form40vf
U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 40-F
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(Check One) |
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Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934 |
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Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2006
Commission file number 001-14534
PRECISION DRILLING TRUST
(Exact name of registrant as specified in its charter)
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Alberta, Canada
(Province or other jurisdiction of
incorporation or organization)
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1381
(Primary Standard Industrial
Classification Code Number
(if applicable))
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Not applicable
(I.R.S. Employer
Identification Number (if applicable)) |
4200-150 6th Avenue, S.W., Calgary, Alberta, Canada T2P 3Y7
(403) 716-4500
(Address and telephone number of Registrants principal executive offices)
CT Corporation System, 811 Dallas Avenue, Houston, Texas 77022
(713) 658-9486
(Name, address (including zip code) and telephone number
(including area code) of agent for service in the United States)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
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Title of each class |
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Name of each exchange on which registered |
Trust Units
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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:
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þ Annual Information Form
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þ Audited Annual Financial Statements |
Indicate the number of outstanding shares of each of the issuers classes of capital or common
stock as of the close of the period covered by the annual report: 125,536,329 Trust Units
Indicate by check mark whether the Registrant by filing the information contained in this form
is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the
Securities Exchange Act of 1934 (the Exchange Act). If Yes is marked, indicate the file number
assigned to the Registrant in connection with such Rule.
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.
The Annual Report on Form 40-F shall be incorporated by reference into, or as an exhibit to,
as applicable, the Registrants Registration Statements under the Securities Act of 1933: Form F-10
(File No. 333-115330), Form S-8 (File No. 333-124811, 333-116492 and 333-105648).
Principal Documents
The following documents have been filed as part of this Annual Report on Form 40-F and are included
immediately after this section:
(a) |
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Annual Information Form for the fiscal year ended December 31, 2006; |
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(b) |
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Managements Discussion and Analysis of Financial Condition and Results of Operations for the
fiscal year ended December 31, 2006; and |
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(c) |
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Consolidated Financial Statements for the fiscal year ended December 31, 2006 (Note 16 to the
Consolidated Financial Statements relates to United States Generally Accepted Accounting
Principles (U.S. GAAP)). |
PRECISION DRILLING TRUST
ANNUAL INFORMATION FORM
For the fiscal year ended December 31, 2006
Dated March 29, 2007
TABLE OF CONTENTS
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ii
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS
This Annual Information Form contains certain forward-looking information and statements,
including statements relating to matters that are not historical facts and statements of our
beliefs, intentions and expectations about developments, results and events which will or may occur
in the future, which constitute forward-looking information within the meaning of applicable
Canadian securities legislation and forward-looking statements within the meaning of the safe
harbor provisions of the United States Private Securities Litigation Reform Act of 1995.
Forward-looking information and statements are typically identified by words such as anticipate,
could, should, expect, seek, may, intend, likely, will, plan, estimate,
believe and similar expressions suggesting future outcomes or statements regarding an outlook.
Forward-looking information and statements in this Annual Information Form include, but are
not limited to statements with respect to:
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2007 expected cash provided by continuing operations; |
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2007 capital expenditures, including the amount and nature thereof; |
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performance of the oil and natural gas industry, including prices and supply and demand; |
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expansion, consolidation and other development trends of the oil and natural gas industry; |
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demand for and status of drilling rigs and other equipment in the oil and natural gas industry; |
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costs and financial trends for companies operating in the oil and natural gas industry; |
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world population and energy consumption trends; |
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our business strategy, including the 2007 strategy and outlook for our business segments; |
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expansion and growth of our business and operations, including diversification of our earnings base, the size and
capabilities of our drilling and service rig fleet, our market share and our position in the markets in which we
operate; |
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demand for our products and services; |
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our management strategy, including transitions in executive roles; |
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the maintenance of existing customer, supplier and partner relationships; |
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accounting policies and tax liability; |
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expected payments pursuant to contractual obligations; |
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the prospective impact of recent or anticipated regulatory changes; |
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financing strategy and compliance with debt covenants; |
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:
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the impact of general economic conditions in Canada and the United States; |
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world energy prices and government policies; |
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industry conditions, including the adoption of new environmental, taxation and other laws and regulations and
changes in how they are interpreted and enforced; |
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the impact of initiatives by the Organization of Petroleum Exporting Countries; |
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the ability of oil and natural gas companies to access external sources of debt and equity capital; |
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the effect of weather conditions on operations and facilities; |
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the existence of operating risks inherent in well servicing, contract drilling and ancillary oilfield services; |
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volatility of oil and natural gas prices; |
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oil and natural gas product supply and demand; |
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risks inherent in the ability to generate sufficient cash flow from operations to meet current and future
obligations; |
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consolidation among our customers; |
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risks associated with technology; |
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political uncertainty, including risks of war, hostilities, civil insurrection, instability or acts of terrorism; |
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the lack of availability of qualified personnel or management; |
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increased costs of operations, including costs of equipment; |
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fluctuations in interest rates; |
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stock market volatility; |
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opportunities available to or pursued by us; |
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and other factors, many of which are beyond our control. |
These risk factors are discussed in this Annual Information Form, our Annual Report and Form
40-F on file with the Canadian securities commission and the United States Securities and Exchange
Commission and available on SEDAR at www.sedar.com and the website of the U.S. Securities and
Exchange Commission at www.sec.gov, respectively. Except as required by law, Precision Drilling
Trust, Precision Drilling Limited Partnership and Precision Drilling Corporation disclaim any
intention or obligation to update or revise any forward-looking information or statements, whether
as a result of new information, future events or otherwise.
The forward-looking information and statements contained in this Annual Information Form are
expressly qualified by this cautionary statement.
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CORPORATE STRUCTURE
INCORPORATION INFORMATION AND ADDRESS
The Trust
Precision Drilling Trust (the Trust) is an unincorporated open-ended investment trust
established under the laws of the Province of Alberta pursuant to a declaration of trust dated
September 22, 2005 (the Declaration of Trust). The Trust maintains its head office and principal
place of business at 4200, 150 6th Avenue SW Calgary, Alberta, T2P 3Y7, telephone (403) 716-4500,
facsimile (403) 264-0251, email info@precisiondrilling.com and website www.precisiondrilling.com.
The Trust issued units (Trust Units) to certain former shareholders of Precision Drilling
Corporation (Precision) pursuant to a plan of arrangement which was approved by the former
shareholders of Precision at a special meeting held on October 31, 2005 (the Plan of
Arrangement).
The notice of meeting and information circular (the 2005 Special Meeting Information
Circular) with respect to the Plan of Arrangement was filed on the Canadian System for Electronic
Document Analysis and Retrieval (SEDAR) on October 3, 2005 under the SEDAR profile for Precision,
and on March 31, 2006 under the SEDAR profile for the Trust, available at www.sedar.com. Specified
pages of the 2005 Special Meeting Information Circular are incorporated herein by reference.
Precision Drilling Limited Partnership
Precision Drilling Limited Partnership (PDLP) is a limited partnership formed pursuant to
the laws of the Province of Manitoba. The Trust holds a 99.82% interest in PDLP through its
holding of Class A Limited Partnership Units (the PDLP A Units) and the remaining 0.18% of PDLP
is held by former shareholders of Precision who elected to receive Class B Limited Partnership
Units (Exchangeable Units) which are exchangeable into Trust Units on a one-for-one basis and are
the economic equivalent of Trust Units. The head and principal offices of PDLP are located at
4200, 150 6th Avenue SW Calgary, Alberta, T2P 3Y7, telephone (403) 716-4500 and facsimile (403)
264-0251, email info@precisiondrilling.com.
Precision Drilling Corporation
Precision was originally incorporated on March 25, 1985 and carried out amalgamations with
wholly-owned subsidiary companies on January 1, 2000, January 1, 2002 and January 1, 2004 pursuant
to Articles of Amalgamation and other provisions of the Business Corporations Act (Alberta). On
November 7, 2005 Precision became a wholly-owned subsidiary of PDLP. As part of the Plan of
Arrangement, Precision amalgamated with a number of its wholly-owned subsidiaries. Precision
amalgamated with: 1195309 Alberta ULC on November 23, 2005; Live Well Service Ltd. on January 1,
2006; and Terra Water Group Ltd. (Terra) on January 1, 2007. In each amalgamation the name of
the amalgamated company remained Precision Drilling Corporation. The head and principal offices
of Precision are located at 4200, 150 6th Avenue SW Calgary, Alberta, T2P 3Y7, telephone (403)
716-4500 and facsimile (403) 264-0251, email info@precisiondrilling.com.
INTERCORPORATE RELATIONSHIPS
The following table sets forth the names of the material subsidiaries (which includes
major limited liability partnerships) of the Trust, the percent of shares (or interest) owned by
the Trust and the jurisdiction of incorporation or continuance of each such subsidiary (or
partnership) as of December 31, 2006:
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Jurisdiction of |
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Incorporation or |
Name of Subsidiary or Partnership |
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Percent or Interest Owned |
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Continuance |
Precision Drilling Limited Partnership |
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99.82 |
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Manitoba |
1194312 Alberta Ltd. |
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100 |
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Alberta |
Precision Drilling Corporation |
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99.82 |
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Alberta |
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Organizational Structure of the Trust
The following diagram sets forth the organizational structure of the Trust and its material
subsidiaries as of the date hereof:
NOTES:
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As of December 31, 2006 there were 125,536,329 PDLP A Units outstanding. |
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As of December 31, 2006 there were 221,595 Exchangeable Units outstanding. |
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The interest of 1194312 Alberta Ltd. in PDLP is 0.001%. |
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Inter-company note owing by Precision to PDLP (the Promissory Note). |
GENERAL DEVELOPMENT OF THE BUSINESS
THREE YEAR HISTORY
During 2006, Precision focused capital spending on additions to property, plant and
equipment to grow and upgrade its rig fleet, initiated contract drilling operations in the United
States and acquired Terra, a privately owned wastewater treatment business operating at remote
worksites.
During 2006, Precision also initiated a plan to establish a full-cycle track record of
distributions following conversion to an income trust in November 2005. However, on October 31,
2006, the Government of Canada announced a Tax Fairness Plan containing its intentions to bring
about new tax measures including a Distribution Tax on distributions from publicly traded income
trusts and limited partnerships. The government is proposing a four-year transition period for
existing income trusts and limited partnerships whereby the new measures will not apply until their
2011 taxation year. Under the proposals, flow-through entities will be taxed more like
corporations and their investors will be treated more like shareholders. The proposed new tax
measures will impair the flow-through nature of Precision Drilling Trusts current tax structure.
If enacted into law, these tax measures would result in a distribution tax to the Trust which will
reduce the cash distributed to Unitholders (as defined below) by the amount of distribution tax
paid. Precision originally converted to a trust because the tax rules of the day allowed the
market to place a higher value for unitholders on the flow-through structure than the traditional
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corporate structure. In light of proposed tax legislative changes the Trusts board of
trustees (the Board of Trustees and each a Trustee) will be examining whether changes in the
current legal structure are appropriate and in the best interests of unitholders and, if so, when
such changes should be implemented.
Upon Precisions conversion to an income trust effective November 7, 2005, Precision began
making monthly distributions to holders of Trust Units and holders of Exchangeable Units (together
Unitholders). The Trust has a legal entity structure whereby Precision Drilling Trust,
effectively must flow its taxable income to Unitholders pursuant to its Declaration of Trust.
Distributions may be reduced, increased or entirely suspended depending on the operations of
Precision and the performance of its assets, or legislative changes in tax laws by governments in
Canada.
Precision is a mature organization that operates in a cyclical industry with seasonal swings
in revenue levels. The actual cash flow available for distribution to Unitholders is a function of
numerous factors, including financial performance, debt covenants and obligations, working capital
requirements, as well as maintenance and expansion capital expenditure requirements for the
purchase of property, plant and equipment.
In Canada, Precision is the largest provider of land based contract drilling services to oil
and natural gas exploration and production companies, based on the number of wells and metres
drilled annually. Precisions continuing business services during 2006 comprised: contract
drilling rigs; well service rigs; snubbing; procurement and distribution of oilfield supplies; camp
and catering; manufacture and refurbishment of rig equipment; portable wastewater treatment
services; as well as rental of surface oilfield equipment, tubulars, well control equipment and
wellsite accommodations.
Precision invested $171 million in expansion capital for the purchase of property, plant and
equipment and $92 million in productive capacity maintenance in 2006. When combined with the $16
million business acquisition of Terra, Precision increased its asset base by $279 million in 2006.
A total of 13 new drilling rigs were commissioned in 2006 and two were decommissioned.
The expansion of Precisions Contract Drilling Services segment in the United States began in
June 2006 with the deployment of one Super Single rig drilling to Texas. Precision deployed a
second drilling rig to the United States from Canada in early 2007 which has commenced drilling in
Colorado. As conditions warrant, Precision may deploy additional rigs from Canada into the United
States market.
Until early 2005, Precision had an aggressive global growth strategy directed toward the
supply of oilfield and industrial services to customers in Canada and internationally. Precision
grew through a series of acquisitions of related businesses in 2003 and 2004 and through
reinvestment in its core businesses to become one of the largest Canadian based international
oilfield and industrial services contractors.
During 2005, Precision underwent a significant shift in its strategic business direction with
its decision to realize the value in the international contract drilling, energy services and
industrial services segments of its business. This value was realized through the divestiture of
three business lines in the third quarter of 2005: Precision Energy Services which was the
technology services group providing cased hole and open hole wireline services, drilling and
evaluation services and production services; Precision Drilling International which was an
international land rig contractor; and CEDA International which provided industrial cleaning,
catalyst handling and mechanical services. The dispositions provided shareholders of Precision
with proceeds in the form of a special cash payment of $844 million and almost 26 million shares of
Weatherford International Ltd. (Weatherford) valued at $2.0 billion.
Those dispositions returned Precision to its original focus on oil and gas contract drilling,
service rig and supplemental business lines in western Canada. The continuing business represents
Precisions core expertise and marks a return to Precisions original business roots which date
back more than 20 years as a publicly traded company and over 50 years in operational experience.
Over the last three years, significant acquisitions, dispositions and reorganizations
consisted of the following:
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Significant Acquisitions
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On August 17, 2006, Precision acquired Terra, a privately
owned wastewater treatment business operating at remote
worksite locations for an aggregate purchase price of $16
million. Terra had 41 treatment units at the time of the
acquisition and closed the year with 51 treatment units.
The service provided by Terra complements those provided
by the LRG Catering and Precision Rentals divisions and
expands the diversity of services Precision offers
customers. |
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On May 21, 2004, Precision acquired all of the land
drilling business carried on by GlobalSantaFe Corporation
for an aggregate purchase price of US$316.5 million. That
land drilling business consisted of 31 drilling rigs, then
located in Kuwait, Saudi Arabia, Egypt, Oman and
Venezuela. |
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Pursuant to an agreement dated May 8, 2004, Precision
purchased all of the issued and outstanding shares of
Reeves Oilfield Services Ltd. for an aggregate purchase
price of £92.4 million (Great Britain Pounds). Reeves
Oilfield Services Ltd. was an international provider of
open hole wireline logging services to the oil and natural
gas industry and carried out field operations in the
western and Appalachian regions of the United States,
western Canada, Australia, Great Britain, Colombia,
Europe, the Middle East and Africa. |
Significant Dispositions
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On August 31, 2005, Precision sold its Energy Services and
International Contract Drilling divisions to Weatherford
for a purchase price consisting of 26 million common shares of Weatherford and $1.13 billion cash pursuant to a
stock purchase agreement dated June 6, 2005 between
Precision and Weatherford (the Weatherford Sale
Agreement). The Energy Services division of Precision
consisted of three main business segments: wireline
logging services; drilling and evaluation services; and
production services. Wireline services included open hole
logging, cased hole logging and completion and slick line
services. Drilling and evaluation services included
measurement-while-drilling, logging-while-drilling,
directional drilling and rotary steerable services.
Production services included well testing and controlled
pressure drilling (which included under balanced drilling
services). Precisions International Contract Drilling
division was comprised of 48 land drilling rigs operating
in Kuwait, Saudi Arabia, Oman, Iran, Egypt, India, Mexico
and Venezuela. |
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On September 13, 2005, Precision sold 100% of the shares
of CEDA International Corporation (CEDA) to an
investment entity of the Ontario Municipal Employees
Retirement System for approximately $274 million pursuant
to an agreement dated September 13, 2005 between Precision
and 1191678 Alberta Inc. (the CEDA Sale Agreement).
CEDA was a leading provider of industrial maintenance,
turnaround services and other specialized services to
various production industries in Canada and the United
States. Its main areas of operation included industrial
cleaning, catalyst handling and mechanical services
usually carried out in large facilities operating in the
oil and natural gas, petro-chemical and pulp and paper
industries. |
Significant Reorganizations
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On July 31, 2005, Precision Limited Partnership (which
carried on Precisions Canadian contract drilling, service
rig and snubbing businesses) completed a re-organization
whereby substantially all of the assets of the Precision
Drilling and Precision Well Servicing divisions of
Precision Limited Partnership were transferred to its
wholly-owned subsidiary Precision Drilling Ltd. Precision
Limited Partnership also transferred its ownership in LRG
Catering Ltd. (Precisions camp and catering business) to
Precision Drilling Ltd. |
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On August 25, 2005, Precision Limited Partnership was
dissolved, with its partners Precision Diversified
Services Ltd. and Precision being allocated their pro rata
share of the net assets of Precision Limited Partnership.
Precision Diversified Services Ltd. and Precision
transferred those net assets to Live Well Service Ltd. |
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On October 31, 2005, the shareholders of Precision
approved the Plan of Arrangement which became effective on
November 7, 2005. The Plan of Arrangement resulted in the
following: |
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the former holders of common shares of Precision received, for each share of Precision
they owned, at their option, either a Trust Unit or an Exchangeable Unit, in addition to
0.2089 of a Weatherford share and a special cash payment of $6.83; |
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Precision amalgamated with the following wholly-owned subsidiaries: Columbia Oilfield
Supply Ltd., Rostel Industries Ltd., Precision Diversified Services Ltd., LRG Catering
Ltd., Precision Rentals Ltd., 1181177 Alberta Ltd. and Precision Drilling Ltd., to form
Precision Drilling Corporation; |
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1195309 Alberta ULC, a wholly-owned subsidiary of PDLP, became indebted to PDLP; |
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all of the issued and outstanding options issued pursuant to Precisions various stock
option plans were converted into New Options (as defined in the Plan of Arrangement) which
became fully vested and were exercisable up to and including November 22, 2005; and |
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all of the PDLP A Units were issued to the Trust, representing 99.12% of the total
number of limited partnership units of PDLP (the Limited Partnership Units) outstanding,
0.88% of the Limited Partnership Units represented by Exchangeable Units were issued to
certain former shareholders of Precision, and 1194312 Alberta Ltd. (the General Partner)
became a nominal interest holder in PDLP. |
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On November 23, 2005, Precision amalgamated with 1195309 Alberta ULC to form Precision Drilling Corporation. |
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On January 1, 2006, Precision amalgamated with Live Well Service Ltd. |
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On August 17, 2006, Terra transferred substantially all of its net assets to Terra Water Systems Limited Partnership. |
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On January 1, 2007, Precision amalgamated with Terra. |
Cash Flow
The Trust holds PDLP A Units and PDLP holds a promissory note owing by Precision (the
Promissory Note). Cash generated from the operations of Precision flow to PDLP in settlement of
principal and interest owing on the Promissory Note. The cash payable to PDLP is then available to
be paid to the limited partners of PDLP which includes holders of Exchangeable Units and
indirectly, the holders of Trust Units.
Cash Distributions on Trust Units
The Trusts Board of Trustees adopted a policy of making regular cash distributions on or
about the 15th day following the end of each calendar month to Unitholders of record on
the last business day of each such calendar month or such other date as determined from time to
time by the Board of Trustees. In addition, the Declaration of Trust provides that, an amount
equal to net income of the Trust not already paid to holders of Trust Units in the year will become
payable on December 31 of each year, such that the Trust will not be liable for ordinary income
taxes for such year. Please refer to Certain Canadian Federal Income Tax Considerations Taxation
of the Trust on pages 46 and 47 of the 2005 Special Meeting Information Circular which are
incorporated by reference into this Annual Information Form.
The Board of Trustees reviews the Trusts 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 Trusts, PDLPs and Precisions
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.
7
As a result of the aforementioned factors, distributions may be reduced or suspended entirely.
The market value of the Trust Units may deteriorate if the Trust decreases cash distributions in
the future. Refer to the heading Risk Factors commencing on page 18 hereof.
Under the terms of the Declaration of Trust, the Trust is required to make distributions to
holders of Trust Units in amounts at least equal to its taxable income. Distributions may be
monthly or special and in cash or in Trust Units (in-kind) at the discretion of the Board of
Trustees. To the extent that additional cash distributions are paid and capital expenditure or
investment programs are not adjusted, debt levels may increase. In the event that a distribution
in the form of Trust Units is declared, the terms of the Declaration of Trust require that the
outstanding units be consolidated immediately subsequent to the distribution. The number of
outstanding Trust Units would remain at the number outstanding immediately prior to the unit
distribution and an amount equal to the distribution would be allocated to the holders of Trust
Units. For greater clarity, holders of Trust Units do not receive additional Trust Units during an
in-kind issuance and consolidation process.
Payments on Exchangeable Units
Holders of Exchangeable Units will be entitled to receive, and PDLP will make, subject to
applicable law, on each date on which the Board of Trustees declares a distribution on the Trust
Units, a loan in respect of each Exchangeable Unit in an amount in cash for each Exchangeable Unit
equal to the distribution declared on each Trust Unit; or in the case of a distribution declared on
the Trust Units in securities or property other than cash or Trust Units, a loan in the amount
equal to the value of such type and amount of securities or property which is the same as, or
economically equivalent to, the type and amount of property declared as a distribution on each
Trust Unit.
Any amount loaned in respect of Exchangeable Units pursuant to these distribution entitlements
will not constitute a distribution of profits or other compensation by way of income in respect of
such Exchangeable Units, rather, will constitute a non-interest bearing loan of the amount thereof,
or in the case of property, a loan in the amount equal to the fair market value thereof as
determined in good faith by the board of directors of the General Partner, which loan is repayable
on the first day of January of the calendar year next following the date of the loan or such
earlier date as may be applicable as more particularly described in paragraph 3.7 of Appendix D of
the 2005 Special Meeting Information Circular which is incorporated into this Annual Information
Form by reference.
On the date on which the loan is repayable, PDLP will make a distribution in respect of each
Exchangeable Unit equal to the amount of the loan outstanding in respect thereof. PDLP will set off
and apply the amount of any such distribution payment against the obligation of any holder of
Exchangeable Units under any loan outstanding in respect thereof.
In the event that a distribution in the form of Exchangeable Units is declared the outstanding
units will be consolidated immediately subsequent to the distribution. The number of outstanding
Exchangeable Units would remain at the number outstanding immediately prior to the unit
distribution and an amount equal to the distribution would be allocated to the holders of
Exchangeable Units. For greater clarity, holders of Exchangeable Units do not receive additional
Exchangeable Units during an in-kind issuance and consolidation process.
Distribution Reinvestment Plan
A distribution reinvestment plan (the DRIP) was approved by the Board of Trustees on
February 14, 2006. The DRIP was implemented on March 31, 2006 and allows certain holders of Trust
Units, at their option, to reinvest monthly cash distributions to acquire additional Trust Units at
the average market price as defined in the DRIP. Unless otherwise announced by the Trust,
Unitholders who are not residents of Canada are not eligible to participate, directly or
indirectly, in the DRIP. Holders of Class B Limited Partnership Units of PDLP are also not
eligible to participate in the DRIP. Generally, no brokerage fees or commissions are payable by
participants for the purchase of Trust Units under the DRIP, but holders of Trust Units should make
inquiries with their broker, investment dealer or financial institution through which their Trust
Units are held as to any policies that may result in any fees or commissions being payable. The
Trust has reserved the right to amend, terminate or suspend the DRIP at any time provided that such
amendment, termination or suspension does not prejudice the interests of holders of Trust Units.
Effective December 18, 2006 the DRIP was suspended indefinitely by the Board of Trustees.
8
Details of the DRIP are described more fully in the DRIP document available on the Trusts
website at www.precisiondrilling.com.
Board of Trustees
Pursuant to the terms of the Declaration of Trust, the Board of Trustees consists of three
members who are responsible for supervising the activities and managing the affairs of the Trust.
The Declaration of Trust provides that, subject to its terms and conditions, the Board of
Trustees has full, absolute and exclusive power, control, authority and discretion over the Trust
assets and the management of the affairs of the Trust to the same extent as if the Board of
Trustees were the sole and absolute legal and beneficial owners of the Trust assets.
Any one or more of the Board of Trustees may resign upon 30 days written notice to the Trust
and may be removed by an ordinary resolution and the vacancy created by such removal may be filled
at the same meeting, failing which it may be filled by the affirmative vote of a quorum of the
Board of Trustees.
Trustees are elected at each annual meeting of Unitholders to hold office for a term expiring
at the close of the next annual meeting. A quorum of the Board of Trustees is a majority of the
Trustees then holding office. A majority of the Trustees may fill a vacancy in the Board of
Trustees, except a vacancy resulting from an increase in the number of Trustees or from a failure
of the Unitholders to elect the required number of Trustees. In the absence of a quorum of
Trustees, or if the vacancy has arisen from a failure of the Unitholders to elect the required
number of Trustees, the Board of Trustees will promptly call a special meeting of the Unitholders
to fill the vacancy. If the Board of Trustees fails to call that meeting or if there are no
Trustees then in office, any Unitholder may call the meeting. Except as otherwise provided in the
Declaration of Trust, the Board of Trustees may, between annual meetings of Unitholders, appoint
one or more additional Trustees to serve until the next annual meeting of Unitholders, but the
number of additional Trustees will not at any time exceed one-third of the number of Trustees who
held office at the expiration of the immediately preceding annual meeting of Unitholders.
Administration Agreement
The Trust and Precision are parties to an administration agreement entered into on November 7,
2005 (the Administration Agreement). Under the terms of the Administration Agreement, Precision
provides administrative and support services to the Trust including, without limitation, those
necessary to:
|
|
ensure compliance by the Trust with continuous disclosure obligations under applicable securities legislation; |
|
|
provide investor relations services; |
|
|
provide or cause to be provided to Unitholders all information to which Unitholders are entitled under the Declaration
of Trust, including relevant information with respect to financial reporting and income taxes; |
|
|
call and hold meetings of Unitholders and distribute required materials, including notices of meetings and information
circulars, in respect of all such meetings; |
|
|
assist the Board of Trustees in calculating distributions to Unitholders; |
|
|
ensure compliance with the Trusts 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. |
9
DESCRIPTION OF THE BUSINESS OF PRECISION
GENERAL
Precisions continuing operations are carried out in two segments consisting of Contract
Drilling Services and Completion and Production Services. The Contract Drilling Services segment
includes land drilling services, camp and catering services, procurement and distribution of
oilfield supplies and the manufacture and refurbishment of drilling and service rig equipment. The
Completion and Production Services segment includes service rig well completion and workover
services, snubbing services, wastewater treatment services and the rental of oilfield surface
equipment, tubulars and well control equipment and wellsite accommodations. As at December 31,
2006, Precision had approximately 5,500 employees.
Precisions revenue by business segment from continuing operations is illustrated in the
following table:
(in thousands CDN$)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
Contract Drilling Services |
|
|
$ |
1,009,821 |
|
|
|
$ |
916,221 |
|
|
|
$ |
727,710 |
|
Completion and Production Services |
|
|
|
441,017 |
|
|
|
|
369,667 |
|
|
|
|
313,386 |
|
Inter-segment Eliminations |
|
|
|
(13,254 |
) |
|
|
|
(16,709 |
) |
|
|
|
(12,608 |
) |
|
|
|
|
|
|
|
|
|
|
Total Revenue |
|
|
$ |
1,437,584 |
|
|
|
$ |
1,269,179 |
|
|
|
$ |
1,028,488 |
|
In Canada, the economics of oilfield services align with global and regional fundamentals.
Important regional drivers include the underlying hydrocarbon make-up of the Western Canada
Sedimentary Basin (the WCSB) and the existence of an established, competitive and efficient
oilfield service infrastructure. Increasingly, natural gas production is driving economics within
the WCSB as approximately 70% of new well completions in 2006 targeted natural gas. In general,
drilling activity in the WCSB is split between three provinces with approximately 75% in Alberta,
15% in Saskatchewan and 10% in British Columbia. Areas in Canadas north hold significant promise
for the expansion of oil and natural gas services but remain as largely untapped frontier
opportunities pending government and community support. The Canadian oilfield service industry
dates to the 1940s and has given Canada the means to develop its reserves to meet domestic
consumption and to provide export capacity, primarily to the United States. Today Canada is the
worlds eighth largest producer of oil and third largest producer of natural gas. Approximately
half of Canadas oil and gas production is exported to the United States.
The hydrocarbon structures of the WCSB are diverse and conventional sources of oil and natural
gas reservoirs exist at a variety of depths which are comparatively shallow by global standards.
These conventional sources are accompanied by more costly and challenging unconventional sources
associated with oil sands, heavy oil, natural gas in coal (coal bed methane), as well as natural
gas in deeper formations. The oil sands deposits in northern Alberta are a world-scale resource
with an estimated 179 billion barrels of recoverable reserves which are second only to Saudi Arabia
in terms of reserves held by an individual country.
Precision derives essentially 100% of its revenue from the Canadian market. In 2006 an
expansion into the United States drilling market was initiated and is expected to become a larger
part of Precisions operations in the future.
10
Providing oilfield services incorporates three main elements: people, technology and
equipment. Attracting, training and retaining qualified employees is a challenge for oilfield
services providers. As exploration and production activities are taking place in an ever increasing
variety of surface and subsurface conditions, developing technology and building equipment that can
withstand increasing physical challenges and operate more efficiently is required to maintain and
improve the economics of crude oil and natural gas production. The primary economic risk assumed by
oilfield service providers relates to the volatility in activity levels which affect utilization
rates, investment in people, technology and equipment and cost controls.
The economics of oilfield services providers are largely driven by current and expected price
of crude oil and natural gas which are determined by supply and demand fundamentals on a global and
regional level. Crude oil and natural gas prices have historically been volatile. The upward
trend in commodity prices since 2002 peaked for natural gas in December 2005 and for oil in July
2006. Prices for both commodities have retreated since then but remain at reasonably high levels
when compared to pricing trends over the past five years.
CONTRACT DRILLING SERVICES
Precisions Contract Drilling Services segment is comprised of the following divisions:
|
|
Precision Drilling 240 drilling rigs approximately 29% of the Canadian industry; |
|
|
LRG Catering (LRG) 101 drilling camps approximately 16% of the industry; |
|
|
Rostel Industries (Rostel) capabilities that include engineering, machining,
fabrication, component manufacturing and repair services for drilling and service
rigs; and |
|
|
Columbia Oilfield Supply (Columbia) capabilities that include centralized
procurement, inventory and distribution of consumable supplies, |
This segment also includes the operations of the following United States subsidiary:
|
|
Precision Drilling Oilfield Services, Inc. one drilling rig was deployed to the
United States in 2006 and a second rig arrived in the United States in early 2007. |
Precision Drilling
The Precision Drilling division owns and operates the largest fleet of land drilling rigs in
Canada with 240 actively marketed drilling rigs located throughout the WCSB, accounting for
approximately 29% of the industrys fleet of 842 drilling rigs in Canada at December 31, 2006.
Oil and natural gas well drilling contracts are carried out on a daywork, meterage or turnkey
basis. Under daywork contracts, Precision charges the customer a fixed rate per day regardless of
the number of days needed to drill the well. In addition, daywork contracts usually provide for a
reduced day rate (or a lump sum amount) for mobilization of the rig to the well location and for
both assembly and dismantling of the rig. Under daywork contracts, Precision ordinarily bears no
part of the costs arising from downhole risks (such as time delays for various reasons, including a
stuck or broken drill string or blowouts). Other contracts could provide for payment on a meterage
basis, whereby Precision would be paid a fixed charge for each metre drilled regardless of the time
11
required or the problems encountered in drilling the well. Some contracts are carried out on a
meterage basis to a specified depth and on a daywork basis thereafter. Turnkey contracts
contemplate the drilling of a well for a fixed price. Compared to daywork contracts, meterage and
turnkey contracts involve a higher degree of risk to Precision and, accordingly, normally provide
greater profit or loss potential. Over the last five years, Precisions contracts have been carried
out almost exclusively on a daywork basis.
Contracts with customers vary in duration from a few days for a single well to multiple year,
multiple well drilling programs. Precisions newly built drilling rigs tend to have a three to
five year capital payout contract in place at the time construction commences.
Precisions drilling rigs have varying configurations and capabilities which enable Precision
to provide services in virtually all areas of drilling activity in the WCSB. Precisions rigs have
drilling depth capacities of up to 6,700 metres. All of Precisions drilling rigs can be
winterized, allowing for operations in the harsh weather conditions faced in the Canadian drilling
environment. Conventional rigs are configured to handle either one, two or three joints of range 2
drill pipe at one time and are categorized as singles, doubles or triples based on this capability.
As well, Precision has coiled tubing drilling rigs which utilize a single strand of pipe coiled
around a reel. As a coil tubing drilling rig drills, the tubing is unwound and as the tubing is
rewound onto the reel the bit returns to surface.
Single, double and coiled tubing rigs are generally used in the shallow drilling market, while
triple rigs, which have greater hoisting capacity, are used in deeper exploration and development
drilling, usually carried out in western Canadas foothills and Rocky Mountain regions.
Precisions triple rig fleet includes specialized rigs for deep sour natural gas well drilling and
for operating in very cold climates.
Rounding out Precisions fleet are Super Single rigs, the majority of which have
slant capability. The Super Single rigs are manufactured by Precision and are equipped
with top drive drilling systems, range 3 drill pipe and an automated pipe handling system. Slant
drilling involves tilting a rig mast from vertical and is primarily used to drill multiple
directional wells from one location. Super Single rigs allow for drilling to be
carried out on a more cost effective basis than using conventional drilling techniques. Drilling
multiple wells from one location for instance, improves the economics of developing shallow
hydrocarbon reserves. Additionally, the same technique can allow for the exploitation of reserves
located in environmentally sensitive areas or inaccessible locations and can reduce or eliminate
the cost of building access roads for multiple drilling locations. Precision believes the Super
Single rig category will continue to offer significant revenue growth. In addition to
conventional wells, Precisions Super Single rigs have been adapted to meet a variety
of operational needs such as heavy oil, coal bed methane, tight gas, oil sands production and steam
assisted gravity drainage (SAGD) projects. These multiple well programs are drilled efficiently
from a single pad using a centralized mud system and other innovative rig design features. SAGD
techniques are used extensively in the production of heavy oil reserves and in-situ bitumen
reserves.
The Super Single Light is a smaller capacity, specialized version of the Super
Single. These rigs have been built for drilling shallow wells up to 1,200 metres in
depth. Using range 3 drill pipe, the design incorporates proven technology and reliability in a
light weight, easily moved load configuration. The Super Single Light competes with
coiled tubing rigs and offers greater drilling capability over a wider range of well configurations
than coiled tubing rigs.
To facilitate customer requirements Precision also owns 16 mobile top drives. A top drive is
used to rotate the drill string and provides greater efficiency in the drilling of a well compared
to the traditional rotary table and kelly. A top drive is suspended in the mast of the drilling rig
and is powered by a hydraulic or electric motor.
Precision continually seeks to upgrade and modify its rig fleet to maximize performance.
Precision works hard to remain abreast of, and in many cases, lead advances in specialized drilling
techniques and technology in order to maximize rig efficiency and minimize environmental impact. A
total of 51 of Precisions drilling rigs are diesel-electric powered, with the remaining rigs
mechanically powered. Diesel-electric powered rigs provide more precise control of drilling
components and are considered more power efficient than mechanical rigs and are well suited for
horizontal and directional drilling. Many of Precisions mechanically powered rigs are also
capable of
12
horizontal and directional drilling by reconfiguring the rigs with additional equipment which
Precision has readily available.
The following table lists the drilling depth capabilities of Precisions drilling rigs and the
total Canadian land drilling industrys rigs in the WCSB as at December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Precision Fleet |
|
|
Industry Fleet (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum |
|
|
Number |
|
|
% of |
|
|
Market |
|
|
Number |
|
|
% of |
|
|
|
Type of Drilling Rig |
|
|
Depth Rating |
|
|
of Rigs |
|
|
Total |
|
|
Share % (3) |
|
|
of Rigs |
|
|
Total |
|
|
Change (4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Single |
|
|
|
1,200m |
|
|
|
|
14 |
|
|
|
|
6 |
|
|
|
|
10 |
|
|
|
|
145 |
|
|
|
|
17 |
|
|
|
|
21 |
|
Super Single (2) |
|
|
|
3,000m |
|
|
|
|
28 |
|
|
|
|
12 |
|
|
|
|
85 |
|
|
|
|
33 |
|
|
|
|
4 |
|
|
|
|
9 |
|
Double |
|
|
|
3,000m |
|
|
|
|
94 |
|
|
|
|
39 |
|
|
|
|
26 |
|
|
|
|
364 |
|
|
|
|
43 |
|
|
|
|
20 |
|
Light triple |
|
|
|
3,600m |
|
|
|
|
44 |
|
|
|
|
18 |
|
|
|
|
38 |
|
|
|
|
117 |
|
|
|
|
14 |
|
|
|
|
3 |
|
Heavy triple |
|
|
|
6,700m |
|
|
|
|
49 |
|
|
|
|
20 |
|
|
|
|
42 |
|
|
|
|
118 |
|
|
|
|
14 |
|
|
|
|
11 |
|
Coiled tubing |
|
|
|
1,500m |
|
|
|
|
11 |
|
|
|
|
5 |
|
|
|
|
17 |
|
|
|
|
65 |
|
|
|
|
8 |
|
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL |
|
|
|
|
|
|
|
|
240 |
|
|
|
|
100 |
% |
|
|
|
29 |
% |
|
|
|
842 |
|
|
|
|
100 |
% |
|
|
|
72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTES:
(1) |
|
Source: Daily Oil Bulletin Rig Locator Report as of January 2007. Precision has allocated
the industry rig fleet by rig type. |
(2) |
|
Super Single excludes single rigs that do not have automated pipe handling
systems, do not have a self contained top drive, or cannot run range 3 drill pipe/casing. |
(3) |
|
Market share means Precisions rigs as a percentage of the industrys rigs.
|
|
(4) |
|
Change in number of industry rigs as compared to the prior year. |
There were 72 new drilling rigs added to the Canadian industry fleet during 2006, a 9%
increase over 2005. Customer demand to drill conventional oil and natural gas wells, in
combination with improving commercialization of coal bed methane, oil sands, heavy oil and deeper
natural gas formations had driven demand for rigs to record levels but the slowdown in drilling
activity in the second half of 2006 pushed utilization rates for rigs lower.
Precision has a balanced drilling rig offering, with a particular weighting in deep drilling.
As customers turn to deeper wells to discover new reserves, Precisions 42% market share in rigs
with a depth capacity greater than 3,600 metres is noteworthy.
The following table lists the drilling rig utilization rates and certain other drilling
statistics for Precision compared to the total land drilling industry in the WCSB for the years
indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utilization Rates (%) |
|
|
Metres Drilled (000s) |
|
|
Wells Drilled(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of |
|
|
|
|
|
|
|
|
|
|
|
|
% of |
|
|
|
Precision |
|
|
Industry(2) |
|
|
Precision |
|
|
Industry(2) |
|
|
Industry |
|
|
Precision |
|
|
Industry(2) |
|
|
Industry |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
52.1 |
|
|
|
|
55.1 |
|
|
|
|
7,810 |
|
|
|
|
27,373 |
|
|
|
|
28.5 |
|
|
|
|
6,180 |
|
|
|
|
22,575 |
|
|
|
|
27.4 |
|
2005 |
|
|
|
56.1 |
|
|
|
|
59.6 |
|
|
|
|
8,901 |
|
|
|
|
28,143 |
|
|
|
|
31.6 |
|
|
|
|
7,766 |
|
|
|
|
24,351 |
|
|
|
|
31.9 |
|
2004 |
|
|
|
50.3 |
|
|
|
|
52.9 |
|
|
|
|
8,021 |
|
|
|
|
23,526 |
|
|
|
|
34.1 |
|
|
|
|
7,525 |
|
|
|
|
21,793 |
|
|
|
|
34.5 |
|
2003 |
|
|
|
52.0 |
|
|
|
|
53.1 |
|
|
|
|
8,604 |
|
|
|
|
21,802 |
|
|
|
|
39.5 |
|
|
|
|
8,451 |
|
|
|
|
20,694 |
|
|
|
|
40.8 |
|
2002 |
|
|
|
38.3 |
|
|
|
|
39.4 |
|
|
|
|
6,222 |
|
|
|
|
15,708 |
|
|
|
|
39.6 |
|
|
|
|
6,315 |
|
|
|
|
14,920 |
|
|
|
|
42.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTES:
(1) |
|
The number of wells drilled is reported on a rig release basis, compiled by Precision. |
|
(2) |
|
Industry numbers exclude drilling rigs not registered with the Canadian Association of
Oilwell Drilling Contractors (CAODC) and non-reporting CAODC member contractors. |
Precision has consistently been the most active land drilling contractor in Canada in
terms of wells and metres drilled, sustaining, since 1997, a market share of greater than
approximately 29% of the industry in Canada. During 2006, Precision achieved a utilization rate of
52% for its drilling rigs compared to the average industry
13
utilization rate in Canada of 55%. Precision strives to obtain high utilization of its fleet
and optimal profitability given competitive pricing and Canadas seasonal reduction in drilling
demand during the second and third quarters.
In 2006, Precision drilled 6,180 exploration and development wells, accounting for 27% of
industry wells drilled in western Canada.
Precisions fleet can drill virtually all types of on-shore conventional and unconventional
oil and gas deposits in North America. It is particularly adept in developing unconventional
resources such as oil sands, coalbed methane or tight gas. The increase in drilling-intensive
unconventional resource plays is creating opportunities for technically innovative and
operationally efficient drillers like Precision.
The drilling industry in Canada requires specialized skill and knowledge which, due to
increased utilization levels over the past decade, has been in short supply. A drilling rig crew is
comprised of a rig manager, driller, derrickman, motorman, floor hands and lease hands. The
traditional rig crewing configuration is three crews working rotating shifts, two weeks in and one
week out, allowing the rig to keep working with one crew off. The floor and lease hand positions
are entry level, with the motorman, derrickman and driller positions being more advanced. Each
position has certain prerequisite qualifications and training. Well control, H2S, first
aid, fall protection, work place hazardous materials and various aspects of Precisions health,
safety and environment management systems are all key training components.
The provision of an experienced competent crew is a competitive strength, highly valued by
Precisions customers. In order to continually recruit rig employees, Precision has a centralized
personnel department and orientation program. In 2006, there were approximately 1,900 candidates
given pre-employment rig orientation training. Precision is also active as a member of the
Canadian Association of Oilwell Drilling Contractors (the CAODC) in implementing a designated
trade certification for drilling rig workers in Alberta, the first jurisdiction to recognize the
specialized skill and knowledge that a driller must possess.
The shortage of labour in the oilfield service industry in recent years eased with the decline
in activity in the second half of 2006, but human resource issues are expected to remain a priority
for the industry for the foreseeable future. For Precision, emphasis is placed on retention of
experienced employees in derrickman, driller and rig manager positions. A shortage occurs in high
activity periods when most of the rig fleet is working. The service industry loses experienced
employees to customers, competitors, other oilfield businesses and to other industries due to the
cyclical nature of the work and the resulting uncertainty of continuing employment. During 2006,
Precision focused on the retention of existing employees through initiatives that provide a safe
and productive work environment, opportunity for advancement and added wage security through
programs such as our Designated Driller Program.
Precisions ability to work an entire fleet of rigs, given Canadian seasonality, arises from
its ability to retain experienced employees in low activity periods, orientate new employees and
effectively administer personnel and payroll functions.
Precision Drilling Oilfield Services, Inc.
Precision Drilling Oilfield Services, Inc. began operations in the United States in June 2006
with one rig operating in Texas. The Super Single TM rig deployed to Texas
under contract operated throughout the remainder of the year given that the United States market
does not typically experience the same seasonality as in Canada. The primary focus for Precision
in the United States market is to provide drilling services to larger exploration and production
companies that Precision has had long-term relationships with and that are primarily targeting
unconventional natural gas.
