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, 2003
Commission file number 1-14534
PRECISION DRILLING CORPORATION
(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
(Address and Telephone Number of Registrant's Principal Executive Offices)
CT CORPORATION SYSTEM, 811 DALLAS AVENUE, HOUSTON, TEXAS 77022
(713) 658-9486
(Name, Address (Including Zip Code) and Telephone Number
(Including Area Code) of Agent For Service in the United States)
Securities registered or to be registered pursuant to Section
12(b) of the Act.
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Common Shares 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: 54,845,678
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 [_]
1
The Annual Report on Form 40-F shall be incorporated by reference into each of
the registrant's Registration Statements on Form S-8 under the Securities Act of
1933: File Nos. 333-105648, 333-14284, 333-13432 and 333-11982.
2
PRINCIPAL DOCUMENTS
The following documents have been filed as part of this Annual Report on Form
40-F, beginning on the following page:
Page 4 (a) Annual Information Form for the fiscal year ended
December 31, 2003;
Page 20 (b) Management's Discussion and Analysis of Financial
Condition and Results of Operations for the fiscal
year ended December 31, 2003; and
Page 39 (c) Consolidated Financial Statements for the fiscal year
ended December 31, 2003 (NOTE 15 TO THE CONSOLIDATED
FINANCIAL STATEMENTS RELATES TO UNITED STATES
GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (U.S.
GAAP)).
3
2003 PRECISION DRILLING CORPORATION RENEWAL ANNUAL INFORMATION FORM
DATED AS OF APRIL 26, 2004
Cautionary Statement on Forward-Looking Information Page 2
Corporate Structure of Precision Drilling Corporation Page 3
INCORPORATION INFORMATION Page 3
INTERCORPORATE RELATIONSHIPS Page 3
General Development of the Business Page 3
THREE YEAR HISTORY Page 3
SIGNIFICANT ACQUISITIONS AND SIGNIFICANT DISPOSITIONS Page 5
TRENDS Page 6
Description of the Business of Precision Page 8
DESCRIPTION OF BUSINESS SEGMENTS Page 8
CONTRACT DRILLING Page 9
CANADIAN DRILLING Page 10
INTERNATIONAL DRILLING Page 13
CANADIAN WELL SERVICING Page 14
TECHNOLOGY SERVICES Page 17
WIRELINE Page 17
DIRECTIONAL DRILLING Page 18
SEPARATION SERVICES Page 20
OTHER Page 21
RENTAL AND PRODUCTION Page 21
RENTAL SERVICES Page 22
PRODUCTION SERVICES Page 22
EMPLOYEES Page 23
LEGAL PROCEEDINGS Page 23
Selected Consolidated Financial Information Page 23
SUMMARY OF OPERATING RESULTS Page 23
DIVIDENDS Page 24
Management's Discussion and Analysis of Financial Condition
and Results of Operations Page 24
Market for Securities Page 24
Directors and Officers Page 25
Additional Information Page 26
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES Page 26
REQUEST FOR ADDITIONAL INFORMATION Page 27
4
CAUTIONARY STATEMENT ON FORWARD-LOOKING INFORMATION
Certain statements contained in this Renewal Annual Information Form (AIF)
and under the heading "Management's Discussion and Analysis" on pages 43 to 75
of the 2003 Annual Report and in other sections of such Annual Report, including
statements which may contain words such as "anticipate", "could", "expect",
"seek", "may", "intend", "will", "believe" and similar expressions, statements
that are based on current expectations and estimates about the markets in which
the Corporation operates and statements of the Corporation's belief, intentions
and expectations about development, results and events which will or may occur
in the future constitute "forward-looking statements" within the meaning of the
"safe harbor" provision of the United States Private Securities Litigation
Reform Act of 1995, and are based on certain assumptions and analysis made by
the Corporation derived from its experience and perceptions. Forward-looking
statements in this AIF include, but are not limited to, statements with respect
to future capital expenditures, including the amount and nature thereof; oil and
gas prices and demand; other development trends of the oil and gas industry;
business strategy; expansion and growth of the Corporation's business and
operations, including the Corporation's market share and position in the
domestic and international drilling and oilfield service markets; and other such
matters. In addition, other written or oral statements which constitute
forward-looking statements may be made from time to time by and on behalf of the
Corporation. Such forward-looking statements are subject to important risks,
uncertainties, and assumptions which are difficult to predict which affect the
