operations are considered self-sustaining operations and will be translated into Canadian dollars using the current rate method. Under this method, the assets and liabilities of Precision’s operations in the United States will be recorded in the consolidated financial statements at the exchange rate in effect at the balance sheet dates and the unrealized gains and losses will be included in other comprehensive income, a component of Unitholders’ equity. As a result, changes in the Canadian to United States dollar exchange rates will increase or decrease Precision’s United States dollar denominated net assets on consolidation which will increase or decrease Unitholders’ equity. The translation will increase and decrease Precision’s United States dollar assets and liabilities as a result of changes in foreign exchange rates which could have a material impact on the amounts recorded in the balance sheet. In addition, under certain circumstances Canadian GAAP requires foreign exchange gains and losses that are accumulated in other comprehensive income to be recorded as a foreign exchange gain or loss in the statement of earnings. Precision’s United States operations generate revenue and incur expenses in United States dollars and the United States dollar based earnings are converted into Canadian dollars for purposes of financial statement consolidation and reporting. The conversion of the United States dollar based revenue and expenses to a Canadian dollar basis does not result in a foreign exchange gain or loss but does result in lower or higher net earnings from United States operations than would have occurred had the exchange rate not changed. If the Canadian dollar strengthens versus the United States dollar, the Canadian dollar equivalent of net earnings from United States operations will be negatively impacted. Precision does not currently hedge any of its exposure related to the translation of United States dollar based earnings into Canadian dollars.
| • | Transaction Exposure. Precision has long-term debt denominated in United States dollars. This debt is converted at the exchange rate in effect at the balance sheet dates with the resulting gains or losses included in the statement of earnings as “foreign exchange”. If the Canadian dollar strengthens versus the United States dollar, Precision will incur a foreign exchange gain from the translation of this debt. Currently, Precision has not designated any of this debt as a hedge against the net asset position of its’ self-sustaining United States operations. The vast majority of Precision’s United States operations are transacted in United States dollars. Transactions for Precision’s Canadian operations are primarily transacted in Canadian dollars. However, Precision occasionally purchases goods and supplies in United States dollars. These transactions and foreign exchange exposure would not typically have a material impact on the Canadian operations’ financial results.

Poor safety performance could lead to a decline in the demand for services.
Standards for the prevention of incidents in the oil and gas industry are governed by service company safety policies and procedures, accepted industry safety practices, customer specific safety requirements, and health and safety legislation. Management believes that Precision’s drilling and well servicing businesses are highly competitive with numerous competitors. A key factor considered by Precision’s customers in selecting oilfield service providers is safety. Deterioration in Precision’s safety performance could result in a decline in the demand for Precision’s services and could have a material adverse effect on its revenues, cash flows, profitability and funds available for distributions.
There are risks associated with increased capital expenditures.
The timing and amount of capital expenditures incurred 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 can be 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.

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Compliance with various environmental laws, rules, legislation and guidelines could impose greater costs on Precision’s business or lead to a decline in the demand for services.
There is growing concern about the apparent connection between the burning of fossil fuels and climate change. The issue of energy and the environment has created intense public debate in Canada and around the world in recent years that is likely to continue for the foreseeable future and could potentially have a significant impact on all aspects of the economy including the demand for hydrocarbons and resulting in lower demand for Precision’s services.
Precision’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 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, prospects and funds available for distributions.
There are certain risks associated with Precision’s dependence on third-party suppliers.
Precision sources certain key rig components, raw materials, equipment and component parts from a variety of suppliers located in Canada, the United States and overseas. Precision also outsources some or all services for the construction of drilling and service rigs. While alternate suppliers exist for most of these components, materials, equipment, parts and services, cost increases, delays in delivery due to high activity or other unforeseen circumstances may be experienced. Precision maintains relationships with a number of key suppliers and contractors, maintains an inventory of key components, materials, equipment and parts and orders long lead time components in advance. However, if the current or alternate suppliers are unable to provide or deliver the necessary components, materials, equipment, parts and services, any resulting delays by Precision in the provision of services to its customers may have a material adverse effect on Precision’s business, results of operations, prospects and funds available for distributions.
The Trust and Precision may face potential unknown liabilities.
There may be unknown liabilities assumed by the Trust through its direct and indirect interests in Precision and its other operating subsidiaries (including the former Grey Wolf), 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 purchasers under the agreement dated September 13, 2005 between Precision and 1191678 Alberta Inc. 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.

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Precision is subject to various risks from its foreign operations.
Precision conducts a material portion of its business in the United States and is subject to risks inherent in such operations, such as: terrorist threats; fluctuations in currency and exchange controls; increases in duties and taxes; and changes in laws and policies governing operations. In addition, in the United States jurisdictions in which Precision operates, it is subject to various laws and regulations that govern the operation and taxation of its businesses in such jurisdictions and the imposition, application and interpretation of which laws and regulations can prove to be uncertain.
Precision’s operations face many risks of 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 and reservoir damage. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage, damage to the property of others and damage to producing or potentially productive oil and natural gas formations through which Precision drills. Generally, drilling and service rig contracts provide for the division of responsibilities between a drilling or service rig company and its customer, and Precision seeks to obtain indemnification from its customers by contract for certain of these risks. Precision also 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 United States and the severe hurricane damage in the United States Gulf Coast region in 2005, 2007 and 2008, all 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.
Risks Relating to the Acquisition
The Trust and its subsidiaries have incurred substantial debt in connection with the Acquisition, which could have a material adverse effect on its financial position and limit its future operations.
The Trust and its subsidiaries have a significant amount of debt as a result of the financing of the Acquisition. See “Description of the Business of Precision – Material Debt”. As of December 31, 2008, the Trust’s total outstanding long-term debt was $1,576.6 million.
The Trust’s substantial debt could have a material adverse effect on its financial condition and results of operations as well as on the distributions that the Trust may pay to Unitholders. In particular, it could:

| • | increase the Trust’s vulnerability to general adverse economic and industry conditions and require it to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of its cash flow to fund working capital, capital expenditures, acquisitions, other debt service requirements, distributions to Unitholders and other general corporate purposes;
| • | decrease the Trust’s ability to satisfy its obligations under the Credit Facilities or other indebtedness and, if the Trust fails to comply with these requirements, an event of default could result;
| • | increase the Trust’s vulnerability to covenants relating to its indebtedness which may limit the Trust’s ability to obtain additional financing for working capital, capital expenditures and other general corporate activities;

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| • | increase the Trust’s exposure to risks inherent in interest rate fluctuations and changes in credit ratings or statements from rating agencies because certain of its borrowings (including borrowings under the Credit Facilities) are at variable rates of interest, which would result in higher interest expense to the extent the Trust has not hedged these risks against increases in interest rates;
| • | increase the Trust’s exposure to exchange rate fluctuations because a change in the value of the Canadian dollar against the United States dollar will result in an increase or decrease in the Trust’s United States dollar denominated debt, as expressed in Canadian dollars, as well as in the related interest expense;
| • | increase the Trust’s vulnerability to covenants relating to its indebtedness that may limit the Trust’s flexibility in planning for, or reacting to, changes in its business or the industry in which it operates;
| • | place the Trust at a competitive disadvantage compared to its competitors that have less debt;
| • | limit the Trust’s ability to borrow additional funds to meet its operating expenses, to make acquisitions and for other purposes; and
| • | limit the Trust’s ability to construct, purchase or acquire new rigs.

The Trust and its subsidiaries may be able to incur substantial additional debt in the future, including additional secured debt pursuant to the Credit Facilities and under operating facilities. This could further exacerbate the risks associated with its substantial debt.
Precision will require significant amounts of cash to service indebtedness.
Precision will require significant amounts of cash in order to service and repay indebtedness. The ability to generate cash in the future will be, to a certain extent, subject to general economic, financial, competitive and other factors that may be beyond management’s control. In addition, the ability to borrow funds in the future to service debt will depend on covenants in the Credit Facilities and other debt agreements which may be entered into in the future. Future borrowings may not be available to the Trust or Precision under the Credit Facilities or from the capital markets in amounts sufficient to enable the Trust or Precision to pay obligations as they mature or to fund other liquidity needs (including the required repayments on the Unsecured Facility and the Secured Facility described under “Description of the Business of Precision – Material Debt”). If Precision is not able to obtain such borrowings or generate cash flow from operations in an amount sufficient to enable it to service and repay indebtedness, the Trust and Precision will need to refinance indebtedness or they will be in default under the agreements governing indebtedness. Such refinancing may not be available on favorable terms or at all. The inability to service, repay and/or refinance indebtedness could negatively impact the Trust’s financial condition and results of operations.
The Credit Facilities contain restrictive covenants.
Each of the Secured Facility and Unsecured Facility contains a number of covenants that, among other things, restrict, the Trust’s, Precision’s and their subsidiaries’ ability to conduct certain activities. See “Description of the Business of Precision – Material Debt”.
In addition, under the Secured Facility, Precision will be required to satisfy and maintain certain financial ratio tests, which ratios may be changed by the lenders in certain circumstances. Precision’s ability to meet such tests could be affected by events beyond its control, and Precision may not be able to meet such tests. A breach of any of these covenants could result in a default under the Secured Facility or Unsecured Facility. Upon the occurrence of an event of default under the Credit Facilities, the lenders could elect to declare all amounts outstanding under the Credit Facilities to be immediately due and payable and terminate all commitments to extend further credit. If Precision is unable to repay those amounts, the lenders under the Credit Facilities could proceed to foreclose or otherwise realize upon the collateral granted to them to secure that indebtedness. If the lenders under the Credit Facilities accelerate the repayment of borrowings, Precision may not have sufficient assets to repay the Credit Facilities as well as its unsecured indebtedness. The acceleration of indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross-default or cross-acceleration

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provisions. If indebtedness is accelerated, Precision may not be able to repay its indebtedness or borrow sufficient funds to refinance it. Even if Precision is able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable. The restrictions in the Credit Facilities may adversely affect the ability to finance future operations and capital needs and to pursue available business opportunities. Moreover, any new indebtedness incurred by Precision may impose financial restrictions and other covenants that may be more restrictive than the Credit Facilities.
The terms of Precision’s Credit Facilities may be amended by the lenders.
In order to complete a successful syndication of the Secured Facility, the Commitment Banks are entitled, prior to March 23, 2009 (extended at Precision’s option to May 22, 2009) in consultation with Precision, to change certain of the terms of the Credit Facilities including, without limitation, to implement additional increases in interest rates, original issue discounts and/or upfront fees, reallocate up to US$250 million between the Term Loan A Facility and the Term Loan B Facility (US$69 million (US$64 million on February 4, 2009 and US$5 million on March 26, 2009) of which has been reallocated from the Term Loan A Facility to the Term Loan B Facility as at March 27, 2009), reallocate up to US$150 million between the Secured Facility and the Unsecured Facility and amend certain covenants, financial ratio tests and other provisions for portions of the Secured Facility. Such changes may result in materially increased or accelerated debt service payments or debt repayments, reduce cash distributions that may be made by the Trust to Unitholders or otherwise materially adversely affect the financial position and operations of the Trust. In addition, adverse market conditions could result in higher than expected interest and/or original issue discount rates or subject the Trust to restrictive covenants that impose restrictions and limitations that are in addition to, or more restrictive than, those currently existing.
All the anticipated benefits of the Acquisition may not be realized.
The success of the Acquisition will depend, in part, on the ability of the Trust to achieve the anticipated strategic benefits from integrating the businesses of Grey Wolf into the Trust. Management expects the Trust to benefit from modest operational synergies resulting from the integration of the capabilities of Grey Wolf as well as greater efficiencies from increased scale. If the Trust is not able to achieve these objectives, the anticipated cost synergies and other strategic benefits of the Acquisition may not be realized fully or at all or may take longer to realize than expected. The Trust may fail to realize some or all of the anticipated benefits of the Acquisition in the amounts and times projected for a number of reasons, including that the integration may take longer than anticipated, be more costly than anticipated or have unanticipated adverse results relating to the Trust’s businesses. As a result of these factors, it is possible that the Trust will not achieve the anticipated operating synergies from the Acquisition.
Grey Wolf may not be integrated successfully.
Prior to the Acquisition, the Trust and Grey Wolf operated independently. As a result, the combined operation of the resulting entities from the Acquisition will present challenges to management, including the integration of the operations, systems, technologies and personnel of Grey Wolf, and special risks, including possible unanticipated liabilities, unanticipated costs, diversion of management’s attention, inconsistencies in standards, controls, procedures and policies, operational interruptions and the loss of key employees, customers or suppliers. The difficulties to be encountered in the transition and integration processes could have an adverse effect on the revenues, levels of expenses and operating results of the combined company. As a result, the Trust may not be able to successfully integrate Grey Wolf.
The Trust has incurred and will incur significant transaction, integration and restructuring costs in connection with the Acquisition.
Significant costs of approximately US$219.2 million (after accounting for applicable discounts), including a US$25 million break-up fee payable by Grey Wolf to a third party, debt issuance costs, professional services fees, severance costs and other costs were incurred in respect of the Acquisition. Additionally, the Trust will incur integration and restructuring costs as the business operations of Grey Wolf are integrated with the business of the Trust. Although it is expected that, over time, the realization of efficiencies related to such integration will offset

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incremental transaction, Acquisition-related and restructuring costs, this net benefit may not be achieved in the near term, or at all. This may result in unanticipated costs and other changes in future financial results.
PDOS, as the successor to Grey Wolf, is subject to litigation regarding the Acquisition.
The Trust’s subsidiary, PDOS, as successor to Grey Wolf, is subject to litigation arising from the Acquisition. A class action petition was filed alleging the Grey Wolf board of directors breached their fiduciary duties and Grey Wolf aided and abetted this breach. In March 2009, the court granted a motion to quash depositions requested by the Plaintiff and requested that a motion for summary judgment be filed and heard to determine as a matter of law whether there is a viable cause of action. In addition, two shareholders derivative actions were filed alleging that Grey Wolf and its board of directors breached their fiduciary duties and acted with negligence or gross negligence in failing to maximize shareholder value. The Plaintiff’s of the two derivative actions have agreed in principal to dismissals of their cases with prejudice and the parties are finalizing documents to present to the court.
The Trust maintains a level of insurance coverage deemed appropriate by management for matters for which insurance coverage can be acquired.
The Trust’s consolidated results of operations may be negatively impacted by foreign currency fluctuations.
A substantial portion of the Trust’s consolidated revenues following the Acquisition will be earned in non-Canadian currencies, primarily United States dollars. For purposes of financial reporting under Canadian GAAP, revenues and expenses denominated in non-Canadian currencies are translated into Canadian dollars at the average exchange rates prevailing during the year. It is expected that the Trust will continue to report its financial results in Canadian dollars. The revenues that are earned in currencies other than Canadian dollars are subject to unpredictable fluctuations if the values of non-Canadian currencies change relative to the Canadian dollar. Such fluctuations could decrease the Trust’s revenues earned in non-Canadian currencies and have a material adverse impact on its business and results of operations.

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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, 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.
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 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.
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.

| (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 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.

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(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. 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.
(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.
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:

• | the integrity of financial reporting to the holders of units of the Trust (“Unitholders”) and the investment community;
• | the integrity of the financial reporting process, including the audit process;
• | the Corporation’s and the Trust’s compliance with legal and regulatory requirements as they relate to financial reporting matters;
• | the external auditor’s qualifications and independence;
• | the integrity of the system of internal accounting and financial reporting controls implemented by management;
• | the work and performance of the Corporation’s and the Trust’s financial management, internal audit function and its external auditor; and
• | any other matter specifically delegated to the Committee by the Board of Directors.

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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;
• | 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;
• | 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;
• | 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 internal or the external auditor regarding financial reporting or the application of any accounting principles or practices;
• | require the external auditor and internal auditor to report directly to the Committee;
• | 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 non-audit services to the Corporation or any affiliated entities by the external auditor or any of their affiliates 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;
• | 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

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| analyses of the effects of alternative Canadian Generally Accepted Accounting Principles (“GAAP”) methods on the financial statements 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 the Trust’s response to that letter and other material written communication between the external auditor and management; (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; (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; (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; and (j) the use of any “pro forma” or “adjusted” information not in accordance with generally accepted accounting principles;

• | 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);
• | 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;
• | 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;
• | 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. Canadian Public Accountability Board or Public Company Accounting Oversight Board or other available 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, and (c) any steps taken to deal with any such issues;
• | evaluate the qualifications and performance of the external auditor, including a written review and evaluation of the lead partner of the external auditor, review and approve hiring policies for partners, employees or former employees of the external auditor 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;
• | review the independence of the external auditor, 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, and consider applicable auditor independence standards;

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• | 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 internal or 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;
• | 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;
• | 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 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;
• | 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;
• | meet in separate, non-management, in camera sessions at each regularly scheduled meeting;
• | meet in separate, non-management, closed sessions with any other internal personnel or outside advisors, as necessary or appropriate;
• | 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;
• | 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;

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| • | 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.
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 March 18, 2009.

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This Management’s Discussion and Analysis (“MD&A”), prepared as at March 23, 2009 focuses on the Consolidated Financial Statements, and pertains to known risks and uncertainties relating to the energy services sector. This discussion should not be considered all-inclusive, as it does not include all changes regarding general economic, political, governmental and environmental events. Additionally, other events may or may not occur which could affect Precision Drilling Trust (the “Trust” or “Precision”) in the future. In order to obtain an overall perspective, this discussion should be read in conjunction with the “Cautionary Statement Regarding Forward-Looking Information and Statements” on page 52 and the audited Consolidated Financial Statements and related notes. The effects on the Consolidated Financial Statements arising from differences in generally accepted accounting principles (“GAAP”) between Canada and the United States are described in Note 20 to the Consolidated Financial Statements. Additional information relating to the Trust, including the Annual Information Form, is available under our profile on the SEDAR website at www.sedar.com and on the EDGAR website at www.sec.gov.
2 MANAGEMENT’S DISCUSSION AND ANALYSIS

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FINANCIAL AND OPERATING HIGHLIGHTS
(Stated in thousands of Canadian dollars, except per unit amounts)

|  |  |  |  |  | % Increase |  |  |  |  |  |  |  | % Increase |  |  |  |  |  |  | % Increase |
Years ended December 31, |  | 2008 |  |  | (Decrease) |  |  |  | 2007 |  |  | (Decrease) |  |  | 2006 |  |  | (Decrease) |
Revenue |  | $ | 1,101,891 |  |  |  | 9.2 |  |  |  | $ | 1,009,201 |  |  |  | (29.8 | ) |  | $ | 1,437,584 |  |  |  | 13.3 |
EBITDA (1) |  |  | 436,536 |  |  |  | (0.1 | ) |  |  |  | 437,075 |  |  |  | (34.6 | ) |  |  | 668,160 |  |  |  | 24.4 |
Earnings from continuing operations |  |  | 302,730 |  |  |  | (11.7 | ) |  |  |  | 342,820 |  |  |  | (40.1 | ) |  |  | 572,512 |  |  |  | 159.2 |
Discontinued operations, net of tax (2) |  |  | — |  |  |  | n/m |  |  |  |  | 2,956 |  |  |  | n/m |  |  |  | 7,077 |  |  |  | n/m |
Net earnings |  |  | 302,730 |  |  |  | (12.4 | ) |  |  |  | 345,776 |  |  |  | (40.3 | ) |  |  | 579,589 |  |  |  | (64.5 | )
Cash provided by continuing operations |  |  | 343,910 |  |  |  | (29.0 | ) |  |  |  | 484,115 |  |  |  | (20.6 | ) |  |  | 609,744 |  |  |  | 196.0 |
Net capital spending (3) |  |  | 219,139 |  |  |  | 20.9 |  |  |  |  | 181,239 |  |  |  | (22.4 | ) |  |  | 233,693 |  |  |  | 66.8 |
Distributions declared — cash |  |  | 200,659 |  |  |  | (18.6 | ) |  |  |  | 246,485 |  |  |  | (44.9 | ) |  |  | 447,001 |  |  |  | n/m |
Distributions declared — in-kind |  |  | 24,029 |  |  |  | (20.4 | ) |  |  |  | 30,182 |  |  |  | 23.1 |  |  |  | 24,523 |  |  |  | n/m |
Earnings per unit from continuing operations: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  | 2.39 |  |  |  | (12.5 | ) |  |  |  | 2.73 |  |  |  | (40.1 | ) |  |  | 4.56 |  |  |  | 154.7 |
Diluted |  |  | 2.39 |  |  |  | (12.5 | ) |  |  |  | 2.73 |  |  |  | (40.1 | ) |  |  | 4.56 |  |  |  | 159.1 |
Earnings per unit: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  | 2.39 |  |  |  | (13.1 | ) |  |  |  | 2.75 |  |  |  | (40.5 | ) |  |  | 4.62 |  |  |  | (65.1 | )
Diluted |  |  | 2.39 |  |  |  | (13.1 | ) |  |  |  | 2.75 |  |  |  | (40.5 | ) |  |  | 4.62 |  |  |  | (64.5 | )
Distributions declared per unit — cash |  |  | 1.56 |  |  |  | (20.4 | ) |  |  |  | 1.96 |  |  |  | (44.9 | ) |  |  | 3.56 |  |  |  | n/m |
Distributions declared per unit — in-kind |  |  | 0.15 |  |  |  | (37.5 | ) |  |  |  | 0.24 |  |  |  | 23.1 |  |  |  | 0.195 |  |  |  | n/m |
Drilling rig utilization days: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Canada |  |  | 34,488 |  |  |  | (0.2 | ) |  |  |  | 34,572 |  |  |  | (32.3 | ) |  |  | 51,050 |  |  |  | (4.9 | )
United States |  |  | 8,006 |  |  |  | 281.6 |  |  |  |  | 2,098 |  |  |  | 1,034.1 |  |  |  | 185 |  |  |  | n/m |
International |  |  | 159 |  |  |  | n/m |  |  |  |  | — |  |  |  | n/m |  |  |  | — |  |  |  | n/m |
Service rig operating hours: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Canada |  |  | 335,127 |  |  |  | (5.9 | ) |  |  |  | 355,997 |  |  |  | (25.9 | ) |  |  | 480,137 |  |  |  | 0.6 |

(1) |  | Non-GAAP measure. See page 50.
(2) |  | Includes gain on disposition of discontinued operations.
(3) |  | Excludes acquisitions.
n/m — calculation not meaningful.

FINANCIAL POSITION AND RATIOS
(Stated in thousands of Canadian dollars, except ratios)

Years ended December 31, |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Working capital |  | $ | 345,329 |  |  |  | $ | 140,374 |  |  | $ | 166,484 |
Working capital ratio |  |  | 2.0 |  |  |  |  | 2.1 |  |  |  | 1.8 |
Long-term debt (1) |  | $ | 1,368,349 |  |  |  | $ | 119,826 |  |  | $ | 140,880 |
Total long-term financial liabilities |  | $ | 1,399,300 |  |  |  | $ | 133,722 |  |  | $ | 163,579 |
Total assets |  | $ | 4,833,702 |  |  |  | $ | 1,763,477 |  |  | $ | 1,761,186 |
Enterprise value (2) |  | $ | 2,636,170 |  |  |  | $ | 1,877,139 |  |  | $ | 3,369,860 |
Long-term debt to long-term debt plus equity (1) |  |  | 0.37 |  |  |  |  | 0.08 |  |  |  | 0.10 |
Long-term debt to cash provided by continuing operations (1) |  |  | 3.98 |  |  |  |  | 0.25 |  |  |  | 0.23 |
Long-term debt to enterprise value (1) |  |  | 0.52 |  |  |  |  | 0.06 |  |  |  | 0.04 |

(1) |  | Excludes current portion of long-term debt which is included in working capital.
(2) |  | Unit price as at December 31 multiplied by the number of units outstanding plus long-term debt minus working capital. See page 36.

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PROFILE AND STRATEGY
For Precision, 2008 was a transformation year to become the second largest land driller in North America with drilling rigs operating in virtually every emerging unconventional gas basin. With the December 23, 2008 acquisition of Grey Wolf, Inc. (“Grey Wolf”), Precision operated 374 land rigs, 229 service rigs and 100 camps along with catering, rental, snubbing and wastewater services.
The Canadian drilling and services market opened 2008 overshadowed by royalty changes, strong Canadian currency and a general reluctance by Canadian exploration and production (“E&P”) companies to spend their drilling budgets in Alberta. Many of the Canadian E&P companies with international operations focused their spending outside Canada. Precision accelerated its growth and diversification strategy moving 17 rigs to the United States over the course of 2008 where strengthening natural gas prices in the first half of the year resulted in higher producer spending. Precision’s high performance high value strategy was well received by customers but with the highly risk-adverse and relationship-based nature of the oilfield services sector this growth would have finite limits. Grey Wolf, Inc., with 123 rigs in seven key oil and natural gas basins, approximately 3,000 experienced personnel and a customer list exceeding 200 proved to be an excellent fit. The acquisition also provided a two rig operation in Mexico and resources from which to launch global growth.
The acquisition of Grey Wolf provides value, diversification and growth.

1. |  | Value lives in high performing assets, people and technology, as evidenced by strong margins and sector leading rig utilization for a heritage rig fleet. The senior management team has global experience and is positioned to enhance Precision’s existing 29 rig operation in the United States. Precision’s in-house supply, manufacturing and support systems provide levers to increase profit margins.

2. |  | Diversification was immediate with contracted drilling rigs strategically positioned in key oil and natural gas basins, especially unconventional resource plays. The customer mix was broad and provides immediate relationships to market Precision’s rig technology and other services.

3. |  | Growth was delivered through people and assets. The combination of new and upgraded rigs with an experienced workforce provides added capacity to leverage favourable long-term drilling industry fundamentals, technologically advanced rigs suited for unconventional plays, history of successful acquisition integrations and a larger platform to apply directional drilling integration.

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Late in the year, the global economic slowdown significantly lowered commodity prices and a reduction in customer spending caused a sharp reduction in drilling and well servicing activity. The industry slowdown combined with higher than anticipated total cost of debt for Precision has created financial challenges.
Precision’s commitment to the long-term strategic importance of the Grey Wolf acquisition remains strong. However, given the rapid and unprecedented disruptions in the capital markets the cost of financing this transaction is higher than anticipated and challenges remain as the underwriter banks move to fully syndicate the debt structure. While the transaction is funded, credit facilities are placed and the unsecured facility (sometimes referred to as a bridge loan) automatically converts to term notes, there remains cost of financing uncertainty that has carried forward from closing. The aggregate credit facility cost of financing had an effective blended cash interest rate of 11%, and a debt to capitalization ratio of 0.37, both higher than management desires. The cost of the effective interest rate may be subject to further increases depending on the success of syndication and certain debt market indices.
Precision’s key priorities for 2009 are the resolution of this finance pricing uncertainty through capital structure planning and debt reduction. These balance sheet priorities are complemented by the successful integration of Grey Wolf and execution of the 2009 business plan.
Precision was able to succeed on many of its 2008 initiatives through its strategy of combining the best people, with the best systems and best technology, including:

• |  | Reducing dependence on underlying economics and seasonality of the relatively mature western Canada sedimentary basin;

• |  | Capitalizing on customer production growth in North America, especially unconventional natural gas wells;

• |  | Pursuing global oil drilling opportunities; and

• |  | Achieving greater high performance high value services through investment in new asset technology and acquisition opportunities to establish market positioning that consolidates industry and provides profit margin improvement through people, technology and systems initiatives.

As a large North American oilfield service provider with diverse operations and two business segments, Contract Drilling Services and Completion and Production Services, Precision holds about 26% of the onshore drilling rig market in Canada, about 7% in the United States and about 20% of the Canadian service rig market. In addition, Precision has a substantial Canadian market presence in the camp and catering, snubbing, equipment rental and wastewater treatment business lines. Precision now operates one of the largest onshore drilling rig fleets in the world which, on December 31, 2008, was comprised of a global drilling fleet of 374 rigs with 220 in Canada, 151 in the United States, two in Mexico and one in Chile.
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KEY RESOURCES AND COMPETENCIES
The acquisition of Grey Wolf was the primary reason for the 2008 increase in long-term debt of $1.25 billion and a reported balance, net of unamortized debt issue costs of $159 million, as of December 31, 2008 of $1.37 billion.
Historic Levels of Long-term Debt
In conjunction with the acquisition of Grey Wolf, Precision entered into a new US$1.6 billion dollar credit facility. The facility has funded the acquisition of Grey Wolf, is available to repay Grey Wolf convertible notes and provides ample liquidity at December 31, 2008 to fund ongoing operational and investment activities.
During the fourth quarter of 2008 the severity of the global financial crisis led to a significant contraction in global debt and equity financing capability. In turn, these conditions led to a rapid decline in consumer confidence and major economies around the world, including the United States and Europe. The resulting demand uncertainty and expectations for reduced energy consumption significantly lowered oil and natural gas commodity prices and cast a negative near term outlook on the oilfield services sector. While many governments have taken measures to inject capital and confidence in their banking systems, there remains an acute undersupply of capital for debt financings. Accordingly, the scarcity of debt financing resulted in higher debt service costs for Precision, risk rated for industry and credit quality, even though government treasury rates in many countries are at historic lows.
Given this current set of circumstances, Precision acted decisively to strengthen its capability to reduce long-term debt and improve its underlying credit quality and capital structure:

• |  | 2009 compensation restructuring to freeze employee pay and reduce salaried positions. Also for 2008, the Chief Executive Officer has agreed to forego certain incentive bonus obligations due under his employment contract and the Chief Financial Officer agreed to a reduced 2008 incentive bonus remuneration;

• |  | 2009 capital expenditures on existing equipment have been reduced to a level that will maintain the safety and overall performance of assets;

• |  | During 2008 and 2009, cost reduction measures have been taken to reduce the salaried workforce, reduce employee travel, consolidate operating and administrative locations, lower certain field wages and optimize supplier relationships;

• |  | Future expansion capital expenditures have been reduced to amounts required to complete the 2008 Super Series™ rig programs pursuant to term customer contracts;

• |  | In February 2009, the Trust announced the indefinite suspension of cash distributions;

• |  | A US$800 million base shelf prospectus was filed with regulatory authorities in February 2009 to facilitate the possible issuance of debt or equity securities over the following 25 month period;

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• |  | Gross proceeds of US$172.5 million were raised through an equity offering of 46 million units of the Trust during February 2009; and

• |  | Management continues to seek permanent pricing for certain remaining debt within its credit facilities. Provisions exist for the commitment banks to facilitate syndication for a period following the Grey Wolf acquisition which may result in further increases in any or a combination of interest rates, original issue discounts or fees, all subject to certain market based indexing.

Precision strengthened its capabilities through management and board of director appointments during the year. During 2008 Precision had full retention of senior management and executive officers and complemented growth during the year with certain new hires and appointments. The management appointments add to existing international and oilfield service expertise and bring new exploration and production business insight.
During 2008 Precision Drilling Corporation appointed four new officers:

• |  | Joanne L. Alexander, Vice President, General Counsel and Corporate Secretary, industry experience from 1990;

• |  | Kenneth J. Haddad, Vice President, Business Development, industry experience from 1981;

• |  | David J. Crowley, President U.S. Operations, former Grey Wolf Chief Operating Officer, industry experience from 1980; and

• |  | David W. Wehlmann, Executive Vice President, Investor Relations, former Grey Wolf Chief Financial Officer, industry experience from 1980.

During 2008 Precision Drilling Corporation appointed three additional directors, Frank M. Brown, William T. Donovan and Trevor M. Turbidy, all formerly directors of Grey Wolf. As a group these appointments provide particular expertise in the areas of finance and United States oilfield services.
SUMMARY OF CONSOLIDATED STATEMENTS OF EARNINGS
(Stated in thousands of Canadian dollars)

Years ended December 31, |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Revenue: |  |  |  |  |  |  |  |  |  |  |  |  |
Contract Drilling Services |  | $ | 809,317 |  |  |  | $ | 694,340 |  |  | $ | 1,009,821 |
Completion and Production Services |  |  | 308,624 |  |  |  |  | 327,471 |  |  |  | 441,017 |
Inter-segment elimination |  |  | (16,050 | ) |  |  |  | (12,610 | ) |  |  | (13,254 | )
|  |  | 1,101,891 |  |  |  |  | 1,009,201 |  |  |  | 1,437,584 |
EBITDA: (1) |  |  |  |  |  |  |  |  |  |  |  |  |
Contract Drilling Services |  |  | 359,137 |  |  |  |  | 329,351 |  |  |  | 511,883 |
Completion and Production Services |  |  | 109,054 |  |  |  |  | 132,030 |  |  |  | 195,173 |
Corporate and Other |  |  | (31,655 | ) |  |  |  | (24,306 | ) |  |  | (38,896 | )
|  |  | 436,536 |  |  |  |  | 437,075 |  |  |  | 668,160 |
Depreciation |  |  | 83,829 |  |  |  |  | 78,326 |  |  |  | 73,234 |
Foreign exchange |  |  | (2,041 | ) |  |  |  | 2,398 |  |  |  | (353 | )
Interest, net |  |  | 14,174 |  |  |  |  | 7,318 |  |  |  | 8,029 |
Other |  |  | — |  |  |  |  | — |  |  |  | (408 | )
Earnings from continuing operations before income taxes |  | 340,574 |  |  |  |  | 349,033 |  |  |  | 587,658 |
Income taxes |  |  | 37,844 |  |  |  |  | 6,213 |  |  |  | 15,146 |
Earnings from continuing operations |  |  | 302,730 |  |  |  |  | 342,820 |  |  |  | 572,512 |
Discontinued operations, net of tax |  |  | — |  |  |  |  | 2,956 |  |  |  | 7,077 |
Net earnings |  | $ | 302,730 |  |  |  | $ | 345,776 |  |  | $ | 579,589 |

(1) |  | Non-GAAP measure. See page 50.