A second rig was deployed to Colorado in early 2007 and Precision currently plans to deliver a
total of five new drilling rigs to the United States in 2007 and early 2008. Precision is
exploring growth opportunities and as conditions warrant, may deploy additional rigs from Canada
into this market. There were approximately 2,300 rigs operating in the United States land market at
the end of 2006.
14
LRG Catering
LRG provides food and accommodation to personnel working at the well site, typically in remote
locations in western Canada. LRG has 101 conventional and base camps, representing approximately
16% of the camp and catering business in western Canada. LRGs mobile camps include five or six
units and can accommodate 20 to 25 crew members. It can also provide food service for all of the
field workers on a location. LRG also has the ability to configure several of its camps and
dormitories on a single site to create a base camp for major projects which can house as many as
200 workers and provide up to 1,000 meals a day. As the oil and gas industry in western Canada
moves to more remote locations in search of new reserves there is increasing demand for crews to
stay near the wellsite throughout the drilling of a well. LRG serves Precision and other companies
in the upstream oil and gas sector and periodically secures opportunities to serve other industries
that operate in remote locations.
Rostel Industries
Rostel Industries manufactures and refurbishes custom drilling rig and service rig components.
This uniquely positions Precision with in-house rig manufacturing capability. Approximately 70% of
Rostels 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 Precisions fleet. In addition to quality construction and repair services, Rostel sustains
high plant utilization by providing specialized services, including inspection and certification of
critical drilling components such as overhead equipment, well control equipment and handling tools.
Rostels expertise includes an in-house engineering group as well as an equipment sales group that
specializes in the distribution of mud pumps and other imported products. Strategically, Rostel
gives Precision the ability to set its own priorities in controlling the work performed on its
equipment. Precision has direct control over scheduling and sets delivery objectives that meet
customer requirements. Rostel designs and builds over 50% of the components for Precisions Super
Single drilling rigs and is developing a new AC-powered top drive that can be applied
to new rigs and retro-fitted to improve the versatility of many of Precisions existing rigs.
Columbia Oilfield Supply
Columbia Oilfield Supply is a general supply store that procures, packages and distributes
large volumes of consumable oilfield supplies for the contract drilling and well servicing
industry. Approximately 90% of Columbias activities support Precision operations and it plays a
key role in supply chain management for the company. Columbias key strengths, which contribute to
Precisions competitiveness, are in inventory management, demand anticipation and distribution.
Precision and its customers also benefit from Columbias 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
Precisions Completion and Production Services segment is comprised of the following divisions:
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Precision Well Servicing (PWS) 237 service rigs approximately 23% of the industry; |
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Live Well Service (Live Well) 26 snubbing units approximately 30% of the industry; |
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Precision Rentals approximately 15,000 pieces of rental equipment items including
well-control equipment, surface equipment, specialty tubulars and wellsite accommodation
units approximately 10% of the industry; and |
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Terra Water Systems Limited Partnership (Terra Water) is a wastewater treatment
business suited for oilfield camps and wellsite accommodation units in remote locations.
It operates 51 wastewater treatment units for the traditional drilling rig camp market in
western Canada approximately 10% of the industry |
15
Precision Well Servicing
The Precision Well Servicing division is Canadas largest service rig contractor, providing
customers with a complete range of oil and natural gas well services completions, workovers,
abandonments, well maintenance, high pressure and critical sour well work and re-entry preparation.
Precisions service rig fleet completes all types of new wells and works over existing wells to
optimize customers oil and natural gas production. The configuration of Precisions Well
Servicing fleet is illustrated in the following table:
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|
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TYPE OF SERVICE RIG |
|
|
2006 |
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|
2005 |
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|
2004 |
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|
|
|
|
|
|
|
|
|
Singles: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mobile single |
|
|
|
12 |
|
|
|
|
17 |
|
|
|
|
19 |
|
Freestanding mobile |
|
|
|
92 |
|
|
|
|
88 |
|
|
|
|
86 |
|
Doubles: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mobile |
|
|
|
44 |
|
|
|
|
44 |
|
|
|
|
42 |
|
Freestanding mobile |
|
|
|
9 |
|
|
|
|
8 |
|
|
|
|
9 |
|
Skid |
|
|
|
65 |
|
|
|
|
65 |
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|
|
|
67 |
|
Slants: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Freestanding |
|
|
|
15 |
|
|
|
|
15 |
|
|
|
|
16 |
|
|
|
|
|
|
|
|
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TOTAL FLEET |
|
|
|
237 |
|
|
|
|
237 |
|
|
|
|
239 |
|
In 2006, PWS maintained an industry market share of almost 23% based on an average registered
CAODC industry fleet of approximately 1,050 service rigs in western Canada. PWS continued to
upgrade its fleet through initiatives that included freestanding conversions and new five ton
transporters along with new pump trucks, engines, combination trailers and mud pumps. As at
December 31, 2006, PWS had 116 freestanding service rigs representing 49% of its service rig fleet.
A freestanding rig is more efficient to set up, minimizes surface disturbance and, as there is no
need for anchors, reduces the possibility of striking underground utilities. However, a majority
of the mobile double rigs are not freestanding as the additional weight to convert them would limit
movement during restricted road use periods. Skid double rigs are ideal for deeper natural gas
wells which require multi-zone completion or re-completion. This type of work usually has the
service rig working for a greater length of time so the rig does not need to be moved as often.
They also include additional equipment such as circulating pumps, tanks, blowout preventers and
tools.
Service rigs are typically used during the completion phase of a well, instead of larger, more
expensive drilling rigs, in order to reduce the cost of completing the well. The demand for well
completion services is related to the level of drilling activity in a region whereas the demand for
production or workover services is based upon the total number of active wells, their age and their
producing characteristics. Consequently, demand for completion services is generally more volatile
than workover services. Completion services accounted for 38% of PWSs well servicing activity in
2006, as compared to 41% in 2005.
A service rig crew has four members (driller, derrickman and two floor hands) in addition to
the rig manager. Jobs are typically shorter in well servicing so the ability of a service rig to
move quickly from one site to another is critical. In general, well servicing is conducted during
daylight hours to co-ordinate activities of a number of service providers. PWS typically charges
its customers an hourly rate for its services based on a number of considerations including market
demand in the region, the type of rig and complement of equipment required.
Completion services prepare a newly drilled well for production and may involve cleaning out
the well bore, and the installation of production tubing, downhole equipment and wellheads.
Service rigs work jointly with other services to perforate the well bore to open the producing
zones and stimulate the producing zones to improve productivity. The well completion process may
take one day to many weeks to complete and PWS provides a service rig to assist during most or all
of this process.
16
Workover services are generally provided according to preventative maintenance schedules or on
a call-out basis when a well needs major repairs or modifications. This can involve operations
similar to those conducted during the initial completion of a well. Workovers may also involve
restoring or enhancing production in an existing producing zone, changing to a new producing zone,
converting the well for use as an injection well for enhanced recovery operations or plugging and
abandoning the well. Workover services also include major subsurface repairs such as casing repair
or replacement, recovery of tubing and removal of foreign objects from the well bore, such as lost
tools. Workover activities may require a few days to several weeks to complete. During this time
PWS may work alongside other oilfield services providers on the well location while other services
are being directed by its customer.
Well maintenance services are often required to ensure continuous and efficient operation of
producing wells. These services include routine mechanical repairs such as repairing broken pumping
equipment in an oil well or replacing damaged rods and tubing. A typical gas well in western
Canada is likely to require one or two workovers during its operating life compared with four or
five workovers for conventional oil wells. Wells for some heavy oil and bitumen production could
require many workovers over their life cycle. Well maintenance activities may require a few hours
to several days to complete. While workover and maintenance activities are not directly linked to
drilling activities, they are influenced by both the short-term and long-term outlooks for oil and
natural gas prices as well as reservoir depletion. Furthermore, an increase in drilling activity
leads to more producing wells that require workover and maintenance services in future years.
As there are close to 190,000 producing wells in western Canada that are potential candidates
for workovers and 15,000 to 20,000 new wells drilled each year that must be completed and
maintained, well servicing has growth potential for Precision.
Live Well Service
Live Well Service markets 25 portable hydraulic rig assist snubbing units and one stand alone
unit in western Canada. Snubbing units are equipped with specialized pressure control devices
which allow tubing to be pushed (snubbed) in and out of a well bore while a well is under pressure
and production has been suspended.
Traditional well servicing operations require the pressure in a well to be neutralized or
killed, prior to performing such operations so they can be conducted safely. Some reservoirs can
be damaged if a well is killed prior to workover operations, as the fluids used in the process may
cause the flow characteristics of the reservoir to be impaired. Consequently, snubbing units have
been developed to perform certain workover and completion activities without killing the well.
A rig assist snubbing unit requires a rig to be on location to hoist it into place. Live
Wells proprietary stand alone snubbing unit does not require a rig to be on the well location. It
is designed to be self-sufficient with automated tubular handling and numerous control features to
enhance safe, cost effective snubbing operations.
The trend toward more natural gas well drilling and low pressure production in the WCSB has
had a positive effect on demand for Live Wells services. Snubbing is primarily performed on gas
wells in western Canada and the process enables customers to increase or maintain well production
rates and to help maximize recoverable reserves.
Precision Rentals
Precision Rentals is a provider of oilfield rental equipment with operating centres and
stocking points located throughout western Canada. Most exploration and production companies do
not own the specialty equipment used in oil and gas operations and equipment offered by Precision
Rentals covers a range of customer needs throughout the drilling, completion and production
process.
Precision Rentals has an inventory of approximately 15,000 pieces of equipment that is
marketed through three product categories: surface equipment; tubulars and well control equipment;
and wellsite accommodation
17
units. Precision Rentals has five operating centres and 14 stock points in the WCSB and a
technical support centre in Nisku, Alberta.
Surface equipment includes 3,700 drilling and production tanks and other equipment primarily
associated with fluid handling. Tubular equipment includes 10,000 joints of specialty-sized drill
pipe and collars. Well-control equipment includes 1,100 handling tools and equipment such as
blowout preventers and diverter systems. The 315 fully equipped accommodation units provide offices
and lodging for senior personnel and are built with heavy-duty skids to facilitate frequent moves.
Precision Rentals also supplies the patented Vapour Tight Oil Battery, which allows for
single well production of oil with H2S content through the use of a 500-barrel vessel with gas
metering and flaring capabilities.
Terra Water
Precision acquired a complementary business line within the oilfield service sector with the
acquisition of Terra Water Group Ltd on August 17, 2006. On August 17, 2006, Terra transferred
substantially all of its net assets to Terra Water. Terra Waters principal role is as provider of
portable on-site wastewater handling, treatment, and disposal expertise within the remote worksite
environment. Terra Waters equipment focuses on reducing environmental impacts from wastewater
generated on site.
Terra Waters treatment units are designed and manufactured in-house. There are numerous
small-scale operators in this emerging sector but it is estimated Terra Waters 51 portable units
comprise approximately 10% of the industry within the remote work site market in western Canada.
RISK FACTORS
THE TRUST
An investment in the Trust Units and Exchangeable Units involves a number of risks
including those set forth below.
Nature of Trust Units
The Trust Units do not represent a traditional investment in the oil and natural gas services
business and should not be viewed as shares of Precision. The Trust Units represent a fractional
interest in the Trust. Holders of Trust Units do not have the statutory rights normally associated
with ownership of shares of a corporation including, for example, the right to bring oppression
or derivative actions. The Trusts sole assets are the shares of the General Partner, the PDLP A
Units and other investments in securities. The price per Trust Unit is a function of anticipated
net earnings, distributable cash, the underlying assets of the Trust and managements ability to
effect long-term growth in the value of Precision and other entities now or hereafter owned
directly or indirectly by the Trust. The market price of the Trust Units are sensitive to a variety
of market conditions including, but not limited to, interest rates, the growth of the general
economy, the price of crude oil and natural gas and changes in law. Changes in market conditions
may adversely affect the trading price of the Trust Units.
The Trust Units are not deposits within the meaning of the Canada Deposit Insurance
Corporation Act (Canada) and are not insured under the provisions of that act or any other
legislation. Furthermore, the Trust is not a trust company and, accordingly, is not registered
under any trust and loan company legislation as it does not carry on or intend to carry on the
business of a trust company.
The Trust is Dependent on Precision for All Cash Available for Distributions
The Trust is dependent on the operations and assets of Precision through its interest in PDLP,
which in turn owns 100% of the shares of Precision and the Promissory Note. Distributions to the
holders of Trust Units and Exchangeable Units are dependent on the ability of Precision to make
principal and interest payments on the Promissory Note, dividends and return of capital payments.
The actual amount of cash available for distribution is dependent upon numerous factors relating to
the business of Precision including profitability, changes in revenue,
18
fluctuations in working capital, capital expenditure levels, applicable laws, compliance with
contracts, contractual restrictions contained in the instruments governing its indebtedness, the
impact of interest rates, the growth of the general economy, the price of crude oil and natural
gas, changes to tax laws, weather, future capital requirements and the number of Trust Units and
Exchangeable Units issued and outstanding and potential tax liabilities resulting from any
successful reassessments of prior taxation years by taxation authorities.
Any reduction in the amount of cash available for distribution, or actually distributed, by
Precision will reduce or suspend entirely the amount of cash available for distributions to the
holders of Trust Units and Exchangeable Units. The market value of the Trust Units may deteriorate
if the Trust is unable to meet distribution expectations in the future, and such deterioration may
be material.
Possible Restriction on Growth
The payout of substantially all of Precisions operating cash flow will make capital and
operating expenditures dependent on increased cash flow or additional financing in the future. The
lack of these funds could limit Precisions future growth and cash flow which in turn may affect
the amount of distributions. In addition, Precision may be precluded from pursuing acquisitions or
investments which may not be accretive on a short-term basis. Proposed rules on undue expansion
were clarified by the Government of Canada in 2006 with the result being that Precision can grow
its equity by approximately $4.0 billion dollars over the four year transition period before
triggering the proposed new tax.
Potential Sales of Additional Trust Units
The Trust may issue additional Trust Units in the future to directly or indirectly fund
capital expenditure requirements of Precision and other entities now or hereafter owned directly or
indirectly by the Trust, including to finance acquisitions by those entities. Such additional
Trust Units may be issued without the approval of Unitholders. Unitholders have no pre-emptive
rights in connection with such additional issues. The Board of Trustees have discretion in
connection with the price and the other terms of the issue of such additional Trust Units.
Nature of Distributions
Unlike interest payments on an interest-bearing security, distributions by income trusts on
trust units (including those of the Trust) are, for Canadian tax purposes, composed of different
types of payments (portions of which may be fully or partially taxable or may constitute
non-taxable returns of capital). The composition for tax purposes of those cash distributions
may change over time, thus affecting the after-tax return to holders of Trust Units. Therefore, the
rate of return for holders of Trust Units over a defined period may not be comparable to the rate
of return on a fixed-income security that provides a return on capital over the same period. This
is because a holder of Trust Units may receive distributions that constitute a return of capital
(rather than a return on capital) to some extent during the relevant period. Returns on capital
are generally taxed as ordinary income, dividends or taxable capital gains in the hands of a holder
of Trust Units, while returns of capital are generally non-taxable to a holder of Trust Units (but
reduce the adjusted cost base in a Trust Unit for tax purposes).
Issuance of Additional Trust Units
The Declaration of Trust provides that an amount equal to the taxable income of the Trust will
be payable each year to holders of Trust Units in order to reduce the Trusts taxable income to
zero. Where in a particular year, the Trust does not have sufficient cash to distribute such an
amount, the Declaration of Trust provides that additional Trust Units may be distributed in lieu of
cash payments. Holders of Trust Units will generally be required to include an amount equal to the
fair market value of those Trust Units in their taxable income, notwithstanding that they do not
directly receive a cash payment. See Certain Canadian Federal Income Tax Considerations
Taxation of Trust Unitholders on pages 47 and 48 of the 2005 Special Meeting Information Circular
which are incorporated by reference into this Annual Information Form. See General Development of
the Business Cash Distributions on Trust Units for a description of the ability to consolidate
Trust Units upon the distribution of Trust Units in lieu of the payment of a cash distribution.
19
Variability of Distributions
The actual cash flow available for distribution to Unitholders is a function of numerous
factors including the Trusts, PDLPs and Precisions financial performance; debt covenants and
obligations; working capital requirements; future productive capacity maintenance expenditures and
future expansion capital expenditure requirements for the purchase of property, plant and
equipment; tax obligations; the impact of interest rates, the growth of the general economy; the
price of crude oil and natural gas; weather; and number of Trust Units and Exchangeable Units
issued and outstanding. Distributions may be reduced or suspended entirely depending on
Precisions operations and the performance of its assets. The market value of the Trust Units may
deteriorate if the Trust is unable to meet distribution expectations in the future, and that
deterioration may be material.
Changes in Legislation
There can be no assurance that income tax laws, such as the status of mutual fund trusts, or
the taxation of mutual fund trusts, will not be changed in a manner which adversely affects holders
of Trust Units.
Environmental and applicable operating legislation may be changed in a manner which adversely
affects holders of Trust Units.
Investment Eligibility
If the Trust ceases to qualify as a mutual fund trust, the Trust Units will cease to be
qualified investments for registered retirement savings plans, registered retirement income funds
and deferred profit sharing plans (Exempt Plans) which will have adverse tax consequences to
Exempt Plans or their annuitants or beneficiaries. The Income Tax Act (Canada) (the Tax Act)
imposes penalties or other tax consequences for the acquisition or holding of non-qualified
investments.
Risks Associated with Trust Units for Non-Resident Holders of Trust Units
For non-resident holders of Trust Units, there are certain risks associated with holding Trust
Units. Non-resident holders of Trust Units should consult their tax advisors with respect to the
tax implications of holding Trust Units, including any associated filing requirements in their
particular tax jurisdiction. Except as provided under the heading Certain United States Federal
Income Tax Considerations on pages 51 to 54 of the 2005 Special Meeting Information Circular which
are incorporated into this Annual Information Form by reference, neither the Trust nor Precision is
providing any representations as to the tax consequences to non-residents of holding Trust Units.
Qualified Dividend Treatment for Individual U.S. Holders of Trust Units
The Trust expects that distributions it makes to individual U.S. holders of Trust Units that
are treated as dividends for U.S. federal income tax purposes will be treated as qualified dividend
income eligible for the reduced maximum rate to individuals of 15% (5% for individuals in lower tax
brackets). However, if the Trust does not constitute a qualified foreign corporation for U.S.
federal income tax purposes, and as a result such dividends to individual U.S. holders of Trust
Units do not qualify for this reduced maximum rate, such holders will be subject to tax on such
dividends at ordinary income rates (currently at a maximum rate of 35%). In addition, under
current law, the preferential tax rate for qualified dividend income will not be available for
taxable years beginning after December 31, 2010. Neither the Trust nor Precision is providing any
representation as to the U.S. tax consequences of holding Trust Units.
Distribution of Assets on Redemption or Termination of the Trust
It is anticipated that a redemption right will not be the primary mechanism for holders of
Trust Units to liquidate their investment. Securities which may be received as a result of a
redemption of Trust Units will not be listed on any stock exchange and no market for such
securities is expected to develop. The securities so distributed may not be qualified investments
for Exempt Plans, depending upon the circumstances existing at that time. On termination of the
Trust, the Board of Trustees may distribute the securities directly to holders of Trust Units,
20
subject to obtaining all of the necessary regulatory approvals. In addition, there may be
resale restrictions imposed by applicable law upon the recipients of securities pursuant to a
redemption right.
Debt Service
Precision and its affiliates may, from time to time, finance a significant portion of their
growth (either from acquisitions or capital expenditure additions) through debt. Amounts paid in
respect of interest and principal on debt incurred by Precision and its affiliates may impair
Precisions ability to satisfy its obligations under its debt instrument(s). Variations in
interest rates and scheduled principal repayments could result in significant changes in the amount
required to be applied to service debt before payment of inter-entity debt. This may result in
lower levels of cash for distribution by the Trust. Ultimately, subordination agreements or other
debt obligations could preclude distributions altogether.
Taxation of the Trust
There can be no assurances that Canadian federal income tax laws and administrative policies
respecting the treatment of mutual fund trusts will not be changed in a manner which adversely
affects the holders of Trust Units. For example, if the Trust ceases to qualify as a mutual fund
trust under the Tax Act, the income tax considerations described under the heading Certain
Canadian Federal Income Tax Considerations Taxation of Trust Unitholders on pages 47 and 48 of
the 2005 Special Meeting Information Circular which are incorporated by reference into this Annual
Information Form, would be materially and adversely different in certain respects.
Currently, under a disqualification rule contained in the Tax Act, a trust will not be
considered to be a mutual fund trust if it is established or is maintained primarily for the
benefit of non-residents of Canada for the purposes of the Tax Act, unless all or substantially all
of its property is property other than taxable Canadian property as defined in the Tax Act. In
an effort to allow the Trust to assert that the foregoing disqualification rule is inapplicable on
the basis that the Trust is not now and has never been established or maintained primarily for the
benefit of non-residents of Canada, the Declaration of Trust restricts and provides mechanisms to
limit the number of Trust Units held by non-residents of Canada and non-Canadian partnerships.
Moreover, as a second reason to allow the Trust to assert that the foregoing disqualification rule
does not apply to the Trust, the assets of the Trust have been structured to allow the Trust to
assert that all or substantially all of its property is property other than Taxable Canadian
property as defined in the Tax Act.
On September 16, 2004, the Minister of Finance (Canada) released draft amendments to the Tax
Act including draft amendments providing that a trust will lose its status as a mutual fund trust
if the aggregate fair market value of all units issued by the trust held by one or more
non-residents of Canada or partnerships that are not Canadian partnerships (as defined in the Tax
Act) is more than 50% of the aggregate fair market value of all the units issued by the trust where
more than 10% (based on fair market value) of the trusts property is certain types of taxable
Canadian property or certain other types of property. If the draft amendments are enacted as
proposed, and if, at any time, more than 50% of the aggregate fair market value of the Trust Units
are held by non-residents of Canada and non-Canadian partnerships, the Trust may thereafter cease
to be a mutual fund trust. The draft amendments do not currently provide any means of rectifying a
loss of mutual fund trust status. On December 6, 2004, the Minister of Finance (Canada) tabled a
Notice of Ways and Means Motion to implement certain measures proposed in the September 16, 2004
draft amendments. However, such notice did not include the proposal concerning mutual fund trusts
maintained primarily for the benefit of non-residents of Canada. In addition, the Minister of
Finance (Canada) announced on December 6, 2004 as well as in the 2005 Budget Proposals that further
discussions would be pursued with the private sector in this respect.
On September 8, 2005, the Department of Finance (Canada) released a consultation paper and
launched public consultations on tax and other issues related to flow-through entities (FTEs).
The focus of the paper was to, among other things, assess whether the tax system should be
modified. In the consultation paper, the Department of Finance identified three possible policy
responses to issues relating to FTEs: (i) limiting deductibility of interest expense by operating
entities, (ii) taxing FTEs in a manner similar to corporations, or (iii) making the income tax
system more neutral with respect to all forms of business organization by better integrating the
personal and corporate income tax system. On November 23, 2005, the Department of Finance announced
that the consultation process was finished and tabled in the House of Commons a Notice of Ways and
Means Motion to implement a
21
reduction in personal income tax on dividends with a view to establishing a better balance
between the integrated tax treatment of large corporations and that of income trusts. No measures
were announced with respect to the taxation of FTEs and their investors.
On October 31, 2006, the Government of Canada announced a Tax Fairness Plan containing its
intentions to bring about new tax measures including a Distribution Tax on distributions from
publicly traded income trusts and limited partnerships. The government is proposing a four-year
transition period for existing income trusts and limited partnerships whereby the new measures will
not apply until their 2011 taxation year. Under the proposal, flow-through entities will be taxed
more like corporations and their investors will be treated more like shareholders. The proposed new
tax measures will impair the flow-through nature of Precision Drilling Trusts current tax
structure. If enacted into law, these tax measures would result in a distribution tax to the Trust
which will reduce the cash distributed to Unitholders by the amount of distribution tax paid.
If the proposed measures are enacted into law, effective January 1, 2011, the current
underlying flow-through status of the Trusts current income trust structure will be ended. The
proposed amendments have negative implications for certain unitholders of the Trust and PDLP
commencing in 2011, particularly Canadian tax-exempt investors, foreign investors and tax-exempt
entities.
The Declaration of Trust restricts and provides mechanisms to limit the number of Trust Units
held by non-residents of Canada and non-Canadian partnerships such that the Trust expects that the
existing imposed non-resident ownership limitations set out in the Tax Act, discussed above, will
be satisfied. In an effort to support the assertion that the Trust qualifies as a mutual fund
trust under the Tax Act and in an effort to support the assertion that the maintenance of such
status the Declaration of Trust provides, in part, that:
(a) if determined necessary or desirable by the Trustees, in their sole discretion, the
Trust may, from time to time, among other things, take all necessary steps to monitor the
activities of the Trust and ownership of the Trust Units. If at any time the Trust or the
Trustees become aware that the activities of the Trust and/or ownership of the Trust Units
by non-residents may threaten the status of the Trust under the Tax Act as a unit trust or
a mutual fund trust, the Trust, by or through the Trustees on the Trusts behalf, is
authorized to take such action as may be necessary in the opinion of the Trustees to
maintain the status of the Trust as a unit trust or a mutual fund trust including,
without limitation, the imposition of restrictions on the issuance by the Trust of Trust
Units or the transfer by any Unitholder of Trust Units to a non-resident and/or require the
sale of Trust Units by non-residents on a basis determined by the Trustees and/or suspend
distribution and/or other rights in respect of Trust Units held by non-residents transferred
contrary to the foregoing provisions or not sold in accordance with the requirements
thereof; and
(b) in addition to the foregoing, the transfer agent of Trust Units, by or through the
Trustees may, if determined appropriate by the Trustees, establish operating procedures for,
and maintain, a reservation system which may limit the number of Trust Units that
non-residents may hold, limit the transfer of the legal or beneficial interest in any Trust
Units to non-residents unless selected through a process determined appropriate by the
Trustees, which may either be a random selection process or a selection process based on the
first to register, or such other basis as determined by the Trustees. The operating
procedures relating to such reservation system shall be determined by the Trustees and,
prior to implementation, the Trust shall publicly announce the implementation of the same.
Such operating procedures may, among other things, provide that any transfer of a legal or
beneficial interest in any Trust Units contrary to the provisions of such reservation system
may not be recognized by the Trust.
Taxation of Precision
Income fund structures often involve significant amounts of inter-entity debt, which may
generate substantial interest expense, which serves to reduce earnings and therefore income tax
payable. The Board of Trustees expects this to be the case in respect of Precision and its
interest expense on the Promissory Note. There can be no assurance that the taxation authorities
will not seek to challenge the amount of interest expense deducted. If such a challenge were to
succeed against Precision, it could have a materially adverse affect on the amount of distributable
cash available.
22
Net Asset Value
The net asset value of the assets of the Trust from time to time will vary depending upon
factors which are beyond the control of Precision. The trading price of the Trust Units also
fluctuates due to factors beyond the control of Precision and such trading prices may be greater
than the net asset value of the Trusts assets.
Residual Liability of Precision
Precision, the successor entity to amalgamations involving its predecessor companies, has
retained all liabilities of its predecessor companies, including liabilities relating to corporate
and income tax matters.
Unitholder Limited Liability
The Declaration of Trust provides that no holder of Trust Units will be subject to any
liability in connection with the Trust or its obligations and affairs and, in the event that a
court determines that holders of Trust Units are subject to any such liabilities, the liabilities
will be enforceable only against, and will be satisfied only out of the Trusts assets. Pursuant to
the Declaration of Trust, the Trust will indemnify and hold harmless each holder of Trust Units
from any costs, damages, liabilities, expenses, charges and losses suffered by a holder resulting
from or arising out of such holder not having such limited liability. The Declaration of Trust
provides that all written instruments signed by or on behalf of the Trust must contain a provision
to the effect that obligations under those instruments will not be binding upon holders of Trust
Units personally. Personal liability may however arise in respect of claims against the Trust that
do not arise under contracts, including claims in tort, claims for taxes and possibly certain other
statutory liabilities. The possibility of any personal liability of this nature arising is
considered unlikely. The Income Trusts Liability Act (Alberta) came into force on July 1, 2004.
The legislation provides that a holder of Trust Units will not be, as a beneficiary, liable for any
act, default, obligation or liability of the Trustee(s) that arises after the legislation came into
force. However, this legislation has not yet been ruled upon by the Courts. The operations of the
Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to
avoid as far as possible any material risk of liability to the holders of Trust Units for claims
against the Trust, including by obtaining appropriate insurance, where available and to the extent
commercially feasible.
Deductibility of Expenses
Although the Trustees, the General Partner of PDLP and management of Precision are of the view
that substantially all of the expenses claimed by the Trust, PDLP and Precision, respectively, will
be reasonable and deductible, there can be no assurance that the taxation authorities will agree.
If the taxation authorities successfully challenge the deductibility of any such expenses, the
return to holders of Trust Units may be adversely affected.
Precision Drilling Limited Partnership
The risks applicable to holders of Exchangeable Units are similar to those for holders of
Trust Units, as Exchangeable Units are the voting and economic equivalent of the Trust Units. For
a discussion of such risks, refer to the heading Risk Factors The Trust commencing on page 18
hereof.
Risks Associated with Exchangeable Units
None of the Trust, PDLP or Precision is providing any representations as to the tax
consequences of holding Exchangeable Units.
Indemnity of Limited Partners
While the General Partner has agreed pursuant to the terms of the Limited Partnership
Agreement of PDLP, to indemnify PDLPs limited partners, including holders of the Class A Limited
Partnership Units and the Exchangeable Units, the General Partner may not have sufficient assets to
honour the indemnity.
23
RISKS RELATING TO THE BUSINESS CURRENTLY CONDUCTED BY PRECISION
Certain activities of Precision are affected by factors that are beyond its control or
influence. The drilling rig, camp and catering, service rig, snubbing, rentals, wastewater
treatment and related service businesses and activities of Precision in Canada and the drilling
rig, camp and catering and rentals business and activities of Precision in the United States are
directly affected by fluctuations in exploration, development and production activity carried on by
its customers which, in turn, is dictated by numerous factors including world energy prices and
government policies. The addition, elimination or curtailment of government regulations and
incentives could have a significant impact on the oil and natural gas business in Canada and the
United States. These factors could lead to a decline in the demand for Precisions services,
resulting in a material adverse effect on revenues, cash flows, earnings and cash distributions to
Unitholders. The majority of Precisions operating costs are variable in nature which minimizes
the impact of downturns on Precisions operational results.
Operations Dependent on the Price of Oil and Natural Gas
Precision sells its services to oil and natural gas exploration and production companies.
Macro economic and geopolitical factors associated with oil and natural gas supply and demand are
prime drivers for pricing and profitability within the oilfield services industry. Generally, when
commodity prices are relatively high, demand for Precisions services are high, while the opposite
is true when commodity prices are low. The markets for oil and natural gas are separate and
distinct. Oil is a global commodity with a vast distribution network. As natural gas is most
economically transported in its gaseous state via pipeline, its market is dependent on pipeline
infrastructure and is subject to regional supply and demand factors. Recent developments in the
transportation of liquefied natural gas (LNG) in ocean going tanker ships has introduced an
element of globalization to the natural gas market. However, the volume capability of the worlds
LNG infrastructure is not expected to be large enough to influence pricing in North American
markets for a number of years. Crude oil and natural gas prices are quite volatile, which accounts
for much of the cyclical nature of the oilfield services business. Oilfield service business
cycles are muted somewhat in non-North American markets where projects tend to be larger and more
long-term and are therefore less susceptible to short-term commodity price fluctuations.
Worldwide military, political and economic events, including initiatives by the Organization
of Petroleum Exporting Countries, may affect both the demand for, and the supply of, oil and
natural gas. Weather conditions, governmental regulation (both in Canada and elsewhere), levels of
consumer demand, the availability of pipeline capacity, and other factors beyond Precisions
control may also affect the supply of and demand for oil and natural gas and thus lead to future
price volatility. Precision believes that any prolonged reduction in oil and natural gas prices
would depress the level of exploration and production activity. This would likely result in a
corresponding decline in the demand for Precisions services and could have a material adverse
effect on its revenues, cash flows and profitability. Lower oil and natural gas prices could also
cause Precisions customers to seek to terminate, renegotiate or fail to honour Precisions
drilling contracts which could affect the fair market value of its rig fleet which in turn could
trigger a writedown for accounting purposes; which could affect Precisions ability to retain
skilled rig personnel; and which could affect Precisions ability to obtain access to capital to
finance and grow its businesses. There can be no assurance that the future level of demand for
Precisions services or future conditions in the oil and natural gas and oilfield services
industries will not decline.
Competitive Industry
The oilfield services industry in which Precision operates is, and will continue to be, very
competitive. There is no assurance that Precision will be able to continue to compete successfully
or that the level of competition and pressure on pricing will not affect its margins.
Capital Overbuild in the Drilling Industry
As at December 31, 2006 there were an estimated 842 industry drilling rigs in Canada, an
increase of 9% from December 31, 2005. There is no assurance that the level of demand for drilling
rig services will be able to support the expected increase in the size of the industry drilling
fleet. Any decline in demand for drilling services within the sector directly or indirectly related
to the current drilling rigs available could also lead to a decline in the
24
demand for Precisions services, resulting in a material adverse effect on Precisions
revenues, cash flows, earnings and distributions to Unitholders.
Workforce Availability
Precisions ability to provide reliable services is dependent upon the availability of
well-trained, experienced crews to operate its field equipment. Precision must also balance the
requirement to maintain a skilled workforce with the need to establish cost structures that
fluctuate with activity levels. Within Precision the most experienced employees are retained
during periods of low utilization by having them fill lower level positions on field crews.
Precision has established training programs for employees new to the oilfield service sector and
works closely with industry associations to ensure competitive compensation levels to attract new
workers to the industry as required. Many of Precisions businesses are currently experiencing
manpower shortages in peak operating periods. These shortages are likely to be further challenged
by the number of rigs being added to the industry along with the entrance and expansion of newly
formed oilfield service companies. In the near-term anticipated declines in activity will offset
challenges due to rig expansion.
New Technology
Technological innovation by oilfield service companies has improved the effectiveness of the
entire exploration and production sector over the industrys more than 140-year history. Drilling
time has been reduced due to improvements in drill bits, logging and measurement-while-drilling
tools, as well as innovation changes in other areas such as mud systems and top drives.
Precisions ability to deliver services that are more efficient is critical to continued success.
Customer Merger and Acquisition Activity
Merger and acquisition activity in the oil and natural gas exploration and production sector
can impact demand for our services as customers focus on internal reorganization activities prior
to committing funds to significant drilling and maintenance projects.
Business Interruption and Casualty Losses
Precisions operations are subject to many hazards inherent in the drilling, workover and
well-servicing industries, including blowouts, cratering, explosions, fires, loss of well control,
loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather or
natural disasters. Any of these hazards could result in personal injury or death, damage to or
destruction of equipment and facilities, suspension of operations, environmental damage and damage
to the property of others. Generally, drilling contracts provide for the division of
responsibilities between a drilling company and its customer, and Precision seeks to obtain
indemnification from its customers by contract for certain of these risks. To the extent that
Precision is unable to transfer such risks to customers by contract or indemnification agreements,
Precision seeks protection through insurance. However, Precision cannot ensure that such insurance
or indemnification agreements will adequately protect it against liability from all of the
consequences of the hazards described above. The occurrence of an event not fully insured or
indemnified against, or the failure of a customer or insurer to meet its indemnification or
insurance obligations, could result in substantial losses. In addition, insurance may not be
available to cover any or all of these risks, or, even if available, may not be adequate.
Insurance premiums or other costs may rise significantly in the future, so as to make such
insurance prohibitively expensive or uneconomic. This is particularly of concern in the wake of
the September 11, 2001 terrorist attacks in the U.S. and the severe hurricane damage in the U.S.
Gulf Coast region in 2005, both of which have resulted in significantly increased insurance costs,
deductibles and coverage restrictions. In future insurance renewals, Precision may choose to
increase its self insurance retentions (and thus assume a greater degree of risk) in order to
reduce costs associated with increased insurance premiums.
Environmental Legislation
Precisions 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
25
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 Precisions 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 Precisions
services.
While Precision maintains liability insurance, including insurance for environmental claims,
the insurance is subject to coverage limits and certain of Precisions 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 Precisions insurance, or
that the dollar amount of such liabilities will not exceed Precisions policy limits. Even a
partially uninsured claim, if successful and of sufficient magnitude, could have a material adverse
effect on Precisions business, results of operations and prospects.
Business is Seasonal
In Canada, the level of activity in the oilfield service industry is influenced by seasonal
weather patterns. During the spring months, wet weather and the spring thaw make the ground
unstable. Consequently, municipalities and provincial transportation departments enforce road bans
that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels and
placing an increased level of importance on the location of our equipment prior to imposition of
the road bans. The timing and length of road bans is dependant upon the weather conditions leading
to the spring thaw and the weather conditions during the thawing period. Additionally, certain oil
and natural gas producing areas are located in sections of the WCSB that are inaccessible, other
than during the winter months, because the ground surrounding or containing the drilling sites in
these areas consists of terrain known as muskeg. Until the muskeg freezes, the rigs and other
necessary equipment cannot cross the terrain to reach the drilling site. Moreover, once the rigs
and other equipment have been moved to a drilling site, they may become stranded or otherwise
unable to relocate to another site should the muskeg thaw unexpectedly. Precisions business
results depend, at least in part, upon the severity and duration of the Canadian winter.
Tax Consequences of Previous Transactions Completed by Precision
The business and operations of Precision prior to completion of the Plan of Arrangement had
been complex and Precision has executed a number of significant financings, business combinations,
acquisitions and dispositions over the course of its history. The computation of income taxes
payable as a result of these transactions involves many complex factors as well as Precisions
interpretation of relevant tax legislation and regulations. Precisions 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 Precisions interpretation of the applicable tax legislation and regulations, with the
result that additional taxes could be payable by Precision and the amount payable could be up to
$300 million. Any increase in Precisions tax liability would reduce the net assets and funds
available for distributions to Unitholders.
26
Credit Risk
Precisions accounts receivable are with customers involved in the oil and natural gas
industry, whose revenues may be impacted by fluctuations in commodity prices. Although collection
of these receivables could be influenced by economic factors affecting this industry, management
considers the risk of a significant loss due to uncollectible receivables to be remote at this
time.
Potential Unknown Liabilities
There may be unknown liabilities assumed by the Trust through its direct and indirect
interests in Precision, including those associated with prior acquisitions and dispositions by
Precision as well as environmental issues or tax issues. Specifically, Precision has provided
certain indemnities to the respective purchasers under the Weatherford Sale Agreement and the CEDA
Sale Agreement. The discovery of any material liabilities could have an adverse affect on the
financial condition and results of discontinued operations of Precision and, as a result, the
amount of cash available for distribution to Unitholders. Precision is not aware of any undisclosed
material liabilities.
Capital Expenditures
The timing and amount of capital expenditures by Precision will directly affect the amount of
cash available for distribution to Unitholders. The cost of equipment has escalated over the past
several years as a result of, among other things, high input costs. There is no assurance that
Precision will be able to recover higher capital costs through rate increases to its customers, and
in such event, cash distributions may be reduced.
Access to Additional Financing
Precision may find it necessary in the future to obtain additional debt or equity financing
through the Trust to support ongoing operations, to undertake capital expenditures or to undertake
acquisitions or other business combination transactions. There can be no assurance that additional
financing will be available to Precision when needed or on terms acceptable to Precision.
Precisions inability to raise financing to support ongoing operations or to fund capital
expenditures or acquisitions could limit Precisions growth and may have a material adverse effect
upon Precision.
27
RECORD OF CASH DISTRIBUTIONS/PAYMENTS
The following table sets forth the distributions (in CDN$) paid or declared payable by
the Trust on each Trust Unit since the completion of the Plan of Arrangement:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount per Trust |
Distribution Type |
|
|
Record Date |
|
|
Payment Date |
|
|
Unit |
2005 |
|
|
|
|
|
|
|
|
|
Regular Distribution |
|
|
November 30, 2005 |
|
|
December 15, 2005 |
|
|
$0.270 |
Regular Distribution |
|
|
December 31, 2005 |
|
|
January 17, 2006 |
|
|
$0.270 |
Special Distribution |
|
|
December 31, 2005 |
|
|
January 17, 2006 |
|
|
$0.022 |
2006 |
|
|
|
|
|
|
|
|
|
Regular Distribution |
|
|
January 31, 2006 |
|
|
February 15, 2006 |
|
|
$0.270 |
Regular Distribution |
|
|
February 28, 2006 |
|
|
March 15, 2006 |
|
|
$0.270 |
Regular Distribution |
|
|
March 31, 2006 |
|
|
April 18, 2006 |
|
|
$0.270 |
Regular Distribution |
|
|
April 28, 2006 |
|
|
May 16, 2006 |
|
|
$0.270 |
Regular Distribution |
|
|
May 31, 2006 |
|
|
June 15, 2006 |
|
|
$0.310 |
Regular Distribution |
|
|
June 30, 2006 |
|
|
July 18, 2006 |
|
|
$0.310 |
Regular Distribution |
|
|
July 31, 2006 |
|
|
August 15, 2006 |
|
|
$0.310 |
Regular Distribution |
|
|
August 31, 2006 |
|
|
September 15, 2006 |
|
|
$0.310 |
Regular Distribution |
|
|
September 29, 2006 |
|
|
October 17, 2006 |
|
|
$0.310 |
Regular Distribution |
|
|
October 31, 2006 |
|
|
November 15, 2006 |
|
|
$0.310 |
Regular Distribution |
|
|
November 30, 2006 |
|
|
December 15, 2006 |
|
|
$0.310 |
Regular Distribution |
|
|
December 31, 2006 |
|
|
January 16, 2007 |
|
|
$0.310 |
Special Year-end in-kind Distribution(1) |
|
|
December 31, 2006 |
|
|
January 16, 2007 |
|
|
$0.195 |
2007 |
|
|
|
|
|
|
|
|
|
Regular Distribution |
|
|
January 31, 2007 |
|
|
February 15, 2007 |
|
|
$0.190 |
Regular Distribution |
|
|
February 28, 2007 |
|
|
March 15, 2007 |
|
|
$0.190 |
Regular Distribution |
|
|
March 30, 2007 |
|
|
April 17, 2007 |
|
|
$0.190 |
NOTE:
(1) |
|
As referenced in the Trusts press release dated December 18, 2006, the special year-end
distribution of $0.195 per unit was not paid in cash and holders of Trust Units did not
receive additional Trust Units. The special year-end distribution was settled in-kind
through Trust Units rather than cash in order for Precision to minimize debt levels and retain
balance sheet strength to fund planned asset growth. Immediately after the special in-kind
distribution, the outstanding Trust Units were consolidated so that the number of Trust Units
outstanding remained unchanged from the number of Trust Units outstanding immediately before
the special in-kind distribution. |
The following table sets forth the amount of payments (in CDN$) paid or payable on each
Exchangeable Unit since the completion of the Plan of Arrangement:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount |
|
|
|
|
|
|
|
|
|
per Exchangeable |
Payment Type |
|
|
Record Date |
|
|
Payment Date |
|
|
Unit |
2005 |
|
|
|
|
|
|
|
|
|
Regular Payment |
|
|
November 30, 2005 |
|
|
December 15, 2005 |
|
|
$0.270 |
Regular Payment |
|
|
December 31, 2005 |
|
|
January 17, 2006 |
|
|
$0.270 |
Special Payment |
|
|
December 31, 2005 |
|
|
January 17, 2006 |
|
|
$0.022 |
2006 |
|
|
|
|
|
|
|
|
|
Regular Payment |
|
|
January 31, 2006 |
|
|
February 15, 2006 |
|
|
$0.270 |
Regular Payment |
|
|
February 28, 2006 |
|
|
March 15, 2006 |
|
|
$0.270 |
Regular Payment |
|
|
March 31, 2006 |
|
|
April 18, 2006 |
|
|
$0.270 |
Regular Payment |
|
|
April 28, 2006 |
|
|
May 16, 2006 |
|
|
$0.270 |
Regular Payment |
|
|
May 31, 2006 |
|
|
June 15, 2006 |
|
|
$0.310 |
Regular Payment |
|
|
June 30, 2006 |
|
|
July 18, 2006 |
|
|
$0.310 |
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount |
|
|
|
|
|
|
|
|
|
per Exchangeable |
Payment Type |
|
|
Record Date |
|
|
Payment Date |
|
|
Unit |
Regular Payment |
|
|
July 31, 2006 |
|
|
August 15, 2006 |
|
|
$0.310 |
Regular Payment |
|
|
August 31, 2006 |
|
|
September 15, 2006 |
|
|
$0.310 |
Regular Payment |
|
|
September 29, 2006 |
|
|
October 17, 2006 |
|
|
$0.310 |
Regular Payment |
|
|
October 31, 2006 |
|
|
November 15, 2006 |
|
|
$0.310 |
Regular Payment |
|
|
November 30, 2006 |
|
|
December 15, 2006 |
|
|
$0.310 |
Regular Payment |
|
|
December 31, 2006 |
|
|
January 16, 2007 |
|
|
$0.310 |
Special 2006
Year-end in-kind
Payment(1) |
|
|
December 31, 2006 |
|
|
January 16, 2007 |
|
|
$0.195 |
2007 |
|
|
|
|
|
|
|
|
|
Regular Distribution |
|
|
January 31, 2007 |
|
|
February 15, 2007 |
|
|
$0.190 |
Regular Distribution |
|
|
February 28, 2007 |
|
|
March 15, 2007 |
|
|
$0.190 |
Regular Distribution |
|
|
March 30, 2007 |
|
|
April 17, 2007 |
|
|
$0.190 |
NOTE:
(1) |
|
As referenced in the Trusts press release dated December 18th, 2006, the special year-end
distribution of $0.195 per unit was not paid in cash and holders of Exchangeable Units did not
receive additional Exchangeable Units of Precision Drilling Limited Partnership. The special
year-end distribution was settled in-kind through Exchangeable Units rather than cash in
order for Precision to minimize debt levels and retain balance sheet strength to fund planned
asset growth. Immediately after the special in-kind distribution, the outstanding Exchangeable
Units of PDLP were consolidated so that the number of Exchangeable Units of PDLP outstanding
remained unchanged from the number of Exchangeable Units of PDLP outstanding immediately
before the special in-kind distribution. |
Historical distributions and payments may not be reflective of future distribution and
payments, which will be subject to review by the Board of Trustees taking into account the
prevailing financial circumstances of the Trust at the relevant time. The declaration of
distributions and the method of settlement (cash or in-kind) is within the discretion of the
Board of Trustees.
