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U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 40-F
(Check One)
[_] Registration statement pursuant to Section 12 of the Securities
Exchange Act of 1934
or
[X] Annual report pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 2005
Commission file number 001-14534
PRECISION DRILLING TRUST
(Exact name of registrant as specified in its charter)
ALBERTA, CANADA 1381 NOT APPLICABLE
(Province or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number (if Identification Number (if
applicable)) Applicable))
4200-150 6TH AVENUE, S.W., CALGARY, ALBERTA, CANADA T2P 3Y7
(403) 716-4500
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(Address and Telephone Number of Registrant's Principal Executive Offices)
CT CORPORATION SYSTEM, 811 DALLAS AVENUE, HOUSTON, TEXAS 77022
(713) 658-9486
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(Name, Address (Including Zip Code) and Telephone Number
(Including Area Code) of Agent For Service in the United States)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Trust Units New York Stock Exchange
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
Securities for which there is a reporting obligation pursuant to Section 15(d)
of the Act. None.
For annual reports, indicate by check mark the information filed with this
Form:
[X] Annual Information Form [X] Audited Annual Financial Statements
Indicate the number of outstanding shares of each of the issuer's classes
of capital or common stock as of the close of the period covered by the annual
report: 124,352,921 Trust Units outstanding as at December 31, 2005.
Indicate by check mark whether the Registrant by filing the information
contained in this form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of
1934 (the "Exchange Act"). If "Yes" is marked, indicate the file number
assigned to the Registrant in connection with such rule.
Yes [_] No [X]
Indicate by check mark whether the Registrant: (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Exchange Act during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports); and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [_]
The Annual Report on Form 40-F shall be incorporated by reference into,
or as an exhibit to, as applicable, the Registrant's Registration Statements
under the Securities Act of 1933: Form F-10 (File No. 333-115330).
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PRINCIPAL DOCUMENTS
The following documents have been filed as part of this Annual Report on Form
40-F and are included immediately after this section:
(a) Annual Information Form for the fiscal year ended December 31, 2005;
(b) Management's Discussion and Analysis of Financial Condition and Results
of Operations for the fiscal year ended December 31, 2005; and
(c) Consolidated Financial Statements for the fiscal year ended December 31,
2005 (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, 2005
DATED MARCH 31, 2006
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS
Certain statements contained in this Annual Information Form, including
statements which contain words such as "anticipate", "could", "should",
"expect", "seek", "may", "intend", "likely", "will", "believe" and similar
expressions, 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, 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, and are based on certain assumptions and
analysis made by us derived from our experience and perceptions.
Forward-looking information and statements in this Annual Information
Form include, but are not limited to: 2006 expected cash provided by
continuing operations; 2006 capital expenditures, including the amount and
nature thereof; 2006 distributions; cash available for distribution; oil and
natural gas prices and demand; expansion and other development trends of the
oil and natural gas industry; business strategy, including the 2006 strategy
and outlook for our business segments; expansion and growth of our business
and operations, including market share and position in the markets in which we
operate; demand for our products and services; labour shortages; the
maintenance of existing customer, supplier and partner relationships; supply
channels; accounting policies; credit risks; planned increases to
subsidiaries' fleets; and other such matters.
All such forward-looking information and statements are based on
certain assumptions and analyses made by us in light of our experience and
perception of historical trends, current conditions and expected future
developments, as well as other factors we believe are appropriate in the
circumstances. The risks, uncertainties, and assumptions are difficult to
predict and may affect operations, including, without limitation: the impact
of general economic conditions in Canada; industry conditions, including the
adoption of new environmental, taxation and other laws and regulations and
changes in how they are interpreted and enforced; the ability of oil and
natural gas companies to raise capital; the effect of weather conditions on
operations and facilities; the existence of operating risks inherent in well
servicing, contract drilling and ancillary oilfield services; the volatility
of oil and natural gas prices; oil and natural gas product supply and demand;
risks inherent in the ability to generate sufficient cash flow from operations
to meet current and future obligations; increased competition; the lack of
availability of qualified personnel or management; labour unrest; fluctuations
in interest rates; stock market volatility; opportunities available to or
pursued by us and other factors, many of which are beyond our control. The
foregoing factors are not exhaustive and are further discussed herein under
the heading "RISK FACTORS" commencing on page 14 hereof.
Actual results, performance or achievements could differ materially
from those expressed in, or implied by, 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.
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. In the event subsequent events prove past statements about current
trends to be materially different, we may choose to issue a news release
explaining the reasons for the difference and update the guidance on the
anticipated impact on revenue, earnings and other key results.
The forward-looking information and statements contained in this Annual
Information Form are expressly qualified by this cautionary statement.
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 "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 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 99.12% interest in PDLP through its holding of Class A Limited
Partnership Units (the "PDLP A Units") and the remaining 0.88% of PDLP is held
by former shareholders of Precision who elected to receive Class B Limited
Partnership Units ("Exchangeable Units") which, after the required holding
period, 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.
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. On November 23, 2005, Precision amalgamated with 1195309 Alberta
ULC and on January 1, 2006 Precision amalgamated with Live Well Service Ltd.
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.
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, 2005:
NAME OF SUBSIDIARY OR PARTNERSHIP PERCENT OR INTEREST OWNED JURISDICTION OF INCORPORATION OR CONTINUANCE
====================================================================================================================
Precision Drilling Limited Partnership 99.12% Manitoba
1194312 Alberta Ltd. 100% Alberta
Precision Drilling Corporation 99.12% Alberta
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ORGANIZATIONAL STRUCTURE OF THE TRUST
The following diagram sets forth the organizational structure of the
Trust as of the date hereof:
-----------
Unitholders
-----------
|
| 100%
v
--------------
---------------- Precision
| Drilling Trust
| 100% --------------
| |
v | 100% of
----------------- | PDLPA Units ---------
1194312 Alberta --\ v /-- Limited
Ltd. \ ---------------- / Partners
(General Partner) \ Precision / ---------
----------------- \-------> Drilling Limited <-------- 100% of
General Partnership <---- Exchangeable Units
Partner ---------------- |
Interest | | Participating
| 100% | Debt
| |
v |
------------------ |
Precision Drilling <--
Corporation
------------------
NOTES:
(1) As of December 31, 2005 there were 124,352,921 PDLP A Units
outstanding.
(2) As of December 31, 2005 there were 1,108,382 Exchangeable Units
outstanding.
(3) The interest of 1194312 Alberta Ltd. in PDLP is 0.001%. (4)
Inter-company note owing by Precision to PDLP (the "Participating
Debt").
GENERAL DEVELOPMENT OF THE BUSINESS
THREE YEAR HISTORY
During 2005, Precision made a significant shift in its strategic
business direction. 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.
Precision's growth strategy changed with its decision to realize the
value in the international contract drilling, energy services and industrial
services segments of Precision's 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.
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Those dispositions returned Precision to its original focus on oil and
gas field drilling and service rig and related operations in western Canada.
The continuing business represents Precision's core expertise and marks a
return to Precision's original business roots which date back 20 years as a
publicly traded company and 50 years in terms of operational experience.
In Canada, Precision has been the leading 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. Precision's
continuing business services during 2005 comprised: contract drilling; well
servicing; snubbing; procurement and distribution of oilfield supplies; camp
and catering; manufacture and refurbishment of drilling and service rig
equipment; as well as rental of surface oilfield equipment, tubulars and well
control equipment, and wellsite office accommodations.
With the conversion to an income trust, Precision moved from a cash
retention business model to a cash flow-through model and adopted a policy to
make regular cash distributions. Precision is a mature organization that
operates in a cyclical industry with seasonal swings in revenue levels. The
actual cash flow available for distribution 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.
Over the last three years, significant acquisitions, dispositions and
reorganizations consisted of the following:
SIGNIFICANT ACQUISITIONS
o On May 21, 2004, Precision acquired all of the land drilling business
carried on by Global SantaFe 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.
o 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 (pound)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
o On August 31, 2005, Precision sold its Energy Services and International
Contract Drilling divisions to Weatherford International Ltd.
("Weatherford") for a purchase price consisting of 26 million common
shares of Weatherford and $1.13 billion cash pursuant to a stock purchase
agreement dated June 6, 2005 between Precision and Weatherford (the
"Weatherford Sale Agreement"). The Energy Services division of Precision
consisted of three main business segments: wireline logging services;
drilling and evaluation services; and production services. Wireline
services included open hole logging, cased hole logging and completion and
slick line services. Drilling and evaluation services included
measurement-while-drilling, logging-while-drilling, directional drilling
and rotary steerable services. Production services included well testing
and controlled pressure drilling (which included under balanced drilling
services). Precision's International Contract Drilling division was
comprised of 48 land drilling rigs operating in Kuwait, Saudi Arabia,
Oman, Iran, Egypt, India, Mexico and Venezuela.
o 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
USA. 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
o On July 31, 2005, Precision Limited Partnership (which carried on
Precision's Canadian contract drilling, service rig and snubbing
businesses) completed a re-organization whereby substantially all of the
assets of the Precision Drilling and Precision Well Servicing divisions of
Precision Limited Partnership were transferred to its wholly-owned
subsidiary Precision Drilling Ltd. Precision Limited Partnership also
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transferred its ownership in LRG Catering Ltd. (Precision's camp and
catering business) to Precision Drilling Ltd.
o On August 25, 2005, Precision Limited Partnership was dissolved, with the
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 these net
assets to Live Well Service Ltd.
o 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:
o 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;
o 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;
o 1195309 Alberta ULC, a wholly-owned subsidiary of PDLP, became indebted
to PDLP;
o all of the issued and outstanding options issued pursuant to
Precision's various stock option plans were converted into New Options
(as defined in the Plan of Arrangement) which became fully vested and
were exercisable up to and including November 22, 2005; and
o 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% Limited Partnership Units
represented by Exchangeable Units were issued to certain former
shareholders of Precision, and 1194312 Alberta Ltd. (the "General
Partner") holds a nominal interest in PDLP.
o On November 23, 2005, Precision amalgamated with 1195309 Alberta ULC to
form Precision Drilling Corporation.
o On January 1, 2006, Precision amalgamated with Live Well Service Ltd. As a
result of such amalgamation (and the previous amalgamations carried out in
2005) all of the operating businesses of Precision are now operated
directly through and by Precision.
CASH FLOW
The Trust holds PDLP A Units and PDLP holds participating debt owing by
Precision (the "Participating Debt"). Cash generated from the operations of
Precision flow to PDLP in settlement of principal and interest owing on the
Participating Debt. The cash payable to PDLP is then available to be paid to
the limited partners of PDLP which includes holders of Exchangeable Units and
indirectly, the holders of Trust Units.
CASH DISTRIBUTIONS ON TRUST UNITS
The Trust's board of trustees (the "Board of Trustees" and each a
"Trustee") adopted a policy of making regular cash distributions which are
made on or about the 15th day following the end of each calendar month to
holders of Trust Units and Exchangeable Units (together "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 Special
Meeting Information Circular which are incorporated by reference into this
Annual Information Form.
The Board of Trustees reviews the Trust's distribution policy from time
to time. The actual amount distributed is dependent on various economic
factors and distributions are declared at the discretion of the Board of
Trustees. The cash flow available for distribution is a function of numerous
factors, including Precision's financial performance, debt covenants and
obligations, working capital requirements, future capital requirements and the
number of Trust Units and Exchangeable Units outstanding. As a result of the
aforementioned factors, distributions may be reduced or suspended entirely.
5
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 14 hereof.
PAYMENTS ON EXCHANGEABLE UNITS
Holders of Exchangeable Units will be entitled to receive, and PDLP
will, subject to applicable law, on each date on which the Board of Trustees
declares a distribution on the Trust Units, make 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, by 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 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.
DISTRIBUTION REINVESTMENT PLAN
A distribution reinvestment plan (the "DRIP") was approved by the Board
of Trustees on February 14, 2006. Upon implementation, the DRIP will allow
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 Units are not eligible to participate in the DRIP. Generally, no
brokerage fees or commissions will be 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 or terminate the DRIP at any time provided that such amendment or
termination does not prejudice the interests of holders of Trust Units.
Details of the DRIP are described more fully in the DRIP plan document
available on the Trust's website at www.precisiondrilling.com.
BOARD OF TRUSTEES
Pursuant to the terms of the Declaration of Trust, the Board of
Trustees consists of three members who are responsible for supervising the
activities and managing the affairs of the Trust.
The Declaration of Trust provides that, subject to its terms and
conditions, the Board of Trustees has full, absolute and exclusive power,
control, authority and discretion over the Trust assets and the management of
the affairs of the Trust to the same extent as if the Board of Trustees were
the sole and absolute legal and beneficial owners of the Trust assets.
Any one or more of the Board of Trustees may resign upon 30 days
written notice to the Trust and may be removed by an ordinary resolution and
the vacancy created by such removal may be filled at the same meeting, failing
which it may be filled by the affirmative vote of a quorum of the Board of
Trustees.
Trustees are elected at each annual meeting of Unitholders to hold
office for a term expiring at the close of the next annual meeting. A quorum
of the Board of Trustees is a majority of the Trustees then holding office. A
majority of the Trustees may fill a vacancy in the Board of Trustees, except a
vacancy resulting from an increase in the number of Trustees or from a failure
of the Unitholders to elect the required number of Trustees. In the absence of
a quorum of Trustees, or if the vacancy has arisen from a failure of the
Unitholders to elect the required number of Trustees, the Board of Trustees
will promptly call a special meeting of the Unitholders to fill the vacancy.
If the Board of Trustees fail 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
6
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:
o ensure compliance by the Trust with continuous disclosure obligations
under applicable securities legislation;
o provide investor relations services;
o 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;
o call and hold meetings of Unitholders and distribute required materials,
including notices of meetings and information circulars, in respect of all
such meetings;
o assist the Board of Trustees in calculating distributions to Unitholders;
o ensure compliance with the Trust's limitations on non-resident ownership,
if applicable; and
o generally provide all other services as may be necessary or as may be
requested by the Board of Trustees.
DESCRIPTION OF THE BUSINESS OF PRECISION
GENERAL
Precision's continuing operations are carried out in two segments
consisting of Contract Drilling Services and Completion and Production
Services. The Contract Drilling Services segment includes land drilling
services, camp and catering services, procurement and distribution of oilfield
supplies and the manufacture and refurbishment of drilling and service rig
equipment. The Completion and Production Services segment includes well
completion and workover services, snubbing services and the rental of oilfield
surface equipment, tubulars and well control equipment and wellsite
accommodations. As at December 31, 2005, Precision had approximately 6,500
employees.
Precision's revenue by business segment from continuing operations is
illustrated in the following table:
(IN THOUSANDS $)
YEARS ENDED DECEMBER 31, 2005 2004 2003
========================================================================================
Contract Drilling Services $ 916,221 $ 727,710 $ 663,619
Completion and Production Services 369,667 313,386 263,218
Inter-segment Eliminations (16,709) (12,608) (11,667)
----------------------------------------------------------------------------------------
TOTAL REVENUE $ 1,269,179 $ 1,028,488 $ 915,170
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 75 percent of new well completions in 2005
were targeted toward natural gas. In general, drilling activity in the WCSB is
split between the provinces with approximately 75 percent in Alberta, 15
percent in British Columbia and 10 percent in Saskatchewan. Areas in Canada's
north hold significant promise for the expansion of the need for oil and
natural gas services as pipelines and local community relations are
7
established. The Canadian oilfield service industry dates back 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.
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 reservoirs associated with oil
sands, heavy oil, natural gas in coal (coal bed methane), as well as natural
gas in deeper formations.
As a result of the divestiture of its energy services segment and its
international drilling business, Precision now derives 100 percent of its
revenue from the Canadian market. The ability to move heavy equipment in the
Canadian oil and natural gas fields is dependent on weather conditions. As
warm weather returns in the spring, the thawing of ground frost typically
renders secondary roads incapable of supporting the weight of heavy equipment
until such time as they have thoroughly dried. The duration of spring breakup
has a direct impact on Precision's activity levels. In addition, many
exploration and production areas in northern Canada are accessible only in
winter when the ground is frozen enough to support the transportation of heavy
equipment. The timing of freeze-up and spring breakup affects Precision's
ability to move equipment in and out of these areas. Wet weather can further
defer commencement of drilling or servicing operations on any given day or
well location.
Providing oilfield services incorporates three main elements: people,
technology and equipment. At this time attracting, training and retaining
qualified employees is the single greatest challenge for oilfield services
providers. 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 the
current and expected price of crude oil and natural gas which are determined
by supply and demand. Crude oil and natural gas prices have historically been
volatile. The upward trend of those prices since 2002 has endured and resulted
in high oil and natural gas price levels during 2005. In addition to the
upward trend in oil and natural gas pricing there were also price spikes in
2005 arising from natural disasters such as Katrina and other hurricanes, and
political and social unrest in various countries which highlight the narrow
tolerance that oil and natural gas pricing has to such events. This
demonstrates that the oil and natural gas supply and demand balance is narrow
and significant industry reinvestment is likely required to add and replace
reserves and replace aging infrastructure.
CONTRACT DRILLING SERVICES
Precision's Contract Drilling Services segment is comprised of the following
divisions:
o Precision Drilling - 230 drilling rigs - 30 percent of industry
o LRG Catering ("LRG") - 92 drilling camps representing - 20 percent of
industry
o Rostel Industries ("Rostel") - manufactures and refurbishes drilling rig
components
o Columbia Oilfield Supply ("Columbia") - centralized procurement, inventory
and distribution of consumable supplies
PRECISION DRILLING
The Precision Drilling division owns and operates the largest fleet of
land drilling rigs in Canada with 230 actively marketed drilling rigs located
throughout the WCSB, accounting for approximately 30 percent of the industry's
fleet of 770 drilling rigs in Canada at December 31, 2005.
Oil and natural gas well drilling contracts are carried out on either 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 is paid a fixed charge for each metre
8
drilled regardless of the time required or the problems encountered in
drilling the well. Some contracts are carried out on a meterage basis to a
specified depth and on a daywork basis thereafter. Turnkey contracts
contemplate the drilling of a well for a fixed price. Compared to daywork
contracts, meterage and turnkey contracts involve a higher degree of risk to
Precision and, accordingly, normally provide greater profit or loss potential.
Over the last five years, Precision's contracts have been carried out almost
exclusively on a daywork basis.
Contracts with customers vary in duration from a few days for a single
well to multiple year, multiple well drilling programs. Precision's newly
built drilling rigs tend to have a three to five year payout contract in place
at the time construction commences.
Precision's drilling rigs have varying configurations and capabilities
which enable Precision to provide services in virtually all areas of drilling
activity in the WCSB. Precision's rigs have drilling depth capacities of up to
6,700 metres. All of Precision's drilling rigs can be winterized, allowing for
operations in the harsh weather conditions faced in the Canadian drilling
environment. Conventional rigs are configured to handle either one, two or
three joints of range 2 drill pipe at one time and are categorized as singles,
doubles or triples based on this capability. As well, Precision has coiled
tubing drilling rigs which utilize a single strand of pipe coiled around a
reel. As a coil tubing drilling rig drills, the tubing is unwound and as the
bit returns to surface the tubing is rewound onto the reel. Except for
connecting the bottomhole assembly, which usually includes the drill bit and a
drilling fluid powered motor which provides the rotation for drilling, no
other connections are necessary.
Single, double and coiled tubing rigs are generally used in the shallow
drilling market, while triple rigs, which have greater hoisting capacity, are
used in deeper exploration and development drilling, usually carried out in
western Canada's foothills and Rocky Mountain regions. Precision's triple rig
fleet includes specialized rigs for deep sour natural gas well drilling and
that can also operate in very cold climates.
Rounding out Precision's fleet are Super Single(R) rigs, the majority
of which have slant rig capability. The Super Single(R) rigs are manufactured
by Precision and are equipped with top drive drilling systems, range 3 jointed
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(R) 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
eliminate the cost of building access roads for multiple drilling locations.
Precision believes the Super Single(R) rig category will continue to offer
significant revenue growth. In addition to conventional wells, Precision's
Super Single(R) rigs have been adapted to meet a variety of operational needs
such as heavy oil, 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 oil sands in-situ bitumen reserves.
The Super Single(R) Light is a smaller capacity, specialized version of
the Super Single(R). These rigs have been built for drilling shallow wells up
to 1,200 metres in depth. Using jointed range 3 drill pipe, the design
incorporates proven technology and reliability in a light weight, easily moved
load configuration. The Super Single(R) Light competes with coiled tubing rigs
and offers greater drilling capability over a wider range of well
configurations than coiled tubing rigs. During 2005, Precision designed and
built a self-propelled version of the Super Single(R) Light which reduces
transportation costs for customers.
A total of 45 of Precision's drilling rigs are diesel-electric powered,
with the remaining rigs mechanically powered. Diesel-electric powered rigs
provide more precise control of drilling components and are considered more
power efficient than mechanical rigs and are well suited for horizontal and
directional drilling. Many of Precision's mechanically powered rigs are also
capable of horizontal and directional drilling by reconfiguring the rigs with
additional equipment which Precision has readily available. Precision
continually seeks to upgrade and modify its rig fleet to maximize performance.
During 2005, one light triple rig and one double rig were converted to
electric power with a complete retrofit and design change which extended their
depth rating to 4,000 metres. 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.
To facilitate customer requirements Precision 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
9
and kelly. A top drive is suspended in the mast of the drilling rig and is
powered by a hydraulic or electric motor. All Super Single(R) drilling rigs
are equipped with an integrated top drive as part of the rig inventory.
The following table lists the drilling depth capability of Precision's
drilling rigs and the total Canadian land drilling industry's rigs in the WCSB
as at December 31, 2005:
PRECISION FLEET INDUSTRY FLEET (1)
---------------------------------------- -------------------------------- ----------------------------------------
MARKET
MAXIMUM NUMBER % OF SHARE NUMBER OF % OF
TYPE OF DRILLING RIG DEPTH RATING OF RIGS TOTAL % (3) RIGS TOTAL CHANGE (4)
=====================================================================================================================
Single 1,200m 17 7% 14% 124 16% 13
---------------------------------------------------------------------------------------------------------------------
Super Single(R) (2) 3,000m 21 9% 88% 24 3% 0
---------------------------------------------------------------------------------------------------------------------
Double 3,000m 94 41% 27% 344 45% 14
---------------------------------------------------------------------------------------------------------------------
Light triple 3,600m 44 19% 39% 114 15% (4)
---------------------------------------------------------------------------------------------------------------------
Heavy triple 6,700m 43 19% 40% 107 14% 6
---------------------------------------------------------------------------------------------------------------------
Coiled tubing 1,500m 11 5% 19% 57 7% 21
---------------------------------------------------------------------------------------------------------------------
TOTAL 230 100% 30% 770 100% 50
---------------------------------------------------------------------------------------------------------------------
NOTES:
(1) Source: Daily Oil Bulletin - Rig Locator Report as of January 4, 2006.
Precision has allocated the industry rig fleet by rig type.
(2) Super Single(R) excludes single rigs that do not have automated pipe
handling systems, or do not have a self contained top drive, or cannot
run range 3 drill pipe/casing.
(3) Market share means Precision's rigs as a percentage of the industry's
rigs.
(4) Change in number of industry rigs as compared to the prior year.
There were 50 new drilling rigs added to the Canadian industry fleet
during 2005, a seven percent increase over 2004. Of these additional rigs, 68
percent had a depth rating of less than 1,500 metres with new coiled tubing
rigs leading the way with 21 and singles with 13. 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 is driving demand for rigs to record levels.
Precision has a balanced drilling rig offering, with a particular
weighting in deep drilling. As customers turn to deeper wells to discover new
reserves, Precision's 40 percent market share in rigs with a depth capacity
greater than 3,600 metres is noteworthy. Drilling opportunities for natural
gas in deeper reservoirs is a market where Precision has an advantage - a
market many expect to emerge in Canada.
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
======================================================================================================================
2005 56.2 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
2001 51.6 53.0 7,384 18,855 39.2 6,907 17,359 39.8
-----------------------------------------------------------------------------------------------------------------------
NOTES:
(1) The number of wells drilled is reported on a rig release basis.
(2) Industry numbers exclude drilling rigs not registered with the
Canadian Association of Oilwell Drilling Contractors ("CAODC") and
non-reporting CAODC member contractors.
10
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 31 percent. During 2005, Precision
achieved a utilization rate of 56 percent for its drilling rigs compared to
the average industry utilization rate in Canada of 60 percent. Precision
strives to obtain high utilization of its fleet and optimal profitability
given competitive pricing and Canada's seasonal reduction in drilling demand
during the second and third quarters.
In 2005, Precision drilled 7,766 exploration and development wells,
accounting for 32 percent of industry wells drilled in western Canada.
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, floorhands and leasehands. 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 leasehand positions are entry level, with the motorman, derrickman and
driller positions being more advanced. Each position has certain prerequisite
qualifications and training. Well control, H2S, first aid, fall protection,
work place hazardous materials and various aspects of Precision's health,
safety and environment management systems are all key training components.
The provision of an experienced competent crew is a competitive
strength, highly valued by Precision's customers. In order to continually
recruit rig employees, Precision has a centralized personnel department and
orientation program. In 2005, there were approximately 1,500 candidates given
pre-employment rig orientation training. Precision is also active as a member
of the CAODC in implementing a designated trade certification for drilling rig
workers in Alberta, the first jurisdiction to recognize the specialized skill
and knowledge a driller possesses. The compulsory journeyman trade
certification is called "Rig Technician". The apprenticeship program requires
the successful completion of three training levels and the accumulation of
6,750 hours of experience with at least 1,000 hours as a driller. In the
long-term, this initiative should foster individual career opportunities, high
quality training, consistent use of industry recommended practices and the
retention of experienced workers. Precision was the first in the industry to
participate in the mandatory Alberta Rig Technician trade, and by the end of
2005, had 427 employees registered in the program.
While the shortage of labour in the oilfield service industry is widely
known, emphasis must be 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. Precision's ability to
work an entire fleet of rigs, given Canadian seasonality, arises from its
ability to retain experienced employees in low activity periods, orientate new
employees and effectively administer personnel and payroll functions.
LRG CATERING
LRG Catering provides camp and catering services to the oil and natural
gas industry in western Canada. LRG provides food and accommodation to
personnel working at the well site, typically in remote locations. LRG has 92
conventional and base camps, representing about 20 percent of the camp and
catering business in western Canada. LRG's traditional five to six unit camps
can lodge 25 field employees and feed up to 50 workers daily. Base camp
modules can be expanded to feed and accommodate larger groups of workers when
required. LRG plans to increase its fleet in 2006 to 102 camps by adding 10
new camps.