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Revenue and EBITDA(1)

(1) |  | Non-GAAP measure. See page 50.

Capital Spending — Total
For the year ended December 31, 2008 Precision’s earnings from continuing operations was $303 million or $2.39 per diluted unit compared to $343 million or $2.73 per diluted unit in 2007. The decrease of $0.34 per diluted unit was due to lower activity and pricing for Precision’s Canadian services in the first half of 2008 relative to 2007 and higher 2008 income tax expense partially mitigated by higher earnings from contract drilling growth in the United States. The decline in the first half of 2008 in Canada was driven by capital planning by customers late in 2007, when natural gas prices were unfavourable and industry economics were hindered by royalty changes announced by the government of Alberta. As commodity prices strengthened in 2008, customers responded by increasing budgets with particular emphasis in British Columbia and Saskatchewan. In 2007, Precision benefitted from a future income tax recovery of $22 million due to enacted Canadian federal tax rate reductions.
West Texas Intermediate (“WTI”) crude oil averaged US$99.67 per barrel in 2008 versus US$72.45 in 2007 and Henry Hub natural gas averaged US$8.84 per MMBtu in 2008 versus US$6.94 in 2007. On Canadian markets the average price for AECO natural gas one-year forward was $8.74 per MMBtu in 2008 compared to $7.50 in 2007. However, commodity prices deteriorated quickly in late 2008 and early 2009 to an average Henry Hub natural gas price of US$4.88 and an average WTI price of US$40.64 for the period of January 1, 2009 to February 28, 2009.
Currency exchange rates can impact commodity prices and have always had an impact on industry fundamentals in the Canadian market. For Precision, this continues and with a significant portion of long-term debt as of December 23, 2008 denominated in United States currency, exchange rate fluctuations to Precision’s Canadian dollar reporting currency and the impact on financial results and credit facility financial covenants will take on additional importance going forward. During the second half of 2008, a stronger United States dollar led to a weakening of 17% for the Canadian dollar.
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During 2008 there were 16,812 wells drilled in western Canada on a rig release basis, an 8% decline from the 18,342 drilled in 2007. Although the industry experienced a decrease in wells drilled total industry drilling operating days increased by 12% to 134,835 as a result of the mix of wells drilled. The average industry drilling operating days per well in 2008 was 8.0 days compared to 6.6 days in 2007.
In 2008, higher oil and natural gas prices mid-way through the year prompted many customers to increase their drilling programs. In the western Canada sedimentary basin (“WCSB”) the total number of well licenses issued for oil targets was 8,275 which represented an 11% increase over 2007 and 41% of the total licenses issued compared to 37% in 2007. Well licenses for natural gas prospects declined 5% in 2008 to 12,082. In the United States the active drilling rig count peaked during the third quarter of 2008 at over 2,000 rigs.
OUTLOOK
While energy fundamentals always carry a degree of uncertainty, the global economic recession and impact from the financial crisis has reduced both our customers’ access to capital and their desire for drilling and well service programs. Hence, the level of uncertainty for 2009 is higher than previous years. In the challenging economic environment of 2009, Precision expects demand for its drilling services to decline in the short term. Precision expects EBITDA as a percentage of revenue and its gross margin to decline and remain at lower levels for much of 2009. However, Precision’s term customer contracts provide a noteworthy degree of profit margin support.
Onshore drilling rigs go to work for customers under contracts that vary in duration, from one-well programs to multi-well programs under near term or spot market pricing or under long-term contracts whereby pricing is established from the outset and the customer has the right to work the rig for a set time period. For 2009, Precision has a solid long-term contracted position and expects to have an average of approximately 102 rigs working under long-term contracts in North America in the first quarter of 2009 and an average of approximately 93 rigs contracted for the second quarter of 2009. For the entire year, Precision expects to have an average of approximately 85 rigs working under long-term contracts, including 53 rigs on average in the United States, 30 on average in Canada and two in Mexico.
As part of an ongoing debt reduction plan, Precision expects to keep capital expenditures at low levels. Precision expects to spend approximately $207 million in capital expenditures for 2009, with approximately $40 million being for upgrade capital and $167 million being for previously committed expansion capital. The expansion capital is for 16 new rigs to be placed into service in 2009 to complete the 2008 new build program. All 16 of these rigs are included in the total term contracted rigs described above.
The combination of weak equity and debt markets, lower commodity prices as well as higher long-term royalty programs in Alberta have caused many customers to reduce their drilling budgets. Precision’s operations in Canada during the first quarter of 2009, as well as industry, have had the lowest first quarter activity levels in over 10 years. Beyond the first quarter, activity is less clear and will be largely dependent on North American natural gas pricing and the availability of capital for customers.
The active rig count is a direct indication of activity levels for exploration and production of oil and natural gas. Rig counts in North America are at reduced levels not seen since 2004 in the United States and 1999 in Canada and continue to deteriorate. This deterioration has put pricing pressure on the spot market and has greatly reduced new term contract opportunities.
During the first two months of 2009, natural gas prices have declined approximately 30%. Natural gas storage levels were approximately 14% above the five-year average as withdrawals are below average levels despite a relatively cold winter in North America. The view that North America has an oversupply of natural gas has driven gas prices lower. The recent increase in United States natural gas production, concerns over industrial gas consumption and the prospect of higher liquefied natural gas (“LNG”) imports has overshadowed lower Canadian imports and the drop in active North American drilling rig count. Subject to demand clarity and LNG imports, we anticipate the supply decline from reduced drilling may begin to outpace demand reductions later in 2009, providing the catalyst for improved fundamentals to support a recovery in drilling activity.
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U.S. Working Gas in Underground Storage Compared with Five-year Range
Despite current near-term industry activity uncertainty, Precision has long-term growth opportunities in North America. Over the past couple of years, through advancements in hydraulic fracturing and directional drilling, the industry has undergone a noteworthy shift from conventional resource plays to unconventional resource plays. This is evidenced by United States natural gas production growth from unconventional resource plays and the rising trend in directional and horizontal well programs.
Unconventional resource plays represent the greatest short-term solution to sustain North America production. The resource plays are characterized by high initial production rates that can payout the customer’s initial investment in a relatively short time. These wells have steep first year decline rates in the range of 50% — 80%. Given their steep early declines, a greater number or higher density of wells are required to efficiently exploit the resource potential. The nature of this production profile presents tremendous upside to drilling contractors. These wells are expensive and technically challenging to drill. Customers who drill these well programs require high-performing drilling rigs and thus recognize Precision’s high performance high value advantage.
U.S. Natural Gas Production and Decline Rate
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Precision believes it is well positioned with the rig fleet, experience and customer relationships for active participation in North America’s resource play development. In Canada, there are three major areas that are considered unconventional resource plays; the shale gas plays in Northeastern British Columbia (Montney and Horn River), the Bakken shale in southern Saskatchewan, and the heavy oil/oilsands in northeastern Alberta. In the United States there are several unconventional resource plays. The three resource plays that present excellent growth potential for Precision are the Haynesville play in Texas/Louisiana, the Marcellus play in New York/Pennsylvania and the Bakken oil shale in North Dakota. Precision’s geographic footprint coupled with application of know-how and experience applicable in these areas provide a significant competitive advantage.
For Precision, international expansion slowed due to lower customer demand from commodity declines. Precision will manage through these conditions and focus on prospects requiring minimal capital investment that provide term contracts in regions that match our strategic goals.
With the expiry of non-competition restrictions during 2008, Precision is now in position to offer customer savings on directional drilling services. Precision’s directional drilling operation commenced in the first quarter of 2009, supporting Precision’s high performance high value strategy to lower customer well costs. A high percentage of Precision’s drilling rigs are used on complex wells that require these services and this provides immediate customer access. The rising industry trend toward directional and horizontal well programs coupled with the high cost of directional field personnel provides an opportunity for Precision to successfully compete in this market. Precision expects to offer this service in both Canada and the United States.
Despite near-term challenges, the future of the global oil and gas industry remains promising. Compared to prior low-cycle troughs, there is marginal excess supply of oil and natural gas on a global basis and short-term oversupply conditions are balanced through lower industry investment in combination with higher well depletion rates. While current economic conditions have led to a recession in many countries, Precision believes that these mechanisms eventually reduce supply sufficiently to provide the impetus for a sustained recovery in drilling and well servicing activity. In the near term, fiscal 2009 has begun in sharp contrast to the high commodity prices of mid-2008 and will be a financial challenge for Precision and its customers. These difficult economic conditions represent continuing opportunity to demonstrate customer value through delivery of high performance high value services that lower well costs.
Precision converted to an income trust in 2005 as the tax rules of the day allowed the market to place a higher value for unitholders on the flow-through structure than the traditional corporate structure. In light of legislated and proposed changes, the sector outlook and resulting financial operating performance and loan covenants the Trust continues to examine whether the current structure is optimal for Precision’s business strategy and in the best interests of unitholders.
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Through this report, management is presenting its views of Precision’s business and the dynamic industry in which it operates. Understanding the oil and gas industry and the factors that impact demand for oilfield services is important to assess risk factors that affect Precision’s long-term strategy and financial performance.
GLOBAL MARKETS
Global economic growth and prosperity drives energy consumption. Crude oil and to a lesser extent natural gas are the most dominant and versatile sources of energy in developed countries while crude oil and coal are the dominant sources of energy in developing countries. Oil and its by-products are currently the most important fuel for the transportation industry as there are few alternatives that can compete economically. Oil and natural gas are major fuel sources for generating heat and electricity and are critical building blocks for countless consumer products.
The impact of global economic recessionary forces resulting from the current global credit crisis has led to a curtailment of near-term global energy demand. As a result, there has been a significant decline in energy prices and capital investment directed towards energy resources while the global energy supply/demand balance realigns in response to near-term global economic conditions. Despite the near-term reductions in supply and demand the worldwide population continues to grow and is expected to rise 1.1% per year fueling a rising global energy demand into the future. From a reference year of 2005, energy consumption is projected by the United States government Energy Information Administration (“EIA”) to increase 50% by 2030 with oil, natural gas and coal meeting approximately 86% of global demand. World oil consumption is predicted to rise about 1.2% per year during this period due largely to growing demand in China, India and other developing countries. Delivering reliable and affordable energy for these fast-growing and upwardly mobile populations is a major challenge in this century with security of supply becoming a dominant theme globally. The EIA is forecasting natural gas consumption increases of 1.7% on average per annum to 2030 as rising oil prices increase the demand for natural gas as an alternative fuel in industrial and electrical sectors in developed and developing economies.
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NORTH AMERICAN MARKETS
The economics of the oilfield service industry are aligned with global and regional fundamentals. Important regional drivers for the industry in North America include the underlying hydrocarbon make-up of the various basins and the existence of established, competitive and efficient service infrastructure. With high service costs per barrel of oil equivalent production in Canada and increased pipeline takeaway capacity within the United States, capital allocation by customers has increasingly favoured unconventional natural gas basins in the United States.
The hydrocarbon basins of North America are diverse and conventional oil and natural gas reservoirs exist at a variety of depths. These conventional sources are complemented by more costly and challenging unconventional reservoirs associated with oil sands, heavy oil, natural gas in coal and in shale and in deeper, low permeability formations. About 70% of the proven natural gas reserves in North America are situated in the United States with the remaining 30% in Canada. In 2008, about 80% of drilling activity in the United States and 60% in Canada targeted natural gas.
The emergence of LNG as a fungible commodity is an important future source of supply to North America that could offset production declines from mature reservoirs and help meet future natural gas demand. There are still technical, political and environmental challenges for significant LNG developments to occur in North America, but it is believed to be a necessary source of supply as demand for natural gas increases. Less than 5% of the world’s proven reserves of natural gas exist in North America yet more than 25% of worldwide natural gas consumption occurs in North America.
Global LNG capacity continues to rise and as the price differential of LNG to North American produced gas narrows, the likelihood for higher LNG imports to the United States increases. Currently the differential to North American natural gas prices is narrow and the opportunity for higher LNG imports during 2009 has increased. The LNG market is developing and has shown that supply moves to high priced markets, such as Europe and Asia, subject to demand fluctuations.
With next-door proximity to the world’s biggest energy consumer Canada has become the world’s seventh largest oil producer and third largest producer of natural gas. With oil sands development, Canada is one of the few countries with growing oil production. A highly integrated continental energy transportation system, security of supply and access to United States markets has made Canada one of the largest energy providers to the United States. Currently, just over half of Canadian oil and natural gas production is exported to the United States.
WCSB Natural Gas Production
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ECONOMIC DRIVERS OF THE OILFIELD SERVICES INDUSTRY
Providing oil and natural gas products to consumers involves a number of players, each taking on different risks in the exploration, production, refining and distribution processes. Exploration and production companies, Precision’s customers, assume the risk of finding hydrocarbons in reservoirs of sufficient size to economically develop and produce. The economics are dictated by the current and expected future margin between the cost to find and develop hydrocarbons and the eventual price of these products. The wider the margin, the greater the incentive to undertake these risks.
Exploration and development activities include acquiring access to prospective lands, seismic surveying to detect hydrocarbon bearing structures, drilling wells and completing successful wells for production. Exploration and production companies hire oilfield service companies to perform the majority of these tasks. The revenue of an oilfield service company is part of the finding and development costs for an exploration and production company.
Number of Producing Wells in Western Canada
The economics of an oilfield service company are largely driven by the price of crude oil and natural gas realized by its customers. Since oil can be transported relatively easily, it is priced in a global market influenced by an array of economic and political factors. Natural gas is priced in continental markets with supply from LNG a growing factor subject to availability.
From a long-term perspective, there is a narrowing supply-demand balance for natural gas in North America. Many industry observers believe a new pricing floor may be set through industry cycles due to the combination of production declines and demand growth. Recent cycles support this thesis with commodity prices generally trending at higher levels than previously encountered. New hydrocarbon reserves are clearly more costly and difficult to discover and develop and it is becoming increasingly necessary to use high-performance drilling rigs and support services to complete well programs. It has taken record drilling activity over most of the last three years in North America to marginally increase overall natural gas production levels. To a large extent this production growth has been derived from unconventional production with significant first-year decline rates.
With the ongoing depletion of conventional resource basins there has been a continued shift in the oil and natural gas industry in North America to develop unconventional resources such as oil sands, natural gas in shale and in coal and in deeper, low permeability formations. The economics of unconventional resource plays are enhanced by technology such as multi-well pad locations, high-performance drilling rigs and advanced reservoir stimulation techniques.
Reserves to production ratios, which indicate how quickly reserves are depleting, have flattened after a period of decline starting in the 1990s. The decline implies that drilling activity must stay level or increase just to maintain current production and producers may need to drill deeper, more remote resource plays to secure large gas fields and extend reserve life.
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WCSB Well Completions vs AECO Spot Natural Gas Price
The graph above compares WCSB well completions and natural gas pricing over the past 10 years. The long-term trend towards higher natural gas prices and increased natural gas well drilling has been suppressed over the past 18 months due primarily to less shallow gas well activity as a result of Alberta government royalty changes. The average natural gas price in 2008 increased as gas storage declined. However, prices closed the year much lower as storage increased and demand uncertainty rose with deteriorating economic conditions in North America.
With growing energy demand, the supply of drilling rigs in Canada increased steadily over the past 14 years from about 450 rigs to an all-time high of about 900 in 2007 and about 850 currently. Customer demand, measured by annual drilling rig operating day utilization, peaked at 71% in 1997 and has since ranged between 38% and 60%. Industry utilization for 2008 was 41%. The current excess drilling rig capacity in Canada has prompted some oilfield service providers to relocate certain assets in their drilling fleets to the United States land drilling market. As illustrated below, Canadian rig activity fluctuates with the seasons, an event which generally does not occur in the United States except in northern states.
Active and Existing Canadian Drilling Rigs
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The United States active drilling rig count steadily increased from about 800 rigs in 2002 to a peak of just over 2,000 rigs in 2008 before falling to about 1,700 rigs by the end of 2008.
Precision estimates that during peak activity in the fourth quarter of 2008 about 1,200 active drilling rigs in the United States fleet were constructed prior to 1990 and underperform when tasked with drilling unconventional complex resource plays. With increased exploitation of unconventional resource basins and the increases in directional and horizontal drilling the demand for high performing rigs and crews capturing premium pricing continues to grow, displacing the underperforming rigs.
Diversification: Unconventional Resource Coverage
The trend toward horizontal and directional well programs has increased with technological and process improvements that have led to higher production, especially in unconventional resource plays. As depicted in the above map of North America, Precision’s drilling rig fleet is positioned in virtually every resource play from northern Canada to the southern United States.
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HISTORY OF CONTINUING OPERATIONS
Precision began operating in western Canada as a land drilling contractor in the 1950s. A combination of new equipment purchases and acquisitions over the last 20 years has expanded fleet capacity and added complementary businesses. For the past decade, Precision has been Canada’s largest oilfield services provider with an increasing presence in the United States since 2006 and is now a large North American oilfield service provider.
Precision has a vertical business model that provides customers with a diverse range of services for the well location. Business lines are organized in two segments to align with the dynamics of customer markets and processes. This encompasses the initial drilling of oil and natural gas wells, Contract Drilling Services, and the subsequent completion and workover of wells to optimize production volumes, Completion and Production Services. These segments have been integrated with internal support infrastructure to optimize customer service delivery and lower costs.
Precision has a supply procurement and distribution division that supports rig operations and all other Precision businesses. This division serves to efficiently handle a high volume of transactions and channel supplier relationships to enhance product quality selection and standardization. Information system automation has streamlined the procurement, supply distribution and decision making process. The support is an integral element in Precision’s Canadian operations and is in the process of being replicated in support of contract drilling operations in the United States.
Precision also has an equipment manufacturing, repair and certification division that supports rig operations. This division provides rig manufacturing capabilities and engineering to facilitate new rig construction and the upkeep of operating assets. Specialized machining, skilled tradesmen and management has allowed Precision to optimize its capital allocation through quality workmanship, project planning, retention of intellectual property and cost savings.
Precision’s supply and manufacturing businesses preserve a small amount of capacity to generate sales with third party customers and maintain industry connectivity for trends, pricing and high-performance benchmarks. These capabilities provide Precision with a capital cost advantage in the manufacture of new Super Series™ rigs.
Precision’s vertical integration is further complemented by rig manufacturing engineering in the drilling division. Rigs built by Precision are designed for greater safety and operating efficiency to deliver well cost savings to customers. High-performance drilling rigs combine high mobility, automated pipe handling, advanced control systems, minimal environmental impact, and highly trained crews. Over the past 13 years Precision has been developing the Super Series™ drilling rigs and has built 40 Super Single™, seven Super Single™ Light and ten Super Triple rigs. Precision also manufactured ten freestanding mobile single and six slant service rigs.
PRECISION DRILLING TRUST 17

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Contract Drilling Services Segment
Precision’s Contract Drilling Services are known within the industry as a part of the upstream sector with operations at the well location to facilitate the drilling of natural gas, oil and, in rare circumstances, geothermal wells. It is the underlying well program requirements that determine which rig is best suited to drill a particular prospect for customers.
Precision’s development was founded on the successful integration of acquisitions. In the decade following a 1987 reverse takeover, a series of acquisitions expanded Precision’s Canadian drilling fleet from four to 106 rigs. With the acquisition of Kenting Energy Services Inc. in 1997, Precision essentially doubled its fleet to 200 rigs representing approximately 40% of the drilling fleet in Canada. The acquisitions of coil tubing drilling rigs and other shallow drilling rigs in 2000 rounded out the acquisition history for Precision’s rig fleet in Canada.
The acquisition of Grey Wolf has accelerated Precision’s presence in the United States market and 2008 ended with Precision having 220 drilling rigs in Canada (comprising 25% of the Canadian market), 151 rigs in the United States (comprising about 7% of the U.S. market), one rig in Chile and two rigs in Mexico. Precision will seek new global opportunities which exploit Precision’s high performance high value services.
To better operate ancillary assets and to provide a comprehensive suite of services to customers, Precision acquired and reorganized assets into complementary businesses. In 1993, Precision entered the camp and catering business with the acquisition of LRG Oilfield Services Ltd. Along with camps from drilling rig business acquisitions and the purchase in 2003 of McKenzie Caterers (1984) Ltd., this division now has 100 camps. In 1996 Precision added in-house capabilities for the design, fabrication and maintenance of rig components with the acquisition of Rostel Industries Ltd. The 1997 acquisition of Columbia Oilfield Supply Ltd. led to the integration of purchasing systems and qualitative improvements in product selection and standardization in all of Precision’s businesses.
Completion and Production Services Segment
Precision’s Completion and Production Services are also known within the oil and gas industry to be a part of the upstream sector with operations at the well location to complete wells that have been drilled and to maintain wells that have been placed into production. The underlying well program parameters determine the type of service rig and ancillary services best suited to workover a particular well. Service rigs are versatile and capable of working on both oil and natural gas wells. Design and technological improvements have made equipment offerings more competitive through efficiency gains and wide market appeal to a broad range of well requirements.
In 1996 Precision diversified into businesses that became the foundation for the Completion and Production Services segment, specifically Precision Well Servicing, Live Well Service and Precision Rentals, through the acquisition of EnServ Corporation. The acquisition enabled Precision to offer services that tracked the life of a particular oil or natural gas well, build customer relationships and moderate demand volatility associated with the drilling of new wells. In 2000 Precision became fully vested in the Canadian service rig business with the acquisition of CenAlta Energy Services Inc. to create at the time a combined fleet of 257 service rigs and an industry-leading 28% market share. Through additional acquisitions in the late 1990s the rental businesses grew and in 2002 were combined and branded as Precision Rentals. In 2006, Precision expanded into the business of remote work site wastewater treatment with the acquisition of Terra Water Group Ltd.
To close fiscal 2008, after acquiring six service rigs strategically positioned near the Bakken shale play from Rick’s Well Servicing, Precision’s 229 service rigs and 29 snubbing units comprise 21% and 24% of the Canadian market, respectively. In addition to completing and servicing wells, the segment offers snubbing to service natural gas wells while pressurized, rental equipment and wastewater treatment for remote accommodations.
18 MANAGEMENT’S DISCUSSION AND ANALYSIS

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VISION
Precision will be recognized as the high performance high value provider of services for global energy exploration and development:

• |  | Precision delivers high performance through passionate people supported by superior systems and equipment designed to maximize and reduce risks; and

• |  | Precision creates high value by lowering customer costs, operating safely, developing people, generating financial growth and attracting investment.

STRATEGIC DIRECTION
Precision’s first step to globalize its contract drilling business and broaden its geographic reach hit stride in late 2007 with drilling rig deployments from Canada and new rig construction to the United States. This market initiative continued through 2008 with an additional 17 rigs and proven high performance high value operational execution leading to a fleet of 29 rigs on December 22, 2008.
On August 25, 2008 with the announcement of the Grey Wolf acquisition, Precision took a second step in the United States by acquiring size and the opportunity to leverage customer relationships, internal systems support, a medium to deep depth rated rig fleet positioned in key basins and human capital in the world’s largest onshore drilling market. With closing of the transaction on December 23, 2008, Precision acquired 123 drilling rigs and operated the fourth largest fleet of rigs in the United States with an emerging international presence through two rigs in Mexico.
Precision will continue to leverage its strategy for high performance high value land drilling services for oil and natural gas exploration and development. As Precision pursues opportunities beyond North America the same organic first deployment and expansion is envisioned to prove out market opportunities and Precision’s high performance high value capabilities. As opportunities and capital markets develop, the second step may involve an acquisition to leverage rig fleet size, to further customer relationships and to improve underlying profit margins.
Precision’s core capabilities reside with its best employees, best systems and best technology. These areas of excellence provide the operating leverage for organic new asset construction growth and for consolidation based growth. The high-performance competitive advantage serves to reduce customer cost and minimize the operational risks associated with drilling and servicing oil and gas wells. Precision’s reputation for high value is evident in financial and operational performance, employee retention, safety and environmental performance and specifically its market share in directional drilling and horizontal applications.
Precision continually reviews assets, retiring those which are less competitive and upgrading others. Precision intends to continue to build high-performance Super Series™ drilling rigs under term contracts targeted to customers who recognize and reward the cost saving benefits of these services.
Precision’s high performance high value strategy is focused on best people, best equipment and best technology to deliver value, diversification and growth:

• |  | Value — capitalize on vertically integrated business model; especially supply distribution, manufacturing and internal system support capabilities to reduce costs and improve margins;

• |  | Value — attract investment capital through strong margins and quality management;

• |  | Diversification — expand to markets beyond Canada to reduce seasonality of equipment utilization and dependence on underlying economics of the WCSB;

• |  | Diversification — capitalize on customer production growth and resulting drilling opportunities, especially North American unconventional natural gas wells;

• |  | Diversification — develop a broad customer base;

PRECISION DRILLING TRUST 19

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• |  | Growth — pursue global oil drilling and service opportunities;

• |  | Growth — integrate directional drilling; and

• |  | Growth — invest in asset growth that creates customer value through enhanced service performance.

Our North American presence enables market share gains as onshore oil and gas basins continue to mature. Precision’s superior equipment technology delivers significantly better operating performance, especially in complex and demanding customer well programs.
Precision seeks consolidation opportunities to implement its core capabilities of employee recruitment, safety, training, environmental footprint, equipment maintenance, equipment manufacturing, supply chain management and cost control to upgrade performance of existing equipment fleets.
KEY PERFORMANCE DRIVERS
Customer economics are dictated by the current and expected margin between the price at which hydrocarbons are sold and the cost to find and develop those products. Some of the key business, customer and industry indicators that Precision focuses on to monitor its performance are:
Safety Management
Precision’s culture is based on the foundation of an all-encompassing Target Zero vision. Precision’s philosophy states that the workplace and organization can be free from injuries, equipment damage and negative environmental impact. Rigs and services that achieve Target Zero deliver operational excellence, best profit margins, operating efficiency and customer satisfaction. Safety is tracked through an industry standard recordable frequency statistic which is measured to benchmark successes and illustrate areas for improvement.
Environmental Management
Precision invests resources to reduce the environmental impact at the work site. This is accomplished through lower emission power systems, small footprint rig designs, efficient field operations, real property assessments and environmental management systems.
Operating Efficiency
Precision maximizes the efficiency of operations through proximity to work sites, operating practices and versatility. Precision’s reliable and well maintained equipment minimizes downtime and non-productive time during operations. Information is gathered from daily drilling log records stored in a database and analyzed to measure productivity, efficiency and effectiveness.
Key factors which contribute to lower customer well costs are:

• |  | Mechanical downtime which is managed through preventative maintenance programs, detailed inspection processes, an extensive fleet of strategically placed spare equipment, an in-house supply chain, and continuous equipment upgrades; and

• |  | Non-productive time, or move, rig-up and rig-out time, which is minimized by decreasing the number of move loads per rig, using lighter move loads, and using mechanized equipment for safer and quicker rig component connections.

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Customer Demand
Precision’s fleet is geographically dispersed to meet customer demands. Relationships with customers, industry knowledge and new well licenses provide Precision with the information necessary to evaluate its marketing strategies. The ability to provide customers with some of the most innovative and advanced rigs in the industry to reduce total well cost increases the value of the rig to the customer. Industry rig utilization statistics are also tracked to evaluate Precision’s performance against competitors.
Workforce
Precision invests in processes and systems that lead to employee development, leadership and retention. Precision’s variable operating cost structure has led to programs and strategies designed to retain senior experienced field personnel. These programs include skill development around leadership and communication, company values, remuneration systems and recruitment initiatives like Toughnecks™, a program that was rolled out during 2008. Precision measures performance excellence through its safety record and reputation to attract and retain employees as industry manpower shortages are often experienced in peak operating periods.
Financial Performance
Precision maximizes revenue without sacrificing operating margins. Key financial information is unitized on a per day or per hour basis and compared to established benchmarks and past performance. Precision evaluates the relative strength of its financial position by monitoring its working capital and debt ratios. The Company’s current focus is to reduce long-term debt.
OPERATING SEGMENTS
As at December 31, 2008 in the Contract Drilling Services segment:

• |  | Precision Drilling operates 220 land drilling rigs in Canada;
• |  | Precision Drilling Oilfield Services operates 151 land drilling rigs in the United States;
• |  | Precision affiliates operate two rigs in Mexico and one in Chile;

• |  | LRG Catering operates 97 camps in Canada, with food catering, and a Precision affiliate operates three camps in the United States;

• |  | Rostel Industries provides engineering, machining, fabrication, component manufacturing and repair services for drilling and service rigs primarily for Precision’s operations; and

• |  | Columbia Oilfield Supply provides centralized procurement, standardized product selection, and coordinated distribution of goods for Precision’s operations.

As at December 31, 2008 in the Completion and Production Services segment:

• |  | Precision Well Servicing operates 229 well completion and workover service rigs in Canada;
• |  | Live Well Service operates 29 snubbing units in Canada;

• |  | Precision Rentals provides approximately 12,000 rental items in Canada including well control equipment, surface equipment, specialty tubulars and wellsite accommodation units; and

• |  | Terra Water Systems provides 76 wastewater treatment units.