DESCRIPTION OF CAPITAL
GENERAL DESCRIPTION OF CAPITAL STRUCTURE
Trust Units
An unlimited number of Trust Units may be created and issued pursuant to the Declaration of
Trust. Each Trust Unit entitles the holder thereof to one vote at any meeting of Trust Unit
holders, or in respect of any written resolution of Trust Unit holders, and represents an equal
undivided beneficial interest in any distribution from the Trust (whether from income, net realized
capital gains or other amounts) and in any net assets of the Trust in the event of termination or
winding up of the Trust. All Trust Units shall rank among themselves equally and rateably without
discrimination, preference or priority whatsoever. Each Trust Unit is transferable, is not subject
to any conversion or pre-emptive rights and entitles the holder thereof to require the Trust to
redeem any or all of the Trust Units held by such holder.
Special Voting Unit
Pursuant to the provisions of the Declaration of Trust a Special Voting Unit was issued to
Computershare Trust Company of Canada, as the initial trustee (the Voting and Exchange Trustee)
under a Voting and Exchange Trust Agreement, which allows the Special Voting Unit to be voted by
the Voting and Exchange Trustee for and on behalf of the holders of Exchangeable Units. The Voting
and Exchange Trustee is only entitled to the number of votes at meetings of Trust Unit holders
which is equal to the number of Exchangeable Units registered and outstanding on the record date in
respect of each meeting. The Voting and Exchange Trustee will be obligated to vote the Special
Voting Unit at meetings of Trust Unit holders pursuant to instructions of the holders of
Exchangeable Units. However, if no instructions are provided by holders of Exchangeable Units, the
votes associated therewith in the Special Voting Unit will be withheld from voting.
29
For a more complete description of the Trust Units and the Special Voting Unit please refer to
pages 57 to 63 of the 2005 Special Meeting Information Circular under the heading Declaration of
Trust and Description of Units which are incorporated by reference into this Annual Information
Form.
Precision Drilling Limited Partnership
As a result of the Plan of Arrangement, PDLP issued 122,512,799 Class A Limited Partnership
Units to the Trust on November 7, 2005 (the effective date of the reorganization of the business of
Precision into the Trust). An additional 1,840,122 Class A Limited Partnership Units were issued
between November 7 and November 22, 2005 inclusive (the last date on which holders of New Options
could exercise their options pursuant to the Plan of Arrangement). As of December 31, 2006 there
were 125,536,329 Class A Limited Partnership Units issued to the Trust. As of March 29, 2007 there
were 125,571,374 Class A Limited Partnership Units issued to the Trust.
Also, as part of the Plan of Arrangement, PDLP issued 1,108,382 Exchangeable Units to certain
shareholders of Precision who elected to receive such Exchangeable Units instead of Trust Units.
As of
December 31, 2006, 221,595 Exchangeable Units remained outstanding. As of March 29, 2007,
186,550 Exchangeable Units remained outstanding. The Exchangeable Units have the economic
equivalence of the Trust Units and the principal terms of the Exchangeable Units are:
|
|
they are exchangeable for Trust Units on a one-for-one basis at the option of the holder; |
|
|
each Exchangeable Unit entitles the holder thereof to receive (in the form of a non-interest bearing loan) cash
payments equal to cash distributions made by the Trust on a Trust Unit (and at the beginning of the next calendar year
a special distribution will be made on each Exchangeable Unit in an amount equal to the outstanding non-interest
bearing loan accumulated during the previous year which will be used to repay such accumulated debt); |
|
|
the holder of each Exchangeable Unit is entitled to direct the Voting and Exchange Trustee to vote the Special Voting
Unit at all meetings of Trust Unit holders; |
|
|
the holders of Exchangeable Units are not entitled, as such, to receive notice of or to attend any meeting of the
partners of PDLP or to vote at any such meeting, however, such holders of Exchangeable Units are entitled to vote
separately as a class in respect of proposals to add to, change or remove any right, privilege, restriction or
condition attaching to the Exchangeable Units or in respect of any other amendment to the applicable Partnership
Agreement which would have an adverse impact on the holders of such Exchangeable Units; and |
|
|
there are certain restrictions on the transfer of Exchangeable Units. |
A more detailed description of the attributes and restrictions associated with Exchangeable
Units is provided on pages 68 through 73 and Appendix D of the 2005 Special Meeting Information
Circular and the applicable portions of those pages and that Appendix D are incorporated by
reference into this Annual Information Form.
In addition to the foregoing, on November 7, 2005, the Trust, PDLP, the General Partner and
Precision entered into a support agreement (the Support Agreement) which requires the Trust or
its affiliates to take all actions and do all things as are reasonably necessary or desirable to
enable and permit PDLP to meet all of its obligations with respect to the Exchangeable Units and
such agreement also provides that the Trust will not, without the prior approval of PDLP and
holders of Exchangeable Units:
|
|
issue or distribute Trust Units to the holders of all, or substantially all, of the then outstanding Trust Units by way
of distribution; or |
|
|
issue or distribute rights, options or warrants to the holders of all, or substantially all, of the then outstanding
Trust Units entitling them to subscribe for or purchase Trust Units (or securities exchangeable for or converting into
or carrying rights to acquire Trust Units); or |
30
|
|
issue or distribute to the holders of all, or substantially all, of the then outstanding Trust Units; |
|
|
|
securities of the Trust or any class other than Trust Units (other than
securities exchangeable for or converting into or carrying rights to acquire Trust Units); |
|
|
|
|
rights, options or warrants other than those described in the second bullet above; or |
|
|
|
|
evidences of indebtedness of the Trust; or |
|
|
|
|
other assets of the Trust, |
unless the economic equivalent on a per Exchangeable Unit basis of such rights, options, warrants,
securities, shares, evidences of indebtedness or other assets is issued or loaned simultaneously to
the holders of Exchangeable Units.
A more complete description of the Support Agreement is set forth on pages 74 and 75 of the
2005 Special Meeting Information Circular under the heading Support Agreement which is
incorporated by reference into this Annual Information Form.
The General Partner
The General Partner of PDLP is a direct wholly-owned subsidiary of the Trust. The General
Partner is the managing partner of PDLP and has the exclusive authority to manage the business and
affairs of PDLP, to make all decisions regarding the business of PDLP and to bind PDLP.
MARKET FOR SECURITIES
Trading Price and Volume of Trust Units
The Trust Units were listed for trading on the Toronto Stock Exchange (the TSX) and the New
York Stock Exchange (the NYSE) on November 7, 2005, the date the reorganization of the business
of Precision into an income trust became effective. The Trust Units trade under the trading
symbols PD.UN and under the trading symbol PDS on the NYSE. The listing of Trust Units denominated
in U.S. dollars under the symbol PD.U on the TSX was discontinued effective December 29, 2006. The
following tables set forth the monthly and quarterly price range and volume traded for the Trust
Units on the TSX and NYSE from January, 2006 to March 27, 2007.
31
TSX PD.UN(1)
(In Canadian dollars, except volume traded amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period |
|
|
High |
|
|
Low |
|
|
Close |
|
|
Volume Traded |
|
|
|
|
|
|
|
|
|
|
|
|
|
January |
|
|
|
40.75 |
|
|
|
|
38.00 |
|
|
|
|
38.00 |
|
|
|
|
13,417,702 |
|
February |
|
|
|
38.95 |
|
|
|
|
34.00 |
|
|
|
|
35.53 |
|
|
|
|
15,792,850 |
|
March |
|
|
|
38.75 |
|
|
|
|
33.56 |
|
|
|
|
37.66 |
|
|
|
|
19,600,919 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2006 |
|
|
|
40.75 |
|
|
|
|
33.56 |
|
|
|
|
37.66 |
|
|
|
|
48,834,244 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April |
|
|
|
43.40 |
|
|
|
|
37.52 |
|
|
|
|
39.70 |
|
|
|
|
16,471,558 |
|
May |
|
|
|
40.74 |
|
|
|
|
35.88 |
|
|
|
|
37.60 |
|
|
|
|
11,463,735 |
|
June |
|
|
|
39.27 |
|
|
|
|
33.19 |
|
|
|
|
37.10 |
|
|
|
|
13,133,745 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2006 |
|
|
|
43.40 |
|
|
|
|
33.19 |
|
|
|
|
37.10 |
|
|
|
|
41,069,038 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July |
|
|
|
39.40 |
|
|
|
|
34.90 |
|
|
|
|
39.11 |
|
|
|
|
8,174,315 |
|
August |
|
|
|
41.80 |
|
|
|
|
38.86 |
|
|
|
|
40.24 |
|
|
|
|
9,384,581 |
|
September |
|
|
|
40.95 |
|
|
|
|
33.21 |
|
|
|
|
34.33 |
|
|
|
|
9,903,090 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q3 2006 |
|
|
|
41.80 |
|
|
|
|
33.21 |
|
|
|
|
34.33 |
|
|
|
|
27,461,986 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October |
|
|
|
34.65 |
|
|
|
|
30.19 |
|
|
|
|
31.94 |
|
|
|
|
19,431,267 |
|
November |
|
|
|
29.31 |
|
|
|
|
24.40 |
|
|
|
|
28.39 |
|
|
|
|
30,123,804 |
|
December |
|
|
|
29.30 |
|
|
|
|
26.80 |
|
|
|
|
27.00 |
|
|
|
|
6,488,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q4 2006 |
|
|
|
34.65 |
|
|
|
|
24.40 |
|
|
|
|
27.00 |
|
|
|
|
56,044,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January |
|
|
|
28.30 |
|
|
|
|
25.30 |
|
|
|
|
26.50 |
|
|
|
|
9,384,691 |
|
February |
|
|
|
27.90 |
|
|
|
|
24.60 |
|
|
|
|
27.43 |
|
|
|
|
10,003,698 |
|
March (2) |
|
|
|
27.33 |
|
|
|
|
25.13 |
|
|
|
|
27.13 |
|
|
|
|
9,629,950 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2007 |
|
|
|
28.30 |
|
|
|
|
24.60 |
|
|
|
|
27.13 |
|
|
|
|
29,018,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTES:
|
|
|
(1) |
|
Price and volume information is taken from the website maintained by the TSX. |
|
(2) |
|
For the period from March 1, 2007 to March 27, 2007. |
TSX PD.U(1)
(In U.S. dollars, except volume traded amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period |
|
|
High |
|
|
Low |
|
|
Close |
|
|
Volume Traded |
|
|
|
|
|
|
|
|
|
|
|
|
|
January |
|
|
|
36.00 |
|
|
|
|
32.50 |
|
|
|
|
33.67 |
|
|
|
|
34,281 |
|
February |
|
|
|
34.00 |
|
|
|
|
29.23 |
|
|
|
|
31.38 |
|
|
|
|
32,745 |
|
March |
|
|
|
33.00 |
|
|
|
|
28.48 |
|
|
|
|
31.86 |
|
|
|
|
33,631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2006 |
|
|
|
36.00 |
|
|
|
|
28.48 |
|
|
|
|
31.86 |
|
|
|
|
100,657 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April |
|
|
|
37.06 |
|
|
|
|
31.61 |
|
|
|
|
35.61 |
|
|
|
|
23,878 |
|
May |
|
|
|
36.83 |
|
|
|
|
32.00 |
|
|
|
|
34.51 |
|
|
|
|
26,386 |
|
June |
|
|
|
34.97 |
|
|
|
|
29.63 |
|
|
|
|
33.02 |
|
|
|
|
13,652 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2006 |
|
|
|
37.06 |
|
|
|
|
29.63 |
|
|
|
|
33.02 |
|
|
|
|
63,916 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July |
|
|
|
35.33 |
|
|
|
|
29.50 |
|
|
|
|
34.85 |
|
|
|
|
21,675 |
|
August |
|
|
|
37.28 |
|
|
|
|
34.00 |
|
|
|
|
35.97 |
|
|
|
|
27,100 |
|
September |
|
|
|
36.72 |
|
|
|
|
29.57 |
|
|
|
|
30.13 |
|
|
|
|
42,794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q3 2006 |
|
|
|
37.28 |
|
|
|
|
29.50 |
|
|
|
|
30.13 |
|
|
|
|
91,569 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October |
|
|
|
31.00 |
|
|
|
|
26.80 |
|
|
|
|
28.75 |
|
|
|
|
192,445 |
|
November |
|
|
|
26.11 |
|
|
|
|
21.25 |
|
|
|
|
24.81 |
|
|
|
|
104,698 |
|
December(2) |
|
|
|
27.38 |
|
|
|
|
23.12 |
|
|
|
|
23.14 |
|
|
|
|
60,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q4 2006 |
|
|
|
31.00 |
|
|
|
|
21.25 |
|
|
|
|
23.14 |
|
|
|
|
358,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
NOTES:
|
|
|
(1) |
|
Price and volume information is taken from the website maintained by the TSX. |
|
(2) |
|
The listing of the Trust Units denominated in U.S. dollars under the symbol PD.U was
discontinued effective December 29, 2006. |
NYSE PDS(1)
(In U.S. dollars, except volume traded amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period |
|
|
High |
|
|
Low |
|
|
Close |
|
|
Volume Traded |
|
|
|
|
|
|
|
|
|
|
|
|
|
January |
|
|
|
35.15 |
|
|
|
|
33.05 |
|
|
|
|
33.53 |
|
|
|
|
9,731,600 |
|
February |
|
|
|
34.12 |
|
|
|
|
29.78 |
|
|
|
|
31.49 |
|
|
|
|
11,524,700 |
|
March |
|
|
|
33.24 |
|
|
|
|
28.83 |
|
|
|
|
32.34 |
|
|
|
|
17,474,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2006 |
|
|
|
35.15 |
|
|
|
|
28.83 |
|
|
|
|
32.34 |
|
|
|
|
38,730,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April |
|
|
|
38.20 |
|
|
|
|
32.32 |
|
|
|
|
35.54 |
|
|
|
|
13,732,300 |
|
May |
|
|
|
36.88 |
|
|
|
|
31.77 |
|
|
|
|
34.05 |
|
|
|
|
14,176,400 |
|
June |
|
|
|
35.63 |
|
|
|
|
29.74 |
|
|
|
|
33.20 |
|
|
|
|
14,627,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2006 |
|
|
|
38.20 |
|
|
|
|
29.74 |
|
|
|
|
33.20 |
|
|
|
|
42,536,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July |
|
|
|
34.89 |
|
|
|
|
30.73 |
|
|
|
|
34.71 |
|
|
|
|
10,921,100 |
|
August |
|
|
|
37.78 |
|
|
|
|
34.61 |
|
|
|
|
36.66 |
|
|
|
|
10,530,300 |
|
September |
|
|
|
36.88 |
|
|
|
|
29.76 |
|
|
|
|
30.82 |
|
|
|
|
12,028,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q3 2006 |
|
|
|
37.78 |
|
|
|
|
29.76 |
|
|
|
|
30.82 |
|
|
|
|
33,480,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October |
|
|
|
31.48 |
|
|
|
|
26.74 |
|
|
|
|
28.66 |
|
|
|
|
21,450,600 |
|
November |
|
|
|
28.11 |
|
|
|
|
21.46 |
|
|
|
|
24.90 |
|
|
|
|
39,824,500 |
|
December |
|
|
|
25.48 |
|
|
|
|
23.00 |
|
|
|
|
23.16 |
|
|
|
|
19,262,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q4 2006 |
|
|
|
31.48 |
|
|
|
|
21.46 |
|
|
|
|
23.16 |
|
|
|
|
80,537,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January |
|
|
|
24.12 |
|
|
|
|
21.50 |
|
|
|
|
22.59 |
|
|
|
|
20,949,100 |
|
February |
|
|
|
24.02 |
|
|
|
|
21.06 |
|
|
|
|
23.41 |
|
|
|
|
13,976,307 |
|
March (2) |
|
|
|
23.57 |
|
|
|
|
21.71 |
|
|
|
|
23.49 |
|
|
|
|
15,773,839 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2007 |
|
|
|
24.12 |
|
|
|
|
21.06 |
|
|
|
|
23.49 |
|
|
|
|
50,699,246 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTES:
|
|
|
(1) |
|
Price and volume information is taken from the website maintained by the NYSE. |
|
(2) |
|
For the period from March 1, 2007 to March 27, 2007. |
ESCROWED SECURITIES
To the knowledge of the Board of Trustees and Precisions board of directors (the Board
of Directors and each a Director), no securities of the Trust are held in escrow.
TRUSTEES, DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth, for each Trustee of the Trust and Director and officer of
Precision: his name; municipality, province or state and country of residence; all positions and
offices now held by him; the month and year in which he was first elected a Director or officer;
his principal occupation during the preceding five years; and the number and percent of Trust Units
and Exchangeable Units that he has advised are beneficially owned by him, directly or indirectly,
as of the date hereof.
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust Units / |
|
|
|
|
|
|
|
|
|
|
|
|
Exchangeable Units |
|
|
|
|
|
|
|
|
|
|
|
|
Beneficially Owned, |
Name, Municipality, Province or |
|
|
Position Presently |
|
|
Director/ Officer |
|
|
Principal Occupation |
|
|
Controlled or |
State & Country of Residence |
|
|
Held(1) |
|
|
Since |
|
|
During the Preceding 5 Years |
|
|
Directed(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
W.C. (Mickey) Dunn(3) (5)
Edmonton, Alberta, Canada
|
|
|
Director
|
|
|
September 1992
|
|
|
Chairman, True Energy Trust
|
|
|
15,600 / nil
0.012% / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
Brian A. Felesky, CM, Q.C.(3)
Calgary, Alberta, Canada
|
|
|
Director
|
|
|
December 2005
|
|
|
Counsel, Felesky Flynn LLP
from April 1978 through
July 2006, Partner at
Felesky Flynn LLP.
|
|
|
2,800 / nil
0.002% / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert J.S. Gibson(3) (4)
Calgary, Alberta, Canada
|
|
|
Trustee
Director
|
|
|
June 1996
|
|
|
President, Stuart & Company
Limited
|
|
|
63,200(6) / nil
0.050% / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
Allen R. Hagerman
Cochrane, Alberta, Canada
|
|
|
Director
|
|
|
December 4, 2006
|
|
|
Chief Financial Officer,
Canadian Oil Sands Limited
since 2003, Vice President
and Chief Financial Officer
of Fording Canadian Coal
Trust 2003, Vice President
and Chief Financial Officer
of Fording Inc. 2001-2003.
|
|
|
1,000 / nil
0.001% / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
Stephen J.J. Letwin
Houston, Texas, USA
|
|
|
Director
|
|
|
December 4, 2006
|
|
|
Executive Vice President,
Enbridge Inc., Gas
Transportation and
International
|
|
|
nil / nil
nil / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
Patrick M. Murray(4)
Dallas, Texas, USA
|
|
|
Trustee
Director
|
|
|
July 2002
|
|
|
Chairman and Chief
Executive Officer, Dresser,
Inc.
|
|
|
40,000 / nil
0.032% / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
Frederick W. Pheasey(5)
Edmonton, Alberta, Canada
|
|
|
Director
|
|
|
July 2002
|
|
|
Director of Dreco Energy
Services Ltd.
|
|
|
44,000 / nil
0.035% / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert L. Phillips(3) (5)
Vancouver, British Columbia, Canada
|
|
|
Director
|
|
|
May 2004
|
|
|
Corporate Director,
President and Chief
Executive Officer, BCR
Group of Companies,
2001-2004
|
|
|
5,000(7) / nil
0.004% / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
Hank B. Swartout
Calgary, Alberta, Canada
|
|
|
Executive Chairman
Director
|
|
|
July 1987
|
|
|
Executive Chairman of
Precision since 2007,
Chairman and Chief
Executive Officer of
Precision 2005-2006,
Chairman, President and
Chief Executive Officer of
Precision 1985-2005
|
|
|
64,888(8) / nil
0.052% / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
H. Garth Wiggins(4) (9)
Calgary, Alberta, Canada
|
|
|
Trustee
Director
|
|
|
September 1997
|
|
|
Principal, Kenway, Mack,
Slusarchuk, Stewart,
Chartered Accountants
|
|
|
17,000 / nil
0.014% / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gene C. Stahl
Calgary, Alberta, Canada
|
|
|
President &
Chief Operating
Officer
|
|
|
November 2005
|
|
|
Vice President, Precision
Rentals 2003 2005,
General Manager Ducharme
Rentals/Big D Rentals 2002
2003, Investor Relations
Officer, Precision Drilling
Corporation 2001 2002
|
|
|
30,091 / nil
0.024% / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
Doug J. Strong
Calgary, Alberta, Canada
|
|
|
Chief Financial
Officer
|
|
|
November 2005
|
|
|
Chief Financial Officer,
Precision Diversified
Services Ltd. 2001 2005,
Group Controller, Precision
Drilling 2001 2005,
Senior Controller,
Precision Drilling 1997
2001
|
|
|
24,000 / nil
0.019% / nil |
|
|
|
|
|
|
|
|
|
|
|
|
|
Darren J. Ruhr
Calgary, Alberta, Canada
|
|
|
Vice President,
Corporate Services
& Corporate
Secretary
|
|
|
November 2005
|
|
|
Director, Information
Technology, Real Estate &
Travel, Precision Drilling
Corporation 2003 2005,
Director, Information
Technology, Precision
Drilling Corporation 2000 -
2003
|
|
|
10,000 / nil
0.008% / nil |
NOTES:
|
|
|
(1) |
|
Each Directors term of office expires not later than the close of business at the next
annual meeting, or until successors are appointed or Directors vacate their office, and
Directors are normally not renominated following the earlier of their fifteenth term or
69th birthday. Mr. Wiggins will not be standing for re-election as a Trustee or
Director. |
|
(2) |
|
Percentage of Trust Units and Exchangeable Units beneficially owned is calculated based on an
aggregate of 125,757,924 Trust Units and Exchangeable Units outstanding as of the Effective
Date. |
|
(3) |
|
Member of the Corporate Governance and Nominating Committee. |
|
(4) |
|
Member of the Audit Committee. |
|
(5) |
|
Member of the Compensation Committee. |
|
(6) |
|
8,000 of the Trust Units are held by Stuart & Company Limited, a company controlled by Mr.
Gibson, and 10,000 Trust Units are held in a registered retirement savings plan for the
benefit of Mr. Gibson. |
34
|
|
|
(7) |
|
2,000 Trust Units are held by R.L. Phillips Investments Inc., a company controlled by Mr.
Phillips. |
|
(8) |
|
The Trust Units are held by 1201112 Alberta Ltd., a company controlled by Mr. Swartout. |
|
(9) |
|
As Mr. Wiggins will not be standing for re-election at the Trusts Annual and Special
Meeting, it is proposed that Mr. Hagerman will replace him on the Audit Committee |
At March 29, 2007, the Trustees, the Directors and the executive officers of Precision,
as a group, beneficially owned, directly or indirectly, or exercised control over 317,579 Trust
Units and nil Exchangeable Units or approximately 0.25% of the issued and outstanding Trust Units
and Exchangeable Units.
CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS
No Trustee, Director or officer of Precision has, within the last 10 years, been a
director or officer of any reporting issuer that, while such person was acting in that capacity,
was the subject of a cease trade or similar order or an order that denied the reporting issuer
access to any statutory exemption for a period of more than 30 consecutive days or was declared a
bankrupt or made a voluntary assignment in bankruptcy, made a proposal under any legislation
relating to bankruptcy or been subject to or instituted any proceedings, arrangement or compromise
with creditors or had a receiver, receiver-manager or trustee appointed to hold assets of that
person.
AUDIT COMMITTEE INFORMATION
Audit Committee Charter
The Audit Committee Charter and Terms of Reference (the Audit Committee Charter) of
Precision is set forth in Appendix 1 of this Annual Information Form.
Composition of the Audit Committee
The Audit Committee of Precision currently consists of Patrick M. Murray (Chairman), H. Garth
Wiggins and Robert J. S. Gibson. As Mr. Wiggins will not be standing for re-election at the
Trusts Annual and Special Meeting it is proposed that Mr. Allen R. Hagerman will replace him on
the Audit Committee. The Audit Committee is a standing committee appointed by the Board of
Directors to assist the Board of Directors in fulfilling its oversight responsibilities with
respect to financial reporting by Precision and the Trust, in its own capacity and in its capacity
as the administrator of the Trust. Each member and the proposed member of the Audit Committee is
independent and none received, directly or indirectly, any compensation from Precision or the Trust
other than for services as a member of the Board of Trustees of the Trust or the Board of Directors
of Precision and its committees. All members and the proposed member of the Audit Committee are
financially literate as defined in Multilateral Instrument 52-110 (4.1) Audit Committees. In
addition, the Board of Directors has determined that each of Messrs. Murray, Wiggins and Hagerman
qualify as audit committee financial experts as that term is defined under the United States
Sarbanes-Oxley Act of 2002.
Relevant Education and Experience
In addition to each members general business experience, the education and experience of each
Audit Committee member that is relevant to the performance of his responsibilities as an Audit
Committee member are as follows: Patrick M. Murray (Chair) is the Chairman, President and Chief
Executive Officer of Dresser, Inc. Mr. Murray received a B.Sc. degree in Accounting in 1964 from
Seton Hall University and an MBA in 1973. Mr. Murray has been a member of Precisions Audit
Committee since April 2003. H. Garth Wiggins received his Bachelor of Electrical Engineering from
the University of Saskatchewan in 1970 and his Chartered Accountant designation in 1974. Mr.
Wiggins is a Principal at Kenway, Mack, Slusarchuk, Stewart, Chartered Accountants. Mr. Wiggins has
been a member of the Audit Committee since September 1997. Robert J.S. Gibson was educated at the
University of Calgary and the University of Alberta. Mr. Gibson is the President of Stuart &
Company Limited and has been a member of the Audit Committee since June 1997. Mr. Hagerman is the
Chief Financial Officer of Canadian Oil Sands Limited. Mr. Hagerman received a B. Comm. from the
University of Alberta in 1973 and his
35
Chartered Accountant designation in 1975. Mr. Hagerman also received an MBA from the Harvard
School of Business in 1977.
Pre-approval Policies and Procedures
Under the Audit Committee Charter, the Audit Committee is required to approve the terms of the
engagement and the compensation to be paid to the external auditor of the Trust. In addition, the
Audit Committee is required to review and pre-approve all permitted non-audit services to be
provided to the Trust or any affiliated entities by the external auditors or any of their
affiliates subject to any de minimus exception allowed by applicable law. The Audit Committee may
delegate to one or more designated members of the Audit Committee the authority to pre-approve
non-audit services. Non-audit services that have been pre-approved by any such delegate must be
presented to the Audit Committee at its first scheduled meeting following such pre-approval.
The Audit Committee implemented specific procedures regarding the pre-approval of services to
be provided by Precisions 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, Precisions management will, in conjunction with the Trusts 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 Committees 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 Trusts 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 Trusts external auditor, during fiscal 2006 and
2005:
|
|
|
|
|
|
|
|
|
|
|
(in thousands CDN$) |
|
|
|
|
|
|
Years ended December 31, |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
Audit fees |
|
|
$ |
1,813 |
|
|
|
$ |
2,108 |
|
Audit-related fees |
|
|
|
|
|
|
|
|
|
|
Tax fees |
|
|
|
579 |
|
|
|
|
753 |
|
All other fees |
|
|
|
|
|
|
|
|
54 |
|
|
|
|
|
|
|
|
Total |
|
|
$ |
2,392 |
|
|
|
$ |
2,915 |
|
|
|
|
|
|
|
|
Audit fees consist of fees for the audit of the Trusts annual financial statements or
services that are normally provided in connection with statutory and regulatory filings or
engagements and include fees related to Sarbanes-Oxley Section 404 compliance in 2006. The decrease in
audit fees from 2005 to 2006 was primarily due to the providing of services for discontinued
businesses in 2005.
Audit-related fees consist of fees for assurance and related services that are reasonably
related to the performance of the audit or review of the Trusts financial statements and are not
reported as audit fees. There were no such fees incurred in 2005 or 2006.
Tax fees consist of fees for tax compliance services, tax advice and tax planning. During
fiscal 2006 and 2005, the services provided in this category included assistance and advice in
relation to the preparation of corporate
36
income tax returns for the Trust and its subsidiaries, tax advice and planning, commodity tax
and property tax consultation.
In 2005, other fees related to translation of financial statements and due diligence
assistance with respect to a disposition. In 2006, there were no such fees.
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
None of the Trust, PDLP or Precision is involved in any legal proceedings that it
believes might have a material adverse effect on its business or results of operations of any of
the Trust, PDLP or Precision.
During the course of the year ended December 31, 2006, none of the Trust, PDLP or Precision
has been subject to any penalties or sanctions imposed by a court in relation to securities
legislation or by securities regulatory authority, has not entered into a settlement agreement with
a regulatory authority or been a subject of any other penalties or sanctions imposed by court or
regulatory authority and has not entered into any settlement agreements with a court relating to
securities legislation or with a securities regulatory authority.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
There were no material interests, direct or indirect, of the Trustees, Directors and
executive officers of Precision, any Unitholder who beneficially owns more than 10% of the
outstanding Trust Units or Exchangeable Units, or any known associate or affiliate of such persons,
in any transaction within the last fiscal year and in any proposed transaction which has materially
affected or would materially affect the Trust, PDLP or Precision.
TRANSFER AGENT, REGISTRAR AND VOTING AND EXCHANGE TRUSTEE
Computershare Trust Company of Canada, located in Calgary, Alberta, is the transfer agent
and registrar of the Trust Units and the Special Voting and Exchange Trustee for the holders of
Exchangeable Units. In the United States, the co-transfer agent for the Trust is Computershare
Trust Company, Inc. located in New York, New York.
MATERIAL CONTRACTS
The only material contracts entered into by Precision, the Trust or PDLP during the most
recently completed financial year, or before the most recently completed financial year that are
still in effect, other than contracts during the ordinary course of business, are as follows:
1. |
|
Weatherford Sale Agreement; |
|
2. |
|
CEDA Sale Agreement; |
|
3. |
|
Declaration of Trust; |
|
4. |
|
Limited Partnership Agreement; |
|
5. |
|
Voting and Exchange Trust Agreement; |
|
6. |
|
Support Agreement; and |
|
7. |
|
Administration Agreement. |
Copies of the material agreements described as 1 and 2 above have been filed by Precision and
the remainder of the material agreements described above have been filed by the Trust on SEDAR and
are available online at www.sedar.com.
INTERESTS OF EXPERTS
KPMG LLP, the Trusts external auditor, has prepared an opinion with respect to the
Trusts consolidated financial statements as at and for the year ended December 31, 2006. In
connection with the audit of the Trusts annual financial statements for the year ended December
31, 2006, the auditors confirmed that they are independent within the meaning of the Rules of
Professional Conduct of the Institute of Chartered Accountants of Alberta.
37
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
As of the fiscal year ended December 31, 2006, an evaluation of the effectiveness of the
Trusts 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 Trusts 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 Trusts 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 Trusts 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 Precisions principal executive officer and principal financial
and accounting officer believe that the Trusts disclosure controls and procedures provide a
reasonable level of assurance that they are effective, they do not expect that the Trusts
disclosure controls and procedures or internal control over financial reporting will prevent all
errors and fraud. A control system, no matter how well conceived or operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system are met.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
During the fiscal year ended December 31, 2006, there were no changes in the Trusts
internal control over financial reporting that have materially affected, or are reasonably likely
to materially affect, the Trusts internal control over financial reporting.
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Managements Discussion and Analysis relating to the consolidated financial statements
for the fiscal year ended December 31, 2006 forms part of the Trusts 2006 Annual Report and is
incorporated by reference in this Annual Information Form. Managements Discussion and Analysis
appears on pages 29 to 66 of the 2006 Annual Report.
ADDITIONAL INFORMATION
Additional information concerning the Trust is available through the Internet on SEDAR
which may be accessed at www.sedar.com. Copies of such information may also be obtained without
charge, on the Trusts website at www.precisiondrilling.com or by request to the Vice President,
Corporate Services and Corporate Secretary, at the offices of Precision at 4200, 150 6th Avenue
S.W., Calgary, Alberta, Canada T2P 3Y7; by email at corporatesecretary@precisiondrilling.com; by
telephone at (403) 716-4500; and by facsimile at (403) 264-0251.
Additional information, including information regarding Precisions Directors and officers
remuneration, is contained in the Management Information Circular of the Trust provided for the
Annual Meeting of Unitholders of the Trust to be held on May 9, 2007. Additional financial
information is provided in the Trusts annual consolidated financial statements and managements
discussion and analysis for the year ended December 31, 2006, which are contained in the Annual
Report. Copies of such documents may be obtained in the manner set forth above.
38
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
The Committee shall consist of no fewer than three members 1 , at least a
majority of whom must be resident Canadians. Each member of the Committee shall be independent
under the requirements or guidelines for audit committee service under applicable securities laws
and the rules of any stock exchange on which the units of the Trust are listed for
trading. 2
Each member of the Committee must be financially literate as such term is interpreted by the
Board of Directors in its business judgment in light of, and in accordance with, the requirements
or guidelines for audit committee service under applicable securities laws and the rules of any
stock exchange 3 on which the Trusts 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
Trusts units are listed for trading. 4
No Committee member shall serve on the audit committees of more than three other issuers
without prior determination by the Board of Directors that such simultaneous service would not
impair the ability of such member to serve effectively on the Committee. 5
|
(b) |
|
Appointment and Replacement of Committee Members |
Each member of the Committee shall serve at the pleasure of the Board of Directors. Any member of
the Committee may be removed or replaced at any time by the Board of Directors, and shall
automatically cease to be a member of the Committee upon ceasing to be a director of the
Corporation. The Board of Directors may fill vacancies on the Committee by appointment from among
its number. The Board of Directors shall fill any vacancy if the membership of the Committee is
less than three directors. If and whenever a vacancy shall exist on the Committee, the remaining
members may exercise all their power so long as a quorum remains in office. Subject to the
foregoing, the members of the Committee shall be appointed by the Board of Directors annually and
each member of the
|
|
|
1 |
|
NYSE s. 303A.07(a) |
|
2 |
|
MI 52-110 ss. 1.4, 1.5, 3.1(2) and 3.1(3); SO s. 301; SEC Final Rule on Standards Relating to Listed Company Audit
Committees; NYSE s. 303A.02, s. 303A.06 and 303A.07(6) |
|
3 |
|
MI 52-110 ss. 1.1 and 3.1(4); NYSE s. 303.01(B)(i)(b); NYSE s. 303A.07(a) |
|
4 |
|
SO s. 407; NYSE s. 303.01; NYSE s. 303A.07(a) |
|
5 |
|
NYSE s. 303A.07(a) |
39
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.
The Committee shall have a quorum of not less than a majority of its members.
|
(d) |
|
Review of Charter and Terms of Reference |
The Committee shall review and reassess the adequacy of this Charter and Terms of Reference at
least annually and otherwise as it deems appropriate, and recommend changes to the Board of
Directors. The Committee shall evaluate its performance with reference to this Charter and Terms
of Reference annually. 6 The Committee will approve the form of disclosure of
this Charter and Terms of Reference on the Trusts website and, where required by applicable
securities laws or regulatory requirements, in the annual management information circular or annual
report of the Trust.
The Committee may delegate from time to time to any person or committee of persons any of the
Committees responsibilities that lawfully may be delegated.
|
(f) |
|
Reporting to the Board of Directors |
The Committee will report through the Chair of the Committee to the Board of Directors following
meetings of the Committee on matters considered by the Committee, its activities and compliance
with this Charter and Terms of Reference. 7
|
(g) |
|
Committee Chair Responsibilities |
The Board of Directors shall appoint a Chair of the Committee. The primary responsibility of the
Chair of the Committee is to provide leadership to the Committee to enhance its effectiveness. In
such capacity, the Chair of the Committee will perform the duties and responsibilities set forth in
the Position Description for the Audit Committee Chair.
The Committee may request any officer or employee of the Corporation, or the Corporations or the
Trusts 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 Corporations expense. 8
Purpose
The Committee shall have responsibility for overseeing the development and maintenance of the
Corporations and the Trusts systems for financial reporting. Responsibility for accounting for
transactions and internal control over financial reporting lies with senior management of the
Corporation with oversight responsibilities vested in the Board of Directors. The Committee is a
permanent committee of the Board of Directors whose purpose is to assist the Board of Directors by
overseeing:
|
|
|
6 |
|
NYSE s. 303A.07(c)(ii) |
|
7 |
|
NYSE s. 303A.07 (c)(iii)(H) |
|
8 |
|
MI 52-110 s. 4.1(a) and (b); SO s. 301(5) and
(6); NYSE s. 303A.07(c) (iii) |
40
|
|
|
the integrity of financial reporting to the holders of units of the Trust
(Unitholders) and the investment community; 9 |
|
|
|
|
the integrity of the financial reporting process, including the audit
process; 10 |
|
|
|
|
the Corporations and the Trusts compliance with legal and regulatory requirements as
they relate to financial reporting matters; 11 |
|
|
|
|
the external auditors qualifications and independence; 12 |
|
|
|
|
the integrity of the system of internal accounting and financial reporting controls
implemented by management; 13 |
|
|
|
|
the work and performance of the Corporations and the Trusts financial management,
internal audit function and its external auditor; and 14 |
|
|
|
|
any other matter specifically delegated to the Committee by the Board of Directors. |
Committee Responsibilities
The Committee shall:
|
|
|
review the interim and annual financial statements of the Corporation and make any
comments or recommendations to the Board of Directors; |
|
|
|
|
review the annual financial statements of the Trust and related notes and managements
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 Trusts public
disclosure of financial information extracted or derived from the Trusts financial
statements, other than the public disclosure referred to above, and must periodically
assess the adequacy of those procedures 15 ; |
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|
|
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 auditors engagement letter as agreed between the
external auditor and financial management of the Corporation, and the compensation to be
paid by the Corporation to the external auditor; 16 |
|
|
|
9 |
|
NYSE s. 303A.07(c)(i)(A) |
|
10 |
|
NYSE s. 303A.07(c)(i)(A) |
|
11 |
|
NYSE s. 303A.07(c)(i)(A) |
|
12 |
|
NYSE s. 303A.07(c)(i)(A) |
|
13 |
|
NYSE s. 303A.07(c)(i)(A) |
|
14 |
|
NYSE s. 303A.07(c)(i)(A) |
|
15 |
|
MI 52-110 s. 2.3(6) |
|
16 |
|
SO s. 301(2); NYSE s. 303A.07(c)(iii) |
41
|
|
|
review the reasons for any proposed change in the external auditor which is not
initiated by the Committee or the Board of Directors and any other significant issues
related to the change, including the response of the incumbent external auditor, and
enquire as to the qualifications of the proposed external auditor before making its
recommendations to the Board of Directors; 17 |
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|
|
|
be directly responsible for overseeing the work of the external auditor engaged for
the purpose of preparing or issuing an auditors report or performing other audit or review
services for the Corporation or the Trust, including the resolution of disagreements
between management and the external auditor regarding financial
reporting 18 or the application of any accounting principles or
practices; |
|
|
|
|
require the external auditor and internal auditor to report directly to the
Committee; 19 |
|
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|
|
provide the external auditor with notice of every meeting of the Committee and, at
the expense of the Corporation, the opportunity to attend and be heard thereat, and if so
requested by a member of the Committee, shall attend every meeting of the Committee held
during the term of the office of the external auditor. The external auditor of the
Corporation or any member of the Committee may call a meeting of the Committee; |
pre-approve all permitted 20 non-audit services to the Corporation or any
affiliated entities by the external auditor or any of their affiliates 21
subject to any de minimus exception allowed by applicable law. The Committee may delegate to one
or more designated members of the Committee the authority to pre-approve non-audit services,
however any non-audit services that have been pre-approved by any such delegate of the Committee
must be presented to the Committee at its first scheduled meeting following such pre-approval;
|
|
|
review the disclosure with respect to its pre-approval of audit and non-audit services
provided by the external auditors; 22 |
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|
|
|
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 Trusts or the Corporations selection or application of
accounting principles, and major issues as to the adequacy of the Trusts or the
Corporations respective internal controls and any special audit steps adopted in light of
material control deficiencies; (c) analyses prepared by management or the external auditor
setting forth significant financial reporting issues and judgments made in connection with
the preparation of the financial statements, including analyses of the effects of
alternative Canadian Generally Accepted Accounting Principles (GAAP) methods on the
financial statements 23 of the Trust and any other opinions sought by
management from an independent or other audit firm or advisor with respect to the
accounting treatment of a particular item; (d) any management letter or schedule of
unadjusted differences provided by the external auditor and |
|
|
|
17 |
|
NI 51-102 s. 4.11 |
|
18 |
|
SO s.301; SEC Final Rule on Standards
Relating to Listed Company Audit Committees; MI 52-110 s.2.3(3) |
|
19 |
|
NI 52-110 s. 2.2 |
|
20 |
|
The following non-audit services are
prohibited under SO s.201(a), the SEC Final Rule on Strengthening the
Commissions Requirements Regarding Auditor Independence and the
CICAs proposed Auditor Independence Standards: |
|
|
|
bookkeeping services and other services related to accounting records
or financial statements; |
|
|
|
|
financial information systems design and implementation; |
|
|
|
|
appraisal or valuation services, fairness opinions or
contribution-in-kind reports; |
|
|
|
|
actuarial services; |
|
|
|
|
internal audit outsourcing services; |
|
|
|
|
management functions or human resources; |
|
|
|
|
broker dealer, investment advisor or investment banking services; |
|
|
|
|
legal services and expert services unrelated to the audit. |
In addition, the SEC Final Rule prohibits providing expert services
unrelated to the audit for advocacy purposes unless limited to a factual
account of the work performed and conclusions reached in respect of an audit
performed.
|
|
|
21 |
|
SO s. 201 and 202; SEC Final Rule on
Strengthening the Commissions Requirements Regarding Independence; SEC
Regulation S-X 2-01(c)(7) |
|
22 |
|
SO s. 202; SEC Final Rule on Strengthening
the Commissions Requirements Regarding Auditor Independence |
|
23 |
|
SO s.204; NYSE s.303A.07(c) (General
Commentary) |
42
the Trusts response to that letter and other material written communication between the
external auditor and management; 24 (e) any problems, difficulties or
differences encountered in the course of the audit work including any disagreements with
management or restrictions on the scope of the external auditors activities or on access to
requested information and managements response thereto; 25 (f) the
effect of regulatory and accounting initiatives, as well as any off-balance sheet structures
on the financial statements of the Trust and other financial
disclosures; 26 (h) any reserves, accruals, provisions or estimates that
may have a significant effect upon the financial statements of the Trust; (i) the use of
special purpose entities and the business purpose and economic effect of off balance sheet
transactions, arrangements, obligations, guarantees and other relationships of the Trust or
the Corporation and their impact on the reported financial results of the
Trust; 27 and (j) the use of any pro forma or adjusted information
not in accordance with generally accepted accounting principles; 28
|
|
|
reviewing earnings press releases (paying particular attention to any use of pro
forma or adjusted non-GAAP information) as well as financial information and earnings
guidance provided to analysts and rating agencies, it being understood that such review may
in the discretion of the Committee, be done generally (i.e., by discussing the types of
information to be disclosed and the type of presentation to be made); 29 |
|
|
|
|
review with the external auditor and management the general audit approach and
scope of proposed audits of the financial statements of the Trust, the objectives,
staffing, locations, co-ordination and reliance upon management in the audit, the overall
audit plans, the audit procedures to be used and the timing and estimated budgets of the
audits; 30 |
|
|
|
|
review any legal matter, claim or contingency that could have a significant impact
on the financial statements of the Trust, the Corporations or the Trusts 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 Trusts financial statements; |
|
|
|
|
review the treatment for financial reporting purposes of any significant transactions
which are not a normal part of the Corporations 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 Corporations major financial risk exposures and
the steps management has taken to monitor and control such exposures, including the
Corporations risk assessment and risk management policies such as financial derivatives
and hedging activities; 31 |
|
|
|
|
annually request and review a report from the external auditor regarding (a) the
external auditors quality-control procedures, (b) any material issues raised by the most
recent quality-control review or peer review of the external auditor, or by any inquiry or
investigation by governmental or professional authorities within the preceding five years
respecting one or more independent audits carried out by the firm, 32
and (c) any steps taken to deal with any such issues; |
|
|
|
24 |
|
SO s. 204; SEC Final Rule on Strengthening
the Commissions Requirements Regarding Auditor Independence |
|
25 |
|
NYSE s. 303A.07(c)(iii)(F); CICA Handbook
Section 5751.23 |
|
26 |
|
NYSR s. 303A.07(c)(General Commentary) |
|
27 |
|
NYSE s.303A.07(c) (General Commentary); SO
s.401; SEC Final Rule on Disclosure in Managements Discussion and
Analysis About Off Balance Sheet Arrangements and Aggregate Contractual
Obligations |
|
28 |
|
SO s.401; SEC Regulation G; NYSE s.