ROSTEL INDUSTRIES
Rostel Industries manufactures and refurbishes custom drilling rig and
service rig components. This uniquely positions Precision with in-house rig
manufacturing capability. In addition to quality construction and repair
services, Rostel sustains high plant utilization by providing specialized
services, including inspection and certification of critical drilling
components such as overhead equipment, well control equipment and handling
tools. Rostel's expertise extends to having its own 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 60
percent of the components for Precision's Super Single(R) drilling rigs.
COLUMBIA OILFIELD SUPPLY
Columbia Oilfield Supply is a general supply store that procures,
packages and distributes large volumes of consumable oilfield supplies to the
contract drilling and well servicing industry. Most of Columbia's activity
supports divisions of Precision, making it an essential extension of
11
Precision's purchasing process. Columbia's key strengths, which contribute to
Precision's competitiveness, are in inventory management, demand anticipation
and distribution. Precision and its customers also benefit from Columbia's
purchasing power, standardized product selection, streamlined business
processes and coordinated distribution. Strategically, Columbia gives
Precision the ability to set its own service level priorities and to
standardize products used on its equipment. Precision has direct control over
supply distribution to field destinations and this enhances its reliability in
the execution of its operations.
COMPLETION AND PRODUCTION SERVICES
Precision's Completion and Production Services segment is comprised of the
following divisions:
o Precision Well Servicing ("PWS") - 237 service rigs - 24 percent of
industry
o Live Well Service ("Live Well") - 26 snubbing units - 30 percent of
industry
o Precision Rentals - 3,700 storage tanks, 8,000 joints of specialty drill
pipe, 4,000 handling tools, 300 wellsite accommodation units - 15 percent
of the industry
PRECISION WELL SERVICING
The Precision Well Servicing division is Canada's largest service rig
contractor, providing customers with a complete range of oil and natural gas
well services - completions, workovers, abandonments, well maintenance, high
pressure and critical sour well work and re-entry preparation. Precision's
service rig fleet completes all types of new wells and works over existing
wells to optimize customers' oil and natural gas production. The configuration
of Precision's Well Servicing fleet is illustrated in the following table:
TYPE OF SERVICE RIG 2005 2004 2003
==============================================================================
Freestanding mobile single 88 86 75
------------------------------------------------------------------------------
Mobile single 17 19 30
------------------------------------------------------------------------------
Double 64 65 57
------------------------------------------------------------------------------
Freestanding mobile double 8 9 6
------------------------------------------------------------------------------
Mobile double 44 42 46
------------------------------------------------------------------------------
Heavy double 1 2 9
------------------------------------------------------------------------------
Freestanding slant 15 16 16
------------------------------------------------------------------------------
TOTAL FLEET 237 239 239
In 2005, PWS maintained an industry market share of almost 24 percent
based on an average registered CAODC industry fleet of approximately 1,009
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, 2005, PWS had 111 freestanding service rigs
representing 47 percent 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 that the rig does not
need to be moved as often.
Well service rigs are typically operated by a crew of four workers and
a rig manager. They also include additional equipment such as circulating
pumps, tanks, blowout preventers and tools. These rigs are mobile to meet
industry call-out demands and can be moved to new locations quickly and with
relative ease. In general, well servicing activities are conducted during
daylight hours. 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. 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
12
more volatile than workover services. Completion services accounted for 41
percent of PWS's well servicing activity in 2005, as compared to 34 percent in
2004, due to higher drilling activity.
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.
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, such as lost tools, from
the well bore. 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. Maintenance services are generally
required throughout the life of a producing well and are typically required
more often for oil wells than natural gas wells. 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.
LIVE WELL SERVICE
The Live Well Service division currently markets 25 portable hydraulic
rig assist snubbing units and a freestanding unit in western Canada. Snubbing
units are equipped with specialized pressure control devices which allows
tubing to be moved in and out of a wellbore while a well is under pressure and
is intended to reduce reservoir damage within a natural gas well. Live Well's
snubbing operations provide benefits to customers that enable increased well
production rates and higher recoverable reserves. A rig assist snubbing unit
requires a rig to be on location to hoist it into place. Live Well's
proprietary freestanding 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 further enhance safe, cost effective
snubbing operations.
Traditional well servicing operations require the pressure in a well to
be neutralized or killed, prior to performing such operations so that they can
be conducted safely. Certain 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. Precision believes that the use of
snubbing units is increasing as oil and gas companies become more aware of the
potential risks of reservoir damage that can be avoided by using snubbing
techniques. Snubbing is typically performed on natural gas wells. The
escalating trend toward higher natural gas well drilling and low pressure
production in the WCSB is having a positive effect on demand for Live Well's
services.
PRECISION RENTALS
Precision Rentals is a leading provider of oilfield rental equipment
from multiple operating centres strategically located in the WCSB. The rental
equipment offered by Precision Rentals covers a range of customer needs
throughout the oil and natural gas drilling, completion and production
process. Equipment is marketed through three product categories: surface
equipment; tubulars and well control equipment; and wellsite accommodations.
The surface equipment category is primarily associated with fluid
handling and includes tanks, separators, invert systems, matting, valves and
other tools. Tubulars and well control equipment are designed for unique well
specifications. Tubular equipment is specialty-sized drill pipe; well control
equipment is blowout preventers and associated assemblies. Wellsite
accommodations provide offices and lodging for senior personnel and are built
with heavy-duty skids to facilitate frequent moves. Precision Rentals also
13
supplies the patented Vapour Tight Oil Battery(TM), which allows for safe,
single well productiOn of oil with H2S content through the use of a 500-barrel
vessel with gas metering and flaring capabilities.
The inventory of the specialty tubulars and well control line consists
of approximately 8,000 joints of specialty drill pipe and collars, 4,000
handling tools and well control equipment (including blowout preventers and
diverter systems). The wellsite accommodation portion of Precision Rentals
consists of a fleet of approximately 300 fully equipped and furnished
accommodation units.
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 land drilling services business and should not be viewed as
shares of Precision. The Trust Units represent a fractional interest in the
Trust. Holders of Trust Units do not have the statutory rights normally
associated with ownership of shares of a corporation including, for example,
the right to bring "oppression" or "derivative" actions. The Trust's sole
assets are the shares of the General Partner, the PDLP A Units and other
investments in securities. The price per Trust Unit is a function of
anticipated distributable cash, the underlying assets of the Trust and
management's ability to effect long-term growth in the value of Precision and
other entities now or hereafter owned directly or indirectly by the Trust. The
market price of the Trust Units are sensitive to a variety of market
conditions including, but not limited to, interest rates, the growth of the
general economy and the price of crude oil and natural gas. 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 percent of the shares of
Precision and the Participating Debt. 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 Participating Debt. The actual amount
of cash available for distribution is dependent upon numerous factors relating
to the business of Precision including profitability, changes in revenue,
fluctuations in working capital, capital expenditure levels, applicable laws,
compliance with contracts, contractual restrictions contained in the
instruments governing its indebtedness, the impact of interest rates, the
growth of the general economy, the price of crude oil and natural gas,
weather, future capital requirements, the number of Trust Units and
Exchangeable Units 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 its distribution targets in the future, and such deterioration
may be material.
POSSIBLE RESTRICTION ON GROWTH
The payout of substantially all of Precision's operating cash flow will
make capital and operating expenditures dependent on increased cash flow or
additional financing in the future. The lack of these funds could limit
Precision's future growth and cash flow which in turn may affect the amount of
distributions. In addition, Precision may be precluded from pursuing
acquisitions or investments which may not be accretive on a short-term basis.
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
14
rights in connection with such additional issues. The Board of Trustees have
discretion in connection with the price and the other terms of the issue of
such additional Trust Units.
NATURE OF DISTRIBUTIONS
Unlike interest payments on an interest-bearing security, distributions
by income trusts on trust units (including those of the Trust) are, for
Canadian tax purposes, composed of different types of payments (portions of
which may be fully or partially taxable or may constitute non-taxable "returns
of capital"). The composition for tax purposes of those cash distributions may
change over time, thus affecting the after-tax return to holders of Trust
Units. Therefore, the rate of return for holder's of Trust Units over a
defined period may not be comparable to the rate of return on a fixed-income
security that provides a return on capital over the same period. This is
because a holder of Trust Units may receive distributions that constitute a
return of capital (rather than a return on capital) to some extent during the
relevant period. Returns on capital are generally taxed as ordinary income,
dividends or taxable capital gains in the hands of a holder of Trust Units,
while returns of capital are generally non-taxable to a holder of Trust Units
(but reduce the adjusted cost base in a Trust Unit for tax purposes).
ISSUANCE OF ADDITIONAL TRUST UNITS
The Declaration of Trust provides that an amount equal to the taxable
income of the Trust will be payable each year to holders of Trust Units in
order to reduce the Trust's taxable income to zero. Where in a particular
year, the Trust does not have sufficient cash to distribute such an amount,
the Declaration of Trust provides that additional Trust Units may be
distributed in lieu of cash payments. Holders of Trust Units will generally be
required to include an amount equal to the fair market value of those Trust
Units in their taxable income, notwithstanding that they do not directly
receive a cash payment. See "CERTAIN CANADIAN FEDERAL INCOME TAX
CONSIDERATIONS -- TAXATION OF TRUST UNITHOLDERS" on pages 47 and 48 of the
Special Meeting Information Circular which are incorporated by reference into
this Annual Information Form.
VARIABILITY OF DISTRIBUTIONS
The cash flow available for distribution is a function of numerous
factors including: Precision's financial performance; the impact of interest
rates; the growth of the general economy; the price of crude oil and natural
gas; weather; debt covenants and obligations; working capital requirements;
future capital requirements; and the number of Trust Units and Exchangeable
Units issued and outstanding. Distributions may be reduced or suspended
entirely depending on Precision's operations and the performance of its
assets. The market value of the Trust Units may deteriorate if the Trust is
unable to meet its distribution targets 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, will not be changed in a manner which adversely affects
Trust Unit holders.
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
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.
15
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, 2008. 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, 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 its growth (either from acquisitions or capital
expenditure additions) through debt. Amounts paid in respect of interest and
principal on debt incurred by Precision and its affiliates may impair
Precision's ability to satisfy its obligations under its debt instrument(s).
Variations in interest rates and scheduled principal repayments could result
in significant changes in the amount required to be applied to service debt
before payment of inter-entity debt. This may result in lower levels of cash
for distribution by the Trust. Ultimately, subordination agreements or other
debt obligations could preclude distributions altogether.
TAXATION OF THE TRUST
There can be no assurances that Canadian federal income tax laws and
administrative policies respecting the treatment of mutual fund trusts will
not be changed in a manner which adversely affects the holders of Trust Units.
For example, if the Trust ceases to qualify as a "mutual fund trust" under the
Tax Act, the income tax considerations described under the heading "CERTAIN
CANADIAN FEDERAL INCOME TAX CONSIDERATIONS - TAXATION OF TRUST UNITHOLDERS" on
pages 47 and 48 of the 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 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.
On September 16, 2004, the Minister of Finance (Canada) released draft
amendments to the Tax Act including draft amendments providing that a trust
will lose its status as a mutual fund trust if the aggregate fair market value
of all units issued by the trust held by one or more non-residents of Canada
or partnerships that are not "Canadian partnerships" (as defined in the Tax
Act) is more than 50% of the aggregate fair market value of all the units
issued by the trust where more than 10% (based on fair market value) of the
trust's property is certain types of "taxable Canadian property" or certain
other types of property. If the draft amendments are enacted as proposed, and
if, at any time, more than 50% of the aggregate fair market value of the Trust
Units are held by non-residents of Canada and non-Canadian partnerships, the
Trust may thereafter cease to be a mutual fund trust. The draft amendments do
not currently provide any means of rectifying a loss of mutual fund trust
status. On December 6, 2004, the Minister of Finance (Canada) tabled a Notice
of Ways and Means Motion to implement certain measures proposed in the
September 16, 2004 draft amendments. However, such notice did not include the
proposal concerning mutual fund trusts maintained primarily for the benefit of
non-residents of Canada. In addition, the Minister of Finance (Canada)
announced on December 6, 2004 as well as in the 2005 Budget Proposals that
further discussions would be pursued with the private sector in this respect.
16
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 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.
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.
TAXATION OF PRECISION
Income fund structures often involve significant amounts of
inter-entity debt, generating 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 Participating Debt. 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.
NET ASSET VALUE
The net asset value of the assets of the Trust from time to time will
vary depending upon factors which are beyond the control of Precision. The
trading price of the Trust Units also fluctuates due to factors beyond the
control of Precision and such trading prices may be greater than the net asset
value of the Trust's assets.
RESIDUAL LIABILITY OF PRECISION
Precision, the successor entity to amalgamations involving its
predecessor companies, has retained all liabilities of its predecessor
companies, including liabilities relating to corporate and income tax matters.
UNITHOLDER LIMITED LIABILITY
The Declaration of Trust provides that no holder of Trust Units will be
subject to any liability in connection with the Trust or its obligations and
affairs and, in the event that a court determines that holders of Trust Units
are subject to any such liabilities, the liabilities will be enforceable only
against, and will be satisfied only out of the Trust's assets. Pursuant to the
Declaration of Trust, the Trust will indemnify and hold harmless each holder
of Trust Units from any costs, damages, liabilities, expenses, charges and
losses suffered by a holder resulting from or arising out of such holder not
having such limited liability. The Declaration of Trust provides that all
written instruments signed by or on behalf of the Trust must contain a
provision to the effect that obligations under those instruments will not be
binding upon holders of Trust Units personally. Personal liability may however
arise in respect of claims against the Trust that do not arise under
contracts, including claims in tort, claims for taxes and possibly certain
other statutory liabilities. The possibility of any personal liability of this
nature arising is considered unlikely. The INCOME TRUSTS LIABILITY ACT
(Alberta) came into force on July 1, 2004. The legislation provides that a
holder of Trust Units will not be, as a beneficiary, liable for any act,
default, obligation or liability of the Trustee(s) that arises after the
legislation came into force. However, this legislation has not yet been ruled
upon by the Courts. The operations of the Trust will be conducted, upon the
advice of counsel, in such a way and in such jurisdictions as to avoid as far
as possible any material risk of liability to the holders of Trust Units for
claims against the Trust, including by obtaining appropriate insurance, where
available and to the extent commercially feasible.
DEDUCTIBILITY OF EXPENSES
Although the Trustees, the General Partner of PDLP and management of
Precision are of the view that 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.
17
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 14 hereof.
RISKS ASSOCIATED WITH EXCHANGEABLE UNITS
None of the Trust, PDLP or Precision is providing any representations
as to the tax consequences of holding Exchangeable Units.
INDEMNITY OF LIMITED PARTNERS
While the General Partner has agreed pursuant to the terms of the
Limited Partnership Agreement of PDLP, to indemnify PDLP's limited partners,
including holders of the Class A Limited Partnership Units and the
Exchangeable Units, the General Partner may not have sufficient assets to
honour the indemnity.
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 Canadian drilling rig, camp and catering,
service rig, snubbing, rentals and related service businesses and activities
of Precision 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. These factors could lead to a decline in the demand for
Precision's services, resulting in a material adverse effect on revenues, cash
flows, earnings and cash distributions to Unitholders. The majority of
Precision's operating costs are variable in nature which minimizes the impact
of downturns on Precision's operational results.
OPERATIONS DEPENDENT ON THE PRICE OF OIL AND NATURAL GAS
Precision sells its services to oil and natural gas exploration and
production companies. Macro economic and geopolitical factors associated with
oil and natural gas supply and demand are prime drivers for pricing and
profitability within the oilfield services industry. Generally, when commodity
prices are relatively high, demand for Precision's services are high, while
the opposite is true when commodity prices are low. The markets for oil and
natural gas are separate and distinct. Oil is a global commodity with a vast
distribution network. As natural gas is most economically transported in its
gaseous state via pipeline, its market is dependent on pipeline infrastructure
and is subject to regional supply and demand factors. Recent developments in
the transportation of liquefied natural gas ("LNG") in ocean going tanker
ships has introduced an element of globalization to the natural gas market.
However, the volume capability of the world's LNG infrastructure is not
expected to be large enough to influence pricing in North American markets for
a number of years. Crude oil and natural gas prices are quite volatile, which
accounts for much of the cyclical nature of the oilfield services business.
Oilfield service business cycles are muted somewhat in non-North American
markets where projects tend to be larger and more long-term and are therefore
less susceptible to short-term commodity price fluctuations.
Worldwide military, political and economic events, including
initiatives by the Organization of Petroleum Exporting Countries ("OPEC"), may
affect both the demand for, and the supply of, oil and natural gas. Weather
conditions, governmental regulation (both in Canada and elsewhere), levels of
consumer demand, the availability of pipeline capacity, and other factors
beyond Precision's control may also affect the supply of and demand for oil
and natural gas and thus lead to future price volatility. Precision believes
that any prolonged reduction in oil and natural gas prices would depress the
level of exploration and production activity. This would likely result in a
corresponding decline in the demand for Precision's services and could have a
material adverse effect on its revenues, cash flows and profitability. Lower
oil and natural gas prices could also cause Precision's customers to seek to
terminate, renegotiate or fail to honour Precision's drilling contracts which
could affect the fair market value of its rig fleet which in turn could
trigger a writedown for accounting purposes; which could affect Precision's
ability to retain skilled rig personnel; and which could affect Precision's
ability to obtain access to capital to finance and grow its businesses. There
can be no assurance that the future level of demand for Precision's services
or future conditions in the oil and natural gas and oilfield services
industries will not decline.
18
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
Industry indications suggest that an additional 100 drilling rigs will
be added by drilling contractors within the WCSB during 2006. This is expected
to increase the industry drilling fleet to 870 rigs. There is no assurance
that the level of demand for drilling rig services in the future will be able
to support the expected increase in the size of the industry drilling rig
fleet. Any decline in demand for drilling services within the services
industry, directly or indirectly related to the current drilling rig expansion
programs, could also lead to a decline in the demand for Precision's services,
resulting in a material adverse effect on Precision's revenues, cash flows,
earnings and cash distributions to Unitholders.
WORKFORCE AVAILABILITY
Precision's ability to provide reliable services is dependent upon the
availability of well-trained, experienced crews to operate field equipment.
Precision must also balance the requirement to maintain a skilled workforce
with the need to establish cost structures that fluctuate with activity
levels. Within Precision the most experienced employees are retained during
periods of low utilization by having them fill lower level positions on field
crews. Precision has established training programs for employees new to the
oilfield service sector and works closely with industry associations to ensure
competitive compensation levels to attract new workers to the industry as
required. Many of Precision's businesses are currently experiencing manpower
shortages. 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.
NEW TECHNOLOGY
Technological innovation by oilfield service companies has improved the
effectiveness of the entire exploration and production sector over the
industry's history. Drilling time has been reduced due to improvements in
drill bits, logging-while-drilling and measurement-while-drilling tools, and
innovation changes in other areas such as mud systems and top drives.
Precision's ability to deliver services that are more efficient is critical to
continued success.
CUSTOMER MERGER AND ACQUISITION ACTIVITY
Merger and acquisition activity in the oil and natural gas exploration
and production sector can impact demand for our services as customers focus on
internal reorganization activities prior to committing funds to significant
drilling and maintenance projects.
BUSINESS INTERRUPTION AND CASUALTY LOSSES
Precision's operations are subject to many hazards inherent in the
drilling, workover and well-servicing industries, including blowouts,
cratering, explosions, fires, loss of well control, loss of hole, damaged or
lost drilling equipment and damage or loss from inclement weather or natural
disasters. Any of these hazards could result in personal injury or death,
damage to or destruction of equipment and facilities, suspension of
operations, environmental damage and damage to the property of others.
Generally, drilling contracts provide for the division of responsibilities
between a drilling company and its customer, and Precision seeks to obtain
indemnification from its customers by contract for certain of these risks. To
the extent that Precision is unable to transfer such risks to customers by
contract or indemnification agreements, Precision seeks protection through
insurance. However, Precision cannot ensure that such insurance or
indemnification agreements will adequately protect it against liability from
all of the consequences of the hazards described above. The occurrence of an
event not fully insured or indemnified against, or the failure of a customer
or insurer to meet its indemnification or insurance obligations, could result
in substantial losses. In addition, insurance may not be available to cover
any or all of these risks, or, even if available, may not be adequate.
Insurance premiums or other costs may rise significantly in the future, so as
to make such insurance prohibitively expensive or uneconomic. This is
particularly of concern in the wake of the September 11, 2001 terrorist
attacks in the U.S. and the severe hurricane damage in the U.S. Gulf Coast
region in 2005, both of which have resulted in significantly increased
insurance costs, deductibles and coverage restrictions. In future insurance
renewals, Precision may choose to increase its self insurance retentions (and
thus assume a greater degree of risk) in order to reduce costs associated with
increased insurance premiums.
19
ENVIRONMENTAL LEGISLATION
Precision's operations are subject to numerous laws, regulations and
guidelines governing the management, transportation and disposal of hazardous
substances and other waste materials and otherwise relating to the protection
of the environment and health and safety. These laws, regulations and
guidelines include those relating to spills, releases, emissions and
discharges of hazardous substances or other waste materials into the
environment, requiring removal or remediation of pollutants or contaminants
and imposing civil and criminal penalties for violations. Some of the laws,
regulations and guidelines that apply to Precision's operations also authorize
the recovery of natural resource damages by the government, injunctive relief,
and the imposition of stop, control, remediation and abandonment orders. The
costs arising from compliance with such laws, regulations and guidelines may
be material to Precision.
The trend in environmental regulation has been to impose more
restrictions and limitations on activities that may impact the environment,
including the generation and disposal of wastes and the use and handling of
chemical substances. These restrictions and limitations have increased
operating costs for both Precision and its customers. Any regulatory changes
that impose additional environmental restrictions or requirements on Precision
or its customers could adversely affect Precision through increased operating
costs and potential decreased demand for Precision's services.
While Precision maintains liability insurance, including insurance for
environmental claims, the insurance is subject to coverage limits and certain
of Precision's policies exclude coverage for damages resulting from
environmental contamination. There can be no assurance that insurance will
continue to be available to Precision on commercially reasonable terms, that
the possible types of liabilities that may be incurred by Precision will be
covered by Precision's insurance, or that the dollar amount of such
liabilities will not exceed Precision's policy limits. Even a partially
uninsured claim, if successful and of sufficient magnitude, could have a
material adverse effect on Precision's business, results of operations and
prospects.
BUSINESS IS SEASONAL
In Canada, the level of activity in the oilfield service industry is
influenced by seasonal weather patterns. During the spring months, wet weather
and the spring thaw make the ground unstable. Consequently, municipalities and
provincial transportation departments enforce road bans that restrict the
movement of rigs and other heavy equipment, thereby reducing activity levels
and placing an increased level of importance on the location of our equipment
prior to imposition of the road bans. Additionally, certain oil and natural
gas producing areas are located in sections of the WCSB that are inaccessible,
other than during the winter months, because the ground surrounding or
containing the drilling sites in these areas consists of terrain known as
muskeg. Until the muskeg freezes, the rigs and other necessary equipment
cannot cross the terrain to reach the drilling site. Moreover, once the rigs
and other equipment have been moved to a drilling site, they may become
stranded or otherwise unable to relocate to another site should the muskeg
thaw unexpectedly. Precision's business results depend, at least in part, upon
the severity and duration of the Canadian winter.
TAX CONSEQUENCES OF PREVIOUS TRANSACTIONS COMPLETED BY PRECISION
The business and operations of Precision prior to completion of the
Plan of Arrangement had been complex and Precision has executed a number of
significant financings, business combinations, acquisitions and dispositions
over the course of its history. The computation of income taxes payable as a
result of these transactions, and in particular those completed within the
past five years, involves many complex factors as well as Precision's
interpretation of relevant tax legislation and regulations. Precision's
management believes that the provision for income tax is adequate and in
accordance with generally accepted accounting principles and applicable
legislation and regulations. However, there are a number of tax filing
positions that can still be the subject of review by taxation authorities who
may successfully challenge Precision's interpretation of the applicable tax
legislation and regulations, with the result that additional taxes could be
payable by Precision and the amount payable could be up to $300 million. Any
increase in Precision's tax liability would reduce the funds available for
distributions on the Trust Units.
CREDIT RISK
Precision's accounts receivable are with customers involved in the oil
and natural gas industry, whose revenues may be impacted by fluctuations in
commodity prices. Although collection of these receivables could be influenced
by economic factors affecting this industry, management considers the risk of
a significant loss due to uncollectible receivables to be remote at this time.
20
POTENTIAL UNKNOWN LIABILITIES
There may be unknown liabilities assumed by the Trust through its
direct and indirect interests in Precision, including those associated with
prior acquisitions and dispositions by Precision as well as environmental
issues or tax issues. Specifically, Precision has provided certain indemnities
to the respective purchasers under the Weatherford Sale Agreement and the CEDA
Sale Agreement. The discovery of any material liabilities could have an
adverse affect on the financial condition and results of discontinued
operations of Precision and, as a result, the amount of cash available for
distribution to Unitholders. Precision is not aware of any undisclosed
material liabilities.
CAPITAL EXPENDITURES
The timing and amount of capital expenditures by Precision will
directly affect the amount of cash available for distribution to Unitholders.
The cost of equipment has escalated over the past several years as a result
of, among other things, high input costs. There is no assurance that Precision
will be able to recover higher capital costs through rate increases to its
customers, and in such event, cash distributions may be reduced.
ACCESS TO ADDITIONAL FINANCING
Precision may find it necessary in the future to obtain additional debt
or equity financing through the Trust to support ongoing operations, to
undertake capital expenditures or to undertake acquisitions or other business
combination transactions. There can be no assurance that additional financing
will be available to Precision when needed or on terms acceptable to
Precision. Precision's inability to raise financing to support ongoing
operations or to fund capital expenditures or acquisitions could limit
Precision's growth and may have a material adverse effect upon Precision.
RECORD OF CASH DISTRIBUTIONS/PAYMENTS
The following table sets forth the distributions paid or declared
payable by the Trust on each Trust Unit since the completion of the Plan of
Arrangement:
AMOUNT
DISTRIBUTION TYPE RECORD DATE PAYMENT DATE PER TRUST 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
The following table sets forth the amount of payments paid or payable
on each Exchangeable Unit since the completion of the Plan of Arrangement:
AMOUNT
PAYMENT TYPE RECORD DATE PAYMENT DATE PER EXCHANGEABLE 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
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 actual amount distributed or paid, if any, is
within the discretion of the Board of Trustees.
21
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.