PRECISION DRILLING TRUST 21

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The table below categorizes the horsepower of Precision’s drilling rig fleet as at December 31, 2008:

|  | Horsepower |
Type of Drilling Rig |  | <500 |  |  | 500-999 |  |  | 1000-1499 |  |  | 1500-1999 |  |  | 2000+ |  |  | Total |
Electric |  |  | 2 |  |  |  | 19 |  |  |  | 7 |  |  |  | 1 |  |  |  | 1 |  |  |  | 30 |
Mechanical |  |  | 82 |  |  |  | 66 |  |  |  | 2 |  |  |  | — |  |  |  | — |  |  |  | 150 |
Super Single |  |  | 23 |  |  |  | 12 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 35 |
Super Triple |  |  | — |  |  |  | — |  |  |  | 5 |  |  |  | — |  |  |  | — |  |  |  | 5 |
Canada |  |  | 107 |  |  |  | 97 |  |  |  | 14 |  |  |  | 1 |  |  |  | 1 |  |  |  | 220 |
Electric |  |  | — |  |  |  | 3 |  |  |  | 32 |  |  |  | 19 |  |  |  | 30 |  |  |  | 84 |
Mechanical |  |  | — |  |  |  | 23 |  |  |  | 15 |  |  |  | 4 |  |  |  | — |  |  |  | 42 |
Super Single |  |  | — |  |  |  | 5 |  |  |  | 6 |  |  |  | — |  |  |  | — |  |  |  | 11 |
Super Triple |  |  | — |  |  |  | — |  |  |  | 4 |  |  |  | 10 |  |  |  | — |  |  |  | 14 |
United States |  |  | — |  |  |  | 31 |  |  |  | 57 |  |  |  | 33 |  |  |  | 30 |  |  |  | 151 |
Electric |  |  | — |  |  |  | 1 |  |  |  | — |  |  |  | — |  |  |  | 2 |  |  |  | 3 |
International |  |  | — |  |  |  | 1 |  |  |  | — |  |  |  | — |  |  |  | 2 |  |  |  | 3 |
Total |  |  | 107 |  |  |  | 129 |  |  |  | 71 |  |  |  | 34 |  |  |  | 33 |  |  |  | 374 |

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 |  |  | 2008 |  |  | 2007 |  |  | 2006 |  |  | 2005 |
Singles: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mobile |  |  | 150-400 |  |  |  | 2 |  |  |  | 5 |  |  |  | 12 |  |  |  | 17 |
Freestanding mobile |  |  | 150-400 |  |  |  | 97 |  |  |  | 94 |  |  |  | 92 |  |  |  | 88 |
Doubles: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mobile |  |  | 250-550 |  |  |  | 42 |  |  |  | 43 |  |  |  | 44 |  |  |  | 44 |
Freestanding mobile |  |  | 200-550 |  |  |  | 23 |  |  |  | 9 |  |  |  | 9 |  |  |  | 8 |
Skid |  |  | 300-860 |  |  |  | 48 |  |  |  | 55 |  |  |  | 65 |  |  |  | 65 |
Slants: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Freestanding |  |  | 250-400 |  |  |  | 17 |  |  |  | 17 |  |  |  | 15 |  |  |  | 15 |
Total |  |  |  |  |  |  | 229 |  |  |  | 223 |  |  |  | 237 |  |  |  | 237 |

CAPACITY TO DELIVER
Precision is a major supplier of services to oil and gas companies and its success is dependent on providing a complement of oilfield services that are cost effective to its customers. Precision provides quality equipment operated by highly experienced and well trained crews. Maintaining customer relationships is fundamental to Precision’s success and is based in large part upon the ability to deliver. Safety is a measure of performance excellence embodied by Precision’s Target Zero program.
High-Performance Drilling Rigs
Precision Drilling is focused on providing efficient, cost-reducing drilling technology. Design innovations and technology improvements capture incremental time savings during all phases of the well drilling process, including moving between wells.
The versatile Super Single™ design comprises technical innovations in safety and drilling efficiency in slant, vertical or directional drilling on single or multiple well pad locations in shallow to medium depth wells. It is extremely proficient on conventional vertical wells and has drilled in many regions of the world. Super Single™ rigs utilize extended length tubulars, integrated top drive, innovative unitization to facilitate quick moves between well locations, a small footprint to minimize environmental impact and enhanced safety features such as automated pipe handling and remotely operated torque wrenches.
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A scaled-down version without slant capability, the Super Single™ Light, also features an integrated top drive and automated pipe handling and is unitized and trailer mounted to reduce the load count for efficient moving, rig up and tear down for the shallow well depth market.
Triple rigs have greater hoisting capacity and are used in deeper exploration and development drilling. The Super Triple electric rigs are fabricated to keep the load count as low as possible using widely available conventional rig moving equipment. Power capabilities are a major design criterion for the new Super Triple rigs. Drilling productivity and reliability with AC power drive systems provides added precision and measurability along with a computerized electronic auto driller feature that precisely controls weight, rotation and torque on the drill bit. These rigs use extended length drill pipe, an integrated top drive, automated pipe handling with iron roughnecks and control automation off the rig floor.
Large Diversified Rig Fleets
Precision’s large diverse fleet of onshore drilling rigs is strategically deployed across the most active regions of the WCSB, and in many basins in the United States. When an exploration and production company needs a specific type or size of rig in a given area, there is a high likelihood that a Precision rig will be readily available. Geographic proximity and fleet versatility make Precision a premium service provider. Precision’s fleet can drill virtually all types of onshore conventional and unconventional oil and natural gas wells in North America. In the United States, Precision also maintains its own fleet of specialized vehicles for mobilizing its drilling rigs.
Precision’s service rigs provide completion, workover, abandonment, well maintenance, high pressure and critical sour gas well work and well re-entry preparation across the WCSB. The rigs are supported by three field locations in Alberta, two in Saskatchewan and one in British Columbia.
Snubbing complements traditional natural gas well servicing by allowing customers to work on wells while they are pressurized and production has been suspended. Precision has two types of snubbing units — rig assist and self-contained. Self-contained units do not require a service rig on site and are capable of snubbing and performing many other well servicing procedures.
A substantive market share provides size and scale for Precision to leverage vertical integration of supply procurement and distribution, equipment manufacture repair and certification and internal support information systems and processes.
Inventory of Ancillary Equipment
Precision has a large inventory of equipment, including portable top drives, loaders, boilers, tubulars and well control equipment, to support its fleet of drilling and service rigs to meet customer requirements. Precision also maintains an inventory of key rig components to minimize downtime in the event of equipment failures.
In support of drilling rig operations, LRG Catering supplies meals and provides accommodation for rig crews at remote worksites. Terra Water Systems plays an essential role in providing wastewater treatment services for LRG Catering and other camp facilities. Precision Rentals supplies customers with an inventory of specialized equipment and wellsite accommodations.
Industry Leading Safety Program
Safety is critical for Precision and its customers. The focus on working safely is one of Precision’s most enduring values. The goal of Target Zero — Precision’s safety vision for eliminating workplace incidents — is a fundamental belief that all injuries can be prevented. In 2008, 338 of Precision’s drilling and service rigs and 80 of Grey Wolf’s drilling rigs achieved Target Zero. Precision is a leader in adopting technological advancements which have made drilling rigs, service rigs and snubbing units safer.
PRECISION DRILLING TRUST 23

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Well-maintained Equipment
Precision consistently reinvests capital to sustain and upgrade existing property, plant and equipment.
Upgrade Capital Expenditures
In addition to capital expenditures for equipment and infrastructure as illustrated above, equipment repair and maintenance expenses are benchmarked to activity levels in accordance with Precision’s maintenance and certification programs. Precision employs computer systems to track key preventative maintenance indicators for major rig components to record equipment performance history, schedule equipment certifications, reduce downtime and allow for better asset management.
Employees
As a service company, Precision is as good as its people. An experienced, competent crew is a competitive strength and highly valued by customers. To recruit rig employees, Precision has centralized personnel departments and orientation and training programs. In 2008 Precision launched its new Toughnecks™ recruiting campaign to ensure its future field personnel requirements are properly managed and maintained.
Information Systems
Precision’s commitment to invest in a fully integrated enterprise-wide reporting system has improved business performance through real-time access to information across all functional areas. The Canadian divisions operate on a common integrated system using standardized business processes across finance, payroll, equipment maintenance, procurement and inventory control. Precision is currently implementing these systems in its expanded United States operations.
Precision continues to invest in information systems that provide competitive advantages. Electronic links between field and financial systems provide accuracy and timely processing. This repository of rig data improves response time to customer enquiries. Rig manufacturing projects benefit from scheduling and budgeting tools as economies of scale can be identified and leveraged as construction demands increase.
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CONTRACT DRILLING SERVICES SEGMENT
(Stated in thousands of Canadian dollars, except where indicated)

|  |  |  |  |  | % of |  |  |  |  |  |  |  | % of |  |  |  |  |  |  | % of |
Years ended December 31, |  | 2008 |  |  | Revenue |  |  |  | 2007 |  |  | Revenue |  |  | 2006 |  |  | Revenue |
Revenue |  | $ | 809,317 |  |  |  |  |  |  |  | $ | 694,340 |  |  |  |  |  |  | $ | 1,009,821 |  |  |  |  |
Expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating |  |  | 425,051 |  |  |  | 52.5 |  |  |  |  | 345,043 |  |  |  | 49.7 |  |  |  | 470,713 |  |  |  | 46.6 |
General and administrative |  |  | 25,129 |  |  |  | 3.1 |  |  |  |  | 19,946 |  |  |  | 2.9 |  |  |  | 27,225 |  |  |  | 2.7 |
EBITDA (1) |  |  | 359,137 |  |  |  | 44.4 |  |  |  |  | 329,351 |  |  |  | 47.4 |  |  |  | 511,883 |  |  |  | 50.7 |
Depreciation |  |  | 57,076 |  |  |  | 7.1 |  |  |  |  | 43,120 |  |  |  | 6.2 |  |  |  | 38,573 |  |  |  | 3.8 |
Foreign exchange |  |  | (8,179 | ) |  |  | (1.0 | ) |  |  |  | 1,477 |  |  |  | 0.2 |  |  |  | (314 | ) |  |  | — |
Operating earnings (1) |  | $ | 310,240 |  |  |  | 38.3 |  |  |  | $ | 284,754 |  |  |  | 41.0 |  |  | $ | 473,624 |  |  |  | 46.9 |
|  |  |  |  |  | % Increase |  |  |  |  |  |  | % Increase |  |  |  |  |  | % Increase
|  |  | 2008 |  |  | (Decrease) |  |  |  | 2007 |  |  | (Decrease) |  |  | 2006 |  |  | (Decrease)
Number of drilling rigs (end of year) |  |  | 374 |  |  |  | 52.7 |  |  |  |  | 245 |  |  |  | 1.7 |  |  |  | 241 |  |  |  | 4.8 |
Drilling utilization days (operating and moving): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Canada |  |  | 34,488 |  |  |  | (0.2 | ) |  |  |  | 34,572 |  |  |  | (32.3 | ) |  |  | 51,050 |  |  |  | (4.9 | )
United States |  |  | 8,006 |  |  |  | 281.6 |  |  |  |  | 2,098 |  |  |  | — |  |  |  | — |  |  |  | — |
International |  |  | 159 |  |  |  | n/m |  |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Drilling revenue per utilization day: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Canada |  | $ | 16,420 |  |  |  | (2.5 | ) |  |  | $ | 16,833 |  |  |  | (6.5 | ) |  | $ | 18,002 |  |  |  | 14.2 |
United States (in US$) |  | $ | 21,549 |  |  |  | (8.2 | ) |  |  | $ | 23,473 |  |  |  | (8.5 | ) |  | $ | 25,646 |  |  |  | n/m |
Drilling statistics: (2) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Number of wells drilled |  |  | 4,432 |  |  |  | (6.1 | ) |  |  |  | 4,718 |  |  |  | (23.7 | ) |  |  | 6,180 |  |  |  | (20.4 | )
Average days per well |  |  | 6.9 |  |  |  | 6.2 |  |  |  |  | 6.5 |  |  |  | (9.7 | ) |  |  | 7.2 |  |  |  | 20.0 |
Number of metres drilled (000s) |  |  | 5,877 |  |  |  | 1.1 |  |  |  |  | 5,813 |  |  |  | (25.6 | ) |  |  | 7,810 |  |  |  | (12.3 | )
Average metres per well |  |  | 1,326 |  |  |  | 7.6 |  |  |  |  | 1,232 |  |  |  | (2.5 | ) |  |  | 1,264 |  |  |  | 10.3 |

(1) |  | Non-GAAP measure. See page 50.
(2) |  | Canadian operations only.

PRECISION DRILLING TRUST 25

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2008 Compared to 2007
The Contract Drilling Services segment generated revenue of $809 million in 2008, 17% more than the $694 million in 2007. The increase was due to a nearly four-fold increase in the United States activity that was partially offset by lower average day rates in both Canada and the United States. In addition, the Grey Wolf acquisition that was completed on December 23, 2008 added 123 rigs and generated activity for the last eight days of the year.
Operating earnings of $310 million increased $25 million or 9% from $285 million in 2007 and were 38% of revenue in 2008 compared to 41% in 2007. The increase is primarily due to greater United States activity. This was offset by increases in operating expenses which were 53% of revenue in 2008 compared to 50% in 2007. The October 1, 2008 labour rate adjustment in Canada accounted for the majority of the operating expense increase. Increases in the cost of operating supplies as well as higher costs associated with increased deep rig activity also played a role.
Capital expenditures for the Contract Drilling Services segment in 2008 were $203 million and included $163 million to expand the underlying asset base and $40 million to upgrade existing equipment. The majority of the expansion capital was associated with our 2008 rig build program where 18 rigs were being constructed for operations in the United States and Canada.
Canadian Drilling division revenues decreased $16 million or 3% over 2007 to $566 million due to a decrease in customer demand mainly in the fourth quarter as the global economic slowdown took hold. Precision’s Canadian drilling rig activity in 2008 was down 84 utilization days, or less than 1% overall compared to 2007. The rapid increase in commodity prices in the first half of 2008 generated substantially higher cash flows and earnings for producers. This situation reversed in the fourth quarter as dramatic reductions in oil and natural gas prices reduced industry cash flows and drilling activity.
Precision’s 2008 year end Canadian rig count declined to 220 from 232 in 2007 and rig operating day utilization increased marginally. The industry drilling rig fleet was reduced to about 850 drilling rigs at the end of 2008 and operating day utilization increased by 10%. Industry operating days in Canada increased to 134,835 reflecting increased drilling days mainly associated with the Montney, Horn River and Bakken unconventional plays, which typically require more days to complete. For the year there was a 25% increase in industry horizontal wells drilled despite an overall decrease in total wells drilled of 8%.
Average drilling rig utilization day rates for Precision rigs in Canada decreased 2% in 2008 from 2007. Average rates strengthened in the second half of 2008 due to pricing for rigs under term contracts for Precision’s versatile, high performing rigs and strong pricing associated with a deeper rig mix.
Canadian Drilling EBITDA decreased by 10% over 2007 due to lower activity and pricing in the first half of 2008. Depreciation expense for the year was $5 million higher than 2007 due to a change in rig mix and higher cost base associated with high-performance deeper rigs.
The United States drilling division revenues increased $139 million or 273% over 2007 to $190 million. The increase is due to strong utilization and the addition of 17 rigs through organic growth and the inclusion of Grey Wolf for eight days. Drilling rig activity in 2008 was up 5,908 utilization days or 282% overall compared to 2007.
Average drilling rig utilization day rates in the United States decreased 8% in 2008 from 2007. The decrease in rates was primarily due to the mix of drilling rigs deployed from Canada during 2008 along with some downward pressure on day rates from operators.
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United States EBITDA of $92 million increased $64 million or 226% from $28 million in 2007 primarily due to an increase in activity from the rig fleet growth during 2008. Operating expenses increased from 42% of revenue in 2007 to 49% in 2008. The increase was mainly due to higher maintenance and repair costs for the rig fleet compared to the relatively new rig fleet during 2007.
LRG Catering achieved activity and revenue growth of 10% in 2008. In response to industry pressure for quality camps 12 of LRG’s oldest camps were replaced with ten new camps. Dorms built in late 2007 and early 2008 were deployed to meet customer demand for base camps.
Rostel Industries and Columbia Oilfield Supply divisions provided valuable support, best measured by the efficiencies and contributions made to Precision through cost savings. Rostel’s expertise provided Precision control over rig construction and enhanced cost control. Columbia leveraged its volume purchasing advantage and supplier relationships to provide timely and reliable supplies to keep Precision’s rigs operating and allowed Precision to standardize product use and quality.
2007 Compared to 2006
The Contract Drilling Services segment generated revenue of $694 million in 2007, 31% less than the record revenue of $1.0 billion in 2006. The decrease was due to lower equipment utilization and reduced pricing resulting from lower customer demand for natural gas drilling in Canada, partially offset by additional rigs and strong utilization in the United States.
Operating earnings decreased by $189 million or 40% to $285 million and were 41% of revenue in 2007 compared to 47% in 2006 primarily due to lower pricing in the final nine months of 2007. Operating expenses increased from 47% of revenue in 2006 to 50% in 2007, due to crew wage increases in October 2006 and an overall increase in the cost of materials.
Capital expenditures for the segment in 2007 were $159 million and included $126 million to expand the underlying asset base and $33 million to upgrade existing equipment. The majority of the expansion capital expenditure was associated with new drilling rig construction.
Canadian Drilling division revenue decreased by $337 million or 37% over 2006 to $582 million. This decline was due to a decrease in industry customer demand resulting in lower utilization and pricing for Precision.
Operating earnings in the division decreased by 45% over 2006 due mainly to a 32% decrease in activity, a 7% decrease in the average operating rate and a 4% crew wage rate increase in October 2006. Depreciation expense for the year was $1 million lower than 2006 as the impact of lower activity was offset by a $3 million write down charge for decommissioned rigs and a change in rig mix.
Precision Drilling Oilfield Services, Inc. generated revenues of $51 million in 2007, a ten-fold increase over 2006 due to fleet growth from one rig at the end of 2006 to 12 rigs at the end of 2007.
LRG Catering experienced activity declines of 51% in 2007 from a record 2006 as a result of the lower industry activity, which placed downward pressure on pricing.
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COMPLETION AND PRODUCTION SERVICES SEGMENT
(Stated in thousands of Canadian dollars, except where indicated)

|  |  |  |  |  | % of |  |  |  |  |  |  |  | % of |  |  |  |  |  |  | % of |
Years ended December 31, |  | 2008 |  |  | Revenue |  |  |  | 2007 |  |  | Revenue |  |  | 2006 |  |  | Revenue |
Revenue |  | $ | 308,624 |  |  |  |  |  |  |  | $ | 327,471 |  |  |  |  |  |  | $ | 441,017 |  |  |  |  |
Expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating |  |  | 188,705 |  |  |  | 61.2 |  |  |  |  | 183,661 |  |  |  | 56.1 |  |  |  | 231,602 |  |  |  | 52.5 |
General and administrative |  |  | 10,865 |  |  |  | 3.5 |  |  |  |  | 11,780 |  |  |  | 3.6 |  |  |  | 14,242 |  |  |  | 3.2 |
EBITDA |  |  | 109,054 |  |  |  | 35.3 |  |  |  |  | 132,030 |  |  |  | 40.3 |  |  |  | 195,173 |  |  |  | 44.3 |
Depreciation |  |  | 22,966 |  |  |  | 7.4 |  |  |  |  | 31,421 |  |  |  | 9.6 |  |  |  | 32,013 |  |  |  | 7.3 |
Foreign exchange |  |  | (16 | ) |  |  | — |  |  |  |  | 13 |  |  |  | — |  |  |  | 41 |  |  |  | — |
Operating earnings (1) |  | $ | 86,104 |  |  |  | 27.9 |  |  |  | $ | 100,596 |  |  |  | 30.7 |  |  | $ | 163,119 |  |  |  | 37.0 |
|  |  |  |  |  | % Increase |  |  |  |  |  |  |  | % Increase |  |  |  |  |  |  | % Increase |
|  | 2008 |  |  | (Decrease) |  |  |  | 2007 |  |  | (Decrease) |  |  | 2006 |  |  | (Decrease) |
Number of service rigs (end of year) |  |  | 229 |  |  |  | 2.7 |  |  |  |  | 223 |  |  |  | (5.9 | ) |  |  | 237 |  |  |  | — |
Service rig operating hours |  |  | 335,127 |  |  |  | (5.9 | ) |  |  |  | 355,997 |  |  |  | (25.9 | ) |  |  | 480,137 |  |  |  | 0.6 |
Revenue per operating hour |  | $ | 708 |  |  |  | (3.0 | ) |  |  | $ | 730 |  |  |  | 2.5 |  |  | $ | 712 |  |  |  | 18.7 |

(1) |  | Non-GAAP measure. See page 50.

2008 Compared to 2007
The Completion and Production Services segment revenue decreased by $19 million to $309 million mainly due to a decline in industry completion and production activity.
Operating earnings decreased by $14 million or 14% and was 28% of revenue in 2008 compared to 31% in 2007 due mainly to lower service activity during the year. Operating expenses increased from 56% of revenue in 2007 to 61% in 2008. On a daily or hourly operating basis, costs increased due to crew wage rate increases in October 2008 and an overall increase in the cost of materials. Lower equipment utilization resulted in increased daily or hourly operating costs associated with fixed operating cost components.
Capital spending in 2008 of $24 million, down 11% from $27 million in 2007, included $7 million for the construction of a service rig, a self-contained snubbing unit, storage tanks and wastewater treatment units, and $17 million for replacement transporter trucks, doghouses, snubbing unit trucks, drill pipe for rental, tanks and a new operating facility. Additionally, in the third quarter of 2008 six service rigs and support equipment were acquired from a third party for $16 million.
The Precision Well Servicing division revenue decreased by $23 million or 9% over 2007 to $237 million as operating rates moved downward in conjunction with reduced activity levels. Price decreases established in the fourth quarter of 2007 impacted most of 2008 with an upward adjustment in the fourth quarter.
A total of 16,812 wells were rig released in 2008, a decrease of 9% from the 18,342 wells in the prior year. With a lag between the drilling and completion of a well, the industry reported 19,340 well completions in 2008, consistent with the 19,272 well completions in 2007. There are currently about 200,000 producing wells within the WCSB which has added to the ongoing maintenance demand to ensure continuous and efficient operation of these producing wells.
Industry fleet capacity was consistent with 2007 with about 1,100 rigs at the end of 2008. High industry capacity coupled with a nominal increase in well completions and commodity price volatility kept market pricing competitive. There was also a rising number of wells where rig-less or coiled tubing methods were employed.
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EBITDA decreased by 22% over 2007 due mainly to the 6% decrease in activity and a 3% decrease in average operating rate. Depreciation expense for the year decreased $2 million due to gains on disposal offset by increased depreciation from the addition of six service rigs during the year and the completion of a new operating facility early in the fourth quarter.
Capital expenditures in 2008 were $18 million and included $2 million to construct a new service rig and $16 million to upgrade pump trucks, certain service rig components and build a new operating facility that was completed in the fourth quarter.
Live Well Service division revenue for 2008 was $24 million as activity increased by 10% over 2007 due to higher activity from self-contained units which generate higher operating rates than rig-assist snubbing units. In 2008, Live Well added a self-contained unit and a rack and pinion unit to the fleet.
Precision Rentals division revenue decreased to $42 million, which was $3 million or 6% lower than 2007 as moderately higher utilization could not offset declining rates. Each of Precision Rental’s three major product lines; surface equipment, tubulars equipment, and wellsite accommodations, experienced year-over-year declines in rates which was brought on by excess industry equipment and pricing pressures.
The Terra Water Systems division generated revenue of $6 million in 2008 compared to $5 million in 2007, an increase of 28%. Terra Water had 76 wastewater treatment units at the end of 2008, an increase of 13 units over 2007.
2007 Compared to 2006
The Completion and Production Services segment revenue decreased by $114 million to $327 million mainly due to a decline in industry activity.
Operating earnings decreased by $63 million or 38% and was 31% of revenue in 2007 compared to 37% in 2006 due mainly to lower service activity during the year. Operating expenses increased from 53% of revenue in 2006 to 56% in 2007. The margin decrease was primarily attributable to cost increases from crew wage rate increases in October 2006 and an overall increase in the cost of materials.
Capital spending in 2007 of $27 million, down 32% from $39 million in 2006, included $15 million for the construction of slant service rigs, self-contained snubbing units, storage tanks and wastewater treatment units, and $12 million for replacement transporter trucks, doghouses, snubbing unit trucks, drill pipe for rental, tanks and a new operating facility.
The Precision Well Servicing division revenue decreased by $82 million or 24% over 2006 to $260 million as moderately higher hourly operating rates could not offset reduced activity levels. Price increases established in the fourth quarter of 2006 were maintained through most of 2007, with downward adjustments in the second half. Operating earnings decreased by 33% over 2006. Costs were higher due to increased crew and rig manager labour expenses. Capital expenditures in 2007 included the construction of two new service rigs and the continuation of long-term plans to upgrade and standardize equipment.
Live Well Service activity decreased by 36% over 2006 with revenues for the year of $19 million due to weakening natural gas prices in 2007 which led to a shift in customer demand away from rig-assist units to self-contained snubbing units.
Precision Rentals generated revenues of $44 million, which was $18 million or 29% lower than 2006. Each of Precision Rental’s three major product lines experienced year-over-year revenue declines due to low utilization from excess industry capacity and lower pricing.
Terra Water Systems generated revenue of $5 million in 2007 compared to $2 million in the period following the date of acquisition in 2006. Terra Water had 63 wastewater treatment units at the end of 2007, an increase of 12 units over 2006.
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OTHER ITEMS
2008 Compared to 2007
Corporate and Other Expenses
Corporate and other expenses increased by $13 million or 43% from 2007 to $42 million. This increase was primarily due to a $4 million long-term incentive plan accrual in 2008 compared to a $4 million recovery in 2007 and an increase in professional fees in the current year. A portion of the award payable under the long-term incentive plan is dependent on the growth in certain defined financial targets over a three year period. The actual results in 2007 were below the threshold amount, resulting in a partial recovery of amounts previously accrued. Increased foreign exchange losses on the translation of United States dollar denominated debt resulting from a strengthening United States dollar were incurred in the year. Of the balance of long-term debt as at December 31, 2008, 92% is denominated in United States dollars.
Interest Expense
Net interest expense of $14 million increased by $7 million compared to 2007. This increase was primarily attributable to the higher average debt outstanding during 2008 compared to the prior year and the interest associated with the new credit facilities as part of the Grey Wolf acquisition.
Income Taxes
The Trust’s effective income tax rate, before enacted tax rate reductions, on earnings from continuing operations before income taxes was 11% in 2008 compared to 8% in 2007. The comparatively low effective income tax rate was primarily a result of the shifting of the income tax burden of the Trust to its unitholders. The year-over-year increase in the effective income tax rate was largely a result of taxes associated with Precision’s United States operations.
The Trust incurs taxes to the extent there are certain provincial capital taxes, franchise taxes, as well as taxes on the taxable income of its underlying subsidiaries. In addition, future income taxes arise from differences between the accounting and tax basis of the Trust and its operating entities’ assets and liabilities.
During 2007 the Government of Canada passed legislation to reduce the federal income tax rates to 15% by 2012. These enacted tax rate reductions resulted in a $22 million future tax recovery in 2007, with no comparable recovery recorded in 2008.
Discontinued Operations
A $3 million gain, net of tax, on discontinued operations was recorded in 2007. The gain arose on the receipt of additional consideration associated with a 2005 business divestiture.
2007 Compared to 2006
Corporate and Other Expenses
Corporate and other expenses decreased by $12 million or 30% from 2006 to $29 million. This reduction was primarily due to a $4 million recovery of long-term incentive plan accruals in 2007 compared to a $10 million expense in 2006. Additional reductions achieved from lower accruals for recurring near-term incentive plans were offset by one-time costs associated with hiring a new Chief Executive Officer and costs associated with workforce restructuring in November 2007. Gains associated with 2006 disposals and increased foreign exchange losses from a weakening United States dollar offset by lower support costs in 2007 made up the remaining decrease.
Interest Expense
Net interest expense of $7 million declined by $1 million or 9% in 2007 compared to 2006. This reduction was primarily attributable to the lower average debt outstanding during 2007 compared to the prior year.
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Income Taxes
The Trust’s effective income tax rate, before enacted tax rate reductions, on earnings from continuing operations before income taxes was 8% in 2007 compared to 6% in 2006. The comparatively low effective income tax rate was primarily a result of the shifting of the income tax burden of the Trust to its unitholders. The year-over-year increase in the effective income tax rate was largely a result of taxes associated with Precision’s United States operations.
During 2007 the Government of Canada passed legislation to reduce the federal income tax rates to 15% by 2012. These enacted tax rate reductions resulted in a $22 million future tax recovery in 2007, compared to the $21 million recorded in 2006.
Discontinued Operations
A $3 million gain, net of tax, on discontinued operations was recorded in 2007. The gain arose on the receipt of additional consideration associated with a 2005 business divestiture. Additional consideration on 2004 and 2005 business divestitures resulted in a $7 million gain in 2006.
LIQUIDITY AND CAPITAL RESOURCES
In connection with the acquisition of Grey Wolf, Precision entered into a new US$1.2 billion senior secured credit facility with a syndicate of lenders consisting of the Royal Bank of Canada, RBC Capital Markets, Deutsche Bank AG Cayman Islands Branch, Deutsche Bank Securities Inc., HSBC Bank Canada, HSBC Bank USA, National Association and the Toronto-Dominion Bank (the “Commitment Banks”), and certain other lenders (the “Secured Facility”) that is guaranteed by the Trust and is comprised of US$800 million of term loans and a US$400 million revolving credit facility. Precision has also entered into a US$400 million unsecured credit facility with certain of the Commitment Banks (the “Unsecured Facility” and, together with the Secured Facility, the “Credit Facilities”) that is also guaranteed by the Trust. The Credit Facilities funded the cash portion of the Acquisition and refinanced the pre-closing Precision bank debt and certain pre-closing debt obligations of Grey Wolf. The Unsecured Facility is available to fund the repurchase of Grey Wolf convertible notes expected to be tendered for repurchase by holders under a change of control offer and on March 18, 2009 US$262.3 million was tendered for repurchase by the holders. When upfront issue discount and fees are factored in, the all-in cost of capital borrowings under the Credit Facilities at December 31, 2008 was about 13%.
In order to complete a successful syndication of the Secured Facility, the Commitment Banks are entitled, prior to March 23, 2009 (extended by Precision to May 22, 2009 ) in consultation with Precision, to change certain of the terms of the Revolver and Term Loan A including, without limitation, to implement, within certain limits, additional increases in interest rates, original issue discounts and/or upfront fees, reallocate up to US$250 million between the Term Loan A Facility (as defined herein) and the Term Loan B Facility (as defined herein) (US$64 million of which was reallocated effective February 4, 2009 from the Term Loan A Facility to the Term Loan B Facility), reallocate up to US$150 million between the Secured Facility and the Unsecured Facility and amend certain covenants, financial ratio tests and other provisions for portions of the Secured Facility.
The following is a summary of the material terms of the Secured Facility and the Unsecured Facility.
Secured Facility
The Secured Facility provides senior secured financing of up to approximately US$1.2 billion, consisting of (after giving effect to the US$64 million reallocation between the Term Loan A Facility and the Term Loan B Facility):

• |  | Term loan A facility in an aggregate principal amount of US$336 million (the “Term Loan A Facility”);
• |  | Term loan B facility in an aggregate principal amount of US$464 million (the “Term Loan B Facility”); and
• |  | Revolving credit facility in the amount of US$400 million (the “Revolving Credit Facility”).

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The terms of the Secured Facility include:

• |  | Blended cash interest rate, as at February 4, 2009, of approximately 8% per annum, before original issue discounts and upfront fees;
• |  | Covenants requiring the Trust and Precision to comply with certain financial ratios; and
• |  | Covenants that will limit the Trust’s capital expenditures above an agreed base-case, allowing for certain exceptions.