303A.07(c); SEC Final Rule on Conditions for Use of Non-GAAP Financial
Measures; CSA Notice 52-306 |
|
29 |
|
NP 51-201 s.6.4; MI 52-110 s.2.3(5); NYSE
s.303A.07(c)(iii)(C) and 303A.07(c) (General Commentary) |
|
30 |
|
CICA Handbook Section 5751.14; MI 52-110 s.
2.3(3)(c)(i)(A) |
|
31 |
|
NYSE s. 303A.07(c)(iii)(D) |
|
32 |
|
NYSE s. 303A.07(c)(iii)(A); CICA Handbook
Section 5751.31 |
43
|
|
|
evaluate the qualifications and performance of the external auditor, including a written
review and evaluation of the lead partner of the external auditor 33 ,
review and approve hiring policies for partners, employees or former employees of the
external auditor 34 and make recommendations to the Board of Directors
as to the appointment or reappointment of the external auditor to be proposed for approval
by the Board of Trustees and Unitholders; 35 |
|
|
|
|
review the independence of the external auditor, 36 annually
request and review a written report from the external auditor respecting its independence,
including a list of all relationships between the external auditor and each of the
Corporation and the Trust, 37 and consider applicable auditor
independence standards; 38 |
|
|
|
|
ensure that the lead audit partner of the external auditor and the audit partner
responsible for reviewing the audit are rotated at least every five years as required by
the Sarbanes-Oxley Act of 2002, and further consider rotation of the external auditors
firm itself; |
|
|
|
|
discuss with management and the external auditors any accounting adjustments that were
noted or proposed by the external auditors but were not adopted (as immaterial or
otherwise); |
|
|
|
|
review the adequacy and effectiveness of the Corporations and the Trusts internal
accounting and financial controls based on recommendations from management and the external
auditor for the improvement of accounting practices and internal controls; 39 |
|
|
|
|
establish and periodically review procedures for (a) the receipt, retention and
treatment of complaints received by the Corporation or the Trust regarding accounting,
internal controls or auditing matters, and (b) the confidential, anonymous submission by
employees of the Corporation of concerns regarding questionable accounting or auditing
matters or other matters that could negatively affect the Corporation or the Trust such as
violations of the Joint Code of Business Conduct and Ethics; 40 |
|
|
|
|
review periodically with management and the external auditors any significant
complaints received; |
|
|
|
|
review other financial information included in the Trusts Annual Report to ensure that
it is consistent with the Board of Directors knowledge of the affairs of the Corporation
and the Trust and is unbiased and non-selective; |
|
|
|
|
if requested by the Board of Directors, receive from the Executive Chair or the Chief
Executive Officer and Chief Financial Officer of the Corporation a certificate certifying
in respect of each annual and interim report of the Trust the matters such officers are
required to certify in connection with the filing of such reports under applicable
securities laws and receive and review disclosures made by such officers about any
significant deficiencies in the design or operation of internal controls or material
weaknesses therein and any fraud involving management or persons who have a significant
role in the Corporations internal controls; |
|
|
|
|
prepare any report required by law, regulations or stock exchange requirement to be
included in the Trusts periodic reports; |
|
|
|
33 |
|
Commentary to NYSE s. 303A.07(c)(iii)(A) |
|
34 |
|
MI 52-110 s. 2.3(8); NYSE s.
303A.07(c)(iii)(G); SO s. 206; SEC Final Rule on Strengthening the
Commissions Requirements Regarding Auditor Independence; Independence
Standards Board Independence Standard No. 3 |
|
35 |
|
SO s. 301(2); MI 52-110 s. 2.3(2); NYSE s.
303A.07(c)(i)(A) and 303A.07(c)(iii) |
|
36 |
|
NYSE s. 303A.07(c)(i)(A) |
|
37 |
|
NYSE s. 303A.07(c)(iii)(A); CICA Handbook
Section 5751.12, .25, .29 and .32 |
|
38 |
|
SO s. 203; NYSE s. 303A.07(c)(iii)(A); CICA
Proposed Independence Standards s. 204.4(20) |
|
39 |
|
NYSE s. 303A.07(c)(General Commentary); CICA
Handbook Section 5751.16 |
|
40 |
|
SO s. 301; SEC Final Rule on Standards
Relating to Listed Company Audit Committees; MI 52-110 s. 2.3(7) |
44
|
|
|
meet at least four times a year on a quarterly basis or more frequently as circumstances
require, with the Chief Financial Officer of the Corporation, the head of the internal
audit function of the Corporation, if other than the Chief Financial Officer, and the
external auditor in separate executive sessions to discuss any matters that the Committee
or each of these groups believes should be discussed privately; |
|
|
|
|
review annually the Corporations 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
Trusts 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 managements response; |
|
|
|
|
review and evaluate the scope, risk assessment, and nature of the internal audit plan
and any subsequent changes; 41 |
|
|
|
|
consider and review the following issues with management and the head of the internal audit group: |
|
|
|
significant findings of the internal audit group as well as managements response to them; |
|
|
|
|
any difficulties encountered in the course of their internal
audits, including any restrictions on the scope of their work or access to
required information; |
|
|
|
|
the internal auditing budget and staffing; |
|
|
|
|
the internal Audit Services Charter; and |
|
|
|
|
compliance with The Institute of Internal Auditors Standards
for the Professional Practice of Internal Auditing; |
|
|
|
approve the appointment, replacement or dismissal of the head of the internal audit
group; and |
|
|
|
|
direct the head of the internal audit group to review any specific areas the Committee
deems necessary; and |
|
|
|
|
ensure that the obligations of the Corporation pursuant to the Administration Agreement
are met and that good corporate governance procedures are used in connection therewith. |
In addition, the Committee shall hold in-camera meetings with representatives of the external
auditor and internal auditor to discuss audit related issues, including the quality of accounting
personnel.
The Committee shall have such other powers and duties as may from time to time by resolution be
assigned to it by the Board of Directors.
Limitation of Committees 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 Trusts or the Corporations financial statements and disclosures
are complete and accurate and are in accordance with GAAP and applicable rules and regulations.
These are the responsibilities of the management of the Corporation and the external auditor.
|
|
|
41 |
|
NYSE s. 303A.07(c)(i)(A) and s.
303A.07(c)(iii)(E); s. 303A.07(d) |
45
The Committee, the Chair of the Committee and any Committee members identified as having accounting
or related financial expertise are members of the Board of Directors, appointed to the Committee to
provide broad oversight of the financial, risk and control-related activities of the Corporation
and the Trust, and are specifically not accountable or responsible for the day-to-day operation or
performance of such activities.
Although the designation of a Committee member as having accounting or related financial expertise
for disclosure purposes is based on that individuals 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 Trusts financial information or public disclosure.
[Approved on July 26, 2006]
46
Precision Drilling Trust
MANAGEMENTS DISCUSSION AND ANALYSIS
This Managements Discussion and Analysis (MD&A), prepared as at March 9, 2007, focuses on
key statistics from the Consolidated Financial Statements, and pertains to known risks and
uncertainties relating to the oilfield services sector. This discussion should not be considered
all-inclusive, as it does not include all changes that may occur in general economic, political
and environmental conditions. Additionally, other events may or may not occur which could affect
Precision Drilling Trust (the Trust or Precision) in the future. In order to obtain an
overall perspective, this discussion should be read in conjunction with the material contained in
other parts of this annual report, including the Cautionary Statement Regarding Forward-Looking
Information and Statements on page 1, the audited Consolidated Financial Statements and the
related notes. The effects on the Consolidated Financial Statements arising from differences in
generally accepted accounting principles (GAAP) between Canada and the United States are
described in Note 16 to the Consolidated Financial Statements. Additional information relating to
the Trust, including the Annual Information Form, has been filed with SEDAR and is available at
www.sedar.com.
With the conversion of the continuing assets and businesses of Precision Drilling Corporation to
an income trust on November 7, 2005 pursuant to a plan of arrangement, the Trust, as the
successor in interest to Precision Drilling Corporation, has been accounted for as a continuity
of interest. Commencing with the year ended December 31, 2005 and the comparables for the
quarterly and annual periods for the years ended December 31, 2005 and 2004, the Consolidated
Financial Statements of the Trust reflect the financial position, results of operations and cash
flows as if the Trust had always carried on the business formerly carried on by Precision
Drilling Corporation.
HIGHLIGHTS
(Stated in thousands of Canadian dollars, except per diluted unit/share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Increase |
|
|
|
|
|
|
% Increase |
|
|
|
|
|
|
% Increase |
|
Years ended December 31, |
|
2006 |
|
|
(Decrease) |
|
|
2005 |
|
|
(Decrease) |
|
|
2004 |
|
|
(Decrease) |
|
|
Revenue |
|
$ |
1,437,584 |
|
|
|
13 |
|
|
$ |
1,269,179 |
|
|
|
23 |
|
|
$ |
1,028,488 |
|
|
|
12 |
|
Operating earnings (1) |
|
|
595,279 |
|
|
|
28 |
|
|
|
465,378 |
|
|
|
40 |
|
|
|
331,313 |
|
|
|
31 |
|
Earnings from continuing operations |
|
|
572,512 |
|
|
|
159 |
|
|
|
220,848 |
|
|
|
17 |
|
|
|
188,131 |
|
|
|
31 |
|
Discontinued operations, net of tax (2) |
|
|
7,077 |
|
|
|
n/m |
|
|
|
1,409,715 |
|
|
|
n/m |
|
|
|
59,273 |
|
|
|
n/m |
|
Net earnings |
|
|
579,589 |
|
|
|
(64 |
) |
|
|
1,630,563 |
|
|
|
559 |
|
|
|
247,404 |
|
|
|
37 |
|
Cash provided by continuing operations |
|
|
609,744 |
|
|
|
196 |
|
|
|
206,013 |
|
|
|
(28 |
) |
|
|
286,437 |
|
|
|
43 |
|
Net capital spending from
continuing operations (3) |
|
|
233,693 |
|
|
|
67 |
|
|
|
140,077 |
|
|
|
23 |
|
|
|
113,897 |
|
|
|
34 |
|
Distributions declared cash |
|
|
447,001 |
|
|
|
n/m |
|
|
|
70,510 |
|
|
|
n/m |
|
|
|
|
|
|
|
|
|
Distributions declared in-kind |
|
|
24,523 |
|
|
|
n/m |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per diluted unit/share information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
4.56 |
|
|
|
159 |
|
|
|
1.76 |
|
|
|
9 |
|
|
|
1.61 |
|
|
|
23 |
|
Net earnings |
|
|
4.62 |
|
|
|
(64 |
) |
|
|
13.00 |
|
|
|
516 |
|
|
|
2.11 |
|
|
|
29 |
|
Distributions declared cash |
|
|
3.56 |
|
|
|
n/m |
|
|
|
0.56 |
|
|
|
n/m |
|
|
|
|
|
|
|
|
|
Distributions declared in-kind |
|
|
0.195 |
|
|
|
n/m |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Non-GAAP measure. See page 66. |
|
(2) |
|
Includes gain on disposition of discontinued operations. |
|
(3) |
|
Excludes acquisitions and discontinued operations. |
|
n/m calculation not meaningful. |
FINANCIAL POSITION AND
RATIOS
(Stated in thousands of Canadian dollars, except ratios)
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Working capital |
|
$ |
166,484 |
|
|
$ |
152,754 |
|
|
$ |
557,311 |
|
Working capital ratio |
|
|
1.8 |
|
|
|
1.4 |
|
|
|
2.5 |
|
Long-term debt (1) |
|
$ |
140,880 |
|
|
$ |
96,838 |
|
|
$ |
718,850 |
|
Total assets |
|
$ |
1,761,186 |
|
|
$ |
1,718,882 |
|
|
$ |
3,852,049 |
|
Long-term debt to long-term debt plus equity (1) |
|
|
0.10 |
|
|
|
0.08 |
|
|
|
0.24 |
|
Long-term debt to cash provided by continuing operations (1) |
|
|
0.23 |
|
|
|
0.47 |
|
|
|
2.51 |
|
Interest coverage (2) |
|
|
74.1 |
|
|
|
15.9 |
|
|
|
7.2 |
|
|
|
|
|
(1) |
|
Excludes current portion of long-term debt which is included in working capital.
|
|
(2) |
|
Operating earnings divided by net interest expense. |
OVERVIEW AND OUTLOOK
Fiscal 2006 marked a new chapter in Precisions development. During the second half of 2005
there were certain events that changed the course of our company. Precision sold 55% of its asset
base, agreed to non-compete provisions restricting certain operational scope to Canada and the
United States through August 2008, realized a gain of $1.3 billion and used the proceeds to
eliminate $0.7 billion in public debt and to return $2.9 billion in cash and marketable
securities to its shareholders. Following these strategic transactions, Precision converted its
continuing Canadian operations into an income trust structure, pursuant to shareholder approval,
on November 7, 2005.
After more than 50 years of operating as either a private or public corporation with no regular
dividends to its owners, Precision commenced 2006 with a new capital structure geared toward the
flow-through of cash pursuant to a distribution policy managed by its Trustees. After almost a
decade of reinvesting a substantial amount of retained earnings toward growth in international
markets and certain downhole technologies, Precision returned to its core business segment,
contract drilling, and its dominant market position in Canada.
The strategy for the continuing business platform in Canada is an affirmation of Precisions
prior operational model and for the near term sets the focus on the Canadian marketplace. The
emphasis is to build upon our core group of people, augment the services we provide our
customers, passionately pursue our Target Zero safety vision and continue to grow and be
profitable. Precision set its growth objectives with a view to participate in market
opportunities throughout North America with a long-term objective to consolidate higher cost,
less efficient competitors and those with a common operational philosophy of providing safe
customer solutions through superior technology, process and personnel.
For 2006 this strategy took root with many noteworthy developments.
Profitability
|
|
Precision benefited from strong industry fundamentals carried over from a banner 2005 to
generate record earnings from continuing operations for 2006 of $573 million or $4.56 per unit. |
|
|
|
Precision generated operating earnings of $595 million, an increase of $130 million or 28% over
2005. |
Growth
|
|
Net capital spending in 2006 for the purchase of property, plant and equipment increased
67% or $94 million over the prior year to $234 million. Before considering proceeds on asset
disposals of $29 million, Precision spent $92 million toward the productive capacity maintenance
of its existing asset base and $171 million on expansionary initiatives. |
|
|
|
Precision established a contract drilling operation in the United States and currently
operates two rigs. |
|
|
|
|
Precision added 13 new and decommissioned two drilling rigs in its Canadian fleet. By the
end of the first quarter of 2008, Precision expects to be operating a North American drilling
fleet of 260 rigs, 13% more than at the end of 2005. |
|
|
|
|
Precision commenced the construction of two service rigs under a long-term customer
arrangement, for deployment in the first half of 2007. |
|
|
|
|
The snubbing, camp and catering and rental divisions grew existing product lines in
response to market
conditions.
|
Augment Customer Services
|
|
On August 17, 2006 Precision acquired a wastewater treatment business for remote work sites
which complements our camp and catering and wellsite rental businesses and enhances our level of
customer service. |
Passionately Pursue Target Zero Safety Vision
|
|
Precision moved closer to its safety vision with a renewed focus on the basic elements of
its health, safety and environmental program. The improvement in safe work practices continued
for Precision, resulting in a 28% reduction in workplace injuries. |
Build Upon Our Core Group of People
|
|
A North American shortage of skilled and experienced oilfield employees carried into 2006.
Precision focused on the retention of existing employees through initiatives that provide a safe
and productive work environment, opportunity for advancement and added wage security through
programs such as our Designated Driller Program. |
|
|
|
The Canadian drilling industry has taken an important step forward with the 2006 commencement
of a compulsory journeyman trade program through the Alberta government, the rig technician
designation, the first of its kind in the world. Precision has been involved in the development
of this initiative from the beginning. |
|
|
|
Precision continued to transition executive roles through a succession process that began in
September 2005. Precision announced in October 2006 that its founder, Hank Swartout, would
relinquish his position as Chief Executive Officer and assume the role of Executive Chairman
effective January 1, 2007. Precision has initiated and continues to develop a more involved
strategic planning process. |
|
|
|
Precision completed its internal control certification over financial reporting pursuant to
Canadian and United States securities regulations. The initiative was led through internal
efforts that sharpened our awareness of the joint code of business conduct and ethics policy and
provided numerous opportunities for Precisions management to build upon its skill in identifying
and managing risk. |
Cash Distributions to Unitholders
|
|
With its conversion to an income trust on November 7, 2005 Precision converted from a cash
retention to a cash flow-through model. For 2006, Precisions first full year as an income trust,
Precision declared cash distributions of $447 million or $3.56 per unit. |
|
|
|
Distributable cash from operations of $495 million resulted in a cash distribution declared
payout ratio of 90% for 2006. This calculation starts with $610 million in cash provided from
operations less $92 million for productive capacity maintenance capital expenditures and $23
million for unfunded long-term incentive plan obligations. The remaining $48 million was retained
to fund other investing and financing activities. |
In summary, 2006 was a very successful year for Precision. We delivered record-setting financial
and safety results through our industry leading market position and operational processes. We
generated growth opportunities in our core Canadian market area and we established a new growth
platform in the United States drilling market.
In form, our new capital structure as an income trust had an excellent start in 2006. Strong
operating cash flow performance led to $472 million declared distributions to unitholders. At
this level, the maximum flow-through potential of Precisions underlying pre-tax income was
obtained. The remaining taxable income in the subsidiaries of Precision Drilling Trust led to a
2006 current income tax expense of $35 million.
By the fourth quarter of 2006, strong business fundamentals were showing clear signs of being
eroded as the volatility and declining trend in natural gas pricing slowed customer demand from
record levels and downward pressure on pricing for the oilfield service industry was experienced.
While customer pricing for Precision has held at record rates, declining demand and the
additional supply of new industry equipment resulted in lower utilization to begin 2007 and lower
pricing is expected to follow once the seasonal spring break-up begins in March. Through the
first two months of 2007 drilling rig operating days were 19% lower than 2006 even though
Precisions fleet was
5% larger. For Precisions service rig fleet in the Western Canada Sedimentary Basin (WCSB),
operating hours for the first two months of 2007 were 15% lower.
Deteriorating business conditions in Canada were compounded by the Government of Canadas tax
announcements on October 31, 2006 and its clarification regarding normal growth for income trusts
on December 15, 2006.
|
|
If the proposed measures are enacted into law, effective January 1, 2011, the current
underlying flow-through status of Precisions current income trust structure will be ended. The
proposed amendments have negative implications for certain unitholders of Precision commencing in
2011, particularly Canadian tax-exempt investors, foreign investors and tax-exempt entities. |
|
|
|
Nonetheless, Precisions operational business model remains intact. |
|
|
|
Precision originally converted to a trust because the tax rules of the day allowed the market
to place a higher value for unitholders on the flow-through structure than the traditional
corporate structure. In light of the proposed legislative changes, it is incumbent on the Board
of Trustees to examine whether changes in the current legal structure and capital structure are
appropriate and in the best interests of unitholders and, if so, when such changes should be
implemented. |
Monitoring of the current operating environment in North America is also warranted as a
significant quantity of new equipment is under construction and Precisions level of customer
demand uncertainty is higher than it has been in the past five years. This shift in momentum is
not new. Precision operates in the cyclical energy sector and our business model has evolved to
ensure that we are in a position to take advantage of opportunities through all stages. Given the
competitiveness and inherent risk factors involved, Precisions strategy is patience,
flexibility, financial prudence and opportunism.
A strong balance sheet has been a key performance driver for Precision over the years. Low debt
levels at the peak and bottom of a cycle enabled Precision to cope with lower operating cash
flows and provided the financial leverage to invest in meaningful growth as opportunities arose.
The Canadian oilfield service sector has undergone significant growth in equipment supply due to
a surge in natural gas well drilling over the past five years. Declining demand conditions in
2007 have created excess drilling rig capacity and a severe drop, or persistent decline in
demand, may result in opportunities for industry consolidation.
Currently, Precisions financial performance is heavily dependant on industry fundamentals within
Canada. These fundamentals are 70% weighted towards natural gas wells and the volatility that
exists with seasonal shifts and customer spending associated with the WCSB.
For 2007, Precisions strategy remains focused on opportunities in Canada and the United States
and 2006 developments are expected to move Precision forward in a more competitive marketplace.
Precisions growth strategy is to diversify our earnings base so that Precision is active in many
of the significant oil and natural gas basins in North America. Our participation in these basins
is focused on providing our customers with a level of service and capability that sets our
performance apart from the competition. Just as Precision has become a prominent SAGD driller for
major projects in Canadas oil sands, our participation in the United States through two drilling
rigs is setting the stage for further opportunity.
For the past two years, growth has been achieved through the construction of new drilling rigs.
The type of rig being built by Precision is a long-term investment geared toward performance and
the lowering of customer well costs. These versatile rigs are of a type and design that is
capable of drilling in North Americas unconventional resource areas and in many other areas of
the world.
The U.S. drilling rig count is about three times larger than Canadas. At present, Precision is a
substantial Canadian oilfield service company and the dominant player with 29% and 23% of the
drilling and service rig markets, respectively. For Precision, the United States is an untapped
growth area that has been renewed by unconventional natural gas production. For the first time in
Precisions history, the company is working to establish permanent operations in the United
States, a market that today has approximately 2,300 drilling rigs. We are moving in this
direction even though we expect rig demand in the United States to moderate. If this occurs, we
believe that rigs with poor mobility and old components will find it difficult to compete. This
high grading of equipment plays into Precisions operational strategy.
Drilling and service rigs make up approximately 90% of Precisions revenue and have always been
the core business platform and areas of expertise for the company. Precision is planning to work
within core customer relationships to broaden market opportunities in North America. We are
focused on equipment that moves technology and processes forward to minimize costs and enable
customers to exploit the full oil and natural gas potential of their land holdings.
SUMMARY OF CONSOLIDATED STATEMENTS OF EARNINGS
(Stated in thousands of Canadian dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling Services |
|
$ |
1,009,821 |
|
|
$ |
916,221 |
|
|
$ |
727,710 |
|
Completion and Production Services |
|
|
441,017 |
|
|
|
369,667 |
|
|
|
313,386 |
|
Inter-Segment Elimination |
|
|
(13,254 |
) |
|
|
(16,709 |
) |
|
|
(12,608 |
) |
|
|
|
|
1,437,584 |
|
|
|
1,269,179 |
|
|
|
1,028,488 |
|
|
Operating earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling Services |
|
|
473,624 |
|
|
|
404,385 |
|
|
|
282,315 |
|
Completion and Production Services |
|
|
163,119 |
|
|
|
121,643 |
|
|
|
77,074 |
|
Corporate and Other |
|
|
(41,464 |
) |
|
|
(60,650 |
) |
|
|
(28,076 |
) |
|
|
|
|
595,279 |
|
|
|
465,378 |
|
|
|
331,313 |
|
|
Interest, net |
|
|
8,029 |
|
|
|
29,270 |
|
|
|
46,280 |
|
Premium on redemption of bonds |
|
|
|
|
|
|
71,885 |
|
|
|
|
|
Loss on disposal of short-term investments |
|
|
|
|
|
|
70,992 |
|
|
|
|
|
Other |
|
|
(408 |
) |
|
|
|
|
|
|
(4,899 |
) |
|
Earnings from continuing operations before income taxes |
|
|
587,658 |
|
|
|
293,231 |
|
|
|
289,932 |
|
Income taxes |
|
|
15,146 |
|
|
|
72,383 |
|
|
|
101,801 |
|
|
Earnings from continuing operations |
|
|
572,512 |
|
|
|
220,848 |
|
|
|
188,131 |
|
Discontinued operations, net of tax |
|
|
7,077 |
|
|
|
1,409,715 |
|
|
|
59,273 |
|
|
Net earnings |
|
$ |
579,589 |
|
|
$ |
1,630,563 |
|
|
$ |
247,404 |
|
|
For the year ended December 31, 2006, Precisions earnings from continuing operations were a
record $573 million or $4.56 per diluted unit compared to $221 million or $1.76 per diluted unit
in 2005. In the prior year, earnings from continuing operations were reduced by one-time charges
of $160 million or $1.04 per diluted unit, net of tax. The lower effective income tax rate as an
income trust and enacted tax rate reductions contributed an increase over the prior year of $1.21
per diluted unit. The remaining increase of $0.55 per diluted unit was due in large part to
pricing and activity strength in the first half of 2006. West Texas Intermediate (WTI) crude
oil averaged US$66.11 per barrel in 2006 versus US$56.49 in 2005 and Henry Hub natural gas
averaged US$6.73 per MMBtu in 2006 versus US$8.95 in 2005.
Natural gas prices in North America peaked in December 2005 at US$15.39 per MMBtu and declined to
about half that level by December 2006. There were 7% fewer wells (22,575) drilled in western
Canada from the record in 2005 and only the first quarter showed a year-over-year increase from
2005 drilling.
Despite a decline in wells drilled, the 158,416 industry operating days were slightly higher than
2005 and established a new record for Canadas drilling contractors. Deeper drilling and fewer
shallow gas and coal bed methane wells increased the average operating days per well by 8% from
6.5 to 7.0 in 2006.
Higher oil prices and lower gas prices prompted some customers to shift drilling dollars to oil
prospects in 2006
which led to the most oil completions since 1997. The increase in well licenses issued for oil
targets was not enough to offset a decline in conventional gas permits and an even bigger drop
for coal bed methane wells. Oil licenses reached 6,770, the most since 2000, while permits to
drill for gas declined 15% to 18,270.
The year ended on a weak note as the spot price for natural gas decreased amid concerns over high
gas storage levels and expectations of a warm winter in North America. Oil prices also retreated
in the fourth quarter from a record high in July but remained relatively strong. Henry Hub
natural gas spot prices ranged from a fourth quarter high of US$8.45 per MMBtu to a low of
US$3.62 on September 29, 2006, compared to a range of US$15.39 to US$8.79 in the same quarter of
the prior year. The one-year forward price for North American natural gas weakened to trade in a
range of approximately $6.50 to $8.50 on Canadian and U.S. exchanges in the quarter. During 2006,
the persistent downward trend in commodity prices, natural gas in particular, led to lower demand
in the fourth quarter for all of Precisions services in western Canada.
OUTLOOK
The oil and gas industry in Canada lost momentum as 2006 progressed after four years of
growth in operating and financial results. The hurricane devastation in the U.S. Gulf Coast in
September 2005 created a strong pricing environment for 2006 natural gas drilling activity,
however, a persistent downward trend in natural gas pricing adversely affected second half
activity levels in the WCSB. The backlog of drilling work quickly depleted and fourth quarter
activity was the lowest since 2002.
Fundamentally, we believe there is too much gas in storage in the short term and not enough
supply in the long term which should ultimately lead to a recovery in drilling activity.
Clearly, there is negative sentiment toward anticipated drilling levels in 2007. The year is
likely to yield far more uncertainty as companies reduce spending because lower cash flows in
conjunction with higher finding and development costs are undermining the economics of gas
drilling in the WCSB.
Increasingly, Precisions results are driven by the fundamentals for natural gas production and
consumption in North America. Moderate gas consumption during the past two winters has left
storage levels in the United States trending higher than the five-year average. This has caused
natural gas commodity prices to decline and generally customer cash flows have followed, with
significant declines reported in the fourth quarter of 2006 as compared to the fourth quarter of
2005. This downward trend has reduced drilling economics and many of Precisions large customers
with global operations have reduced their 2007 Canadian drilling budgets.
For 2007, the operating environment for Precision will be challenging. While customer pricing for
drilling rigs has held to begin the first quarter, there are signs of market deterioration. For
January and February 2007, industry gas well licensing in western Canada is down approximately
30% over 2006. In this same period, Precisions drilling and service rigs have been less active
by 19% and 15%, respectively. Customer pricing in the spot market for available equipment is
lower than winter 2006/2007 rates. The commissioning of previously announced new equipment will
increase industry capacity. With lower 2007 drilling budgets for many of Precisions large
customers, Precision will have a higher proportion of its drilling rig fleet available for spot
market work than it has had for the previous three years. Further, inflationary pressures from
Albertas strong economy and an active U.S. drilling industry are expected to increase operating
costs and maintenance capital expenditures per drilling operating day.
The shallow gas market was the most affected by the slowdown in activity but it also has the
potential to recover quickly in response to higher natural gas prices. Deeper drilling programs
tend to require more lead time and will typically react more slowly to a recovery in commodity
prices.
Drilling activity trends influence well completion work and commodity prices influence the
servicing or workover of existing oil and natural gas wells in production. For Precisions
service rigs in 2007, reduced drilling rig activity is expected to lower completion work. Early
indications are that workovers for conventional oil and heavy oil wells are reasonably firm,
however, Precision does not expect this to be enough to compensate for lower activity for
producing gas wells.
As of March 9, 2007, the supply and demand fundamentals for North American natural gas are
beginning to show
cause for optimism. Winter consumption of gas over the first two months of 2007 has lowered
United States natural gas storage from prior year levels by approximately 10%. The AECO spot
price for Alberta natural gas was 18% higher than a year ago at $7.44 per Mcf and the NYMEX
12-month strip natural gas price of US$8.09 was essentially flat.
While these developments are positive, Precision believes it will take time for its customers to
realize higher cash flows and increase their drilling and well servicing expenditures over prior
year levels. Looking ahead, high natural gas consumption for summer cooling, weather related
natural gas supply disruptions in the Gulf of Mexico and a slowing of U.S. gas drilling could
have a favourable impact on natural gas commodity prices and result in higher Canadian drilling
activity. To the extent that these events are unfavourable, the increasing rate of decline for
new producing wells in North America lowers the supply of gas and eventually should result in
higher drilling activity.
Precision remains positive on the medium to long term fundamentals for the North American onshore
drilling industry. With a strategy to broaden its market presence and diversify into the United
States, Precision intends to deploy rigs from its Canadian fleet for core customers to the major
producing basins.
As producers struggle to increase output and growth in oil and gas consumption exceeds new
supply, capital spending cutbacks will have a material impact on field productivity and set the
stage for recovery. With a recovery as early as winter 2007/2008, a continuing trend in deep
natural gas plays and expanding in-situ oil sands development, Precision is well positioned with
its large, versatile fleet of rigs and support services.
DYNAMICS OF THE OILFIELD SERVICES INDUSTRY
Through this report, management is presenting its views of Precisions business and the
industry in which it operates. Understanding the oil and gas industry and the factors that impact
demand for oilfield services is important to assess Precisions long-term strategy,
opportunities, financial performance and distribution potential.
GLOBAL MARKETS
For more than a century, global economic growth and prosperity has been largely driven by
energy consumption. In that time, crude oil and natural gas have proven to be the cheapest and
most versatile sources of energy. Oil and its by-products provide fuel for virtually all of the
worlds automobiles while oil and natural gas are primary fuel sources for generating heat and
electricity and are critical building blocks for countless consumer products.
With 6 billion people worldwide and the population expected to rise by another 1.5 billion in the
next 20 years, global energy demand is unprecedented and rising. Energy consumption is predicted
to rise 50% to 60% by 2030, as illustrated below, with oil, natural gas and coal meeting
approximately 80% of demand. World oil consumption is predicted to rise 1.6% in 2007 due largely
to growing demand in China, India and other developing countries. Delivering reliable and
affordable energy for these fast-growing and upwardly mobile populations is one of the major
challenges society faces in this century.
There is growing concern about the connection between burning fossil fuels and climate change. In
February 2007, the United Nations Intergovernmental Panel on Climate Change reiterated calls for
action on fossil fuel consumption citing the links to hotter temperatures and rising sea levels.
As environmental concerns over carbon dioxide emissions increase, natural gas becomes a more
appealing fuel choice, particularly for electricity generation as it is less carbon intensive
than traditional fuel sources such as coal. Despite the environmental challenges, crude oil and
natural gas are the worlds primary energy sources. History has proven it takes decades, if not
centuries, to displace energy sources and hydrocarbon production will remain crucial to the
worlds energy needs for the foreseeable future.
NORTH AMERICAN MARKETS
Economics of the oilfield service industry are aligned with global and regional fundamentals.
Important regional drivers for the industry in Canada include the underlying hydrocarbon make-up
of the WCSB and the existence of an established, competitive and efficient service
infrastructure. Natural gas production increasingly drives
economics in the WCSB as approximately 70% of new well completions in 2006 targeted natural gas.
Drilling activity in the WCSB is split between the provinces with approximately 75% in Alberta,
15% in Saskatchewan and 10% in British Columbia. Areas of Canadas north hold significant future
promise but remain largely untapped frontier opportunities pending government and community
support.
The hydrocarbon structure of the WCSB is diverse. Conventional oil and natural gas reservoirs
exist at a variety of depths which are comparatively shallow by global standards. These
conventional sources are accompanied by more costly and challenging unconventional reservoirs
associated with oil sands, heavy oil, coal bed methane and natural gas in deeper, low
permeability formations.
A vast natural resource base and next-door proximity to the worlds biggest energy consumer have
helped Canada to become the worlds eighth largest oil producer and third largest producer of
natural gas. With oil sands development, Canada is one of the few countries with growing
petroleum production.
A highly integrated continental energy transportation system and free-market access to U.S.
markets has made Canada one of the largest energy providers to the United States. Approximately
half of Canadian oil and gas production is exported to the United States.
ECONOMIC DRIVERS OF THE OILFIELD SERVICES BUSINESS
Providing oil and natural gas products to consumers involves a number of players, each taking
on different risks in the exploration, production, refining and distribution processes.
Exploration and production companies, Precisions customers, assume the risk of finding
hydrocarbons in reservoirs of sufficient size to economically develop and produce. The economics
are dictated by the current and expected future margin between the cost to find and develop
hydrocarbons and the eventual price of these products. The wider the margin, the greater the
incentive to undertake these risks.
Exploration and development activities include acquiring access to prospective lands, seismic
surveying to detect hydrocarbon bearing structures, drilling wells and completing successful
wells for production. Exploration and production companies hire oilfield service companies to
perform the majority of these jobs. The revenue for an oilfield service company is part of the
finding and development costs for an exploration and production company.
The economics of an oilfield service company are largely driven by the price of crude oil and
natural gas realized by its customers. Since oil can be transported relatively easily, it is
priced in a global market influenced by an array of economic and political factors. Natural gas
is priced in continental markets due to restrictions on overseas transportation capabilities.
The emergence of liquefied natural gas (LNG) is an important new source of supply to North
America that could offset production declines from mature reservoirs and help meet rising gas
demand. There are still technical, political and environmental challenges for significant LNG
developments to occur in North America, but it is widely projected to be a necessary source of
supply as demand for natural gas increases.
Over the past two years, rising demand, tight supply and concern over political and weather
factors disrupting supply have driven commodity pricing to record levels. The dramatic price rise
over a relatively short period has created uncertainty over the sustainability of high cash flows
in the industry. Cash flows are critical to replacing production in the upstream sector.
Oil prices, which rose above US$78 per barrel in July 2006, are impacted by global factors such
as worldwide economic growth, political and social unrest in major producing regions, global
weather patterns, policies of the Organization of Petroleum Exporting Countries, commodity market
speculation and industrialization in developing countries.
Natural gas, which peaked in North America at US$15.39 per MMBtu in December 2005, is impacted by
factors such as regional economic activity, oil prices, commodity market speculation and, most
significantly, the severity of weather in the major population centres across North America.
There is currently a narrow supply-demand balance. Many industry observers believe a new pricing
floor is being
set due to the combination of production declines and demand growth. New hydrocarbon reserves are
clearly more costly and difficult to discover and develop. It has taken record drilling activity
over the last three years in North America to maintain overall natural gas production levels. The
following illustration demonstrates declines in WCSB new well productivity.
The graph for western Canada above suggests more wells will be required to meet supply needs. In
the WCSB, incremental new gas well production has decreased with the development of shallow gas
reservoirs. With record drilling in the last two years (17,769 gas wells in 2005 and 15,640 in
2006) new gas wells only produced an average 215 Mcf per day in 2006 compared with 740 Mcf per
day in 1996. In the 1990s the industry drilled approximately 10,000 wells per year in Canada. In
this decade the number of wells has averaged approximately 20,000 per year. Natural gas drilling
represented approximately 38% of the wells drilled in the 1990s compared to 67% of the wells
drilled in the current decade.
Onshore North America is characterized by mature conventional oil and natural gas basins that
require substantial activity to maintain or enhance production.
Rising energy demand coupled with depletion of conventional resource basins has created an
historic shift in the oil and gas industry in North America to develop unconventional resources
such as oil sands, natural gas in shale and coal bed methane. Unconventional reservoirs tend to
be more challenging and expensive to develop than conventional oil and gas reservoirs and
generate more service activity. The biggest unconventional resource in Canada is the estimated
179 billion barrels of oil reserves in northern Albertas oil sands. There are also large
reserves of coal bed methane and shale gas in Canada and the United States. The economics of
unconventional resource plays require significant dependence upon technology such as multi-well
pad locations, slant drilling rigs and advanced reservoir stimulation techniques.
Reserves to production ratios, which indicate how quickly reserves are depleting, have flattened
after a period of decline starting in the 1990s. The result is drilling activity must stay level
or increase just to maintain current production and it is leading producers to drill deeper
resource plays looking for large gas fields to extend reserve life.
The graph above depicts the increase in natural gas completions over the past 10 years and the
correlation to gas pricing. Two successive mild winters have led to high levels of gas in storage
and a corresponding decline in price.
With growing energy demand, the supply of drilling rigs in Canada increased steadily over the
past 13 years to an all-time high of approximately 850. Customer demand, measured by drilling rig
operating day utilization, peaked at 71% in 1997 and has since ranged between 38% and 60%.
Industry utilization was 55% for 2006. Higher utilization levels in 2005 and early 2006 prompted
drilling contractors to add rigs. Many of the new rigs are telescopic doubles, singles or hybrid
coil tubing rigs which are geared to shallow drilling and peak winter demand. In the long term,
the larger fleet provides capacity to drill more wells through better year-round utilization. In
order to sustain an industry operating day utilization rate of 55%, assuming seven operating days
per well and 850 available rigs, there would need to be almost 24,500 wells drilled in the WCSB
in 2007. The CAODC is currently estimating that only 19,023 wells will be drilled in 2007.
Approximately 72 drilling rigs were added to the Canadian fleet during 2006, a 9% increase to the
total. Despite market softness expected for much of 2007, long-term customer demand to drill
conventional oil and gas wells, in combination with improving commercialization of coal bed
methane, oil sands and tight gas formations will drive future rig demand.
Just as natural gas is a North American commodity so too are drilling rigs. Many rigs are able to
work in Canada or the United States and it is notable that the Canadian drilling rig count is at
an all time high and the U.S. rig count is approximately half the capacity of the early 1980s. As
illustrated above, Canadian rig activity fluctuates with the seasons, a phenomenon which
generally does not occur in the United States.
PRECISIONS DEVELOPMENT
PRECISIONS HISTORY OF CONTINUING OPERATIONS
Precisions history began in western Canada as a land drilling contractor in the 1950s.
Through a series of acquisitions over the years, along with organic growth in its service lines,
Precision has established itself as Canadas largest oilfield services provider.
Precision Drilling Corporation was founded in 1985 as Cypress Drilling Ltd. and grew from four
drilling rigs to 19 with the reverse takeover in 1987 of Precision Drilling Ltd., the company
originally formed in 1952.
In the decade following the takeover, a series of acquisitions expanded Precisions Canadian
drilling fleet to 106 rigs. With the acquisition of Kenting Energy Services Inc. in 1997,
Precision essentially doubled its fleet to 200 rigs representing approximately 40% of the
drilling fleet in Canada. The acquisitions of coil tubing drilling rigs and other shallow
drilling rigs in 2000 rounded out the drilling rig fleet. Today, after strategic new rig builds
and decommissioning, Precisions 240 drilling rigs in Canada comprise approximately 29% of the
market.
To support the expanded rig fleet Precision acquired a number of complementary businesses. In
1993, Precision entered the camp and catering business with the acquisition of LRG Oilfield
Services Ltd. Along with camps from the drilling rig business acquisitions and the purchase in
2003 of McKenzie Caterers (1984) Ltd., this division now has 101 camps. In 1996, Precision added
in-house capabilities for the design, fabrication and maintenance of rig components with the
acquisition of Rostel Industries Ltd. The acquisitions of Columbia Oilfield Supply Ltd. and a
number of other oilfield equipment companies followed in 1997.
Diversification into businesses that would become Precision Well Servicing, Live Well Service and
Precision Rentals began in 1996 with the acquisition of EnServ Corporation that set the stage for
a broadened asset base and future growth. In 2000, Precision became fully vested in the Canadian
service rig business with the acquisition of CenAlta Energy Services Inc. to create a combined
fleet of 257 service rigs and an industry-leading market share of 28%. Today, Precision has 237
service rigs and 26 snubbing units that account for approximately 23% and 30% of their respective
markets. Through additional acquisitions in the late 1990s the rental businesses grew and in 2002
were combined and branded as Precision Rentals. In 2006, Precision expanded into the business of
remote work site wastewater treatment with the acquisition of Terra Water Group Ltd.