For a more complete description of the Trust Units and the Special
Voting Unit please refer to pages 57 to 63 of the 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, 2005 and March 30, 2006 there were 124,352,921 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. The Exchangeable Units have
the economic equivalence of the Trust Units and the principal terms of the
Exchangeable Units are:
o they are exchangeable for Trust Units on a one-for-one basis at the option
of the holder;
o 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);
o 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;
o 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
22
o 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 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:
o issue or distribute Trust Units to the holders of all, or substantially
all, of the then outstanding Trust Units by way of distribution; or
o 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
o issue or distribute to the holders of all, or substantially all, of the
then outstanding Trust Units;
o 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);
o rights, options or warrants other than those described in the second
bullet above; or
o evidences of indebtedness of the Trust; or
o 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 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
(in U.S. dollars) PD.U on the TSX, and under the trading symbol PDS on the
NYSE. The following tables set forth the monthly and quarterly price range and
volume traded for the Trust Units on the TSX and NYSE from November 2005 until
March 15, 2006.
23
TSX- PD.UN(1)
(In Canadian dollars, except volume traded amounts)
PERIOD HIGH LOW CLOSE VOLUME TRADED
================================================================================================================
November 39.75 30.50 36.01 33,456,809
December 39.35 36.15 38.38 15,612,847
----------------------------------------------------------------------------------------------------------------
Q4 2005 39.75 30.50 38.38 49,069,656
----------------------------------------------------------------------------------------------------------------
January 40.75 38.00 38.00 13,417,702
February 38.95 34.00 35.53 15,792,850
March (2) 36.50 33.56 35.82 8,121,209
----------------------------------------------------------------------------------------------------------------
Q1 2006 40.75 33.56 35.82 37,331,761
----------------------------------------------------------------------------------------------------------------
NOTES:
(1) Price and volume information is taken from the website maintained by
the TSX.
(2) For the period from March 1, 2006 to March 15, 2006.
TSX - PD.U(1)
(In U.S. dollars, except volume traded amounts)
PERIOD HIGH LOW CLOSE VOLUME TRADED
================================================================================================================
November 32.50 25.00 31.34 21,472
December 34.41 31.13 32.85 25,202
----------------------------------------------------------------------------------------------------------------
Q4 2005 34.41 25.00 32.85 46,674
----------------------------------------------------------------------------------------------------------------
January 36.00 32.50 33.67 34,281
February 34.00 29.23 31.38 32,745
March (2) 32.08 28.48 30.79 22,133
----------------------------------------------------------------------------------------------------------------
Q1 2006 36.00 28.48 30.79 89,159
----------------------------------------------------------------------------------------------------------------
NOTES:
(1) Price and volume information is taken from the website maintained by
the TSX.
(2) For the period from March 1, 2006 to March 15, 2006.
NYSE - PDS(1)
(In U.S. dollars, except volume traded amounts)
PERIOD HIGH LOW CLOSE VOLUME TRADED
================================================================================================================
November 32.48 25.85 31.18 8,463,800
December 34.01 30.92 33.00 4,980,600
----------------------------------------------------------------------------------------------------------------
Q4 2005 34.01 25.85 33.00 13,444,400
----------------------------------------------------------------------------------------------------------------
January 35.13 33.10 33.53 6,633,100
February 34.12 29.79 31.49 9,138,800
March (2) 32.14 28.84 30.84 4,827,400
----------------------------------------------------------------------------------------------------------------
Q1 2006 35.13 28.84 30.84 20,599,300
----------------------------------------------------------------------------------------------------------------
NOTES:
(1) Price and volume information is taken from the website maintained by
the NYSE.
(2) For the period from March 1, 2006 to March 15, 2006.
24
TRADING PRICE AND VOLUME OF THE COMMON SHARES OF PRECISION
Prior to the reorganization of the business of Precision into the
Trust, the common shares of Precision were listed for trading on the TSX under
the trading symbol PD and (in U.S. dollars) PD.U, and on the NYSE under the
trading symbol PDS. The following table sets forth the monthly price range and
trading volumes of the common shares of Precision in 2005 prior to the
effective date of the Plan of Arrangement.
TSX - PD(1)
(In Canadian dollars, except volume traded amounts)
PERIOD HIGH LOW CLOSE VOLUME TRADED
================================================================================================================
January 86.30 71.24 84.37 8,333,688
February 97.22 83.76 94.47 6,292,605
March 97.50 85.40 90.50 7,909,619
April 98.14 86.82 90.80 6,209,453
May (2) 97.85 44.86 49.30 8,646,055
June 52.06 47.30 48.29 28,567,329
July 52.00 46.31 51.82 13,915,249
August 56.47 50.97 55.67 17,604,880
September 60.98 55.68 57.21 31,600,603
October 58.00 47.43 54.30 34,585,128
November (3) 55.45 51.83 54.50 19,546,749
----------------------------------------------------------------------------------------------------------------
NOTES:
(1) Price and volume information is taken from the website maintained by
the TSX.
(2) Precision common shares split on a two-for-one basis on May 18, 2005.
(3) Ending November 7, 2005, the date on which the Plan of Arrangement
creating the Trust became effective.
TSX - PD.U(1)
(In U.S. dollars, except volume traded amounts)
PERIOD HIGH LOW CLOSE VOLUME TRADED
================================================================================================================
January 68.78 59.50 66.50 900
February 76.00 68.00 75.50 545
March 78.00 72.00 74.92 2,050
April 77.00 70.00 72.75 800
May (2) 78.29 37.00 38.50 1,000
June 40.56 38.50 40.00 1,200
July 42.10 39.00 41.50 1,700
August 46.85 42.50 46.85 1,140
September 52.00 47.50 49.00 2,615
October 46.00 42.00 42.64 1,025
November (3) - - - 0
----------------------------------------------------------------------------------------------------------------
NOTES:
(1) Price and volume information is taken from the website maintained by
the TSX.
(2) Precision common shares split on a two-for-one basis on May 18, 2005.
(3) Ending November 7, 2005, the date on which the Plan of Arrangement
creating the Trust became effective.
25
NYSE - PDS(1)
(In U.S. dollars, except volume traded amounts)
PERIOD HIGH LOW CLOSE VOLUME TRADED
================================================================================================================
January 69.62 57.77 68.20 10,859,200
February 78.45 67.89 76.32 11,507,600
March 79.69 70.19 74.66 13,673,400
April 78.68 69.66 72.17 13,261,400
May (2) 39.80 34.64 39.75 13,537,200
June 41.64 37.95 39.48 18,147,500
July 42.65 38.08 42.06 11,177,700
August 47.58 41.80 47.15 16,206,000
September 51.72 46.87 49.20 20,784,000
October 49.76 40.46 46.00 17,646,600
November (3) 47.14 45.36 45.98 2,875,400
----------------------------------------------------------------------------------------------------------------
NOTES:
(1) Price and volume information is taken from the website maintained by
the NYSE.
(2) Precision common shares split on a two-for-one basis on May 18, 2005.
(3) Ending November 7, 2005, the date on which the Plan of Arrangement
creating the Trust became effective.
ESCROWED SECURITIES
To the knowledge of the Board of Trustees and Precision's board of
directors (the "Board of Directors" and each a "Director"), no securities of
the Trust are held in escrow.
TRUSTEES, DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth, for each Trustee of the Trust and
Director and officer of Precision: his name; municipality, province or state
and country of residence; all positions and offices now held by him; the month
and year in which he was first elected a Director or officer; his principal
occupation during the preceding five years; and the number and percent of
Trust Units and Exchangeable Units that he has advised are beneficially owned
by him, directly or indirectly, as of the date hereof.
================================================================================================================================
TRUST UNITS /
EXCHANGEABLE UNITS
NAME, MUNICIPALITY, POSITION DIRECTOR/ BENEFICIALLY OWNED,
PROVINCE & COUNTRY OF PRESENTLY OFFICER PRINCIPAL OCCUPATION CONTROLLED OR
RESIDENCE HELD(1) SINCE DURING THE PRECEDING 5 YEARS DIRECTED (2)
================================================================================================================================
W.C. (Mickey) Dunn(3)(4)(6) Director September Chairman, True Energy Trust 15,600 / nil
Edmonton, Alberta, Canada 1992 0.012% / nil
--------------------------------------------------------------------------------------------------------------------------------
Brian A. Felesky, CM, Q.C. Director December Partner, Felesky Flynn LLP 2,800 / nil
Calgary, Alberta, Canada 2005 0.002% / nil
--------------------------------------------------------------------------------------------------------------------------------
Robert J.S. Gibson(3)(4)(5)(6) Trustee June 1996 President, Stuart & Company Limited 63,200(7) / nil
Calgary, Alberta, Canada Director 0.050% / nil
--------------------------------------------------------------------------------------------------------------------------------
Patrick M. Murray(4)(5) Trustee July 2002 Chairman and Chief Executive Officer, 40,000 / nil
Dallas, Texas, USA Director Dresser, Inc. 0.032% / nil
--------------------------------------------------------------------------------------------------------------------------------
Frederick W. Pheasey(3)(4)(6) Director July 2002 Director of Dreco Energy Services Ltd. 44,000 / nil
Edmonton, Alberta, Canada
--------------------------------------------------------------------------------------------------------------------------------
Robert L. Phillips(3)(4)(6) Director May 2004 President and Chief Executive Officer, BCR 5,000(8) / nil
Vancouver, BC, Canada Group of Companies, 2001-2004 0.005% / nil
--------------------------------------------------------------------------------------------------------------------------------
Hank B. Swartout Chairman July 1987 CEO of Precision since 1985, President of 1,413,579(9) /
Calgary, Alberta, Canada Director Precision 1985-2005 829,788(10)
CEO 1.127% / 0.661%
--------------------------------------------------------------------------------------------------------------------------------
H. Garth Wiggins(4)(5) Trustee September Principal, Kenway, Mack, Slusarchuk, 21,100 / nil
Calgary, Alberta, Canada Director 1997 Stewart, Chartered Accountants 0.017% / nil
--------------------------------------------------------------------------------------------------------------------------------
26
================================================================================================================================
TRUST UNITS /
EXCHANGEABLE UNITS
NAME, MUNICIPALITY, POSITION DIRECTOR/ BENEFICIALLY OWNED,
PROVINCE & COUNTRY OF PRESENTLY OFFICER PRINCIPAL OCCUPATION CONTROLLED OR
RESIDENCE HELD(1) SINCE DURING THE PRECEDING 5 YEARS DIRECTED (2)
================================================================================================================================
Gene C. Stahl President & November Vice President, Precision Rentals 2003 - 28,000 / nil
Calgary, Alberta Canada Chief 2005 2005, General Manager Ducharme Rentals/Big 0.022% / nil
Operating D Rentals 2002 - 2003, Investor Relations
Officer Officer, Precision Drilling Corporation
2001 - 2002
-------------------------------------------------------------------------------------------------------------------------------
Doug J. Strong Chief November Chief Financial Officer, Precision 24,000 / nil
Calgary, Alberta, Canada Financial 2005 Diversified Services Ltd. 2001 - 2005, 0.019% / nil
Officer Group Controller, Precision Drilling 2001 -
2005, Senior Controller, Precision Drilling
1997 - 2001
-------------------------------------------------------------------------------------------------------------------------------
Darren J. Ruhr Vice November Director, Information Technology, Real 11,000 / nil
Calgary, Alberta, Canada President, 2005 Estate & Travel, Precision Drilling 0.009% / nil
Corporate Corporation 2003 - 2005, Director,
Services & Information Technology, Precision Drilling
Corporate Corporation 2000 - 2003
Secretary
-------------------------------------------------------------------------------------------------------------------------------
NOTES:
(1) Each Director's term of office expires not later than the close of
business at the next annual meeting, or until successors are appointed
or Directors vacate their office, and Directors are normally not
renominated following the earlier of their fifteenth term or 69th
birthday.
(2) Percentage of Trust Units and Exchangeable Units beneficially owned is
calculated based on an aggregate of 125,461,303 Trust Units and
Exchangeable Units outstanding as of the Effective Date.
(3) Member of the Corporate Governance and Nominating Committee.
(4) Member of the Special Committee formed during fiscal 2005.
(5) Member of the Audit Committee.
(6) Member of the Compensation Committee.
(7) 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.
(8) 2,000 Trust Units are held by R.L. Phillips Investments Inc., a company
controlled by Mr. Phillips.
(9) The Trust Units include 10,541 held in a registered retirement plan for
the benefit of Mr. Swartout.
(10) The Exchangeable Units are held by 1201112 Alberta Ltd., a company
controlled by Mr. Swartout.
CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS
No Trustee or 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.
At March 15, 2006, the Trustees, the Directors and the executive
officers of Precision, as a group, beneficially owned, directly or indirectly,
or exercised control over 1,668,279 Trust Units and 829,788 Exchangeable Units
or approximately 1.99% of the issued and outstanding Trust Units and
Exchangeable Units.
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 consists of Patrick M. Murray
(Chairman), H. Garth Wiggins and Robert J. S. Gibson. The Audit Committee is a
standing committee appointed by the Board of Directors to assist the Board of
Directors in fulfilling its oversight responsibilities with respect to
financial reporting by Precision and the Trust, in its own capacity and in its
capacity as the administrator of the Trust. Each member of the Audit Committee
is independent and none received, directly or indirectly, any compensation
from Precision or the Trust other than for services as a member of the Board
of Trustees of the Trust or the Board of Directors of Precision and its
committees. All members 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 both Messrs. Murray and
Wiggins qualify as "audit committee financial experts" as that term is defined
under the United States SARBANES-OXLEY ACT OF 2002.
27
RELEVANT EDUCATION AND EXPERIENCE
In addition to each member's general business experience, the education
and experience of each Audit Committee member that is relevant to the
performance of his responsibilities as an Audit Committee member are as
follows: Patrick M. Murray (Chair) is the Chairman, President and Chief
Executive Officer of Dresser, Inc. Mr. Murray received a B.Sc. degree in
Accounting in 1964 from Seton Hall University and an MBA in 1973. Mr. Murray
has been a member of Precision's Audit Committee since April 2003. H. Garth
Wiggins received his Bachelor of Electrical Engineering from the University of
Saskatchewan in 1970 and his Chartered Accountant designation in 1974. Mr.
Wiggins is a Principal at Kenway, Mack, Slusarchuk, Stewart, Chartered
Accountants. Mr. Wiggins has been a member of the Audit Committee since
September 1997. Robert J.S. Gibson was educated at the University of Calgary
and the University of Alberta. Mr. Gibson is the President of Stuart & Company
Limited and has been a member of the Audit Committee since June 1997.
PRE-APPROVAL POLICIES AND PROCEDURES
Under the Audit Committee Charter, the Audit Committee is required to
approve the terms of the annual audit engagement and the compensation to be
paid to the external auditor of the Trust for the annual audit. In addition,
the Audit Committee is required to review and pre-approve all permitted
non-audit services to be provided to the Trust or any affiliated entities by
the external auditors or any of their affiliates subject to any DE MINIMUS
exception allowed by applicable law. The Audit Committee may delegate to one
or more designated members of the Audit Committee the authority to pre-approve
non-audit services. Non-audit services that have been pre-approved by any such
delegate must be presented to the Audit Committee at its first scheduled
meeting following such pre-approval.
The Audit Committee implemented specific procedures regarding the
pre-approval of services to be provided by Precision's external auditor
commencing in 2003. These procedures specify certain prohibited services that
are not to be performed by the external auditor. In addition, these procedures
require that at least annually, prior to the period in which the services are
proposed to be provided, Precision's management will, in conjunction with the
Trust's external auditor, prepare and submit to the Audit Committee a complete
list of all proposed services to be provided to Precision and the Trust by the
external auditor. Under the Audit Committee pre-approval procedures, for those
services proposed to be provided by the external auditor that have not been
previously approved by the Audit Committee, the Chairman of the Audit
Committee has the authority to grant pre-approvals of such services. The
decision to pre-approve a service covered under this procedure is required to
be presented to the full Audit Committee at the next scheduled meeting. At
each of the Audit Committee's regular meetings, the Audit Committee is to be
provided with an update as to the status of services previously pre-approved.
Pursuant to these procedures, since their implementation in 2003, 100%
of each of the services provided by the Trust's external auditor relating to
the fees reported as audit, audit-related, tax and all other fees were
pre-approved by the Audit Committee or its delegate.
AUDIT FEES
The following table provides information about fees billed to the Trust
and its affiliates for professional services rendered by KPMG LLP, the Trust's
external auditor, during fiscal 2005 and 2004:
============================================================
(IN THOUSANDS $)
YEARS ENDED DECEMBER 31, 2005 2004
============================================================
Audit fees $ 2,108 $ 2,257
Audit-related fees - 24
Tax fees 753 456
All other fees 54 5
------------------------------------------------------------
TOTAL $ 2,915 $ 2,742
------------------------------------------------------------
Audit fees consist of fees for the audit of the Trust's annual
financial statements or services that are normally provided in connection with
statutory and regulatory filings or engagements.
Audit-related fees consist of fees for assurance and related services
that are reasonably related to the performance of the audit or review of the
Trust's financial statements and are not reported as audit fees. In 2004, the
services provided in this category related to due diligence assistance with
respect to an acquisition.
28
Tax fees consist of fees for tax compliance services, tax advice and
tax planning. During fiscal 2005 and 2004, the services provided in this
category included assistance and advice in relation to the preparation of
corporate 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
information and due diligence assistance with respect to a disposition. In
2004, other fees related to translation of financial statements and
information.
LEGAL PROCEEDINGS
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.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
There were no material interests, direct or indirect, of the Trustees,
Directors and executive officers of Precision, any Unitholder who beneficially
owns more than 10% of the outstanding Trust Units or Exchangeable Units, or
any known associate or affiliate of such persons, in any transaction within
the last fiscal year and in any proposed transaction which has materially
affected or would materially affect the Trust, PDLP or Precision.
TRANSFER AGENT, REGISTRAR AND VOTING AND EXCHANGE TRUSTEE
Computershare Trust Company of Canada, located in Calgary, Alberta, is
the transfer agent and registrar of the Trust Units and the Special Voting and
Exchange Trustee for the holders of Exchangeable Units. In the United States,
the co-transfer agent for the Trust is Computershare Trust Company, Inc.
located in New York, New York.
MATERIAL CONTRACTS
The only material contracts entered into by Precision, the Trust or
PDLP during the most recently completed financial year, or before the most
recently completed financial year that are still in effect, other than
contracts during the ordinary course of business, are as follows:
1. Weatherford Sale Agreement; 2. CEDA Sale Agreement; 3. Declaration of
Trust; 4. Limited Partnership Agreement; 5. Voting and Exchange Trust
Agreement; 6. Support Agreement; and 7. Administration Agreement.
Copies of the material agreements described as 1 and 2 above have been
filed by Precision and the remainder of the material agreements described
above have been filed by the Trust on SEDAR and are available online at
www.sedar.com.
INTERESTS OF EXPERTS
KPMG LLP, the Trust's external auditor, has prepared an opinion with
respect to the Trust's consolidated financial statements as at and for the
year ended December 31, 2005. In connection with the audit of the Trust's
annual financial statements for the year ended December 31, 2005, the auditors
confirmed that they are independent within the meaning of the Rules of
Professional Conduct of the Institute of Chartered Accountants of Alberta.
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
As of the fiscal year ended December 31, 2005, an evaluation of the
effectiveness of the Trust's "disclosure controls and procedures" (as such
term is defined in Rules 13a-15(e) and 15d-15(e) of the United States
Securities Exchange Act of 1934, as amended (the "Exchange Act")) was carried
out by Precision's Chief Executive Officer and Chief Financial Officer for
29
Precision on behalf of the Trust. Based upon that evaluation, the Chief
Executive Officer and Chief Financial Officer have concluded that as of the
end of that fiscal year, the Trust's disclosure controls and procedures are
effective to ensure that information required to be disclosed by the Trust in
reports that it files or submits under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified in the
Securities and Exchange Commission rules and forms.
During the fiscal year ended December 31, 2005, there were no changes
in the Trust's internal control over financial reporting that have materially
affected, or are reasonably likely to materially affect, the Trust's internal
control over financial reporting.
It should be noted that while Precision's Chief Executive Officer and
Chief Financial Officer believe that the Trust's disclosure controls and
procedures provide a reasonable level of assurance that they are effective,
they do not expect that the Trust's disclosure controls and procedures or
internal control over financial reporting will prevent all errors and fraud. A
control system, no matter how well conceived or operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system
are met.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Management's Discussion and Analysis relating to the consolidated
financial statements for the fiscal year ended December 31, 2005 forms part of
the Trust's 2005 Annual Report and is incorporated by reference in this Annual
Information Form. Management's Discussion and Analysis appears on pages 47 to
72 of the 2005 Annual Report.
ADDITIONAL INFORMATION
Additional information concerning the Trust is available through the
Internet on SEDAR which may be accessed at www.sedar.com. Copies of such
information may also be obtained without charge, on the Trust's website at
www.precisiondrilling.com or by request to the Vice President, Corporate
Services and Corporate Secretary, at the offices of Precision at 4200, 150 -
6th Avenue S.W., Calgary, Alberta, Canada T2P 3Y7; by email at
info@precisiondrilling.com; by telephone at 403.716.4500; and by facsimile at
403.264.0251.
Additional information, including information regarding Precision's
Directors' and officers' remuneration, is contained in the Management
Information Circular of the Trust provided for the Annual Meeting of
Unitholders of the Trust to be held on May 9, 2006. Additional financial
information is provided in the Trust's annual consolidated financial
statements and management's discussion and analysis for the year ended
December 31, 2005, which are contained in the Annual Report. Copies of such
documents may be obtained in the manner set forth above.
30
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 "Audit Committee") of Precision Drilling Corporation
("Precision"). The Audit Committee is a standing committee of the board of
directors of Precision (the "Board of Directors" and each a "Director")
appointed to assist the Board of Directors in fulfilling its oversight
responsibilities with respect to financial reporting by Precision, in its own
capacity and as the administrator for the 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, 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 of the Trust (the "Board of Trustees" and each a "Trustee"),
in a timely fashion. The activities of the Audit Committee are fundamental to
the process.
STATUTORY AND REGULATORY REFERENCES
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 U.S. Securities Exchange Act of 1934
(the "U.S. Exchange Act") for issuers listed on the New York Stock Exchange
(the "NYSE").
COMMITTEE STRUCTURE
The Board of Directors shall elect annually, from members of the Board of
Directors, an Audit Committee which shall be comprised of not less than three
members, at least half of which are resident Canadians. All members of the
Audit Committee must be independent directors (as defined in the rules of the
SECURITIES ACT (Alberta) and the U.S. Exchange Act), every Audit Committee
member must be financially literate and at least one of those members must
qualify as a financial expert as defined in the U.S. Exchange Act by having
accounting or related financial management expertise. No Audit Committee
member shall serve on the audit committee of more than three public companies
without prior determination by the Board of Directors that such simultaneous
service does not impair the ability of such Director to serve effectively on
the Audit Committee.
Each member of the Audit Committee shall serve during the pleasure of the
Board of Directors and, in any event only so long as that person shall be a
Director. The Directors may fill vacancies in the Audit Committee by election
from among their number.
The Audit Committee shall have the power to fix its quorum at not less than a
majority of its members and to determine its own rules of procedure subject to
applicable regulatory requirements and any regulations imposed by the Board of
Directors from time to time.
The external auditor of Precision and the Trust will be entitled to receive
notice of every meeting of the Audit Committee and, at the expense of
Precision, to attend and be heard thereat, and if so requested by a member of
the Audit Committee, shall attend every meeting of the Audit Committee held
during the term of the office of the external auditor. The external auditor of
Precision and the Trust or any member of the Audit Committee may call a
meeting of the Audit Committee.
PURPOSE
The Audit Committee shall have responsibility for overseeing the development
and maintenance of Precision's and the Trust's systems for financial
reporting. Accounting for transactions and internal control over financial
reporting lies with senior management with oversight responsibilities vested
in the Board of Directors. The Audit Committee is a permanent committee of the
Board of Directors whose purpose is to assist the Board of Directors by
dealing with specific issues including:
31
o those that may affect the integrity of financial reporting to the
holders of the units of the Trust and holders of Class B Limited
Partnership Units of Precision Drilling Limited Partnership (together
the "Unitholders") and the investment community, accounting and
internal controls;
o Precision's and the Trust's compliance with legal and regulatory
requirements as they relate to financial reporting matters;
o the external auditor's qualifications and independence;
o the performance of Precision's and the Trust's internal audit function
and its external auditor; and
o conducting an evaluation of the external auditor's qualifications and
independence.