Corporation's operations, including: the impact of general economic conditions
in Canada, the U.S. and in other countries in which the Corporation currently
does business; industry conditions, including the adoption of new environmental
and other laws and regulations and changes in how they are interpreted and
enforced; volatility of oil and gas prices; oil and gas product supply and
demand; risks inherent in the Corporation's ability to generate sufficient cash
flow from operations to meet its current and future obligations; increased
competition; the lack of availability of qualified personnel or management;
labor unrest; fluctuation in foreign exchange or interest rates; stock market
volatility; opportunities available to or pursued by the Corporation and other
factors, many of which are beyond the control of the Corporation. The
Corporation's actual results, performance or achievements could differ
materially from those expressed in, or implied by, these forward-looking
statements and, accordingly, no assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or occur, or if any
of them do so, what benefits, including the amount of proceeds, the Corporation
will derive therefrom. The Corporation disclaims any intention or obligation to
update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise.
CORPORATE STRUCTURE OF PRECISION DRILLING CORPORATION
INCORPORATION INFORMATION
Precision Drilling Corporation (the Corporation or Precision) was
originally incorporated on March 25, 1985, amalgamated with two wholly owned
subsidiary companies on January 1, 2000; on January 1, 2002 was amalgamated with
one wholly owned subsidiary and on January 1, 2004 was amalgamated with one
wholly owned subsidiary, all pursuant to Articles of Amalgamation and other
provisions of the Business Corporations Act of Alberta. The Corporation
maintains its head office and principal place of business at 4200, 150 - 6th
Avenue S.W., Calgary, Alberta T2P 3Y7. The telephone number is (403) 716-4500,
the facsimile number is (403) 264-0251 and the website address is
www.precisiondrilling.com.
INTERCORPORATE RELATIONSHIPS
The following table sets forth the names of the Material Subsidiaries
(which includes major Limited Partnerships) of Precision, the percentage of
shares (or interest) owned by it and the jurisdiction of incorporation or
continuance of each such subsidiary (or partnership) as of December 31, 2003:
Jurisdiction of
Name of Subsidiary or Partnership Percentage Owned Incorporation or Continuance
------------------------------------------------------------------------------------------------------------
Precision Limited Partnership 100% Alberta
Precision Drilling Technology Services Group Inc. 100% Alberta
CEDA International Corporation 100% Alberta
PD International Services Inc. 100% Alberta
PD Holdings Mexicana, S. de R.L. de C.V. 100% Mexico
PD Holdings (USA), L.P. 100%
Delaware
Computalog Holdings, Inc. 100% Nevada
Precision Drilling Holdings, Inc. 100%
Delaware
------------------------------------------------------------------------------------------------------------
GENERAL DEVELOPMENT OF THE BUSINESS
THREE YEAR HISTORY
Precision provides oilfield and industrial services to customers in Canada,
the U.S., Mexico and internationally. For more than the last three years, the
Corporation has been the leading provider, in Canada, of land drilling services
to oil and gas exploration and production companies, based on the number of
wells and metres drilled. Additionally, the Corporation provided the following
during 2003: well service rigs and hydraulic well assist snubbing units;
procurement and distribution of oilfield supplies; camp and catering services;
manufacture, sale and repair of drilling equipment; open hole logging, cased
hole logging and completion services, slickline services, directional drilling
services; measurement-while-drilling (MWD) and logging-while-drilling (LWD)
services; the manufacture, rental and sale of polycrystalline diamond compact
(PDC) drill bits; controlled pressure drilling services (CPD) and well testing
services; the design, manufacture, rental and sale of downhole completion
products; pressure pumping and coiled tubing services; rental of mobile
combination office and industrial housing; rental of surface oilfield equipment
for drilling, completion and production activities; and also provided industrial
maintenance and turnaround services, including specialized equipment and labour
services, to downstream oil and gas, petrochemical and other process industry
customers.