STRATEGIC DIRECTION
Precision is tightly integrated in terms of operations, safety, engineering, information
technology, accounting and senior management. Each segment has experienced asset growth and
performs a lead market role. Communication is a skill that has been refined and ingrained in
Precisions operating culture while continuously focusing on safety initiatives to eliminate
workplace incidents. These attributes provide Precision with the ability to pursue the following
strategic initiatives as key factors in maximizing the value proposition for its unitholders:
|
|
maintain a flexible business that is responsive to market conditions; |
|
|
exploit technological advances where markets dictate; |
|
|
focus on organic growth opportunities to enhance and diversify service offerings; |
|
|
capitalize on strategic and accretive acquisitions both geographically and operationally; |
|
|
develop and enhance employee safety, recruitment and retention initiatives; |
|
|
upgrade equipment with customer needs and regulatory requirements in mind; and |
|
|
apply operational and financial discipline throughout all areas of the business. |
KEY PERFORMANCE DRIVERS
Customer economics are dictated by the current and expected margin between the price at which
hydrocarbons are sold and the cost to find and develop those products. Some of the key business,
customer and industry indicators that Precision focuses on to monitor its performance are:
Commodity Prices: Precision monitors the spot and forward prices for oil and
natural gas as these prices impact customer cash flow and funds for capital programs which govern
land acquisition, well licensing and future drilling,
and well servicing activities.
Customer Demand: Precision matches the availability of its equipment with customer
budgets and drilling programs. Precisions fleet is geographically dispersed to meet customer
demands. Relationships with its customers, industry knowledge and new well licenses provide
Precision with the necessary information to evaluate its marketing strategies. Industry rig
utilization statistics are tracked to evaluate Precisions performance against competitors.
Workforce: Precisions employees are its most important asset. Precision closely
monitors crew availability for field operations. Precision focuses on initiatives that provide a
safe and productive work environment, opportunity for advancement and added wage security through
programs to retain employees. Target Zero reinforces Precisions safety vision and safety
statistics are used to benchmark its performance. Precision relies heavily on its safety record
to attract new employees.
Operating Efficiency: Precisions revenue is a component of an oil and gas
companys finding and development costs. Precision maximizes the efficiency of its operations
through its proximity to work sites, its operating practices and its versatility. Precisions
reliable and well maintained equipment minimizes downtime during operations. These factors
contribute to lower customer well costs.
Financial Performance: Precision maximizes revenue without sacrificing operating
margins. Key financial information is unitized on a per day or per hour basis and compared to
established benchmarks and past performance. Precision evaluates the relative strength of its
financial position by monitoring its working capital and debt ratios. Low debt levels have
allowed Precision to manage the cyclical nature of the industry and provide the financial
leverage to invest in meaningful growth opportunities.
Expansion Capital Spending: Precision evaluates growth opportunities based on
internally established rate of return targets. New drilling rig expansion is typically based on
predetermined activity levels over a fixed term operating contract.
OPERATING SEGMENTS
Precision is divided into two operating segments to effectively manage its business, Contract
Drilling Services and Completion and Production Services.
The Contract Drilling Services segment is comprised of the following:
|
|
Precision Drilling which provides land drilling services utilizing 240 drilling rigs,
approximately 29% of the Canadian industry; |
|
|
|
Precision Drilling Oilfield Services, Inc. which provides land drilling services in the United
States and established operations in June 2006 with one rig; |
|
|
|
LRG Catering which supplies camp and catering services with 101 camps, approximately 16% of the
industry; |
|
|
|
Rostel Industries which provides engineering, machining, fabrication, component manufacturing
and repair services for drilling and service rigs; and |
|
|
|
Columbia Oilfield Supply which provides centralized procurement, standardized product
selection, and coordinated distribution of goods for Precisions operations. |
|
The Completion and Production Services segment is comprised of the following: |
|
|
|
Precision Well Servicing which provides well completions and workovers with 237 rigs,
approximately 23% of the industry service rigs; |
|
|
|
Live Well Service which performs well completions and workovers with 26 snubbing units,
approximately 30% of the industry; |
|
|
|
Precision Rentals which supplies approximately 15,000 rental equipment items including well
control equipment, surface equipment, specialty tubulars and wellsite accommodation units
representing approximately 10% of the
industry; and |
|
|
Terra Water Systems Limited Partnership which operates 51 wastewater treatment units,
representing approximately 10% of the industry. |
Precision Drilling
The following table lists the drilling depth capability of Precisions and industrys
Canadian drilling rigs in the WCSB as at December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Precision Fleet |
|
|
Industry Fleet(1) |
|
|
|
Maximum |
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
Depth Rating |
|
|
Number |
|
|
% of |
|
|
Market |
|
|
Number |
|
|
% of |
|
|
|
|
Type of Drilling Rig |
|
(metres) |
|
|
of Rigs |
|
|
Total |
|
|
Share (3) |
|
|
of Rigs |
|
|
Total |
|
|
Change(4) |
|
|
Single |
|
|
1,200 |
|
|
|
14 |
|
|
|
6 |
|
|
|
10 |
|
|
|
145 |
|
|
|
17 |
|
|
|
21 |
|
Super SingleTM (2) |
|
|
3,000 |
|
|
|
28 |
|
|
|
12 |
|
|
|
85 |
|
|
|
33 |
|
|
|
4 |
|
|
|
9 |
|
Double |
|
|
3,000 |
|
|
|
94 |
|
|
|
39 |
|
|
|
26 |
|
|
|
364 |
|
|
|
43 |
|
|
|
20 |
|
Light triple |
|
|
3,600 |
|
|
|
44 |
|
|
|
18 |
|
|
|
38 |
|
|
|
117 |
|
|
|
14 |
|
|
|
3 |
|
Heavy triple |
|
|
6,700 |
|
|
|
49 |
|
|
|
20 |
|
|
|
42 |
|
|
|
118 |
|
|
|
14 |
|
|
|
11 |
|
Coiled tubing |
|
|
1,500 |
|
|
|
11 |
|
|
|
5 |
|
|
|
17 |
|
|
|
65 |
|
|
|
8 |
|
|
|
8 |
|
|
Total |
|
|
|
|
|
|
240 |
|
|
|
100 |
|
|
|
29 |
|
|
|
842 |
|
|
|
100 |
|
|
|
72 |
|
|
|
|
|
(1) |
|
Source: Daily Oil Bulletin Rig Locator Report as of January 2007. Precision has
allocated the industry rig fleet by rig type.
|
|
(2) |
|
Super SingleTM excludes single rigs that do not have automated pipe-handling systems, or do
not have a self-contained top drive, or cannot run range 3 drill pipe/casing. |
|
(3) |
|
Market share means Precisions rigs as a percent of the industrys rigs. |
|
(4) |
|
Change in number of industry rigs as compared to the prior year. |
The table below summarizes the capabilities of Precision Drillings North American drilling
rig fleet for the past four years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum Depth Rating |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type of Drilling Rig |
|
Metres |
|
|
Feet |
|
|
Horsepower |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
Single |
|
|
1,200 |
|
|
|
4,000 |
|
|
|
250-300 |
|
|
|
14 |
|
|
|
17 |
|
|
|
16 |
|
|
|
18 |
|
Super SingleTM |
|
|
3,000 |
|
|
|
10,000 |
|
|
|
400-600 |
|
|
|
29 |
|
|
|
21 |
|
|
|
21 |
|
|
|
15 |
|
Double |
|
|
3,000 |
|
|
|
10,000 |
|
|
|
300-500 |
|
|
|
94 |
|
|
|
94 |
|
|
|
95 |
|
|
|
96 |
|
Light triple |
|
|
3,600 |
|
|
|
12,000 |
|
|
|
500-750 |
|
|
|
44 |
|
|
|
44 |
|
|
|
45 |
|
|
|
47 |
|
Heavy triple |
|
|
6,700 |
|
|
|
22,000 |
|
|
|
1,000-2,000 |
|
|
|
49 |
|
|
|
43 |
|
|
|
41 |
|
|
|
39 |
|
Coiled tubing |
|
|
1,500 |
|
|
|
5,000 |
|
|
|
250-300 |
|
|
|
11 |
|
|
|
11 |
|
|
|
11 |
|
|
|
10 |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
241 |
|
|
|
230 |
|
|
|
229 |
|
|
|
225 |
|
|
Precision Well Servicing
The configuration of Precision Well Servicings Canadian fleet for the past four years is illustrated in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type of Service Rig |
|
Horsepower |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
Singles: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mobile |
|
|
150-400 |
|
|
|
12 |
|
|
|
17 |
|
|
|
19 |
|
|
|
30 |
|
Freestanding mobile |
|
|
150-400 |
|
|
|
92 |
|
|
|
88 |
|
|
|
86 |
|
|
|
75 |
|
Doubles: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mobile |
|
|
250-550 |
|
|
|
44 |
|
|
|
44 |
|
|
|
42 |
|
|
|
46 |
|
Freestanding mobile |
|
|
200-550 |
|
|
|
9 |
|
|
|
8 |
|
|
|
9 |
|
|
|
6 |
|
Skid |
|
|
300-860 |
|
|
|
65 |
|
|
|
65 |
|
|
|
67 |
|
|
|
66 |
|
Slants: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Freestanding |
|
|
250-400 |
|
|
|
15 |
|
|
|
15 |
|
|
|
16 |
|
|
|
16 |
|
|
Total |
|
|
|
|
|
|
237 |
|
|
|
237 |
|
|
|
239 |
|
|
|
239 |
|
|
CAPACITY TO DELIVER
Precision is a major supplier of services to oil and gas companies and its success is
dependant on providing a complement of oilfield services that are cost effective to its
customers. Precision prides itself on providing quality equipment operated by highly experienced
and well trained crews. Maintaining customer relationships is fundamental to Precisions success
and based in large part upon the ability to deliver.
Large Diversified Rig Fleets
Precisions large diverse fleet of rigs is strategically deployed across the most active
regions of the WCSB. When an oil and gas company needs a specific type and size of rig in a given
area, there is a high likelihood that a Precision rig will be readily available. Geographic
proximity and fleet versatility make Precision a premium service provider.
Precisions drilling rigs have varying configurations and capabilities, with drilling depth
capacities of up to 6,700 metres. Rig categories where Precision dominates correlate well with
future drilling opportunities. Deeper depth rigs target foothills natural gas, while Super
SingleTM rigs are effective in shallow to medium depths including oil sands and heavy oil
drilling.
Precisions service rigs provide completion, workover, abandonment, well maintenance, high
pressure and critical sour well work and well re-entry preparation across the WCSB. The rigs are
supported by three field locations in Alberta, two in Saskatchewan and one in British Columbia.
Snubbing complements traditional natural gas well servicing by allowing customers to work on
wells while they are pressurized and production has been suspended. Precision has two types of
snubbing units rig assist and stand alone. Stand alone units do not require a service rig on
site and are capable of snubbing and performing many other well servicing procedures.
Inventory of Ancillary Equipment
Precision has a large inventory of equipment, including portable top drives, loaders,
boilers, tubulars and well control equipment, to support its fleet of drilling and service rigs
to meet customer requirements. Precision also maintains an inventory of key rig components to
minimize downtime due to equipment failures.
In support of drilling rig operations, LRG Catering supplies meals and provides accommodation for
rig crews at remote worksites. Terra Water Systems plays an essential role in providing
wastewater treatment services for LRG Catering and other camp facilities. Precision Rentals
supplies customers with an inventory of 15,000 pieces of specialized equipment and wellsite
accommodations.
Industry-leading Safety Program
Safety is critical for Precision and its customers. In 2006, almost 300 rigs and four
Precision business units achieved Target Zero, Precisions safety vision for eliminating
workplace incidents. Precision is a leader in adopting technological advancements which have made
drilling rigs, service rigs and snubbing units safer.
Well-maintained Equipment
Precision consistently reinvests capital to sustain and upgrade existing property, plant and
equipment its productive capacity maintenance.
In addition to capital expenditures as illustrated above, equipment repair and maintenance
expenses are benchmarked to activity levels in accordance with Precisions maintenance and
certification programs. Precision employs computer technology to track key preventative
maintenance indicators for major rig components to record equipment performance history, schedule
equipment certifications, reduce downtime and allow for better asset management.
Precision benefits from internal services for equipment certifications and component
manufacturing provided by Rostel Industries and for standardization and distribution of
consumable oilfield products through Columbia Oilfield Supply.
Employees
As a service company, Precision is only as good as its people. An experienced, competent crew
is a competitive strength and highly valued by customers. To recruit rig employees, Precision has
centralized personnel departments and orientation and training programs.
Information Systems
Precisions commitment to invest in a fully integrated enterprise-wide accounting system has
improved business performance through real-time access to information across all functional areas
of the company. All divisions operate on a common integrated system using standardized business
processes across finance, payroll, equipment maintenance, procurement and inventory control.
FINANCIAL RESULTS
CONTRACT DRILLING SERVICES SEGMENT
(Stated in thousands of Canadian dollars, except where indicated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of |
|
|
|
|
|
|
% of |
|
|
|
|
|
|
% of |
|
Years ended December 31, |
|
2006 |
|
|
Revenue |
|
|
2005 |
|
|
Revenue |
|
|
2004 |
|
|
Revenue |
|
|
Revenue |
|
$ |
1,009,821 |
|
|
|
|
|
|
$ |
916,221 |
|
|
|
|
|
|
$ |
727,710 |
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
470,713 |
|
|
|
46.6 |
|
|
|
448,930 |
|
|
|
49.0 |
|
|
|
382,886 |
|
|
|
52.6 |
|
General and administrative |
|
|
27,225 |
|
|
|
2.7 |
|
|
|
23,911 |
|
|
|
2.6 |
|
|
|
19,190 |
|
|
|
2.6 |
|
Depreciation |
|
|
38,573 |
|
|
|
3.8 |
|
|
|
39,233 |
|
|
|
4.3 |
|
|
|
42,245 |
|
|
|
5.8 |
|
Foreign exchange |
|
|
(314 |
) |
|
|
|
|
|
|
(238 |
) |
|
|
|
|
|
|
1,074 |
|
|
|
0.2 |
|
|
Operating earnings (1) |
|
$ |
473,624 |
|
|
|
46.9 |
|
|
$ |
404,385 |
|
|
|
44.1 |
|
|
$ |
282,315 |
|
|
|
38.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Increase |
|
|
|
|
|
|
% Increase |
|
|
|
|
|
|
% Increase |
|
|
|
2006 |
|
|
(Decrease) |
|
|
2005 |
|
|
(Decrease) |
|
|
2004 |
|
|
(Decrease) |
|
|
Number of drilling rigs (end of year) |
|
|
241 |
|
|
|
4.8 |
|
|
|
230 |
|
|
|
0.4 |
|
|
|
229 |
|
|
|
1.8 |
|
Drilling operating days |
|
|
44,938 |
|
|
|
(4.3 |
) |
|
|
46,937 |
|
|
|
12.8 |
|
|
|
41,625 |
|
|
|
(1.5 |
) |
Drilling revenue per operating day ($/day) |
|
|
20,518 |
|
|
|
13.8 |
|
|
|
18,034 |
|
|
|
9.3 |
|
|
|
16,494 |
|
|
|
11.5 |
|
Drilling statistics: (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of wells drilled |
|
|
6,180 |
|
|
|
(20.4 |
) |
|
|
7,766 |
|
|
|
3.2 |
|
|
|
7,525 |
|
|
|
(11.0 |
) |
Average days per well |
|
|
7.2 |
|
|
|
20.0 |
|
|
|
6.0 |
|
|
|
9.1 |
|
|
|
5.5 |
|
|
|
10.0 |
|
Number of metres drilled (000s) |
|
|
7,810 |
|
|
|
(12.3 |
) |
|
|
8,901 |
|
|
|
11.0 |
|
|
|
8,021 |
|
|
|
(6.8 |
) |
Average metres per well |
|
|
1,264 |
|
|
|
10.3 |
|
|
|
1,146 |
|
|
|
7.5 |
|
|
|
1,066 |
|
|
|
4.7 |
|
|
|
|
|
(1) |
|
Non-GAAP measure. See page 66. |
|
(2) |
|
Canadian operations only. |
2006 Compared to 2005
The Contract Drilling Services segment, in 2006, generated record financial results on
the strength of improved pricing and the third highest total drilling days in company history.
Revenue increased by $94 million or 10% over 2005 to $1.0 billion while operating earnings
increased by $69 million or 17% to $474 million. Operating earnings increased to 47% of revenue
in 2006 as compared to 44% in 2005. The operating earnings margin increase was primarily
attributable to pricing established in the fourth quarter of 2005 and other pricing increases
which held throughout 2006.
Operating costs declined from 49% of revenue in 2005 to 47% in 2006. On a per operating day
basis, costs increased slightly due to higher crew wages and cost of materials. Lower equipment
utilization increased the per operating day cost associated with fixed operating cost components.
Variable costs are controlled through extensive analysis and cost awareness. This combined with
the ability to mitigate cost escalations through volume purchasing and relationships with
suppliers further enhanced profitability.
The momentum in activity that started to build at the beginning of the third quarter of 2005
continued through the winter drilling season and the start of the 2006 spring break-up. The first
half of 2006 was one of the strongest drilling periods on record for the WCSB. However, a
persistent downward trend in the natural gas price over the second half of 2006 adversely
affected activity levels as the backlog of drilling work quickly depleted and the fourth quarter
saw the lowest fourth quarter activity since 2002.
Activity for drilling rigs was down 1,999 operating days, a 4% decline from the prior year. The
first half of 2006 showed increases in drilling levels over 2005 with the third quarter only
marginally lower due largely to wet weather in September. At the end of the third quarter,
Precision was on track to surpass the record drilling activity established in 1997. That would
not happen, however, as operators rig released only 5,484 wells in the final quarter of 2006,
down 25% from a year earlier.
The decline in natural gas prices contributed to lower active rig counts in the second half of
2006 compared with 2005. Coupled with the expanded industry fleet of 9%, to approximately 842 at
year end, the drilling rig operating day utilization fell to 43% in the fourth quarter of 2006
from 68% in the same period of 2005.
During the year, Precision commenced operations in the U.S. land based contract drilling market.
In June, Rig 297 was mobilized from the Canadian fleet to Texas to begin work under contract.
Capital expenditures for the Contract Drilling Services segment in 2006 were $220 million and
included $158 million to grow and expand the underlying asset base and $62 million to sustain and
upgrade existing equipment. The majority of the expansion capital expenditure was associated with
new drilling rig construction.
The Precision Drilling division set new financial benchmarks in 2006. Revenue increased
by $73 million or 9% over 2005 to $919 million. The decrease in activity for 2006 was more than
offset by increased rates. Precision commenced 2006 with 170 rigs drilling as operators shortened
the Christmas shutdown period to get an early start on winter drilling programs. The first
quarter provided the industry with ideal winter drilling conditions as cool temperatures kept the
frost in the ground but it was not cold enough to hinder field operations. This unprecedented rig
demand and near perfect weather conditions provided an excellent start to the year.
Cold weather in the latter part of March 2006 prolonged the winter drilling season. This enabled
rigs to spud late in March and allowed deeper-rated rigs to work into the spring. The first sign
of a slowing shallow gas market appeared in the second quarter, particularly with coil tubing and
single rigs in southeastern Alberta. The demand for triples was able to offset the shortfall in
shallow gas drilling as operating days in the second quarter reached the third highest level in
the last 10 years. The triple rig activity in the second quarter was more than 50% higher than
the prior year. Strength in the triple rig market at that time reflected customer commitment to
deeper gas drilling.
Warm dry weather in western Canada in the third quarter allowed drilling operations to run as
scheduled for most of the summer allowing the backlog of wells to be drilled. Drilling days for
July and August were 169 days ahead of the previous years pace going into September 2006. Wet
weather in September reduced the rig count and dampened drilling momentum. Precision still
reported its third highest activity level in any third quarter in the last 10 years.
Fourth quarter 2006 results were hampered by activity declines attributable to commodity price
uncertainties and constraints on customers 2006 exploration and production budgets. Rising costs
and lower cash flows meant many customers had spent their entire 2006 budget by the start of the
fourth quarter and they did not move 2007 drilling programs forward. The urgency to put rigs to
work diminished as cautious spending developed despite increased rig availability.
Operating earnings in the Precision Drilling division increased by 17% over 2005 due mainly to a
14% increase in the average rate offset by a 5% decline in activity. Depreciation expense for the
year was $3 million higher due to the change in rig mix in the year with increased deep rig
activity and new rig builds going into the field. Precision Drillings cost per operating day
increased by 7% mainly due to hourly crew labour rate increases in October 2005 and 2006 of 7%
and 4%, respectively. There were also cost escalations for third party labour and materials
associated with equipment maintenance programs. An important component of the success of the
division is the degree to which cost structures were developed to be as variable as possible with
activity levels. This flexibility allowed the division to respond quickly to sudden changes in
equipment utilization and produce superior returns in periods of high or low activity.
The Precision Drilling division continued its organic growth strategy with the addition of 13
versatile rigs backed by customer arrangements. Precision spent $203 million in capital
expenditures in 2006, close to twice the spending in 2005.
LRG Catering achieved a new record for activity and revenue in 2006. Activity grew by
11%, while revenue increased 25% due in part to rate increases implemented in the fourth quarter
of 2005. Over the first eight months of 2006 activity remained at record levels then slowed in
the last four months as commodity prices softened and deeper drilling programs were completed.
LRG experienced a higher average day rate as a result of increased base camp activity. LRG is
becoming a larger drilling camp and catering provider in western Canada, having expanded its
fleet by 10 camps in 2006 to end the year with 101, representing about 16% of the market in
western Canada.
Rostel Industries and Columbia Oilfield Supply divisions provided valuable support,
best measured by the efficiencies and contributions made to Precision through cost savings.
Rostels expertise provided Precision control over rig construction and enhanced cost control.
Columbia is an essential extension of the purchasing process and provided timely, reliable and
consistent quality supplies to keep Precisions rigs operating and allowed Precision to
standardize product use and quality.
Precision Drilling Oilfield Services, Inc. began operations in the United States in
June 2006, with one rig. The rig was active 100% of the time. Growth is planned in the U.S.
market through the construction of new rigs and by deploying additional rigs from Canada through
customer arrangements.
2005 Compared to 2004
The Contract Drilling Services segment generated record financial results in 2005 on
the strength of unprecedented drilling activity in western Canada and improved pricing for
related services. The rise in activity strengthened on a comparative quarterly basis year over
year for the prior three years. That demand enabled the Contract Drilling Services segment to
steadily increase revenue and underlying operating margins.
The segment reported revenues of $916 million, $189 million more than 2004, an increase of 26%.
These results were generated with an equipment fleet size that was relatively unchanged from the
prior year. Revenue growth in 2005 was due to a combination of increased activity and pricing.
Operating earnings increased by $122 million or 43% to $404 million. Operating earnings increased
to 44% of revenue in 2005 as compared to 39% in 2004. The margin increase was primarily
attributable to pricing improvements.
Operating expenses declined from 53% of revenue in 2004 to 49% in 2005, and on a per operating
day basis, remained flat despite crew wage rate increases. Higher equipment utilization lowered
the daily cost associated with fixed operating cost components.
Capital expenditures for the Contract Drilling Services segment in 2005 were $107 million and
included $54 million to expand the underlying asset base and $53 million to sustain and upgrade
existing equipment. The majority of the expansion capital expenditure was associated with new
drilling rig construction.
For the Precision Drilling division revenue increased by $160 million or 23% over 2004
to $846 million. Just over half of the revenue growth was due to increased activity and the
remainder to increased rates. The division entered the year with great anticipation as rig demand
exceeded rig availability by a wide margin. Disappointing activity results for the first half of
the year were strictly weather related. These activity levels caused customer drilling programs
to fall behind. As ground conditions dried in July, the impact of the pent-up demand led to an
outstanding third and fourth quarter in 2005.
Rig demand continued to build momentum through to the end of 2005. Overall, the industry
benefited from the pricing leverage established from strong third quarter activity. Accordingly,
increased pricing was established in the fourth quarter for the winter drilling season. Rig
shortages also created a large spot market for operators who did not have equipment booked for
the winter, enabling the division to raise rates.
Operating earnings for the Precision Drilling division increased by 46% due in part to the 13%
increase in operating activity combined with the 9% increase in revenue per operating day.
Depreciation expense for the year was $11 million lower due to the effects of a change in the
estimated life of rig assets to 5,000 utilization days in 2005 from 4,150 in 2004. Precision
Drilling was able to maintain its cost per operating day at its 2004 rate. Crew labour costs in
2005 comprised 52% of operating costs, up 2% from 2004. The 2005 cost of drilling, maintenance
and overhead on a per day basis was consistent with 2004.
In the fourth quarter, two Super SingleTM Light rigs were added to the fleet and one rig was sold
resulting in a rig count of 230 at the end of 2005.
LRG Catering experienced a 26% increase in camp days and a 40% increase in revenue over
the prior year. The growing number of field personnel in the industry put overwhelming pressure
on other accommodation sources, such as hotels. Customers compensated by utilizing camps in areas
where crews would normally have returned to town for lodging. LRG grew its fleet in 2005 by
adding five new six-unit camps.
COMPLETION AND PRODUCTION SERVICES SEGMENT
(Stated in thousands of Canadian dollars, except where indicated)
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of |
|
|
|
|
|
|
% of |
|
|
|
|
|
|
% of |
|
Years ended December 31, |
|
2006 |
|
|
Revenue |
|
|
2005 |
|
|
Revenue |
|
|
2004 |
|
|
Revenue |
|
|
Revenue |
|
$ |
441,017 |
|
|
|
|
|
|
$ |
369,667 |
|
|
|
|
|
|
$ |
313,386 |
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
231,602 |
|
|
|
52.5 |
|
|
|
209,657 |
|
|
|
56.7 |
|
|
|
196,113 |
|
|
|
62.6 |
|
General and administrative |
|
|
14,242 |
|
|
|
3.2 |
|
|
|
11,021 |
|
|
|
3.0 |
|
|
|
12,708 |
|
|
|
4.0 |
|
Depreciation |
|
|
32,013 |
|
|
|
7.3 |
|
|
|
27,402 |
|
|
|
7.4 |
|
|
|
27,508 |
|
|
|
8.8 |
|
Foreign exchange |
|
|
41 |
|
|
|
|
|
|
|
(56 |
) |
|
|
|
|
|
|
(17 |
) |
|
|
|
|
|
Operating earnings (1) |
|
$ |
163,119 |
|
|
|
37.0 |
|
|
$ |
121,643 |
|
|
|
32.9 |
|
|
$ |
77,074 |
|
|
|
24.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Increase |
|
|
|
|
|
|
% Increase |
|
|
|
|
|
|
% Increase |
|
|
|
2006 |
|
|
(Decrease) |
|
|
2005 |
|
|
(Decrease) |
|
|
2004 |
|
|
(Decrease) |
|
|
Number of service rigs (end of year) |
|
|
237 |
|
|
|
|
|
|
|
237 |
|
|
|
(0.8 |
) |
|
|
239 |
|
|
|
|
|
Service rig operating hours |
|
|
480,137 |
|
|
|
0.6 |
|
|
|
477,232 |
|
|
|
1.1 |
|
|
|
472,008 |
|
|
|
7.4 |
|
Revenue per operating hour ($/hour) |
|
|
712 |
|
|
|
18.7 |
|
|
|
600 |
|
|
|
17.0 |
|
|
|
513 |
|
|
|
11.0 |
|
|
|
|
|
(1) |
|
Non-GAAP measure. See page 66. |
2006 Compared to 2005
The Completion and Production Services segment generated another year of record results
on the strength of robust industry activity in western Canada and stronger pricing for services.
Improved pricing resulted in a revenue increase of $71 million or 19% over 2005 to $441 million
while operating earnings increased by $41 million or 34% to $163 million. Operating earnings
increased to 37% of revenue in 2006 compared to 33% in 2005. The margin increase was mainly
attributable to price increases established during the year.
Operating expenses declined from 57% of revenue in 2005 to 53% in 2006, but on a per operating
hour basis, increased due to higher crew labour costs and higher costs associated with repair and
maintenance.
The number of wells rig released in 2006 was 22,575, a decrease of 7% from the record of 24,351
established in 2005. However, with a lag between the drilling and completion of a well, the
industry reported a record 22,171 well completions for the year, an increase of 1% from 21,980 in
2005. The total well count for completions in western Canada was 97,164 for the last five years
adding to the ongoing maintenance demand to ensure continuous and efficient operation of
producing wells. There are currently about 190,000 producing wells within the WCSB.
Service rig contractors in western Canada have maintained the industry rig fleet count relatively
constant over the past several years at approximately 1,050 service rigs as market pricing
remained competitive.
The Completion and Production Services segment is also affected by seasonality in Canada. The
first and fourth quarters of the year are the most active as colder weather allows for the
unrestricted movement of heavy equipment on county and provincial roads. The first quarter
traditionally produces the highest utilization as customers are able to work in northern areas
that are only accessible at that time.
During 2006, Precision acquired Terra Water Systems, a wastewater treatment business. Terra Water
had 41 treatment units at the time of the acquisition and closed the year with 51. The service
provided by Terra Water complements those provided by the LRG Catering and Precision Rentals
divisions and strengthened the diversity of Precisions services.
Reinvestment in equipment in recent years has helped to position the Completion and Production
Services segment as an industry leader. Excluding the business acquisition of Terra Water
Systems, capital spending in 2006 was $39 million, an increase of 11% over 2005. The total
included expansion capital of $13 million for new pump trucks, new slant service rigs, stand
alone snubbing unit fabrication, wellsite accommodations, storage tanks and wastewater treatment
units. Productive capacity maintenance expenditures of $26 million were incurred in the year and
included replacement pump and transporter trucks, snubbing unit trucks, drill pipe for rental and
tanks.
The Precision Well Servicing division increased revenue by $56 million or 20% over 2005
to $342 million. Higher rig rates and marginally improved activity levels over the prior year
contributed to the higher revenue. Price increases established in the fourth quarter of 2005 were
maintained with a slight upward adjustment in the fourth quarter of 2006.
Service rig activity was at record levels for the first three quarters of 2006 due to continued
strong industry activity carried over from 2005 and the backlog of new well completions. However,
wet weather in September and declining natural gas prices caused customers to reassess natural
gas completion and workover programs. Oil well servicing was steady throughout the year as crude
oil prices remained above US$50 per barrel. The strong first half of the year offset the activity
decline in the fourth quarter resulting in 2006 exceeding 2005 by 2,905 operating hours, for 56%
utilization.
Operating earnings for the division improved by $36 million, or 41%, over 2005, due mainly to
service price increases. Costs per operating hour were higher year over year due to increased
crew and rig manager labour expenses and equipment repair and maintenance costs.
Capital expenditures in 2006 were a continuation of long-term plans to upgrade and standardize
equipment. Pump trucks, transporters and mobile doghouse replacements were completed primarily to
replace aging units. The electronic upgrade of engines to include the latest emission control and
fuel conservation standards was also undertaken. Carrier modifications were completed to reduce
rig weights for travel during road ban periods. The construction of two new slant service rigs
under long-term contract commenced in 2006 and, when commissioned in 2007, will bring the fleet
to 239 rigs.
Live Well Services activity decreased by 14% over 2005 with revenues for the year of
$35 million. The decrease was due to the weakening of natural gas prices in 2006 which led to a
cost savings shift by customers away from rig assist and to stand alone snubbing services. Live
Wells snubbing fleet consists of 26 units of which 25 are rig assist with one stand alone unit.
In the fourth quarter of 2006, construction started on four stand alone units, two under
long-term customer contract, which will bring the total snubbing fleet to 30 units in 2007.
Precision Rentals generated revenues of $62 million, which was $11 million or 21%
higher than in 2005. Each of Precision Rentals three product categories; surface equipment,
tubulars and well control equipment, and wellsite accommodations, experienced year over year
revenue increases. Total capital expenditures for 2006 increased 26% from 2005 and included 79
tanks and 10 new wellsite trailers.
Terra Water Systems generated revenues of $2 million for the period subsequent to
August 17, 2006. Growth is expected through product and market diversification, leveraging its
synergies with LRG Caterings remote camp business and Precision Rentals wellsite
accommodations.
2005 Compared to 2004
The Completion and Production Services segment generated revenue of $370 million, 18%
higher than the $313 million in 2004 with operating earnings increasing by $45 million or 58% to
$122 million. Operating earnings increased to 33% of revenue in 2005 as compared to 25% in 2004.
The margin increase was attributable to the enhanced operating performance of the service rig
fleet as the division was able to increase rates throughout the year. Equipment demand provided
the ability to establish pricing levels based on possession rather than just usage.
Operating expenses declined from 63% of revenue in 2004 to 57% in 2005 and increased marginally
per operating hour due to higher labour costs. Centralization of personnel, accounting,
purchasing, and equipment management provided economies of scale and more effective deployment of
segment resources.
Capital spending in 2005 was $35 million, an increase of 9% over 2004. This included expansion
capital of $8 million for a stand alone snubbing unit, additional pump trucks, wellsite
accommodations and storage tanks. Maintenance capital included replacement trucks for
transporters, snubbing units and pump trucks as well as drill pipe for rental, snubbing equipment
and a facility upgrade in Grande Prairie, Alberta.
The Precision Well Servicing division increased revenue by $44 million or 18% over 2004
to $286 million due to a slight increase in activity and higher rates. Precision Well Servicing
achieved 55% utilization, a nominal
improvement over the prior year. Operating earnings improved by $38 million, a 79% improvement
over the prior year due mainly to price increases. In addition, operating costs were marginally
higher per operating hour year over year due to higher labour costs. Cost efficiencies were
achieved by the consolidation of operating centres in the latter part of the prior year. Capital
expenditures in 2005 emphasized the upgrading and standardization of equipment.
Live Well Services activity decreased slightly in 2005. The demand for snubbing, while
finishing strong, slowed early in the year. However, revenue increased by $4 million or 12% over
2004 to $32 million. The improvement was attributable to higher hourly operating and standby
rates established in the last half of the year. Live Well upgraded its fleet of hydraulic rig
assist snubbing units through scheduled truck chassis replacement and introduced its first stand
alone unit.
Precision Rentals reported a revenue increase of $8 million or 19% over 2004 to $51
million. The increase was attributable to higher drilling activity which led to higher demand and
improved pricing for rental equipment. Operating earnings increased by 37% over the prior year.
The division expanded its wellsite accommodation fleet in 2005 by 8% with the purchase of 24
units.
OTHER ITEMS
2006 Compared to 2005
Corporate and Other Expenses
Corporate and other expenses decreased by $19 million or 32% as compared to 2005. Included in
the 2005 expenses were $18 million in costs related to the conversion to an income trust.
Excluding these conversion costs, corporate and other expenses decreased $1 million or 4% year
over year. The introduction of the long-term incentive plan (LTIP) added an additional $4
million of costs during 2006 over the prior period stock option plan expense, while increased
accruals for recurring near-term incentive plans added another $3 million. Disposals of corporate
property, plant and equipment in 2005 and 2006 contributed to a $2 million reduction in
depreciation expense. Significant reductions in Precisions net foreign currency position related
to 2005 divestitures and the repayment of U.S. dollar debentures led to a $3 million reduction in
foreign exchange gains in 2006. The remaining $9 million reduction in costs were mostly
attributable to the absence of severance and retention bonuses incurred in 2005, lower legal,
advisory and support costs in 2006 and the recovery of certain liability provisions expensed in
prior periods.
Interest Expense
Net interest expense of $8 million declined by $21 million or 73% in 2006 compared to 2005.
This reduction was primarily attributable to the repayment of the outstanding bonds (debentures)
in October 2005 which resulted in lower subsequent debt levels. Also in 2005, Precision was in a
significant surplus cash position, to the date of trust conversion, which generated $10 million
in interest income. Monthly debt, net of cash, averaged $164 million in 2006.
Income Taxes
The Trusts effective tax rate, before enacted tax rate reductions, on earnings from
continuing operations before income taxes was 6% in 2006 compared to 25% in 2005. This
comparatively low effective tax rate was primarily a result of the conversion to an income trust
which had the effect of shifting the income tax burden of the Trust to its unitholders.
The Trust incurs taxes to the extent there are certain provincial capital taxes, as well as taxes
on any taxable income, of its underlying subsidiaries, not distributed to unitholders. In
addition, future income taxes arise from differences between the accounting and tax basis of the
operating entities assets and liabilities.
During 2006 the federal and certain provincial governments enacted various reductions to
corporate income tax rates. The Government of Canada passed legislation to eliminate the
corporate capital tax, reduce the federal
income tax rate from 21% to 19% over the next four years and eliminate the federal corporate
surtax in 2008. The Province of Alberta reduced the corporate income tax rate by 1.5% effective
April 1, 2006. Enacted tax rate reductions resulted in a $21 million future tax recovery in the
second quarter of 2006.
Discontinued Operations
A $7 million gain, net of tax, on discontinued operations was recorded in 2006. A $2 million
gain was recorded on the final payment of contingent consideration associated with the 2004
disposal of United Diamond Ltd. Gains of $4 million and $1 million were recorded for working
capital adjustments related to the 2005 disposals of CEDA International Corporation (CEDA) and
the Energy Services and International Contract Drilling divisions, respectively. The 2005
business divestitures contributed $74 million in net earnings and $1.3 billion in gains on
disposition towards the financial results in fiscal 2005.
2005 Compared to 2004
Corporate and Other Expenses
Corporate and other expenses increased by $33 million or 116% in 2005 as compared to 2004.
Included in these expenses are $18 million in costs associated with the conversion to an income
trust comprising a one-time severance payment of $13 million to a senior executive and $5 million
in legal, accounting and advisory fees. Excluding those costs, corporate and other expenses
increased by $15 million or 53% year over year of which $6 million was attributable to a
reduction in foreign exchange gains and the remaining $9 million to severance and retention bonus
payments, increased legal and advisory fees related to other internal reorganization activities,
examining strategic and financing alternatives, and increased internal and external audit costs
to comply with financial reporting requirements.
Interest Expense
Net interest expense of $29 million declined by 37% in 2005 compared to 2004. This reduction
was attributable to the repayment of the outstanding bonds (debentures) in October 2005 and from
being in a surplus cash position, to the date of trust conversion, which generated $10 million in
interest income.
Premium on Redemption of Bonds
In October 2005, the outstanding bonds were repaid, resulting in a charge of $72 million that
was absent in 2004.
Loss on Disposal of Short-term Investments
Precision received 26 million shares of Weatherford International Ltd. as part of the
consideration for the disposal of the Energy Services and International Contract Drilling
divisions. Substantially all of the shares were transferred to shareholders in conjunction with
the November 7, 2005 plan of arrangement and a $71 million loss was incurred.
Discontinued Operations
During the third quarter of 2005, Precision completed two significant business divestitures.
These businesses contributed $74 million in net earnings which have been included in discontinued
operations. Combined with the gains on disposition in the amount of $1.3 billion, discontinued
operations contributed net earnings of $1.4 billion towards the financial results in fiscal 2005.
First, Precision disposed of its Energy Services and International Contract Drilling divisions,
resulting in an after tax gain of $1.2 billion. Second, Precision disposed of the industrial
services business carried on by CEDA for an after tax gain of $132 million.
Income Taxes
Precisions effective tax rate on earnings from continuing operations before income taxes was
25% in 2005 compared to 35% in 2004. The decrease in the tax rate was primarily a result of the
conversion to an income trust in November 2005 which had the effect of shifting the income tax
burden of the Trust to its unitholders.
LIQUIDITY AND CAPITAL RESOURCES
In 2006, strong operating results combined with lower net debt levels provided the Trust with
cash flows from operations of $610 million. Issuances of Trust units through the distribution
reinvestment plan and increases in long-term debt and bank indebtedness added $70 million. An
additional $7 million was provided from the settlement of matters relating to prior year
dispositions. Offsetting these sources of cash, the Trust incurred capital expenditures, net of
dispositions of capital assets and changes in related non-cash working capital, of $226 million
and spent $16 million to purchase all the outstanding shares of Terra Water Group Ltd. Total cash
distributions paid to unitholders during 2006 were $445 million.
The Trust exited 2006 with a long-term debt to long-term debt plus equity ratio of 10% and a
ratio of long-term debt to cash from operations of 23%.
In the 2005 MD&A, the Trust gave guidance as to the expected 2006 amounts for certain balance
sheet and cash flow items. Lower 2006 fourth quarter activity, which resulted in a reduction of
$184 million to the expected working capital and profitability, was the primary factor leading to
a positive variance of $260 million over estimated 2006 cash provided by continuing operations of
$350 million. This positive variance combined with lower net productive capacity maintenance
capital expenditures, which includes disposal proceeds of $29 million, led to long-term debt
being $294 million lower than the $435 million estimate.
Precision has a number of committed and uncommitted lines of credit available to finance its
activities. The committed facilities consist of a $700 million three-year revolving unsecured
credit facility with a syndicate led by a Canadian chartered bank. The borrowing capacity of the
facility was increased by $150 million in 2006 to assist in financing the expansionary growth
plans of Precision. The facility matures in November 2009, and is extendible annually with the
consent of lenders. The facility has three financial covenants which are tested quarterly: total
liabilities to equity of less than 1:1; total debt to the trailing four quarters cash flow of
less than 2.75:1; and total distributions to unitholders of less than 100% of consolidated cash
flow, as defined in the credit facility agreement. As at December 31, 2006, Precision was well
within the financial covenant levels, and is expected to remain so for 2007. There was $141
million outstanding under the committed facilities at December 31, 2006. In addition to the
committed facilities, Precision also has a number of uncommitted operating facilities which total
approximately $66 million equivalent and are utilized for working capital management and the
issuance of letters of credit.
The Corporations contractual obligations are outlined in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
|
(Stated in thousands of Canadian dollars) |
|
Total |
|
|
Less Than 1 Year |
|
|
1 3 Years |
|
|
4 5 Years |
|
|
After 5 Years |
|
|
Long-term debt |
|
$ |
140,880 |
|
|
$ |
|
|
|
$ |
140,880 |
|
|
$ |
|
|
|
$ |
|
|
Operating leases |
|
|
26,538 |
|
|
|
7,858 |
|
|
|
11,371 |
|
|
|
7,309 |
|
|
|
|
|
Long-term incentive plan |
|
|
22,699 |
|
|
|
|
|
|
|
22,699 |
|
|
|
|
|
|
|
|
|
|
Total contractual obligations |
|
$ |
190,117 |
|
|
$ |
7,858 |
|
|
$ |
174,950 |
|
|
$ |
7,309 |
|
|
$ |
|
|
|
The Trust instituted the LTIP in 2006 which compensates officers and key employees through
cash payments at the end of a three-year term. The compensation is comprised of two components, a
retention award and a performance award. The retention award is a lump sum amount determined at
the date of commencement in the LTIP. The retention component is accrued evenly over the
three-year term and is estimated to total $11 million with anticipated payment to occur in March
2009. The performance component is based on the growth in cash distributions measured against a
base distribution rate as determined by the Compensation Committee of Precision. The performance
component is accrued based on actual distributions compared to target distributions. There is no
assurance that the performance component will be paid.
Outstanding Unit Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
February 28 |
|
|
December 31 |
|
|
December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
Trust units |
|
|
125,570,432 |
|
|
|
125,536,329 |
|
|
|
124,352,921 |
|
Exchangeable LP units |
|
|
187,492 |
|
|
|
221,595 |
|
|
|
1,108,382 |
|
|
Total units outstanding |
|
|
125,757,924 |
|
|
|
125,757,924 |
|
|
|
125,461,303 |
|
|
DISTRIBUTIONS
Upon Precisions conversion to an income trust effective November 7, 2005, the Trust adopted
a policy of making monthly distributions to holders of Trust units and holders of exchangeable LP
units (together Unitholders). Precision has a legal entity structure whereby the trust entity,
Precision Drilling Trust, effectively must flow its taxable income to unitholders pursuant to its
Declaration of Trust. Distributions may be reduced, increased or suspended entirely depending on
the operations of Precision and the performance of its assets, or legislative changes in tax laws
by governments in Canada. The actual cash flow available for distribution to Unitholders is a
function of numerous factors, including the Trusts: financial performance; debt covenants and
obligations; working capital requirements; productive capacity maintenance expenditures and
expansion capital expenditure requirements for the purchase of property, plant and equipment; and
number of units outstanding. The Trust considers these factors on a monthly basis in determining
future distributions. In 2006 cash distributions declared were $447 million or $3.56 per diluted
unit. In December 2006, a special year-end in-kind distribution, as explained below, payable in
Trust or exchangeable LP units (together Units), of $25 million or $0.195 per diluted unit was
declared.
In the event that a distribution is declared in the form of in-kind Units, the terms of the
Declaration of Trust and the Limited Partnership Agreement require that the outstanding Units be
consolidated immediately subsequent to the distribution. Accordingly, the number of outstanding
Units would remain at the number outstanding immediately prior to the Unit distribution. As a
result, Unitholders would not receive additional Units and the declared amount of the in-kind
distribution would be retained in Precision.