COMMITTEE RESPONSIBILITIES
The Audit Committee shall:
o review the annual financial statements of the Trust and related notes
and management's discussion and analysis ("MD&A") component 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;
o review the interim financial statements of the Trust and related notes
and MD&A component prepared for distribution to the Unitholders and the
investment community;
o be satisfied that adequate procedures are in place for the review of
the Trust's public disclosure of financial information extracted or
derived from the Trust's financial statements, other than the public
disclosure referred to in the point above, and must periodically assess
the adequacy of those procedures;
o assess the external auditor's performance 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;
o report through the Chairman of the Audit Committee to the Board of
Directors following each meeting of the Audit Committee. The report
would outline the nature of discussions and the major decisions reached
by the Audit Committee;
o recommend to the Board of Directors the external auditor to be
appointed as the auditor of Precision and the Trust and the
compensation of such external auditor;
o require the external auditor to report directly to the Audit Committee;
o pre-approve all non-audit services to be provided to the Trust,
Precision or any subsidiary entities by the external auditor. The Audit
Committee may delegate to the Chairman of the Audit Committee the
authority to pre-approve non-audit services. Non-audit services that
have been pre-approved by the Chairman of the Audit Committee must be
presented to the Audit Committee at its first scheduled meeting
following such pre-approval;
o review and discuss with management and the external auditor, as
applicable, (a) major issues regarding accounting principles and
financial statement presentations including any significant changes in
the Trust's selection or application of accounting principles, and
major issues as to the adequacy of the Trust's internal controls and
any special audit steps adopted in light of material control
deficiencies; (b) 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; (c) any management letter provided by the
external auditor and the Trust's response to that letter and other
material written communication between the external auditor and
33
management; (d) any problems, difficulties or differences encountered
in the course of the audit work including any disagreements with
management or restrictions on the scope of the external auditor's
activities or on access to requested information and management's
response thereto; (e) the effect of regulatory and accounting
initiatives, as well as any off-balance sheet structures on the
financial statements of the Trust; and (f) 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 (generally on a case-by-case basis) provided to analysts and
rating agencies.
o discuss with management Precision's major financial risk exposures and
the steps management has taken to monitor and control such exposures,
including Precision's risk assessment and risk management policies;
o annually request and review a report from the external auditor
regarding (a) the external auditor's quality-control procedures, (b)
any material issues raised by the most recent quality-control review or
peer review of the firm, 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, (c) any steps taken to deal with any such issues, and (d) all
relationships between the external auditor and Precision or the Trust;
o evaluate the qualifications, performance and independence of the
external auditor, including a review and evaluation of the lead partner
of the external auditor and set clear hiring policies for employees or
former employees of the external auditor;
o ensure that the lead audit partner of the external auditor and the
audit partner responsible for reviewing the audit are rotated at least
every five years as required by the Sarbanes-Oxley Act of 2002, and
further consider rotation of the external auditor's firm itself;
o discuss with management and the external auditor any accounting
adjustments that were noted or proposed by the external auditor but
were not adopted (as immaterial or otherwise);
o establish procedures for (a) the receipt, retention and treatment of
complaints received by the Trust regarding accounting, internal
controls or auditing matters, and (b) the confidential, anonymous
submission by employees of Precision of concerns regarding questionable
accounting or auditing matters;
o review other financial information included in the Trust's Annual
Report to ensure that it is consistent with the Board of Directors'
knowledge of the affairs of Precision and the Trust is unbiased and
non-selective;
o review the MD&A component of the Trust's Annual Report and the
quarterly reports;
o take steps to ensure that adequate procedures are in place for the
review of the Trust's public disclosure of financial information
extracted or derived from the Trust's financial statements and
periodically assessing the adequacy of those procedures;
o prepare any report required by law, regulations or exchange requirement
to be included in the Trust's periodic reports;
o meet at least four times a year on a quarterly basis or more frequently
as circumstances require, and at least annually with the internal and
external auditor of Precision and the Trust;
o report regularly to the Board of Directors;
o review planning for, and the results of, the annual external audit and
solely approve:
o the external auditor's engagement letter as agreed between the
external auditor and financial management of Precision and the
Trust;
33
o the reasonableness of audit fees as agreed between the external
auditor and corporate management;
o audit scope, including locations to be visited, areas of audit
risk, materiality as it affects audit judgment, timetable,
deadlines, coordination with internal audit;
o the audit report to Unitholders and the investment community and
any other reports prepared by the external auditor;
o the informal reporting from the external auditor on accounting
systems and internal controls, including management's response;
o non-audit related services provided by the external auditor;
o assessment of the external auditor's performance; and
o the external auditor's appointment or re-appointment or
replacement;
o review and evaluate the scope, risk assessment, and nature of the
internal audit plan and any subsequent changes;
o consider and review the following issues with management and the head
of internal audit;
o significant findings of the internal audit group as well as
management's response to them;
o any difficulties encountered in the course of their internal
audits, including any restrictions on the scope of their work or
access to required information;
o the internal auditing budget and staffing;
o the Audit Services Charter; and
o compliance with the Institute of Internal Auditors' Standards for
the Professional Practice of Internal Auditing;
o approve the appointment, replacement, or dismissal of the head of the
internal audit group; and
o direct the head of the internal audit group to review any specific
areas the Audit Committee deems necessary.
In addition, the Audit Committee shall hold in-camera meetings with
representatives of the external and internal auditors to discuss the audit
related issues including the quality of accounting personnel.
The Audit 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.
The Audit Committee shall also carry out an annual performance evaluation of
such committee and review and reassess annually the adequacy of the Charter
and Terms of Reference and recommend changes, as appropriate to the Board of
Directors.
COMMITTEE AUTHORITY
The Audit Committee shall have the authority, to the extent it deems necessary
or appropriate, to retain special legal, accounting or other consultants to
advise the Audit Committee and carry out its duties, and to conduct or
authorize investigations into any matters within its scope of
responsibilities. The Audit Committee shall have the authority to set and pay
the compensation for any advisors employed by the Audit Committee.
The Audit Committee may request any officer or employee of Precision or
Precision's or the Trust's outside counsel or external or internal auditors to
attend a meeting of the Audit Committee or to meet with any members of, or
consultants to the Audit Committee.
The Audit Committee shall review its Charter and Terms of Reference and, as
required, propose changes to the Board of Directors.
The Audit Committee shall have the authority to communicate directly with the
internal and external auditor.
34
LIMITATION OF AUDIT COMMITTEE'S ROLE
While the Audit Committee has the responsibilities and powers set forth in its
Charter, it is not the duty of the Audit Committee to prepare financial
statements, plan or conduct audits or to determine that the Trust's financial
statements and disclosures are complete and accurate and are in accordance
with GAAP and applicable rules and regulations. These are the responsibilities
of management and the external auditor.
UPDATED AND APPROVED BY THE AUDIT COMMITTEE MARCH 7, 2006
35
MANAGEMENT'S DISCUSSION AND ANALYSIS
The Management's Discussion and Analysis, prepared as at March 7, 2006,
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 excludes
changes that may occur in general economic, political and environmental
conditions. Additionally, other elements may or may not occur which could
affect Precision Drilling Trust (the "Trust" or "Precision") in the future. In
order to obtain the best 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 2, 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, 2004 and 2003, 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 UNIT/SHARE AMOUNTS, WHICH ARE PRESENTED ON A DILUTED BASIS)
----------------------------------------------------------------------------------------------------------------------------
INCREASE Increase
YEARS ENDED DECEMBER 31, 2005 (DECREASE) % CHANGE 2004 (Decrease) % Change 2003
----------------------------------------------------------------------------------------------------------------------------
Revenue 1,269,179 240,691 23 1,028,488 113,318 12 915,170
Operating earnings(1) 465,378 134,065 40 331,313 78,864 31 252,449
Earnings from continuing operations 220,848 32,717 17 188,131 43,983 31 144,148
Discontinued operations 1,409,715 1,350,442 2,278 59,273 22,947 63 36,326
Net earnings 1,630,563 1,383,159 559 247,404 66,930 37 180,474
Earnings per unit/share from
continuing operations 1.76 0.15 9 1.61 0.30 23 1.31
Net earnings per unit/share 13.00 10.89 516 2.11 0.48 29 1.63
Cash flow from continuing operations 203,101 (84,720) (29) 287,821 86,900 43 200,921
Net capital spending from
continuing operations 140,077 26,180 23 113,897 29,039 34 84,858
Distributions to unitholders 70,510 70,510 N/A - - - -
Distributions per unit 0.56 0.56 N/A - - - -
============================================================================================================================
(1) OPERATING EARNINGS IS NOT A RECOGNIZED MEASURE UNDER CANADIAN GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (GAAP). MANAGEMENT BELIEVES THAT IN
ADDITION TO NET EARNINGS, OPERATING EARNINGS IS A USEFUL SUPPLEMENTAL
MEASURE AS IT PROVIDES AN INDICATION OF THE RESULTS GENERATED BY THE
TRUST'S PRINCIPAL BUSINESS ACTIVITIES PRIOR TO CONSIDERATION OF HOW THOSE
ACTIVITIES ARE FINANCED OR HOW THE RESULTS ARE TAXED. INVESTORS SHOULD BE
CAUTIONED, HOWEVER, THAT OPERATING EARNINGS SHOULD NOT BE CONSTRUED AS AN
ALTERNATIVE TO NET EARNINGS DETERMINED IN ACCORDANCE WITH GAAP AS AN
INDICATOR OF PRECISION'S PERFORMANCE. PRECISION'S METHOD OF CALCULATING
OPERATING EARNINGS MAY DIFFER FROM OTHER ENTITIES AND, ACCORDINGLY,
OPERATING EARNINGS MAY NOT BE COMPARABLE TO MEASURES USED BY OTHER
ENTITIES.
36
FINANCIAL POSITION AND RATIOS
(STATED IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT RATIOS)
Years ended December 31, 2005 2004 2003
-------------------------------------------------------------------------------------------------------------
Working capital $ 152,754 $ 557,311 $ 248,994
Working capital ratio 1.4 2.5 1.6
Long-term debt(1) $ 96,838 $ 718,850 $ 399,386
Total assets $ 1,718,882 $ 3,852,049 $ 2,932,030
Long-term debt to long-term debt plus equity(1) 0.08 0.24 0.19
Long-term debt to cash flow from continuing operations(1) 0.5 2.5 2.0
Interest coverage(2) 15.9 7.2 7.4
=============================================================================================================
(1) EXCLUDES CURRENT PORTION OF LONG-TERM DEBT WHICH IS INCLUDED IN WORKING
CAPITAL.
(2) OPERATING EARNINGS DIVIDED BY NET INTEREST EXPENSE.
The year 2005 was a period of significant change at Precision. In the
second quarter, Precision entered into an agreement to sell its Energy
Services and International Contract Drilling divisions to Weatherford
International Ltd. ("Weatherford"). This transaction closed on August 31,
2005. As well, Precision sold its industrial plant maintenance business,
carried on by CEDA, on September 13, 2005. In conjunction with funding from
the above transactions, Precision repaid its outstanding debentures on October
17, 2005.
On November 7, 2005 Precision completed its conversion into an income
trust pursuant to a plan of arrangement. As part of this conversion, Precision
made a special cash payment of $844 million and transferred almost 26 million
shares of Weatherford valued at $2.0 billion to shareholders. The resulting
reduction to retained earnings was $2.9 billion.
Underlying all this change, the continuing Canadian business
operations, our foundation, enjoyed a banner year. The continued world demand
for crude oil and the related high commodity prices in combination with record
high North American natural gas prices, manifested itself into a record 24,805
wells being drilled in the Western Canada Sedimentary Basin ("WCSB").
Precision was able to leverage off this demand through improved pricing,
higher equipment utilization and effective cost control, resulting in a $134
million or 40 percent increase in operating earnings from 2004 to 2005. This
strong performance followed a $79 million or 31 percent increase in operating
earnings from 2003 to 2004.
Despite record setting business fundamentals in 2005, earnings from
continuing operations before income taxes amounted to $293 million for an
increase of just one percent over the prior year. Results for 2005 were
reduced by one time items in the amount of $72 million for the premium paid on
early bond redemption, $71 million for the loss on disposal of the short-term
investment related to the 68-day holding period on the 26 million Weatherford
shares and $18 million in reorganization costs associated with the conversion
to an income trust. With the income trust conversion on November 7, 2005
subsequent earnings have benefited from a lower tax rate as the trust
structure has the effect of shifting the income tax burden to unitholders.
The strategic decision to dispose of Energy Services and International
Contract Drilling as well as CEDA has had a significant impact on Precision.
First, it resulted in a gain on disposal of $1.3 billion within 2005
discontinued earnings. Second, Precision's underlying total asset base as at
December 31, 2005 contracted by 55 percent from $3.9 billion in 2004 to $1.7
billion in 2005. Third, Precision's employee workforce was reduced from
approximately 12,000 in more than 25 countries to 6,500 employees in one
country, Canada.
Consistent with the new business footprint, Precision appointed an
experienced management team at the executive and functional corporate level to
effectively manage the business as it moves forward. The new management team
was appointed from within the continuing business divisions, with transition
leadership provided by the founding Chairman and Chief Executive Officer of
Precision, Mr. Hank Swartout.
With the conversion to an income trust, Precision moved from a cash
retention business model to a cash flow-through model with the adoption of a
policy to make regular monthly cash distributions to unitholders. Precision is
a mature organization that operates in a cyclical industry with sharp 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. The capital resources available to Precision as
at December 31, 2005 are strong, with positive working capital of $153 million
and long-term debt of $97 million drawn on the $550 million syndicated loan
facility.
The Canadian business platform has always been the foundation of
Precision. With the contraction in scope to our business roots, our
operational focus is set on Canada. Strategically, Precision expects to
maintain and 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 has set its sights on the market
place, with a view to participate in market growth throughout North America
and with a longer term objective to consolidate higher cost, less efficient
competitors.
37
SUMMARY OF INCOME STATEMENT
(STATED IN THOUSANDS OF CANADIAN DOLLARS)
Years ended December 31, 2005 2004 2003
----------------------------------------------------------------------------------------------------------
Operating earnings (loss)
Contract Drilling Services $ 404,385 $ 282,315 $ 218,012
Completion and Production Services 121,643 77,074 48,706
Corporate and Other (60,650) (28,076) (14,269)
----------------------------------------------------------------------------------------------------------
465,378 331,313 252,449
Interest, net 29,270 46,280 34,066
Premium on redemption of bonds 71,885 - -
Loss on disposal of short-term investments 70,992 - -
Gain on disposal of investments - (4,899) (1,493)
----------------------------------------------------------------------------------------------------------
Earnings from continuing operations before income taxes 293,231 289,932 219,876
Income taxes 72,383 101,801 75,728
----------------------------------------------------------------------------------------------------------
Earnings from continuing operations 220,848 188,131 144,148
Discontinued operations 1,409,715 59,273 36,326
Net earnings $ 1,630,563 $ 247,404 $ 180,474
==========================================================================================================
ECONOMIC DRIVERS OF THE GLOBAL OILFIELD SERVICES BUSINESS
In Canada, the economics of an oilfield service company align with
global and regional fundamentals as described in the paragraphs that follow.
Important regional drivers for the oilfield service business in Canada include
the underlying hydrocarbon make-up of 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 75 percent of new well completions in 2005 were targeted towards
natural gas. In general terms, drilling activity in the WCSB is split between
the provinces with 75 percent in Alberta, 15 percent in British Columbia and
the remaining 10 percent in Saskatchewan. At present, the activity levels in
northern Canada and areas east are relatively low. Areas in Canada's north
hold significant promise for the future as pipeline and local community
relations are established. The Canadian oilfield service industry dates back
to the 1940s and has given Canada the means to develop its reserves to meet
domestic consumption and to provide large export capacity, primarily to the
United States.
The hydrocarbon structure of the WCSB is world class in its diversity.
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 reservoirs associated
with oil sands, heavy oil, coal bed methane or natural gas in coal and tight
natural gas in deeper formations. These sources of energy border with the
largest consumer of hydrocarbons in the world, the United States.
Crude oil and natural gas are the primary sources of energy in the
world. As history has proven, it takes decades if not centuries to displace
energy sources. As a result, hydrocarbon production will remain critical to
the world's energy needs for the foreseeable future, with demand forecasted by
many to continue to increase, as illustrated below.
The provision of these commodities to the consuming public involves a
number of players, each of which take on different risks in the process of
exploring for, producing, refining and distributing hydrocarbons and
associated refined by-products. Exploration and production companies assume
the risk of finding hydrocarbons in pools of sufficient size to economically
develop and produce reserves. The economics of exploration and production is
dictated by the current and expected future margin between the cost to find
and develop hydrocarbons and the price at which those products can be sold.
The wider the margin, the more incentive there is to undertake the activities
involved in the process of exploration and development.
These activities include acquiring access to prospective lands,
shooting seismic to detect the presence of hydrocarbon-bearing structures,
drilling wells and measuring the characteristics of subsurface geological
formations. Exploration and production companies hire oilfield service
companies to perform the majority of these services. The revenue for an
oilfield service company is part of an exploration and production company's
finding and development costs.
Providing these oilfield services incorporates three main elements:
people, technology and equipment. Attracting, training and retaining qualified
employees is the single biggest challenge for a service company. Exploration
and production activities are taking place in an ever increasing variety of
surface and subsurface conditions. Developing technology and building
38
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 risks assumed by oilfield service
companies are the volatility of activity levels that translate into
utilization rates for its investment in people, technology and equipment, and
cost control to maximize the margins earned.
The economics of a service company are thus largely driven by the
current and expected price of crude oil and natural gas, which are determined
by the supply and demand for these commodities. Since crude oil can be
transported relatively easily, it is priced in a worldwide market, which is
influenced by a wide array of economic and political factors. Natural gas is
priced in more local markets due to the requirement to transport this gaseous
product in pressurized pipelines, although this is changing slowly with the
emergence of liquefied natural gas ("LNG"). North America will need to compete
on a global basis to secure access to LNG supplies as demand in other parts of
the world continues to rise.
Although, as illustrated, crude oil and natural gas prices have
historically been quite volatile, the upward trend since 2002 has endured and
resulted in very high commodity price levels to exit 2005. Certainly, weather
was a factor in the Gulf of Mexico this past hurricane season, as Katrina and
others caused tremendous damage to production infrastructure and caused a
spike in commodity pricing during September 2005. These events highlight the
narrow tolerance and lack of surplus capacity to compensate for oil or natural
gas production that may suddenly go off-line. The supply and demand balance is
narrow and significant industry reinvestment is required to add and replace
old infrastructure. Many industry observers believe that a new pricing floor
is being set due to the pace of production decline in combination with demand
growth projections. Clearly, hydrocarbons are a non-renewable resource that is
more costly and difficult to discover and develop. West Texas Intermediate
(WTI) oil prices averaged US$56 per barrel during 2005, an increase of 37
percent over the 2004 average of US$41 per barrel. Oil prices continue to be
affected by political instability in some OPEC member nations (Venezuela,
Iraq, Nigeria and Iran) and from a strengthening world economy with energy
demand growth particularly strong in China, India and Southeast Asia.
Consistent with commentary over the past three years, North American
natural gas prices are also being supported by strong fundamentals. North
American Henry Hub natural gas prices surged 45 percent in 2005 averaging
US$8.96 per mmbtu, an increase of US$2.78 per mmbtu over 2004. Demand for
natural gas is increasing with economic growth while supply from relatively
mature producing basins is continuing to gradually decline. The record North
American drilling levels over the past three years have served to slow the
decline in the production rate and this situation is not expected to change in
the near future. High oil prices also serve to support natural gas prices as
the economic benefits of switching between the two fuels is minimal. The graph
at left demonstrates decline rates in natural gas production in Alberta.
The graph at the top of page 52 shows that the number of producing
natural gas wells has dramatically increased over the past decade. This,
coupled with the previous graph, which indicates natural gas production
remains flat with high decline rates, suggests that more wells are required to
be drilled in order to meet North American supply needs. This situation could
be further magnified if the demand for natural gas continues to strengthen.
The demand for crude oil and natural gas is forecast to increase over the next
two decades.
Over the last decade, customers in North America have shifted focus
from crude oil and are pursuing alternatives such as natural gas, coal and
nuclear power, looking for cleaner sources of energy. The parameters for
natural gas, however, remain the strongest as it is a proven, environmentally
efficient energy source with infrastructure in place. Other sources of natural
gas such as coal bed methane will be required in western Canada to replace the
production decline in sweet and sour natural gas wells in the WCSB.
In spite of record drilling activity, production levels remain
relatively flat. The trend in recent years is for customers to drill shallow
gas wells within existing reservoirs to exploit reserves. This is supported by
the fact that over 75 percent of the natural gas wells drilled in 2005 were
shallow wells. The shallow wells are quick, easy finds with relatively rapid
declines in production rate.
Reserve to production ratios, which are an indication of how quickly
reserves are depleting, are beginning to flatten after a period of decline
starting in the 1990s. The end result of these trends is that drilling
activity must stay the same or increase to allow current production levels to
be maintained. This situation is leading producers to drill deeper resource
plays to extend their natural gas reserve life index. Increasingly, industry
is looking for the next big, prolific natural gas field. This situation bodes
well for the oilfield service industry and Precision's contract drilling
services segment, in particular, with respect to its overweighting in deep
drilling rig capacity.
The graph at left depicts the increase in natural gas completions over
the past eleven years and its direct correlation to natural gas pricing. To
begin 2006, we are experiencing the effects of having record amounts of
natural gas in storage as we close out the winter heating season. Natural gas
prices are falling because of the warmer weather that is being experienced
throughout North America. It is important to consider that natural gas prices
are still more than triple the US$2.00 per mmbtu average seen in the 1990s. We
also have to be cognizant of the fact that there is a lead time to drill and
tie-in new discoveries. Even with commodity price declines, it is questionable
whether customers in the short term will slow down exploration and development
given demand growth. Conversely, the lower natural gas prices will most likely
lead to additional consumption.
39
Precision is the industry leader in Canada for providing a wide array
of oilfield services. The Canadian industry is in a good position as the
United States, the largest consumer of energy, is looking to Canadian
production to help meet its energy needs. The worldwide demand for crude oil
looks to be ever increasing. China, the world's second largest oil consumer,
imports more than 40 percent of its needs. Additionally, India, the second
most populated country and third largest consumer, currently imports 70
percent of its needs.
In light of this, the supply of drilling rigs in Canada has steadily
increased over the past 12 years to 770, an all-time high. Customer demand as
measured by operating day utilization peaked at 71 percent in 1997 and has
ranged between 38 percent and 60 percent since that time. Rig industry
utilization was 60 percent for 2005. The recent higher utilization levels have
caused the drilling contractors to add capacity. During the year, 50 drilling
rigs were added and an additional 100 new rig builds are anticipated in the
coming year, many of which are without long-term contracts. The bulk of these
new builds are either telescopic doubles or coil tubing units. In the
short-term, capacity is geared towards peak winter demand. In the long-term,
it provides the capacity to drill more wells through better utilization during
the remainder of a year. If commodity prices weaken for a prolonged period,
the industry may have a large supply and demand imbalance. Clearly, the
industry believes that the pace of drilling to sustain natural gas production
for domestic Canadian use and export to the United States will keep equipment
utilization strong.
There were 50 new drilling rigs added to the Canadian industry fleet
during 2005, a seven percent increase to the total. Of these additional rigs,
68 percent had a depth rating of less than 1,500 metres with new coiled tubing
rigs leading the way with 21 and singles with 13. Customer demand to drill
conventional natural gas and oil wells, in combination with improving
commercialization of natural gas in coal, oil sands and tight natural gas
formations are driving demand for rigs to record levels.
Just as natural gas is a North American commodity, drilling rigs are,
although to a lesser degree, available to work in the Canadian and lower 48
United States markets. It is interesting to note that while the Canadian
drilling rig count is at an all time high, the count in the United States is
one third of the capacity that was in existence in the early 1980s, as
illustrated in the graph at left.
PRECISION'S DEVELOPMENT IN THE OILFIELD SERVICES BUSINESS
Precision began in western Canada as a land drilling contractor and our
development has matched that of the WCSB. Initially founded in 1985 as Cypress
Drilling Ltd., the business quickly grew from four drilling rigs to 19 with
the reverse takeover in 1987 of Precision Drilling Ltd., a company formed in
1952. Over the following decade, a series of nine acquisitions expanded the
Canadian drilling rig fleet to 200 as of May 1997 and established a 40 percent
market share of industry rigs. Diversification into service rigs and snubbing
operations came with the 1996 acquisition of EnServ Corporation. In the second
half of the year 2000, Precision became fully vested in the Canadian service
rig business as the CenAlta Energy Services Inc. acquisition created a
combined fleet of 257 service rigs and a leading industry market share of 28
percent. The additional acquisition in 2000 of coil tubing drilling rigs and
other shallow drilling rigs rounded out key milestones in our Canadian asset
base growth.
Precision's success is dependant on providing a complement of oilfield
services that are cost effective to exploration and production companies,
enabling them to find and develop hydrocarbon pools of sufficient size to
economically produce. Precision prides itself on providing quality equipment
operated by teams of highly experienced and well trained crews. In order to
facilitate customer needs and to optimally manage our business, Precision is
divided into two operating segments:
Contract Drilling Services is comprised of:
o Precision Drilling - 230 drilling rigs - 30 percent of industry
o LRG Catering ("LRG") - 92 drilling camps - 20 percent of industry
o Rostel Industries ("Rostel") - manufactures and refurbishes
drilling rig components
o Columbia Oilfield Supply ("Columbia") - centralized procurement,
inventory and distribution of consumable supplies
Completion and Production Services is comprised of:
o Precision Well Servicing ("PWS") - 237 service rigs - 24 percent of
industry
o Live Well Servicing Ltd. ("Live Well") - 26 snubbing units - 30
percent of industry
o Precision Rentals - 3,700 storage tanks, 8,000 joints of specialty
drill pipe, 4,000 handling tools, 300 wellsite accommodation units
- 15 percent of the industry
The following graphs illustrate how the Contract Drilling Services
segment and the Completion and Production Services segment have historically
contributed to Precision's profitability and investment.
Precision is tightly integrated in terms of operational management,
safety, engineering, information technology, accounting and senior management.
Each division has experienced asset growth and performs a lead market role
within Canada. Communication is a skill that has been refined and ingrained in
the operating culture. Precision works closely with customers to ensure their
40
needs are being meet. The ability to successfully combine acquisitions through
vertical integration within and between related ancillary business units has
been developed over the past 20 years.
While each division is at its own stage in the business life cycle,
Precision Well Servicing in particular has matured the most over the past four
years as it follows the proven Precision Drilling model. The remaining
divisions are in the process of following suit. Accordingly, each division has
developed critical equipment mass and employee depth. Precision has
implemented and is further developing integrity-based systems that enable the
business to be versatile in order to meet fundamental industry challenges
while delivering better profit and safety performance.
While safety and quality of service continue as our primary focus,
close behind are our basic and simple methods of controlling costs in
conjunction with revenue generation. Canada is a market that has allowed the
segments to mature into an efficient and productive business model, but not
without challenge. Due to the seasonal and economic cycles associated with our
industry, our fixed support infrastructure is required to be lean with
elasticity to expand direct variable costs to meet high equipment demand
periods and conversely, to shrink with drops in utilization. Fixed cost
support infrastructure relates to salaried office personnel and systems while
variable costs typically relate to employees that work directly with equipment
on the job, in the field. The variable, hourly paid field employees work and
are paid when associated equipment is generating revenue.
The supply of experienced people yields profit leverage for oilfield
service companies, not just the "iron". Employee retention and seasonal cycles
remain manpower challenges for the industry. The already tight supply for
people is being further challenged by the number of rigs being added to the
industry along with the expansion of newly formed oilfield service companies.
Despite the above, in the fourth quarter of 2005, Precision Drilling had only
15 of 230 rigs operating without a full crew complement. Precision has been
cognizant of the need to hire, train and retain qualified field staff. In
order to alleviate crew shortages there are centralized personnel groups to
more effectively recruit and retain employees. In addition, we have
pre-employment rig orientation training where in 2005 we put through 1,500
candidates, an increase of 43 percent over 2004.
Precision has a balanced drilling rig offering, with particular
strength in deep drilling. As customers turn to deeper wells to discover new
reserves, Precision's 40 percent market share in rigs with a depth capacity
greater than 3,600 meters is noteworthy. Drilling opportunities for tight
natural gas in deeper reservoirs is a market where Precision has particular
advantage, a market many expect to emerge in Canada.