The interest rate on loans under the Secured Facility that are denominated in United States dollars is, at the option of Precision, either a margin over an adjusted United States base rate (the “ABR rate”) or a margin over a Eurodollar rate. The interest rate on loans denominated in Canadian dollars is, at the option of Precision, a margin over the Canadian prime rate or a margin over the bankers’ acceptance rate. Certain of the margins on the Revolving Credit Facility are subject to reduction based upon a leverage test.
The Revolving Credit Facility provides for a commitment fee of 0.60% (subject to reduction based on a leverage test) on the unused portion; a fee on the outstanding amount of the letters of credit denominated in United States dollars equal to the margin applicable to the Eurodollar rate; and a fee on the outstanding amount of the letters of credit denominated in Canadian dollars equal to the margin applicable to the bankers’ acceptance rate (subject to reduction for non-financial letters of credit).
The Term Loan A Facility is repayable in quarterly installments in aggregate annual amounts equal to 5% of the original principal amount thereof in the first year following the closing date, 10% of the original principal amount thereof in the second year following the closing date, 10% of the original principal amount thereof in the third year following the closing date and 15% of the original principal amount thereof in the fourth and fifth years following the closing date, with the balance payable on the final maturity date thereof, which is December 23, 2013.
The Term Loan B Facility is repayable in quarterly installments in an aggregate annual amount equal to 5% of the original principal amount thereof with the balance payable on the final maturity date thereof, which is September 30, 2014.
Unsecured Facility
Precision (as the borrower) and the Trust (as a guarantor) entered into a credit agreement dated December 23, 2008 governing the Unsecured Facility with the lenders parties thereto, Royal Bank of Canada, as syndication agent, Deutsche Bank AG Cayman Islands Branch, as administrative agent and HSBC Bank USA, National Association, as documentation agent. The Unsecured Facility originally provided senior unsecured financing of up to US$400 million of which approximately US$138 million was drawn after completion of the Grey Wolf acquisition and the related financing transactions. Net proceeds received of approximately US$165 million from the equity raise in February 2009 reduced the amount available under the Unsecured Facility by an equivalent amount. The Unsecured Facility, along with net proceeds from the equity offering will be used to fund the repurchase of Grey Wolf convertible notes tendered for repurchase by holders under a change of control offer made in the first quarter of 2009.
The loans under the Unsecured Facility bear interest at a fixed rate per annum of 17%, which initially mature on December 23, 2009, and, to the extent unpaid on that date, will be converted into exchange notes that will mature on December 23, 2016 provided that the loans will not be converted to exchange notes if an event of default has occurred under the Unsecured Facility or the Secured Facility or certain other conditions are not satisfied.
After the initial maturity date of the Unsecured Facility of December 23, 2009, each lender under the Unsecured Facility may request the Trust issue an exchange note bearing interest at a specified interest rate (to be calculated on the date of issuance of such exchange note based on the greater of 16.66% and a market-based interest rate cap) in replacement for the term loan (or a portion thereof) made under the Unsecured Facility. In the event that the Trust receives such a request, the Trust shall, as promptly as practicable after being requested to do so, among
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other things: (i) enter into an exchange note indenture pursuant to which the exchange notes will be issued and governed; (ii) enter into an exchange and registration rights agreement providing for, among other things, registration rights in respect of the exchange notes in favour of the holders thereof; and (iii) cause to be issued exchange notes in the same principal aggregate amount as the term loan being exchanged.
In addition, between June 30, 2009 and December 23, 2009, the lenders under the Unsecured Facility may require that debt securities be issued and sold to repay amounts outstanding under the Unsecured Facility, subject to certain specified terms and conditions. Precision has agreed to engage one or more investment banks to publicly sell or privately place debt securities in such circumstances, the proceeds of which will be used to repay outstanding loans under the Unsecured Facility. The Trust may also, at its own option, choose to issue equity or debt securities and Precision may also choose to issue debt securities to repay outstanding loans under the Unsecured Facility.
The Unsecured Facility is unsecured and has been guaranteed by the Trust and each subsidiary of the Trust that guaranteed the Secured Facility.
General
The terms of the documents governing the Credit Facilities contain provisions that in effect ensure that the lenders have priority as to payment over the unitholders in respect to the assets and income of the Trust and its subsidiaries. Amounts due and owing to the lenders under the Credit Facilities must be paid before any distributions can be made to unitholders. This relative priority of payments could result in a temporary or permanent interruption of distributions to unitholders.
As at December 31, 2008, approximately $1,087 million was outstanding under the Secured Facility and approximately $168 million was outstanding under the Unsecured Facility. The Revolving Credit Facility may be redrawn by Precision in the future to fund capital expenditures or for other corporate purposes.
At the time of the closing of the acquisition, Grey Wolf had outstanding $321 million aggregate principal amount of convertible notes, the obligations for which were assumed by Precision. Pursuant to the terms of the convertible notes, during the first quarter of 2009, the Trust, as successor to Grey Wolf, was required to make to the holders thereof a “change of control” offer to repurchase any or all of the outstanding convertible notes at 100% of the principal amount thereof, plus accrued but unpaid interest to the date of the repurchase, payable in cash.
In 2008 the Trust generated cash from continuing operations of $344 million and borrowed an additional $1,148 million in long-term debt net of financing fees. The cash generated was used to complete the business acquisitions of $768 million, purchase property plant and equipment net of disposal proceeds and related non-cash working capital of $197 million, repay long-term debt of $180 million and bank indebtedness of $14 million, pay an income tax reassessment of $55 million, and make cash distributions to unitholders of $216 million leaving a cash balance as at December 31, 2008 of $62 million.
The Trust exited 2008 with a long-term debt to long-term debt plus equity ratio of 0.37 compared to 0.08 in 2007 and a ratio of long-term debt to cash provided by continuing operations of 3.98 compared to 0.25 in 2007. The significant increases are due to the additional debt arising from the acquisition of Grey Wolf. The long-term debt to cash provided by continuing operations ratio is high in part due to only eight days of Grey Wolf operations in 2008 included in cash provided by operations.
In addition to the Secured Facility and Unsecured Facility, Precision also has uncommitted operating facilities which total approximately $51 million equivalent and are utilized for working capital management and the issuance of letters of credit.
As at March 20, 2009, holders of convertible notes representing US$262 million had notified Precision that they will be accepting the purchase offer and Precision will be required to purchase these notes at the principal balance plus accrued interest of US$2 million by March 24, 2009.
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Precision’s contractual obligations are outlined in the following table:

|  | Payments Due by Period
(Stated in thousands of Canadian dollars) |  | Total |  | Less Than 1 Year |  |  | 1 - 3 Years |  |  | 4 - 5 Years |  |  | After 5 Years |
Long-term debt (1) |  | $ | 1,255,388 |  |  | $ | 48,953 |  |  | $ | 138,990 |  |  | $ | 472,933 |  |  | $ | 594,512 |
Interest on long-term debt (2) |  |  | 581,459 |  |  |  | 114,953 |  |  |  | 215,530 |  |  |  | 191,961 |  |  |  | 59,015 |
Rig construction |  |  | 125,289 |  |  |  | 66,062 |  |  |  | 59,227 |  |  |  | — |  |  |  | — |
Operating leases |  |  | 35,013 |  |  |  | 10,977 |  |  |  | 16,093 |  |  |  | 2,811 |  |  |  | 5,132 |
Long-term incentive plans (3) |  |  | 20,751 |  |  |  | 9,217 |  |  |  | 11,534 |  |  |  | — |  |  |  | — |
Total contractual obligations |  | $ | 2,017,900 |  |  | $ | 250,162 |  |  | $ | 441,374 |  |  | $ | 667,705 |  |  | $ | 658,659 |

(1) |  | Excludes unsecured convertible notes as these debt instruments contain a provision whereby Precision is required to provide holders of the notes with an offer to purchase all or a portion of their notes, including accrued but unpaid interest to the date of purchase, which Precision expects to repay in 2009 with proceeds received from an equity offering and existing credit facilities. Upon completion of this transaction the Unsecured Facility would increase to approximately $287.8 million (US$235 million) with repayment in 2016. Interest on the unsecured convertible notes to the date of purchase is approximately $2.8 million (US$2.3 million). Amounts are after giving effect to the February 4, 2009 re-allocation between the Term Loan A and Term Loan B facilities.
(2) |  | Interest has been calculated based upon debt balances, interest rates and foreign exchange rates in effect as at December 31, 2008.
(3) |  | Includes amounts not yet accrued at December 31, 2008 but payable at the end of the contract term. Unit based compensation amounts disclosed at year-end unit price.

Precision has multiple long-term incentive plans (“LTIP”) which compensate officers and key employees through cash payments at the end of a three-year term. The compensation is comprised of two components, a retention award and a performance award. The retention awards are lump sum amounts determined at the date of commencement in the LTIP. The retention components are accrued evenly over their respective three-year terms. The performance components are accrued based on actual results compared to predetermined targets. There is no assurance that the performance component will be paid. In addition, the Chief Executive Officer has a separate unit-based plan which paid $1.4 million in September 2008 and anticipated payments of $0.7 million annually, in September 2009 and September 2010 based on the December 31, 2008 unit price of Precision.
Outstanding Unit Data

|  | March 20, |  |  | December 31, |  |  | December 31, |  |  | December 31, |
|  | 2009 |  |  | 2008 |  |  | 2007 |  |  | 2006 |
Trust units |  |  | 206,065,086 |  |  |  | 160,042,065 |  |  |  | 125,587,919 |  |  |  | 125,536,329 |
Exchangeable LP units |  |  | 128,562 |  |  |  | 151,583 |  |  |  | 170,005 |  |  |  | 221,595 |
Total units outstanding |  |  | 206,193,648 |  |  |  | 160,193,648 |  |  |  | 125,757,924 |  |  |  | 125,757,924 |
Deferred Trust units outstanding |  |  | 78,776 |  |  |  | 54,543 |  |  |  | 18,280 |  |  |  | — |

DISTRIBUTIONS
Upon Precision’s conversion to an income trust effective November 7, 2005 the Trust adopted a policy of making monthly distributions to holders of Trust units and holders of exchangeable LP units (together “unitholders”). Precision has a legal entity structure whereby the trust entity, Precision Drilling Trust, effectively must flow its taxable income to unitholders pursuant to its Declaration of Trust. Distributions, including special distributions, may be declared in cash or “in-kind” or a combination of both and reduced, increased or suspended entirely depending on the operations of Precision, the performance of its assets, or legislative changes in tax laws. The actual cash flow available for distribution to unitholders is a function of numerous factors, including the Trust’s: financial performance; debt covenants and obligations; working capital requirements; upgrade and expansion capital expenditure requirements for the purchase of property, plant and equipment; and number of units outstanding. The Trust considers these factors on a monthly basis in determining future distributions. In 2008 cash distributions declared were $201 million or $1.56 per unit, a decrease of $46 million or $0.40 per unit from the previous year. A special year-end “in-kind” distribution, as explained below, payable in Trust units, of $24 million or $0.15 per unit (2007 — $30 million or $0.24 per unit) was also declared.
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In the event that a distribution is declared in the form of “in-kind” units, the terms of the Declaration of Trust requires that the outstanding units be consolidated immediately subsequent to the distribution. Accordingly, the number of outstanding units would remain at the number outstanding immediately prior to the distribution. As a result, unitholders would not receive additional units and the declared amount of the “in-kind” distribution would be retained in Precision. Holders of exchangeable LP units receive economic equivalent treatment.
On February 9, 2009 Precision announced the suspension of cash distributions for an indefinite period for distributions to be paid after February 17, 2009. The suspension of the distribution was taken in response to lower financial operating performance at the start of 2009 and will allow Precision to increase debt repayment capability and balance sheet strength.
Key factors for consideration in determining actual cash flow available for distribution, in an historical context, are disclosed within the consolidated statements of cash flow. In calculating distributable cash Precision makes the following adjustments to cash provided by continuing operations:

• |  | Deducts the purchase of property, plant and equipment for upgrade capital as the minimum capital reinvestment required to maintain current operating capacity;
• |  | Deducts the purchase of property, plant and equipment for expansion initiatives to grow capacity;
• |  | Adds the proceeds on the sale of property, plant and equipment which are incidental transactions occurring within the normal course of operations; and
• |  | Deducts long-term incentive plan changes as an unfunded liability resulting from the operating activities in the current period with payments beginning March 2009.

A three-year reconciliation of distributable cash from continuing operations follows:

Years ended December 31, |  |  |  |  |  |  |  |  |  |
(Stated in thousands of Canadian dollars, except per diluted unit amounts) |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Cash provided by continuing operations |  | $ | 343,910 |  |  |  | $ | 484,115 |  |  | $ | 609,744 |
Deduct: |  |  |  |  |  |  |  |  |  |  |  |  |
Purchase of property, plant and equipment for upgrade capital |  |  | (59,454 | ) |  |  |  | (45,970 | ) |  |  | (92,123 | )
Purchase of property plant and equipment for expansion initiatives |  |  | (170,125 | ) |  |  |  | (141,003 | ) |  |  | (170,907 | )
Add: |  |  |  |  |  |  |  |  |  |  |  |  |
Proceeds on the sale of property, plant and equipment |  |  | 10,440 |  |  |  |  | 5,767 |  |  |  | 29,337 |
Standardized distributable cash (1) |  |  | 124,771 |  |  |  |  | 302,909 |  |  |  | 376,051 |
Unfunded long-term incentive plan compensation |  |  | (2,163 | ) |  |  |  | 8,496 |  |  |  | (22,699 | )
Distributable cash from continuing operations (1) |  | $ | 122,608 |  |  |  | $ | 311,405 |  |  | $ | 353,352 |
Cash distributions declared |  | $ | 200,659 |  |  |  | $ | 246,485 |  |  | $ | 447,001 |
Per diluted unit information: |  |  |  |  |  |  |  |  |  |  |  |  |
Cash distributions declared |  | $ | 1.56 |  |  |  | $ | 1.96 |  |  | $ | 3.56 |
Standardized distributable cash (1) |  | $ | 0.98 |  |  |  | $ | 2.41 |  |  | $ | 3.00 |
Distributable cash from continuing operations (1) |  | $ | 0.97 |  |  |  | $ | 2.48 |  |  | $ | 2.81 |

(1) |  | Non-GAAP measure. See page 50.

Upgrade capital expenditures allow Precision to maintain its existing service levels. These expenditures consist of betterments and replacements to existing assets and capitalized costs relating to the underlying support infrastructure. The upgrade capital expenditure strategy of Precision also involves costs that are charged directly to the income statement. These costs are related to the scheduled maintenance and certification processes within the various operating divisions. The level of these expenditures is driven by activity levels and can be scaled back in times of low activity without jeopardizing the long-term productive capacity of Precision and its underlying assets.
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Years ended December 31, |  |  |  |  |  |  |
(Stated in thousands of Canadian dollars) |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Cash provided by continuing operations (A) |  | $ | 343,910 |  |  |  | $ | 484,115 |  |  | $ | 609,744 |
Net earnings (B) |  | $ | 302,730 |  |  |  | $ | 345,776 |  |  | $ | 579,589 |
Distributions declared (C) |  | $ | 224,688 |  |  |  | $ | 276,667 |  |  | $ | 471,524 |
Excess of cash provided by operations over distributions declared (A-C) |  | $ | 119,222 |  |  |  | $ | 207,448 |  |  | $ | 138,220 |
Excess of net earnings over distributions declared (B-C) |  | $ | 78,042 |  |  |  | $ | 69,109 |  |  | $ | 108,065 |

Precision has acted decisively to strengthen its capability to reduce long-term debt and improve its underlying credit quality and capital structure. The near-term management strategy involves retaining sufficient funds from available distributable cash to repay debt finance, spend on required upgrade capital expenditures as well as financing working capital needs. Planned asset growth will generally be financed through existing debt facilities or cash retained from continuing operations.

Years ended December 31, |  |  |  |  |  |  |  |  |  |
(Stated in thousands of Canadian dollars except per unit amounts) |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Units outstanding |  |  | 160,193,648 |  |  |  |  | 125,757,924 |  |  |  | 125,757,924 |
Year-end unit price |  | $ | 10.07 |  |  |  | $ | 15.09 |  |  | $ | 27.00 |
Units at market |  | $ | 1,613,150 |  |  |  | $ | 1,897,687 |  |  | $ | 3,395,464 |
Long-term debt |  |  | 1,368,349 |  |  |  |  | 119,826 |  |  |  | 140,880 |
Less working capital |  |  | (345,329 | ) |  |  |  | (140,374 | ) |  |  | (166,484 | )
Enterprise value |  | $ | 2,636,170 |  |  |  | $ | 1,877,139 |  |  | $ | 3,369,860 |

Precision carried a long-term debt to enterprise value ratio of 0.52 at December 31, 2008. This represents a significant increase over the 2007 ratio of 0.06 due to the refinancing undertaken to facilitate the Grey Wolf acquisition in December 2008.
QUARTERLY FINANCIAL SUMMARY
(Stated in thousands of Canadian dollars, except per unit amounts)

Year ended December 31, 2008 |  | Q1 |  |  | Q2 |  |  | Q3 |  |  | Q4 |  |  | Year |
Revenue |  | $ | 342,689 |  |  | $ | 138,514 |  |  | $ | 285,639 |  |  | $ | 335,049 |  |  | $ | 1,101,891 |
EBITDA (1) |  |  | 147,347 |  |  |  | 35,574 |  |  |  | 118,820 |  |  |  | 134,795 |  |  |  | 436,536 |
Earnings from continuing operations: |  |  | 106,266 |  |  |  | 21,739 |  |  |  | 82,349 |  |  |  | 92,376 |  |  |  | 302,730 |
Per basic unit |  |  | 0.85 |  |  |  | 0.17 |  |  |  | 0.65 |  |  |  | 0.72 |  |  |  | 2.39 |
Per diluted unit |  |  | 0.84 |  |  |  | 0.17 |  |  |  | 0.65 |  |  |  | 0.71 |  |  |  | 2.39 |
Net earnings: |  |  | 106,266 |  |  |  | 21,739 |  |  |  | 82,349 |  |  |  | 92,376 |  |  |  | 302,730 |
Per basic unit |  |  | 0.85 |  |  |  | 0.17 |  |  |  | 0.65 |  |  |  | 0.72 |  |  |  | 2.39 |
Per diluted unit |  |  | 0.84 |  |  |  | 0.17 |  |  |  | 0.65 |  |  |  | 0.71 |  |  |  | 2.39 |
Cash provided by continuing operations |  |  | 57,307 |  |  |  | 200,458 |  |  |  | 3,241 |  |  |  | 82,904 |  |  |  | 343,910 |
Distributions to unitholders — declared |  | $ | 49,046 |  |  | $ | 49,045 |  |  | $ | 49,046 |  |  | $ | 77,551 |  |  | $ | 224,688 |

Year ended December 31, 2007 |  | Q1 |  |  | Q2 |  |  | Q3 |  |  | Q4 |  |  | Year |
Revenue |  | $ | 410,542 |  |  | $ | 122,005 |  |  | $ | 227,928 |  |  | $ | 248,726 |  |  | $ | 1,009,201 |
EBITDA (1) |  |  | 201,831 |  |  |  | 39,825 |  |  |  | 92,068 |  |  |  | 103,351 |  |  |  | 437,075 |
Earnings from continuing operations: |  |  | 158,067 |  |  |  | 25,722 |  |  |  | 69,702 |  |  |  | 89,329 |  |  |  | 342,820 |
Per basic unit |  |  | 1.26 |  |  |  | 0.20 |  |  |  | 0.55 |  |  |  | 0.71 |  |  |  | 2.73 |
Per diluted unit |  |  | 1.26 |  |  |  | 0.20 |  |  |  | 0.55 |  |  |  | 0.71 |  |  |  | 2.73 |
Net earnings: |  |  | 158,067 |  |  |  | 25,722 |  |  |  | 72,658 |  |  |  | 89,329 |  |  |  | 345,776 |
Per basic unit |  |  | 1.26 |  |  |  | 0.20 |  |  |  | 0.58 |  |  |  | 0.71 |  |  |  | 2.75 |
Per diluted unit |  |  | 1.26 |  |  |  | 0.20 |  |  |  | 0.58 |  |  |  | 0.71 |  |  |  | 2.75 |
Cash provided by continuing operations |  |  | 156,298 |  |  |  | 229,073 |  |  |  | 20,270 |  |  |  | 78,474 |  |  |  | 484,115 |
Distributions to unitholders — declared |  | $ | 71,682 |  |  | $ | 56,591 |  |  | $ | 49,046 |  |  | $ | 99,348 |  |  | $ | 276,667 |

(1) |  | Non-GAAP measure. See page 50.

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The Canadian drilling industry is subject to seasonality with activity peaking during the winter months in the fourth and first quarters. As temperatures rise in the spring, the ground thaws and becomes unstable. Government road bans severely restrict activity in the second quarter in Canada before equipment is moved for summer drilling programs in the third quarter. These seasonal trends typically lead to quarterly fluctuations in operating results and working capital requirements. In contrast the activity in the United States is not subject to the same level of seasonal interruptions and therefore impacts on operating results and working capital fluctuations are less volatile.
FOURTH QUARTER DISCUSSION
The global economic recession that began in the United States with the credit crisis significantly impacted the oil and natural gas commodity prices during the fourth quarter of 2008. However, the impact of lower commodity prices did not have an immediate impact on Precision’s activity as utilization rates held relatively strong for the first two months of the fourth quarter. Starting in December 2008 activity began to experience a significant downturn as a result of the decreased commodity prices. Generally, Precision’s expanding market presence in the United States land drilling market helped to mitigate the lower activity and earnings in Canada.
Net earnings in the fourth quarter ended December 31, 2008 were $92 million or $0.71 per diluted compared to $89 million or $0.71 per diluted unit in the fourth quarter of 2007.
Revenue for the fourth quarter of 2008 was $335 million, up 35% from $249 million in the fourth quarter of 2007. Earnings before income taxes for the fourth quarter of 2008 were $102 million, up 35% from $76 million in the fourth quarter of 2007. The increases resulted from the trend established during the third quarter of 2008 as customer demand from high commodity prices carried over to start the fourth quarter. However, by the end of the quarter, commodity prices had declined as the economic recession deepened and customer demand declined. Net earnings were reduced by income tax expense in the fourth quarter of 2008 of $10 million compared to an income tax benefit of $13 million in the last quarter of 2007.
The Trust’s organic growth in the United States, along with the completion of the acquisition of Grey Wolf on December 23, 2008, led to the growth in quarterly revenue and earnings before income taxes. Drilling rig utilization days in the United States increased to 3,248 days in the fourth quarter of 2008, up by 258% from the fourth quarter of 2007, while Canadian drilling rig utilization days increased during the same period by 419 days, up 5% from the fourth quarter of 2007. Overall, North American drilling rig utilization days for Precision totaled 12,314 in the fourth quarter of 2008, up by 29% from the fourth quarter of 2007.
The Trust reported total earnings before foreign exchange, interest, income taxes, depreciation and amortization (“EBITDA”) for the fourth quarter of 2008 of $135 million compared with $103 million for the fourth quarter of 2007.
Contract Drilling Services segment revenue of $261 million and EBITDA of $117 million increased by 50% and 41% respectively in the fourth quarter of 2008 compared to the same period in 2007. Average customer pricing in Canada was 8% higher in 2008 compared to the fourth quarter of 2007. Drilling rig utilization days, spud to rig release plus moving, for Precision in Canada in the fourth quarter of 2008 were 9,066, an increase of 5% compared with 8,647 in the same quarter in 2007. Utilization increased to 40% in the fourth quarter of 2008 compared with 34% a year ago. United States land drilling operations contributed 33% of the segment’s current quarter revenue compared to 12% in the same quarter of 2007. The increase in revenue in the United States was the result of Precision’s organic growth initiatives and the inclusion of Grey Wolf for eight days added $22 million in revenue during the quarter. LRG Catering followed Canadian industry trends and experienced an increase in revenue of 64% over the same prior year period.
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Completion and Production Services segment revenue of $80 million increased by 2% over the prior year while EBITDA of $26 million was 7% lower than the fourth quarter of 2007. Precision’s service rig operating hours during the fourth quarter of 2008 were 79,507 compared to 86,416 in 2007, a decrease of 8%. The reduction was a result of lower demand as customers scaled back production activity due to lower commodity prices, particularly natural gas wells. New well completions accounted for 36% of service rig operating hours in the fourth quarter compared to 33% in 2007 while production activity accounted for 58% of total hours compared to the prior year of 59%. The average rate per hour for the current year quarter was 6% higher than the prior year due to a flow through of a wage rate increase in October. Demand for rental equipment followed industry trends as revenue in the quarter was 6% higher than the fourth quarter of 2007 while revenue for the snubbing division was higher by 38% and the wastewater treatment division was higher by 44%.
Total operating costs increased from 51% of revenue in the fourth quarter of 2007 to 54% in 2008 due to wage increase for field personnel in October and higher fixed costs. During the quarter, excluding the effect of field wage increases, service rig costs per hour were up 8% while drilling rig costs per day were up by 6% over the prior year.
General and administrative expense for the fourth quarter of 2008 was $18 million, in-line with the same period in 2007. Lower costs associated with employee incentive compensation costs in 2008 and charges associated with workforce reductions in early November 2007 were offset by increased professional fees.
Depreciation and amortization expense in the fourth quarter of 2008 was $23 million compared with $25 million in the same period on 2007. Increased utilization in the current year and depreciation recorded on a higher asset base was offset by a 2007 charge of $7 million for decommissioned assets.
The Trust’s effective income tax rate on earnings before income taxes for fiscal 2008 was 11%, compared to 8% for 2007, before enacted tax rate reductions. Compared to a corporate income tax rate, the low effective income tax rate is primarily the result of the income trust structure shifting all or a portion of the income tax burden of the Trust to its unitholders.
During the fourth quarter of 2007 the Government of Canada enacted legislation reducing federal income tax rates to 15% by 2012. The enacted tax rate reductions resulted in a $20 million future income tax recovery in the fourth quarter of 2007.
In the fourth quarter of 2008 capital expenditures were $99 million, an increase of $62 million over the same period in 2007. Capital spending for the quarter included $31 million in upgrade and $68 million in expansion initiatives.
Fourth quarter monthly cash distributions declared were $0.13 per unit for aggregate quarterly cash distributions declared of $54 million or $0.39 per unit. In addition the Trust declared a special year-end distribution of $24 million or $0.15 per unit to be settled “in-kind”. The special “in-kind” distribution was made to minimize debt levels and increase balance sheet strength.
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CRITICAL ACCOUNTING ESTIMATES
This Management’s Discussion and Analysis of Precision’s financial condition and results of operations is based on Precision’s consolidated financial statements which are prepared in accordance with Canadian GAAP. These principles differ in certain respects from United States GAAP and these differences are described and quantified in Note 20 to the consolidated financial statements.
The Trust’s significant accounting policies are described in Note 2 to the consolidated financial statements. The preparation of the financial statements requires that certain estimates and judgments be made that affect the reported assets, liabilities, revenues and expenses. These estimates and judgments are based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Anticipating future events cannot be done with certainty, therefore, these estimates may change as new events occur, more experience is acquired and as the Trust’s operating environment changes.
Following are the accounting estimates believed to require the most difficult, subjective or complex judgments and which are the most critical to Precision’s reporting of results of operations and financial positions.
Allowance for Doubtful Accounts Receivable
Precision performs ongoing credit evaluations of its customers and grants credit based upon past payment history, financial condition and anticipated industry conditions. Customer payments are regularly monitored and a provision for doubtful accounts is established based upon specific situations and overall industry conditions. Precision’s history of bad debt losses has been within expectations and generally limited to specific customer circumstances. However, given the cyclical nature of the oil and natural gas industry in Canada, the current state of debt and equity markets and the inherent risk of successfully finding hydrocarbon reserves, a customer’s ability to fulfill its payment obligations can change suddenly and without notice. In cases where creditworthiness is uncertain, services are provided on receipt of cash in advance, on receipt of a letter of credit, on deposit of monies in trust or services are declined.
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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 2008, 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.
Income Taxes
The Trust and its subsidiaries follow the liability method which takes into account the differences between financial statement treatment and tax treatment of certain transactions, assets and liabilities. Future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Valuation allowances are established to reduce future tax assets when it is more likely than not that some portion or all of the asset will not be realized. Estimates of future taxable income and the continuation of ongoing prudent tax planning arrangements have been considered in assessing the utilization of available tax losses. Changes in circumstances and assumptions and clarifications of uncertain tax regimes may require changes to the valuation allowances associated with Precision’s future tax assets.
The business and operations of Precision are complex and Precision has executed a number of significant financings, business combinations, acquisitions and dispositions over the course of its history. The computation of income taxes payable as a result of these transactions involves many complex factors as well as Precision’s interpretation of relevant tax legislation and regulations. Precision’s management believes that the provision for income tax is adequate.
Long-term Incentive Plan Compensation
The Trust instituted annual long-term incentive plans which compensates officers and key employees through cash payments at the end of a three-year term. The compensation includes two components, a retention award and a performance award. The performance component is based on growth over the three-year term measured against targets as determined by the Compensation Committee of Precision. As a result of actual results in the subsequent years, the accrued amount for the performance component may be reduced or increased.
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NEW ACCOUNTING STANDARDS
The Canadian Institute of Chartered Accountants (“CICA”) issued certain new accounting standards which will be in effect for fiscal years beginning on or after January 1, 2009 for recognition and measurement of goodwill and intangibles and accounting for business combinations:

• |  | Section 3064, “Goodwill and Intangible Assets” establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. The new Section is not anticipated to have a significant impact on the consolidated financial statements;
• |  | Section 1582 “Business Combinations” will require most assets acquired and liabilities assumed, including contingent liabilities to be measured at fair value and that all acquisition costs to be expensed.

In addition two new Sections were added with an effective date of January 1, 2011 with early adoption permitted, consolidated financial statements and non-controlling interests:

• |  | Section 1602 “Non-controlling Interests” will require that non-controlling interests be recognized as a separate component of equity and that net earnings be calculated without a deduction for non-controlling interest;
• |  | Section 1601 “Consolidated Financial Statements” establishes standards for the preparation of consolidated financial statements.

The Trust is currently evaluating the impact of the new Sections, 1582, 1602, and 1601 on its consolidated financial statements.
TRANSITION TO INTERNATIONAL FINANCIAL REPORTING STANDARDS:
In February 2008, the CICA Accounting Standards Board (“AcSB”) confirmed the transition from Canadian Generally Accepted Accounting Principles (“GAAP”) to International Financial Reporting Standards (“IFRS”) for all Publicly Accountable Enterprises (“PAE”). PAE include listed companies and any other organizations that are responsible to large or diverse groups of stakeholders, including non-listed financial institutions, securities dealers and many cooperative enterprises. The goal of IFRS is to improve financial reporting internationally by establishing a single set of high-quality, consistent, and comparable reporting standards.
The Trust will be required to report its financial results in accordance with IFRS from January 1, 2011, the changeover date set by AcSB. IFRS compliant comparative financial information for one year will be required on the effective date, therefore the transition date for adoption of IFRS is January 1, 2010, determined in accordance with IFRS 1, First Time Adoption of International Financial Reporting Standards.
Although many elements of Canadian GAAP and IFRS are similar, the Trust expects its transition to IFRS to take considerable effort. Precision has established a project team and steering committee to oversee the transition to IFRS. A preliminary assessment of the impact of IFRS on the financial reporting processes has been completed. Planning is currently underway to address the identified differences.
The key areas identified that affect financial reporting under IFRS for the Trust are:

• |  | Capital asset componentization
• |  | Financial statement disclosure
• |  | Provisions
• |  | Asset Impairments
• |  | IFRS 1 — first time adoption

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A summary of significant activities and deadlines within the plan along with their current status is as follows:

| Key Activity |  |  | Deadlines/Milestones |  |  | Status at December 31, 2008 |
| Financial Statement Preparation: |  |  |  |  |  |  |
| • Identify differences in Canadian GAAP/IFRS accounting policies • Select entity’s continuing IFRS policies • Select entity’s IFRS 1 choices • Develop financial statement format • Quantify IFRS 1 disclosures for 2010 |  |  | • Identify Canadian GAAP/IFRS differences Q4, 2008 • Identify and evaluate IFRS 1 options Q2, 2009 • Identify disclosure requirements under IFRS Q4, 2009 • Ready for complete IFRS reporting in 2011 financial year including comparative financial statements for 2010 financial year |  |  | • Diagnostic assessment completed to identify differences between Canadian GAAP and IFRS as applicable to Precision • Possible significant accounting policy choices and IFRS 1 elections identified |
| Infrastructure: |  |  |  |  |  |  |
| • Determine and develop IFRS expertise needed at all levels within the entity • Determine and implement information technology changes needed to be fully IFRS compliant |  |  | • Identify and train IFRS project team Q1, 2009 • Ready for parallel processing of 2010 general ledger using IFRS accounting procedures, Q1 2010 |  |  | • IFRS training delivered to project team and key stakeholders within Precision in February 2009 • Information technology impact assessment completed and system configuration changes to commence Q3, 2009 |
| Business Policy Assessment: |  |  |  |  |  |  |
| • Identify impact on financial covenants and renegotiate/ redefine as needed • Identify impact on compensation plans and change as required • Evaluate impact on customer and supplier contracts |  |  | • Impact of IFRS on debt covenants to be determined • Review compensation plans by Q4, 2010 • Renegotiate and amend customer and supplier contracts by Q3, 2010 if needed |  |  | • Assessment of impact of IFRS conversion on compensation plans, debt covenants and customer and supplier contracts has not yet commenced |
| Control Environment: |  |  |  |  |  |  |
| • Assess impact on design and effectiveness of internal control over financial reporting • Assess impact on design and effectiveness of disclosure controls and procedures |  |  | • Update business process and information technology controls documentation timing to be determined • Update CEO/CFO certifications process by end of Q4, 2010 for SOX 302 |  |  | • Identification of material process changes underway |