Key factors for consideration in determining actual cash flow available for distribution, in an
historical context, are disclosed within the consolidated statements of cash flow. A
reconciliation of distributable cash from operations in 2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Stated in thousands of Canadian dollars, except per unit amounts) |
|
2006 |
|
|
|
2005 |
|
|
|
2004 |
|
|
|
|
|
|
Cash provided by continuing operations |
|
$ |
609,744 |
|
|
|
$ |
206,013 |
|
|
|
$ |
286,437 |
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive capacity maintenance capital expenditures |
|
|
(92,123 |
) |
|
|
|
(92,214 |
) |
|
|
|
(82,014 |
) |
Unfunded long-term incentive plan obligation |
|
|
(22,699 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash from operations (A) (1) |
|
|
494,922 |
|
|
|
$ |
113,799 |
|
|
|
$ |
204,423 |
|
|
|
|
|
|
|
|
|
|
|
Cash retained |
|
|
(47,921 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions declared (B) |
|
$ |
447,001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payout ratio (B)/(A) |
|
|
90.3% |
|
|
|
|
|
|
Distributable cash from operations per basic and diluted unit |
|
$ |
3.94 |
|
|
|
|
|
(1) |
|
Non-GAAP measure. See page 66. |
Fiscal 2006 was Precisions first full year as an income trust. Management believes that any
retained cash or payout ratio calculation for prior years would not be meaningful given the
Trusts November 2005 conversion.
Productive capacity maintenance capital expenditures allow the Trust to maintain its existing
service levels. These expenditures consist of betterments and replacements to existing assets and
capitalized costs relating to the underlying support infrastructure. The productive capacity
maintenance strategy of Precision also involves costs that are charged directly to the income
statement. These costs are related to the scheduled maintenance and certification processes
within the various operating divisions. The level of these expenditures is driven by activity
levels and can be scaled back in times of low activity without jeopardizing the long-term
productive capacity of
Precision and its underlying assets.
The Trust maintains a strong balance sheet and has sufficient debt facilities to manage
short-term funding needs as well as planned equipment additions. Part of the debt management
strategy involves retaining sufficient funds from available distributable cash to finance
productive capacity maintenance capital expenditures as well as working capital needs. Planned
asset growth will generally be financed through existing debt facilities or cash retained from
continuing operations.
|
|
|
|
|
|
|
|
|
(Stated in thousands of Canadian dollars) |
|
2006 |
|
|
2005 |
|
|
Units outstanding |
|
|
125,757,924 |
|
|
|
125,461,303 |
|
Year end unit price |
|
$ |
27.00 |
|
|
$ |
33.00 |
|
|
Units at market |
|
$ |
3,395,464 |
|
|
$ |
4,140,223 |
|
Long-term debt |
|
|
140,880 |
|
|
|
96,838 |
|
Less: Working capital |
|
|
(166,484 |
) |
|
|
(152,754 |
) |
|
Enterprise value |
|
$ |
3,369,860 |
|
|
$ |
4,084,307 |
|
|
Precision carried a long-term debt to unit market value ratio of 4% at December 31, 2006.
This represents a slight increase over the 2005 ratio of 2%.
QUARTERLY FINANCIAL SUMMARY
(Stated in thousands of Canadian dollars except per diluted unit/share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2006 |
|
Q1 |
|
|
Q2 |
|
|
Q3 |
|
|
Q4 |
|
|
Year |
|
|
Revenue |
|
$ |
536,408 |
|
|
$ |
223,569 |
|
|
$ |
349,558 |
|
|
$ |
328,049 |
|
|
$ |
1,437,584 |
|
Operating earnings (1) |
|
|
245,909 |
|
|
|
74,543 |
|
|
|
142,431 |
|
|
|
132,396 |
|
|
|
595,279 |
|
Earnings from continuing operations |
|
|
224,183 |
|
|
|
88,303 |
|
|
|
133,552 |
|
|
|
126,474 |
|
|
|
572,512 |
|
Per diluted unit/share |
|
|
1.79 |
|
|
|
0.70 |
|
|
|
1.06 |
|
|
|
1.01 |
|
|
|
4.56 |
|
Net earnings |
|
|
224,183 |
|
|
|
88,303 |
|
|
|
139,667 |
|
|
|
127,436 |
|
|
|
579,589 |
|
Per diluted unit/share |
|
|
1.79 |
|
|
|
0.70 |
|
|
|
1.11 |
|
|
|
1.01 |
|
|
|
4.62 |
|
Cash provided by (used in) continuing operations |
|
|
40,940 |
|
|
|
339,619 |
|
|
|
74,952 |
|
|
|
154,233 |
|
|
|
609,744 |
|
Distributions to unitholders declared |
|
$ |
101,623 |
|
|
$ |
111,681 |
|
|
$ |
116,785 |
|
|
$ |
141,435 |
|
|
$ |
471,524 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2005 |
|
Q1 |
|
|
Q2 |
|
|
Q3 |
|
|
Q4 |
|
|
Year |
|
|
Revenue |
|
$ |
383,407 |
|
|
$ |
157,895 |
|
|
$ |
300,016 |
|
|
$ |
427,861 |
|
|
$ |
1,269,179 |
|
Operating earnings (1) |
|
|
153,020 |
|
|
|
24,505 |
|
|
|
111,956 |
|
|
|
175,897 |
|
|
|
465,378 |
|
Earnings from continuing operations |
|
|
88,281 |
|
|
|
9,308 |
|
|
|
2,382 |
|
|
|
120,877 |
|
|
|
220,848 |
|
Per diluted unit/share |
|
|
0.71 |
|
|
|
0.07 |
|
|
|
0.08 |
|
|
|
0.96 |
|
|
|
1.76 |
|
Net earnings |
|
|
138,518 |
|
|
|
25,851 |
|
|
|
1,382,648 |
|
|
|
83,546 |
|
|
|
1,630,563 |
|
Per diluted unit/share |
|
|
1.11 |
|
|
|
0.21 |
|
|
|
11.00 |
|
|
|
0.66 |
|
|
|
13.00 |
|
Cash provided by (used in) continuing operations |
|
|
95,902 |
|
|
|
116,719 |
|
|
|
46,978 |
|
|
|
(53,587 |
) |
|
|
206,013 |
|
Distributions to unitholders declared |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
70,510 |
|
|
$ |
70,510 |
|
|
|
|
|
(1) |
|
Non-GAAP measure. See page 66. |
The Canadian drilling industry is subject to seasonality with activity peaking during the
winter months in the fourth and first quarters. As temperatures rise in the spring, the ground
thaws and becomes unstable. Government road bans severely restrict activity in the second quarter
before equipment is moved for summer drilling programs in the third quarter. These seasonal
trends typically lead to quarterly fluctuations in operating results and working capital
requirements.
FOURTH QUARTER DISCUSSION
During 2006, the persistent downward trend in commodity prices, natural gas in particular,
led to lower fourth quarter demand for all of Precisions services in western Canada. For the
first time in five quarters, Precisions operating results were down from the comparable quarter
in the prior year as overall customer demand decreased due to the decline in natural gas prices.
Revenue of $328 million and operating earnings of $132 million in the fourth quarter of 2006
represented decreases of 23% and 25% respectively, compared to the same period in 2005. Despite
the decline in equipment activity, firm pricing helped maintain operating earnings at 40% of
revenue in the fourth quarter of 2006 versus 41% in the fourth quarter of 2005.
Earnings from continuing operations in the fourth quarter of 2006 were $126 million compared with
$121 million in 2005, an increase of $0.05 per diluted unit. Adjusted for the impact of one-time
charges against the prior year fourth quarter earnings from continuing operations of $75 million,
the current quarter represented a decrease of $0.48 per diluted unit, or 32%. These one-time
charges included $18 million for the reorganization of Precision into an income trust, $51
million for the loss on a short-term investment in Weatherford International Ltd., and $6 million
for the repayment of outstanding debentures. Precision realized the benefit of a lower effective
tax rate for the full quarter in 2006.
Activity for the quarter was down 33% for drilling rigs and 23% for service rigs from the prior
year, consistent with industry declines in the quarter of approximately 25% in the number of
wells rig released and the number of rigs working. Drilling rig operating days for the fourth
quarter of 2006 were also 18% lower than the third quarter of 2006.
Compared to 2005, Canadian industry drilling rig operating days decreased by approximately 27% in
the fourth quarter of 2006 to 35,682. Industry wells drilled, on a rig release basis, decreased
by 24% to 5,339 and the available rig count increased by 9% to approximately 842 compared to the
fourth quarter of 2005. New rig capacity in the industry adversely impacted overall equipment
utilization rates.
Contract Drilling Services segment revenue of $223 million and operating earnings of $104
million decreased by 28% and 33%, respectively, in the fourth quarter of 2006 compared to the
same period in 2005. The decline in equipment activity was offset somewhat by an increase in
average day rates for contract drilling of 8%. LRG experienced an activity decrease, achieving
3,730 camp days for a 39% decline over the prior year.
Completion and Production Services segment revenue of $108 million and operating earnings of $40
million decreased by 13% and 22%, respectively, in the fourth quarter of 2006 compared to the
same period in 2005. Precisions service rig operating hours during the fourth quarter of 2006
were 109,737 compared to 142,122 in 2005, a decrease of 23%. Well service rig operating hours
were down over the prior year due to the general decline in industry activity related to natural
gas. The decline in activity was somewhat offset by an increase in hourly service rig rates of
14% for the fourth quarter year over year. Demand for rental equipment followed downward industry
trends and was 15% lower than the prior year. For Precisions snubbing division, activity was
down 27% in the quarter over the prior year as a result of lower natural gas well activity.
Operating costs increased from 45% of revenue in the fourth quarter of 2005 to 47% in 2006. The
increase was mainly caused by a 13% rise in costs per operating day for contract drilling and 15%
per operating hour in well servicing including crew wage increases of 4% implemented in the
fourth quarter of 2006. There were also increases in third party labour and material costs.
Historically, on October 1, a winter rate adjustment for these costs is passed on to customers.
This year, in many cases Precision was unable to increase rates to absorb these costs. In
addition, equipment repair and maintenance costs were higher per day and per hour as scheduled
equipment maintenance was deferred from earlier in 2006 due to a shortage of maintenance
infrastructure. Further, lower activity in the fourth quarter of 2006 contributed to increase
fixed operating costs per day in contract drilling and per hour in well servicing.
The Trusts effective income tax rate before enacted tax rate reductions on earnings from
continuing operations before income taxes was 3% in the fourth quarter and 6% for the 2006 fiscal
year. The comparatively low effective income tax rate was primarily a result of the conversion to
an income trust part way through the comparative quarter of 2005 which had the effect of shifting
all or a portion of the income tax burden of the Trust to its unitholders.
In the fourth quarter, capital expenditures amounted to $72 million of which $44 million was for
the construction of new drilling rigs and an additional $2 million for expansion capital in the
Completions and Production Services segment. During the fourth quarter of 2006, four new drilling
rigs were released into the field. The remaining $26 million was spent to sustain and upgrade
existing equipment and infrastructure.
Fourth quarter monthly cash distributions declared were $0.31 per diluted unit for aggregate
distributions declared of $117 million or $0.93 per diluted unit. A special year-end in-kind
distribution of $25 million or $0.195 per diluted unit was also declared bringing total declared
distributions for the quarter to $141 million or $1.125 per diluted unit. The special in-kind
distribution was made to minimize debt levels and retain balance sheet strength to fund planned
asset growth. The distribution reinvestment plan generated cash of $4 million and on December 18,
2006 was suspended. Long-term debt decreased by $25 million during the quarter to $141 million
for a long-term debt to long-term debt plus equity ratio of 10%. Working capital decreased by $51
million during the quarter to $166 million as lower activity levels reduced revenue and
corresponding accounts receivable, while capital expenditures increased.
CRITICAL ACCOUNTING ESTIMATES, NEW ACCOUNTING STANDARDS AND BUSINESS RISKS
CRITICAL ACCOUNTING ESTIMATES
This Managements Discussion and Analysis of Precisions financial condition and results of
operations is based on Precisions consolidated financial statements which are prepared in
accordance with Canadian generally accepted
accounting principles (GAAP). These principles differ in certain respects from U.S. generally
accepted accounting principles, and these differences are described and quantified in Note 16 to
the consolidated financial statements.
The Trusts significant accounting policies are described in Note 2 to its consolidated financial
statements. The preparation of these financial statements requires that certain estimates and
judgments be made that affect the reported assets, liabilities, revenues and expenses. These
estimates and judgments are based on historical experience and on various other assumptions that
are believed to be reasonable under the circumstances. Anticipating future events cannot be done
with certainty, therefore, these estimates may change as new events occur, more experience is
acquired and as the Trusts 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 Precisions 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. Precisions history of bad debt losses has been
within expectations and generally limited to specific customer circumstances. However, given the
cyclical nature of the oil and natural gas industry and the inherent risk of successfully finding
hydrocarbon reserves, a customers ability to fulfill its payment obligations can change suddenly
and without notice. In cases where creditworthiness is uncertain, services are provided for cash
in advance.
Impairment of Long-lived Assets
Long-lived assets, which include property, plant and equipment, intangibles and goodwill,
comprise the majority of Precisions assets. The carrying value of these assets is periodically
reviewed for impairment or whenever events or changes in circumstances indicate that their
carrying amounts may not be recoverable. This requires Precision to forecast future cash flows to
be derived from the utilization of these assets based upon assumptions about future business
conditions and technological developments. Significant, unanticipated changes to these
assumptions could require a provision for impairment in the future. During the fourth quarter of
2006, Precision completed its assessment and concluded that there was no impairment of the
carrying value.
Depreciation and Amortization
Precisions property, plant and equipment and its intangible assets are depreciated and
amortized based upon estimates of useful lives and salvage values. These estimates may change as
more experience is gained, market conditions shift or new technological advancements are made.
Effective January 1, 2005, Precision changed the useful life of its drilling rigs for purposes of
determining depreciation expense to 5,000 utilization days from 4,150 utilization days (3,650
operating days), and its drill strings to 1,500 from 1,100 operating days. Utilization days
include both operating and rig move days. This change in accounting estimate has been applied
prospectively and resulted in an $11 million reduction of depreciation expense or $0.09 per
diluted unit for the year ended December 31, 2005.
Income Taxes
The corporate subsidiaries of the Trust use the liability method which takes into account the
differences between financial statement treatment and tax treatment of certain transactions,
assets and liabilities. The Trust, itself, does not have any significant temporary tax
differences. Future tax assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of existing assets
and liabilities and their respective tax bases. Valuation allowances are established to reduce
future tax assets when it is more likely than not that some portion or all of the asset will not
be realized. Estimates of future taxable income and the continuation of ongoing prudent tax
planning arrangements have been considered in assessing the utilization of available tax losses.
Changes in circumstances and assumptions and clarifications of uncertain tax regimes may require
changes to the valuation allowances associated with Precisions 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 Precisions interpretation of relevant tax legislation and
regulations. Precisions management believes that the provision for income tax is adequate.
During 2006, the Government of Canada released for comment draft legislation which would result
in a tax structure for trusts similar to that of corporate entities. If the proposed legislation
is implemented, the Trust would be required to recognize, on a prospective basis, future income
taxes on temporary differences in the Trust.
Long-term Incentive Plan Compensation
The Trust instituted a long-term incentive plan which compensates officers and key employees
through cash payments at the end of a three-year term. The compensation includes two components,
a retention component and a performance award. The performance component is based on growth in
distributions measured against a distribution rate as determined by the Compensation Committee of
Precision. As a result of actual distributions in the subsequent two years, the accrued amount
for the performance component may be reduced or increased depending on the actual amounts
distributed.
NEW ACCOUNTING STANDARDS
The Canadian Institute of Chartered Accountants issued certain new accounting standards which
will be in effect for fiscal years beginning on or after October 1, 2006 for recognition and
measurement of financial instruments, disclosure of comprehensive income, and hedge accounting.
Section 3855, Financial Instruments Recognition and Measurement, provides guidance on when
a financial instrument must be recognized on the balance sheet and how it must be measured. It
also provides guidance on the presentation of gains and losses on financial instruments.
Section 3865, Hedges, provides guidance on the application of hedge accounting and related
disclosures.
Section 1530, Comprehensive Income, requires an entity to recognize certain gains and losses
in a separate statement, until such gains and losses are recognized in the statement of income.
The Trust does not expect that the adoption of these standards will have a material impact on the
consolidated financial statements.
BUSINESS RISKS
The discussion of risk that follows is not a complete representation. Refer to the
Cautionary Statement Regarding Forward-Looking Information and Statements on page 1.
Certain activities of Precision are affected by factors that are beyond its control or influence.
The drilling rig, camp and catering, service rig, snubbing, wastewater treatment, rentals, and
related service businesses and activities of Precision in Canada and the drilling rig, camp and
catering and rentals businesses and activities of Precision in the United States are directly
affected by fluctuations in the levels of exploration, development and production activity
carried on by its customers which, in turn, is dictated by numerous factors, including world
energy prices and government policies. The addition, elimination or curtailment of government
regulations and incentives could have a significant impact on the oil and gas business in Canada
and the United States. These factors could lead to a decline in the demand for Precisions
services, resulting in a material adverse effect on revenues, cash flows, earnings and cash
distributions to unitholders. The majority of Precisions operating costs are variable in nature
which minimizes the impact of downturns on its operational results.
Crude Oil and Natural Gas Prices
Precisions revenue, cash flow and earnings are substantially dependent upon, and affected
by, the level of activity associated with oil and natural gas exploration and production. Both
short-term and long-term trends in oil and natural gas prices affect the level of such activity.
Oil and natural gas prices and, therefore, the level of drilling,
exploration and production activity have been volatile over the past few years and likely will
continue to be volatile. WTI crude oil prices in 2006 ranged from a low of US$56 per barrel to a
high of US$78 per barrel. Military, political, weather, economic and other events in certain
parts of the world, including initiatives by the Organization of Petroleum Exporting Countries,
may affect both the demand for, and the supply of, oil and natural gas. North American petroleum
service activity is largely focused on natural gas. In 2006 the natural gas spot price, as
measured at Henry Hub, averaged almost US$7 per MMBtu and ranged from an approximate low and high
of US$4 to US$10 per MMBtu, respectively. Weather conditions, governmental regulation (both in
Canada and elsewhere), levels of consumer demand, the availability of pipeline capacity, storage
levels and other factors beyond Precisions control may also affect the supply of and demand for
oil and natural gas and thus lead to future price volatility. Precision believes that any
prolonged reduction in oil and natural gas prices would depress the level of exploration and
production activity. Lower oil and natural gas prices could also cause Precisions customers to
seek to terminate, renegotiate or fail to honour Precisions drilling contracts which: could
affect the fair market value of its rig fleet which in turn could trigger a write-down for
accounting purposes; could affect Precisions ability to retain skilled rig personnel; and could
affect Precisions ability to obtain access to capital to finance and grow its businesses. There
can be no assurance that the future level of demand for Precisions services or future conditions
in the oil and natural gas industry will not decline.
Workforce Availability
Precisions ability to provide reliable services is dependent upon the availability of
well-trained, experienced crews to operate its field equipment. Precision must also balance the
requirement to maintain a skilled workforce with the need to establish cost structures that
fluctuate with activity levels.
Within Precision, the most experienced people are retained during periods of low utilization by
having them fill lower level positions on field crews. Precision has established training
programs for employees new to the oilfield service sector and works closely with industry
associations to ensure competitive compensation levels and to attract new workers to the industry
as required. Many of Precisions businesses regularly experience manpower shortages in peak
operating periods. These shortages are likely to be further challenged by the number of rigs
being added to the industry along with the entrance and expansion of start-up oilfield service
companies. In the near-term, anticipated declines in activity will offset challenges due to rig
expansion.
Business is Seasonal
In Canada, the level of activity in the oilfield service industry is influenced by seasonal
weather patterns. During the spring months, wet weather and the spring thaw make the ground
unstable. Consequently, municipalities and provincial transportation departments enforce road
bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity
levels and placing an increased level of importance on the location of Precisions equipment
prior to imposition of road bans. The timing and length of road bans is dependant upon the
weather conditions leading to the spring thaw and the weather conditions during the thawing
period.
Additionally, certain oil and natural gas producing areas are located in sections of the WCSB
that are inaccessible, other than during the winter months, because the ground surrounding or
containing the drilling sites in these areas consists of terrain known as muskeg. Until the
muskeg freezes, the rigs and other necessary equipment cannot cross the terrain to reach the
drilling site. Moreover, once the rigs and other equipment have been moved to a drilling site,
they may become stranded or otherwise be unable to relocate to another site should the muskeg
thaw unexpectedly. Precisions business results depend, at least in part, upon the severity and
duration of the Canadian winter.
Technology
Technological innovation by oilfield service companies has improved the effectiveness of the
entire exploration and production sector over the industrys more than 140-year history. Drilling
time has been reduced due to improvements in drill bits, logging and measurement while drilling
tools, as well as innovative changes in other areas such as mud systems and top drives.
Precisions ability to deliver services that are more efficient in reducing
customer development costs is critical to continued success.
Customer Merger and Acquisition Activity
Merger and acquisition activity in the oil and natural gas exploration and production sector
can impact demand for Precisions services as customers focus on internal reorganization
activities prior to committing funds to significant drilling and maintenance projects.
Competitive Industry
The oilfield services industry in which Precision operates is, and will continue to be, very
competitive. There is no assurance that Precision will be able to continue to compete
successfully or that the level of competition and pressure on pricing will not affect its
margins.
Capital Overbuild in the Drilling Industry
As at December 31, 2006 there were an estimated 842 industry drilling rigs in Canada, an
increase of 9% from December 31, 2005. There is no assurance that the level of demand for
drilling rigs in the future will be able to support the size of the current industry drilling rig
fleet in Canada. Any decline in demand for drilling services within the services industry,
directly or indirectly related to the current drilling rigs available, could also lead to a
decline in the demand for Precisions services, resulting in a material adverse effect on
Precisions revenues, cash flows, earnings and cash distributions to unitholders.
Tax Consequences of Previous Transactions Completed by Precision
The business and operations of Precision prior to completion of the Plan of Arrangement were
complex and Precision has executed a number of significant financings, business combinations,
acquisitions and dispositions over the course of its history. The computation of income taxes
payable as a result of those transactions involves many complex factors as well as Precisions
interpretation of relevant tax legislation and regulations. Precisions management believes that
the provision for income tax is adequate and in accordance with GAAP and applicable legislation
and regulations. However, there are a number of tax filing positions that can still be the
subject of review by taxation authorities who may successfully challenge Precisions
interpretation of the applicable tax legislation and regulations, with the result that additional
taxes could be payable by Precision and the amount payable could be up to $300 million. Any
increase in Precisions tax liability would reduce the funds available for distributions on Trust
units.
Credit Risk
Precisions accounts receivable are with customers involved in the oil and natural gas
industry, whose revenues may be impacted by fluctuations in commodity prices. Although collection
of these receivables could be influenced by economic factors affecting this industry, management
considers the risk of a significant loss due to uncollectible receivables to be remote at this
time.
Capital Expenditures
The timing and amount of capital expenditures by Precision will directly affect the amount of
cash available for distribution to unitholders. The cost of equipment has escalated over the past
several years as a result of, among other things, high input costs. There is no assurance that
Precision will be able to recover higher capital costs through rate increases to its customers,
in which case cash distributions may be reduced.
Access to Additional Financing
Precision may find it necessary in the future to obtain additional debt or equity financing
through the Trust to support ongoing operations, to undertake capital expenditures or undertake
acquisitions or other business combination transactions. There can be no assurance that
additional financing will be available to Precision when needed or on terms acceptable to
Precision. Precisions inability to raise financing to support ongoing operations or to fund
capital expenditures or acquisitions or other business combination transactions could limit
Precisions growth and may
have a material adverse effect upon Precision.
Taxation of Distributions
On October 31, 2006, the Government of Canada announced a Tax Fairness Plan containing its
intentions to bring about new tax measures including a Distribution Tax on distributions from
publicly traded income trusts and limited partnerships. The government is proposing a four-year
transition period for existing income trusts and limited partnerships whereby the new measures
will not apply until their 2011 taxation year. Under the proposals, flow-through entities will
be taxed more like corporations and their investors will be treated more like shareholders. The
proposed new tax measures will impair the flow-through nature of Precision Drilling Trusts
current tax structure. If enacted into law, these tax measures would result in a distribution tax
to the Trust which will reduce the cash distributed to unitholders by the amount of distribution
tax paid.
Environmental
There is growing concern about the apparent correlation between the burning of fossil fuels
and climate change. In February 2007, the United Nations Intergovernmental Panel on Climate
Change released a report reiterating calls for action on the basis that man-made activities,
particularly burning fossil fuels, were very likely behind global warming. The issue of energy
and the environment has created intense public debate in Canada and around the world in recent
years that is likely to continue for the foreseeable future and could potentially have a
significant impact on all aspects of the economy including the demand for hydrocarbons and the
resulting lower demand for Precisions services.
DISCLOSURE CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to provide reasonable assurance that
information required to be disclosed in reports filed with, or submitted to, securities
regulatory authorities is recorded, processed, summarized and reported within the time periods
specified under Canadian and United States securities laws. The information is accumulated and
communicated to management, including the principal executive officer and principal financial and
accounting officer, to allow timely decisions regarding required disclosure.
As of December 31, 2006, an evaluation was carried out, under the supervision of and with the
participation of management, including the principal executive officer and principal financial
and accounting officer, of the effectiveness of Precisions 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 Precisions disclosure controls and procedures were effective as at December 31,
2006.
During the
2006 fiscal year, there have been no changes in internal control over financial
reporting that have materially affected, or are reasonably likely to materially affect,
Precisions internal control over financial reporting.
NON-GAAP MEASURES
Precision uses certain measures that are not recognized under Canadian generally accepted
accounting principles to assess performance and believes these non-GAAP measures provide useful
supplemental information to investors. Following are the non-GAAP measures Precision uses in
assessing performance.
Precisions 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 Precisions performance.
OPERATING EARNINGS
Management believes that in addition to net earnings, operating earnings as reported in the
Consolidated Statements of Earnings and Retained Earnings (Deficit) is a useful supplemental
measure as it provides an indication of the results generated by Precisions principal business
activities prior to consideration of how those activities are financed or how the results are
taxed.
DISTRIBUTABLE CASH FROM OPERATIONS
Management believes that in addition to cash provided by (used in) continuing operations,
distributable cash from operations is a useful supplemental measure. It provides an indication of
the funds available for distribution to unitholders after consideration of the impacts of capital
expenditures to maintain the existing productive capacity of Precisions assets and other
operational related funding requirements.
Precision Drilling Trust
MANAGEMENTS 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 Managements Discussion and Analysis (MD&A). The MD&A is based upon
Precision Drilling Trusts (the Trust) financial results prepared in accordance with Canadian
GAAP. The MD&A compares the audited financial results for the years ended December 31, 2006 to
December 31, 2005 and the years ended December 31, 2005 to December 31, 2004. Note 16 to the
consolidated financial statements describes the impact on the consolidated financial statements
of significant differences between Canadian and United States GAAP.
Management is responsible for establishing and maintaining adequate internal control over the
Trusts financial reporting. Internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting and the preparation
of consolidated financial statements for external reporting purposes in accordance with generally
accepted accounting principles. Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to financial
statement preparation and presentation. Also, projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with direction from our principal executive officer and principal
financial and accounting officer, management conducted an evaluation of the effectiveness of the
Trusts internal control over financial reporting. Managements evaluation of internal control
over financial reporting was based on the Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this
evaluation, management concluded that the Trusts internal control over financial reporting was
effective as of December 31, 2006.
The Trust has documented its assessment of internal control over financial reporting and has made
this assessment available to our auditors KPMG LLP. Managements assessment of the effectiveness
of the Trusts internal control over financial reporting as of December 31, 2006, has been
audited by KPMG LLP, as stated in their report included herein, which expresses an unqualified
opinion on managements assessment of the effectiveness of internal control over financial
reporting as of December 31, 2006.
KPMG LLP, an independent firm of Chartered Accountants, was engaged, as approved by a vote of
unitholders at the Trusts most recent annual meeting, to audit the consolidated financial
statements and provide an independent professional opinion.
The Audit Committee of the Board of Directors, which is comprised of three independent directors
who are not employees of the Trust, provides oversight to the financial reporting process.
Integral to this process is the Audit Committees 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 Trusts internal
controls. The consolidated financial statements have been approved by the Board of Trustees on
the recommendation of the Board of Directors of Precision Drilling Corporation and its Audit
Committee.
|
|
|
(Signed) |
|
(Signed) |
|
|
|
Gene C. Stahl
|
|
Doug J. Strong |
President and Chief Operating Officer
|
|
Chief Financial Officer |
Precision Drilling Corporation,
|
|
Precision Drilling Corporation, |
Administrator to Precision Drilling Trust
|
|
Administrator to Precision Drilling Trust |
March 9, 2007
|
|
March 9, 2007 |
Precision Drilling Trust
AUDITORS REPORT TO THE UNITHOLDERS
To the Unitholders of Precision Drilling Trust
We have audited the consolidated balance sheets of Precision Drilling Trust (the Trust) as
at December 31, 2006 and 2005 and the consolidated statements of earnings and retained earnings
(deficit) and cash flow for each of the years in the three-year period ended December 31, 2006.
These financial statements are the responsibility of the Trusts management. Our responsibility
is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. With
respect to the consolidated financial statements for the year ended December 31, 2006, we also
conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects,
the financial position of the Trust as at December 31, 2006 and 2005 and the results of its
operations and its cash flow for each of the years in the three-year period ended December 31,
2006 in accordance with Canadian generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of the Trusts internal control over financial reporting
as of December 31, 2006, based on the criteria established in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
and our report dated February 13, 2007 expressed an unqualified opinion on managements
assessment of, and the effective operation of, internal control over financial reporting.
(Signed: KPMG LLP)
Chartered Accountants
Calgary, Alberta
February 13, 2007
Precision Drilling Trust
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Precision Drilling Corporation, as Administrator of Precision
Drilling Trust and the Unitholders of Precision Drilling Trust
We have audited managements assessment, included in the accompanying managements report,
that Precision Drilling Trust (the Trust) maintained effective internal control over financial
reporting as of December 31, 2006, based on the criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). The Trusts management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control
over financial reporting. Our responsibility is to express an opinion on managements assessment
and an opinion on the effectiveness of the Trusts internal control over financial reporting
based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating managements assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as
we considered necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
An entitys 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
entitys internal control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the entity are being made only in accordance with authorizations of management
and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the entity assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, managements assessment that the Trust maintained effective internal control over
financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on
the criteria established in Internal Control Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Trust
maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2006, based on the criteria established in Internal Control Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have conducted our audits on the consolidated financial statements in accordance with
Canadian generally accepted auditing standards. With respect to the year ended December 31, 2006,
we also have conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Our report dated February 13, 2007, expressed an
unqualified opinion on those consolidated financial statements.
(Signed: KPMG LLP)
Chartered Accountants
Calgary, Alberta
February 13, 2007
Precision Drilling Trust
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, |
|
|
|
|
|
|
|
|
|
|
(Stated in thousands of Canadian dollars) |
|
|
|
|
|
2006 |
|
|
2005 |
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
(Note 19) |
|
$ |
354,671 |
|
|
$ |
500,655 |
|
Income taxes recoverable |
|
|
|
|
|
|
8,701 |
|
|
|
|
|
Inventory |
|
|
|
|
|
|
9,073 |
|
|
|
7,035 |
|
|
|
|
|
|
|
|
|
372,445 |
|
|
|
507,690 |
|
Property, plant and equipment, net of accumulated depreciation |
|
(Note 5) |
|
|
1,107,617 |
|
|
|
943,900 |
|
Intangibles, net of accumulated amortization of $503 (2005 $413) |
|
|
|
|
|
|
375 |
|
|
|
465 |
|
Goodwill |
|
|
|
|
|
|
280,749 |
|
|
|
266,827 |
|
|
|
|
|
|
|
|
$ |
1,761,186 |
|
|
$ |
1,718,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND UNITHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Bank indebtedness |
|
(Note 6) |
|
$ |
36,774 |
|
|
$ |
20,468 |
|
Accounts payable and accrued liabilities |
|
(Note 19) |
|
|
130,202 |
|
|
|
134,303 |
|
Incomes taxes payable |
|
|
|
|
|
|
|
|
|
|
163,530 |
|
Distributions payable |
|
(Note 7) |
|
|
38,985 |
|
|
|
36,635 |
|
|
|
|
|
|
|
|
|
205,961 |
|
|
|
354,936 |
|
Long-term incentive plan payable |
|
|
|
|
|
|
22,699 |
|
|
|
|
|
Long-term debt |
|
(Note 8) |
|
|
140,880 |
|
|
|
96,838 |
|
Future income taxes |
|
(Note 9) |
|
|
174,571 |
|
|
|
192,517 |
|
|
|
|
|
|
|
|
|
544,111 |
|
|
|
644,291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
(Notes 12 and 20) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unitholders equity: |
|
|
|
|
|
|
|
|
|
|
|
|
Unitholders capital |
|
(Note 10) |
|
|
1,412,294 |
|
|
|
1,377,875 |
|
Deficit |
|
|
|
|
|
|
(195,219 |
) |
|
|
(303,284 |
) |
|
|
|
|
|
|
|
|
1,217,075 |
|
|
|
1,074,591 |
|
|
|
|
|
|
|
|
$ |
1,761,186 |
|
|
$ |
1,718,882 |
|
|
See accompanying notes to consolidated financial statements.
Approved by the Board of Trustees:
|
|
|
|
|
(Signed) |
|
(Signed) |
|
|
|
Robert J.S. Gibson
|
|
Patrick M. Murray
|
|
|
Trustee
|
|
Trustee |
|
|
Precision Drilling Trust
CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS (DEFICIT)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
|
|
|
|
|
|
|
|
|
|
|
(Stated in thousands of Canadian dollars, except per unit/share amounts) |
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Revenue |
|
|
|
|
|
$ |
1,437,584 |
|
|
$ |
1,269,179 |
|
|
$ |
1,028,488 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
|
688,207 |
|
|
|
641,805 |
|
|
|
566,297 |
|
General and administrative |
|
|
|
|
|
|
81,217 |
|
|
|
76,397 |
|
|
|
64,149 |
|
Depreciation and amortization |
|
|
|
|
|
|
73,234 |
|
|
|
71,561 |
|
|
|
74,829 |
|
Foreign exchange |
|
|
|
|
|
|
(353 |
) |
|
|
(3,474 |
) |
|
|
(8,100 |
) |
Reorganization costs |
|
(Note 23) |
|
|
|
|
|
|
17,512 |
|
|
|
|
|
|
|
|
|
|
|
|
|
842,305 |
|
|
|
803,801 |
|
|
|
697,175 |
|
|
Operating earnings |
|
|
|
|
|
|
595,279 |
|
|
|
465,378 |
|
|
|
331,313 |
|
Interest: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
|
|
|
|
8,800 |
|
|
|
38,735 |
|
|
|
46,575 |
|
Other |
|
|
|
|
|
|
171 |
|
|
|
558 |
|
|
|
246 |
|
Income |
|
|
|
|
|
|
(942 |
) |
|
|
(10,023 |
) |
|
|
(541 |
) |
Premium on redemption of bonds |
|
(Note 8) |
|
|
|
|
|
|
71,885 |
|
|
|
|
|
Loss on disposal of short-term investments |
|
(Note 24) |
|
|
|
|
|
|
70,992 |
|
|
|
|
|
Other |
|
|
|
|
|
|
(408 |
) |
|
|
|
|
|
|
(4,899 |
) |
|
Earnings from continuing operations before income taxes |
|
|
|
|
|
|
587,658 |
|
|
|
293,231 |
|
|
|
289,932 |
|
Income taxes: |
|
(Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
34,526 |
|
|
|
241,402 |
|
|
|
53,698 |
|
Future |
|
|
|
|
|
|
(19,380 |
) |
|
|
(169,019 |
) |
|
|
48,103 |
|
|
|
|
|
|
|
|
|
15,146 |
|
|
|
72,383 |
|
|
|
101,801 |
|
|
Earnings from continuing operations |
|
|
|
|
|
|
572,512 |
|
|
|
220,848 |
|
|
|
188,131 |
|
Gain (loss) on disposal of discontinued operations,
net of tax |
|
(Note 24) |
|
|
7,077 |
|
|
|
1,335,382 |
|
|
|
(616 |
) |
Discontinued operations, net of tax |
|
(Note 24) |
|
|
|
|
|
|
74,333 |
|
|
|
59,889 |
|
|
Net earnings |
|
|
|
|
|
|
579,589 |
|
|
|
1,630,563 |
|
|
|
247,404 |
|
Retained earnings (deficit), beginning of year |
|
(Note 4) |
|
|
(303,284 |
) |
|
|
1,041,683 |
|
|
|
794,279 |
|
Adjustment on cash purchase of employee stock options,
net of tax of $22,060 |
|
(Note 23(c)) |
|
|
|
|
|
|
(42,087 |
) |
|
|
|
|
Reclassification from contributed surplus on cash
buy-out of employee stock options |
|
(Note 23(c)) |
|
|
|
|
|
|
23,215 |
|
|
|
|
|
Distribution of disposal proceeds |
|
(Note 24) |
|
|
|
|
|
|
(2,851,784 |
) |
|
|
|
|
Repurchase of common shares of
dissenting shareholders |
|
(Note 23(a)) |
|
|
|
|
|
|
(34,364 |
) |
|
|
|
|
Distributions declared |
|
(Note 7) |
|
|
(471,524 |
) |
|
|
(70,510 |
) |
|
|
|
|
|
Retained earnings (deficit), end of year |
|
|
|
|
|
$ |
(195,219 |
) |
|
$ |
(303,284 |
) |
|
$ |
1,041,683 |
|
|
Earnings per unit/share from continuing operations: |
|
(Note 13) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
|
|
|
$ |
4.56 |
|
|
$ |
1.79 |
|
|
$ |
1.63 |
|
Diluted |
|
|
|
|
|
$ |
4.56 |
|
|
$ |
1.76 |
|
|
$ |
1.61 |
|
|
Earnings per unit/share: |
|
(Note 13) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
|
|
|
$ |
4.62 |
|
|
$ |
13.22 |
|
|
$ |
2.14 |
|
Diluted |
|
|
|
|
|
$ |
4.62 |
|
|
$ |
13.00 |
|
|
$ |
2.11 |
|
|
See accompanying notes to consolidated financial statements.
Precision Drilling Trust
CONSOLIDATED STATEMENTS OF CASH FLOW
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
|
|
|
|
|
|
|
|
|
|
|
(Stated in thousands of Canadian dollars) |
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Cash provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
|
|
|
$ |
572,512 |
|
|
$ |
220,848 |
|
|
$ |
188,131 |
|
Adjustments and other items not involving cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term incentive plan compensation |
|
|
|
|
|
|
22,699 |
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
|
|
|
|
73,234 |
|
|
|
71,561 |
|
|
|
74,829 |
|
Future income taxes |
|
|
|
|
|
|
(19,380 |
) |
|
|
(169,019 |
) |
|
|
48,103 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
11,229 |
|
|
|
8,190 |
|
Write-off of deferred financing costs |
|
|
|
|
|
|
|
|
|
|
7,664 |
|
|
|
|
|
Loss in market value of short-term investments |
|
|
|
|
|
|
|
|
|
|
70,992 |
|
|
|
|
|
Amortization of deferred financing costs |
|
|
|
|
|
|
|
|
|
|
1,453 |
|
|
|
1,579 |
|
Unrealized foreign exchange gain on long-term monetary items |
|
|
|
|
|
|
|
|
|
|
(4,740 |
) |
|
|
(4,284 |
) |
Other |
|
|
|
|
|
|
(408 |
) |
|
|
|
|
|
|
(4,899 |
) |
Changes in non-cash working capital balances |
|
(Note 19) |
|
|
(38,913 |
) |
|
|
(3,975 |
) |
|
|
(25,212 |
) |
|
|
|
|
|
|
|
|
609,744 |
|
|
|
206,013 |
|
|
|
286,437 |
|
Discontinued operations: |
|
(Note 24) |
|
|
|
|
|
|
|
|
|
|
|
|
Funds provided by discontinued operations |
|
|
|
|
|
|
|
|
|
|
183,330 |
|
|
|
187,018 |
|
Changes in non-cash working capital balances
of discontinued operations |
|
|
|
|
|
|
|
|
|
|
(86,310 |
) |
|
|
(26,797 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
97,020 |
|
|
|
160,221 |
|
Investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business acquisitions, net of cash acquired |
|
(Notes 15 and 24) |
|
|
(16,428 |
) |
|
|
(30,421 |
) |
|
|
(679,814 |
) |
Purchase of property, plant and equipment |
|
|
|
|
|
|
(263,030 |
) |
|
|
(155,231 |
) |
|
|
(122,692 |
) |
Proceeds on sale of property, plant and equipment |
|
|
|
|
|
|
29,337 |
|
|
|
15,174 |
|
|
|
8,795 |
|
Proceeds on disposal of discontinued operations |
|
(Note 24) |
|
|
7,337 |
|
|
|
1,306,799 |
|
|
|
49,299 |
|
Proceeds on disposal of investments |
|
|
|
|
|
|
510 |
|
|
|
14,569 |
|
|
|
8,665 |
|
Purchase of property, plant and equipment of
discontinued operations |
|
|
|
|
|
|
|
|
|
|
(128,214 |
) |
|
|
(159,532 |
) |
Proceeds on sale of property, plant and equipment
of discontinued operations |
|
|
|
|
|
|
|
|
|
|
17,785 |
|
|
|
21,145 |
|
Purchase of intangibles |
|
|
|
|
|
|
|
|
|
|
(20 |
) |
|
|
|
|
Purchase of intangibles of discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(320 |
) |
Investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(90 |
) |
Changes in non-cash working capital balances |
|
(Note 19) |
|
|
7,551 |
|
|
|
(2,912 |
) |
|
|
1,384 |
|
|
|
|
|
|
|
|
|
(234,723 |
) |
|
|
1,037,529 |
|
|
|
(873,160 |
) |
Financing: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions paid |
|
(Note 7) |
|
|
(444,651 |
) |
|
|
(33,875 |
) |
|
|
|
|
Repayment of long-term debt |
|
|
|
|
|
|
(204,910 |
) |
|
|
(703,970 |
) |
|
|
(173,260 |
) |
Increase in long-term debt |
|
|
|
|
|
|
248,338 |
|
|
|
96,826 |
|
|
|
522,136 |
|
Issuance of Trust units |
|
|
|
|
|
|
9,896 |
|
|
|
|
|
|
|
|
|
Issuance of Trust units on exercise of options |
|
|
|
|
|
|
|
|
|
|
8,263 |
|
|
|
|
|
Issuance of Trust units on purchase of options |
|
|
|
|
|
|
|
|
|
|
5,504 |
|
|
|
|
|
Distribution of disposal proceeds |
|
(Note 24) |
|
|
|
|
|
|
(844,334 |
) |
|
|
|
|
Cash buy-out of employee stock options |
|
|
|
|
|
|
|
|
|
|
(64,147 |
) |
|
|
|
|
Repurchase of common shares of dissenting shareholders |
|
|
|
|
|
|
|
|
|
|
(43,299 |
) |
|
|
|
|
Issuance of common shares on exercise of options |
|
|
|
|
|
|
|
|
|
|
73,930 |
|
|
|
55,361 |
|
Issuance of common shares, net of costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
276,428 |
|
Deferred financing costs on long-term debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,612 |
) |
Changes in non-cash working capital balances |
|
|
|
|
|
|
|
|
|
|
22,060 |
|
|
|
|
|
Change in bank indebtedness |
|
|
|
|
|
|
16,306 |
|
|
|
20,468 |
|
|
|
(147,909 |
) |
|
|
|
|
|
|
|
|
(375,021 |
) |
|
|
(1,462,574 |
) |
|
|
527,144 |
|
|
Increase (decrease) in cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
(122,012 |
) |
|
|
100,642 |
|
Cash and cash equivalents, beginning of year |
|
|
|
|
|
|
|
|
|
|
122,012 |
|
|
|
21,370 |
|
|
Cash and cash equivalents, end of year |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
122,012 |
|
|
See accompanying notes to consolidated financial statements.