41
The following provides a summary of Precision's drilling and service
rig fleets:
PRECISION DRILLING
Precision Fleet Industry Fleet(2)
-------------------------------------------------------------------------------------------------------------
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 17 7 14 124 16 13
Super Single(R)(1) 3,000m 21 9 88 24 3 0
Double 3,000m 94 41 27 344 45 14
Light triple 3,600m 44 19 39 114 15 (4)
Heavy Triple 6,700m 43 19 40 107 14 6
Coiled tubing 1,500m 11 5 19 57 7 21
-------------------------------------------------------------------------------------------------------------
Total fleet 230 100 30 770 100 50
=============================================================================================================
Notes:
(1) Super Single(R) 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.
(2) Source: Daily Oil Bulletin's Rig Locator Report as of January 4, 2006.
Precision has allocated the industry rig fleet by rig type.
(3) Market share means Precision's rigs as a percentage of the industry's
rigs.
(4) Change in number of industry rigs as compared to prior year.
Maximum
Type of Drilling Rig Depth Rating 2005 2004 2003 2002 2001
-------------------------------------------------------------------------------------------------------------
Single 1,200m 17 16 18 17 16
Super Single(R) 3,000m 21 21 15 16 17
Double 3,000m 94 95 96 96 99
Light triple 3,600m 44 45 47 47 48
Heavy Triple 6,700m 43 41 39 39 38
Coiled tubing 1,500m 11 11 10 11 11
-------------------------------------------------------------------------------------------------------------
Total fleet 230 229 225 226 229
=============================================================================================================
PRECISION WELL SERVICING
Type of Service Rig 2005 2004 2003 2002 2001
-------------------------------------------------------------------------------------------------------------
Freestanding mobile single 88 86 75 50 23
Mobile single 17 19 30 56 95
Double 64 65 57 58 60
Freestanding mobile double 8 9 6 6 5
Mobile double 44 42 46 45 48
Heavy double 1 2 9 9 9
Freestanding slant 15 16 16 16 16
Swab - - - - 1
-------------------------------------------------------------------------------------------------------------
Total fleet 237 239 239 240 257
=============================================================================================================
42
RESULTS OF OPERATIONS
CONTRACT DRILLING SERVICES SEGMENT
(STATED IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE INDICATED)
% OF % of % of
YEARS ENDED DECEMBER 31, 2005 REVENUE 2004 Revenue 2003 Revenue
-------------------------------------------------------------------------------------------------------------
Revenue $ 916,221 $ 727,710 $ 663,619
Expenses:
Operating 448,930 49.0 382,886 52.6 379,842 57.2
General and administrative 23,911 2.6 19,190 2.6 15,676 2.4
Depreciation 39,233 4.3 42,245 5.8 47,895 7.2
Foreign exchange (238) - 1,074 0.2 2,194 0.3
-------------------------------------------------------------------------------------------------------------
Operating earnings $ 404,385 44.1 $ 282,315 38.8 $ 218,012 32.9
=============================================================================================================
% INCREASE % Increase
2005 (DECREASE) 2004 (Decrease) 2003
-------------------------------------------------------------------------------------------------------------
Number of drilling rigs (end of year) 230 0.4 229 1.8 225
Drilling operating days 46,937 12.8 41,625 (1.5) 42,275
Drilling revenue per operating day ($/day) 18,034 9.3 16,494 11.5 14,792
Number of wells drilled 7,766 3.2 7,525 (11.0) 8,451
Average days per well 6.0 9.1 5.5 10.0 5.0
Number of meters drilled (000s) 8,901 11.0 8,021 (6.8) 8,604
Average meters per well 1,146 7.5 1,066 4.7 1,018
=============================================================================================================
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. Revenue increased by $189
million or 26 percent over 2004 to $916 million while operating earnings
increased by $122 million or 43 percent to $404 million. As a percentage of
revenue, operating earnings increased to 44 percent in 2005 as compared to 39
percent in 2004. The margin increase was primarily attributable to pricing
improvements.
Operating expenses were lower as a percentage of revenue despite crew
wage rate increases. These costs declined from 53 percent of revenue in 2004
to 49 percent in 2005, and on a per operating day basis, they have remained
flat. Higher equipment utilization has lowered the daily 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.
Oil and natural gas prices were the story of 2005. Economic conditions
for energy continued to show significant improvement with crude oil and
natural gas establishing record pricing. These commodity prices had Canada's
oil and gas companies drilling a record 24,805 wells on a rig release basis,
an increase of nine percent over 2004. In fact, new record well counts have
been set for three successive years. As customers push to bring on-stream as
much production as possible during these times, oilfield service firms benefit
from this surge in spending. Precision, the largest oilfield service provider
in Canada, was a direct benefactor.
The Canadian drilling industry is subject to seasonality, with peak
activity levels during winter months from November through to March. Typically
during the latter half of March, weather conditions turn warmer to the point
that thawing occurs and causes ground conditions to become too soft and
unstable. These unstable ground conditions increase operating costs for
customers and cause seasonal road bans to be temporarily imposed. This event
can extend into June in certain areas, and is commonly referred to as "spring
break-up". In some areas of the extreme north, where there is only winter
access over ice bridges, this break-up period can span April through November.
Timing for these northern rigs becomes critical for customers that need to
migrate the equipment south to areas where summer drilling can occur.
This rise in activity has been strengthening on a comparative quarterly
basis year over year for the past three years. This demand has enabled the
Contract Drilling Services segment to steadily increase revenue and underlying
operating margins even though the overall fleet of equipment has increased
just slightly.
Drilling contractors in western Canada have increased the available rig
count to a level that will require the industry to drill more than 20,000
wells, at an average of seven days per well, to keep annual operating day
utilization above 50 percent. For 2006, indications are that drilling
companies may add another 100 rigs, which will raise the well count threshold
even higher.
43
Capital expenditures for the Contract Drilling Services segment in 2005
were $107 million and included $54 million to grow and 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.
THE PRECISION DRILLING DIVISION has once again set new financial
benchmarks for 2005. Revenue increased by $160 million or 23 percent over 2004
to $846 million. Just over half of this revenue growth was associated with
increased activity and the remainder with increased rates. The division
entered the year with great anticipation as rig demand exceeded rig
availability by a wide margin. Then came the March melt down as warm weather
in western Canada caused a somewhat premature end to the winter drilling
season. Soon after, the June rains rolled in and thwarted thoughts of an
exceptional second quarter. Disappointing activity results for the first half
of the year were strictly weather related. These activity levels caused
customer drilling programs to fall behind and created a backlog. As ground
conditions dried in July, the impact of this pent-up demand led to an
outstanding third and fourth quarter.
Rig demand continued to build momentum through to the end of the year.
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 of operators who did not have equipment booked for
the winter, enabling the division to charge premium prices.
Operating earnings in the Precision Drilling division increased by 46
percent due in part to the 13 percent increase in operating activity combined
with the nine percent 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 from 4,150 in 2005.
Precision Drilling was able to maintain its cost per operating day at its 2004
rate. Crew labour costs in 2005 were 52 percent of operating costs up two
percent from 2004. The 2005 cost of drilling, maintenance and overhead on a
per day basis was consistent with 2004. An important component of the success
of the division is the degree to which the cost structures have been developed
to be as variable as possible with activity levels. This flexibility has
allowed the division to respond quickly to sudden changes in equipment
utilization and produce superior returns in periods of high activity similar
to 2005.
THE PRECISION DRILLING DIVISION is slightly larger than it was in 2004.
In the fourth quarter, two Super Single(R) Light rigs were added to the fleet
and one rig was sold. The net addition is the start of Precision's strategy to
organically expand through the addition of versatile rigs backed by long-term
customer commitments. Precision Drilling commenced 19 new rig builds in 2005
and expects that all but two will be field ready in 2006. The division's rig
fleet is expected to average 237 for 2006, exiting the year at 247 rigs.
LRG CATERING DIVISION, has been sized to support Precision's drilling
rig fleet and also had an outstanding year. LRG camp days increased over the
prior year by 26 percent in 2005 leading to a revenue increase of 40 percent.
The growing number of field personnel in the industry is putting 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 operating expenses increased due to higher labour and grocery
costs and these increases were more than offset by an increase in revenue
rates. In terms of capital expenditures, LRG grew its fleet by adding five new
six-unit camps.
ROSTEL INDUSTRIES AND COLUMBIA OILFIELD SUPPLY DIVISIONS continue to
provide valuable support for this segment and are best measured by the
efficiencies and contributions made to Precision through cost savings.
Rostel's core business is the manufacture and refurbishment of custom drilling
and service rig components. Columbia is a general supply store that procures
and distributes large volumes of consumable oilfield supplies for the
Precision divisions. Columbia is an essential extension of the purchasing
process that ensures all rigs are provided with timely and reliable running
supplies to keep them operational. More importantly, Columbia allows
operations in Precision to standardize product use and quality.
2004 COMPARED TO 2003
THE CONTRACT DRILLING SERVICES SEGMENT generated increased financial
results in 2004 due to an improvement in oil and natural gas commodity prices,
which led to greater customer demand for all of the segment's oilfield
services and the leverage to increase revenue rates. Operational execution and
diligence allowed for the efficient delivery of services and control over the
rate of operating and administrative cost escalations.
The segment reported revenues of $728 million, $64 million more than
2003, an increase of 10 percent. These results were generated with an
equipment fleet size that was relatively unchanged from the prior year.
Revenue growth in 2004 was primarily attributable to revenue rate increases.
Operating earnings increased by $64 million or 29 percent to $282 million. As
a percentage of revenue, operating earnings increased to 39 percent in 2004 as
compared to 33 percent in 2003. The margin increase was attributable to higher
pricing even though operating day utilization for the drilling rig fleet was
two percent lower in 2003. The second half of the year benefited from rising
commodity prices enabling the segment to increase rates commencing in the
fourth quarter. However, poor weather conditions in the third quarter hampered
industry drilling activity.
Operating expenses were lower as a percentage of revenue, improving to
53 percent in 2004 from 57 percent in 2003. The improvement is attributable to
higher revenue rates partially offset by higher labour costs.
44
Capital expenditures amounted to $75 million in 2004. This was
comprised of $37 million in growth initiatives for the construction of new
rigs and camps and was matched by $38 million in expenditures to sustain and
upgrade existing equipment.
FOR THE PRECISION DRILLING DIVISION revenue increased by $55 million or
nine percent over 2003 to $687 million. The majority of 2004 revenue was
attributable to rate increases that flowed through to operating earnings as
overall activity was very similar to 2003. In 2004 winter drilling revenue
rates held firm through the second quarter. While adverse third quarter
weather prevented some wells from being drilled, it did add to the backlog of
work, strengthening spot market demand and enabling the division to put
through an additional revenue rate increase to start the fourth quarter.
Although industry activity in Canada was approximately five percent higher
than 2003, the industry supply of additional drilling rigs hindered
opportunities to gain higher utilization. Precision Drilling's rig fleet
increased by four rigs in 2004, ending the year at 229 rigs. Operating costs
were reasonably well contained with a six percent fourth quarter labour rate
increase and static maintenance costs.
LRG CATERING DIVISION experienced a seven percent increase in camp days
and a 16 percent increase in revenue. Much of the rate increase was due to the
impact of three new base camps commissioned in the fourth quarter.
COMPLETION AND PRODUCTION SERVICES SEGMENT
(STATED IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE INDICATED)
% OF % of % of
YEARS ENDED DECEMBER 31, 2005 REVENUE 2004 Revenue 2003 Revenue
-------------------------------------------------------------------------------------------------------------
Revenue $ 369,667 $ 313,386 $263,218
Expenses:
Operating 209,657 56.7 196,113 62.6 176,295 67.0
General and administrative 11,021 3.0 12,708 4.0 12,447 4.7
Depreciation 27,402 7.4 27,508 8.8 25,720 9.8
Foreign exchange (56) - (17) - 50 -
-------------------------------------------------------------------------------------------------------------
Operating earnings $ 121,643 32.9 $ 77,074 24.6 $ 48,706 18.5
=============================================================================================================
% INCREASE % Increase % Increase
2005 (DECREASE) 2004 (Decrease) 2003 (Decrease)
-------------------------------------------------------------------------------------------------------------
Number of service rigs (end of year) 237 (0.8) 239 - 239 -
Service rig operating hours 477,232 1.1 472,008 7.4 439,519 12.1
Revenue per operating hour ($/hr.) 600 17.0 513 11.0 462 3.6
=============================================================================================================
2005 COMPARED TO 2004
THE COMPLETION AND PRODUCTION SERVICES SEGMENT, also generated record
financial results in 2005 on the strength of industry activity in western
Canada and improved pricing for services. Revenue increased by $56 million or
18 percent over 2004 to $370 million while operating earnings increased by $45
million or 58 percent to $122 million. As a percentage of revenue, operating
earnings increased to 33 percent in 2005 as compared to 25 percent in 2004.
The margin increase is attributable to the enhanced operating performance of
the service rig fleet as the division was able to increase rates throughout
the year. Equipment demand has provided the ability to establish pricing
levels that are based on possession rather than just usage.
Operating expenses declined from 63 percent of revenue in 2004 to 57
percent in 2005 and, on a per operating hour basis, increased marginally due
to higher labour costs. This segment continues to strengthen its systems and
cost controls as it follows the proven model built around the drilling
business. Analytical tools are extensively used as we continue to benefit from
Precision's enterprise-wide information system. Centralization of personnel,
accounting, purchasing, and equipment management has provided economies of
scale and more effective deployment of the segment's resources.
The segment is beginning to benefit from unprecedented industry
activity in 2005 which set records for the number of wells completed and the
number of producing wells in western Canada. The 24,805 wells rig released in
2005 brings the total in the past three years to 69,365. This has put extreme
pressure on equipment demands as customers were eager to increase their
production levels to benefit from high commodity prices.
The Completion and Production segment is also affected by the cyclical
nature of the seasons. The first and fourth quarters are the most active as
colder weather conditions allow for unrestricted movement of heavy equipment
on county and provincial roads. The first quarter traditionally produces the
highest utilization as customers are able to work northern areas only
accessible at this time. However, the fourth quarter of 2005 produced
exceptional results as customers caught up on the backlog of work deferred
from the first half of the year. This resulted from an early "spring break-up"
and an exceptionally wet second quarter.
45
Service rig contractors in western Canada have kept the industry rig
fleet count relatively constant over the past five years at a level of
approximately 1,000 service rigs. Precision and the industry have adjusted to
the shift in focus from oil to natural gas by customers. Recent growth in the
WCSB has been associated with natural gas production which is beginning to
increase demand for completion and production services providing additional
opportunities for Precision's diverse service rig fleet.
Surging oilfield activity in the drilling sector has created shortages
in both equipment and manpower. The well documented manpower shortage
continues to be a concern. Strong customer relationships, reliable equipment
and a safe working environment are important aspects in employee recruitment
and retention.
The reinvestment in equipment over the last several years has helped to
position the Completion and Production segment as an industry leader. Capital
spending in 2005 amounted to $35 million, an increase of nine percent over
2004. This included expansion capital of $8 million for a freestanding
snubbing unit, additional pump trucks, wellsite accommodations and storage
tanks. Maintenance capital to sustain the existing asset base included
replacement trucks for transporters, snubbing units and pump trucks as well as
rental drill pipe, snubbing equipment and a facility upgrade in Grande
Prairie, Alberta.
THE PRECISION WELL SERVICING DIVISION has set a new financial benchmark
in 2005. Revenue increased $44 million or 18 percent over 2004 to $286
million. A slight increase in activity combined with higher rates accounted
for the increase. PWS achieved 55 percent utilization, a nominal improvement
over the prior year. Activity levels were dampened in the first half of 2005
due to poor weather conditions, leading to a rebound in the latter half due to
the backlog of work. By the end of the year activity levels had only exceeded
the prior year by 5,224 operating hours or one percent. The opportunity to
make up additional hours in the last half of the year was just a factor of
calendar time as there was plenty of work available. Rig rates therefore were
the major contributor to the increased revenue. Traditional winter pricing
takes affect on October 1 and coupled with record fourth quarter activity in
2005, the division generated record quarterly results to exit the year. The
influx of junior oil and gas companies created a spot market that allowed for
stronger pricing.
Operating earnings for this division improved by $38 million resulting
in a 79 percent improvement over the prior year, due mainly to price
increases. In addition, operating costs were marginally higher year over year
on a per operating hour basis due to higher labour costs. Cost efficiencies
were achieved by consolidating operating centres in the latter part of the
prior year.
Capital expenditures in 2005 continued to emphasize the upgrading and
standardization of equipment. This includes upgrades to rig carriers through
new electronic engines and design changes to adapt axle configurations for
lighter road weights. This design change allows for greater utilization during
periods when restrictive road bans are in effect. The strategy is to optimize
service availability to generate revenue without having to increase the size
of the rig fleet. Today, approximately 60 percent of the service rig fleet is
able to move year round.
LIVE WELL'S activity decreased slightly in 2005. The demand for
snubbing, while finishing strong, paused early in the year. Despite this,
revenue increased by $4 million or 12 percent over 2004 to $32 million. The
improvement was attributable to higher hourly operating and standby rates
established in the last half of the year. Strong activity in the fourth
quarter allowed Live Well to exit 2005 with strong utilization. Operating
earnings increased by seven percent over the prior year due to price
increases.
Lower utilization was due, in part, to the industry's challenge to
modify and improve recommended industry practices. Snubbing services are
associated with producing natural gas wells and involves safety risks that can
be greater than other oilfield services. Live Well is working with its
industry partners and customers to bring about constructive change.
In terms of capital expenditures, Live Well upgraded its fleet of
hydraulic rig assist snubbing units through scheduled truck chassis
replacement and introduced its first freestanding snubbing unit. This
proprietary, automated design includes a pipe handling system that sets new
standards for safety and efficiency.
PRECISION RENTALS reported a revenue increase of $8 million or 19
percent over 2004 to $51 million. The increase is attributable to higher
drilling activity which led to higher demand for rental equipment. This demand
enabled the division to benefit from higher utilization and improved pricing
for each of its three product categories: surface equipment; tubulars and well
control equipment; and wellsite accommodations. This accretion was established
in the fourth quarter, consistent with Precision's other divisions. Operating
earnings increased by 37 percent over the prior year.
The operation has been restructured and now consists of multiple
operating centres strategically located in the WCSB. This new structure allows
Precision Rentals to logistically manage all product categories from each
location and is supported by a new enterprise-wide information system. This
initiative has brought about improvements in service delivery, equipment
standardization and a more structured pricing regime.
In terms of capital expenditures, Precision Rentals continues to
reinvest in each of its product categories to keep its equipment in premium
condition and achieve the most efficient design available in the industry. The
division expanded its wellsite accommodation fleet in 2005 by eight percent
with the purchase of 24 units.
46
2004 COMPARED TO 2003
THE COMPLETION AND PRODUCTION SEGMENT generated revenues of $313
million, which is $50 million or 19 percent higher than revenues of $263
million in 2003. Operating earnings increased by $28 million or 58 percent to
$77 million. The increase in revenue is attributable to a balanced mix of rate
increases and higher equipment utilization. The Precision Well Servicing
division contributed 78 percent of the revenue increase. Operating expenses
were lower as a percentage of revenue, showing an improvement from 67 percent
of revenue in 2003 to 63 percent in 2004. Continued reinvestment as well as
the streamlining of operations has enabled the Completion and Production
segment to provide premium equipment and services to customers. Capital
spending in 2004 amounted to $32 million and included expansion capital of $7
million for additional pump trucks, storage tanks and initial construction of
a freestanding snubbing unit. Maintenance capital in the amount of $25 million
was incurred to sustain the existing asset base through upgrades that included
transporters, pump trucks, wellsite units, surface tanks and facilities.
FOR THE PRECISION WELL SERVICING DIVISION, revenue increased $39
million or 19 percent over 2003 to $242 million. Service rig activity
increased by 32,489 hours to 472,008 in 2004, for utilization of 54 percent.
This higher demand enabled the division to increase average revenue per
operating hour by 11 percent over the prior year. Although upstream drilling
activity was marginally lower year over year, Precision's service rig division
was able to increase revenue and began to capitalize on the commitment made
toward the reinvestment in its people and equipment. Operating costs were
marginally higher year over year on a per operating hour basis. The higher
service rig activity provided better coverage of lower fixed overhead costs
but not enough to offset higher major maintenance costs associated with
equipment repair and certification. Precision's service rig fleet was
unchanged in 2004 at 239 rigs, representing an industry market share of
approximately 26 percent.
LIVE WELL'S snubbing unit activity increased approximately 10 percent
over 2003 as demand for snubbing continued to gain momentum in line with the
industry's emphasis on natural gas production. Revenue increased $7 million or
33 percent over 2003 to $28 million. With the acquisition of two snubbing
units in December 2003, the fleet size increased to 25 units. Operating
earnings rose by 63 percent over 2003 due to the growth in fleet size and
higher pricing.
PRECISION RENTAL'S revenue increased $4 million or 10 percent over 2003
to $43 million. Operating earnings rose by 13 percent over 2003 despite a one
percent decline in industry drilling activity. Precision Rentals was more
profitable as a result of pricing improvements on a number of product
categories. In 2004, the division began to realize benefits and synergies from
the restructuring process to take advantage of a consolidated marketing group
and the centralization of certain business functions.
OTHER ITEMS
2005 COMPARED TO 2004
CORPORATE AND OTHER EXPENSES Corporate and other expenses increased by
$33 million or 116 percent 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
percent year over year of which $6 million is 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
percent in 2005 compared to 2004. This reduction is 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 to Weatherford, resulting in an after tax gain of
$1.2 billion. Precision has recorded a $20 million receivable in conjunction
with a working capital calculation pursuant to the agreement. This amount is
subject to change depending on the outcome of ongoing discussions with the
47
purchaser and could result in an adjustment to the proceeds on disposition.
Management estimates that ultimate settlement of this issue will not have a
material impact on the recorded gain on disposal of discontinued operations.
Second, Precision disposed of the industrial services business carried
on by CEDA for an after tax gain of $132 million.
INCOME TAXES Precision's effective tax rate on earnings from continuing
operations before income taxes was 25 percent in 2005 compared to 35 percent
in 2004. The decrease in the tax rate is primarily a result of the conversion
to an income trust in November 2005 which has the effect of shifting the
income tax burden of the Trust to the unitholders. The Trust incurs taxes to
the extent that there are federal large corporation and 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.
2004 COMPARED TO 2003
CORPORATE AND OTHER EXPENSES Corporate and other expenses increased by
$14 million or 97 percent in 2004 as compared to 2003. These costs are
primarily associated with the corporate executive, human resources, internal
audit, information technology, treasury, tax, and financial reporting
functions. Expenses increased in conjunction with the growth of the
organization and with the complexities associated with Precision's former
strategy to globalize its business. In addition, heightened regulatory
requirements, in particular those associated with the Sarbanes-Oxley Act, have
resulted in increased personnel requirements.
INTEREST EXPENSE Net interest expense of $46 million increased by 36
percent in 2004 compared to 2003. Average net debt outstanding (borrowings
less cash on hand) increased nine percent as acquisitions made in 2004 were
partially financed by additional borrowings. The combination of the issuance
of common shares and long-term debentures to finance acquisitions and strong
cash flow from operations resulted in a change in the make up of Precision's
net debt outstanding. In the first half of 2004, a portion of net debt took
the form of short-term borrowings on its bank facilities at relatively low
interest rates. These short-term borrowings were replaced with long-term
debentures at higher interest rates. Interest expense was inflated by fees
related to bridge financing facilities put in place in conjunction with
acquisitions completed during the year.
INCOME TAXES Precision's effective tax rate on earnings from continuing
operations before income taxes was 35 percent in 2004 consistent with the rate
of 34 percent experienced in 2003.
LIQUIDITY AND CAPITAL RESOURCES
In 2005, dispositions of the Energy Services and International Contract
Drilling divisions and CEDA provided proceeds of $1.3 billion. Cash flow from
operations was $203 million, while the exercise of share purchase options and
increases in long-term debt and sources of funds through financing activities
added $227 million. An additional $15 million was provided from the sale of
Weatherford shares that were not distributed as part of the plan of
arrangement. Precision incurred capital expenditures from continuing
operations, net of dispositions of capital assets, of $140 million and capital
spending for discontinued operations of $110 million. In conjunction with the
CEDA disposition, Precision purchased all the outstanding shares of CASCA
Electric Ltd. and CASCA Tech Inc. for $30 million. A total of $844 million was
paid to shareholders as part of the plan of arrangement, while $704 million
was used to repay the outstanding public debt. In addition, $43 million was
used to repurchase and cancel the common shares held by dissenting
shareholders and $64 million was used in settlement of share purchase options.
On December 15, 2005, the initial monthly cash distribution of the Trust for
November, 2005 in the amount of $34 million, was paid to unitholders.
The Trust exited 2005 with a long-term debt to long-term debt plus
equity ratio of eight percent and a ratio of long-term debt to cash flow from
operations of 48 percent.
In 2006, Precision expects cash provided by continuing operations,
before an estimated use of funds in the amount of $200 million for working
capital changes, to be approximately $550 million. Net capital expenditures
are expected to be $285 million with $165 million directed towards organic
growth initiatives to expand equipment fleets and the remaining $120 million
towards sustaining and upgrading existing property, plant and equipment
assets. There was bank indebtedness and long-term debt in the combined amount
of $117 million at December 31, 2005. On the basis that the Trust sustains
cash distributions at a monthly rate of $0.27 per unit throughout the year,
total cash distributions in the amount of $407 million are expected to be paid
to unitholders assuming an average of 125.5 million units outstanding during
the year. Given these estimates and forecast amounts, Precision expects
long-term debt to increase by approximately $340 million to exit 2006 with a
balance close to $435 million. The application of funds towards the $200
million estimated change in working capital balances and a partial use of
funds for growth-oriented capital expenditures is expected to weaken the
long-term debt to long-term debt plus equity ratio from eight percent in 2005
to approximately 27 percent in 2006. There was working capital in the amount
of $153 million on December 31, 2005 and Precision expects this amount to
increase to approximately $350 million to exit 2006.
48
Precision has a number of committed and uncommitted lines of credit
available to finance its activities. The committed facilities consist of a
$550 million three-year revolving unsecured credit facility with a syndicate
led by a Canadian chartered bank. The facility matures in November 2008, 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 percent of
consolidated cash flow, as defined in the credit facility agreement. As at
December 31, 2005, Precision was well within the financial covenant levels,
and is expected to remain so for 2006. There was $97 million outstanding under
the committed facilities at December 31, 2005. In addition to the committed
facilities, Precision also has a number of uncommitted operating facilities
which total approximately $66 million equivalent and are utilized for working
capital management and the issuance of letters of credit.