During the fourth quarter 2003, two product lines within the Technology
Services segment, namely pressure pumping services and the rental and sale of
downhole completion products, were identified as being not core to the segment's
ongoing growth initiatives. As a result a program was initiated to dispose of
these businesses. Results of operations of these businesses were classified as
results of discontinued operations at December 31, 2003.
Effective February 12, 2004, Precision sold the operating assets of Fleet
Cementers, Inc. (Fleet), the wholly owned subsidiary that carried on the
pressure pumping business. Effective as of March 29, 2004, an agreement was
entered into to sell the assets of Polar Completions, representing the rental
and sale of downhole completion products business of the Corporation.
The Corporation has grown primarily through a series of acquisitions of
related businesses as well as reinvestment in its core business to become the
largest Canadian integrated oilfield and industrial service contractor. Over the
past three fiscal years, the Corporation has reinvested substantially all of its
cash flow from operations to grow its service and product offerings. In the year
ended December 31, 2003, 18% of the Corporation's revenue was generated by
operations outside of Canada and the U.S.
Since January 1, 2001, the Corporation has made a number of acquisitions
and dispositions as follows:
In January 2001, the Corporation acquired 100% of the shares of BecField
Drilling Services Ltd. (BecField). BecField, with established operations in
Europe and the Middle East, provided directional drilling and MWD services
through its technical field and support personnel to both onshore and offshore
oil and gas companies. It also owned an interest in Smart Stabilizer Systems
Limited which was established to develop a new generation rotary steerable
device used to steer a drill bit down hole.
Also in January 2001, Precision Drilling Technology Services Group Inc.
(formerly Computalog Ltd.), acquired the shares it did not own of Computalog
Europe GmbH. Thereafter, Computalog Europe GmbH and BecField Drilling Services
GmbH merged and subsequently became Precision Drilling Technology Services GmbH.
Precision Drilling Technology Services GmbH, a 100% owned subsidiary, supplies
wireline, directional drilling, MWD, LWD, CPD, well testing services and PDC
drilling bits throughout Europe.
In July 2001, Computalog U.S.A., Inc. acquired all of the issued and
outstanding shares of Premium Pump Services, Inc. (Premium). Premium provided
pressure pumping services, including cementing, fracturing and other stimulation
services in Texas. In December 2001, Premium was merged with Fleet, with the
operations of both entities being carried on under Fleet.
In December 2001, Precision's wholly owned subsidiary, BecField, acquired
the remaining outstanding shares it did not own of Smart Stabilizer Systems
Limited and has since taken steps to complete the commercialization of the
rotary steerable device.
On March 6, 2003 (but effective January 1, 2003), Precision Drilling
Corporation sold 100% of the shares of Energy Industries Inc.
In May 2003 a wholly owned subsidiary of Precision sold its 50% interest in
Equipment Rentals General Partnership and Oil Drilling & Exploration (Argentina)
SA., both of which pertained to two rigs in Argentina.
On September 30, 2003, a wholly owned subsidiary of Precision sold its 49%
interest in Computalog SA (Argentina) to an unrelated third party.
Since January 1, 2001, the Corporation has undertaken a number of internal
reorganization transactions as follows:
In August 2001, Precision Drilling Limited Partnership was dissolved into
Precision Limited Partnership (PLP), with the drilling operations continuing to
operate as Precision Drilling (PD) and the well servicing operations
continuing to operate as Precision Well Servicing (PWS), and the hydraulic rig
assist snubbing units continuing to operate as Live Well Service (Live), all as
divisions of PLP.