Precision Drilling Trust
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts are stated in thousands of Canadian dollars except unit/share numbers and per unit/share amounts)
NOTE 1. DESCRIPTION OF BUSINESS
Precision Drilling Trust (the Trust) is a provider of contract drilling, service rig and
ancillary services to oil and natural gas exploration and production companies in Canada and the
United States.
The Trust is an unincorporated open-ended investment trust governed by the laws of Alberta and
created pursuant to the Declaration of Trust dated September 22, 2005. On September 29, 2005, the
Trust, Precision Drilling Limited Partnership (PDLP), 1194312 Alberta Ltd., 1195309 Alberta
ULC., and Precision Drilling Corporation (Precision) entered into an Arrangement Agreement
(Plan of Arrangement or the Plan) to convert Precision to an income trust. As part of the
Plan of Arrangement, on November 7, 2005, Precision Drilling Corporation and certain of its
subsidiaries amalgamated, and continued as one corporation (PDC). After giving effect to the
Plan, and related transactions, all of the shares of PDC are owned by PDLP and indirectly by the
Trust.
Prior to the Plan of Arrangement effective date of November 7, 2005, the consolidated financial
statements included the accounts of Precision, its subsidiaries and its partnerships,
substantially all of which were wholly-owned. The conversion to a trust has been accounted for on
a continuity of interest basis and accordingly, the consolidated financial statements reflect the
financial position, results of operations and cash flows as if the Trust had always carried on
the business formerly carried on by Precision. Due to the conversion to a trust, certain
information included in the financial statements for prior periods may not be directly
comparable.
Pursuant to the Plan of Arrangement, shareholders ultimately received either Trust units or a
combination of Trust units and exchangeable LP units of PDLP for each previously held common
share of Precision (other than dissenting shareholders, who received cash equal to the fair value
of their shares). After giving effect to the Plan, the consolidated financial statements include
the accounts of the Trust, its subsidiaries and its partnerships.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
(a) Basis of presentation
The Trusts accounting policies are in accordance with Canadian generally accepted accounting
principles (GAAP). These policies are consistent with accounting principles generally accepted
in the United States in all material respects except as outlined in Note 16.
The preparation of the consolidated financial statements requires management to make estimates
and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses,
and the disclosure of contingencies. Significant estimates used in the preparation of the
financial statements include, but are not limited to, depreciation of property, plant and
equipment, valuation of long-lived assets and goodwill, allowance for doubtful accounts, accrual
for long-term incentive plan, and income taxes. Actual results could differ from these and other
estimates, the impact of which would be recorded in future periods.
Certain of the prior periods figures have been reclassified to conform to the current years
presentation.
(b) Principles of consolidation
The consolidated financial statements include the accounts of the Trust and all of its
subsidiaries and partnerships substantially all of which are wholly-owned. All significant
intercompany balances and transactions have been eliminated.
The Trust does not hold investments in any companies where it exerts significant influence and
does not hold interests in any variable interest entities.
(c) Cash and cash equivalents
Cash and cash equivalents consist of cash and short-term investments with original maturities of
three months or less.
(d) Inventory
Inventory is primarily comprised of operating supplies and is carried at the lower of average
cost, being the cost to acquire the inventory, and replacement cost. Inventory is charged to
operating expenses as items are sold or consumed at the amount of the average cost of the item.
(e) Property, plant and equipment
Property, plant and equipment are carried at cost, including costs of direct material and labour.
Where costs are incurred to extend the useful life of property, plant and equipment or to
increase its capabilities, the amounts are capitalized to the related asset. Costs incurred to
repair or maintain property, plant and equipment are expensed as incurred.
Property, plant, and equipment are depreciated as follows:
|
|
|
|
|
|
|
|
|
Expected life |
|
Salvage value |
|
Basis of depreciation |
|
Drilling rig equipment
|
|
5,000 (1) utilization days
|
|
20%
|
|
unit-of-production |
Drill pipe and drill collars
|
|
1,500 (1) operating days
|
|
|
|
unit-of-production |
Service rig equipment
|
|
24,000 service hours
|
|
20%
|
|
unit-of-production |
Drilling rig spare equipment
|
|
15 years
|
|
|
|
straight-line |
Rental equipment
|
|
10 to 15 years
|
|
|
|
straight-line |
Other equipment
|
|
3 to 10 years
|
|
|
|
straight-line |
Light duty vehicles
|
|
4 years
|
|
|
|
straight-line |
Heavy duty vehicles
|
|
7 to 10 years
|
|
|
|
straight-line |
Buildings
|
|
10 to 20 years
|
|
|
|
straight-line |
|
(f) Intangibles
Intangibles, which are comprised primarily of patents, are recorded at cost and amortized by the
straight-line method over their useful lives ranging from 10 to 12 years. The weighted average
amortization period is 12 years, and amortization over the next five years is anticipated to be
$90,000 per year for years one through four and $9,000 for year five.
(g) Goodwill
Goodwill is the amount that results when the purchase price of an acquired business exceeds the
sum of the amounts allocated to the assets acquired, less liabilities assumed, based on their
fair values. Goodwill is allocated as of the date of the business combination to the Trusts
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 segments goodwill
is compared with its carrying amount to measure the amount of the impairment loss, if any. The
implied fair value of goodwill is determined in the same manner as the value of goodwill is
determined in a business combination, as described in the preceding paragraph, using the fair
value of the reporting segment as if it was the purchase price. When the carrying amount of a
reporting segments goodwill exceeds the implied fair value of the goodwill, an impairment loss
is recognized in an amount equal to the excess.
(h) Long-lived assets
On a periodic basis, management assesses the carrying value of long-lived assets for indications
of impairment. Indications of impairment include an ongoing lack of profitability and significant
changes in technology. When an indication of impairment is present, the Trust tests for
impairment by comparing the carrying value of the asset to its net recoverable amount. If the
carrying amount is greater than the net recoverable amount, the asset is written down to its
estimated fair value.
(i) Income taxes
Income earned directly by PDLP is not subject to income taxes as its income is taxed directly to
the PDLP partners. The Trust is a taxable entity under the Income Tax Act (Canada) and income
earned is taxable only to the extent it is not distributed or distributable to its holders of
Trust units and exchangeable LP units (together Unitholders). As the Trust
distributes all of its taxable income to its respective Unitholders pursuant to the requirements
of the Declaration of Trust, it does not make a provision for future income taxes.
PDC and its subsidiaries follow the liability method of accounting for future income taxes. Under
the liability method, future income tax assets and liabilities are determined based on temporary
differences (differences between the accounting basis and the tax basis of the assets and
liabilities), and are measured using current or substantively enacted tax rates and laws expected
to apply when these differences reverse. The effect of a change in income tax rates on future tax
liabilities and assets is recognized in income in the period in which the change occurs.
During 2006 the Government of Canada released for comment draft legislation which would result in
a tax structure for trusts similar to that of corporate entities. If the proposed legislation is
implemented, the Trust would be required to recognize, on a prospective basis, future income
taxes on temporary differences in the Trust.
(j) Revenue recognition
The Trusts services are generally sold based upon purchase orders or contracts with a customer
that include fixed or determinable prices based upon daily, hourly or job rates. Customer
contract terms do not include provisions for significant post-service delivery obligations.
Revenue is recognized when services and equipment rentals are rendered and only when
collectability is reasonably assured.
(k) Employee benefit plans
At December 31, 2006, approximately 37% (2005 44%) of the employees of the Trusts subsidiaries
were enrolled in defined contribution retirement plans.
Employer contributions to defined contribution plans are expensed as employees earn the
entitlement and contributions are made.
(l) Long-term incentive plan
In 2006, the Trust instituted a long-term incentive plan (the LTIP) which compensates officers
and key employees through cash payments at the end of a three-year term. The compensation is
comprised of two components, a retention award and a performance award. The retention award is a
lump sum amount determined at the date of commencement in the LTIP and is accrued and charged to
earnings on a straight-line basis over the three-year term. The performance component is based on
the growth in cash distributions measured against a base distribution rate as determined by the
Compensation Committee of Precision. The estimated cost of the performance component is accrued
over the three-year term of the plan.
(m) Foreign currency translation
Accounts of the Trusts integrated foreign operations are translated to Canadian dollars using
average exchange rates for the month of the respective transaction for revenue and expenses.
Monetary assets and liabilities are translated at the year-end current exchange rate and
non-monetary assets and liabilities are translated using historical rates of exchange. Gains or
losses resulting from these translation adjustments are included in net earnings.
Transactions in foreign currencies are translated at rates in effect at the time of the
transaction. Monetary assets and liabilities are translated at current rates. Gains and losses
are included in net earnings.
(n) Stock-based compensation plans
The Trust had equity incentive plans in 2005 and prior periods, which are described in Note
23(c). The fair value of common share purchase options was calculated at the date of grant using
the Black-Scholes option pricing model and that value was recorded as compensation expense on a
straight-line basis over the grants vesting period with an offsetting credit to contributed
surplus. Upon exercise of the equity purchase option, the associated amount was reclassified from
contributed surplus to Unitholders capital as appropriate. Consideration paid by employees upon
exercise of equity purchase options was credited to Unitholders capital as appropriate.
(o) Exchangeable LP units
Exchangeable LP units are presented as equity of the Trust as their features make them
economically equivalent to Trust units.
(p) Per unit amounts
Basic per unit amounts are calculated using the weighted average number of Trust units
outstanding during the year. Diluted per unit amounts are calculated based on the treasury stock
method, which assumes that any proceeds obtained
on exercise of options would be used to purchase Trust units at the average market price during
the period. The weighted average number of units outstanding is then adjusted by the difference
between the number of units issued from the exercise of options and units repurchased from the
related proceeds.
The Trust had no dilutive instruments outstanding during the year ended December 31, 2006.
NOTE 3. ACCOUNTING ESTIMATES
Effective January 1, 2005, the Trust changed the useful life of its drilling rigs for
purposes of determining depreciation expense to 5,000 utilization days from 4,150 utilization
days (3,650 operating days), and its drill string to 1,500 from 1,100 operating days. Utilization
days include both operating and rig move days. This change in accounting estimate was applied
prospectively and resulted in a $10.7 million reduction in depreciation expense, or $0.09 per
diluted unit/share, for the year ended December 31, 2005.
NOTE 4. ACCOUNTING CHANGES
Stock-based compensation plans
Effective January 1, 2004, the Trust adopted the revised Canadian accounting standards with
respect to accounting for stock-based compensation. Under those standards, the fair value of
common share purchase options is calculated at the date of the grant and that value is recorded
as compensation expense over the vesting period of those grants. Under the previous standard, no
compensation expense was recorded when stock options were issued with any consideration received
upon exercise credited to share capital.
The Trust has retroactively applied this standard, with restatement of prior years, to all common
share purchase options granted since January 1, 2002. This has resulted in a charge to net
earnings for the year ended December 31, 2004 of $13.8 million or $0.11 diluted earnings per
share and a reduction to opening retained earnings of $14.5 million at January 1, 2004.
NOTE 5. PROPERTY, PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
Net Book |
|
2006 |
|
Cost |
|
|
Depreciation |
|
|
Value |
|
|
Rig equipment |
|
$ |
1,294,289 |
|
|
$ |
434,491 |
|
|
$ |
859,798 |
|
Rental equipment |
|
|
94,184 |
|
|
|
40,658 |
|
|
|
53,526 |
|
Other equipment |
|
|
95,137 |
|
|
|
61,317 |
|
|
|
33,820 |
|
Vehicles |
|
|
78,675 |
|
|
|
24,461 |
|
|
|
54,214 |
|
Buildings |
|
|
29,583 |
|
|
|
9,673 |
|
|
|
19,910 |
|
Assets under construction |
|
|
76,239 |
|
|
|
|
|
|
|
76,239 |
|
Land |
|
|
10,110 |
|
|
|
|
|
|
|
10,110 |
|
|
|
|
$ |
1,678,217 |
|
|
$ |
570,600 |
|
|
$ |
1,107,617 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
Net Book |
|
2005 |
|
Cost |
|
|
Depreciation |
|
|
Value |
|
|
Rig equipment |
|
$ |
1,143,786 |
|
|
$ |
386,191 |
|
|
$ |
757,595 |
|
Rental equipment |
|
|
81,099 |
|
|
|
35,307 |
|
|
|
45,792 |
|
Other equipment |
|
|
102,727 |
|
|
|
62,852 |
|
|
|
39,875 |
|
Vehicles |
|
|
68,911 |
|
|
|
20,703 |
|
|
|
48,208 |
|
Buildings |
|
|
32,830 |
|
|
|
9,580 |
|
|
|
23,250 |
|
Assets under construction |
|
|
20,184 |
|
|
|
|
|
|
|
20,184 |
|
Land |
|
|
8,996 |
|
|
|
|
|
|
|
8,996 |
|
|
|
|
$ |
1,458,533 |
|
|
$ |
514,633 |
|
|
$ |
943,900 |
|
|
NOTE 6. BANK INDEBTEDNESS
At December 31, 2006 and 2005, the Trust had available $60.0 million and US$5.0 million
under uncommitted, unsecured credit facilities, of which $36.8 million had been drawn (2005 -
$20.5 million). Availability of these facilities were reduced by outstanding letters of credit in
the amount of $4.0 million (2005 $8.4 million). Advances under the facilities are available at
the banks prime lending rate, U.S. base rate, U.S. Libor plus applicable margin or Bankers
Acceptance plus applicable margin, or in combination. As at December 31, 2006, the amounts drawn
under these facilities were at the banks prime lending rate of 6% (2005 5%).
NOTE 7. DISTRIBUTIONS
The beneficiaries of the Trust are the holders of Trust units and the partners of PDLP are
the holders of exchangeable LP units and the Trust. The monthly distributions made by the Trust
to Unitholders are determined by the Trustees. PDLP earns interest income from a promissory note
issued by its subsidiary PDC at a rate which is determined by the terms of the promissory note.
PDLP in substance pays distributions to holders of exchangeable LP units in amounts equal to the
distributions paid to the holders of Trust units. All distributions are made to Unitholders of
record on the last business day of each calendar month.
The Declaration of Trust provides that an amount equal to net income of the Trust not already
paid to Unitholders in the year will become payable on December 31 of each year such that the
Trust will not be liable for ordinary income taxes for such year.
A distribution reinvestment plan (the DRIP) was approved by the Board of Trustees in February
2006, and implemented in March 2006. The DRIP allows certain holders of Trust units, at their
option, to reinvest monthly cash distributions to acquire additional Trust units at the average
market price as defined in the DRIP. Unitholders who are not resident in Canada or hold
exchangeable LP units are not eligible to participate in the DRIP. The Trust reserved the right
to amend, suspend, or terminate the DRIP at any time. The DRIP was suspended in December 2006.
A summary of the distributions is as follows:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
Declared |
|
$ |
471,524 |
|
|
$ |
70,510 |
|
Paid |
|
$ |
444,651 |
|
|
$ |
33,875 |
|
Payable in cash at December 31 |
|
$ |
38,985 |
|
|
$ |
36,635 |
|
Payable in units at December 31 |
|
$ |
24,523 |
|
|
$ |
|
|
|
Included in the 2006 distributions declared is a special non-cash distribution of $24.5
million ($0.195 per unit). This special distribution was settled on January 16, 2007 through the
issuance of units. Immediately following the issuance of these units, the Trust consolidated the
units such that the number of Trust units and exchangeable LP units remained unchanged from the
number outstanding prior to the special distribution.
NOTE 8. LONG-TERM DEBT
Extendible revolving unsecured facility:
At December 31, 2006, PDC, a subsidiary of the Trust, has available a three-year revolving
unsecured facility of $700.0 million (or U.S. equivalent) (2005 $550.0 million) with a
syndicate led by a Canadian chartered bank, which is guaranteed by the Trust. The facility
matures on November 2, 2009 and is renewable annually at the option of the lenders. Advances are
available to PDC under this facility either at the banks prime lending rate, U.S. base rate,
U.S. Libor plus applicable margin or Bankers Acceptance plus applicable margin or in
combination. The applicable margin is dependent on the Trusts consolidated debt to cash flow
ratio and the percentage of the total facility outstanding, which at December 31, 2006 and 2005
was 75 basis points. The facility requires that the Trust maintain a ratio of total liabilities
to total equity of less than 1:1, a trailing 12 month ratio of consolidated debt to cash flow of
less than 2.75:1 and total distributions to Unitholders of less than 100% of consolidated cash
flow as defined in the facility agreement. As at December 31, 2006, the Trust had drawn $140.9
million (2005 $96.8 million) under this facility.
Unsecured debentures and notes:
During the fourth quarter of 2005, Precision repaid all of its outstanding debentures and notes
pursuant to the early redemption provisions of the related agreements. The difference between the
$766.7 million redemption price and the carrying value of the debentures was charged to
income.
NOTE 9. INCOME TAXES
The provision for income taxes differs from that which would be expected by applying
Canadian statutory income tax rates as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Earnings from continuing operations before income taxes |
|
$ |
587,658 |
|
|
$ |
293,231 |
|
|
$ |
289,932 |
|
Federal and provincial statutory rates |
|
|
33 |
% |
|
|
34 |
% |
|
|
36 |
% |
|
Tax at statutory rates |
|
$ |
193,927 |
|
|
$ |
99,699 |
|
|
$ |
104,375 |
|
Adjusted for the effect of: |
|
|
|
|
|
|
|
|
|
|
|
|
Non-deductible expenses |
|
|
297 |
|
|
|
2,795 |
|
|
|
4,965 |
|
Non-deductible stock-based compensation |
|
|
|
|
|
|
3,216 |
|
|
|
2,948 |
|
Income to be distributed to Unitholders, not subject to
tax in the Trust |
|
|
(155,354 |
) |
|
|
(23,980 |
) |
|
|
|
|
Utilization of losses and surcharge credits |
|
|
|
|
|
|
(10,550 |
) |
|
|
|
|
Other |
|
|
(2,896 |
) |
|
|
1,203 |
|
|
|
(7,600 |
) |
|
Income tax expense before tax rate reductions |
|
|
35,974 |
|
|
|
72,383 |
|
|
|
104,688 |
|
Reduction of future income tax balances due to
enacted tax rate reductions |
|
|
(20,828 |
) |
|
|
|
|
|
|
(2,887 |
) |
|
Income tax expense |
|
$ |
15,146 |
|
|
$ |
72,383 |
|
|
$ |
101,801 |
|
|
Effective income tax rate before enacted tax rate reductions |
|
|
6 |
% |
|
|
25 |
% |
|
|
36 |
% |
|
In 2006 the federal and certain provincial governments enacted various reductions to
corporate income tax rates. The Government of Canada introduced tax rate reductions to be
implemented over the next four years that will decrease the federal corporate income tax rate
from 21% to 19%. The federal corporate capital tax was eliminated effective January 1, 2006 and
the federal corporate surtax will be eliminated in 2008. The Province of Alberta reduced the
corporate income tax rate by 1.5% (2004 1.0%) effective April 1, 2006. These and other
provincial corporate income tax rate reductions have been reflected as a reduction of future tax
expense.
The net future tax liability is comprised of the tax effect of the following temporary differences:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
Future income tax liability: |
|
|
|
|
|
|
|
|
Property, plant and equipment and intangibles |
|
$ |
213,281 |
|
|
$ |
232,277 |
|
|
Future income tax assets: |
|
|
|
|
|
|
|
|
Bond redemption premium |
|
|
13,314 |
|
|
|
20,820 |
|
Losses carried forward |
|
|
9,884 |
|
|
|
14,586 |
|
Share issue costs |
|
|
1,966 |
|
|
|
3,039 |
|
Long-term incentive plan |
|
|
10,614 |
|
|
|
|
|
Accrued liabilities |
|
|
2,937 |
|
|
|
1,910 |
|
Valuation allowance |
|
|
(5 |
) |
|
|
(595 |
) |
|
|
|
|
38,710 |
|
|
|
39,760 |
|
|
Net future income tax liability |
|
$ |
174,571 |
|
|
$ |
192,517 |
|
|
PDC and its subsidiaries have available net capital losses of $33.6 million of which, after
valuation allowances, the benefit of $33.6 million has been recognized. These capital losses can
be carried forward indefinitely.
During 2004, $7.5 million representing future tax expense on foreign exchange gains
associated with the Trusts U.S.$300 million unsecured notes was charged to the cumulative
translation account in Unitholders equity. This amount was related to the Trusts discontinued
operations.
NOTE 10. UNITHOLDERS CAPITAL
(a) Authorized unlimited number of voting Trust units
unlimited number of voting exchangeable LP units
(b) Unitholders capital
|
|
|
|
|
|
|
|
|
Trust units |
|
Number |
|
|
Amount |
|
|
Balance, November 7, 2005 |
|
|
|
|
|
$ |
|
|
Issued pursuant to the Plan |
|
|
122,512,799 |
|
|
|
1,339,646 |
|
Options
exercised cash consideration |
|
|
1,676,616 |
|
|
|
8,263 |
|
reclassification from contributed surplus |
|
|
|
|
|
|
12,342 |
|
Issued for cash |
|
|
163,506 |
|
|
|
5,504 |
|
|
Balance, December 31, 2005 |
|
|
124,352,921 |
|
|
|
1,365,755 |
|
Issued pursuant to distribution reinvestment plan (Note 7) |
|
|
296,621 |
|
|
|
9,896 |
|
Issued on retraction of exchangeable LP units |
|
|
886,787 |
|
|
|
9,697 |
|
Issued and
consolidated pursuant to special distribution (Note 7) |
|
|
|
|
|
|
24,480 |
|
|
Balance, December 31, 2006 |
|
|
125,536,329 |
|
|
$ |
1,409,828 |
|
|
Trust units are redeemable at the option of the holder, at which time all rights with
respect to such units are cancelled. Upon redemption, the unitholder is entitled to receive a
price per unit equal to the lesser of 90% of the average market price of the Trusts units for
the 10 trading days just prior to the date of redemption, and the closing market price of the
Trusts units on the date of redemption. The maximum value of units that can be redeemed for cash
is $50,000 per month. Redemptions, if any, in excess of this amount are satisfied by issuing a
note from PDC to the unitholder, payable over 15 years and bearing interest at a market rate set
by the Board of Directors.
|
|
|
|
|
|
|
|
|
Exchangeable LP units |
|
Number |
|
|
Amount |
|
|
Balance, November 7, 2005 |
|
|
|
|
|
$ |
|
|
Issued pursuant to the Plan |
|
|
1,108,382 |
|
|
|
12,120 |
|
|
Balance, December 31, 2005 |
|
|
1,108,382 |
|
|
|
12,120 |
|
Redeemed on retraction of exchangeable LP units |
|
|
(886,787 |
) |
|
|
(9,697 |
) |
Issued and consolidated pursuant to special distribution (Note 7) |
|
|
|
|
|
|
43 |
|
|
Balance, December 31, 2006 |
|
|
221,595 |
|
|
$ |
2,466 |
|
|
Exchangeable LP units have voting rights and were exchangeable, after May 6, 2006, for
Trust units on a one-for-one basis at the option of the holder. Holders are entitled to monthly
cash distributions equal to those paid to holders of Trust units.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Summary as at December 31, |
|
Number |
|
|
Amount |
|
|
Number |
|
|
Amount |
|
|
Trust units |
|
|
125,536,329 |
|
|
$ |
1,409,828 |
|
|
|
124,352,921 |
|
|
$ |
1,365,755 |
|
Exchangeable LP units |
|
|
221,595 |
|
|
|
2,466 |
|
|
|
1,108,382 |
|
|
|
12,120 |
|
|
Unitholders capital |
|
|
125,757,924 |
|
|
$ |
1,412,294 |
|
|
|
125,461,303 |
|
|
$ |
1,377,875 |
|
|
NOTE 11. EMPLOYEE BENEFIT PLANS
The Trust has registered pension plans covering a significant number of its employees.
(a) Defined contribution plan
Under the defined contribution plan, the Trust matches individual contributions up to 5% of the
employees compensation. Total expense under the defined contribution plan in 2006 was $5.5
million (2005 $8.5 million; 2004
$7.3 million), of which $nil (2005 $3.2 million; 2004 $3.0 million) relates to discontinued operations.
(b) Retirement allowance
The Trust had entered into an employment agreement with a senior officer, which provided for a
one-time payment upon
retirement. The amount of this retirement allowance increased by a fixed amount for each
year of service over a ten year period commencing April 30, 1996. The estimated cost of this
benefit was being accrued and charged to earnings on a straight-line basis over the ten year
period. During the year ended December 31, 2005, the Trust charged $201,000 (2004 $335,000) and
paid $2.9 million as final settlement of this liability.
NOTE 12. COMMITMENTS
The Trust has commitments for operating lease agreements, primarily for vehicles and office
space, in the aggregate amount of $26.5 million. Payments over the next five years are as
follows:
|
|
|
|
|
|
|
Total |
|
|
2007 |
|
$ |
7,858 |
|
2008 |
|
|
6,551 |
|
2009 |
|
|
4,820 |
|
2010 |
|
|
4,044 |
|
2011 |
|
|
3,265 |
|
|
Rent expense included in the statements of earnings is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing |
|
|
Discontinued |
|
|
|
|
|
|
Operations |
|
|
Operations |
|
|
Total |
|
|
2006 |
|
$ |
4,189 |
|
|
$ |
|
|
|
$ |
4,189 |
|
2005 |
|
|
3,836 |
|
|
|
11,983 |
|
|
|
15,819 |
|
2004 |
|
|
5,874 |
|
|
|
17,284 |
|
|
|
23,158 |
|
|
NOTE 13. PER UNIT/SHARE AMOUNTS
The following table summarizes the units, adjusted retroactively for a 2 for 1 stock split
on May 18, 2005, used in calculating earnings per unit/share:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Stated in thousands) |
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Weighted average units/shares outstanding basic |
|
|
125,545 |
|
|
|
123,304 |
|
|
|
115,654 |
|
Effect of stock options |
|
|
|
|
|
|
2,108 |
|
|
|
1,556 |
|
|
Weighted average units/shares outstanding diluted |
|
|
125,545 |
|
|
|
125,412 |
|
|
|
117,210 |
|
|
NOTE 14. SIGNIFICANT CUSTOMERS
During the year ended December 31, 2006 no customers (2005 no customers; 2004 one
customer) accounted for more than 10% of the Trusts revenue.
NOTE 15. BUSINESS ACQUISITIONS
Acquisitions have been accounted for by the purchase method with results of operations
acquired included in the consolidated financial statements from the closing date of acquisition.
Acquisitions relating to discontinued operations are reflected in Note 24.
On August 17, 2006, the Trust acquired all of the shares of Terra Water Group Ltd. (Terra), a
privately owned provider of wastewater treatment units for the traditional drilling rig camp
market in western Canada. The Terra operations are included in the Completion and Production
Services segment. The acquisition has been accounted for by the purchase method with the results
of operations included in the financial statements from the date of acquisition. The details of
the acquisition are as follows:
|
|
|
|
|
Net assets acquired at assigned values: |
|
|
|
|
Working capital (1) |
|
$ |
207 |
|
Property, plant and equipment |
|
|
3,168 |
|
Goodwill (no tax basis) |
|
|
13,922 |
|
Long-term debt |
|
|
(614 |
) |
Future income taxes |
|
|
(212 |
) |
|
|
|
$ |
16,471 |
|
|
Consideration: |
|
|
|
|
Cash |
|
$ |
16,471 |
|
|
|
|
|
(1) |
|
Working capital includes cash of $43 |
NOTE 16. UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
These financial statements have been prepared in accordance with Canadian GAAP which
conform with United States generally accepted accounting principles (U.S. GAAP) in all material
respects, except as follows:
(a) Income taxes
In 2000 the Trust adopted the liability method of accounting for future income taxes without
restatement of prior years. As a result, the Trust recorded an adjustment to retained earnings
and future tax liability in the amount of $70.0 million at January 1, 2000. U.S. GAAP required
the use of the liability method prescribed in the Statement of Financial Accounting Standards
(SFAS) No. 109, which substantially conforms to the Canadian GAAP accounting standard adopted in
2000. Application of U.S. GAAP in years prior to 2000 would have resulted in $70.0 million of
additional goodwill being recognized at January 1, 2000 as opposed to an implementation
adjustment to retained earnings allowed under Canadian GAAP. Prior to 2002 goodwill was amortized
under Canadian and U.S. GAAP. As a result, $7.0 million of amortization was recorded on the
additional goodwill in 2000 and 2001 under U.S. GAAP. In 2005 and 2006 the U.S. GAAP financial
statements would reflect an increase in goodwill of $63.0 million and a corresponding increase in
retained earnings.
(b) Stock-based compensation
In 2004, under Canadian GAAP, the Trust adopted the fair value of accounting for stock-based
compensation with restatement of prior years for share purchase options granted after January 1,
2002. U.S. GAAP allows the use of either the intrinsic method, as prescribed by Accounting
Principles Board (APB) Opinion 25, or the fair value method as prescribed by SFAS 123. Where
companies elect to use the intrinsic method, disclosure of the impact of using the fair value
method is required.
Application of the intrinsic method in accordance with APB Opinion 25 would have resulted in an
increase in net earnings of $21.3 million for 2005 (2004 $13.8 million) with a corresponding
increase in Unitholders equity. Had the Trust determined compensation based on the fair value at
the date of grant for its options under SFAS 123, net earnings in accordance with U.S. GAAP would
have decreased to $1,588.5 million in 2005 (2004 decreased to $247.8 million). Basic earnings
per unit/share would have been $12.88 in 2005 (2004 $2.14).
Under Financial Accounting Standards Board (FASB) Interpretation No. 44 (FIN 44) Accounting
for Certain Transactions Involving Stock Compensation, compensation expense is required to be
recognized on certain modifications to stock-based compensation plans. During the year ended
December 31, 2005, employee stock options (options) were subjected to a variety of changes or
restructurings which included accelerated vesting, repricing on the date of conversion to an
income trust to reflect the distribution of disposal consideration to Precisions shareholders
just prior to conversion, or repurchase for cash depending on elections made by the option
holders. Under Canadian GAAP, even with repricing, the options were treated as equity awards and
were not accounted for under a variable accounting method. However, under U.S. GAAP, the
accelerated vesting represents a restructuring in the form of a modification that would result in
a new measurement of compensation expense on the date of the modification to the date of exercise
using the intrinsic method. For award repricing, this restructuring only results in additional
expense provided that the aggregate intrinsic value of the awards immediately after the change is
not greater than that immediately before, and the ratio of exercise price per unit/share to the
market value per unit/share is not reduced. To the extent that both criteria are not met, the
awards are accounted for under ABP Opinion 25 as a variable award from the date of restructuring
to the date the award was exercised. For restructuring in the form of cash buy-out of the
options, the intrinsic value was charged to retained earnings under Canadian GAAP, however, under
U.S. GAAP the amount was charged to earnings.
(c) Redemption of Trust units
Under the Declaration of Trust, Trust units are redeemable at any time on demand by the
unitholder for cash and notes
(see Note 10). Under U.S. GAAP, the amount included on the consolidated balance sheet for
Unitholders equity would be moved to temporary equity and recorded at an amount equal to the
redemption value of the Trust units as at the balance sheet date. The same accounting treatment
would be applicable to the exchangeable LP units. The redemption value of the Trust units and the
exchangeable LP units is determined with respect to the trading value of the Trust units as at
each balance sheet date, and the amount of the redemption value is classified as temporary
equity. Changes (increases and decreases) in the redemption value during a period results in a
change to temporary equity and is charged to retained earnings.
(d) Acquisitions
Under U.S. GAAP, when significant acquisitions have occurred, supplemental disclosure is required
on a pro forma basis of the results of operations for the current prior periods as though the
business combination had occurred at the beginning of the period unless it is not practicable to
do so. At December 31, 2005, the Trust did not have access to sufficient information to provide
this disclosure for acquisitions completed in 2004. No significant acquisitions occurred in 2006.
(e) Recently issued accounting pronouncements
On September 15, 2006, FASB issued SFAS 157, Fair Value Measurements. The statement provides
enhanced guidance for using fair value to measure assets and liabilities, but does not expand the
use of fair value in any new circumstances. The new standard is effective for fiscal years
beginning after November 15, 2007, and will be effective for the Trusts December 31, 2008 year
end. Management does not expect this statement to have a material impact on the consolidated
financial statements.
In June 2006, FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109. The interpretation clarifies the accounting for
uncertainty in income taxes by prescribing a consistent recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax position taken or
expected to be taken on a tax return. The interpretation is effective for fiscal years beginning
after December 15, 2006, and will be effective for the Trusts December 31, 2007 year end. The
impact of this interpretation is yet to be determined by management.
On February 16, 2006, FASB issued SFAS 155, Accounting for Certain Hybrid Financial Instruments -
an amendment of FASB Statements no. 133 and 140. The statement clarifies and simplifies the
financial reporting of certain hybrid financial instruments by requiring more consistent
accounting that eliminates exemptions. The new standard is effective for financial instruments
acquired or issued after the beginning of an entitys first fiscal year that begins after
September 15, 2006, and will be effective for the Trusts first quarter of the December 31, 2007
year end. Management does not expect this statement to have a material impact on the consolidated
financial statements.
The application of U.S. GAAP accounting principles would have the following impact on the
consolidated financial statements:
Consolidated Statements of Earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Earnings from continuing operations under Canadian GAAP |
|
$ |
572,512 |
|
|
$ |
220,848 |
|
|
$ |
188,131 |
|
Adjustments under U.S. GAAP: |
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense |
|
|
|
|
|
|
11,229 |
|
|
|
8,190 |
|
Cash buy-out of options |
|
|
|
|
|
|
(22,119 |
) |
|
|
|
|
Intrinsic value recognized on options exercised and/or repriced |
|
|
|
|
|
|
(2,270 |
) |
|
|
|
|
|
Earnings from continuing operations under U.S. GAAP |
|
|
572,512 |
|
|
|
207,688 |
|
|
|
196,321 |
|
|
Earnings from discontinued operations under Canadian GAAP |
|
|
7,077 |
|
|
|
1,409,715 |
|
|
|
59,273 |
|
Adjustments under U.S. GAAP: |
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense |
|
|
|
|
|
|
10,109 |
|
|
|
5,647 |
|
Cash buy-out of options |
|
|
|
|
|
|
(19,968 |
) |
|
|
|
|
Intrinsic value recognized on options exercised and/or repriced |
|
|
|
|
|
|
(11,796 |
) |
|
|
|
|
|
Earnings from discontinued operations under U.S. GAAP |
|
|
7,077 |
|
|
|
1,388,060 |
|
|
|
64,920 |
|
|
Net earnings under U.S. GAAP |
|
|
579,589 |
|
|
|
1,595,748 |
|
|
|
261,241 |
|
Cumulative translation adjustment |
|
|
|
|
|
|
|
|
|
|
(20,933 |
) |
|
Comprehensive income under U.S. GAAP |
|
$ |
579,589 |
|
|
$ |
1,595,748 |
|
|
$ |
240,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Earnings from continuing operations per unit/share under U.S. GAAP: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
4.56 |
|
|
$ |
1.68 |
|
|
$ |
1.70 |
|
Diluted |
|
$ |
4.56 |
|
|
$ |
1.66 |
|
|
$ |
1.67 |
|
Earnings per unit/share under U.S. GAAP: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
4.62 |
|
|
$ |
12.94 |
|
|
$ |
2.26 |
|
Diluted |
|
$ |
4.62 |
|
|
$ |
12.72 |
|
|
$ |
2.23 |
|
|
Consolidated Statements of Retained Earnings (Deficit)
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Retained earnings (deficit) under U.S. GAAP, beginning of year |
|
$ |
(3,167,045 |
) |
|
$ |
1,133,030 |
|
|
$ |
871,789 |
|
Net earnings under U.S. GAAP |
|
|
579,589 |
|
|
|
1,595,748 |
|
|
|
261,241 |
|
Distributions declared |
|
|
(471,524 |
) |
|
|
(70,510 |
) |
|
|
|
|
Distribution of disposal proceeds |
|
|
|
|
|
|
(2,851,784 |
) |
|
|
|
|
Repurchase of common shares of dissenting shareholders |
|
|
|
|
|
|
(34,364 |
) |
|
|
|
|
Opening temporary equity on conversion to an income trust |
|
|
|
|
|
|
(2,560,709 |
) |
|
|
|
|
Change in redemption value of temporary equity |
|
|
1,185,490 |
|
|
|
(378,456 |
) |
|
|
|
|
|
Retained earnings (deficit) under U.S. GAAP, end of year |
|
$ |
(1,873,490 |
) |
|
$ |
(3,167,045 |
) |
|
$ |
1,133,030 |
|
|
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
As at December 31, |
|
As reported |
|
|
U.S. GAAP |
|
|
As reported |
|
|
U.S. GAAP |
|
|
Current assets |
|
$ |
372,445 |
|
|
$ |
372,445 |
|
|
$ |
507,690 |
|
|
$ |
507,690 |
|
Property, plant and equipment |
|
|
1,107,617 |
|
|
|
1,107,617 |
|
|
|
943,900 |
|
|
|
943,900 |
|
Intangibles |
|
|
375 |
|
|
|
375 |
|
|
|
465 |
|
|
|
465 |
|
Goodwill |
|
|
280,749 |
|
|
|
343,778 |
|
|
|
266,827 |
|
|
|
329,856 |
|
|
|
|
$ |
1,761,186 |
|
|
$ |
1,824,215 |
|
|
$ |
1,718,882 |
|
|
$ |
1,781,911 |
|
|
Current liabilities |
|
$ |
205,961 |
|
|
$ |
205,961 |
|
|
$ |
354,936 |
|
|
$ |
354,936 |
|
Long-term incentive plan payable |
|
|
22,699 |
|
|
|
22,699 |
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
140,880 |
|
|
|
140,880 |
|
|
|
96,838 |
|
|
|
96,838 |
|
Future income taxes |
|
|
174,571 |
|
|
|
174,571 |
|
|
|
192,517 |
|
|
|
192,517 |
|
Temporary equity |
|
|
|
|
|
|
3,153,594 |
|
|
|
|
|
|
|
4,304,665 |
|
Unitholders capital |
|
|
1,412,294 |
|
|
|
|
|
|
|
1,377,875 |
|
|
|
|
|
Deficit |
|
|
(195,219 |
) |
|
|
(1,873,490 |
) |
|
|
(303,284 |
) |
|
|
(3,167,045 |
) |
|
|
|
$ |
1,761,186 |
|
|
$ |
1,824,215 |
|
|
$ |
1,718,882 |
|
|
$ |
1,781,911 |
|
|
NOTE 17. SEGMENTED INFORMATION
The Trust operates primarily in Canada, in two industry segments; Contract Drilling
Services and Completion and Production Services. Contract Drilling Services includes drilling
rigs, procurement and distribution of oilfield supplies, camp and catering services, and
manufacture, sale and repair of drilling equipment. Completion and Production Services includes
service rigs, snubbing units, wastewater treatment units, and oilfield equipment rental.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract |
|
|
Completion and |
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
|
Production |
|
|
Corporate |
|
|
Inter-segment |
|
|
|
|
2006 |
|
Services |
|
|
Services |
|
|
and Other |
|
|
Eliminations |
|
|
Total |
|
|
Revenue |
|
$ |
1,009,821 |
|
|
$ |
441,017 |
|
|
$ |
|
|
|
$ |
(13,254 |
) |
|
$ |
1,437,584 |
|
Operating earnings |
|
|
473,624 |
|
|
|
163,119 |
|
|
|
(41,464 |
) |
|
|
|
|
|
|
595,279 |
|
Depreciation and amortization |
|
|
38,573 |
|
|
|
32,013 |
|
|
|
2,648 |
|
|
|
|
|
|
|
73,234 |
|
Total assets |
|
|
1,198,284 |
|
|
|
507,510 |
|
|
|
55,392 |
|
|
|
|
|
|
|
1,761,186 |
|
Goodwill |
|
|
172,440 |
|
|
|
108,309 |
|
|
|
|
|
|
|
|
|
|
|
280,749 |
|
Capital expenditures* |
|
|
220,397 |
|
|
|
39,273 |
|
|
|
3,360 |
|
|
|
|
|
|
|
263,030 |
|
|
* Excludes business acquisitions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract |
|
|
Completion and |
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
|
Production |
|
|
Corporate |
|
|
Inter-segment |
|
|
|
|
2005 |
|
Services |
|
|
Services |
|
|
and Other |
|
|
Eliminations |
|
|
Total |
|
|
Revenue |
|
$ |
916,221 |
|
|
$ |
369,667 |
|
|
$ |
|
|
|
$ |
(16,709 |
) |
|
$ |
1,269,179 |
|
Operating earnings |
|
|
404,385 |
|
|
|
121,643 |
|
|
|
(60,650 |
) |
|
|
|
|
|
|
465,378 |
|
Depreciation and amortization |
|
|
39,233 |
|
|
|
27,402 |
|
|
|
4,926 |
|
|
|
|
|
|
|
71,561 |
|
Total assets |
|
|
1,159,687 |
|
|
|
486,701 |
|
|
|
72,494 |
|
|
|
|
|
|
|
1,718,882 |
|
Goodwill |
|
|
172,440 |
|
|
|
94,387 |
|
|
|
|
|
|
|
|
|
|
|
266,827 |
|
Capital expenditures* |
|
|
106,986 |
|
|
|
34,576 |
|
|
|
13,689 |
|
|
|
|
|
|
|
155,251 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract |
|
|
Completion and |
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
|
Production |
|
|
Corporate |
|
|
Inter-segment |
|
|
|
|
2004 |
|
Services |
|
|
Services |
|
|
and Other |
|
|
Eliminations |
|
|
Total |
|
|
Revenue |
|
$ |
727,710 |
|
|
$ |
313,386 |
|
|
$ |
|
|
|
$ |
(12,608 |
) |
|
$ |
1,028,488 |
|
Operating earnings |
|
|
282,315 |
|
|
|
77,074 |
|
|
|
(28,076 |
) |
|
|
|
|
|
|
331,313 |
|
Depreciation and amortization |
|
|
42,245 |
|
|
|
27,508 |
|
|
|
5,076 |
|
|
|
|
|
|
|
74,829 |
|
Total assets |
|
|
971,863 |
|
|
|
461,191 |
|
|
|
180,009 |
|
|
|
|
|
|
|
1,613,063 |
|
Goodwill |
|
|
172,440 |
|
|
|
94,387 |
|
|
|
|
|
|
|
|
|
|
|
266,827 |
|
Capital expenditures* |
|
|
74,975 |
|
|
|
31,759 |
|
|
|
15,958 |
|
|
|
|
|
|
|
122,692 |
|
|
* Excludes business acquisitions
NOTE 18. FINANCIAL INSTRUMENTS
(a) Fair value
The carrying value of cash and cash equivalents, accounts receivable, income taxes recoverable,
bank indebtedness, accounts payable and accrued liabilities, income tax payable and distributions
payable approximate their fair value due to the relatively short period to maturity of the
instruments.
(b) Credit risk
Accounts receivable includes balances from a large number of customers primarily operating in the
oil and gas industry. The Trust assesses the creditworthiness of its customers on an ongoing
basis as well as monitoring the amount and age of balances outstanding. Accordingly, the Trust
views the credit risks on these amounts as normal for the industry. As at December 31, 2006 the
Trusts allowance for doubtful accounts was $5.6 million (2005 $5.1 million).
(c) Interest rate risk
The Trust is exposed to interest rate risk with respect to interest expense on its credit
facilities.
(d) Foreign currency risk
The Trust was exposed to foreign currency fluctuations in relation to its international
operations prior to their disposal in 2005 (see Note 24). To manage a portion of this exposure,
the Trust designated US$300.0 million notes as a hedge against foreign currency fluctuations of
its investment in self-sustaining foreign operations. A net foreign exchange gain of $10.1
million associated with these notes was included in the cumulative translation account during
2005 (2004 gain of $43.1 million). The cumulative translation account at August 31, 2005 of
$24.8 million was charged to the gain on disposal of discontinued operations in 2005.