The Corporation's contractual obligations are outlined in the following
table:
Payments Due by Period
Less Than After
(STATED IN THOUSANDS OF CANADIAN DOLLARS) Total 1 Year 1 - 3 Years 4 - 5 Years 5 Years
-------------------------------------------------------------------------------------------------------------
Long-term debt 96,838 - 96,838 - -
Operating leases 27,900 7,362 10,167 7,334 3,037
-------------------------------------------------------------------------------------------------------------
Total contractual obligations 124,738 7,362 107,005 7,334 3,037
=============================================================================================================
OUTSTANDING UNIT/SHARE DATA
February 28 December 31 December 31
2006 2005 2004
-------------------------------------------------------------------------------------------------------------
Trust units/common shares 124,352,921 124,352,921 121,580,424
Exchangeable LP units 1,108,382 1,108,382 -
Options to purchase common shares - - 6,695,120
=============================================================================================================
DISTRIBUTIONS
Upon Precision's conversion to an income trust effective November 7,
2005, the Trust adopted a policy of making regular monthly cash distributions
to unitholders. As previously disclosed in the Information Circular of
Precision Drilling Corporation dated October 3, 2005, distributions may be
reduced, increased or suspended entirely depending on the operations of
Precision and the performance of its assets. The actual cash flow available
for distribution to holders of Trust units and holders of Exchangeable LP
units is a function of numerous factors, including the Trust's: financial
performance; debt covenants and obligations; working capital requirements;
maintenance 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 and made its first
payment in December in the amount of $34 million at the rate of $0.27 for each
outstanding unit including Exchangeable LP units. At December 31, 2005 there
were 125,461,303 Trust and Exchangeable LP units outstanding. In December, a
distribution of $0.27 per unit plus a special distribution of $0.022 per unit
was declared by the Trust with a payment of $37 million being made on January
17, 2006.
The declaration of trust, the governing document of Precision Drilling
Trust, provides that, if necessary, on December 31 of each year, the Trust
will make an additional amount payable such that the Trust will not be liable
for ordinary income taxes for such year. Reference can be made to "Certain
Canadian Federal Income Tax Considerations - Taxation of the Trust" on pages
46 to 47 of the Special Meeting Information Circular dated October 3, 2005.
QUARTERLY FINANCIAL SUMMARY
(STATED IN THOUSANDS OF CANADIAN DOLLARS EXCEPT PER UNIT/SHARE AMOUNTS, WHICH ARE PRESENTED ON A DILUTED BASIS)
---------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2005 Q1 Q2 Q3 Q4 YEAR
---------------------------------------------------------------------------------------------------------------
Revenue 383,407 157,895 300,016 427,861 1,269,179
Operating earnings 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 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 unit/share 1.11 0.21 11.00 0.66 13.00
Cash provided by (used in) continuing operations 91,762 117,722 42,359 (48,742) 203,101
49
---------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2004 Q1 Q2 Q3 Q4 Year
---------------------------------------------------------------------------------------------------------------
Revenue 361,524 134,963 218,023 313,978 1,028,488
Operating earnings 131,570 24,065 61,799 113,879 331,313
Earnings from continuing operations 80,427 10,127 36,995 60,582 188,131
Per unit/share 0.71 0.09 0.31 0.49 1.61
Net earnings 100,519 15,995 42,707 88,183 247,404
Per unit/share 0.89 0.14 0.36 0.71 2.11
Cash provided by continuing operations 48,657 186,709 21,536 30,919 287,821
===============================================================================================================
FOURTH QUARTER DISCUSSION
Sustained high crude oil and natural gas prices generated a strong
environment for the oilfield services business in Canada. The unusually wet
spring and early summer caused many of the oil and natural gas customers to
delay drilling programs. This, along with high customer cash flows set the
stage for the extremely busy fourth quarter which had activity levels not
normally seen until the middle of the winter season. This left customers with
an abundance of wells to be drilled in order to meet production targets. This
demand, coupled with the weather pattern that occurred in the fourth quarter
of 2005 created an almost perfect scenario. Unseasonably warm weather
temperatures and dry conditions were ideal after exiting an extremely wet
second quarter. Customers were able to extend summer drilling programs and
mitigate land expiry issues. It was also beneficial to customers who did not
have rigs reserved for the winter and required windows to complete projects as
rigs were delayed moving north.
Contract Drilling Service's revenue of $308 million and operating
earnings of $155 million increased by 36 percent and 57 percent in the fourth
quarter of 2005 compared to the same period of 2004, respectively. Record
fourth quarter activity and the impact of increased winter dayrates which took
effect during the quarter were the primary reasons for this change. Rig demand
in the quarter remained extremely strong and reached unprecedented levels.
Completion and Production Service's revenue of $124 million and
operating earnings of $51 million increased by 35 percent and 87 percent in
the fourth quarter of 2005 compared to the same period of 2004, respectively.
Precision Well Servicing also set new highs for activity and profitability in
the fourth quarter. Completion work was abundant due to record drilling
activity combined with pent-up demand from weather delays in the first half of
the year. Workover demand was high as customers scheduled wells for production
maintenance to take advantage of strong commodity prices. Winter pricing took
effect October 1, 2005. Live Well's snubbing revenues for the fourth quarter
increased year over year even though activity decreased slightly as customers
were reluctant to release the rig assist units into the market place and were
charged standby fees. Precision Rentals had record revenue and operating
earnings due to increased utilization and pricing on select product categories
as a result of continued strong demand for equipment throughout the quarter.
Precision Drilling and Precision Well Servicing rig operations
experienced an activity level increase of 19 percent and 11 percent with
utilization of 68 percent and 65 percent in the quarter, respectively. The
drilling rig fleet achieved 14,350 operating days in the fourth quarter of
2005 and the service rig fleet generated 142,122 operating hours. Continued
favourable commodity prices and good weather conditions set the environment
for these results. Traditional winter pricing rate increases were addressed to
start the fourth quarter and benefited from an equipment supply/demand
shortfall carried over from the third quarter. As a result, Precision Drilling
was able to increase revenue per drilling rig operating day by an average of
12 percent during the fourth quarter and PWS was able to raise service rig
rates per operating hour by 23 percent.
Fourth quarter operating costs were lower as a percentage of revenue
despite crew wage rate increases of approximately seven percent effective
October 1, 2005. Operating expenses declined from 51 percent of revenue in the
fourth quarter of 2004 to 45 percent in 2005. Consistent with the third
quarter 2005 results, equipment repair and maintenance expenses were lower on
a per day basis as scheduled costs were spread over a higher activity level
relative to the last year. In addition, operating expenses have not increased
to the same magnitude as customer pricing.
Corporate and other costs, after excluding one time trust conversion
costs of $18 million were up $1 million to $13 million from $12 million in
2004. This increase was a result of an increase in foreign exchange expense of
$3 million offset by lower general and administrative costs due to the
resizing of the corporate function to meet the needs of the smaller business
organization.
In the fourth quarter, capital expenditures amounted to $45 million of
which $17 million was for the construction of new drilling rigs. Two of the
scheduled 19 new builds were completed and commenced drilling in the quarter.
The remaining $28 million was for maintenance capital expenditures to sustain
and upgrade existing equipment.
CRITICAL ACCOUNTING ESTIMATES
This Management's Discussion and Analysis of Precision's financial
condition and results of operations is based on its consolidated financial
statements which are prepared in accordance with Canadian generally accepted
accounting principles. The Trust's significant accounting policies are
50
described in Note 1 to its consolidated financial statements. The preparation
of these financial statements requires that certain estimates and judgments be
made that affect the reported assets, liabilities, revenues and expenses.
These estimates and judgments are based on historical experience and on
various other assumptions that are believed to be reasonable under the
circumstances. Anticipating future events cannot be done with certainty,
therefore, these estimates may change as new events occur, more experience is
acquired and as the Trust's operating environment changes.
The accounting estimates believed to require the most difficult,
subjective or complex judgments and which are the most critical to our
reporting of results of operations and financial position are as follows:
ALLOWANCE FOR DOUBTFUL ACCOUNTS RECEIVABLE
Precision performs ongoing credit evaluations of our customers and
grants credit based upon past payment history, financial condition and
anticipated industry conditions. Customer payments are regularly monitored and
a provision for doubtful accounts is established based upon specific
situations and overall industry conditions. Precision's history of bad debt
losses has been within expectations and generally limited to specific customer
circumstances, however, given the cyclical nature of the oil and natural gas
industry and the inherent risk of successfully finding hydrocarbon reserves, a
customer's ability to fulfill its payment obligations can change suddenly and
without notice.
BUSINESS DIVESTITURE RECEIVABLE
In conjunction with disposition of the Energy Services and
International Contract Drilling divisions, Precision estimated and recorded a
$20 million receivable regarding a working capital and property, plant and
equipment adjustment. This amount is subject to change depending on the
outcome of ongoing discussions with the purchaser and could result in an
adjustment to the proceeds on disposition. Management estimates that ultimate
settlement of this issue will not have a material impact on the recorded gain
on disposal of discontinued operations.
IMPAIRMENT OF LONG-LIVED ASSETS
Long-lived assets, which include property, plant and equipment,
intangibles and goodwill, comprise the majority of Precision's assets. The
carrying value of these assets is periodically reviewed for impairment or
whenever events or changes in circumstances indicate that their carrying
amounts may not be recoverable. This requires Precision to forecast future
cash flows to be derived from the utilization of these assets based upon
assumptions about future business conditions and technological developments.
Significant, unanticipated changes to these assumptions could require a
provision for impairment in the future. During the fourth quarter of 2005,
Precision completed its goodwill assessment and concluded that there was no
impairment of the carrying value.
DEPRECIATION AND AMORTIZATION
Precision's property, plant and equipment and its intangible assets are
depreciated and amortized based upon estimates of useful lives and salvage
values. These estimates may change as more experience is gained, market
conditions shift or new technological advancements are made.
Effective January 1, 2005, Precision changed the useful life of its
drilling rigs for purposes of determining depreciation expense to 5,000
utilization days from 4,150 utilization days (3,650 operating days), and its
drill strings to 1,500 from 1,100 operating days. Utilization days include
both operating and rig move days. This change in accounting estimate has been
applied prospectively and resulted in an $11 million reduction of depreciation
expense or $0.09 per 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. 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 the Trust's future tax assets.
The business and operations of Precision are complex and Precision has
executed a number of significant financings, business combinations,
acquisitions and dispositions over the course of its history. The computation
of income taxes payable as a result of these transactions, and in particular
those completed within the last five years, involves many complex factors as
well as Precision's interpretation of relevant tax legislation and
regulations. Precision's management believes that the provision for income tax
is adequate.
However, there are a number of tax filing positions that can still be
the subject of review by taxation authorities who may successfully challenge
Precision's interpretation of the applicable tax legislation and regulations,
with the result that additional taxes could be payable by Precision and the
amount payable could be up to $300 million.
51
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 2.
Certain activities of Precision are affected by factors that are beyond
its control or influence. The Canadian drilling rig, camp and catering,
service rig, snubbing, rentals and related service businesses and activities
of Precision 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. These factors could lead to a decline in the
demand for Precision's services, resulting in a material adverse effect on
revenues, cash flows, earnings and cash distributions to unitholders. The
majority of Precision's operating costs are variable in nature which minimizes
the impact of downturns on our operational results.
CRUDE OIL AND NATURAL GAS PRICES
Precision's revenue, cash flow and earnings are substantially dependent
upon, and affected by, the level of activity associated with oil and natural
gas exploration and production. Both short-term and long-term trends in oil
and natural gas prices affect the level of such activity. Oil and natural gas
prices and, therefore, the level of drilling, exploration and production
activity have been volatile over the past few years and likely will continue
to be volatile. Crude oil prices in 2005 ranged from a low of US$43 per barrel
to a high of nearly US$70 per barrel. 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. North American oilfield service activity is largely focused
on natural gas. Natural gas in 2005 averaged almost US$9 per mmbtu and ranged
from an approximate low and high of US$7 and US$16 per mmbtu respectively.
Weather conditions, governmental regulation (both in Canada and elsewhere),
levels of consumer demand, the availability of pipeline capacity, and other
factors beyond Precision's control may also affect the supply of and demand
for oil and natural gas and thus lead to future price volatility. Precision
believes that any prolonged reduction in oil and natural gas prices would
depress the level of exploration and production activity. Lower oil and
natural gas prices could also cause Precision's customers to seek to
terminate, renegotiate or fail to honour Precision's drilling contracts; which
could affect the fair market value of its rig fleet which in turn could
trigger a write-down for accounting purposes; which could affect Precision's
ability to retain skilled rig personnel; and which could affect Precision's
ability to obtain access to capital to finance and grow its businesses. There
can be no assurance that the future level of demand for Precision's services
or future conditions in the oil and natural gas industry will not decline.
WORKFORCE AVAILABILITY
Precision's ability to provide reliable services is dependent upon the
availability of well-trained, experienced crews to operate our 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 attract new workers to the industry as
required. Many of Precision's businesses are currently experiencing manpower
shortages. 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.
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. Additionally, certain oil and natural
gas producing areas are located in sections of the WCSB that are inaccessible,
other than during the winter months, because the ground surrounding or
containing the drilling sites in these areas consists of terrain known as
muskeg. Until the muskeg freezes, the rigs and other necessary equipment
cannot cross the terrain to reach the drilling site. Moreover, once the rigs
and other equipment have been moved to a drilling site, they may become
stranded or otherwise unable to relocate to another site should the muskeg
thaw unexpectedly. Precision's business results depend, at least in part, upon
the severity and duration of the Canadian winter.
TECHNOLOGY
Technological innovation by oilfield service companies has improved the
effectiveness of the entire exploration and production sector over the
industry's 140-year history. Drilling time has been reduced due to
improvements in drill bits, logging and measurement while drilling tools, as
52
well as innovative changes in other areas such as mud systems and top drives.
Precision's ability to deliver services that are more efficient is critical to
continued success.
CUSTOMER MERGER AND ACQUISITION ACTIVITY
Merger and acquisition activity in the oil and natural gas exploration
and production sector can impact demand for our services as customers focus on
internal reorganization activities prior to committing funds to significant
drilling and maintenance projects.
DISCLOSURE CONTROLS AND PROCEDURES
The Chief Executive Officer and the Chief Financial Officer have
evaluated the effectiveness of Precision's disclosure controls and procedures
as of December 31, 2005 and have concluded that such disclosure controls and
procedures were effective to provide reasonable assurance that material
information relating to the Trust or its divisions is made known to them.
OUTLOOK
Global macro energy fundamentals remain positive as worldwide energy
demand continues to be firm, supported to a large extent by the growing
economies of China, southeast Asia and India. OPEC has remained disciplined
and rational with respect to managing the supply dynamics for oil and
worldwide production capacity is challenged to meet growing needs. Natural gas
fundamentals are also strong in the face of healthy industrial demand and
ongoing production challenges. These factors, which analysts are predicting
will not change in the foreseeable future, have led to the sustainment of
historically high crude oil and natural gas prices. As a result, the financial
capabilities of Precision's customers have been greatly strengthened over the
past year and the returns they are generating are compelling them to increase
their exploration and development spending.
Macro energy fundamentals for Precision's Canadian businesses are
expected to be largely driven by North American natural gas prices, production
and consumption. Increasingly, oilfield service activity in Canada is weighted
towards natural gas production. Short-term natural gas fundamentals will be
impacted by industrial and residential consumption associated with seasonal
heating and air conditioning demand. Accordingly, weather patterns play a
large role in natural gas storage levels and impact near-term natural gas
pricing. Warm weather conditions throughout North America during the fourth
quarter of 2005 resulted in lower natural gas pricing to close out the
2005/2006 winter.
With these medium to long-term fundamentals as the backdrop, Precision
anticipates demand for its oilfield services to be robust in 2006. The
Canadian Association of Oilwell Drilling Contractors is forecasting just over
26,000 wells to be drilled, on a rig release basis, in the WCSB in 2006, an
all time high. A recurring challenge Precision faces in filling the increased
demand for its services is attracting employees with sufficient expertise and
training. Precision is focused on recruiting, training and retaining people so
that it can continue to respond to customers needs.
The first quarter of 2006 has provided an excellent start to the year.
Precision began the year at high levels as customers were extremely well
prepared to pursue their winter drilling, completion and production programs.
To the extent that warm weather was an issue, customers were prepared to shift
well locations to ensure high equipment utilization, thereby avoiding costly
standby charges or loss of equipment use. With industry's growing emphasis on
spreading drilling activity throughout the year, load levelling practices bode
well for the seasonally soft second and third quarters. Given that there is a
healthy inventory of wells to be drilled, completed and maintained, second
quarter slow downs caused by weather could heighten demand and allow for a
repeat of last year, which led to a sharp rebound in third quarter activity
and provided pricing leverage to start the winter drilling season. The most
important factor, however, would be a repeat of the record upward trend in
natural gas prices.
During the fourth quarter of 2005, Precision announced a growth
initiative to construct 19 new drilling rigs that will expand the fleet by
eight percent over the following 12 to 15 months. These new rigs are of a
versatile design and are being built to meet customer specifications. Ten of
the new builds will be of Precision's proprietary Super Single(R) design, with
the remaining nine rigs being diesel electric light triples rated to a depth
of 4,000 metres. Customer commitments on many of these rigs are symbolic of
the current strength in demand for drilling in Canada, as the contract term
from the date of rig commission will carry through to the first quarter of
2011. Industry indications suggest that an additional 100 drilling rigs will
be added by drilling contractors within the WCSB during 2006. This would
increase the industry drilling fleet to 870 rigs to a level that is
unprecedented. In the event that demand softens, the additional industry
capacity could put the market in an oversupply position. This would impact
pricing and lower profitability for drilling contractors and other oilfield
service businesses.
Precision has and will continue to apply conservative financial
principles in managing its balance sheet and to remain opportunistic in its
pursuit of North American growth opportunities.
53
MANAGEMENT'S REPORT TO THE UNITHOLDERS
The accompanying consolidated financial statements and all information
in the Annual Report are the responsibility of management. The consolidated
financial statements have been prepared by management in accordance with the
accounting policies in the notes to the consolidated financial statements.
When necessary, management has made informed judgments and estimates in
accounting for transactions which were not complete at the balance sheet date.
In the opinion of management, the consolidated financial statements have been
prepared within acceptable limits of materiality, and are in accordance with
Canadian generally accepted accounting principles (GAAP) appropriate in the
circumstances. The financial information elsewhere in the Annual Report has
been reviewed to ensure consistency with that in the consolidated financial
statements.
Management has prepared Management's Discussion and Analysis (MD&A).
The MD&A is based upon the Trust's financial results prepared in accordance
with Canadian GAAP. The MD&A compares the audited financial results for the
years ended December 31, 2005 to December 31, 2004 and the years ended
December 31, 2004 to December 31, 2003. 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 maintains an appropriate system of internal control designed
to give reasonable assurance that transactions are properly authorized, assets
are safeguarded and financial records properly maintained to provide reliable
information for the preparation of financial statements.
KPMG LLP, an independent firm of Chartered Accountants, was engaged, as
approved by a vote of shareholders at the Trust's most recent annual and
special meeting, to audit the consolidated financial statements in accordance
with Canadian generally accepted auditing standards and provide an independent
professional opinion.
The Audit Committee of the Board of Directors, which is comprised of
three independent directors who are not employees of the Trust, provides
oversight to the financial reporting process. Integral to this process is the
Audit Committee's review and discussion with management and the external
auditors of the quarterly and annual financial statements and reports prior to
their respective release. The Audit Committee is also responsible for
reviewing and discussing with management and the external auditors major
issues as to the adequacy of the Trust's internal controls. The consolidated
financial statements have been approved by the Board of Trustees on the
recommendation of the Board of Directors of Precision Drilling Corporation and
its Audit Committee.
/s/ Hank B. Swartout /s/ Doug J. Strong
----------------------------------- -------------------------------
CHAIRMAN AND CHIEF EXECUTIVE OFFICER CHIEF FINANCIAL OFFICER
PRECISION DRILLING CORPORATION, PRECISION DRILLING CORPORATION,
ADMINISTRATOR TO PRECISION DRILLING TRUST ADMINISTRATOR TO PRECISION DRILLING TRUST
MARCH 7, 2006 MARCH 7, 2006
54
AUDITORS' REPORT TO THE UNITHOLDERS
We have audited the consolidated balance sheets of Precision Drilling
Trust as at December 31, 2005 and 2004 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, 2005. These consolidated financial
statements are the responsibility of the Trust's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted
auditing standards. 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, 2005 and 2004 and the results of its operations and its cash flow for each
of the years in the three-year period ended December 31, 2005 in accordance
with Canadian generally accepted accounting principles.
/s/ KPMG LLP
Chartered Accountants
CALGARY, ALBERTA
MARCH 2, 2006
55
CONSOLIDATED BALANCE SHEETS
(STATED IN THOUSANDS OF DOLLARS)
As at December 31, 2005 2004
-------------------------------------------------------------------------------------------------------------
ASSETS
Current assets:
Cash and cash equivalents $ - $ 122,012
Accounts receivable (NOTE 19) 500,655 309,292
Inventory 7,035 7,734
Assets of discontinued operations (NOTE 21) - 497,036
-------------------------------------------------------------------------------------------------------------
507,690 936,074
Property, plant and equipment, net of accumulated depreciation (NOTE 4) 943,900 897,584
Intangibles, net of accumulated amortization of $413 (2004 - $380) 465 498
Goodwill 266,827 266,827
Deferred financing costs - 9,116
Assets of discontinued operations (NOTE 21) - 1,741,950
-------------------------------------------------------------------------------------------------------------
$ 1,718,882 $ 3,852,049
=============================================================================================================
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Bank indebtedness (NOTE 6) $ 20,468 $ -
Accounts payable and accrued liabilities (NOTE 19) 134,303 120,432
Incomes taxes payable 163,530 13,624
Distributions payable (NOTE 5) 36,635 -
Liabilities of discontinued operations (NOTE 21) - 244,707
-------------------------------------------------------------------------------------------------------------
354,936 378,763
Long-term debt (NOTE 7) 96,838 718,850
Future income taxes (NOTE 12) 192,517 354,268
Liabilities of discontinued operations (NOTE 21) - 78,427
Unitholders' equity:
Unitholders' capital (NOTE 8) 1,377,875 1,274,967
Contributed surplus (NOTE 8) - 26,024
Cumulative translation adjustment (NOTE 18) - (20,933)
Retained earnings (deficit) (303,284) 1,041,683
-------------------------------------------------------------------------------------------------------------
1,074,591 2,321,741
Commitments and contingencies (NOTES 11 AND 20)
-------------------------------------------------------------------------------------------------------------
$ 1,718,882 $ 3,852,049
=============================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Approved by the Board:
/s/ Robert J.S. Gibson /s/ Patrick M. Murray
--------------------------- --------------------------
Robert J.S. Gibson Patrick M. Murray
TRUSTEE TRUSTEE
56
CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS (DEFICIT)
(STATED IN THOUSANDS OF DOLLARS, EXCEPT PER UNIT/SHARE AMOUNTS)
Years ended December 31, 2005 2004 2003
-------------------------------------------------------------------------------------------------------------
Revenue $ 1,269,179 $ 1,028,488 $ 915,170
Expenses:
Operating 641,805 566,297 544,163
General and administrative 76,397 64,149 42,662
Depreciation and amortization 71,561 74,829 78,112
Foreign exchange (3,474) (8,100) (2,216)
Reorganization costs (NOTE 9) 17,512 - -
-------------------------------------------------------------------------------------------------------------
803,801 697,175 662,721
-------------------------------------------------------------------------------------------------------------
Operating earnings 465,378 331,313 252,449
Interest:
Long-term debt (NOTE 7) 38,735 46,575 34,492
Other 558 246 115
Income (10,023) (541) (541)
Premium on redemption of bonds (NOTE 7) 71,885 - -
Loss on disposal of short-term investments (NOTE 21) 70,992 - -
Gain on disposal of investments - (4,899) (1,493)
-------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before income taxes 293,231 289,932 219,876
Income taxes: (NOTE 12)
Current 241,402 53,698 40,828
Future (169,019) 48,103 34,900
-------------------------------------------------------------------------------------------------------------
72,383 101,801 75,728
-------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 220,848 188,131 144,148
Gain (loss) on disposal of discontinued operations,
net of tax (NOTE 21) 1,335,382 (616) 17,460
Discontinued operations, net of tax (NOTE 21) 74,333 59,889 18,866
-------------------------------------------------------------------------------------------------------------
Net earnings 1,630,563 247,404 180,474
Retained earnings, beginning of year (NOTE 3) 1,041,683 794,279 613,805
Adjustment on cash purchase of employee stock options,
net of tax of $22,060 (NOTE 8) (42,087) - -
Reclassification from contributed surplus on cash
buy-out of employee stock options (NOTE 8) 23,215 - -
Distribution of disposal proceeds (NOTE 21) (2,851,784) - -
Repurchase of common shares of dissenting
shareholders (NOTE 8) (34,364) - -
Distributions (NOTE 5) (70,510) - -
-------------------------------------------------------------------------------------------------------------
Retained earnings (deficit), end of year $ (303,284) $ 1,041,683 $ 794,279
=============================================================================================================
Earnings per unit/share from continuing
operations: (NOTE 13)
Basic $ 1.79 $ 1.63 $ 1.33
Diluted $ 1.76 $ 1.61 $ 1.31
-------------------------------------------------------------------------------------------------------------
Earnings per unit/share: (NOTE 13)
Basic $ 13.22 $ 2.14 $ 1.66
Diluted $ 13.00 $ 2.11 $ 1.63
=============================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
57
CONSOLIDATED STATEMENTS OF CASH FLOW
(STATED IN THOUSANDS OF DOLLARS)
Years ended December 31, 2005 2004 2003
-------------------------------------------------------------------------------------------------------------
Cash provided by (used in):
Continuing operations:
Earnings from continuing operations $ 220,848 $ 188,131 $ 144,148
Items not affecting cash:
Depreciation and amortization 71,561 74,829 78,112
Stock-based compensation 11,229 8,190 6,366
Future income taxes (169,019) 48,103 34,900
Write-off of deferred financing costs 7,664 - -
Loss in market value of short-term investments 70,992 - -
Gain on disposal of investments - (4,899) (1,493)
Amortization of deferred financing costs 1,453 1,579 1,286
Unrealized foreign exchange gain on long-term
monetary items (4,740) (4,284) (42)
Changes in non-cash working capital balances (NOTE 19) (6,887) (23,828) (62,356)
-------------------------------------------------------------------------------------------------------------
203,101 287,821 200,921
Discontinued operations (NOTE 21):
Funds provided by discontinued operations 183,330 187,018 89,051
Changes in non-cash working capital balances
of discontinued operations (86,310) (26,797) (31,545)
-------------------------------------------------------------------------------------------------------------
97,020 160,221 57,506
Investments:
Business acquisitions, net of cash acquired (NOTE 15) (30,421) (679,814) (6,800)
Purchase of property, plant and equipment (155,231) (122,692) (96,193)
Purchase of intangibles (20) - (6)
Proceeds on sale of property, plant and equipment 15,174 8,795 11,341
Purchase of property, plant and equipment
of discontinued operations (128,214) (159,532) (218,728)
Purchase of intangibles of discontinued operations - (320) -
Proceeds on sale of property, plant and equipment
of discontinued operations 17,785 21,145 13,082
Proceeds on disposal of investments - 8,665 10,966
Proceeds on disposal of short-term investments 14,569 - -
Investments - (90) (1,080)
Proceeds on disposal of discontinued operations 1,306,799 49,299 67,274
-------------------------------------------------------------------------------------------------------------
1,040,441 (874,544) (220,144)
Financing:
Increase in long-term debt 96,826 522,136 85,228
Repayment of long-term debt (703,970) (173,260) (145,657)
Deferred financing costs on long-term debt - (5,612) -
Distribution of disposal proceeds (NOTE 21) (844,334) - -
Distributions (NOTE 5) (33,875) - -
Issuance of common shares, net of costs - 276,428 -
Issuance of common shares on exercise of options 73,930 55,361 23,613
Repurchase of common shares of dissenting shareholders (43,299) - -
Cash buy-out of employee stock options (64,147) - -
Issuance of trust units on exercise of options 8,263 - -
Issuance of trust units on purchase of options 5,504 - -
Changes in non-cash working capital balances 22,060 - -
Change in bank indebtedness 20,468 (147,909) 2,588
-------------------------------------------------------------------------------------------------------------
(1,462,574) 527,144 (34,228)
-------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents (122,012) 100,642 4,055
Cash and cash equivalents, beginning of year 122,012 21,370 17,315
-------------------------------------------------------------------------------------------------------------
Cash and cash equivalents, end of year $ - $ 122,012 $ 21,370
=============================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
58
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(TABULAR AMOUNTS STATED IN THOUSANDS OF DOLLARS EXCEPT PER UNIT/PER
SHARE AMOUNTS)
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.