A number of projects are currently underway between the International Accounting Standards Board, the United States Financial Standards Board and the AcSB in order to converge GAAP (both U.S. and Canadian) with IFRS. These projects may result in new pronouncements or change existing standards and as a result IFRS as at the transition date may differ from its current form.
The above disclosure is made keeping in mind the Trust’s circumstances as of today in order to help stakeholders understand the impact of the transition on various aspects of financial reporting. The Trust’s circumstances may change during the course of the project resulting in the need to change some or all of the key activities and deadlines/milestones disclosed above.
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BUSINESS RISKS
The discussion of risk that follows is not a complete representation. Additional information related to risks is disclosed in the 2008 Annual Information Form filed with SEDAR and available at www.sedar.com. Also refer to the “Cautionary Statement Regarding Forward-Looking Information and Statements” on page 52.
Certain activities of Precision are affected by factors that are beyond its control or influence. The drilling rig, camp and catering, service rig, snubbing, rentals, wastewater treatment and related service businesses and activities of Precision in Canada and the drilling rig, camp and catering and rentals business and activities of Precision in the United States are directly affected by fluctuations in exploration, development and production activity carried on by its customers which, in turn, is dictated by numerous factors including world energy prices and government policies. The addition, elimination or curtailment of government regulations and incentives could have a significant impact on the oil and natural gas business in Canada and the United States. These factors could lead to a decline in the demand for Precision’s services, resulting in a material adverse effect on revenues, cash flows, earnings and cash distributions to unitholders.
Crude Oil and Natural Gas Prices
Precision sells its services to oil and natural gas exploration and production companies. 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. However, recent developments in the transportation of liquefied natural gas (“LNG”) in ocean going tanker ships have introduced an element of globalization to the natural gas market. Crude oil and natural gas prices are quite volatile, which accounts for much of the cyclical nature of the oilfield services business.
Worldwide military, political and economic events, including initiatives by the Organization of the Petroleum Exporting Countries and other major petroleum exporting countries, for instance, 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, United States and Canadian natural gas 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. A prolonged reduction in oil and natural gas prices would likely 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 write down for accounting purposes, Precision’s ability to retain skilled rig personnel and Precision’s ability to obtain access to capital to finance and grow its businesses. There can be no assurance that the future level of demand for Precision’s services or future conditions in the oil and natural gas and oilfield services industries will not decline.
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. The collection of receivables may be adversely affected by any prolonged weakness in oil and natural gas prices.
Workforce Availability
Precision may not be able to find enough skilled labor to meet its needs, which could limit its growth. As a result, Precision may have problems finding enough skilled and unskilled laborers in the future if demand for its services increases. If Precision is not able to increase its service rates sufficiently to compensate for similar wage rate increases, its operating results may be adversely affected.
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Business is Seasonal and Highly Variable
In Canada and the northern part of the United States, the level of activity in the oilfield service industry is influenced by seasonal weather patterns. During the spring months, wet weather and the spring thaw make the ground unstable. Consequently, municipalities and counties and provincial and state transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels and placing an increased level of importance on the location of Precision’s equipment prior to imposition of the road bans. The timing and length of road bans is 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 western Canada that are inaccessible, other than during the winter months, because the ground surrounding or containing the drilling sites in these areas consists of terrain known as muskeg. Until the muskeg freezes, the rigs and other necessary equipment cannot cross the terrain to reach the drilling site. Moreover, once the rigs and other equipment have been moved to a drilling site, they may become stranded or otherwise unable to relocate to another site should the muskeg thaw unexpectedly. Precision’s business results depend, at least in part, upon the severity and duration of the winter season.
Deteriorating Conditions in the Credit Markets May Adversely Affect Business
The ability to make scheduled payments on or to refinance debt obligations depends on the financial condition and operating performance of the Trust, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond its control. The credit markets have recently experienced and continue to experience adverse conditions. Continuing volatility in the credit markets may increase costs associated with debt instruments due to increased spreads over relevant interest rate benchmarks, or affect the Trust’s, or third parties it seeks to do business with, ability to access those markets. The Trust may be unable to maintain a level of cash flow from operating activities sufficient to permit it to pay the principal, premium, if any, and interest on its indebtedness.
In addition, there has been substantial uncertainty in the capital markets and access to financing is uncertain. These conditions could have an adverse effect on the industry in which the Trust operates and its business, including future operating results. Precision’s customers may curtail their drilling programs, which could result in a decrease in demand for drilling rigs and a reduction in dayrates, reduction in the number and profitability of turnkey jobs and/or utilization. In addition, certain customers could experience an inability to pay suppliers, including the Trust, in the event they are unable to access the capital markets to fund their business operations.
Technology
Complex drilling programs for the exploration and development of remaining conventional and unconventional oil and natural gas reserves in North America demand high-performance drilling rigs. The ability of drilling rig service providers to meet this demand will depend on continuous improvement of existing rig technology such as drive systems, control systems, automation, mud systems and top drives to improve drilling efficiency. Precision’s ability to deliver equipment and services that are more efficient is critical to continued success. There is no assurance that competitors will not achieve technological improvements that are more advantageous, timely or cost effective than improvements developed by Precision.
Precision is Subject to Various Risks from its Foreign Operations
Precision conducts a material portion of its business in the United States and is subject to risks inherent in such operations, such as: fluctuations in currency and exchange controls; increases in duties and taxes; and changes in laws and policies governing operations. In addition, in the United States jurisdictions in which Precision operates, it is subject to various laws and regulations that govern the operation and taxation of its businesses in such jurisdictions and the imposition, application and interpretation of which laws and regulations can prove to be uncertain.
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Customer Merger and Acquisition Activity
Merger and acquisition activity in the oil and natural gas exploration and production sector can impact demand for Precision’s services as customers focus on internal reorganization activities prior to committing funds to significant drilling and capital maintenance projects.
Competitive Industry
The contract drilling business is highly competitive with numerous industry participants, and the drilling contracts Precision competes for are usually awarded on the basis of competitive bids. Management believes pricing and rig availability are the primary factors considered by Precision’s potential customers in determining which drilling contractor to select.
Capital Overbuild in the Drilling Industry
Because of the long life nature of drilling equipment and the lag between the moment a decision to build a rig is made and the moment the rig is placed into service, the number of rigs in the industry does not always correlate to the level of demand for those rigs. Periods of high demand often spur increased capital expenditures on rigs, and those capital expenditures may exceed actual demand. Management believes that there is currently an excess of rigs in the North American oil and gas industry in relation to current levels of demand. This capital overbuild could cause Precision’s competitors to lower their rates and could lead to a decrease in rates in the oilfield services industry generally, which would have an adverse effect on the revenues, cash flows and earnings of the Trust.
Distributions on the Trust Units are Variable
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 upgrade capital expenditures and future expansion capital expenditure requirements for the purchase of property, plant and equipment; tax obligations; the impact of interest rates and/or foreign exchange rates; the growth of the general economy; the price of crude oil and natural gas; weather; and number of Trust units and exchangeable LP units issued and outstanding. Cash distributions may be increased, reduced or suspended or eliminated entirely depending on the Trust’s operations and the performance of its assets. The market value of the Trust units may deteriorate if the Trust is unable to meet cash distribution expectations in the future, and that deterioration may be material.
Distributions on the Trust Units Have Been Suspended and May Not Be Reinstated
On February 9, 2009, the Trust announced that it had suspended cash distributions for an indefinite period. The Trust’s ability to resume making cash distributions in the future and the actual cash flow available for distribution to unitholders, if any, is a function of numerous factors including, among other things, the Trust’s, Precision’s and Precision Drilling Limited Partnership’s financial performance; debt covenants and obligations; working capital requirements; future upgrade capital expenditures and future expansion capital expenditure requirements for the purchase of property, plant and equipment; tax obligations; the impact of interest rates and/or foreign exchange rates; the growth of the general economy; the price of crude oil and natural gas; weather; and number of Trust units and exchangeable LP units issued and outstanding. Cash distributions may or may not be reinstated, may be reinstated at amounts different than historical or recent amounts (and subsequently increased or reduced) or may be eliminated entirely depending on the Trust’s operations and the performance of its assets. The market value of the Trust units may deteriorate if the Trust is unable to reinstate its cash distributions or otherwise meet cash distribution expectations in the future, and that deterioration may be material.
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Precision May Not Be Able to Obtain Financing or Obtain Financing on Acceptable Terms
Because of the Deterioration of the Credit and Capital Markets
On February 19th, Precision announced that the Senior Note Offering had been postponed due to currently unfavourable market conditions. Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. The re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding on acceptable terms, if at all. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to Precision’s current debt and reduced and, in some cases, ceased to provide funding to borrowers.
If Precision’s business does not generate sufficient cash flow from operations to enable it to pay its indebtedness or to fund its other liquidity needs, then, as a consequence of these changes in the credit markets, Precision cannot assure that future borrowings will be available to it under its credit facilities in sufficient amounts, either because Precision’s lending counterparties may be unwilling or unable to meet their funding obligations or because Precision’s borrowing base may decrease as a result of lower asset valuations, operating difficulties, lending requirements or regulations, or for any other reason. Moreover, even if lenders and institutional investors are willing and able to provide adequate funding, interest rates may rise in the future and therefore increase the cost of borrowing Precision incurs on any of its floating rate debt. Finally, Precision may need to refinance all or a portion of its indebtedness on or before maturity, sell assets, reduce or delay capital expenditures, seek additional equity financing or seek third-party financing to satisfy such obligations. Precision cannot assure that it will be able to refinance any of its indebtedness on commercially reasonable terms or at all. There can be no assurance that Precision’s business, liquidity, financial condition, or results of operations will not be materially and adversely impacted in the future as a result of the existing or future credit market conditions.
Tax Consequences of Previous Transactions Completed by Precision
The business and operations of Precision prior to completion of the Plan of Arrangement pursuant to which former shareholders of Precision were issued Trust Units 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 these transactions involves many complex factors as well as Precision’s interpretation of relevant tax legislation and regulations. 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 without penalties could be up to $382 million as of December 31, 2008. Any increase in tax liability would reduce the net assets of and funds available to the Trust.
The Trust received Notices of Reassessment from a provincial taxing authority relating to a prior period tax filing position in the total amount of $58 million as of December 31, 2008. This $58 million has been paid, recorded as a long-term receivable and included in the $382 million tax contingency disclosed in the preceding paragraph. The income tax-related portion of the applicable reassessments and the interest portion are $38 million and $20 million, respectively.
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Access to Additional Financing
Precision may find it necessary in the future to obtain additional debt or equity financing through the Trust to support ongoing operations, to undertake capital expenditures, to repay existing indebtedness or to undertake acquisitions or other business combination transactions. There can be no assurance that additional financing will be available to Precision when needed or on terms acceptable or favourable to Precision. Precision’s inability to raise financing to support ongoing operations or to fund capital expenditures, acquisitions, debt repayments or other business combination transactions could limit Precision’s growth and may have a material adverse effect upon Precision.
Taxation of Distributions
In June 2007 the Government of Canada’s Bill C-52 Budget Implementation Act 2007 was enacted and included legislative provisions that impose a tax on certain distributions from publicly traded specified investment flow-through (“SIFT”) trusts at a rate equal to the applicable federal corporate tax rate plus a provincial SIFT tax factor. After the enactment of federal tax rate reductions in December 2007 the combined SIFT tax would be 29.5% in 2011, reducing to 28% in 2012. Precision will be a SIFT trust on the earlier of January 1, 2011 or the first day after it exceeds the normal growth guidelines announced by the federal Department of Finance on December 15, 2006.
Environmental
There is growing concern about the apparent connection between the burning of fossil fuels and climate change. The issue of energy and the environment has created intense public debate in Canada and around the world in recent years that is likely to continue for the foreseeable future and could potentially have a significant impact on all aspects of the economy including the demand for hydrocarbons and resulting in lower demand for Precision’s services.
United States Dollar Exchange Exposure
Precision’s operations in the United States have revenue, expenses, assets and liabilities denominated in United States dollars. As a result Precision’s income statement, balance sheet and statement of cash flow are impacted by changes in exchange rates between Canadian and United States currencies.

• |  | Translation of United States Subsidiaries
|  | Precision’s United States operations are considered self-sustaining operations and will be translated into Canadian dollars using the current rate method. Under this method, the assets and liabilities of Precision’s operations in the United States will be recorded in the consolidated financial statements at the exchange rate in effect at the balance sheet dates and the unrealized gains and losses will be included in other comprehensive income, a component of unitholders’ equity. As a result, changes in the Canadian to United States dollar exchange rates will increase or decrease Precision’s United States dollar denominated net assets on consolidation which will increase or decrease unitholders’ equity. The translation will increase and decrease Precision’s United States dollar assets and liabilities as a result of changes in foreign exchange rates which could have a material impact on the amounts recorded in the balance sheet. In addition, under certain circumstances Canadian GAAP requires foreign exchange gains and losses that are accumulated in other comprehensive income to be recorded as a foreign exchange gain or loss in the statement of earnings.
|  | Precision’s United States operations generate revenue and incur expenses in United States dollars and the United States dollar based earnings are converted into Canadian dollars for purposes of financial statement consolidation and reporting. The conversion of the United States dollar based revenue and expenses to a Canadian dollar basis does not result in a foreign exchange gain or loss but does result in lower or higher net earnings from United States operations than would have occurred had the exchange rate not changed. If the Canadian dollar strengthens versus the United States dollar, the Canadian dollar equivalent of net earnings from United States operations will be negatively impacted. Precision does not currently hedge any of its exposure related to the translation of United States dollar based earnings into Canadian dollars.

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• |  | Transaction Exposure
|  | Precision has long-term debt denominated in United States dollars. This debt is converted at the exchange rate in effect at the balance sheet dates with the resulting gains or losses included in the statement of earnings as “foreign exchange”. If the Canadian dollar weakens versus the United States dollar, Precision will incur a foreign exchange loss from the translation of this debt. Currently, Precision has not designated any of this debt as a hedge against the net asset position of its self-sustaining United States operations.
|  | The vast majority of Precision’s United States operations are transacted in United States dollars. Transactions for Precision’s Canadian operations are primarily transacted in Canadian dollars. However, Precision occasionally purchases goods and supplies in United States dollars. These transactions and foreign exchange exposure would not typically have a material impact on the Canadian operations’ financial results.

Safety Risk
Standards for the prevention of incidents in the oil and gas industry are governed by service company safety policies and procedures, accepted industry safety practices, customer specific safety requirements, and health and safety legislation. Management believes that Precision’s drilling and well servicing businesses are highly competitive with numerous competitors. A key factor considered by Precision’s customers in selecting oilfield service providers is safety. Deterioration in Precision’s safety performance could result in a decline in the demand for Precision’s services and could have a material adverse effect on its revenues, cash flows, profitability and funds available for distributions.
Dependence on Third Party Suppliers
Precision sources certain key rig components, raw materials, equipment and component parts from a variety of suppliers located in Canada, the United States and overseas. Precision also outsources some or all services for the construction of drilling and service rigs. While alternate suppliers exist for most of these components, materials, equipment, parts and services, cost increases, delays in delivery due to high activity or other unforeseen circumstances may be experienced. Precision maintains relationships with a number of key suppliers and contractors, maintains an inventory of key components, materials, equipment and parts and orders long lead time components in advance. However, if the current or alternate suppliers are unable to provide or deliver the necessary components, materials, equipment, parts and services, any resulting delays by Precision in the provision of services to its customers may have a material adverse effect on Precision’s business, results of operations, prospects and funds available for distributions.
Significant Debt and Potential Material Adverse Effect on Financial Position and Limit on Future Operations
The Trust and its subsidiaries have a significant amount of debt as a result of the financing of the Acquisition. As of December 31, 2008, the Trust’s total outstanding long-term debt was $1,577 million.
The Trust’s substantial debt could have a material adverse effect on its financial condition and results of operations as well as on the distributions that the Trust may pay to unitholders. In particular, it could:

• |  | increase the Trust’s vulnerability to general adverse economic and industry conditions and require it to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of its cash flow to fund working capital, capital expenditures, acquisitions, other debt service requirements, distributions to unitholders and other general corporate purposes;

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• |  | decrease the Trust’s ability to satisfy our obligations under our credit facilities or other indebtedness and, if we fail to comply with these requirements, an event of default could result;
• |  | increase our vulnerability to covenants relating to our indebtedness which may limit our ability to obtain additional financing for working capital, capital expenditures and other general corporate activities;
• |  | increase the Trust’s exposure to risks inherent in interest rate fluctuations and changes in credit ratings or statements from rating agencies because certain of its borrowings (including borrowings under the Credit Facilities) are at variable rates of interest, which would result in higher interest expense to the extent the Trust has not hedged these risks against increases in interest rates;
• |  | increase the Trust’s exposure to exchange rate fluctuations because a change in the value of the Canadian dollar against the United States dollar will result in an increase or decrease in the Trust’s United States dollar denominated debt, as expressed in Canadian dollars, as well as in the related interest expense;
• |  | increase our vulnerability to covenants relating to our indebtedness that may limit the Trust’s flexibility in planning for, or reacting to, changes in its business or the industry in which it operates;
• |  | place the Trust at a competitive disadvantage compared to its competitors that have less debt;
• |  | limit the Trust’s ability to borrow additional funds to meet its operating expenses, to make acquisitions and for other purposes; and
• |  | limit the Trust’s ability to construct, purchase or acquire new rigs.

The Trust and its subsidiaries may be able to incur substantial additional debt in the future, including additional secured debt pursuant to the Credit Facilities and under operating facilities. This could further exacerbate the risks associated with its substantial debt.
Precision Will Require Significant Amounts of Cash to Service Indebtedness
Precision will require significant amounts of cash in order to service and repay indebtedness. The ability to generate cash in the future will be, to a certain extent, subject to general economic, financial, competitive and other factors that may be beyond management’s control. In addition, the ability to borrow funds in the future to service debt will depend on covenants in the Credit Facilities and other debt agreements which may be entered into in the future. Future borrowings may not be available to the Trust or Precision under the Credit Facilities or from the capital markets in amounts sufficient to enable the Trust or Precision to pay obligations as they mature or to fund other liquidity needs (including the required repayments on the Unsecured Facility and the Secured Facility). If Precision is not able to obtain such borrowings or generate cash flow from operations in an amount sufficient to enable it to service and repay indebtedness, the Trust and Precision will need to refinance indebtedness or they will be in default under the agreements governing indebtedness. Such refinancing may not be available on favourable terms or at all. The inability to service, repay and/or refinance indebtedness could negatively impact the Trust’s financial condition and results of operations.
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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, 2008, 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, 2008.
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.
With the acquisition of Grey Wolf occurring close to the fiscal year end management of Precision is not required to conclude on the effectiveness of disclosure controls and procedures within Grey Wolf. As such, the principal executive officer and principal financial accounting officer have not concluded on the design and effectiveness of disclosure controls and procedures in Grey Wolf.
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with Canadian GAAP, including a reconciliation to U.S. GAAP.
Under the supervision and with the participation of management, including the CEO and CFO, Precision conducted an evaluation of the design and effectiveness of our internal control over financial reporting as of the end of the fiscal year based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. On December 23, 2008 Precision acquired Grey Wolf and began consolidating the operations from that date. Based on the proximity of this acquisition to year end management has excluded this business from its evaluation of the effectiveness of Precision’s internal control over financial reporting as of December 31, 2008. The net earnings attributable to this business represented approximately one per cent of Precision’s consolidated net earnings for the year ended December 31, 2008, and its aggregate total assets represented approximately 56% of the consolidated total assets as at December 31, 2008.
Based on this evaluation, management concluded that as of December 31, 2008, Precision maintained effective internal control over financial reporting.
NON-GAAP MEASURES
Precision uses certain measures that are not recognized under Canadian generally accepted accounting principles to assess performance and believe these non-GAAP measures provide useful supplemental information to investors. Following are the non-GAAP measures Precision uses in assessing performance.
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EBITDA
Management believes that in addition to earnings from continuing operations, EBITDA as derived from information reported in the Consolidated Statements of Earnings and Deficit is a useful supplemental measure as it provides an indication of the results and cash generated by Precision’s principal business activities prior to consideration of how those activities are financed, how the results are taxed, how funds are invested or how foreign exchange and non-cash depreciation and amortization charges affect results.
The following table provides a reconciliation of earnings from continuing operations under GAAP as disclosed in the Consolidated Statement of Earnings and Deficit to EBITDA.

Years ended December 31, |  |  |  |  |  |  |  |  |  |
(Stated in thousands of Canadian dollars) |  | 2008 |  |  |  | 2007 |  |  | 2006 |
EBITDA |  | $ | 436,536 |  |  |  | $ | 437,075 |  |  | $ | 668,160 |
Add (deduct): |  |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | (83,829 | ) |  |  |  | (78,326 | ) |  |  | (73,234 | )
Foreign exchange |  |  | 2,041 |  |  |  |  | (2,398 | ) |  |  | 353 |
Interest: |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt |  |  | (14,478 | ) |  |  |  | (7,767 | ) |  |  | (8,800 | )
Other |  |  | (151 | ) |  |  |  | (106 | ) |  |  | (171 | )
Income |  |  | 455 |  |  |  |  | 555 |  |  |  | 942 |
Other |  |  | — |  |  |  |  | — |  |  |  | 408 |
Income taxes |  |  | (37,844 | ) |  |  |  | (6,213 | ) |  |  | (15,146 | )
Earnings from continuing operations |  | $ | 302,730 |  |  |  | $ | 342,820 |  |  | $ | 572,512 |

Operating Earnings
Management believes that in addition to earnings from continuing operations, operating earnings as reported in the Consolidated Statements of Earnings and 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.

Years ended December 31, |  |  |  |  |  |  |  |  |  |
(Stated in thousands of Canadian dollars) |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Operating earnings |  | $ | 354,748 |  |  |  | $ | 356,351 |  |  | $ | 595,279 |
Add (deduct): |  |  |  |  |  |  |  |  |  |  |  |  |
Interest: |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt |  |  | (14,478 | ) |  |  |  | (7,767 | ) |  |  | (8,800 | )
Other |  |  | (151 | ) |  |  |  | (106 | ) |  |  | (171 | )
Income |  |  | 455 |  |  |  |  | 555 |  |  |  | 942 |
Other |  |  | — |  |  |  |  | — |  |  |  | 408 |
Income taxes |  |  | (37,844 | ) |  |  |  | (6,213 | ) |  |  | (15,146 | )
Earnings from continuing operations |  | $ | 302,730 |  |  |  | $ | 342,820 |  |  | $ | 572,512 |

Standardized Distributable Cash, Distributable Cash from Continuing Operations, Standardized Distributable Cash per Diluted Unit and Distributable Cash from Continuing Operations per Diluted Unit
Management believes that in addition to cash provided by continuing operations, standardized distributable cash and distributable cash from continuing operations are useful supplemental measures. They provide an indication of the funds available for distribution to unitholders after consideration of the impacts of capital expenditures and long-term unfunded contractual obligations. In prior years, instead of deducting total capital expenditures in the calculation of distributable cash, Precision only excluded upgrade capital but as a result of new guidance expansion capital is now also deducted.
Precision’s method of calculating these measures may differ from other entities and, accordingly, may not be comparable to measures used by other entities. Investors should be cautioned that these measures should not be construed as an alternative to measures determined in accordance with GAAP as an indicator of Precision’s performance.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS
This Annual Report contains certain forward-looking information and statements, including statements relating to matters that are not historical facts and statements of our beliefs, intentions and expectations about developments, results and events which will or may occur in the future, which constitute “forward-looking information” within the meaning of applicable Canadian securities legislation and “forward-looking statements” within the meaning of the “safe harbor” provisions of the United States Private Securities Litigation Reform Act of 1995 (collectively the “forward-looking information and statements”). Forward-looking information and statements are typically identified by words such as “anticipate”, “could”, “should”, “expect”, “seek”, “may”, “intend”, “likely”, “will”, “plan”, “estimate”, “believe” and similar expressions suggesting future outcomes or statements regarding an outlook.
Forward-looking information and statements are included throughout this Annual Report including under the headings “Overview and Outlook”, “Dynamics of the Oilfield Services Industry”, “Precision’s Development”, “Financial Results”, “Critical Accounting Estimates, New Accounting Standards and Business Risks” and “Disclosure Controls and Procedures” and include, but are not limited to statements with respect to: 2009 expected cash provided by continuing operations; 2009 capital expenditures, including the amount and nature thereof; suspension of distributions on Trust units and payments on exchangeable LP units; performance of the oil and natural gas industry, including oil and natural gas commodity prices and supply and demand; expansion, consolidation and other development trends of the oil and natural gas industry; impact of rising demand in directional and horizontal well programs; demand for and status of drilling rigs and other equipment in the oil and natural gas industry; costs and financial trends for companies operating in the oil and natural gas industry; energy consumption trends; our business strategy, including the 2009 strategy and outlook for our business segments; impact of diversification of our earnings base, and focus on safety and operating performance, the size and capabilities of our drilling and service rig fleet, our market share and our position in the markets in which we operate; demand for our products and services; labour shortages; climatic conditions; the maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies and tax liabilities; expected payments pursuant to contractual obligations; the prospective impact of recent or anticipated regulatory changes; financing strategy and compliance with debt covenants; expected results of cash conservation measures; credit risks; and other such matters.
All such forward-looking information and statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. These statements are, however, subject to known and unknown risks and uncertainties and other factors. As a result, actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking information and statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information and statements will transpire or occur, or if any of them do so, what benefits will be derived therefrom. These risks, uncertainties and other factors include, among others: the impact of general economic conditions in Canada and the United States; world energy prices and government policies; the availability of credit and equity globally to both Precision and the oil and gas companies that are its customers; consumer confidence and the duration of any recessionary period; industry conditions, including capital spending decisions, priority placed on high-performance rigs in shale-type plays; the adoption of new environmental, taxation and other laws and
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regulations and changes in how they are interpreted and enforced; the impact of initiatives by the Organization of Petroleum Exporting Countries and other major petroleum exporting countries; the effect of weather conditions on operations and facilities; the existence of operating risks inherent in well servicing, contract drilling and ancillary oilfield services; volatility of oil and natural gas prices; oil and natural gas product supply and demand; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; consolidation among our customers; risks associated with technology; political uncertainty, including risks of war, hostilities, civil insurrection, instability or acts of terrorism; the lack of availability of qualified personnel or management; credit risks; increased costs of operations, including costs of equipment; fluctuations in interest rates; stock market volatility; safety performance; foreign operations; foreign currency exposure; dependence on third party suppliers; opportunities available to or pursued by us; and other factors, many of which are beyond our control.
These risk factors are discussed in the Annual Information Form and Form 40-F on file with the Canadian securities commissions and the United States Securities and Exchange Commission and are available on SEDAR at www.sedar.com and the website of the United States Securities and Exchange Commission at www.sec.gov, respectively. Except as required by law, Precision Drilling Trust, Precision Drilling Limited Partnership and Precision Drilling Corporation disclaim any intention or obligation to update or revise any forward-looking information or statements, whether as a result of new information, future events or otherwise.
The forward-looking information and statements contained in this Annual Report are expressly qualified by this cautionary statement.
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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, 2008 to December 31, 2007 and the years ended December 31, 2007 to December 31, 2006. Note 20 to the consolidated financial statements describes the impact on the consolidated financial statements of significant differences between Canadian and United States GAAP.
Management is responsible for establishing and maintaining adequate internal control over the Trust’s financial reporting and is supported by an internal audit function who conducts periodic testing of these controls. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external reporting purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with direction from our principal executive officer and principal financial and accounting officer, management conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting. Management’s evaluation of internal control over financial reporting was based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trust acquired Grey Wolf, Inc. on December 23, 2008 and began consolidating the financial results from date of acquisition. Management has excluded this business from its evaluation of the effectiveness of the Trust’s internal control over financial reporting as at December 31,2008. Based on this evaluation, management concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2008. Also management determined that there were no material weaknesses in the Trust’s internal control over financial reporting as of December 31, 2008.
KPMG LLP, an independent firm of Chartered Accountants, was engaged, as approved by a vote of unitholders at the Trust’s most recent annual meeting, to audit the consolidated financial statements and provide an independent professional opinion.
KPMG LLP completed an audit of the design and effectiveness of the Trust’s internal control over financial reporting as of December 31, 2008, as stated in their report included herein and expressed an unqualified opinion on design and effectiveness of internal control over financial reporting as of December 31, 2008.
The Audit Committee of the Board of Directors, which is comprised of five independent directors who are not employees of the Trust, provides oversight to the financial reporting process. Integral to this process is the Audit Committee’s review and discussion with management and the external auditors of the quarterly and annual financial statements and reports prior to their respective release. The Audit Committee is also responsible for reviewing and discussing with management and the external auditors major issues as to the adequacy of the Trust’s internal controls. The external auditors have unrestricted access to the Audit Committee to discuss their audit and related matters. The consolidated financial statements have been approved by the Board of Trustees on the recommendation of the Board of Directors of Precision Drilling Corporation and its Audit Committee.

Kevin A. Neveu |  | Doug J. Strong
Chief Executive Officer |  | Chief Financial Officer
Precision Drilling Corporation, |  | Precision Drilling Corporation,
Administrator to Precision Drilling Trust |  | Administrator to Precision Drilling Trust
March 23, 2009 |  | March 23, 2009

54 CONSOLIDATED FINANCIAL STATEMENTS

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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, 2008 and 2007 and the consolidated statements of earnings and deficit, comprehensive income and cash flow for each of the years in the three-year period ended December 31, 2008. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2008 and 2007 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2008 in accordance with Canadian generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 23, 2009 expressed an unqualified opinion on the effectiveness of the Trust’s internal control over financial reporting.
Chartered Accountants
Calgary, Canada
March 23, 2009
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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 Precision Drilling Trust’s (the “Trust”) internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trust’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report to the Unitholders. Our responsibility is to express an opinion on the Trust’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
The Trust acquired Grey Wolf, Inc. during 2008, and management excluded from its assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2008, Grey Wolf, Inc.’s internal control over financial reporting associated with total assets of $2,724 million and total revenue of $22 million included in the consolidated financial statements of the Trust as of and for the year ended December 31, 2008. Our audit of internal control over financial reporting of the Trust also excluded an evaluation of the internal control over financial reporting of Grey Wolf, Inc.
We also have conducted our audits on the consolidated financial statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Our report dated March 23, 2009 on the consolidated balance sheets of the Trust as of December 31, 2008 and 2007, and the related consolidated statements of earnings and deficit, comprehensive income and cash flow for each of the years in the three-year period ended December 31, 2008 expressed an unqualified opinion on those consolidated financial statements.
Chartered Accountants
Calgary, Canada
March 23, 2009
56 CONSOLIDATED FINANCIAL STATEMENTS

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Precision Drilling Trust
CONSOLIDATED BALANCE SHEETS
As at December 31,

(Stated in thousands of Canadian dollars) |  |  |  |  |  | 2008 |  |  |  | 2007 |
ASSETS |  |  |  |  |  |  |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |  |  |  |  |  |  |
Cash |  |  |  |  |  | $ | 61,511 |  |  |  | $ | — |
Accounts receivable |  | (Note 24) |  |  | 601,753 |  |  |  |  | 256,616 |
Income tax recoverable |  |  |  |  |  |  | 13,313 |  |  |  |  | 5,952 |
Inventory |  |  |  |  |  |  | 8,652 |  |  |  |  | 9,255 |
|  |  |  |  |  |  | 685,229 |  |  |  |  | 271,823 |
Income tax recoverable |  |  |  |  |  |  | 58,055 |  |  |  |  | — |
Property, plant and equipment, net of accumulated depreciation |  | (Note 4) |  |  | 3,243,213 |  |  |  |  | 1,210,587 |
Intangibles |  | (Note 5) |  |  | 5,676 |  |  |  |  | 318 |
Goodwill |  | (Note 6) |  |  | 841,529 |  |  |  |  | 280,749 |
|  |  |  |  |  | $ | 4,833,702 |  |  |  | $ | 1,763,477 |
LIABILITIES AND UNITHOLDERS’ EQUITY |  |  |  |  |  |  |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |
Bank indebtedness |  | (Note 7) |  | $ | — |  |  |  | $ | 14,115 |
Accounts payable and accrued liabilities |  | (Note 24) |  |  | 270,122 |  |  |  |  | 80,864 |
Distributions payable |  | (Note 8) |  |  | 20,825 |  |  |  |  | 36,470 |
Current portion of long-term debt |  | (Note 10) |  |  | 48,953 |  |  |  |  | — |
|  |  |  |  |  |  | 339,900 |  |  |  |  | 131,449 |
Long-term liabilities |  | (Note 9) |  |  | 30,951 |  |  |  |  | 13,896 |
Long-term debt |  | (Note 10) |  |  | 1,368,349 |  |  |  |  | 119,826 |
Future income taxes |  | (Note 11) |  |  | 770,623 |  |  |  |  | 181,633 |
|  |  |  |  |  |  | 2,509,823 |  |  |  |  | 446,804 |
Commitments and contingencies |  | (Notes 16 and 25) |  |  |  |  |  |  |  |  |
Subsequent events |  | (Notes 8, 10 and 28) |  |  |  |  |  |  |  |  |
Unitholders’ equity: |  |  |  |  |  |  |  |  |  |  |  |  |
Unitholders’ capital |  | (Note 12(b)) |  |  | 2,355,590 |  |  |  |  | 1,442,476 |
Contributed surplus |  | (Note 12(c)) |  |  | 998 |  |  |  |  | 307 |
Deficit |  |  |  |  |  |  | (48,068 | ) |  |  |  | (126,110 | )
Accumulated other comprehensive income |  | (Note 13) |  |  | 15,359 |  |  |  |  | — |
|  |  |  |  |  |  | 2,323,879 |  |  |  |  | 1,316,673 |
|  |  |  |  |  | $ | 4,833,702 |  |  |  | $ | 1,763,477 |

See accompanying notes to consolidated financial statements.
Approved by the Board of Trustees:

Robert J.S. Gibson |  | Patrick M. Murray
Trustee |  | Trustee

PRECISION DRILLING TRUST 57

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Precision Drilling Trust
CONSOLIDATED STATEMENTS OF EARNINGS AND DEFICIT
Years ended December 31,