NOTE 19. SUPPLEMENTAL INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Interest paid: |
|
|
|
|
|
|
|
|
|
|
|
|
continuing operations |
|
$ |
8,929 |
|
|
$ |
43,232 |
|
|
$ |
45,338 |
|
discontinued operations |
|
|
|
|
|
|
304 |
|
|
|
997 |
|
|
|
|
$ |
8,929 |
|
|
$ |
43,536 |
|
|
$ |
46,335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid: |
|
|
|
|
|
|
|
|
|
|
|
|
continuing operations |
|
$ |
207,160 |
|
|
$ |
91,496 |
|
|
$ |
38,759 |
|
discontinued operations |
|
|
|
|
|
|
35,176 |
|
|
|
35,935 |
|
|
|
|
$ |
207,160 |
|
|
$ |
126,672 |
|
|
$ |
74,694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of change in non-cash working capital balances: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
$ |
148,046 |
|
|
$ |
(171,363 |
) |
|
$ |
(42,714 |
) |
Inventory |
|
|
(2,038 |
) |
|
|
699 |
|
|
|
(2,017 |
) |
Accounts payable and accrued liabilities |
|
|
(4,736 |
) |
|
|
13,871 |
|
|
|
5,964 |
|
Income taxes |
|
|
(172,634 |
) |
|
|
149,906 |
|
|
|
14,939 |
|
|
|
|
$ |
(31,362 |
) |
|
$ |
(6,887 |
) |
|
$ |
(23,828 |
) |
|
The components of accounts receivable are as follows:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
Trade |
|
$ |
220,623 |
|
|
$ |
306,264 |
|
Accrued trade |
|
|
93,308 |
|
|
|
148,537 |
|
Prepaids and other |
|
|
40,740 |
|
|
|
45,854 |
|
|
|
|
$ |
354,671 |
|
|
$ |
500,655 |
|
|
The components of accounts payable and accrued liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
Accounts payable |
|
$ |
60,650 |
|
|
$ |
71,027 |
|
Accrued liabilities: |
|
|
|
|
|
|
|
|
Payroll |
|
|
47,001 |
|
|
|
30,351 |
|
Other |
|
|
22,551 |
|
|
|
32,925 |
|
|
|
|
$ |
130,202 |
|
|
$ |
134,303 |
|
|
NOTE 20. CONTINGENCIES
The business and operations of the Trust are complex and the Trust has executed a number of
significant financings, business combinations, acquisitions and dispositions over the course of
its history. The computation of income taxes payable as a result of these transactions involves
many complex factors as well as the Trusts interpretation of relevant tax legislation and
regulations. The Trusts 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 Trusts interpretation of the
applicable tax legislation and regulations, with the result that additional taxes could be
payable by the Trust and the amount payable could be up to $300 million.
The Trust, through the performance of its services, product sales and business arrangements, is
sometimes named as a defendant in litigation. The outcome of such claims against the Trust is not
determinable at this time, however, their ultimate resolution is not expected to have a material
adverse effect on the Trust.
The Trust maintains a level of insurance coverage deemed appropriate by management for matters
for which insurance coverage can be acquired.
NOTE 21. GUARANTEES
The Trust has entered into agreements indemnifying certain parties primarily with respect
to tax and specific third party claims associated with businesses sold by the Trust. Due to the
nature of the indemnifications, the maximum exposure under these agreements cannot be estimated.
No amounts have been recorded for the indemnities as the Trusts obligations under them are not
probable or estimable.
NOTE 22. RELATED PARTY TRANSACTIONS
During the year ended December 31, 2005, the Trust incurred a total of $6.1 million in
legal fees with a law firm for various legal matters where a director of Precision Drilling
Corporation was a partner. These transactions were incurred in the normal course of business and
were recorded at the exchange amounts.
NOTE 23. REORGANIZATION INTO A TRUST
To effect the reorganization into a trust, for the year ended December 31, 2005, the Trust
incurred $17.5 million of reorganization costs comprised as follows:
|
|
|
|
|
Severance |
|
$ |
12,600 |
|
Legal, accounting, financial advisory services and other |
|
|
4,912 |
|
|
|
|
$ |
17,512 |
|
|
Share capital of Precision prior to reorganization into the Trust included:
(a) Common shares
On November 7, 2005, Precision converted to an unincorporated, open-ended investment trust
pursuant to the Plan, which resulted in shareholders receiving one Trust unit or one exchangeable
LP unit or a combination thereof, for each previously held common share. Common shares held by
shareholders who dissented to the Plan were repurchased and cancelled on the effective date of
the Plan. All outstanding common share purchase options were converted to options to acquire
Trust units. The holder then had three options; exercise the options, have the Trust repurchase
them for cash using the closing market price of the Trust one day prior to cash-out, or have the
Trust repurchase the options as set-out above and use the proceeds to purchase an equivalent
number of Trust units.
|
|
|
|
|
|
|
|
|
|
|
Number |
|
|
Amount |
|
|
Balance, December 31, 2003 |
|
|
54,845,678 |
|
|
$ |
936,744 |
|
Issuance of common shares, net of costs and related tax effect |
|
|
4,400,000 |
|
|
|
280,783 |
|
Options exercised cash consideration |
|
|
1,544,534 |
|
|
|
55,361 |
|
reclassification from contributed surplus |
|
|
|
|
|
|
2,079 |
|
|
Balance, December 31, 2004 |
|
|
60,790,212 |
|
|
|
1,274,967 |
|
Options exercised cash consideration |
|
|
578,346 |
|
|
|
24,516 |
|
reclassification from contributed surplus |
|
|
|
|
|
|
1,521 |
|
|
Balance, May 18, 2005 |
|
|
61,368,558 |
|
|
|
1,301,004 |
|
Issued on 2:1 stock split |
|
|
61,368,558 |
|
|
|
|
|
Options exercised cash consideration |
|
|
1,679,110 |
|
|
|
49,414 |
|
reclassification from contributed surplus |
|
|
|
|
|
|
10,284 |
|
Adjustment to number of shares outstanding |
|
|
21,960 |
|
|
|
|
|
Cancellation of shares owned by dissenting shareholders |
|
|
(817,005 |
) |
|
|
(8,936 |
) |
|
Balance, November 7, 2005, before conversion to units |
|
|
123,621,181 |
|
|
|
1,351,766 |
|
Conversion to Trust units |
|
|
(122,512,799 |
) |
|
|
(1,339,646 |
) |
Conversion to exchangeable LP units |
|
|
(1,108,382 |
) |
|
|
(12,120 |
) |
|
Balance, November 7, 2005, after conversion to units |
|
|
|
|
|
$ |
|
|
|
Pursuant to the Plan, any shareholders of Precision could dissent and be paid the fair
value of the shares, being the trading price at the close of business on the last business day prior to the Special Meeting of
Securityholders on October 31, 2005. As a result, the Trust repurchased for cancellation a total
of 817,005 shares for $43.3 million, of which a premium of $34.4 million over the stated capital
was charged to retained earnings.
In the third quarter of 2004, the Trust issued 4,400,000 common shares at US $49.80 for net
proceeds of approximately $276.5 million.
(b) Contributed surplus:
|
|
|
|
|
Balance, December 31, 2003 |
|
$ |
14,266 |
|
Stock-based compensation expense |
|
|
13,837 |
|
Reclassification to common shares on exercise of options |
|
|
(2,079 |
) |
|
Balance, December 31, 2004 |
|
|
26,024 |
|
Stock-based compensation expense |
|
|
13,077 |
|
Accelerated vesting of options on disposal of discontinued operations |
|
|
5,205 |
|
Reclassification to common shares on exercise of options prior to the Plan |
|
|
(11,805 |
) |
Accelerated vesting of options pursuant to the Plan |
|
|
3,056 |
|
Reclassification to Trust units on exercise of options |
|
|
(12,342 |
) |
Reclassification to retained earnings on cash buy-out of options |
|
|
(23,215 |
) |
|
Balance, December 31, 2005 |
|
$ |
|
|
|
(c) Equity incentive plans
Prior to conversion to a Trust, Precision had equity incentive plans under which the exercise
price of each option equaled the market value of the Corporations stock on the date of grant and
an options maximum term was 10 years. Options vested over a period of 1 to 4 years from the date
of grant as employees or directors rendered continuous service to Precision.
Options held by employees of the Energy Services and International Contract Drilling Divisions
and of CEDA International Corporation (CEDA) became fully vested when these businesses were
sold during the third quarter of 2005 (see Note 24). Pursuant to the Plan, the remaining
outstanding options were exchanged for newly vested options to acquire Trust units. The exercise
prices of the options to acquire Trust units were adjusted downward to reflect the value of the
distribution of certain assets to shareholders as part of the Plan. The options to acquire Trust
units expired on November 22, 2005.
Upon acceleration of the vesting of options, options holders were given the choice to pay the
exercise price and receive a common share or Trust unit, as applicable, or to surrender their
option for a cash payment equal to the difference between the closing market value of the common
share or Trust unit one day prior to cash buy-out and the exercise price. All outstanding options
were exercised prior to December 31, 2005.
A summary of the equity incentive plans, adjusted retroactively to reflect the 2 for 1 stock
split on May 18, 2005, as at December 31, 2004 and 2005 and changes during the periods then ended
is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Options |
|
|
Range of |
|
|
Average |
|
|
Options |
|
Common Share Purchase Options |
|
Outstanding |
|
|
Exercise Price |
|
|
Exercise Price |
|
|
Exercisable |
|
|
Outstanding at December 31, 2003 |
|
|
6,786,388 |
|
|
$ |
6.75 32.95 |
|
|
$ |
20.85 |
|
|
|
4,076,396 |
|
Granted |
|
|
3,381,000 |
|
|
|
20.13 36.32 |
|
|
|
31.77 |
|
|
|
|
|
Exercised |
|
|
(3,089,068 |
) |
|
|
6.75 28.78 |
|
|
|
17.92 |
|
|
|
|
|
Cancelled |
|
|
(383,200 |
) |
|
|
15.53 32.95 |
|
|
|
25.68 |
|
|
|
|
|
|
Outstanding at December 31, 2004 |
|
|
6,695,120 |
|
|
|
15.53 36.32 |
|
|
|
27.44 |
|
|
|
2,580,302 |
|
Granted |
|
|
696,200 |
|
|
|
37.76 48.29 |
|
|
|
41.42 |
|
|
|
|
|
Exercised |
|
|
(2,835,802 |
) |
|
|
15.53 48.29 |
|
|
|
26.07 |
|
|
|
|
|
Cancelled |
|
|
(141,650 |
) |
|
|
15.53 31.87 |
|
|
|
30.26 |
|
|
|
|
|
Purchased |
|
|
(1,105,018 |
) |
|
|
15.53 45.25 |
|
|
|
31.30 |
|
|
|
|
|
Exchanged for Trust unit purchase options |
|
|
(3,308,850 |
) |
|
|
15.53 48.29 |
|
|
|
30.14 |
|
|
|
|
|
|
Outstanding at December 31, 2005 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Options |
|
|
Range of |
|
|
Average |
|
|
Options |
|
Trust Unit Purchase Options |
|
Outstanding |
|
|
Exercise Price |
|
|
Exercise Price |
|
|
Exercisable |
|
|
Outstanding at November 7, 2005 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
Granted in exchange for common share
purchase options pursuant to the Plan |
|
|
3,308,850 |
|
|
nil 27.25 |
|
|
9.16 |
|
|
|
3,308,850 |
|
Granted on repricing of common share options |
|
|
5,600 |
|
|
nil |
|
nil |
|
|
|
|
Exercised |
|
|
(1,676,616 |
) |
|
nil 27.25 |
|
|
4.93 |
|
|
|
|
|
Purchased |
|
|
(1,637,834 |
) |
|
nil 27.25 |
|
|
13.46 |
|
|
|
|
|
|
Outstanding at December 31, 2005 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
In accordance with the Trusts stock option plans, options had an initial exercise price
equal to the market price at date of grant. The per share weighted average fair value of stock
options granted during the year ended December 31, 2005 was $8.30 (2004 $7.83) based on the
date of grant valuation using the Black-Scholes option pricing model with the following
assumptions: average risk-free interest rate of 3.28% (2004 3.44%), average expected life of
2.92 years (2004 2.97 years) and expected volatility of 28.04% (2004 32.33%).
For the year ended December 31, 2005 stock-based compensation costs included in net earnings
totaled $21.3 million (2004 $13.8 million), of which $10.1 million (2004 $5.6 million)
related to discontinued operations.
NOTE 24. DISCONTINUED OPERATIONS
A summary of discontinued operations is presented below including: disposal transactions;
financial information with respect to amounts included in the statements of earnings and
statements of cash flows; significant accounting policies relating specifically to discontinued
operations; and business acquisitions included in discontinued operations.
The details of disposals of discontinued operations are as follows:
2006
In January 2007, the Trust received $21.3 million as final payment of the working capital
adjustment related to the 2005 disposition of its Energy Services and International Contract
Drilling divisions to Weatherford International Ltd. (Weatherford). This amount had been
recorded in accounts receivable at December 31, 2006 (2005 $20.0 million).
In August 2006, the Trust received $4.8 million as settlement of the working capital adjustment
arising from the 2005 disposal of CEDA and $2.5 million as final payment of the contingent
consideration associated with the 2004 disposal of United Diamond Ltd.
In total these amounts resulted in a gain of $8.3 million ($7.1 million net of tax).
2005
On August 31, 2005, the Trust sold its Energy Services and International Contract Drilling
divisions to Weatherford International Ltd. for proceeds of approximately $1.13 billion cash and
26 million common shares of Weatherford, valued at $2.1 billion. In conjunction with the Plan of
Arrangement, the Trust then distributed a total of $2.9 billion of this consideration to
Unitholders, being $844.3 million in cash and 25.7 million Weatherford common shares, valued at
$2.0 billion which represented the fair value of the shares at the date of distribution. Included
in the statement of earnings for the year ended December 31, 2005 was a loss on disposal of these
shares of $71.0 million. In conjunction with this sale, a working capital adjustment was included
as part of the purchase and sale agreement. This adjustment was settled in January 2007.
In addition on September 13, 2005, the Trust sold its industrial plant maintenance business
carried on by CEDA to Borealis Investments Inc., an investment entity of the Ontario Municipal
Employees Retirement System, for proceeds of approximately $274.0 million. Included in the CEDA
proceeds was $26.8 million for the purchase of CASCA Electric Ltd. and CASCA Tech Inc., a
transaction undertaken by CEDA on July 29, 2005. A working capital adjustment relating to this
disposal was received in August 2006.
The Energy Services, International Contract Drilling and CEDA assets were included in the Energy
Services, Contract Drilling and Rental and Production segments respectively and were disposed in
accordance with an extensive process undertaken by the Trusts Board of Directors to investigate
avenues of value creation for the Trusts Unitholders.
2004
On February 12, 2004, the Trust sold substantially all of the assets of Fleet Cementers, Inc. for
proceeds of $25.7 million. On May 7, 2004, the Trust sold the assets of the Polar Completions
division for proceeds of $15.0 million, subject to working capital adjustments. On August 31,
2004, the Trust sold its 65% interest in United Diamond Ltd. for proceeds of $8.5 million.
Additional proceeds in the amount of up to $9.5 million was receivable with respect to the sale
of United Diamond Ltd., contingent upon the extent of future business undertaken between the
Trust and United Diamond Ltd. In August 2006 this adjustment was finalized. These assets were
included in the Energy Services segment and were disposed of as they were not a core component,
at that time, to the energy services globalization strategy.
Results of the operations of these businesses have been classified as results of discontinued
operations.
The following table provides additional information with respect to amounts included in the
statements of earnings related to discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
Energy services |
|
$ |
|
|
|
$ |
689,319 |
|
|
$ |
898,199 |
|
International contract drilling |
|
|
|
|
|
|
204,987 |
|
|
|
246,612 |
|
Industrial plant maintenance (CEDA) |
|
|
|
|
|
|
149,371 |
|
|
|
175,802 |
|
|
|
|
$ |
|
|
|
$ |
1,043,677 |
|
|
$ |
1,320,613 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on disposal: |
|
|
|
|
|
|
|
|
|
|
|
|
Loss on disposal of Fleet Cementers assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
(362 |
) |
Gain (loss) on disposal of United Diamond |
|
|
2,070 |
|
|
|
|
|
|
|
(254 |
) |
Gain on disposal of Energy services and International contract drilling |
|
|
962 |
|
|
|
1,203,309 |
|
|
|
|
|
Gain on disposal of Industrial plant maintenance |
|
|
4,045 |
|
|
|
132,073 |
|
|
|
|
|
|
|
|
|
7,077 |
|
|
|
1,335,382 |
|
|
|
(616 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations before income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
Energy services |
|
|
|
|
|
|
76,607 |
|
|
|
33,060 |
|
International contract drilling |
|
|
|
|
|
|
41,171 |
|
|
|
65,043 |
|
Industrial plant maintenance |
|
|
|
|
|
|
18,135 |
|
|
|
19,658 |
|
Other |
|
|
|
|
|
|
(22,298 |
) |
|
|
(20,251 |
) |
Writedown of assets held for sale |
|
|
|
|
|
|
|
|
|
|
(6,117 |
) |
|
|
|
|
|
|
|
|
113,615 |
|
|
|
91,393 |
|
Income tax expense |
|
|
|
|
|
|
39,282 |
|
|
|
28,824 |
|
|
Results of operations, before non-controlling interest |
|
|
|
|
|
|
74,333 |
|
|
|
62,569 |
|
Non-controlling interest |
|
|
|
|
|
|
|
|
|
|
2,680 |
|
|
Results of operations |
|
|
|
|
|
|
74,333 |
|
|
|
59,889 |
|
|
Net earnings of discontinued operations |
|
$ |
7,077 |
|
|
$ |
1,409,715 |
|
|
$ |
59,273 |
|
|
The following table provides additional information with respect to amounts included in the
statements of cash flow related to discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Net earnings of discontinued operations |
|
$ |
7,077 |
|
|
$ |
1,409,715 |
|
|
$ |
59,273 |
|
Items not affecting cash: |
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on disposal of discontinued operations |
|
|
(7,077 |
) |
|
|
(1,335,382 |
) |
|
|
616 |
|
Depreciation and amortization |
|
|
|
|
|
|
95,794 |
|
|
|
130,163 |
|
Writedown of assets of discontinued operations |
|
|
|
|
|
|
|
|
|
|
3,293 |
|
Stock-based compensation |
|
|
|
|
|
|
10,109 |
|
|
|
5,647 |
|
Future income taxes |
|
|
|
|
|
|
(1,735 |
) |
|
|
(17,383 |
) |
Unrealized foreign exchange loss on long-term monetary items |
|
|
|
|
|
|
4,829 |
|
|
|
2,729 |
|
Non-controlling interest |
|
|
|
|
|
|
|
|
|
|
2,680 |
|
|
Funds provided by discontinued operations |
|
$ |
|
|
|
$ |
183,330 |
|
|
$ |
187,018 |
|
|
Components of changes in non-cash working capital balances of discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Accounts receivable |
|
$ |
|
|
|
$ |
(60,912 |
) |
|
$ |
(93,743 |
) |
Inventory |
|
|
|
|
|
|
(23,463 |
) |
|
|
5,725 |
|
Accounts payable and accrued liabilities |
|
|
|
|
|
|
1,688 |
|
|
|
52,861 |
|
Income taxes payable |
|
|
|
|
|
|
(3,623 |
) |
|
|
8,360 |
|
|
|
|
$ |
|
|
|
$ |
(86,310 |
) |
|
$ |
(26,797 |
) |
|
Significant accounting policies relating to discontinued operations included:
(a) Employee benefit plans
At December 31, 2004, approximately 36% of employees of discontinued operations were enrolled in
retirement plans. Of that, approximately 6% of participating employees were enrolled in the
defined benefit plan and approximately 94% in the defined contribution plan.
Employer contributions to defined contribution plans were expensed as employees earned the
entitlement and contributions were made.
The Trust accrued the cost of pensions earned by employees under its defined benefit plan, which
was actuarially determined using the projected benefit method pro-rated on services and
managements best estimate of expected plan investment performance, salary escalation and
retirement ages of employees. For the purpose of calculating the expected return on plan assets,
those assets were valued at quoted market value at the balance sheet date. The discount rate used
to calculate the interest cost on the accrued benefit obligation was the long-term market rate at
the balance sheet date. Past service costs from plan amendments were amortized on a straight-line
basis over the average remaining service period of employees active at the date of amendment
(EARSL). The excess of the net cumulative unamortized actuarial gain or loss over 10% of the
greater of the accrued benefit obligation and the market value of plan assets was amortized over
EARSL.
(b) Foreign currency translation
Accounts of the Trusts self-sustaining operations were translated to Canadian dollars using
average exchange rates for the year for revenue and expenses. Assets and liabilities were
translated at the year-end current exchange rate.
Gains or losses resulting from these translation adjustments were included in the cumulative
translation account in Unitholders equity.
Gains and losses arising on translation of long-term debt designated as a hedge of
self-sustaining foreign operations were deferred and included in the cumulative translation
account in Unitholders equity on a net of tax basis.
(c) Hedging relationships
The Trust utilized foreign currency long-term debt to hedge its exposure to changes in the
carrying values of the Trusts net investment in certain self-sustaining foreign operations as a
result of changes in foreign exchange rates.
To be accounted for as a hedge, the foreign currency long-term debt must be designated and
documented as a hedge, and must be effective at inception and on an ongoing basis. The
documentation defined the relationship between the foreign currency long-term debt and the net
investment in the foreign operations, as well as the Trusts risk management objective and
strategy for undertaking the hedging transaction. The Trust formally assessed, both at the
hedges inception and on an ongoing basis, whether the changes in fair value of the foreign
currency long-term debt was highly effective in offsetting changes in the fair value of the net
investment in the foreign operations. If the hedging relationship was terminated or ceased to be
effective, hedge accounting was not applied to subsequent gains or losses. Any previously
deferred amounts were carried forward and recognized in earnings in the same period as the hedged
item.
(d) Research and engineering
Research and engineering costs were charged to income as incurred. Costs associated with the
development of new operating tools and systems were expensed during the period unless the
recovery of these costs could be reasonably assured given the existing and anticipated future
industry conditions. Upon successful completion and field testing of the tools, any deferred
costs were transferred to the related capital asset accounts.
The details of business acquisitions included in discontinued operations are as follows:
2005
On July 29, 2005, the Trust completed the acquisition of all the issued and outstanding shares of
CASCA Electric Ltd. and CASCA Tech Inc. for $30.4 million. No value was assigned to intangibles
or goodwill.
2004
During the year ended December 31, 2004, in accordance with the Trusts then globalization and
technology advancement strategies, the Trust completed several acquisitions, the most significant
of which were:
(a) On May 14, 2004, the Trust acquired all of the issued and outstanding shares of Reeves
Oilfield Services Ltd. (Reeves), including a 56.5% interest in Allegheny Wireline Services, Inc.
(Allegheny). On October 14, 2004, the Trust acquired the remaining 43.5% interest in Allegheny.
In the intervening period from the date of acquisition of Reeves to the acquisition of the
remaining interest in Allegheny, earnings attributable to non-controlling interest totaled $1.3
million. Reeves provided open hole and cased hole logging services to the oil and gas industry
with operations in Canada, the United States, Australia, Africa, Europe and the Middle East.
Intangible assets acquired relate entirely to intellectual property.
(b) On May 21, 2004, the Trust acquired land drilling assets, located in Venezuela and the Middle
East, from GlobalSantaFe Corporation (GlobalSantaFe). Intangible assets acquired relate to
non-competition agreements and customer contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reeves |
|
|
GlobalSantaFe |
|
|
Other |
|
|
Total |
|
|
Net assets acquired at assigned values: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital |
|
$ |
23,000 |
(1) |
|
$ |
12,463 |
|
|
$ |
60 |
|
|
$ |
35,523 |
|
Intangible assets |
|
|
106,900 |
|
|
|
33,138 |
|
|
|
|
|
|
|
140,038 |
|
Property, plant and equipment |
|
|
41,730 |
|
|
|
296,655 |
|
|
|
1,547 |
|
|
|
339,932 |
|
Goodwill (no tax basis) |
|
|
118,531 |
|
|
|
103,956 |
|
|
|
130 |
|
|
|
222,617 |
|
Non-controlling interest in earnings
of intervening period |
|
|
1,298 |
|
|
|
|
|
|
|
|
|
|
|
1,298 |
|
Future income taxes |
|
|
(37,732 |
) |
|
|
(9,720 |
) |
|
|
|
|
|
|
(47,452 |
) |
|
|
|
$ |
253,727 |
|
|
$ |
436,492 |
|
|
$ |
1,737 |
|
|
$ |
691,956 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consideration: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash |
|
$ |
253,727 |
|
|
$ |
436,492 |
|
|
$ |
1,737 |
|
|
$ |
691,956 |
|
|
(1) Includes cash of $12,142
Precision Drilling Trust
CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS (DEFICIT)
Years ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Stated in millions of Canadian dollars, |
|
|
|
|
|
|
|
|
|
|
|
|
except per unit/share amounts) |
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
Revenue |
|
$ |
1,437.6 |
|
|
$ |
1,269.2 |
|
|
$ |
1,028.5 |
|
|
$ |
915.2 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
688.2 |
|
|
|
641.8 |
|
|
|
566.3 |
|
|
|
544.2 |
|
General and administrative |
|
|
81.2 |
|
|
|
76.4 |
|
|
|
64.2 |
|
|
|
42.7 |
|
Depreciation and amortization |
|
|
73.2 |
|
|
|
71.6 |
|
|
|
74.8 |
|
|
|
78.1 |
|
Foreign exchange |
|
|
(0.3 |
) |
|
|
(3.5 |
) |
|
|
(8.1 |
) |
|
|
(2.2 |
) |
Reorganization costs |
|
|
|
|
|
|
17.5 |
|
|
|
|
|
|
|
|
|
|
Operating earnings |
|
|
595.3 |
|
|
|
465.4 |
|
|
|
331.3 |
|
|
|
252.4 |
|
Interest, net |
|
|
8.0 |
|
|
|
29.3 |
|
|
|
46.3 |
|
|
|
34.0 |
|
Premium on redemption of bonds |
|
|
|
|
|
|
71.9 |
|
|
|
|
|
|
|
|
|
Loss on disposal of short-term investments |
|
|
|
|
|
|
71.0 |
|
|
|
|
|
|
|
|
|
Other |
|
|
(0.4 |
) |
|
|
|
|
|
|
(4.9 |
) |
|
|
(1.5 |
) |
|
Earnings from continuing operations
before income taxes |
|
|
587.7 |
|
|
|
293.2 |
|
|
|
289.9 |
|
|
|
219.9 |
|
Income taxes |
|
|
15.2 |
|
|
|
72.4 |
|
|
|
101.8 |
|
|
|
75.7 |
|
|
Earnings from continuing operations |
|
|
572.5 |
|
|
|
220.8 |
|
|
|
188.1 |
|
|
|
144.2 |
|
Discontinued operations, net of tax |
|
|
7.1 |
|
|
|
1,409.8 |
|
|
|
59.3 |
|
|
|
36.3 |
|
|
Net earnings |
|
|
579.6 |
|
|
|
1,630.6 |
|
|
|
247.4 |
|
|
|
180.5 |
|
Retained earnings (deficit), beginning of year |
|
|
(303.3 |
) |
|
|
1,041.7 |
|
|
|
794.3 |
|
|
|
613.8 |
|
Adjustment on cash purchase of employee
stock options, net of tax |
|
|
|
|
|
|
(42.1 |
) |
|
|
|
|
|
|
|
|
Reclassification from contributed surplus
on cash buy-out of employee stock options |
|
|
|
|
|
|
23.2 |
|
|
|
|
|
|
|
|
|
Distribution of disposal proceeds |
|
|
|
|
|
|
(2,851.8 |
) |
|
|
|
|
|
|
|
|
Repurchase of common shares of
dissenting shareholders |
|
|
|
|
|
|
(34.4 |
) |
|
|
|
|
|
|
|
|
Distributions declared |
|
|
(471.5 |
) |
|
|
(70.5 |
) |
|
|
|
|
|
|
|
|
|
Retained earnings (deficit), end of year |
|
$ |
(195.2 |
) |
|
$ |
(303.3 |
) |
|
$ |
1,041.7 |
|
|
$ |
794.3 |
|
|
Earnings per unit/share from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic ($) |
|
|
4.56 |
|
|
|
1.79 |
|
|
|
1.63 |
|
|
|
1.33 |
|
Diluted ($) |
|
|
4.56 |
|
|
|
1.76 |
|
|
|
1.61 |
|
|
|
1.31 |
|
Earnings per unit/share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic ($) |
|
|
4.62 |
|
|
|
13.22 |
|
|
|
2.14 |
|
|
|
1.66 |
|
Diluted ($) |
|
|
4.62 |
|
|
|
13.00 |
|
|
|
2.11 |
|
|
|
1.63 |
|
|
Precision Drilling Trust
ADDITIONAL SELECTED FINANCIAL INFORMATION
Years ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Stated in millions of Canadian dollars, |
|
|
|
|
|
|
|
|
|
|
|
|
except per unit/share amounts) |
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
Return on sales % (1) |
|
|
39.8 |
|
|
|
17.4 |
|
|
|
18.3 |
|
|
|
15.8 |
|
Return on assets % (2) |
|
|
33.6 |
|
|
|
43.3 |
|
|
|
7.3 |
|
|
|
6.3 |
|
Return on equity % (3) |
|
|
49.4 |
|
|
|
66.1 |
|
|
|
12.3 |
|
|
|
11.0 |
|
Working capital |
|
$ |
166.5 |
|
|
$ |
152.8 |
|
|
$ |
557.3 |
|
|
$ |
249.0 |
|
Current ratio |
|
|
1.81 |
|
|
|
1.43 |
|
|
|
2.47 |
|
|
|
1.57 |
|
PP&E and intangibles |
|
$ |
1,108.0 |
|
|
$ |
944.4 |
|
|
$ |
898.1 |
|
|
$ |
887.7 |
|
Total assets |
|
$ |
1,761.2 |
|
|
$ |
1,718.9 |
|
|
$ |
3,852.0 |
|
|
$ |
2,932.0 |
|
Long-term debt |
|
$ |
140.9 |
|
|
$ |
96.8 |
|
|
$ |
718.9 |
|
|
$ |
399.4 |
|
Unitholders equity |
|
$ |
1,217.1 |
|
|
$ |
1,074.6 |
|
|
$ |
2,321.7 |
|
|
$ |
1,745.3 |
|
Long-term debt to long-term debt plus equity |
|
|
0.10 |
|
|
|
0.08 |
|
|
|
0.24 |
|
|
|
0.19 |
|
Interest coverage (4) |
|
|
74.1 |
|
|
|
15.9 |
|
|
|
7.2 |
|
|
|
7.4 |
|
Net capital expenditures from continuing
operations excluding business acquisitions |
|
$ |
233.7 |
|
|
$ |
140.1 |
|
|
$ |
113.9 |
|
|
$ |
84.9 |
|
EBITDA (5) |
|
$ |
668.5 |
|
|
$ |
536.9 |
|
|
$ |
406.1 |
|
|
$ |
330.6 |
|
EBITDA % of revenue |
|
|
46.5 |
|
|
|
42.3 |
|
|
|
39.5 |
|
|
|
36.1 |
|
Operating earnings |
|
$ |
595.3 |
|
|
$ |
465.4 |
|
|
$ |
331.3 |
|
|
$ |
252.4 |
|
Operating earnings % of revenue |
|
|
41.4 |
|
|
|
36.7 |
|
|
|
32.2 |
|
|
|
27.6 |
|
Cash flow from continuing operations |
|
$ |
609.7 |
|
|
$ |
206.0 |
|
|
$ |
286.4 |
|
|
$ |
200.9 |
|
Cash flow from continuing operations per unit/share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
4.86 |
|
|
$ |
1.67 |
|
|
$ |
2.48 |
|
|
$ |
1.85 |
|
Diluted |
|
$ |
4.86 |
|
|
$ |
1.64 |
|
|
$ |
2.44 |
|
|
$ |
1.82 |
|
Book value per unit/share (6) |
|
$ |
9.68 |
|
|
$ |
8.57 |
|
|
$ |
19.10 |
|
|
$ |
15.91 |
|
Price earnings ratio (7) |
|
|
5.84 |
|
|
|
2.90 |
|
|
|
17.6 |
|
|
|
17.1 |
|
Basic
weighted average units/shares outstanding (000s) |
|
|
125,545 |
|
|
|
123,304 |
|
|
|
115,654 |
|
|
|
108,860 |
|
|
(1) Return on sales was calculated by dividing earnings from continuing operations by total
revenues.
(2) Return on assets was calculated by dividing net earnings by quarter average total assets.
(3) Return on equity was calculated by dividing net earnings by quarter average total
unitholders equity.
(4) Interest coverage was calculated by dividing operating earnings by net interest expense.
(5) Earnings before net interest, taxes, depreciation, amortization, non-controlling interest,
premium on redemption of bonds, gain/loss on disposal of investments and discontinued operations.
EBITDA is not a recognized measure under Canadian GAAP. Management believes that in addition to
net earnings, EBITDA is a useful supplemental measure as it provides an indication of the results
generated by the Trusts principal business activities prior to consideration of how those
activities are financed or how the results are taxed in various jurisdictions and prior to the
impact of depreciation and amortization. Investors should be cautioned, however, that EBITDA
should not be construed as an alternative to net earnings determined in accordance with GAAP as
an indicator of Precisions performance. Precisions method of calculating EBITDA may differ from
other companies and, accordingly, EBITDA may not be comparable to measures used by other
companies.
(6) Book value per unit/share was calculated by dividing unitholders equity by units/shares
outstanding.
(7) Year end closing price divided by basic earnings per unit/share.
ADDITIONAL DISCLOSURE
Certifications and Disclosure Regarding Controls and Procedures.
(a) |
|
Certifications. See Exhibits 99.1 and 99.2 to this Annual Report on Form 40-F. |
|
(b) |
|
Disclosure Controls and Procedures. As of the end of the Registrants fiscal year
ended December 31, 2006, an evaluation of the effectiveness of the registrants disclosure
controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the
Securities Exchange Act of 1934, as amended (the Exchange Act)) was carried out by
the registrants management with the participation of the principal executive officer and
principal financial officer. Based upon that evaluation, the Registrants principal executive
officer and principal financial officer have concluded that as of the end of that fiscal year,
the registrants disclosure controls and procedures are effective to ensure that information
required to be disclosed by the registrant in reports that it files or submits under the
Exchange Act is (i) recorded, processed, summarized and reported within the time periods
specified in Securities and Exchange Commission rules and forms and (ii) accumulated and
communicated to the Registrants management, including its principal executive officer and
principal financial officer, to allow timely decisions regarding required disclosure. |
|
|
|
It should be noted that while the Registrants principal executive officer and principal
financial officer believe that the Registrants disclosure controls and procedures provide a
reasonable level of assurance that they are effective, they do not expect that the
Registrants disclosure controls and procedures or internal control over financial reporting
will prevent all errors and fraud. A control system, no matter how well conceived or
operated, can provide only reasonable, not absolute, assurance that the objectives of the
control system are met. |
|
(c) |
|
Managements Annual Report on Internal Control Over Financial Reporting. The required
disclosure is included in the Management Report that accompanies the registrants
Consolidated Financial Statements for the fiscal year ended December 31, 2006, filed as part
of this Annual Report on Form 40-F. |
|
(d) |
|
Attestation Report of the Registered Public Accounting Firm. The required disclosure
is included in the Auditors Report that accompanies the registrants Consolidated Financial
Statements for the fiscal year ended December 31, 2006, filed as part of this Annual Report on
Form 40-F. |
|
(e) |
|
Changes in Internal Control Over Financial Reporting. During the fiscal year ended
December 31, 2006, there were no changes in the Registrants internal control over financial
reporting that have materially affected, or are reasonably likely to materially affect, the
Registrants internal control over financial reporting. |
Notices Pursuant to Regulation BTR.
None.
Audit Committee Financial Expert.
Precision
Drilling Corporation (Precision), administrator of the Registrant, has
determined that Patrick M. Murray and H. Garth Wiggins, members of Precisions audit committee both
qualify as an audit committee financial expert (as such term is defined in Form 40-F).
Precisions board of directors has determined that each of Mr. Murray and Mr. Wiggins is
independent as that term is defined in the New York Stock Exchange (NYSE) listing
standards. For a description of the relevant experience in financial matters of Mr. Murray and Mr.
Wiggins, see the section Relevant Education and Experience under the heading Audit Committee
Information in the Registrants Annual Information Form for the fiscal year ended December 31,
2006, which is filed as part of this Annual Report on Form 40-F.
Code of Ethics.
The registrant has adopted a code of ethics (as that term is defined in Form 40-F), entitled
the Joint Code of Business Conduct and Ethics (the Code of Ethics), that applies to its
directors, officers and employees, including its principal executive officer, principal financial
officer, principal accounting officer or controller, and persons performing similar functions.
The Code of Ethics is available for viewing on the registrants website at
www.precisiondrilling.com, and is available in print to any unit holder who requests it. Requests
for copies of these documents should be made by contacting: Darren Ruhr, Vice President Corporate
Services and Corporate Secretary, 4200, 150 6th Avenue S.W., Calgary, Alberta, Canada T2P 3Y7.
Since the adoption of the Code of Ethics, there have not been any amendments to the Code of Ethics
or waivers, including implicit waivers, from any provision of the Code of Ethics.
Principal Accountant Fees and Services.
The following table provides information about the fees billed to the Registrant for
professional services rendered by KPMG LLP during fiscal years 2006 and 2005:
|
|
|
|
|
|
|
|
|
(CANADIAN $000) |
|
2006 |
|
|
2005 |
|
Audit Fees |
|
$ |
1,813 |
|
|
$ |
2,108 |
|
Audit-Related Fees |
|
|
|
|
|
|
|
|
Tax Fees |
|
$ |
579 |
|
|
$ |
753 |
|
All Other Fees |
|
|
|
|
|
$ |
54 |
|
|
TOTAL |
|
$ |
2,392 |
|
|
$ |
2,915 |
|
|
Audit Fees.
Audit fees consist of fees for the audit of the Registrants annual financial statements or
services that are normally provided in connection with statutory and regulatory filings or
engagements and include fees related to the Sarbanes-Oxley Act of
2002 Section 404 compliance in 2006. The
decrease in audit fees from 2005 to 2006 was primarily due to the providing of services for
discontinued businesses in 2005.
Audit-Related Fees.
Audit-related fees consist of fees for assurance and related services that are reasonably
related to the performance of the audit or review of the Registrants financial statements and are
not reported as audit fees. There were no such fees incurred in 2005 or 2006.
Tax Fees.
Tax fees consist of fees for tax compliance services, tax advice and tax planning. During
fiscal 2006 and 2005, the services provided in this category included assistance and advice in
relation to the preparation of corporate income tax returns for the Registrant and its
subsidiaries, tax advice and planning, commodity tax and property tax consultation.
All Other Fees.
In 2005, other fees related to translation of financial statements and due diligence
assistance with respect to a disposition. In 2006, there were no such fees.
Pre-Approval Policies and Procedures.
Under the Audit Committee Charter, the Audit Committee is required to approve the terms of
engagement and the compensation to be paid to the external auditor of the Registrant. In addition,
the Audit Committee is required to review and pre-approve all permitted non-audit services to be
provided to the Registrant or any affiliated entities by the external auditors or any of their
affiliates subject to any de minimus exception allowed by applicable law. The Audit Committee may
delegate to one or more designated members of the Audit Committee the authority to pre-approve
non-audit services. Non-audit services that have been pre-approved by any such delegate must be
presented to the Audit Committee at its first scheduled meeting following such pre-approval.
The Audit Committee implemented specific procedures regarding the pre-approval of services to
be provided by Precisions 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, Precisions management will, in conjunction with Precisions external auditor,
prepare and submit to the Audit Committee a complete list of all proposed services to be provided
to Precision and the Registrant by the external auditor. Under the Audit Committee pre-approval
procedures, for those services proposed to be provided by the external auditor that have not been
previously approved by the Audit Committee, the Chairman of the Audit Committee has the authority
to grant pre-approvals of such services. The decision to pre-approve a service covered under this
procedure is required to be presented to the full Audit Committee at the next scheduled meeting.
At each of the Audit Committees 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 Registrants external auditor relating to the fees reported as audit,
audit-related, tax and all other fees were pre-approved by the Audit Committee or its delegate.
Off-Balance Sheet Arrangements.
The Registrant does not have any off-balance sheet arrangements.
Tabular Disclosure of Contractual Obligations.
The
required disclosure is included under the heading Liquidity and
Capital Resources in the Registrants Managements Discussion and
Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31,
2006, included in this Annual Report on Form 40-F.
Identification of the Audit Committee.
Precision has a separately-designated standing audit committee established in accordance with
Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Robert J.S.
Gibson, Patrick M. Murray and H. Garth Wiggins.
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NYSE.
Presiding Director at Meetings of Non-Management Directors
Precision schedules regular executive sessions in which Precisions non-management directors
(as that term is defined in the rules of the NYSE) meet without management participation. The board
of directors of Precision appoints a presiding director (the Presiding Director) from the
independent and unrelated directors present at each regularly held in-camera session of the board
of directors. The Presiding Director is responsible for developing the agenda for, and presiding
over, in-camera sessions and acting as principal liaison between the non-management directors and
the Chief Executive Officer on matters dealt with during the in-camera session. Each of
Precisions non-management directors is unrelated as such term is used in the rules of the NYSE.
Communication with Non-Management Directors
The Registrants unit holders may send communications to Precisions non-management directors
by writing to the Presiding Director, c/o Darren Ruhr, Vice President Corporate Services and
Corporate Secretary, 4200, 150 6th Avenue S.W., Calgary, Alberta, Canada, T2P 3Y7.
Communications will be referred to the Presiding Director for appropriate action. The status of
all outstanding concerns addressed to the Presiding Director will be reported to the board of
directors as appropriate.
Corporate Governance Guidelines
According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt
and disclose a set of corporate governance guidelines with respect to specified topics. Such
guidelines are required to be posted on the listed companys website. The Registrant and Precision
have adopted the required guidelines, and the guidelines are available for viewing on the
Registrants website at www.precisiondrilling.com, and are available in print to any unit holder
who requests them. Requests for copies of these documents should be made by contacting: Darren
Ruhr, Vice President Corporate Services and Corporate Secretary, 4200, 150 6th Avenue S.W.,
Calgary, Alberta, Canada T2P 3Y7.
Board Committee Mandates
The Registrants board of trustees mandate and Precisions board of directors mandate, audit
committee charter and terms of reference, compensation committee mandate and corporate governance
and nominating committee mandate are each available for viewing on the Registrants website at
www.precisiondrilling.com, and are available in print to any unit holder who requests them.
Requests for copies of these documents should be made by contacting: Darren Ruhr, Vice President
Corporate Services and Corporate Secretary, 4200, 150 6th Avenue S.W., Calgary, Alberta, Canada T2P 3Y7.
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. |
|
Undertaking. |
|
|
|
The Registrant undertakes to make available, in person or by telephone, representatives to
respond to inquiries made by the Securities and Exchange Commission (the Commission)
staff, and to furnish promptly, when requested to do so by the Commission staff,
information relating to: the securities registered pursuant to Form 40-F; the securities
in relation to which the obligation to file an annual report on Form 40-F arises; or
transactions in said securities. |
|
B. |
|
Consent to Service of Process. |
|
|
|
The Registrant has previously filed a Form F-X in connection with the class of securities
in relation to which the obligation to file this report arises. |
|
|
|
Any change to the name or address of the agent for service of process of the Registrant
shall be communicated promptly to the Commission by an amendment to the Form F-X
referencing the file number of the relevant registration statement. |
SIGNATURES
Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets
all of the requirements for filing on Form 40-F and has duly caused this annual report to
be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
|
|
Precision Drilling Corporation, as agent for
and on behalf of Precision Drilling Trust
|
|
|
By: |
/s/ Gene C. Stahl
|
|
|
|
Name: |
Gene C. Stahl |
|
|
|
Title: |
President and Chief Operating Officer |
|
|
Date: March 29, 2007
EXHIBIT INDEX
|
|
|
Exhibit |
|
Description |
99.1
|
|
Certification of President and Chief Operating Officer pursuant to Rule
13a-14 or 15d-14 of the Securities Exchange Act of 1934 |
|
|
|
99.2
|
|
Certification of Chief Financial Officer pursuant to Rule 13a-14 or 15d-14 of
the Securities Exchange Act of 1934 |
|
|
|
99.3
|
|
Certification of President and Chief Operating Officer pursuant to 18 U.S.C. 1350 |
|
|
|
99.4
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350 |
|
|
|
99.5
|
|
Consent of KPMG LLP |