The Trust is an unincorporated, open-ended investment trust governed by
the laws of Alberta and created pursuant to a 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 "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 were 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 consolidated
financial statements for prior periods may not be directly comparable. For
purposes of these consolidated financial statements, the share capital of PDC
is reported under Unitholders' capital (Note 8). 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 previously
held common shares of Precision (other than dissenting shareholders, who
received cash equal to the fair value of their shares). After giving effect to
the Plan of Arrangement, the consolidated financial statements include the
accounts of the Trust, its subsidiaries and its partnerships.
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 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.
1. SIGNIFICANT ACCOUNTING POLICIES:
CONTINUING OPERATIONS
(a) PRINCIPLES OF CONSOLIDATION:
The consolidated financial statements include the accounts of the
Trust, its subsidiaries and its partnerships, substantially all of which are
wholly-owned at December 31, 2005.
(b) CASH AND CASH EQUIVALENTS:
Cash and cash equivalents consist of cash and short-term investments
with original maturities of three months or less.
(c) INVENTORY:
Inventory is primarily comprised of operating supplies and spare parts
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.
(d) PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment are carried at cost, including costs of
direct material, labor, and indirect overhead for manufactured items. 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.
Drilling rig equipment is depreciated by the unit-of-production method
based on 5,000 utilization days (3,650 drilling days for the year ended
December 31, 2004 - see Note 2) with a 20 percent salvage value. Drill pipe
and drill collars are depreciated over 1,500 drilling days (1,100 drilling
days for the year ended December 31, 2004 - see Note 2) and have no salvage
value. Service rig equipment is depreciated by the unit-of-production method
based on 24,000 hours for single and double rigs and 48,000 hours for heavy
double rigs. Service rigs have a 20% salvage value.
Rental equipment is depreciated by the straight-line method over
periods ranging from 10 to 15 years. Other equipment is depreciated by the
straight-line method over periods ranging from three to ten years.
59
Light duty vehicles are depreciated by the straight-line method over
four years. Heavy-duty vehicles are depreciated by the straight-line method
over periods ranging from seven to ten years.
Buildings are depreciated by the straight-line method over periods
ranging from 10 to 20 years.
(e) 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 $75,000 per year.
(f) GOODWILL:
Goodwill is the amount that results when the purchase price of an
acquired business exceeds the sum of the amounts allocated to the assets
acquired, less liabilities assumed, based on their fair values. Goodwill is
allocated as of the date of the business combination to the Trust's reporting
segments that are expected to benefit from the business combination.
Goodwill is not amortized and is tested for impairment annually in the
fourth quarter, or more frequently if events or changes in circumstances
indicate that the asset might be impaired. The impairment test is carried out
in two steps. In the first step, the carrying amount of the reporting segment
is compared with its fair value. When the fair value of a reporting segment
exceeds its carrying amount, goodwill of the reporting segment is considered
not to be impaired and the second step of the impairment test is unnecessary.
The second step is carried out when the carrying amount of a reporting segment
exceeds its fair value, in which case the implied fair value of the reporting
segment's goodwill is compared with its carrying amount to measure the amount
of the impairment loss, if any. The implied fair value of goodwill is
determined in the same manner as the value of goodwill is determined in a
business combination described in the preceding paragraph, using the fair
value of the reporting segment as if it was the purchase price. When the
carrying amount of a reporting segment's goodwill exceeds the implied fair
value of the goodwill, an impairment loss is recognized in an amount equal to
the excess.
(g) LONG LIVED ASSETS:
On a periodic basis, management assesses the carrying value of long
lived assets for indications of impairment. Indications of impairment include
items such as 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.
(h) INVESTMENTS:
Investments in shares of associated companies, over which the Trust has
significant influence, are accounted for by the equity method. Other
investments are carried at cost. If there are other than temporary declines in
value, these investments are written down to their net realizable value.
(i) DEFERRED FINANCING COSTS:
Costs associated with the issuance of long-term debt are deferred and
amortized by the straight-line method over the term of the debt. The
amortization is included in interest expense.
(j) 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 unitholders. As the Trust
distributes all of its taxable income to its respective unitholders pursuant
to the requirements of the trust indenture, 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 the currently enacted, 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.
(k) REVENUE RECOGNITION:
The Trust's services are generally sold based upon purchase orders or
contracts with the 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.
(l) EMPLOYEE BENEFIT PLANS:
At December 31, 2005, approximately 52% (2004 - 33%) of the Trust's
employees were enrolled in the Trust's defined contribution retirement plans.
60
Employer contributions to defined contribution plans are expensed as
employees earn the entitlement and contributions are made.
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. This retirement allowance was paid during the year
ended December 31, 2005 (see Note 10).
(m) FOREIGN CURRENCY TRANSLATION:
Accounts of the Trust's integrated foreign operations are translated to
Canadian dollars using average exchange rates for the year 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, which are described in Note 8.
The fair value of common share purchase options was calculated at the date of
grant using the Black-Scholes option pricing model and that value was recorded
as compensation expense on a straight-line basis over the grant's vesting
period with an offsetting credit to contributed surplus. Upon exercise of the
equity purchase option, the associated amount was reclassified from
contributed surplus to unitholders' capital. Consideration paid by employees
upon exercise of equity purchase options was credited to unitholders' capital.
(o) EXCHANGEABLE SHARES:
Exchangeable shares 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.
Share and per share amounts prior to the trust conversion on November
7, 2005 are referred to as unit or per unit amounts in the consolidated
financial statements.
(q) MEASUREMENT UNCERTAINTY:
Certain items recognized in the consolidated financial statements are
subject to measurement uncertainty as they are based on management's estimate
using current information and judgment. The effect on the consolidated
financial statements of changes in such estimates in future years could be
significant.
DISCONTINUED OPERATIONS
(a) EMPLOYEE BENEFIT PLANS:
At December 31, 2004, approximately 36% of employees of discontinued
operations were enrolled in retirement plans. Of that, approximately 6% of
participating employees were enrolled in the defined benefit plan and
approximately 94% in the defined contribution plan.
Employer contributions to defined contribution plans were expensed as
employees earned the entitlement and contributions were made.
The Trust accrued the cost of pensions earned by employees under its
defined benefit plan, which was actuarially determined using the projected
benefit method pro-rated on services and management's best estimate of
expected plan investment performance, salary escalation and retirement ages of
employees. For the purpose of calculating the expected return on plan assets,
those assets were valued at quoted market value at the balance sheet date. The
discount rate used to calculate the interest cost on the accrued benefit
obligation was the long-term market rate at the balance sheet date. Past
service costs from plan amendments were amortized on a straight-line basis
over the average remaining service period of employees active at the date of
amendment (EARSL). The excess of the net cumulative unamortized actuarial gain
or loss over 10% of the greater of the accrued benefit obligation and the
market value of plan assets was amortized over EARSL.
(b) FOREIGN CURRENCY TRANSLATION:
Accounts of the Trust's self-sustaining operations were translated to
Canadian dollars using average exchange rates for the year for revenue and
expenses. Assets and liabilities were translated at the year-end current
exchange rate.
61
Gains or losses resulting from these translation adjustments were
included in the cumulative translation account in unitholders' equity.
Gains and losses arising on translation of long-term debt designated as
a hedge of self-sustaining foreign operations were deferred and included in
the cumulative translation account in unitholders' equity on a net of tax
basis.
(c) HEDGING RELATIONSHIPS:
The Trust utilized foreign currency long-term debt to hedge its
exposure to changes in the carrying values of the Trust's net investment in
certain self-sustaining foreign operations as a result of changes in foreign
exchange rates.
To be accounted for as a hedge, the foreign currency long-term debt
must be designated and documented as a hedge, and must be effective at
inception and on an ongoing basis. The documentation defined the relationship
between the foreign currency long-term debt and the net investment in the
foreign operations, as well as the Trust's risk management objective and
strategy for undertaking the hedging transaction. The Trust formally assessed,
both at the hedge's inception and on an ongoing basis, whether the changes in
fair value of the foreign currency long-term debt is 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.
2. 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 drilling days), and its
drill string to 1,500 from 1,100 drilling days. Utilization days include both
operating and rig move days. This change in accounting estimate has been
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.
3. 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 (2003 - $8.2 million) or $0.11 diluted
earnings per share (2003 - $0.08) and a reduction to opening retained earnings
of $14.5 million at January 1, 2004 ($6.3 million at January 1, 2003).
62
4. PROPERTY, PLANT AND EQUIPMENT:
ACCUMULATED NET BOOK
2005 COST DEPRECIATION VALUE
-------------------------------------------------------------------------------------------------------------
Rig equipment $ 1,163,970 $ 386,191 $ 777,779
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
Land 8,996 - 8,996
-------------------------------------------------------------------------------------------------------------
$ 1,458,533 $ 514,633 $ 943,900
=============================================================================================================
Accumulated Net Book
2004 Cost Depreciation Value
-------------------------------------------------------------------------------------------------------------
Rig equipment $ 1,070,428 $ 341,827 $ 728,601
Rental equipment 77,246 32,117 45,129
Other equipment 111,820 63,939 47,881
Vehicles 58,391 16,359 42,032
Buildings 32,901 8,715 24,186
Land 9,755 - 9,755
-------------------------------------------------------------------------------------------------------------
$ 1,360,541 $ 462,957 $ 897,584
=============================================================================================================
5. DISTRIBUTIONS PAYABLE:
Distributions were declared on trust and exchangeable LP units of $0.27
per unit for the month ended November 30, 2005 and $ 0.27 per unit plus a
special distribution of $0.022 per unit for the month ended December 31, 2005.
Total distributions were $70.5 million, of which $33.9 million was paid on
December 15, 2005 and $36.6 million was paid on January 17, 2006.
6. BANK INDEBTEDNESS:
At December 31, 2005, the Trust has available $60.0 million (December
31, 2004 - $63.0 million) and US$5.0 million (December 31, 2004 - US$30.7
million) under uncommitted, unsecured credit facilities, of which $20.5
million had been drawn (December 31, 2004 - $nil). Availability of these
facilities was reduced by outstanding letters of credit in the amount of $8.4
million (December 31, 2004 - $33.3 million, of which $29.2 million related to
discontinued operations). Advances under the facilities are available at the
bank's prime lending rate, U.S. base rate, U.S. Libor plus applicable margin
or Banker's Acceptance plus applicable margin, or in combination. The
applicable margin is dependent on the Trust's consolidated debt to cashflow
ratio.
7. LONG-TERM DEBT:
2005 2004
-------------------------------------------------------------------------------------------------------------
Extendible revolving unsecured facility $ 96,838 $ -
Unsecured debentures - Series 1 - 200,000
Unsecured debentures - Series 2 - 150,000
Unsecured notes, US$300.0 million - 368,850
-------------------------------------------------------------------------------------------------------------
$ 96,838 $ 718,850
=============================================================================================================
EXTENDIBLE REVOLVING UNSECURED FACILITY:
At December 31, 2005, PDC, a subsidiary of the Trust, has available a
three-year revolving unsecured facility of $550.0 million (or U.S. equivalent)
with a syndicate led by a Canadian chartered bank which is guaranteed by the
Trust. The facility matures November 2, 2008 and is renewable annually at the
option of the lenders. Advances are available to PDC under this facility
either at the bank's prime lending rate, U.S. base rate, U.S. Libor plus
applicable margin or Bankers' Acceptance plus applicable margin or in
combination. The applicable margin is dependent on the Trust's consolidated
debt to cashflow ratio and the percentage of the total facility outstanding,
which at December 31, 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
and a trailing 12 month ratio of consolidated debt to cash flow of less than
2.75:1.
The above facility replaces those facilities available and outstanding
as at December 31, 2004 which were cancelled as follows:
63
For the year ended December 31, 2004, the Trust had a three-year
revolving unsecured facility of $335.0 million (or U.S. equivalent) with a
syndicate led by a Canadian chartered bank. The facility was to have matured
August 31, 2007 and was renewable annually at the option of the lenders.
Advances were available to the Trust under this facility either at the bank's
prime lending rate, U.S. base rate, U.S. Libor plus applicable margin or
Bankers' Acceptance plus applicable margin, or in combination. The applicable
margin was dependent on the Trust's credit rating and the percentage of the
total facility outstanding. The facility was extendable annually at the option
of the lenders and required that the Trust maintain a ratio of total
liabilities to total equity of less than 1:1 and a ratio of debt to cash flow
of less than 2.75:1. No amounts were drawn on this facility at December 31,
2004.
Also for the year ended December 31, 2004, the Trust had a US$50.0
million unsecured facility with Export Development Canada (EDC) that was to
have matured on December 8, 2005 and bore interest at six-month U.S. Libor
plus applicable margin. The margin was dependent upon the Trust's margin on
its $335.0 million three-year revolving unsecured credit facility, which at
December 31, 2004 resulted in a margin of 0.8%. The facility was extendable
upon mutual agreement between the Trust and EDC, or could be converted, at the
Trust's option, to a term loan repayable in two equal semi-annual instalments.
No amounts were drawn on this facility at December 31, 2004.
UNSECURED DEBENTURES:
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.
o The $200.0 million 6.85% Series 1 unsecured debentures was to have
matured June 26, 2007 and had an effective interest rate of 7.44%
after taking into account deferred financing costs. The debentures
were redeemable at any time at the option of Precision upon payment
of a redemption price equal to the greater of an amount calculated
with reference to the yield on a Government of Canada bond with the
same maturity, and par.
o The $150.0 million 7.65% Series 2 unsecured debentures was to have
matured October 27, 2010 and had an effective interest rate of
7.71% after taking into account deferred financing costs. The
debentures were redeemable at any time at the option of Precision
upon payment of a redemption price equal to the greater of an
amount calculated with reference to the yield on a Government of
Canada bond with the same maturity, and par.
UNSECURED NOTES:
o The US$300.0 million 5.625% unsecured notes were to have matured
June 1, 2014 and had an effective interest rate of 5.71% after
taking into account deferred financing costs. The notes were
redeemable at any time at the option of Precision upon payment of a
redemption price equal to the greater of an amount calculated with
reference to the yield on a United States treasury security with
the same maturity, and par.
OTHER:
o The $3.5 million unsecured term financing facility with EDC matured
on January 20, 2004 and bore interest at six-month U.S. Libor plus
applicable margin. The margin was dependent upon Precision's credit
rating, which at December 31, 2003 resulted in a margin of 0.8%.
o The $26.2 million unsecured term financing facility with EDC was
repaid and cancelled in 2004 and bore interest at six-month U.S.
Libor plus applicable margin. The margin was dependent upon
Precision's credit rating, which at December 31, 2003 resulted in a
margin of 0.9%.
Principal repayments after 2005 are as follows:
------------------------------------------------------------------------------
2006 $ -
2007 -
2008 96,838
Thereafter -
------------------------------------------------------------------------------
2008 $ 96,838
==============================================================================
8. UNITHOLDERS' CAPITAL:
On November 7, 2005, Precision converted to an unincorporated,
open-ended investment trust pursuant to a Plan of Arrangement. The Plan
resulted in shareholders receiving one trust unit or one exchangeable LP unit
or a combination thereof, for previously held common shares. 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.
64
(a) AUTHORIZED - unlimited number of voting trust units.
- unlimited number of voting exchangeable LP units
(b) COMMON SHARES:
NUMBER AMOUNT
-------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002 54,066,753 $ 913,087
Options exercised - cash consideration 778,925 23,613
- reclassification from contributed surplus - 44
-------------------------------------------------------------------------------------------------------------
Balance, December 31, 200 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 123,621,181 $ 1,351,766
=============================================================================================================
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. Proceeds of the
offering were primarily used to repay indebtedness incurred in connection with
the acquisition of all of the issued and outstanding shares of Reeves Oilfield
Services Ltd.
(c) 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
=============================================================================================================
Trust units are redeemable at the option of the holder, at which time
all rights with respect to such units are cancelled. Upon redemption, the
unitholder is entitled to receive a price per unit equal to the lesser of 90%
of the average market price of the Trust's units for the 10 trading days just
prior to the date of redemption, and the closing market price of the Trust's
units on the date of redemption. The maximum value of units that can be
redeemed for cash is $50,000 per month. Redemptions, if any, in excess of this
amount are satisfied by issuing a note from PDC to the unitholder, payable
over 15 years and bearing interest at a market rate set by the Board of
Directors.
65
NUMBER AMOUNT
-------------------------------------------------------------------------------------------------------------
Exchangeable LP units
Balance, November 7, 2005 - $ -
Issued pursuant to the Plan 1,108,382 12,120
-------------------------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2005 1,108,382 $ 12,120
=============================================================================================================
Exchangeable LP units have voting rights and are 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.
NUMBER AMOUNT
-------------------------------------------------------------------------------------------------------------
SUMMARY:
TRUST UNITS 124,352,921 $ 1,365,755
EXCHANGEABLE LP UNITS 1,108,382 12,120
-------------------------------------------------------------------------------------------------------------
UNITHOLDERS' CAPITAL 125,461,303 $ 1,377,875
-------------------------------------------------------------------------------------------------------------
(d) CONTRIBUTED SURPLUS:
-------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002 $ 6,108
Stock-based compensation expense 8,202
Reclassification to common shares on exercise of options (44)
-------------------------------------------------------------------------------------------------------------
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 $ -
=============================================================================================================
(e) EQUITY INCENTIVE PLANS:
Prior to conversion to a Trust, Precision Drilling Corporation had
equity incentive plans under which the exercise price of each option equalled
the market value of Precision's stock on the date of grant and an option's
maximum term was 10 years. Options vested over a period of one to four 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 became fully vested when these
businesses were sold during the third quarter of 2005 (see Note 21). 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 transfer 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-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, 2003, 2004
and 2005 and changes during the periods then ended is presented below:
66
COMMON SHARE PURCHASE OPTIONS:
Weighted
Range of Average
Options Exercise Exercise Options
Outstanding Price Price Exercisable
-----------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2002 8,238,656 $ 6.75 - 32.95 $ 19.47 3,255,554
Granted 832,000 24.64 - 25.52 25.31
Exercised (1,557,850) 6.75 - 25.50 15.17
Cancelled (726,418) 15.53 - 32.95 22.45
-----------------------------------------------------------------------------------------------------------------
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 - $ - $ - -
=================================================================================================================
TRUST UNIT PURCHASE OPTIONS:
Granted in exchange for Common share
purchase options pursuant to the Plan 3,308,850 $ nil - 27.25 $ 9.16 3,308,850
Granted on repricing of common share options 5,600 nil nil
Exercised (1,676,616) nil - 27.25 4.93
Purchased (1,637,834) nil - 27.25 13.46
-----------------------------------------------------------------------------------------------------------------
OUTSTANDING AT DECEMBER 31, 2005 - $ - $ - -
=================================================================================================================
In accordance with the Trust's stock option plans, options have 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; 2003 - $9.74) 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%;
2003 - 3.47%), average expected life of 2.92 years (2004 - 2.97 years; 2003 -
3.42 years) and expected volatility of 28.04% (2004 - 32.33%; 2003 - 47.00%).
For the year ended December 31, 2005, stock-based compensation costs
included in net earnings totalled $21.3 million (2004 - $13.8 million; 2003 -
$8.2 million), of which $10.1 million (2004 - $5.6 million; 2003 - $1.8
million) relates to discontinued operations.
9. REORGANIZATION PURSUANT TO PLAN OF ARRANGEMENT
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
=============================================================================================================
67
10. EMPLOYEE BENEFIT PLANS:
The Trust has registered pension plans covering a significant number of
its employees. Of participating employees in continuing operations, all
participate in the defined contribution plan. Of participating employees in
discontinued operations, approximately 94% participated in the defined
contribution plan and approximately 6% participated in the defined benefit
plan.
(a) DEFINED CONTRIBUTION PLAN
Under the defined contribution plan, the Trust matches individual
contributions up to 5% of the employee's compensation. Total expense under the
defined contribution plan in 2005 was $8.5 million (2004 - $7.3 million; 2003
- $7.5 million), of which $3.2 million (2004 - $3.0 million; 2003 - $3.3
million) relates to discontinued operations.
(b) DEFINED BENEFIT PLANS
The defined benefit plans were acquired as part of the Reeves Oilfield
Services Ltd. acquisition in 2004 (see Note 15) and was closed to new
employees since the date of acquisition. The latest actuarial valuations of
the defined benefit pension plans were at December 31, 2004. The measurement
date used to determine plan assets and accrued benefit obligation was December
31, 2004. Significant actuarial assumptions adopted in measuring the Trust's
accrued benefit obligation at the measurement date included a liability
discount rate of between 5.5% and 6.0%, an expected long-term rate of return
on plan assets of between 5.8% and 6.4% and a rate of compensation increase of
between 3.8% and 5.0%, excluding promotions. At the measurement date, the
plans had an unfunded deficit of $13.5 million as the accrued benefit
obligation of $41.5 million exceeded plan assets of $28.0 million. The
unfunded deficit liability was included in accounts payable and accrued
liabilities in discontinued operations.
Expense under the defined benefit plans in 2004 totalled $1.1 million.
(c) RETIREMENT ALLOWANCE
With respect to the retirement allowance described in Note 1(l), the
Trust charged $201,000 to earnings in 2005 (2004 - $335,000; 2003 - $351,000),
and during the year ended December 31, 2005 paid $2.9 million as settlement of
this liability. As at December 31, 2004, the Trust had accrued a total of $2.7
million, which amount is included in accounts payable and accrued liabilities.
11. COMMITMENTS:
The Trust has commitments for operating lease agreements, primarily for
vehicles and office space, in the aggregate amount of $27.9 million. Payments
over the next five years are as follows:
Total
------------------------------------------------------------------------------
2006 $ 7,362
2007 5,832
2008 4,335
2009 3,674
2010 3,660
==============================================================================
Rent expense included in the statements of earnings is as follows:
Continuing Discontinued
Operations Operations Total
------------------------------------------------------------------------------
2005 $ 2,679 $ 11,983 $ 14,662
2004 5,874 17,284 23,158
2003 5,258 18,666 23,924
==============================================================================
68
12. INCOME TAXES:
The provision for income taxes differs from that which would be
expected by applying statutory rates. A reconciliation of the difference is as
follows:
2005 2004 2003
-------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before income taxes $ 293,231 $ 289,932 $ 219,876
Income tax rate 34% 36% 36%
-------------------------------------------------------------------------------------------------------------
Expected income tax provision $ 99,699 $ 104,375 $ 79,155
Add (deduct):
Non-deductible expenses 2,795 4,965 1,234
Non-deductible stock-based compensation 3,216 2,948 2,292
Income of the Trust (23,980) - -
Utilization of losses and surcharge credits (10,550) - -
Non-taxable disposition of investment - - (2,327)
Other 1,203 (7,600) (1,948)
-------------------------------------------------------------------------------------------------------------
72,383 104,688 78,406
Reduction of future tax balances due to
substantively enacted tax rate reductions - (2,887) (2,678)
-------------------------------------------------------------------------------------------------------------
$ 72,383 $ 101,801 $ 75,728
-------------------------------------------------------------------------------------------------------------
Effective income tax rate 25% 35% 34%
=============================================================================================================
In 2004, the Province of Alberta enacted a 1.0% reduction in tax
rates (2003 and 2002 - 0.5%). This reduction was reflected as a reduction in
future tax expense in the respective years.
The net future tax liability is comprised of the tax effect of the
following temporary differences:
2005 2004
-------------------------------------------------------------------------------------------------------------
Liabilities:
Property, plant and equipment and intangibles $ 232,277 $ 232,770
Operations of a partnership with different tax year - 124,251
Deferred financing costs - 1,584
-------------------------------------------------------------------------------------------------------------
$ 232,277 $ 358,605
-------------------------------------------------------------------------------------------------------------
Assets:
Bond redemption premium $ 20,820 $ -
Losses carried forward 14,586 -
Share issue costs 3,039 -
Accrued liabilities 1,910 4,337
Valuation allowance (595) -
-------------------------------------------------------------------------------------------------------------
$ 39,760 $ 4,337
-------------------------------------------------------------------------------------------------------------
$ 192,517 $ 354,268
=============================================================================================================
PDC and its subsidiaries have available capital losses of $42.4 million
of which, after valuation allowances, the benefit of $40.7 million has been
recognized. These capital losses can be carried forward indefinitely.
During 2004, $7.5 million, representing future tax expense on foreign
exchange gains associated with the Trust's US$300 million unsecured notes was
charged to the cumulative translation account in unitholders' equity. This
amount was related to the Trust's discontinued operations.