(Stated in thousands of Canadian dollars, except per unit amounts) |  |  |  |  |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Revenue |  |  |  |  |  | $ | 1,101,891 |  |  |  | $ | 1,009,201 |  |  | $ | 1,437,584 |
Expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating |  |  |  |  |  |  | 598,181 |  |  |  |  | 516,094 |  |  |  | 688,207 |
General and administrative |  |  |  |  |  |  | 67,174 |  |  |  |  | 56,032 |  |  |  | 81,217 |
Depreciation and amortization |  | (Note 4) |  |  | 83,829 |  |  |  |  | 78,326 |  |  |  | 73,234 |
Foreign exchange |  |  |  |  |  |  | (2,041 | ) |  |  |  | 2,398 |  |  |  | (353 | )
Interest: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt |  |  |  |  |  |  | 14,478 |  |  |  |  | 7,767 |  |  |  | 8,800 |
Other |  |  |  |  |  |  | 151 |  |  |  |  | 106 |  |  |  | 171 |
Income |  |  |  |  |  |  | (455 | ) |  |  |  | (555 | ) |  |  | (942 | )
Other |  |  |  |  |  |  | — |  |  |  |  | — |  |  |  | (408 | )
Earnings from continuing operations before income taxes |  |  |  |  |  |  | 340,574 |  |  |  |  | 349,033 |  |  |  | 587,658 |
Income taxes: |  | (Note 11) |  |  |  |  |  |  |  |  |  |  |  |  |
Current |  |  |  |  |  |  | 6,102 |  |  |  |  | (737 | ) |  |  | 34,526 |
Future |  |  |  |  |  |  | 31,742 |  |  |  |  | 6,950 |  |  |  | (19,380 | )
|  |  |  |  |  |  | 37,844 |  |  |  |  | 6,213 |  |  |  | 15,146 |
Earnings from continuing operations |  |  |  |  |  |  | 302,730 |  |  |  |  | 342,820 |  |  |  | 572,512 |
Gain on disposal of discontinued operations, net of tax |  | (Note 27) |  |  | — |  |  |  |  | 2,956 |  |  |  | 7,077 |
Net earnings |  |  |  |  |  |  | 302,730 |  |  |  |  | 345,776 |  |  |  | 579,589 |
Deficit, beginning of year |  |  |  |  |  |  | (126,110 | ) |  |  |  | (195,219 | ) |  |  | (303,284 | )
Distributions declared |  | (Note 8) |  |  | (224,688 | ) |  |  |  | (276,667 | ) |  |  | (471,524 | )
Deficit, end of year |  |  |  |  |  | $ | (48,068 | ) |  |  | $ | (126,110 | ) |  | $ | (195,219 | )
Earnings per unit from continuing operations: |  | (Note 17) |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  |  |  |  | $ | 2.39 |  |  |  | $ | 2.73 |  |  | $ | 4.56 |
Diluted |  |  |  |  |  | $ | 2.39 |  |  |  | $ | 2.73 |  |  | $ | 4.56 |
Earnings per unit: |  | (Note 17) |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  |  |  |  | $ | 2.39 |  |  |  | $ | 2.75 |  |  | $ | 4.62 |
Diluted |  |  |  |  |  | $ | 2.39 |  |  |  | $ | 2.75 |  |  | $ | 4.62 |

See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Years ended December 31,

(Stated in thousands of Canadian dollars) |  |  |  |  |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Net earnings |  |  |  |  |  | $ | 302,730 |  |  |  | $ | 345,776 |  |  | $ | 579,589 |
Unrealized gain recorded on translation of assets and liabilities of self-sustaining operations denominated in foreign currency |  |  |  |  |  |  | 11,222 |  |  |  |  | — |  |  |  | — |
Comprehensive income |  |  |  |  |  | $ | 313,952 |  |  |  | $ | 345,776 |  |  | $ | 579,589 |

See accompanying notes to consolidated financial statements.
58 CONSOLIDATED FINANCIAL STATEMENT

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Precision Drilling Trust
CONSOLIDATED STATEMENTS OF CASH FLOW
Years ended December 31,

(Stated in thousands of Canadian dollars) |  |  |  |  |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Cash provided by (used in): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Continuing operations: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Earnings from continuing operations |  |  |  |  |  | $ | 302,730 |  |  |  | $ | 342,820 |  |  | $ | 572,512 |
Adjustments and other items not involving cash: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term incentive plan compensation |  |  |  |  |  |  | 2,163 |  |  |  |  | (8,496 | ) |  |  | 22,699 |
Depreciation and amortization |  |  |  |  |  |  | 83,829 |  |  |  |  | 78,326 |  |  |  | 73,234 |
Future income taxes |  |  |  |  |  |  | 31,742 |  |  |  |  | 6,950 |  |  |  | (19,380 | )
Other |  |  |  |  |  |  | 7,219 |  |  |  |  | 112 |  |  |  | (408 | )
Amortization of debt issue costs |  |  |  |  |  |  | 798 |  |  |  |  | — |  |  |  | — |
Changes in non-cash working capital balances |  | (Note 24) |  |  | (84,571 | ) |  |  |  | 64,403 |  |  |  | (38,913 | )
|  |  |  |  |  |  | 343,910 |  |  |  |  | 484,115 |  |  |  | 609,744 |
Investments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Business acquisitions, net of cash acquired |  | (Note 19) |  |  | (768,392 | ) |  |  |  | — |  |  |  | (16,428 | )
Purchase of property, plant and equipment |  |  |  |  |  |  | (229,579 | ) |  |  |  | (186,973 | ) |  |  | (263,030 | )
Proceeds on sale of property, plant and equipment |  |  |  |  |  |  | 10,440 |  |  |  |  | 5,767 |  |  |  | 29,337 |
Changes in income tax recoverable |  |  |  |  |  |  | (55,148 | ) |  |  |  | — |  |  |  | — |
Proceeds on disposal of discontinued operations |  | (Note 27) |  |  | — |  |  |  |  | 2,956 |  |  |  | 7,337 |
Proceeds on disposal of investments |  |  |  |  |  |  | — |  |  |  |  | — |  |  |  | 510 |
Purchase of intangibles |  |  |  |  |  |  | — |  |  |  |  | (33 | ) |  |  | — |
Changes in non-cash working capital balances |  | (Note 24) |  |  | 22,583 |  |  |  |  | (13,119 | ) |  |  | 7,551 |
|  |  |  |  |  |  | (1,020,096 | ) |  |  |  | (191,402 | ) |  |  | (234,723 | )
Financing: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Distributions paid |  | (Note 8) |  |  | (216,304 | ) |  |  |  | (249,000 | ) |  |  | (444,651 | )
Repayment of long-term debt |  |  |  |  |  |  | (179,826 | ) |  |  |  | (99,700 | ) |  |  | (204,910 | )
Debt issue costs |  |  |  |  |  |  | (160,098 | ) |  |  |  | — |  |  |  | — |
Increase in long-term debt |  |  |  |  |  |  | 1,308,040 |  |  |  |  | 78,646 |  |  |  | 248,338 |
Issuance of Trust units |  |  |  |  |  |  | — |  |  |  |  | — |  |  |  | 9,896 |
Change in bank indebtedness |  |  |  |  |  |  | (14,115 | ) |  |  |  | (22,659 | ) |  |  | 16,306 |
|  |  |  |  |  |  | 737,697 |  |  |  |  | (292,713 | ) |  |  | (375,021 | )
Increase in cash and cash equivalents |  |  |  |  |  |  | 61,511 |  |  |  |  | — |  |  |  | — |
Cash and cash equivalents, beginning of year |  |  |  |  |  |  | — |  |  |  |  | — |  |  |  | — |
Cash and cash equivalents, end of year |  |  |  |  |  | $ | 61,511 |  |  |  | $ | — |  |  | $ | — |

See accompanying notes to consolidated financial statements.
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Precision Drilling Trust
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts are stated in thousands of Canadian dollars except unit numbers and per unit amounts)
NOTE 1. DESCRIPTION OF BUSINESS
Precision Drilling Trust (the “Trust”) is a provider of contract drilling and completion and production services primarily to oil and natural gas exploration and production companies in Canada and the United States. The Trust is an unincorporated open-ended investment trust governed by the laws of Alberta and created pursuant to the Declaration of Trust dated September 22, 2005.
Prior to the conversion to a trust on November 7, 2005, the consolidated financial statements included the accounts of Precision Drilling Corporation (“Precision”), its subsidiaries and its partnerships, substantially all of which were wholly-owned. 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.
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 20.
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, accruals for uninsured workers’ compensation and general liability claims and income taxes. Actual results could differ from these and other estimates, the impact of which would be recorded in future periods.
(b) Principles of consolidation
The consolidated financial statements include the accounts of the Trust and all of its subsidiaries and partnerships substantially all of which are wholly-owned. All significant intercompany balances and transactions have been eliminated.
The Trust does not hold investments in any companies where it exerts significant influence and does not hold interests in any variable interest entities.
(c) Cash and cash equivalents
Cash and cash equivalents consist of cash and short-term investments with original maturities of three months or less.
(d) Inventory
Inventory is primarily comprised of operating supplies and is carried at the lower of average cost, being the cost to acquire the inventory, and net realizable value. Inventory is charged to operating expenses as items are sold or consumed at the amount of the average cost of the item.
(e) Property, plant and equipment
Property, plant and equipment are carried at cost, including costs of direct material and labour. Where costs are incurred to extend the useful life of property, plant and equipment or to upgrade its capabilities, the amounts are capitalized to the related asset. Costs incurred to repair or maintain property, plant and equipment are expensed as incurred.
60 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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Property, plant, and equipment are depreciated as follows:

|  | Expected life |  | Salvage value |  | Basis of depreciation
Drilling rig equipment |  | 5,000 utilization days |  | 20% |  | unit-of-production
Drill pipe and drill collars |  | 1,500 operating days |  | — |  | unit-of-production
Service rig equipment |  | 24,000 service hours |  | 20% |  | unit-of-production
Drilling rig spare equipment |  | 15 years |  | — |  | straight-line
Service rig spare equipment |  | 10 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

(f) Intangibles
Intangibles with determinable lives are amortized using the straight-line method based on the estimated useful lives of the respective assets as follows:

Customer relationships |  | 1 to 5 years
Patents |  | 10 years

(g) Goodwill
Goodwill is the amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the assets acquired, less liabilities assumed, based on their fair values. Goodwill is allocated as of the date of the business combination to the Trust’s reporting segments that are expected to benefit from the business combination.
Goodwill is not amortized and is tested for impairment annually in the fourth quarter, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test is carried out in two steps.
In the first step, the carrying amount of the reporting segment is compared with its fair value. When the fair value of a reporting segment exceeds its carrying amount, goodwill of the reporting segment is considered not to be impaired and the second step of the impairment test is unnecessary. The second step is carried out when the carrying amount of a reporting segment exceeds its fair value, in which case the implied fair value of the reporting segment’s goodwill is compared with its carrying amount to measure the amount of the impairment loss, if any. The implied fair value of goodwill is determined in the same manner as the value of goodwill is determined in a business combination using the fair value of the reporting segment as if it was the purchase price. When the carrying amount of a reporting segment’s goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess.
(h) Long-lived assets
On a periodic basis, management assesses the carrying value of long-lived assets for indications of impairment. Indications of impairment include an ongoing lack of profitability and significant changes in technology. When an indication of impairment is present, the Trust tests for impairment by comparing the carrying value of the asset to its net recoverable amount. If the carrying amount is greater than the net recoverable amount, the asset is written down to its estimated fair value.
(i) Income taxes
The Trust and its subsidiaries follow the liability method of accounting for future income taxes. Under the liability method, future income tax assets and liabilities are determined based on “temporary differences” (differences between the accounting basis and the tax basis of the assets and liabilities), and are measured using current or substantively enacted tax rates and laws expected to apply when these differences reverse. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs. Future tax assets are recognized if it is considered more likely than not that the tax asset will be realized.
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Currently, income earned directly by Precision Drilling Limited Partnership (“PDLP”) is not subject to income taxes as its income is taxed directly to the PDLP partners. The Trust is a taxable entity under the Income Tax Act (Canada) and income earned is taxable only to the extent it is not distributed or distributable to its holders of Trust units and exchangeable LP units (together “unitholders”). In June 2007, the government of Canada’s Bill C-52 Budget Implementation Act, 2007 was enacted and included legislative provisions that impose a tax on certain distributions from publicly traded specified income flow-through (“SIFT”) trusts at a rate equal to the applicable federal corporate tax rate plus a provincial SIFT factor. The Trust will be a SIFT trust on the earlier of January 1, 2011 or the first day after it exceeds the normal growth guidelines announced by the federal Department of Finance on December 15, 2006. The enacted SIFT tax had no significant impact on the Trust’s future tax liability.
(j) Revenue recognition
The Trust’s services are generally sold based upon service orders or contracts with a customer that include fixed or determinable prices based upon daily, hourly or job rates. Customer contract terms do not include provisions for significant post-service delivery obligations. Revenue is recognized when services and equipment rentals are rendered and only when collectability is reasonably assured. The Trust also provides services under turnkey contracts whereby it drills a well to an agreed upon depth under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. Revenue from turnkey drilling contracts is recognized using the percentage-of-completion method based upon costs incurred to date and estimated total contract costs. Anticipated losses, if any, on uncompleted contracts are recorded at the time the estimated costs exceed the contract revenue.
(k) Employee benefit plans
At December 31, 2008, approximately 43% (2007 — 42%) 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
The Trust has an annual long-term incentive plan (the “LTIP”) which compensates officers and other key employees through cash payments at the end of a three-year term. The compensation is comprised of two components, a retention award and a performance award. The retention award is a lump sum amount determined in cash or equivalent notional Trust units at the date of commencement in the LTIP and is accrued and charged to earnings on a straight-line basis over the three-year term. The values of the notional Trust units are adjusted monthly based on the period-end trading price of Trust units and the resulting gains or losses are included in earnings. The performance components are based on the growth targets as determined by the Compensation Committee of Precision and is accrued over the three-year term of the plans.
(m) Foreign currency translation
Accounts of the Trust’s integrated foreign operations are translated to Canadian dollars using average exchange rates for the month of the respective transaction for revenue and expenses. Monetary assets and liabilities are translated at exchange rates in effect at the balance sheet date and non-monetary assets and liabilities are translated using historical rates of exchange. Gains or losses resulting from these translation adjustments are included in net earnings.
Accounts of the Trust’s self-sustaining foreign operations are translated to Canadian dollars using average exchange rates for the month of the respective transaction for revenue and expenses. Assets and liabilities are translated at exchange rates in effect at the balance sheet date. Gains or losses resulting from these translation adjustments are included in accumulated other comprehensive income in unitholders’ equity.
Coinciding with the acquisition of Grey Wolf, Inc. (“Grey Wolf” — see note 19) the Trust determined its existing United States based contract drilling operations had changed from integrated to self-sustaining and accordingly prospectively changed its method of foreign currency translation for these operations.
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.
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(n) Unit-based compensation plans
An equity settled deferred trust unit plan has been established whereby non-management directors of Precision can elect to receive all or a portion of their compensation in fully-vested deferred trust units. Under this plan, the number of deferred trust units are adjusted for cash distributions to unitholders declared prior to redemption by issuing additional Trust units based on the weighted average trading price of the Trust’s units on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. Compensation expense is recognized based on the current trading price of the Trust units at the date of grant with a corresponding increase to contributed surplus. Upon redemption of the deferred trust units into Trust units, the amount previously recognized in contributed surplus is recorded as an increase to Unitholders’ capital.
A cash settled deferred trust unit plan has been established whereby eligible participants of Precision’s Performance Savings Plan may elect to receive a portion of their annual performance bonus in the form of deferred trust units (“DTU”). These notional units are adjusted for each cash distribution to unitholders by issuing additional DTUs based on the weighted average trading price of the Trust’s units on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. The values of these DTUs are adjusted monthly based on the period-end trading price of Trust units and the resulting amount is included in accounts payable and accrued liabilities. Gains or losses resulting from these adjustments are charged to earnings.
A cash settled Deferred Signing Bonus Unit Plan has been established for the Chief Executive Officer. Under this plan deferred trust units are vested on the date of grant and are redeemable over a three-year period. These notional units are adjusted for each cash distribution to unitholders by issuing additional DTUs based on the weighted average trading price of the Trust’s units on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. The values of these DTUs are adjusted monthly based on the period-end trading price of Trust units and the resulting amount that is redeemable in the current year is included in accounts payable and accrued liabilities and the remainder is included in long-term incentive plan payable. Gains or losses resulting from these adjustments are charged to earnings.
A cash settled unit appreciation rights plan (“UAR”) has been established for certain eligible participants. This plan uses notional units that are valued based on the Trust’s unit price on the New York Stock Exchange. Compensation costs are accrued over the vesting periods when the market price of the trust units exceeds the strike price under the plan adjusted by unit distributions. The recorded liability is revalued at the end of each reporting period to reflect changes in the market price of the trust units with the net change recognized in earnings. When the UAR’s are exercised, the accrued liability is reduced. The accrued compensation cost for a UAR that is forfeited or cancelled is adjusted by decreasing the compensation cost in the period of forfeiture or cancellation.
(o) Exchangeable LP units
Exchangeable LP units are presented as equity of the Trust as their features make them economically equivalent to Trust units.
(p) Per unit amounts
Basic per unit amounts are calculated using the weighted average number of Trust units outstanding during the year. Diluted per unit amounts are calculated by using the treasury stock method for equity based compensation arrangements and the “if-converted” method for the convertible notes. The treasury stock method assumes that any proceeds obtained on exercise of equity based compensation arrangements would be used to purchase Trust units at the average market price during the period. The weighted average number of units outstanding is then adjusted by the difference between the number of units issued from the exercise of equity based compensation arrangements and units repurchased from the related proceeds. Under the “if-converted” method, the after-tax effect of interest expense related to the convertible notes are added back to net earnings, and the convertible notes are assumed to have been converted to trust units at the beginning of the period and are added to the weighted average number of units outstanding.
(q) Financial instruments
Cash and cash equivalents are classified as “held for trading” and any change in fair value is recorded through net income.
Accounts receivable are classified as “loans and receivables”. After their initial fair value measurement, they are measured at amortized cost using the effective interest rate method. For the Trust, the measured amount generally corresponds to historical cost.
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Accounts payable and accrued liabilities, bank indebtedness, distributions payable, long-term debt and other long-term liabilities, except for the long-term incentive plans, are classified as “other financial liabilities”. After their initial fair value measurement, they are measured at amortized cost using the effective interest rate method. For the Trust, the measured amount generally corresponds to historical cost.
Transaction costs incurred on the issuance of debt are classified with the related debt instrument. These costs are amortized using the effective interest rate method over the life of the related debt instrument.
NOTE 3. CHANGES IN ACCOUNTING POLICIES
(a) 2008 changes
Effective January 1, 2008 the Trust adopted new accounting standards issued by The Canadian Institute of Chartered Accountants (“CICA”) relating to inventories (Section 3031) and capital disclosures (Section 1535). Section 3031 requires inventories to be measured at the lower of cost or net realizable value and provides guidance on the determination of cost and its subsequent recognition as an expense, including any write-downs to net realizable value and circumstances for their subsequent reversal. This new standard did not have a material impact on the Trust’s financial statements. Section 1535 requires the Trust to provide additional quantitative and qualitative information regarding its objectives, policies and processes for managing its capital.
(b) 2007 changes
Effective January 1, 2007 the Trust adopted new accounting standards issued by the CICA. The standards regarding the disclosure of comprehensive income (Sections 1530 and 3251) require a statement of comprehensive income, which is comprised of net earnings and other comprehensive income.
The adoption of the standards relating to the recognition, measurement, disclosure and presentation of financial instruments (Sections 3855 and 3861), and hedge accounting (Section 3865) did not have a material impact on the consolidated financial statements.
In addition, the Trust early adopted new accounting standards related to the disclosure and presentation of financial instruments (Sections 3862 and 3863). These standards, which replace Section 3861, provide enhanced disclosure around the nature and extent of risks arising from financial instruments to which the entity is exposed and how the entity manages those risks. Adoption of these standards did not have a material impact on the consolidated financial statements.
(c) Future accounting pronouncements
Effective January 1, 2009 the Trust is required to adopt new Canadian accounting standards relating to goodwill and intangible assets (Section 3064), replacing Section 3062, goodwill and other intangible assets and Section 3450, research and development costs. This new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. The new Section will be applicable to the Trust on January 1, 2009 and is not anticipated to have a significant impact on the consolidated financial statements.
In February 2008, the CICA confirmed that Canadian GAAP for publicly accountable enterprises will be converged with International Financial Reporting Standards (IFRS) for fiscal years beginning on or after January 1, 2011. IFRS uses a conceptual framework similar to Canadian GAAP, but there are significant differences on recognition, measurement and disclosures. The conversion from Canadian GAAP to IFRS will be applicable to the Trust’s reporting for the first quarter of 2011 for which the current and comparative information will be prepared under IFRS. The Trust has developed a plan to convert its consolidated financial statements to IFRS. As part of this plan, the Trust will provide training to key employees and monitor the impact of the transition on its business practices, systems and internal controls over financial reporting.
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In January 2009 the CICA issued new standards relating to business combinations (Section 1582), consolidated financial statements (Section 1601) and non-controlling interests (Section 1602). Section 1582 will be harmonized with IFRS 3, “Business Combinations” and will require most assets acquired and liabilities assumed, including contingent liabilities to be measured at fair value and that all acquisition costs to be expensed. Section 1602 will harmonize with the requirements of International Accounting Standard 27, “Consolidated and Separate Financial Statements” and requires that non-controlling interests be recognized as a separate component of equity and that net earnings be calculated without a deduction for non-controlling interest. Section 1601 in combination with Section 1602 replaces the former consolidated financial statements standard (Section 1600) and establishes standards for the preparation of consolidated financial statements. These standards are effective January 1, 2011 with early adoption permitted. The Trust is currently evaluating the impact of these new sections on the consolidated financial statements.
NOTE 4. PROPERTY, PLANT AND EQUIPMENT

|  |  |  |  |  | Accumulated |  |  | Net Book |
2008 |  | Cost |  |  | Depreciation |  |  | Value |
Rig equipment |  | $ | 3,444,120 |  |  | $ | 548,380 |  |  | $ | 2,895,740 |
Rental equipment |  |  | 89,433 |  |  |  | 44,240 |  |  |  | 45,193 |
Other equipment |  |  | 122,795 |  |  |  | 76,841 |  |  |  | 45,954 |
Vehicles |  |  | 86,260 |  |  |  | 30,817 |  |  |  | 55,443 |
Buildings |  |  | 43,048 |  |  |  | 12,775 |  |  |  | 30,273 |
Assets under construction |  |  | 151,003 |  |  |  | — |  |  |  | 151,003 |
Land |  |  | 19,607 |  |  |  | — |  |  |  | 19,607 |
|  | $ | 3,956,266 |  |  | $ | 713,053 |  |  | $ | 3,243,213 |

|  |  |  |  |  | Accumulated |  |  | Net Book |
2007 |  | Cost |  |  | Depreciation |  |  | Value |
Rig equipment |  | $ | 1,464,145 |  |  | $ | 485,822 |  |  | $ | 978,323 |
Rental equipment |  |  | 95,435 |  |  |  | 45,917 |  |  |  | 49,518 |
Other equipment |  |  | 97,397 |  |  |  | 69,483 |  |  |  | 27,914 |
Vehicles |  |  | 76,387 |  |  |  | 27,892 |  |  |  | 48,495 |
Buildings |  |  | 30,614 |  |  |  | 11,494 |  |  |  | 19,120 |
Assets under construction |  |  | 77,096 |  |  |  | — |  |  |  | 77,096 |
Land |  |  | 10,121 |  |  |  | — |  |  |  | 10,121 |
|  | $ | 1,851,195 |  |  | $ | 640,608 |  |  | $ | 1,210,587 |

In 2007 the Trust incurred $6.7 million of additional depreciation expense associated with the reduction in the carrying amounts of assets decommissioned during the year. The assets were decommissioned due to the inefficient nature of the asset and the high cost to maintain. The charge was allocated $2.4 million to the Contract Drilling Services segment and $4.3 million to the Completion and Production Services segment.
NOTE 5. INTANGIBLES

|  |  |  |  |  | Accumulated |  |  | Net Book |
2008 |  | Cost |  |  | Amortization |  |  | Value |
Customer relationships |  | $ | 5,585 |  |  | $ | 134 |  |  | $ | 5,451 |
Patents |  |  | 931 |  |  |  | 706 |  |  |  | 225 |
|  | $ | 6,516 |  |  | $ | 840 |  |  | $ | 5,676 |
|  |  |  |  |  | Accumulated |  |  | Net Book |
2007 |  | Cost |  |  | Amortization |  |  | Value |
Patents |  | $ | 931 |  |  | $ | 613 |  |  | $ | 318 |

Amortization expense for the year ended December 31, 2008 was $0.2 million (2007 — $0.1 million).
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NOTE 6. GOODWILL

Balance, December 31, 2006 and 2007 |  | $ | 280,749 |
Acquisitions (Note 19) |  |  | 557,165 |
Exchange adjustment |  |  | 3,615 |
Balance, December 31, 2008 |  | $ | 841,529 |

NOTE 7. BANK INDEBTEDNESS
At December 31, 2008, the Trust had available $50.0 million (2007 — $60.0 million) and US$0.9 million (2007 — US$5.0 million) under secured and unsecured credit facilities, of which no significant amounts had been drawn (2007 — $14.1 million). Availability of these facilities were reduced by outstanding letters of credit in the amount of $35.4 million (2007 — $2.0 million). The current facilities are primarily secured by charges on substantially all present and future property of the Trust and its material subsidiaries. Advances under the facilities are available at the banks’ 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, 2008, the amounts drawn under these facilities were at the banks’ prime lending rate of approximately 3.6% (2007 — 6%).
NOTE 8. DISTRIBUTIONS
The beneficiaries of the Trust are the holders of Trust units and the partners of PDLP are the holders of exchangeable LP units of the Trust. The 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 Precision at a rate which is determined by the terms of the promissory note. PDLP in substance pays distributions to holders of exchangeable LP units in amounts equal to the distributions paid to the holders of Trust units. All distributions are made to unitholders of record on the last business day of each calendar month.
The Declaration of Trust provides that an amount equal to the taxable income of the Trust not already paid to unitholders in the year will become payable on December 31 of each year such that the Trust will not be liable for ordinary income taxes for such year.
A distribution reinvestment plan (the “DRIP”) was approved by the Board of Trustees in February 2006, and implemented in March 2006. The DRIP allows certain holders of Trust units, at their option, to reinvest monthly cash distributions to acquire additional Trust units at the average market price as defined in the DRIP. Unitholders who were not resident in Canada or held exchangeable LP units were 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:

|  | 2008 |  |  |  | 2007 |
Declared |  | $ | 224,688 |  |  |  | $ | 276,667 |
Paid |  | $ | 216,304 |  |  |  | $ | 249,000 |
Payable in cash at December 31 |  | $ | 20,825 |  |  |  | $ | 36,470 |
Payable in units at December 31 |  | $ | 24,029 |  |  |  | $ | 30,182 |

Included in the 2008 distributions declared is a special non-cash in-kind distribution of $24.0 million ($0.15 per unit) (2007 — $ 30.2 million or $0.24 per unit). This special distribution was settled on January 15, 2009 through the issuance of units. Immediately following the issuance of these units, the Trust consolidated the units such that the number of Trust units and exchangeable LP units remained unchanged from the number outstanding prior to the special non-cash in-kind distribution.
On February 9, 2009 the Trust announced the suspension of cash distributions for an indefinite period for distributions to be paid after February 17, 2009.
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NOTE 9. LONG-TERM LIABILITIES

|  | 2008 |  |  |  | 2007 |
Long-term incentive plans (Note 14) |  | $ | 7,489 |  |  |  | $ | 13,896 |
Long-term workers’ compensation and other liabilities |  |  | 23,462 |  |  |  |  | — |
|  | $ | 30,951 |  |  |  | $ | 13,896 |

NOTE 10. LONG-TERM DEBT

|  | 2008 |  |  |  | 2007 |
Secured facility: |  |  |  |  |  |  |  |  |
Term Loan A |  | $ | 489,215 |  |  |  | $ | — |
Term Loan B |  |  | 489,840 |  |  |  |  | — |
Revolving credit facility |  |  | 107,981 |  |  |  |  | — |
Unsecured facility |  |  | 168,352 |  |  |  |  | — |
Unsecured convertible notes: |  |  |  |  |  |  |  |  |
3.75% notes |  |  | 168,413 |  |  |  |  | — |
Floating rate notes |  |  | 152,801 |  |  |  |  | — |
Unsecured revolving credit facility |  |  | — |  |  |  |  | 119,826 |
|  |  | 1,576,602 |  |  |  |  | 119,826 |
Less net unamortized debt issue costs |  |  | (159,300 | ) |  |  |  | — |
|  |  | 1,417,302 |  |  |  |  | 119,826 |
Less current portion |  |  | (48,953 | ) |  |  |  | — |
|  | $ | 1,368,349 |  |  |  | $ | 119,826 |

(a) Secured facility:
During 2008 Precision established a Secured Facility which provides senior secured financing of up to approximately US$1.2 billion, consisting of a Term Loan A Facility in an aggregate principal amount of US$400 million, a Term Loan B Facility in an aggregate principal amount of US$400 million and a Revolving Credit Facility in the amount of US$400 million. The Secured Facility is primarily secured by charges on substantially all present and future property of the Trust and its material subsidiaries. The Trust and its material subsidiaries have also guaranteed the obligations of Precision under the Secured Facility. The Secured Facility requires the Trust comply with certain financial covenants including a leverage ratio of total debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (“EBITDA”) of less than 3:1; an interest coverage ratio of EBITDA to cash interest expense of greater than 3:1; and a fixed charge coverage ratio of EBITDA less cash distributions to scheduled principal repayments plus cash interest expense plus current tax expense plus upgrade capital expenditures of greater than 1:1 in 2009 and 2010 and 1.05:1 thereafter. As well, the Secured Facility contains certain covenants that places limits on Trust distributions and limits the Trusts’ capital expenditures above an agreed base-case. The first test of these covenants is not until March 31, 2009.
The Secured Facility was not fully syndicated by the underwriting banks that funded borrowings by Precision at December 31, 2008. As a result these banks retain certain provisions that are available to March 23, 2009 (extended at Precision’s option to May 22, 2009) to facilitate syndication which may result in further increases in any or a combination of interest rates, original issue discounts or fees, all subject to certain market based indexing including the re-allocation of debt between the Term Loan A and Term Loan B and between the Term Loan A and B loans and the unsecured facility. On February 4, 2009 these provisions remain and resulted in US$64.0 million ($78.5 million) being reallocated from the Term Loan A to the Term Loan B. The re-tranche of debt between Term Loan A and Term Loan B facilities led to additional debt issue costs through original issue discount of US$10.0 million ($12.2 million).
The Secured Facility requires mandatory prepayments upon the occurrence of certain events, including, the incurrence of debt, certain sales or other dispositions of assets and when cash flows exceed certain base-case projections. In addition to mandatory prepayments, Precision has the option to prepay the loans under the Secured Facility generally without premium or penalty, other than customary “breakage” costs for Eurodollar rate loans.
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The interest rate on loans under the Secured Facility that are denominated in U.S. dollars is, at the option of Precision, either a margin over an adjusted United States base rate (the “ABR rate”) or a margin over a Eurodollar rate. The interest rate on loans denominated in Canadian dollars is, at the option of Precision, a margin over the Canadian prime rate or a margin over the bankers’ acceptance rate. Certain of the margins on the Revolving Credit Facility are subject to reduction based upon a leverage test and these margins range from 3% to 4% for Eurodollar and bankers acceptance loans and 2% to 3% for ABR and Canadian prime rate loans based on leverage ratios ranging from greater than 1.5:1 to 1:1. Under the terms of the Secured Facility Precision is required to enter into interest rate contracts if necessary, on or before June 23, 2009, to ensure that at least 50% of the aggregate amounts borrowed under the Secured and Unsecured Facilities are subject to fixed interest rates.
At December 31, 2008 the Term Loan A Facility was fully drawn by Precision and consists of a term loan A-1 facility denominated in U.S. dollars in the amount of US$381.1 million ($466.7 million) and a term loan A-2 facility denominated in Canadian dollars in the amount of $22.5 million. The Term Loan A Facility is repayable in quarterly installments in aggregate annual amounts equal to 5% of the original principal amount thereof in 2009, 10% of the original principal amount thereof in each of 2010 and 2011 and 15% of the original principal amount in 2012 and 2013, with the balance payable on the final maturity date of December 23, 2013. As of December 31, 2008, the Term Loan A Facility had an interest rate of approximately 6.3% per annum, before original issue discounts and upfront fees.
At December 31, 2008 the Term Loan B Facility was fully drawn by Precision and consists of a term loan B-1 facility denominated in U.S. dollars in the amount of US$325 million ($398 million) and a term loan B-2 facility denominated in U.S. dollars in the amount of US$75 million ($91.8 million). The Term Loan B Facility is repayable in quarterly installments in aggregate annual amounts equal to 5% of the original principal amount with the balance payable on the final maturity date of September 30, 2014. As of December 31, 2008, the Term Loan B Facility had an interest rate of approximately 9.6% per annum, before original issue discounts and upfront fees.
The Revolving Credit Facility is available to Precision to finance working capital needs and for general corporate purposes. Under the Revolving Credit Facility amounts can be drawn in U.S. dollars and/or Canadian dollars and $108 million was drawn as at December 31, 2008. Up to US$200 million of the Revolving Credit Facility is available for letters of credit denominated in United States and/or Canadian dollars. As of December 31, 2008, the Revolving Credit Facility had an interest rate of approximately 6.5% per annum, before original issue discounts, upfront fees and commitment fees.
(b) Unsecured facility:
In connection with the acquisition of Grey Wolf, Inc. (“Grey Wolf”) Precision established the Unsecured Facility which provides senior unsecured financing of up to US$400 million. The facility has been guaranteed by the Trust and each subsidiary of the Trust that has guaranteed the Secured Facility. After the completion of the acquisition and the related acquisition financing transactions, approximately US$137.5 million ($168.4 million) was outstanding. Up to an additional approximately US$262.5 million is available under the Unsecured Facility to fund the repurchase, in whole or in part, of outstanding (formerly Grey Wolf) unsecured convertible notes that may be tendered pursuant to the change of control offer for repurchase in the first quarter of 2009 and related fees and expenses. Loans under the Unsecured Facility currently bear interest at a fixed rate per annum of 17% and will initially mature on December 23, 2009, and, to the extent unpaid on that date, will be converted into term loans that will mature on December 23, 2016. Loans under the Unsecured Facility are subject to mandatory prepayments from the net cash proceeds from the issuance or sale of any equity securities by the Trust (subject to certain exceptions).
The Unsecured Facility contains a number of occurrence-based covenants that, among other things, restrict, subject to certain exceptions, the Trust’s, Precision’s and their subsidiaries ability to: make certain restricted payments (which include dividends, distributions (including by the Trust to unitholders), redemptions and certain investments); incur additional indebtedness; sell assets; enter into mergers, consolidations or amalgamations; and amend certain material agreements. The terms of this facility limit, subject to certain exceptions, the Trust’s ability to make distributions in the following circumstances: where a default under the terms of this facility has occurred; where the incurrence of at least US$1.00 of additional indebtedness would result in the consolidated interest coverage ratio of consolidated cash flow to consolidated interest expense, as defined in the agreement, being less than 2.5:1; for so long as the Trust is a “mutual fund trust” for Canadian federal income tax purposes, where the consolidated leverage ratio of total indebtedness to consolidated cash flow, as defined in the agreement, exceeds 3:1 or where the amount of such distribution, when added to the amount of all distributions (subject to certain exceptions) made after the closing date of the Grey Wolf acquisition exceeds certain prescribed amounts specified in the agreement.
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After the initial maturity date of the Unsecured Facility each lender under the Unsecured Facility may request Precision issue an exchange note bearing interest at a specified interest rate (to be calculated on the date of issuance of such exchange note based on the greater of 16.66% and a market-based interest rate cap) in replacement for the term loan (or a portion thereof) made under the Unsecured Facility. In the event that Precision receives such a request, Precision shall, as promptly as practicable after being requested to do so, among other things: (i) enter into an exchange note indenture pursuant to which the exchange notes will be issued and governed; (ii) enter into an exchange and registration rights agreement providing for, among other things, registration rights in respect of the exchange notes in favour of the holders thereof; and (iii) cause to be issued exchange notes in the same principal aggregate amount as the term loan being exchanged.
In addition, after June 30, 2009 (or after April 1, 2009 in certain circumstances), the lenders under the Unsecured Facility may require that debt securities be issued and sold to repay amounts outstanding under the Unsecured Facility, subject to certain specified terms and conditions. Precision has agreed to engage one or more investment banks to publicly sell or privately place debt securities in such circumstances, the proceeds of which will be used to repay outstanding loans under the Unsecured Facility. The Trust may also, at any time, issue equity or debt securities and Precision may, at any time, issue debt securities to repay outstanding loans under the Unsecured Facility.
On February 18, 2009 the Trust received gross proceeds of $217.3 million (US$172.5 million) from an equity issue (Note 28). As a result of this issuance, the funds available under the Unsecured Facility were reduced to US$235 million.
(c) Unsecured convertible notes:
The US$137.5 million ($168.4 million) principal amount of 3.75% Contingent Convertible Notes (“3.75% Notes”) due May 2023 bear interest at 3.75% per annum. These notes are convertible into Trust units, upon the occurrence of certain events, including a change of control, at a conversion price of US$15.27 per Trust unit, which is equal to a conversion rate of 65.4879 Trust units per US$1,000 principal amount of 3.75% Notes, subject to adjustment. The 3.75% Notes are general unsecured senior obligations and are fully and unconditionally guaranteed, on a joint and several basis, by all wholly-owned United States subsidiaries. The 3.75% Notes rank equally with the Floating Rate Notes described below. During the first quarter of 2009, as a result of the Grey Wolf acquisition (which constitutes a change of control under the terms of the indenture governing the 3.75% Notes), Precision is required to provide holders of the 3.75% Notes with an offer to purchase all or a portion of their 3.75% Notes at 100% of the principal amount of the 3.75% Notes, plus accrued but unpaid interest to the date of purchase, payable in cash.
The US$124.8 million ($152.8 million) principal amount of Contingent Convertible Floating Rate Notes (“Floating Rate Notes”) due April 2024 bear interest at a per annum rate equal to 3-month LIBOR, adjusted quarterly, minus a spread of 0.05% to a maximum limit rate of interest of 6%. The Floating Rate Notes are convertible into Trust units, upon the occurrence of certain events, including a change of control, at a conversion price of US$15.41 per Trust unit, which is equal to a conversion rate of 64.8929 Trust units per US$1,000 principal amount of the Floating Rate Notes, subject to adjustment. The Floating Rate Notes are general unsecured senior obligations and are fully and unconditionally guaranteed, on a joint and several basis, by all wholly-owned United States subsidiaries. The Floating Rate Notes rank equally with the 3.75% Notes. During the first quarter of 2009, as a result of the Grey Wolf acquisition (which constitutes a change of control under the terms of the indenture governing the Floating Rate Notes), Precision is required to provide holders of the Floating Rate Notes with an offer to purchase all or a portion of their Floating Rate Notes at 100% of the principal amount of the Floating Rate Notes, plus accrued but unpaid interest to the date of purchase, payable in cash.
As at March 20, 2009 holders of 3.75% Notes and Floating Rate Notes representing US$137.5 million and US$124.8 million, respectively, had notified Precision that they will be accepting the purchase offer described above and Precision will be required to purchase these Notes at the principal balance plus accrued interest of US$2.3 million by March 24, 2009.
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(d) Unsecured revolving credit facility:
At December 31, 2007 Precision, a subsidiary of the Trust, had available a three-year revolving unsecured facility of $700.0 million (or U.S. equivalent) with a syndicate led by a Canadian chartered bank, which was guaranteed by the Trust. Advances were available to Precision 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 was dependent on the Trust’s consolidated debt to cash flow ratio and the percentage of the total facility outstanding, which at December 31, 2007 was 75 basis points. The facility required 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. This facility was repaid and extinguished in the fourth quarter of 2008 as a requirement of the Senior Secured and Senior Unsecured financing for the acquisition of Grey Wolf.
Mandatory principal repayments after 2008 giving effect to the February 4, 2009 re-allocation of Term Loan A and Term Loan B facilities as described above are as follows:

2009 |  | $ | 48,953 |
2010 |  |  | 69,495 |
2011 |  |  | 69,495 |
2012 |  |  | 90,037 |
2013 |  |  | 382,896 |
Thereafter |  |  | 915,726 |

NOTE 11. INCOME TAXES
The provision for income taxes differs from that which would be expected by applying Canadian statutory income tax rates as follows:

|  | 2008 |  |  |  | 2007 |  |  | 2006 |
Earnings from continuing operations before income taxes |  | $ | 340,574 |  |  |  | $ | 349,033 |  |  | $ | 587,658 |
Federal and provincial statutory rates |  |  | 30% |  |  |  |  | 33% |  |  |  | 33% |
Tax at statutory rates |  | $ | 102,172 |  |  |  | $ | 115,181 |  |  | $ | 193,927 |
Adjusted for the effect of: |  |  |  |  |  |  |  |  |  |  |  |  |
Non-deductible expenses |  |  | 372 |  |  |  |  | 1,080 |  |  |  | 297 |
Income to be distributed to Unitholders, not subject to tax in the Trust |  |  | (67,463 | ) |  |  |  | (91,013 | ) |  |  | (155,354 | )
Other |  |  | 2,763 |  |  |  |  | 3,426 |  |  |  | (2,896 | )
Income tax expense before tax rate reductions |  |  | 37,844 |  |  |  |  | 28,674 |  |  |  | 35,974 |
Reduction of future income tax balances due to enacted tax rate reductions |  |  | — |  |  |  |  | (22,461 | ) |  |  | (20,828 | )
Income tax expense |  | $ | 37,844 |  |  |  | $ | 6,213 |  |  | $ | 15,146 |
Effective income tax rate before enacted tax rate reductions |  |  | 11% |  |  |  |  | 8% |  |  |  | 6% |

In 2007 the Canadian federal government enacted various reductions to corporate income tax rates, that when fully implemented over the next five years will decrease the federal corporate income tax rate to 15% in 2012. These reductions were in addition to those introduced in 2006 that were to reduce the federal corporate income tax rates from 21% to 18.5% by 2011. The federal corporate capital tax was eliminated effective January 1, 2006 and the federal corporate surtax was eliminated in 2008. In 2006 the Province of Alberta reduced the corporate income tax rate by 1.5% effective April 1, 2006. These and other provincial corporate income tax rate reductions have been reflected as a reduction of future tax expense.
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|  | The net future tax liability is comprised of the tax effect of the following temporary differences:

|  | 2008 |  |  |  | 2007 |
Future income tax liability: |  |  |  |  |  |  |  |  |
Property, plant and equipment and intangibles |  | $ | 783,945 |  |  |  | $ | 209,772 |
Partnership deferrals |  |  | 4,716 |  |  |  |  | — |
Debt issue costs |  |  | 3,352 |  |  |  |  | — |
|  |  | 792,013 |  |  |  |  | 209,772 |
Future income tax assets: |  |  |  |  |  |  |  |  |
Losses (the non capital losses expire from time to time up to 2028) |  |  | 7,416 |  |  |  |  | 9,128 |
Long-term incentive plan |  |  | 5,664 |  |  |  |  | 5,743 |
Other |  |  | 8,310 |  |  |  |  | 13,268 |
Net future income tax liability |  | $ | 770,623 |  |  |  | $ | 181,633 |

Included in the net future tax liability is $560.9 million of tax effected temporary differences related to the Trust’s United States operations.
NOTE 12. UNITHOLDERS’ CAPITAL
(a) Authorized — unlimited number of voting Trust units
— unlimited number of voting exchangeable LP units
(b) Unitholders’ capital

Trust units |  | Number |  |  | Amount |
Balance, December 31, 2005 |  |  | 124,352,921 |  |  | $ | 1,365,755 |
Issued pursuant to distribution reinvestment plan (Note 8) |  |  | 296,621 |  |  |  | 9,896 |
Issued on retraction of exchangeable LP units |  |  | 886,787 |  |  |  | 9,697 |
Issued and consolidated pursuant to special distribution (Note 8) |  |  | — |  |  |  | 24,480 |
Balance, December 31, 2006 |  |  | 125,536,329 |  |  |  | 1,409,828 |
Issued on retraction of exchangeable LP units |  |  | 51,590 |  |  |  | 574 |
Issued and consolidated pursuant to special distribution (Note 8) |  |  | — |  |  |  | 30,141 |
Balance, December 31, 2007 |  |  | 125,587,919 |  |  |  | 1,440,543 |
Issued on the acquisition of Grey Wolf |  |  | 34,435,724 |  |  |  | 889,085 |
Issued on retraction of exchangeable LP units |  |  | 18,422 |  |  |  | 209 |
Issued and consolidated pursuant to special distribution (Note 8) |  |  | — |  |  |  | 24,006 |
Balance, December 31, 2008 |  |  | 160,042,065 |  |  | $ | 2,353,843 |

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 Precision to the unitholder, payable over 15 years and bearing interest at a market rate set by the Board of Directors.

Exchangeable LP units |  | Number |  |  | Amount |
Balance, December 31, 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 8) |  |  | — |  |  |  | 43 |
Balance, December 31, 2006 |  |  | 221,595 |  |  |  | 2,466 |
Redeemed on retraction of exchangeable LP units |  |  | (51,590 | ) |  |  | (574 | )
Issued and consolidated pursuant to special distribution (Note 8) |  |  | — |  |  |  | 41 |
Balance, December 31, 2007 |  |  | 170,005 |  |  |  | 1,933 |
Redeemed on retraction of exchangeable LP units |  |  | (18,422 | ) |  |  | (209 | )
Issued and consolidated pursuant to special distribution (Note 8) |  |  | — |  |  |  | 23 |
Balance, December 31, 2008 |  |  | 151,583 |  |  | $ | 1,747 |

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Exchangeable LP units have voting rights and have been exchangeable since May 7, 2006, for Trust units on a one-for-one basis at the option of the holder. Holders are entitled to monthly cash distributions equal to those paid to holders of Trust units.

|  | 2008 |  |  |  | 2007 |
Summary as at December 31, |  | Number |  |  | Amount |  |  |  | Number |  |  | Amount |
Trust units |  |  | 160,042,065 |  |  | $ | 2,353,843 |  |  |  |  | 125,587,919 |  |  | $ | 1,440,543 |
Exchangeable LP units |  |  | 151,583 |  |  |  | 1,747 |  |  |  |  | 170,005 |  |  |  | 1,933 |
Unitholders’ capital |  |  | 160,193,648 |  |  | $ | 2,355,590 |  |  |  |  | 125,757,924 |  |  | $ | 1,442,476 |

(c) Contributed surplus

Balance, December 31, 2006 |  | $ | — |
Unit based compensation expense (Note 4(c)) |  |  | 307 |
Balance, December 31, 2007 |  |  | 307 |
Unit based compensation expense (Note 4(c)) |  |  | 691 |
Balance, December 31, 2008 |  | $ | 998 |

NOTE 13. ACCUMULATED OTHER COMPREHENSIVE INCOME

Balance, December 31, 2006 and 2007 |  | $ | — |
Foreign currency translation adjustment upon change in translation methods |  |  | 4,137 |
Unrealized foreign currency translation gains |  |  | 11,222 |
Balance, December 31, 2008 |  | $ | 15,359 |

NOTE 14. UNIT BASED COMPENSATION PLANS
(a) Officers and employees
Eligible participants of Precision’s Performance Savings Plan may elect to receive a portion of their annual performance bonus in the form of deferred trust units (“DTUs”). These notional units are redeemable in cash and are adjusted for each cash distribution to unitholders by issuing additional DTUs based on the weighted average trading price on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. All DTUs must be redeemed within 60 days of ceasing to be an employee of Precision or by the end of the second full calendar year after the receipt of the DTUs. A summary of this unit based incentive plan is presented below:

Deferred Trust Units |  | Outstanding |
Balance, December 31, 2006 |  |  | — |
Issued, including as a result of cash distributions |  |  | 87,340 |
Redeemed on employee resignations and withdrawals |  |  | (10,611 | )
Balance, December 31, 2007 |  |  | 76,729 |
Issued, including as a result of cash distributions |  |  | 31,006 |
Redeemed on employee resignations and withdrawals |  |  | (24,300 | )
Balance, December 31, 2008 |  |  | 83,435 |

As at December 31, 2008 $0.8 million (2007 — $1.2 million) is included in accounts payable and accrued liabilities for outstanding DTUs. Included in net earnings for the year ended December 31, 2008 is a recovery of $0.4 million (2007 -$0.8 million).
In conjunction with the acquisition of Grey Wolf (Note 19) the Trust instituted a Unit Appreciation Rights (“UAR”) plan. Under the plan eligible participants were granted UAR’s that entitle the rights holder to receive cash payments calculated as the excess of the market price over the exercise price per unit on the exercise date. The exercise price of the UAR is adjusted by the aggregate unit distributions paid or payable on Trust units from the grant date to the exercise date. The UAR’s vest over a period of 5 years and expire 10 years from the date of grant.
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|  |  |  |  |  |  |  |  |  |  |  |  |  | Weighted |  |  |  |
|  |  |  |  |  |  |  |  |  | Range of |  |  | Average |  |  |  |
Unit Appreciation Rights |  |  |  |  |  | Outstanding |  |  | Exercise Price |  |  | Exercise Price |  |  | Exercisable |
Outstanding at December 31, 2006 and 2007 |  |  |  |  |  |  | — |  |  | $ | — |  |  | $ | — |  |  |  | — |
Granted |  |  |  |  |  |  | 925,746 |  |  |  | 11.34 — 21.94 |  |  |  | 18.20 |  |  |  |  |
Outstanding at December 31, 2008 |  |  |  |  |  |  | 925,746 |  |  | $ | 11.34 — 21.94 |  |  | $ | 18.20 |  |  |  | 469,267 |
|  | Total UAR’s Outstanding |  |  |  | Exercisable UAR’s |
|  |  |  |  |  |  |  |  |  | Weighted |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  | Average |  |  |  |  |  |  |  |
|  |  |  |  |  | Weighted |  |  | Remaining |  |  |  |  |  |  | Weighted |
|  |  |  |  |  | Average |  |  | Contractual |  |  |  |  |  |  | Average |
Range of Exercise Prices: |  | Number |  |  | Exercise Price |  |  | Life (Years) |  |  | Number |  |  | Exercise Price |
$11.34 — 14.99 |  |  | 81,641 |  |  | $ | 11.34 |  |  |  | 5.23 |  |  |  | 53,668 |  |  | $ | 11.34 |
15.00 — 18.99 |  |  | 492,443 |  |  |  | 18.03 |  |  |  | 8.33 |  |  |  | 199,279 |  |  |  | 17.46 |
19.00 — 21.94 |  |  | 351,662 |  |  |  | 20.04 |  |  |  | 7.75 |  |  |  | 216,320 |  |  |  | 20.26 |
$11.34 — 21.94 |  |  | 925,746 |  |  | $ | 18.20 |  |  |  | 7.84 |  |  |  | 469,267 |  |  | $ | 18.05 |

No amounts relating to the UAR plan have been recorded as compensation expense or accrued liability as at December 31, 2008, as the intrinsic value of the awards was nil.
(b) Executive
In 2007 Precision instituted a Deferred Signing Bonus Unit Plan for its Chief Executive Officer. Under the plan 178,336 notional DTUs were granted on September 1, 2007. The units are redeemable one-third annually beginning September 1, 2008 and are settled for cash based on the Trust unit trading price on redemption. The number of notional DTUs is adjusted for each cash distribution to unitholders by issuing additional notional DTUs based on the weighted average trading price on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. As at December 31, 2008 $0.7 million (2007 – $0.9 million) is included in accounts payable and accrued liabilities and $0.7 million (2007 – $1.9 million) in long-term incentive plan payable for the 133,780 (2007 – 182,372) outstanding DTUs. Included in net earnings for the year ended December 31, 2008 is an expense of $21,000 (2007 – $2.8 million).
(c) Non-management directors
The Trust has a deferred trust unit plan for non-management directors. Under the plan fully vested deferred trust units are granted quarterly based upon an election by the non-management director to receive all or a portion of their compensation in deferred trust units. Cash distributions to unitholders declared by the Trust prior to redemption are reinvested into additional deferred trust units on the date of the cash distribution. These deferred trust units are redeemable into an equal number of Trust units any time after the director’s retirement. A summary of this unit based incentive plan is presented below:

Deferred Trust Units |  | Outstanding
Balance, December 31, 2006 |  |  | —
Granted |  |  | 17,855
Issued as a result of cash distributions |  |  | 425
Balance, December 31, 2007 |  |  | 18,280
Granted |  |  | 33,058
Issued as a result of cash distributions |  |  | 3,205
Balance, December 31, 2008 |  |  | 54,543

For the year ended December 31, 2008 the Trust expensed $691,000 (2007 – $307,000) as unit based compensation, with a corresponding increase in contributed surplus.
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NOTE 15. EMPLOYEE BENEFIT PLANS
The Trust has a defined contribution pension plan covering a significant number of its employees. Under this plan, the Trust matches individual contributions up to 5% of the employee’s compensation. Total expense under the defined contribution plan in 2008 was $5.7 million (2007 – $5.3 million; 2006 – $5.5 million).
NOTE 16. COMMITMENTS
The Trust has commitments for operating lease agreements, primarily for vehicles and office space, in the aggregate amount of $35.0 million. Additionally, the Trust has commitments with a drilling rig manufacturer for the construction, or partial construction, of 11 drilling rigs in the amount of $125.3 million (US$102.3 million). Expected payments over the next five years are as follows:

2009 |  | $ | 77,039 |
2010 |  |  | 68,557 |
2011 |  |  | 6,763 |
2012 |  |  | 1,608 |
2013 |  |  | 1,203 |

Rent expense included in the statements of earnings is as follows:

2008 |  | $ | 3,636 |
2007 |  |  | 3,838 |
2006 |  |  | 4,189 |

NOTE 17. PER UNIT AMOUNTS
The following tables reconcile the net earnings and weighted average units outstanding used in computing basic and diluted earnings per unit:

(Stated in thousands) |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Net earnings — basic |  | $ | 302,730 |  |  |  | $ | 345,776 |  |  | $ | 579,589 |
Impact of assumed conversion of convertible notes, net of tax |  |  | 164 |  |  |  |  | — |  |  |  | — |
Net earnings — diluted |  | $ | 302,894 |  |  |  | $ | 345,776 |  |  | $ | 579,589 |

(Stated in thousands) |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Weighted average units outstanding — basic |  |  | 126,507 |  |  |  |  | 125,758 |  |  |  | 125,545 |
Effect of stock options and other equity compensation plans |  |  | 33 |  |  |  |  | 2 |  |  |  | — |
Effect of convertible notes |  |  | 372 |  |  |  |  | — |  |  |  | — |
Weighted average units outstanding — diluted |  |  | 126,912 |  |  |  |  | 125,760 |  |  |  | 125,545 |

NOTE 18. SIGNIFICANT CUSTOMERS
During the years ended December 31, 2008 and 2007 one customer (2006 – no customers) accounted for approximately 13% (2007 – 10%) of the Trust’s revenue and year end trade accounts receivable balance.
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NOTE 19. BUSINESS ACQUISITIONS
Acquisitions have been accounted for by the purchase method with results of operations acquired included in the consolidated financial statements from the closing date of acquisition.
On December 23, 2008 Precision acquired all the issued and outstanding shares of Grey Wolf, Inc. Grey Wolf provides land-based daywork and turnkey contract drilling services to the oil and gas industry in the United States and Mexico. The acquisition facilitates and accelerates Precision’s organic expansion into the United States market and provides a foundation for future international expansion. Intangible assets acquired relate to customer relationships. The Grey Wolf operations have been included in the Contract Drilling Services segment.
On July 31, 2008, Precision acquired six service rigs and related equipment from Rick’s Well Servicing Ltd. (“RWS”) a privately owned well servicing company based in Virden, Manitoba. The acquisition represented all of the operating assets of RWS and Precision will maintain and operate out of the RWS facility. Intangible assets acquired relate to customer lists. The acquisition strengthens Precision’s product offering in southeastern Saskatchewan and southwestern Manitoba. The operations of RWS have been included in the Completion and Production Services segment.
The details of these acquisitions are as follows:

|  | Grey Wolf |  |  | RWS |  |  | Total |
Net assets at assigned values: |  |  |  |  |  |  |  |  |  |  |  |
Working capital |  | $ | 470,586 | (1) |  | $ | 19 |  |  | $ | 470,605 |
Property, plant and equipment |  |  | 1,869,875 |  |  |  | 10,542 |  |  |  | 1,880,417 |
Intangible assets |  |  | 4,428 |  |  |  | 1,128 |  |  |  | 5,556 |
Goodwill (no tax basis) |  |  | 553,335 |  |  |  | 3,830 |  |  |  | 557,165 |
Long-term liabilities |  |  | (23,308 | ) |  |  | — |  |  |  | (23,308 | )
Long-term debt |  |  | (319,115 | ) |  |  | — |  |  |  | (319,115 | )
Future income taxes |  |  | (553,682 | ) |  |  | — |  |  |  | (553,682 | )
|  | $ | 2,002,119 |  |  | $ | 15,519 |  |  | $ | 2,017,638 |
Consideration: |  |  |  |  |  |  |  |  |  |  |  |
Cash |  | $ | 1,113,034 |  |  | $ | 15,519 |  |  | $ | 1,128,553 |
Trust units |  |  | 889,085 |  |  |  | — |  |  |  | 889,085 |
|  | $ | 2,002,119 |  |  | $ | 15,519 |  |  | $ | 2,017,638 |

(1) |  | Working capital includes cash of $360,161

Due to the proximity of the Grey Wolf acquisition to the year end, the purchase price allocation is preliminary and adjustments to the allocation may occur as a result of obtaining additional information regarding asset valuations or transaction costs.
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 acquisition provides complementary services to Precision’s existing camp and wellsite unit rental businesses. The Terra operations are included in the Completion and Production Services segment. The details of the acquisition are as follows:

Net assets acquired at assigned values: |  |  |  |
Working capital (1) |  | $ | 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

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NOTE 20. UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
These financial statements have been prepared in accordance with Canadian GAAP which conform with United States generally accepted accounting principles (U.S. GAAP) in all material respects, except as follows:
(a) Income taxes
On December 31, 2008 Precision had $56.6 million (2007 – $44.4 million) of unrecognized tax benefits that, if recognized, would have a favourable impact on Precision’s effective income tax rate in future periods. Precision classifies interest accrued on unrecognized tax benefits and income tax penalties as income tax expense. Included in the unrecognized tax benefit as at December 31, 2008 is interest and penalties of $9.6 million (2007 – $7.0 million). Under FIN 48, unrecognized tax benefits are classified as current or long-term liabilities as opposed to future income tax liabilities.
Reconciliation of unrecognized tax benefits

Year ended December 31, |  | 2008 |  |  |  | 2007 |
Unrecognized tax benefits, beginning of year |  | $ | 44,407 |  |  |  | $ | 40,047 |
Additions: |  |  |  |  |  |  |  |  |
Prior year’s tax positions |  |  | 2,822 |  |  |  |  | 5,770 |
Assumed on acquisition of Grey Wolf, Inc. |  |  | 9,696 |  |  |  |  | — |
Reductions: |  |  |  |  |  |  |  |  |
Prior year’s tax positions |  |  | (362 | ) |  |  |  | (1,410 | )
Unrecognized tax benefits, end of year |  | $ | 56,563 |  |  |  | $ | 44,407 |

It is anticipated that approximately $9.0 million (2007 – $8.4 million) of an unrecognized tax position that relates to past reorganization activities will be realized during the next 12 months and has been classified as a current liability. Subject to the results of audit examinations by taxing authorities and/or legislative changes by taxing jurisdictions, Precision does not anticipate further adjustments of unrecognized tax positions during the next 12 months that would have a material impact on the financial statements of Precision.
There is no difference between the amounts recorded for tax exposures under Canadian and U.S. GAAP.
(b) Equity settled unit based compensation
As described in Note 14(c), the Trust has an equity settled unit based compensation plan for non-management directors. Trust units issued upon settlement of this plan are redeemable (see Note 20(d)) therefore under U.S. GAAP are accounted for as a liability based award. The liability is re-measured, until settlement, at the end of each reporting period with the resultant change being charged or credited to the statement of earnings as compensation expense.
(c) Cash settled unit based compensation
As described in Note 14(a), the Trust has a cash settled unit appreciation rights plan. Under Canadian GAAP this plan is treated as a liability based compensation plan and recorded at its intrinsic value. Under U.S. GAAP rights issued under this plan would be measured at their fair value, and re-measured at fair value at each reporting date with the change in the obligation charged as unit based compensation. At December 31, 2008 the fair value and intrinsic value of the rights were insignificant.
(d) Redemption of Trust units
Under the Declaration of Trust, Trust units are redeemable at any time on demand by the unitholder for cash and notes (see Note 12). Under U.S. GAAP, the amount included on the consolidated balance sheet for Unitholders’ equity would be moved to temporary equity and recorded at an amount equal to the redemption value of the Trust units as at the balance sheet date. The same accounting treatment would be applicable to the exchangeable LP units. The redemption value of the Trust units and the exchangeable LP units is determined with respect to the trading value of the Trust units as at each balance sheet date, and the amount of the redemption value is classified as temporary equity. Changes (increases and decreases) in the redemption value during a period results in a change to temporary equity and is charged to retained earnings.
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(e) Debt issuance costs
Under U.S. GAAP debt issuance costs are recorded as a deferred charge and amortized over the term of the debt instrument. Canadian GAAP requires that such costs be presented as a reduction of the related debt, resulting in a $159.3 million reclassification from long-term debt to other noncurrent assets at December 31, 2008.
(f) Goodwill
In 2000 the Trust adopted the liability method of accounting for future income taxes without restatement of prior years. As a result, the Trust recorded an adjustment to retained earnings and future tax liability in the amount of $70.0 million at January 1, 2000. U.S. GAAP requires the use of the liability method prescribed in the Statement of Financial Accounting Standards (SFAS) No. 109, which substantially conforms to the Canadian GAAP accounting standard adopted in 2000. Application of U.S. GAAP in years prior to 2000 would have resulted in $70.0 million of additional goodwill being recognized at January 1, 2000 as opposed to an implementation adjustment to retained earnings allowed under Canadian GAAP. Prior to 2002 goodwill was amortized under Canadian and U.S. GAAP. As a result, $7.0 million of amortization was recorded on the additional goodwill in 2000 and 2001 under U.S. GAAP. In 2007 and 2008 the U.S. GAAP financial statements reflect an increase in goodwill of $63.0 million and a corresponding increase in retained earnings.
(g) Business acquisitions
Under SFAS 141, “Business Combinations”, supplemental pro forma disclosure is required for significant business combinations occurring during the year. On December 23, 2008 Precision completed the business acquisition of Grey Wolf, Inc. with results of operations acquired included in the consolidated financial statements from this date.
The following unaudited pro forma information provides an indication of what the Trust’s results of operations might have been under U.S. GAAP, had the Grey Wolf acquisition taken place on January 1, 2008:

Pro Forma (unaudited) |  | 2008 |  |  |  | 2007 |
Revenue |  | $ | 2,038,828 |  |  |  | $ | 1,983,046 |
Net earnings |  | $ | 289,892 |  |  |  | $ | 437,239 |
Earnings per unit: |  |  |  |  |  |  |  |  |
Basic |  | $ | 1.81 |  |  |  | $ | 2.73 |
Diluted |  | $ | 1.81 |  |  |  | $ | 2.73 |

(h) New accounting policies adopted
On January 1, 2008, Precision adopted SFAS 157, Fair Value Measurements with the deferral for certain non-financial assets and liabilities. SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. On February 12, 2008, SFAS 157-2 was issued which allows for a one year deferral for the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). Beginning January 1, 2009, Precision will adopt the provisions for non-financial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis.
SFAS 157 (as amended), defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.
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Beginning January 1, 2008, assets and liabilities recorded or disclosed at fair value in the consolidated balance sheet are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels – defined by SFAS 157 and directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities – are as follows:
Level I — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date;
Level II — Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life; and
Level III — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.
The estimated fair value of the fixed rate unsecured credit facility and the unsecured convertible notes as disclosed in Note 22 is based on level II inputs. The fair value is estimated considering the risk free interest rates on government debt instruments of similar maturities, adjusted for estimated credit risk, industry risk and market risk premiums and considering the debt holders ability to demand redemption of the debt.
On January 1, 2008, Precision adopted SFAS 159, The Fair Value Option for Financial Assets and Liabilities – Including an amendment of FASB Statement No. 115. The statement provides entities with an irrevocable option to report selected financial assets and liabilities at fair value. The objective is to improve financial reporting by reducing both the complexity in accounting and the volatility in earnings caused by differences in existing accounting rules. The adoption of this standard had no effect on the consolidated financial statements.
(i) Recently issued accounting pronouncements
In December 2007, FASB issued SFAS 160, Non-controlling Interest in Consolidated Financial Statements. The statement clarifies the classification of non-controlling interests in the financial statements and the accounting for and reporting of transactions between the reporting entity and the holders of the non-controlling interests. The statement is effective for fiscal years beginning after December 15, 2008, and will be effective for the Trust’s December 31, 2009 year end. At this time management does not expect this statement to have a material impact on the consolidated financial statements.
In December 2007, FASB issued SFAS 141(R), Business Combinations. The statement requires most identifiable assets, liabilities, non-controlling interests and goodwill acquired in a business combination be recorded at fair value. In addition the new standard requires all business combinations be accounted for by applying the acquisition method and that all transaction costs be expensed as incurred. The statement is applicable for all business combinations occurring in fiscal years beginning after December 15, 2008, and will be effective for the Trust’s December 31, 2009 year end.
In March 2008, FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities. This standard requires enhanced disclosures about an entity’s derivative and hedging activities. Entities are required to provide enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The standard increases convergence with IFRS, as it relates to disclosures of derivative instruments. The Trust is currently reviewing the guidance, which is effective for fiscal years beginning after November 15, 2008, to determine the potential impact, if any, on its consolidated financial statements.
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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, |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Earnings from continuing operations under Canadian GAAP |  | $ | 302,730 |  |  |  | $ | 342,820 |  |  | $ | 572,512 |
Adjustments under U.S. GAAP: |  |  |  |  |  |  |  |  |  |  |  |  |
Equity-based compensation expense |  |  | 183 |  |  |  |  | 35 |  |  |  | — |
Earnings from continuing operations under U.S. GAAP |  |  | 302,913 |  |  |  |  | 342,855 |  |  |  | 572,512 |
Earnings from discontinued operations under Canadian and U.S. GAAP |  |  | — |  |  |  |  | 2,956 |  |  |  | 7,077 |
Net earnings and comprehensive income under U.S. GAAP |  | $ | 302,913 |  |  |  | $ | 345,811 |  |  | $ | 579,589 |
Earnings from continuing operations per unit under U.S. GAAP: |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | 2.39 |  |  |  | $ | 2.73 |  |  | $ | 4.56 |
Diluted |  | $ | 2.39 |  |  |  | $ | 2.73 |  |  | $ | 4.56 |
Earnings per unit under U.S. GAAP: |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | 2.39 |  |  |  | $ | 2.75 |  |  | $ | 4.62 |
Diluted |  | $ | 2.39 |  |  |  | $ | 2.75 |  |  | $ | 4.62 |
Consolidated Statements of Retained Earnings (Deficit) |  |  |  |  |  |  |  |  |  |  |  |  |
Years ended December 31, |  | 2008 |  |  |  | 2007 |  |  | 2006 |
Retained earnings (deficit) under U.S. GAAP, beginning of year |  | $ | (350,898 | ) |  |  | $ | (1,873,490 | ) |  | $ | (3,167,045 | )
Net earnings under U.S. GAAP |  |  | 302,913 |  |  |  |  | 345,811 |  |  |  | 579,589 |
Distributions declared |  |  | (224,688 | ) |  |  |  | (276,667 | ) |  |  | (471,524 | )
Change in redemption value of temporary equity |  |  | 1,333,475 |  |  |  |  | 1,453,448 |  |  |  | 1,185,490 |
Retained earnings (deficit) under U.S. GAAP, end of year |  | $ | 1,060,802 |  |  |  | $ | (350,898 | ) |  | $ | (1,873,490 | )