69
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:
For the years ended December 31, 2005 2004 2003
-------------------------------------------------------------------------------------------------------------
Weighted average units/shares outstanding - basic 123,304 115,654 108,860
Effect of unit/share purchase options 2,108 1,556 1,738
-------------------------------------------------------------------------------------------------------------
Weighted average units/shares outstanding - diluted 125,412 117,210 110,598
=============================================================================================================
14. SIGNIFICANT CUSTOMERS:
During the year ended December 31, 2005 no customers (2004 - one
customer; 2003 - two customers) accounted for more than 10% of the Trust's
revenue.
15. ACQUISITIONS:
Acquisitions have been accounted for by the purchase method with
results of operations acquired included in the financial statements from the
effective date of acquisition. The details of acquisitions for the past three
years are as follows.
On July 29, 2005, the Trust completed the acquisition of all the issued
and outstanding shares of CASCA Electric Ltd. and CASCA Tech Inc. for $30.4
million. No value was assigned to intangibles or goodwill. These operations
have been included in discontinued operations.
During the year ended December 31, 2004, in accordance with the Trust's
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 totalled $1.3 million. Reeves provides 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. The
Reeves operations have been included in discontinued operations.
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. The Global SantaFe operations have been included in discontinued
operations.
Reeves GlobalSantaFe Other Total
-----------------------------------------------------------------------------------------------------------------
Net assets acquired at assigned values:
Working capital $ 23,000(a) $ 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
=================================================================================================================
(a) Includes cash of $12,142
In February 2003, Precision completed the acquisition of the operating
assets of MacKenzie Caterers (1984) Ltd., a provider of oilfield camp and
catering services in western Canada, for $6.8 million. No value was assigned
to intangibles or goodwill.
70
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 2003,
2004 and 2005, 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; 2003 - $8.2 million) and 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; 2003 decreased to $180.7 million). Basic
earnings per unit/share would have been $12.88 in 2005 (2004 - $2.14; 2003 -
$1.66).
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 transfer of disposal
consideration to Precision's shareholders just prior to conversion, or
repurchase for cash depending on elections made by the option holders. Under
Canadian GAAP, even with the 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 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 the 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 trust indenture, trust units are redeemable at any time on
demand by the unitholder for cash and notes (see Note 8). 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 reflected as a
reduction in earnings available to unitholders for the year.
71
(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.
(e) RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
On December 16, 2004, FASB issued SFAS 123R SHARE BASED PAYMENT - AN
AMENDMENT OF FASB STATEMENT NO. 123 AND 95. The Statement addresses the
accounting for transactions in which an enterprise receives employee services
in exchange for (a) equity instruments of the enterprise or (b) liabilities
that are based on the fair value of the enterprise's equity instruments or
that may be settled by the issuance of such equity instruments. Companies will
be required to recognize an expense for compensation cost related stock-based
compensation on a basis consistent with SFAS 123 for periods beginning on or
after June 15, 2005.
In December 2004, FASB issued Statement 153 Exchanges of Nonmonetary
Assets - An Amendment of APB Opinion 29. This Statement amends Opinion 29 to
eliminate the exception for nonmonetary exchanges or similar productive assets
and replaces it with a general exception for exchanges of nonmonetary assets
that do not have commercial substance. A nonmonetary exchange has commercial
substance if the future cash flows of the entity are expected to change
significantly as a result of the exchange. Application is prospective
beginning after June 15, 2005, and management does not expect this statement
to have a material impact on the consolidated financial statements.
As of January 1, 2006, the Trust will be required to adopt, for U.S.
GAAP purposes, SFAS 154 Accounting Changes and Error Corrections - A
Replacement of APB Opinion 20 and SFAS 3. This Statement requires
retrospective application of voluntary changes in accounting principles,
unless it is impracticable. Management does not expect this standard to have a
material impact on the consolidated financial statements.
The application of U.S. accounting principles would have the following
impact on the consolidated financial statements:
CONSOLIDATED STATEMENTS OF EARNINGS
Years ended December 31, 2005 2004 2003
-------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations under Canadian GAAP $ 220,848 $ 188,131 $ 144,148
Adjustments under U.S. GAAP:
Stock-based compensation expense 11,229 8,190 6,366
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 207,688 196,321 150,514
-------------------------------------------------------------------------------------------------------------------
Earnings from discontinued operations under Canadian GAAP 1,409,715 59,273 36,326
Adjustments under U.S. GAAP:
Stock-based compensation expense 10,109 5,647 1,836
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 1,388,060 64,920 38,162
-------------------------------------------------------------------------------------------------------------------
Net earnings under U.S. GAAP $ 1,595,748 $ 261,241 $ 188,676
Cumulative translation adjustment - (20,933) -
-------------------------------------------------------------------------------------------------------------------
Comprehensive income under U.S. GAAP $ 1,595,748 $ 240,308 $ 188,676
===================================================================================================================
Net earnings under U.S. GAAP $ 1,595,748 $ 261,241 $ 188,676
Change in redemption value of unitholders' capital (378,456) - -
-------------------------------------------------------------------------------------------------------------------
Net earnings available to unitholders under U.S. GAAP $ 1,217,292 $ 261,241 $ 188,676
===================================================================================================================
72
Earnings from continuing operations per unit/share under U.S. GAAP:
Basic $ 1.68 $ 1.70 $ 1.38
Diluted $ 1.66 $ 1.67 $ 1.36
Earnings per unit/share under U.S. GAAP before change in redemption
value of unitholders' capital:
Basic $ 12.94 $ 2.26 $ 1.73
Diluted $ 12.72 $ 2.23 $ 1.71
Earnings per unit/share under U.S. GAAP after change in
redemption value of unitholders' capital:
Basic $ 9.87 $ 2.26 $ 1.73
Diluted $ 9.71 $ 2.23 $ 1.71
=============================================================================================================
BALANCE SHEETS
DECEMBER 31, 2005 December 31, 2004
-------------------------------------------------------------------------------------------------------------
AS REPORTED U.S. GAAP As reported U.S. GAAP
-------------------------------------------------------------------------------------------------------------
Current assets $ 507,690 $ 507,690 $ 936,074 $ 936,074
Property, plant and equipment 943,900 943,900 897,584 897,584
Intangibles 465 465 498 498
Goodwill 266,827 329,856 266,827 329,856
Other assets - - 9,116 9,116
Long-term assets of discontinued operations - - 1,741,950 1,741,950
-------------------------------------------------------------------------------------------------------------
$ 1,718,882 $ 1,781,911 $ 3,852,049 $ 3,915,078
=============================================================================================================
Current liabilities $ 354,936 $ 354,936 $ 378,763 $ 378,783
Long-term debt 96,838 96,838 718,850 718,850
Future income tax liability 192,517 192,517 354,268 354,268
Liabilities of discontinued operations - - 78,427 78,407
Temporary equity - 4,304,665 - -
Unitholders' equity (deficit) 1,074,591 (3,167,045) 2,321,741 2,384,770
-------------------------------------------------------------------------------------------------------------
$ 1,718,882 $ 1,781,911 $ 3,852,049 $ 3,915,078
=============================================================================================================
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 and hydraulic well assist snubbing units, and oilfield equipment
rental.
Contract Completion and Corporate Inter-segment
2005 Drilling Services Production 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 Corporate Inter-segment
2004 Drilling Services Production 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
=============================================================================================================
73
Contract Completion and Corporate Inter-segment
2003 Drilling Services Production Services and Other Eliminations Total
-------------------------------------------------------------------------------------------------------------
Revenue $ 663,619 $ 263,218 $ - $ (11,667) $ 915,170
Operating earnings 218,012 48,706 (14,269) - 252,449
Depreciation and amortization 47,895 25,720 4,497 - 78,112
Total assets 919,383 448,067 90,984 - 1,458,434
Goodwill 172,440 94,387 - - 266,827
Capital expenditures* 47,918 25,410 22,871 - 96,199
=============================================================================================================
* EXCLUDES BUSINESS ACQUISITIONS
18. FINANCIAL INSTRUMENTS:
(a) FAIR VALUE
The carrying value of cash and cash equivalents, accounts receivable,
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. The fair value of
long-term debt approximates its carrying value as it bears interest at
floating rates.
The fair values of the unsecured debentures and notes have been
calculated with reference to the year end prevailing interest and foreign
exchange rates and are as follows:
DECEMBER 31, 2005 December 31, 2004
-------------------------------------------------------------------------------------------------------------
($ millions) CARRYING VALUE FAIR VALUE Carrying Value Fair Value
-------------------------------------------------------------------------------------------------------------
Unsecured debentures - Series 1 - - 200.0 215.4
Unsecured debentures - Series 2 - - 150.0 174.5
Unsecured notes, US$300.0 million - - 368.9 384.8
=============================================================================================================
(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 credit
worthiness 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,
2005 the Trust's allowance for doubtful accounts was $5.1 million (December
31, 2004 - $13.7 million, of which $8.5 million related to discontinued
operations).
(c) INTEREST RATE RISK
The Trust is exposed to interest rate risk with respect to interest
expense on its extendible revolving credit facilities.
(d) FOREIGN CURRENCY RISK
The Trust was exposed to foreign currency fluctuations in relation to
its international operations prior to their disposal (see Note 21). To manage
a portion of this exposure, the Trust designated the U.S. $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.
19. SUPPLEMENTAL INFORMATION:
2005 2004 2003
-------------------------------------------------------------------------------------------------------------
Interest paid:
- continuing operations $ 43,232 $ 45,338 $ 34,917
- discontinued operations 304 997 1,804
-------------------------------------------------------------------------------------------------------------
$ 43,536 $ 46,335 $ 36,721
=============================================================================================================
Income taxes paid:
- continuing operations $ 91,496 $ 38,759 $ 25,842
- discontinued operations 35,176 35,935 18,152
-------------------------------------------------------------------------------------------------------------
$ 126,672 $ 74,694 $ 43,994
=============================================================================================================
74
Components of change in non-cash working capital balances:
Accounts receivable $ (171,363) $ (42,714) $ (98,501)
Inventory 699 (2,017) 1,269
Accounts payable and accrued liabilities 13,871 5,964 19,890
Income taxes payable 149,906 14,939 14,986
-------------------------------------------------------------------------------------------------------------
$ (6,887) $ (23,828) $ (62,356)
=============================================================================================================
The components of accounts receivable are as follows:
2005 2004
-------------------------------------------------------------------------------------------------------------
Trade $ 306,264 $ 203,976
Accrued trade 148,537 88,746
Prepaids and other 45,854 16,570
-------------------------------------------------------------------------------------------------------------
$ 500,655 $ 309,292
=============================================================================================================
The components of accounts payable and accrued liabilities are as
follows:
2005 2004
-------------------------------------------------------------------------------------------------------------
Accounts payable $ 71,027 $ 25,658
Accrued liabilities
Payroll 30,351 30,048
Other 32,925 64,726
-------------------------------------------------------------------------------------------------------------
$ 134,303 $ 120,432
=============================================================================================================
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, and in particular
those completed within the last five years, involves many complex factors as
well as the Trust's interpretation of relevant tax legislation and
regulations. The Trust's management believes that the provision for income tax
is adequate and in accordance with generally accepted accounting principles
and applicable legislation and regulations. However, there are a number of tax
filing positions that can still be the subject of review by taxation
authorities who may successfully challenge the Trust's interpretation of the
applicable tax legislation and regulations, with the result that additional
taxes could be payable by the Trust and the amount payable could be up to
$300.0 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.
21. DISCONTINUED OPERATIONS:
On August 31, 2005, the Trust sold its Energy Services and
International Contract Drilling divisions to Weatherford International Ltd.
("Weatherford") for proceeds of approximately $1.13 billion cash and 26
million common shares of Weatherford, valued at $2.1 billion. In conjunction
with the Plan of Arrangement, the Trust then transferred 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
represents the fair value of the shares at the date of transfer. Included in
the statement of earnings for the year ended December 31, 2005 is a loss on
disposal of these shares of $71.0 million. In conjunction with this sale, a
working capital adjustment has been included as part of the purchase and sale
agreement. This adjustment is calculated based on the period January 1, 2005
to August 31, 2005 (the closing date of the sale) and is subject to certain
interpretations and assessments as to the working capital balances as at
August 31, 2005 and December 31, 2004. As at December 31, 2005, the Trust has
included as part of the gain on disposal of discontinued operations an amount
of $20.0 million owing to it, representing its best estimate of the final
working capital adjustment. However, this amount is subject to change
depending on the outcome of ongoing discussion and possible arbitration and
could adjust the disposal proceeds. Management estimates that ultimate
settlement of this issue will not have a material impact on the recorded gain
on disposal of discontinued operations.
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
75
for the purchase of all the issued and outstanding shares of CASCA Electric
Ltd. and CASCA Tech Inc., a transaction undertaken by CEDA on July 29, 2005.
The Energy Services, International Contract Drilling and CEDA assets were
included in the Energy Services, Contract Drilling and Rental and Production
segments respectively and were disposed in accordance with an extensive
process undertaken by the Trust's board of directors to explore avenues of
valuation creation for the Trust's unitholders.
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 are 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. No
portion of the $9.5 million of contingent proceeds has been recognized. 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.
Effective January 1, 2003, the Trust sold Energy Industries Inc., a
wholly-owned subsidiary for $60.0 million cash. Energy Industries designed and
manufactured modularized natural gas compression packages. These assets were
included in the Rental and Production segment and were disposed of as they
were not a core component, at that time, to the globalization strategy.
In May 2003, the Trust sold its 50% interest in Energy Equipment
Rentals General partnership ("EER") and Oil Drilling Exploration (Argentina)
SA ("OD&E") for cash proceeds of $6.9 million, net of transaction costs. Both
entities were components of the Contract Drilling segment and were disposed of
as they were not a core component, at that time, to the contract drilling
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 results of discontinued
operations:
2005 2004 2003
-------------------------------------------------------------------------------------------------------------
Revenue
Energy services $ 689,319 $ 898,199 $ 762,536
International contract drilling 204,987 246,612 114,691
Industrial plant maintenance 149,371 175,802 174,246
-------------------------------------------------------------------------------------------------------------
$ 1,043,677 $ 1,320,613 $ 1,051,473
=============================================================================================================
Gain on disposal of Energy Industries $ - $ - $ 13,071
Gain on disposal of EER and OD&E - - 4,389
Loss on disposal of Fleet Cementers' assets - (362) -
Loss on disposal of United Diamond - (254) -
Gain on disposal of Energy services and
International contract drilling 1,203,309 - -
Gain on disposal of Industrial plant maintenance 132,073 - -
-------------------------------------------------------------------------------------------------------------
$ 1,335,382 $ (616) $ 17,460
=============================================================================================================
Results of operations before income taxes
Energy services $ 76,607 $ 33,060 $ (12,631)
International contract drilling 41,171 65,043 42,959
Industrial plant maintenance 18,135 19,658 20,683
Other (22,298) (20,251) (29,210)
Writedown of assets held for sale - (6,117) (10,799)
=============================================================================================================
113,615 91,393 11,002
Income tax expense (recovery) 39,282 28,824 (9,616)
-------------------------------------------------------------------------------------------------------------
Results of operations, before non-controlling interest 74,333 62,569 20,618
Non-controlling interest - 2,680 1,752
-------------------------------------------------------------------------------------------------------------
74,333 59,889 18,866
-------------------------------------------------------------------------------------------------------------
Discontinued operations $ 1,409,715 $ 59,273 $ 36,326
=============================================================================================================
The following table provides additional information with respect to
amounts included in the balance sheet as assets and liabilities of
discontinued operations:
76
2005 2004
-------------------------------------------------------------------------------------------------------------
Accounts receivable $ - $ 381,707
Inventory - 106,618
Future income tax asset - 8,711
Other - -
-------------------------------------------------------------------------------------------------------------
$ - $ 497,036
=============================================================================================================
Property, plant and equipment $ - $ 1,047,937
Intangibles - 191,167
Goodwill - 468,586
Future income tax asset - 34,260
-------------------------------------------------------------------------------------------------------------
$ - $ 1,741,950
=============================================================================================================
Accounts payable and accrued liabilities $ - $ 219,940
Income taxes payable - 17,479
Future income tax liability - 7,270
Other - 18
-------------------------------------------------------------------------------------------------------------
$ - $ 244,707
=============================================================================================================
Future income tax liability $ - $ 78,407
Other - 20
-------------------------------------------------------------------------------------------------------------
$ - $ 78,427
=============================================================================================================
The following table provides additional information with respect to
amounts included in the statements of cash flow related to discontinued
operations:
2005 2004 2003
-------------------------------------------------------------------------------------------------------------
Net earnings of discontinued operations $ 1,409,715 $ 59,273 $ 36,326
Items not affecting cash:
Loss (gain) on disposal of discontinued
operations (1,335,382) 616 (17,460)
Depreciation and amortization 95,794 130,163 101,016
Writedown of assets of discontinued operations - 3,293 10,799
Stock-based compensation 10,109 5,647 1,836
Future income taxes (1,735) (17,383) (26,965)
Gain on disposal of investments - - (1,862)
Unrealized foreign exchange loss (gain)
on long-term monetary items 4,829 2,729 (16,391)
Non-controlling interest - 2,680 1,752
-------------------------------------------------------------------------------------------------------------
Funds provided by discontinued operations $ 183,330 $ 187,018 $ 89,051
=============================================================================================================
Components of changes in non-cash working capital balances of
discontinued operations:
2005 2004 2003
-------------------------------------------------------------------------------------------------------------
Accounts receivable $ (60,912) $ (93,743) $ (12,175)
Inventory (23,463) 5,725 (4,370)
Accounts payable and accrued liabilities 1,688 52,861 (15,327)
Income taxes payable (3,623) 8,360 327
-------------------------------------------------------------------------------------------------------------
$ (86,310) $ (26,797) $ (31,545)
=============================================================================================================
22. GUARANTEES:
The Trust has entered into agreements indemnifying certain parties
primarily with respect to tax and specific third party claims associated with
businesses sold by the Trust. Due to the nature of the indemnifications, the
maximum exposure under these agreements cannot be estimated. No amounts have
been recorded for the indemnities as the Trust's obligations under them are
not probable and estimable.
23. RELATED PARTY TRANSACTIONS:
A director of PDC is a partner at a law firm used by PDC and the Trust
for various legal matters. During the year ended December 31, 2005, the Trust
incurred a total of $6.1 million in legal fees. These transactions were
incurred in the normal course of business and were recorded at the exchange
amounts.
77
CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES.
(a) CERTIFICATIONS. See Exhibits 99.1 and 99.2 to this Annual Report on
Form 40-F.
(b) DISCLOSURE CONTROLS AND PROCEDURES. As of the end of the Registrant's
fiscal year ended December 31, 2005, an evaluation of the effectiveness
of the Registrant's "disclosure controls and procedures" (as such term
is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange
Act of 1934, as amended (the "Exchange Act")) was carried out by the
Registrant's principal executive officer and principal financial
officer. Based upon that evaluation, the Registrant's principal
executive officer and principal financial officer have concluded that
as of the end of that fiscal year, the Registrant's disclosure controls
and procedures are effective to ensure that information required to be
disclosed by the Registrant in reports that it files or submits under
the Exchange Act is (i) recorded, processed, summarized and reported
within the time periods specified in Securities and Exchange Commission
rules and forms and (ii) accumulated and communicated to the
Registrant's management, including its principal executive officer and
principal financial officer, to allow timely decisions regarding
required disclosure.
It should be noted that while the Registrant's principal executive
officer and principal financial officer believe that the Registrant's
disclosure controls and procedures provide a reasonable level of
assurance that they are effective, they do not expect that the
Registrant's disclosure controls and procedures or internal control
over financial reporting will prevent all errors and fraud. A control
system, no matter how well conceived or operated, can provide only
reasonable, not absolute, assurance that the objectives of the control
system are met.
(c) CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. During the fiscal
year ended December 31, 2005, there were no changes in the Registrant's
internal control over financial reporting that have materially
affected, or are reasonably likely to materially affect, the
Registrant's internal control over financial reporting.
NOTICES PURSUANT TO REGULATION BTR.
None.
AUDIT COMMITTEE FINANCIAL EXPERT.
Precision Drilling Corporation ("Precision"), administrator of the Registrant,
has determined that Patrick M. Murray and H. Garth Wiggins, members of
Precision's audit committee of the board of directors, both qualify as an
"audit committee financial expert" (as such term is defined in Form 40-F).
Precision's board of directors has determined that each of Mr. Murray and Mr.
Wiggins is "independent" as such term is defined in the New York Stock
Exchange ("NYSE") listing standards.
CODE OF ETHICS.
The Registrant has adopted a "code of ethics" (as that term is defined in Form
40-F), entitled the "Code of Business Conduct and Ethics" (the "Ethics Code"),
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 Ethics Code is available for viewing on the Registrant's website at
www.precisiondrilling.com.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table provides information about the fees billed to the
Registrant and its for professional services rendered by KPMG LLP during
fiscal 2005 and 2004:
(CANADIAN $000) 2005 2004
------------------------------------------------------------------------------
Audit Fees $ 1,806 $ 2,100
Audit-Related Fees $ 252 $ 147
Tax Fees $ 753 $ 456
All Other Fees $ 104 $ 39
------------------------------------------------------------------------------
TOTAL $ 2,915 $ 2,742
==============================================================================
78
AUDIT FEES.
Audit Fees consist of fees for the audit of the Registrant's annual financial
statements and quarterly reviews of interim financial statements.
AUDIT-RELATED FEES.
Audit-related fees consist of fees for assurance and related services that are
reasonably related to the performance of the audit or review of the
Registrant's financial statements and are not reported as Audit Fees such as
services provided in connection with statutory and regulatory filings or
engagements.
In 2005 and 2004, the services provided in this category relate to statutory
and regulatory filings.
TAX FEES.
Tax fees consist of fees for tax compliance services, tax advice and tax
planning. During fiscal 2005 and 2004, the services provided in this category
included assistance and advice in relation to the preparation of corporate
income tax returns for Precision 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
information, consultation regarding compliance with reporting on internal
controls required by the Sarbanes-Oxley Act and due diligence assistance with
respect to a disposition. In 2004, other fees included translation of
financial statements and information and due diligence assistance with respect
to an acquisition.
PRE-APPROVAL POLICIES AND PROCEDURES.
Under the Audit Committee Charter, the Audit Committee is required to approve
the terms of engagement and the compensation to be paid to the external
auditor of the Registrant. In addition, the Audit Committee is required to
review and pre-approve all permitted non-audit services to be provided to the
Registrant or any affiliated entities by the external auditors or any of their
affiliates subject to any de minimus exception allowed by applicable law. The
Audit Committee may delegate to one or more designated members of the Audit
Committee the authority to pre-approve non-audit services. Non-audit services
that have been pre-approved by any such delegate must be presented to the
Audit Committee at its first scheduled meeting following such pre-approval.
The Audit Committee implemented specific procedures regarding the pre-approval
of services to be provided by Precision's external auditor commencing in 2003.
These procedures specify certain prohibited services that are not to be
performed by the external auditor. In addition, these procedures require that
at least annually, prior to the period in which the services are proposed to
be provided, Precision's management will, in conjunction with the Registrant's
external auditor, prepare and submit to the Audit Committee a complete list of
all proposed services to be provided to Precision and the Registrant by the
external auditor. Under the Audit Committee pre-approval procedures, for those
services proposed to be provided by the external auditor that have not been
previously approved by the Audit Committee, the Chairman of the Audit
Committee has the authority to grant pre-approvals of such services. The
decision to pre-approve a service covered under this procedure is required to
be presented to the full Audit Committee at the next scheduled meeting. At
each of the Audit Committee's regular meetings, the Audit Committee is to be
provided with an update as to the status of services previously pre-approved.
Pursuant to these procedures, since their implementation in 2003, 100% of each
of the services provided by the Registrant's external auditor relating to the
fees reported as audit, audit-related, tax and all other fees were
pre-approved by the Audit Committee or its delegate.
OFF-BALANCE SHEET ARRANGEMENTS.
The Registrant has no off-balance sheet arrangements.
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS.
The required disclosure is included on page 66 of the Registrant's
Management's Discussion and Analysis of Financial Condition and Results of
Operations for the fiscal year ended December 31, 2005, included in this
Annual Report on Form 40-F.
79
IDENTIFICATION OF THE AUDIT COMMITTEE.
Precision Drilling Corporation ("Precision"), administrator to the Registrant,
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 NEW YORK STOCK EXCHANGE.
LEAD DIRECTOR AT MEETINGS OF NON-MANAGEMENT DIRECTORS.
Precision schedules regular executive sessions in which Precision's
"non-management directors" (as that term is defined in the rules of the NYSE)
meet without management participation. The board of directors of Precision
appoint a lead director (the "Lead Director") from the independent and
unrelated directors present at each regularly held in-camera session of the
board of directors. The Lead Director is responsible for developing the agenda
for, and presiding over, in-camera sessions and acting as principal liaison
between the non-management directors and the Chief Executive Officer on
matters dealt with during the in-camera session. Each of Precision's
non-management directors is "unrelated" as such term is used in the rules of
the NYSE.
COMMUNICATION WITH NON-MANAGEMENT DIRECTORS.
The Registrant's unit holders may send communications to Precision's
non-management directors by writing to the Lead 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 Lead Director for appropriate action. The status of all
outstanding concerns addressed to the Lead Director will be reported to the
board of directors as appropriate.
CORPORATE GOVERNANCE GUIDELINES.
According to NYSE Rule 303A.09, a listed company must adopt and disclose a set
of corporate governance guidelines with respect to specified topics. Such
guidelines are required to be posted on the listed company's website. The
Registrant and Precision have adopted the required guidelines and have posted
them on the Registrant's website at www.precisiondrilling.com.
BOARD COMMITTEE MANDATES.
The Registrant's board of trustees mandate and Precision's board of directors'
mandate, audit committee charter and terms of reference, compensation
committee mandate and corporate governance and nominating committee mandate
are each available for viewing on the Registrant's website at
www.precisiondrilling.com, and are available in print to any unit holder who
requests them. Requests for copies of these documents should be made by
contacting: Darren Ruhr, Vice President Corporate Services and Corporate
Secretary, 4200, 150-6th Avenue S.W., Calgary, Alberta, Canada T2P 3Y7.
80
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 Securities and
Exchange 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, on March 31, 2006.
PRECISION DRILLING CORPORATION, AS AGENT FOR
AND ON BEHALF OF PRECISION DRILLING TRUST
By: /s/ Hank B. Swartout
---------------------------------
Name: Hank B. Swartout
Title: Chairman and Chief Executive Officer
81
EXHIBIT INDEX
Exhibit Description
------- -----------
99.1 Certification of Chief Executive Officer pursuant to Rule
13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
99.2 Certification of Chief Financial Officer pursuant to Rule
13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
99.3 Certification of Chief Executive 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