Consolidated Balance Sheets

|  | 2008 |  |  |  | 2007 |
As at December 31, |  | As reported |  |  | U.S. GAAP |  |  |  | As reported |  |  | U.S. GAAP |
Current assets |  | $ | 685,229 |  |  | $ | 685,229 |  |  |  | $ | 271,823 |  |  | $ | 271,823 |
Income taxes recoverable |  |  | 58,055 |  |  |  | 58,055 |  |  |  |  | — |  |  |  | — |
Other long-term assets |  |  | — |  |  |  | 159,300 |  |  |  |  | — |  |  |  | — |
Property, plant and equipment |  |  | 3,243,213 |  |  |  | 3,243,213 |  |  |  |  | 1,210,587 |  |  |  | 1,210,587 |
Intangibles |  |  | 5,676 |  |  |  | 5,676 |  |  |  |  | 318 |  |  |  | 318 |
Goodwill |  |  | 841,529 |  |  |  | 904,558 |  |  |  |  | 280,749 |  |  |  | 343,778 |
|  | $ | 4,833,702 |  |  | $ | 5,056,031 |  |  |  | $ | 1,763,477 |  |  | $ | 1,826,506 |
Current liabilities |  | $ | 339,900 |  |  | $ | 349,780 |  |  |  | $ | 131,449 |  |  | $ | 140,117 |
Long-term liabilities |  |  | 30,951 |  |  |  | 30,951 |  |  |  |  | 13,896 |  |  |  | 13,896 |
Long-term debt |  |  | 1,368,349 |  |  |  | 1,527,649 |  |  |  |  | 119,826 |  |  |  | 119,826 |
Future income taxes |  |  | 770,623 |  |  |  | 713,918 |  |  |  |  | 181,633 |  |  |  | 137,226 |
Other long-term liabilities |  |  | — |  |  |  | 47,605 |  |  |  |  | — |  |  |  | 36,011 |
Temporary equity |  |  | — |  |  |  | 1,309,967 |  |  |  |  | — |  |  |  | 1,730,328 |
Unitholders’ capital |  |  | 2,355,590 |  |  |  | — |  |  |  |  | 1,442,476 |  |  |  | — |
Contributed surplus |  |  | 998 |  |  |  | — |  |  |  |  | 307 |  |  |  | — |
Accumulated other comprehensive income |  |  | 15,359 |  |  |  | 15,359 |  |  |  |  | — |  |  |  | — |
Retained earnings (deficit) |  |  | (48,068 | ) |  |  | 1,060,802 |  |  |  |  | (126,110 | ) |  |  | (350,898 | )
|  | $ | 4,833,702 |  |  | $ | 5,056,031 |  |  |  | $ | 1,763,477 |  |  | $ | 1,826,506 |

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NOTE 21. SEGMENTED INFORMATION
The Trust operates primarily in Canada and the United States, in two industry segments; Contract Drilling Services and Completion and Production Services. Contract Drilling Services includes drilling rigs, procurement and distribution of oilfield supplies, camp and catering services, and manufacture, sale and repair of drilling equipment. Completion and Production Services includes service rigs, snubbing units, wastewater treatment units, and oilfield equipment rental.

|  | Contract |  |  | Completion and |  |  |  |  |  |  |  |  |  |
|  | Drilling |  |  | Production |  |  | Corporate |  |  | Inter-segment |  |  |  |
2008 |  | Services |  |  | Services |  |  | and Other |  |  | Eliminations |  |  | Total |
Revenue |  | $ | 809,317 |  |  | $ | 308,624 |  |  | $ | — |  |  | $ | (16,050 | ) |  | $ | 1,101,891 |
Segment profit (loss) (1) |  |  | 310,240 |  |  |  | 86,104 |  |  |  | (41,596 | ) |  |  | — |  |  |  | 354,748 |
Depreciation and amortization |  |  | 57,076 |  |  |  | 22,966 |  |  |  | 3,787 |  |  |  | — |  |  |  | 83,829 |
Total assets |  |  | 4,289,517 |  |  |  | 448,697 |  |  |  | 95,488 |  |  |  | — |  |  |  | 4,833,702 |
Goodwill |  |  | 729,390 |  |  |  | 112,139 |  |  |  | — |  |  |  | — |  |  |  | 841,529 |
Capital expenditures* |  |  | 202,863 |  |  |  | 23,713 |  |  |  | 3,003 |  |  |  | — |  |  |  | 229,579 |

* |  | Excludes business acquisitions

|  | Contract |  |  | Completion and |  |  |  |  |  |  |  |  |  |
|  | Drilling |  |  | Production |  |  | Corporate |  |  | Inter-segment |  |  |  |
2007 |  | Services |  |  | Services |  |  | and Other |  |  | Eliminations |  |  | Total |
Revenue |  | $ | 694,340 |  |  | $ | 327,471 |  |  | $ | — |  |  | $ | (12,610 | ) |  | $ | 1,009,201 |
Segment profit (loss) (1) |  |  | 284,754 |  |  |  | 100,596 |  |  |  | (28,999 | ) |  |  | — |  |  |  | 356,351 |
Depreciation and amortization |  |  | 43,120 |  |  |  | 31,421 |  |  |  | 3,785 |  |  |  | — |  |  |  | 78,326 |
Total assets |  |  | 1,282,865 |  |  |  | 457,587 |  |  |  | 23,025 |  |  |  | — |  |  |  | 1,763,477 |
Goodwill |  |  | 172,440 |  |  |  | 108,309 |  |  |  | — |  |  |  | — |  |  |  | 280,749 |
Capital expenditures |  |  | 159,004 |  |  |  | 26,772 |  |  |  | 1,230 |  |  |  | — |  |  |  | 187,006 |

|  | 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 |
Segment profit (loss) (1) |  |  | 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
(1) |  | Segment profit (loss) is defined as revenue less operating, general and administrative, depreciation and amortization and foreign exchange expenses. A reconciliation of segment profit (loss) to earnings from continuing operations before income taxes is as follows:

|  | 2008 |  |  |  | 2007 |  |  | 2006 |
Total segment profit (loss) |  | $ | 354,748 |  |  |  | $ | 356,351 |  |  | $ | 595,279 |
Add (deduct): |  |  |  |  |  |  |  |  |  |  |  |  |
Interest: |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt |  |  | (14,478 | ) |  |  |  | (7,767 | ) |  |  | (8,800 | )
Other |  |  | (151 | ) |  |  |  | (106 | ) |  |  | (171 | )
Income |  |  | 455 |  |  |  |  | 555 |  |  |  | 942 |
Other |  |  | — |  |  |  |  | — |  |  |  | 408 |
Earnings from continuing operations before income taxes |  | $ | 340,574 |  |  |  | $ | 349,033 |  |  | $ | 587,658 |

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The Corporation’s operations are carried on in the following geographic locations:

|  |  |  |  |  |  |  |  |  |  |  |  |  | Inter-segment |  |  |  |
2008 |  | Canada |  |  | United States |  |  | International |  |  | Eliminations |  |  | Total |
Revenue |  | $ | 909,001 |  |  | $ | 189,796 |  |  | $ | 4,686 |  |  | $ | (1,592 | ) |  | $ | 1,101,891 |
Total assets |  |  | 1,741,462 |  |  |  | 3,033,378 |  |  |  | 58,862 |  |  |  | — |  |  |  | 4,833,702 |
|  |  |  |  |  |  |  |  |  |  |  |  |  | Inter-segment |  |  |  |
2007 |  | Canada |  |  | United States |  |  | International |  |  | Eliminations |  |  | Total |
Revenue |  | $ | 958,937 |  |  | $ | 51,082 |  |  | $ | — |  |  | $ | (818 | ) |  | $ | 1,009,201 |
Total assets |  |  | 1,651,920 |  |  |  | 108,683 |  |  |  | 2,874 |  |  |  | — |  |  |  | 1,763,477 |
|  |  |  |  |  |  |  |  |  |  |  |  |  | Inter-segment |  |  |  |
2006 |  | Canada |  |  | United States |  |  | International |  |  | Eliminations |  |  | Total |
Revenue |  | $ | 1,432,062 |  |  | $ | 5,645 |  |  | $ | — |  |  | $ | (123 | ) |  | $ | 1,437,584 |
Total assets |  |  | 1,752,403 |  |  |  | 8,783 |  |  |  | — |  |  |  | — |  |  |  | 1,761,186 |

NOTE 22. FINANCIAL INSTRUMENTS
(a) Fair value
The carrying value of cash, accounts receivable, bank indebtedness, accounts payable and accrued liabilities and distributions payable approximate their fair value due to the relatively short period to maturity of the instruments. The fair value of the Secured Facilities approximates its carrying value as it bears interest at floating rates. The fair value of the Unsecured Facility approximates carrying value due to the short period from issuance to year end. The unsecured convertible notes were recorded at their estimated fair value as part of allocating the Grey Wolf purchase consideration on December 23, 2008. The carrying value of the unsecured convertible notes approximates their fair value due to the short period that has elapsed since the unsecured convertible notes were recorded.
(b) Credit risk
Accounts receivable includes balances from a large number of customers primarily operating in the oil and gas industry. The Trust manages credit risk by assessing the creditworthiness of its customers before providing services and on an ongoing basis as well as monitoring the amount and age of balances outstanding. In some instances the Trust will take additional measures to reduce credit risk including obtaining letters of credit and prepayments from customers. When indicators of credit problems appear the Trust takes appropriate steps to reduce its exposure including negotiating with the customer, filing liens and entering into litigation. The Trust views the credit risks on these amounts as normal for the industry. The Trust does not have any significant accounts receivable at December 31, 2008 that are past due and uncollectible.
As at December 31, 2008 the Trust’s allowance for doubtful accounts was $6.2 million (2007 — $6.4 million). Included in net earnings for the year ended December 31, 2008 is an expense of $0.6 million (2007 — $1.2 million) related to a provision for doubtful accounts.
(c) Interest rate risk
The Trust is exposed to interest rate risk with respect to interest expense on its credit facilities. The Trust manages its interest rate exposure by incurring a combination of fixed and floating rate debt obligations of varying maturities in appropriate levels relative to its expected cash flows from operations. If interest rates applying to long-term debt during the year had been 100 basis points lower or higher, with all other variables held constant, earnings from continuing operations would have changed by approximately $2.1 million (2007 — $1.1 million), net of income tax. Applying a 100 basis points change in interest rates to the Trust’s long-term debt balance at December 31, 2008, with all other variables held constant, would impact earnings from continuing operations, on a go forward basis, by approximately $15.8 million.
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(d) Foreign currency risk
The Trust is exposed to foreign currency fluctuations in relation to the working capital and long-term debt of its United States operations and certain long-term debt facilities of its Canadian operations. The Trust has no significant exposures to foreign currencies other than the U.S. dollar. The Trust monitors its foreign currency exposure and attempts to minimize the impact by aligning appropriate levels of U.S. dollar denominated debt with cash flows from United States based operations.
The following financial instruments were denominated in U.S. dollars at December 31, 2008:

|  | Canadian |  |  | U.S. |
|  | Operations |  |  | Operations |
Cash |  | $ | 100 |  |  | $ | 65,619 |
Accounts receivable |  |  | 49 |  |  |  | 262,461 |
Accounts payable and accrued liabilities |  |  | (15,861 | ) |  |  | (112,983 | )
Long-term liabilities, excluding long-term incentive plans |  |  | — |  |  |  | (19,158 | )
Long-term debt, including current portion |  |  | (918,591 | ) |  |  | (262,301 | )
Net foreign currency exposure |  | $ | (934,303 | ) |  | $ | (66,362 | )
Impact of $ 0.01 change in the U.S. dollar to Canadian dollar exchange rate on net earnings |  | $ | 9,343 |  |  | $ | — |
Impact of $ 0.01 change in the U.S. dollar to Canadian dollar exchange rate on comprehensive income |  | $ | — |  |  | $ | 664 |

(e) Liquidity risk
Liquidity risk is the exposure of the Trust to the risk of not being able to meet its financial obligations as they become due. The Trust manages liquidity risk by monitoring and reviewing actual and forecasted cash flows to ensure there are available cash resources to meet these needs. The following are the contractual maturities of the Trust’s financial liabilities as at December 31, 2008:

(Stated in thousands) |  | 2009 |  |  | 2010 |  |  | 2011 |  |  | 2012 |  |  | 2013 |  |  | Thereafter |  |  | Total |
Long-term debt (1) |  | $ | 48,953 |  |  | $ | 69,495 |  |  | $ | 69,495 |  |  | $ | 90,037 |  |  | $ | 382,896 |  |  | $ | 594,512 |  |  | $ | 1,255,388 |
Interest on long-term debt (2) |  |  | 114,953 |  |  |  | 110,455 |  |  |  | 105,075 |  |  |  | 99,288 |  |  |  | 92,673 |  |  |  | 59,015 |  |  |  | 581,459 |
Commitments |  |  | 77,039 |  |  |  | 68,557 |  |  |  | 6,763 |  |  |  | 1,608 |  |  |  | 1,203 |  |  |  | 5,132 |  |  |  | 160,302 |
Total |  | $ | 240,945 |  |  | $ | 248,507 |  |  | $ | 181,333 |  |  | $ | 190,933 |  |  | $ | 476,772 |  |  | $ | 658,659 |  |  | $ | 1,997,149 |

(1) |  | Excludes unsecured convertible notes as these debt instruments contain a provision (see Note 10) whereby Precision is required to provide holders of the notes with an offer to purchase all or a portion of their notes, including accrued but unpaid interest to the date of purchase, which Precision expects to repay in 2009 with proceeds received from an equity offering (see Note 28) and existing credit facilities. Upon completion of this transaction, the Unsecured Facility would increase to approximately $ 287.8 million (US$ 235 million) with repayments in 2016. Interest on the unsecured convertible notes to the date of purchase is approximately $ 2.8 million (US$ 2.3 million). Amounts are after giving effect to the February 4, 2009 re-allocation between the Term Loan A and Term Loan B facilities (see Note 10).
(2) |  | Interest has been calculated based upon debt balances, interest rates and foreign exchange rates in effect as at December 31, 2008.

NOTE 23. CAPITAL MANAGEMENT
The Trust’s strategy is to carry a capital base to maintain investor, creditor and market confidence and to sustain future development of the business. The Trust seeks to maintain a balance between the level of long-term debt and unitholders’ equity to ensure access to capital markets to fund growth and working capital given the cyclical nature of the oilfield services sector. On a historical basis, the Trust has maintained a conservative ratio of long-term debt to long-term debt plus equity. The Grey Wolf acquisition caused the Trust to increase these levels. As at December 31, 2008 and 2007 these ratios were as follows:

|  | 2008 |  |  |  | 2007 |
Long-term debt |  | $ | 1,368,349 |  |  |  | $ | 119,826 |
Unitholders’ equity |  |  | 2,323,879 |  |  |  |  | 1,316,673 |
Total capitalization |  | $ | 3,692,228 |  |  |  | $ | 1,436,499 |
Long-term debt to long-term debt plus equity ratio |  |  | 0.37 |  |  |  |  | 0.08 |

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The increase in long-term debt for Precision has coincided with the severe contraction in global debt and equity markets. The limited availability of capital has created a challenging economic environment at December 31, 2008 and Precision expects demand for its drilling and other oilfield services to decline in the short-term.
Accordingly, Precision has undertaken a debt reduction plan to reduce long-term debt levels and strengthen its capital structure. Included in this management plan are initiatives to keep capital expenditures for the purchase of property, plant and equipment at efficient levels, limit and suspend cash distributions to unitholders and raise additional unitholder capital through the issuance of Trust units, as described in greater detail in Note 28.
In addition, Precision continues to pursue market opportunities to set in place permanent cost of debt terms associated with long-term debt facilities as outlined in Note 10.
On December 15, 2006 the Minister of Finance (Canada) issued guidelines establishing “normal growth” limitations designed to limit the ability of a trust to issue equity (including convertible debentures or other equity substitutes) that exceeds certain specified percentages of the market capitalization of a trust on October 31, 2006 and amended such guidelines effective December 4, 2008. The normal growth limitation is cumulative in nature to the extent not taken and for the year ended December 31, 2008 the Trust’s normal growth limitation was approximately $ 4 billion. The Trust will be a specified investment flow-through (“SIFT”) trust, subject to the SIFT tax rules, on the earlier of January 1, 2011 or the first day after it exceeds the normal growth guidelines.
The Trust is bound by a debt covenant limiting the Trust’s ability to make distributions to unitholders and incur additional indebtedness as described in Note 10.
NOTE 24. SUPPLEMENTAL INFORMATION

|  | 2008 |  |  |  | 2007 |  |  | 2006 |
Interest paid |  | $ | 13,394 |  |  |  | $ | 7,870 |  |  | $ | 8,929 |
Income taxes paid |  | $ | 764 |  |  |  | $ | 4,307 |  |  | $ | 207,160 |
Components of change in non-cash working capital balances: |  |  |  |  |  |  |  |  |  |  |  |  |
Accounts receivable |  | $ | (114,444 | ) |  |  | $ | 98,055 |  |  | $ | 148,046 |
Inventory |  |  | 603 |  |  |  |  | (182 | ) |  |  | (2,038 | )
Accounts payable and accrued liabilities |  |  | 56,299 |  |  |  |  | (49,338 | ) |  |  | (4,736 | )
Income taxes |  |  | (4,446 | ) |  |  |  | 2,749 |  |  |  | (172,634 | )
|  | $ | (61,988 | ) |  |  | $ | 51,284 |  |  | $ | (31,362 | )

The components of accounts receivable are as follows:

|  | 2008 |  |  |  | 2007 |
Trade |  | $ | 387,004 |  |  |  | $ | 144,468 |
Accrued trade |  |  | 178,946 |  |  |  |  | 96,869 |
Prepaids and other |  |  | 35,803 |  |  |  |  | 15,279 |
|  | $ | 601,753 |  |  |  | $ | 256,616 |

The components of accounts payable and accrued liabilities are as follows:

|  | 2008 |  |  |  | 2007 |
Accounts payable |  | $ | 136,054 |  |  |  | $ | 36,742 |
Accrued liabilities: |  |  |  |  |  |  |  |  |
Payroll |  |  | 78,143 |  |  |  |  | 28,527 |
Other |  |  | 55,925 |  |  |  |  | 15,595 |
|  | $ | 270,122 |  |  |  | $ | 80,864 |

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NOTE 25. CONTINGENCIES AND COMMITMENTS
The business and operations of the Trust are complex and the Trust has executed a number of significant financings, business combinations, acquisitions and dispositions over the course of its history. The computation of income taxes payable as a result of these transactions involves many complex factors as well as the Trust’s interpretation of relevant tax legislation and regulations. 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 owed, with estimated interest but without penalties, could be up to $ 382 million, including $ 58 million recorded as a long-term receivable.
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’s subsidiary, Precision Drilling Oilfield Services Corporation, as the successor to Grey Wolf, is subject to litigation regarding the Grey Wolf acquisition. A class action petition was filed alleging the Grey Wolf board of directors breached their fiduciary duties and Grey Wolf aided and abetted this breach. In March 2009, the court requested that a motion for summary judgment be filed and heard to determine as a matter of law whether there is a viable cause of action. In addition, two shareholder derivative actions were filed alleging that Grey Wolf and its board of directors breached their fiduciary duties and acted with negligence or gross negligence in failing to maximize shareholder value. The Plaintiffs of the two derivative actions have agreed in principal to dismissals of their cases with prejudice and the parties are finalizing documents to present to the court.
The Trust maintains a level of insurance coverage deemed appropriate by management for matters for which insurance coverage can be acquired.
NOTE 26. 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.

84 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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NOTE 27. DISCONTINUED OPERATIONS
The details of disposals of discontinued operations are as follows:
2007
In September 2007 the Trust received $ 3.0 million as partial settlement of an outstanding matter associated with a previous business divestiture.
2006
In January 2007, the Trust received $ 21.3 million as payment of the working capital adjustment related to the 2005 disposition of its Energy Services and International Contract Drilling divisions to Weatherford International Ltd. This amount had been recorded in accounts receivable at December 31, 2006.
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).
The following table provides additional information with respect to amounts included in the statements of earnings related to discontinued operations:

|  | 2008 |  |  |  | 2007 |  |  | 2006 |
Gain on disposal: |  |  |  |  |  |  |  |  |  |  |  |  |
Gain on disposal of United Diamond |  | $ | — |  |  |  | $ | — |  |  | $ | 2,070 |
Gain on disposal of Energy services and International contract drilling |  |  | — |  |  |  |  | 2,956 |  |  |  | 962 |
Gain on disposal of CEDA |  |  | — |  |  |  |  | — |  |  |  | 4,045 |
|  |  | — |  |  |  |  | 2,956 |  |  |  | 7,077 |
Net earnings of discontinued operations |  | $ | — |  |  |  | $ | 2,956 |  |  | $ | 7,077 |

The following table provides additional information with respect to amounts included in the statements of cash flow related to discontinued operations:

|  | 2008 |  |  |  | 2007 |  |  | 2006 |
Net earnings of discontinued operations |  | $ | — |  |  |  | $ | 2,956 |  |  | $ | 7,077 |
Items not affecting cash: |  |  |  |  |  |  |  |  |  |  |  |  |
Gain on disposal of discontinued operations |  |  | — |  |  |  |  | (2,956 | ) |  |  | (7,077 | )
Funds provided by discontinued operations |  | $ | — |  |  |  | $ | — |  |  | $ | — |

NOTE 28. SUBSEQUENT EVENTS
On February 4, 2009 the Trust filed a short form base shelf prospectus that allows the Trust to raise up to US$ 800 million through the sale and issue of trust units, debt securities, warrants, and subscription receipts.
On February 18, 2009 the Trust issued 46,000,000 trust units at a price of US$ 3.75 per unit for aggregate gross proceeds of $ 217.3 million, net of proceeds of $ 208.6 million (US$ 172.5 million, net proceeds of US$ 165.6 million). The proceeds will be used in the repurchase of outstanding convertible notes which were assumed in conjunction with the Grey Wolf acquisition.

PRECISION DRILLING TRUST 85

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UNIT TRADING SUMMARY — 2008
The Toronto Stock Exchange (TSX)
The New York Stock Exchange (NYSE)

86 SUPPLEMENTAL INFORMATION

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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) |  | 2008 |  |  |  | 2007 |  |  | 2006 |  |  | 2005 |  |  | 2004 |
Revenue |  | $ | 1,101.9 |  |  |  | $ | 1,009.2 |  |  | $ | 1,437.6 |  |  | $ | 1,269.2 |  |  | $ | 1,028.5 |
Expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating |  |  | 598.2 |  |  |  |  | 516.1 |  |  |  | 688.2 |  |  |  | 641.8 |  |  |  | 566.3 |
General and administrative |  |  | 67.2 |  |  |  |  | 56.0 |  |  |  | 81.2 |  |  |  | 76.4 |  |  |  | 64.2 |
Reorganization costs |  |  | — |  |  |  |  | — |  |  |  | — |  |  |  | 17.5 |  |  |  | — |
EBITDA |  |  | 436.5 |  |  |  |  | 437.1 |  |  |  | 668.2 |  |  |  | 533.5 |  |  |  | 398.0 |
Depreciation and amortization |  |  | 83.8 |  |  |  |  | 78.3 |  |  |  | 73.2 |  |  |  | 71.6 |  |  |  | 74.8 |
Foreign exchange |  |  | (2.0 | ) |  |  |  | 2.4 |  |  |  | (0.3 | ) |  |  | (3.5 | ) |  |  | (8.1 | )
Operating earnings |  |  | 354.7 |  |  |  |  | 356.4 |  |  |  | 595.3 |  |  |  | 465.4 |  |  |  | 331.3 |
Interest, net |  |  | 14.1 |  |  |  |  | 7.4 |  |  |  | 8.0 |  |  |  | 29.3 |  |  |  | 46.3 |
Premium on redemption of bonds |  |  | — |  |  |  |  | — |  |  |  | — |  |  |  | 71.9 |  |  |  | — |
Loss on disposal of short-term investments |  |  | — |  |  |  |  | — |  |  |  | — |  |  |  | 71.0 |  |  |  | — |
Other |  |  | — |  |  |  |  | — |  |  |  | (0.4 | ) |  |  | — |  |  |  | (4.9 | )
Earnings from continuing operations before income taxes |  |  | 340.6 |  |  |  |  | 349.0 |  |  |  | 587.7 |  |  |  | 293.2 |  |  |  | 289.9 |
Income taxes |  |  | 37.9 |  |  |  |  | 6.2 |  |  |  | 15.2 |  |  |  | 72.4 |  |  |  | 101.8 |
Earnings from continuing operations |  |  | 302.7 |  |  |  |  | 342.8 |  |  |  | 572.5 |  |  |  | 220.8 |  |  |  | 188.1 |
Discontinued operations, net of tax |  |  | — |  |  |  |  | 3.0 |  |  |  | 7.1 |  |  |  | 1,409.8 |  |  |  | 59.3 |
Net earnings |  |  | 302.7 |  |  |  |  | 345.8 |  |  |  | 579.6 |  |  |  | 1,630.6 |  |  |  | 247.4 |
Retained earnings (deficit), beginning of year |  |  | (126.1 | ) |  |  |  | (195.2 | ) |  |  | (303.3 | ) |  |  | 1,041.7 |  |  |  | 794.3 |
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 |  |  | (224.7 | ) |  |  |  | (276.7 | ) |  |  | (471.5 | ) |  |  | (70.5 | ) |  |  | — |
Retained earnings (deficit), end of year |  | $ | (48.1 | ) |  |  | $ | (126.1 | ) |  | $ | (195.2 | ) |  | $ | (303.3 | ) |  | $ | 1,041.7 |
Earnings per unit/share from continuing operations: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | 2.39 |  |  |  | $ | 2.73 |  |  | $ | 4.56 |  |  | $ | 1.79 |  |  | $ | 1.63 |
Diluted |  | $ | 2.39 |  |  |  | $ | 2.73 |  |  | $ | 4.56 |  |  | $ | 1.76 |  |  | $ | 1.61 |
Earnings per unit/share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | 2.39 |  |  |  | $ | 2.75 |  |  | $ | 4.62 |  |  | $ | 13.22 |  |  | $ | 2.14 |
Diluted |  | $ | 2.39 |  |  |  | $ | 2.75 |  |  | $ | 4.62 |  |  | $ | 13.00 |  |  | $ | 2.11 |

PRECISION DRILLING TRUST 87

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Precision Drilling Trust
ADDITIONAL SELECTED FINANCIAL INFORMATION

Years ended December 31, |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
(Stated in millions of Canadian dollars, |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
except per unit/share amounts) |  | 2008 |  |  |  | 2007 |  |  | 2006 |  |  | 2005 |  |  | 2004 |
Return on sales — % (1) |  |  | 27.5 |  |  |  |  | 34.0 |  |  |  | 39.8 |  |  |  | 17.4 |  |  |  | 18.3 |
Return on assets — % (2) |  |  | 12.4 |  |  |  |  | 19.9 |  |  |  | 33.6 |  |  |  | 43.3 |  |  |  | 7.3 |
Return on equity — % (3) |  |  | 19.6 |  |  |  |  | 27.0 |  |  |  | 49.4 |  |  |  | 66.1 |  |  |  | 12.3 |
Working capital |  | $ | 345.3 |  |  |  | $ | 140.4 |  |  | $ | 166.5 |  |  | $ | 152.8 |  |  | $ | 557.3 |
Current ratio |  |  | 2.0 |  |  |  |  | 2.1 |  |  |  | 1.81 |  |  |  | 1.43 |  |  |  | 2.47 |
PP&E and intangibles |  | $ | 3,248.9 |  |  |  | $ | 1,210.9 |  |  | $ | 1,108.0 |  |  | $ | 944.4 |  |  | $ | 898.1 |
Total assets |  | $ | 4,833.7 |  |  |  | $ | 1,763.5 |  |  | $ | 1,761.2 |  |  | $ | 1,718.9 |  |  | $ | 3,852.0 |
Long-term debt |  | $ | 1,368.3 |  |  |  | $ | 119.8 |  |  | $ | 140.9 |  |  | $ | 96.8 |  |  | $ | 718.9 |
Unitholders’ equity |  | $ | 2,323.9 |  |  |  | $ | 1,316.7 |  |  | $ | 1,217.1 |  |  | $ | 1,074.6 |  |  | $ | 2,321.7 |
Long-term debt to long-term debt plus equity |  |  | 0.37 |  |  |  |  | 0.08 |  |  |  | 0.10 |  |  |  | 0.08 |  |  |  | 0.24 |
Net capital expenditures from continuing operations excluding business acquisitions |  | $ | 219.1 |  |  |  | $ | 181.2 |  |  | $ | 233.7 |  |  | $ | 140.1 |  |  | $ | 113.9 |
EBITDA |  | $ | 436.5 |  |  |  | $ | 437.1 |  |  | $ | 668.2 |  |  | $ | 533.5 |  |  | $ | 398.0 |
EBITDA — % of revenue |  |  | 39.6 |  |  |  |  | 43.3 |  |  |  | 46.5 |  |  |  | 42.0 |  |  |  | 38.7 |
Operating earnings |  | $ | 354.7 |  |  |  | $ | 356.4 |  |  | $ | 595.3 |  |  | $ | 465.4 |  |  | $ | 331.3 |
Operating earnings — % of revenue |  |  | 32.2 |  |  |  |  | 35.3 |  |  |  | 41.4 |  |  |  | 36.7 |  |  |  | 32.2 |
Cash flow from continuing operations |  | $ | 343.9 |  |  |  | $ | 484.1 |  |  | $ | 609.7 |  |  | $ | 206.0 |  |  | $ | 286.4 |
Cash flow from continuing operations per unit/share Basic |  | $ | 2.72 |  |  |  | $ | 3.85 |  |  | $ | 4.86 |  |  | $ | 1.67 |  |  | $ | 2.48 |
Diluted |  | $ | 2.71 |  |  |  | $ | 3.85 |  |  | $ | 4.86 |  |  | $ | 1.64 |  |  | $ | 2.44 |
Book value per unit/share (4) |  | $ | 14.51 |  |  |  | $ | 10.47 |  |  | $ | 9.68 |  |  | $ | 8.57 |  |  | $ | 19.10 |
Price earnings ratio (5) |  |  | 4.21 |  |  |  |  | 5.53 |  |  |  | 5.84 |  |  |  | 2.90 |  |  |  | 17.6 |
Basic weighted average units/shares outstanding (000’s) |  |  | 126,507 |  |  |  |  | 125,758 |  |  |  | 125,545 |  |  |  | 123,304 |  |  |  | 115,654 |

(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) |  | Book value per unit/share was calculated by dividing unitholders’ equity by units/shares outstanding.
(5) |  | Year end closing price divided by basic earnings per unit/share.

88 SUPPLEMENTAL INFORMATION