In November 2001, the Four Lakes Precision Drilling Limited Partnership
(FLPD) was formed as a 50% limited partnership with Alberta Treaty Six First
Nations, to operate a jointly owned drilling rig, with a 100% owned subsidiary
of the Corporation as General Partner. FLPD has engaged PD to operate the rig
through an Operating Agreement.
In December 2001, Computalog Ltd. changed its name to Precision Drilling
Technology Services Group Inc. (PDTSG).
On January 1, 2002, Precision was amalgamated with a wholly owned
subsidiary to form and continue as Precision Drilling Corporation.
On January 1, 2003, Precision Drilling Technology Services Group Inc.,
Plains Perforating Ltd., Polar Completions Engineering Inc. and Northland Energy
Corporation were amalgamated to form "new" Precision Drilling Technology
Services Group Inc.
On April 8, 2003 Montero Oilfield Services Ltd. changed its name to
"Precision Rentals Ltd."
On December 31, 2003, PD Holdings (USA), Inc. was converted from a Delaware
Corporation to a Delaware limited partnership, and now operates under the name
"PD Holdings (USA), L.P."
On January 1, 2004, Precision was amalgamated with a wholly owned
subsidiary to continue as Precision Drilling Corporation.
SIGNIFICANT ACQUISITIONS AND SIGNIFICANT DISPOSITIONS
There were no significant acquisitions or dispositions during 2003.
TRENDS
As illustrated above, crude oil and natural gas prices have historically
been quite volatile. Oil prices, which during 2003 averaged US$31.10 per barrel
for West Texas Intermediate (WTI), are the result of political instability in
some OPEC member nations (Venezuela, Iraq and Nigeria) and from a generally
improving world economy with energy demand growth particularly strong in China
and Southeast Asia. Another important factor in the crude oil pricing equation,
and one that has seen a fundamental change from past pricing scenarios, is the
value of the U.S. dollar. Since oil prices are denominated in U.S. dollars
around the world, the devaluation of the U.S. dollar that has occurred over the
past year has implications for both the seller and buyer of the commodity. Oil
producing nations, with OPEC members taking the lead in controlling supplies and
prices, are motivated to see an increase in the U.S. dollar price of oil to
maintain their purchasing power in other currencies such as the Euro. From a
buyer's perspective, the devaluation of the U.S. dollar has made oil a cheaper
commodity for those who spend Euros and Japanese Yen, for instance, thus
supporting the increased demand.
The supply and demand fundamentals that have brought commodity prices to
today's relatively high levels are not expected to change rapidly. Energy price
prognosticators have historically focused on the supply side of the equation
where geopolitical events can have a large impact on short-term supply and where
consensus was generally that there was an abundant supply to fill long-term
requirements. This view is now starting to be questioned by some pricing
analysts. The surplus crude oil production capacity of the Middle East is being
examined with suggestions that it is not as high as once thought. Similarly, the
ability to rapidly increase production of the vast crude oil reserves in the
former Soviet Union is being slowed by the recognition of the large amount of
infrastructure investment required to bring these reserves to market. Recent
world events have also brought security of supply issues to the top of the
energy agenda for many countries.
North American natural gas prices are also being supported by strong
fundamentals. Demand has been increasing with recent economic growth while
supply from relatively mature producing basins is starting to decline. The near
record gas drilling activity in 2003 served only to slow the decline in
production reserves. High oil prices also served to support natural gas prices
as the economic benefit of switching between the two fuels is minimal. The
importing of liquefied natural gas into the North American market, once thought
to be the competitive product that would cause gas prices to decline, is now
viewed by many industry analysts as a requirement to fill the gap between demand
and conventional production capabilities. It is not anticipated that the price
of natural gas will experience sustained downward pressure from the supply side
of the pricing equation any time soon.
Many analysts are now looking at the demand elements of energy pricing
economics. Commodity prices have risen over the last number of years in an
environment where the major economies of the world were generally in a period of
slow growth. This is changing as growth rates in the major industrialized
countries are beginning to recover. Of particular importance to the outlook for
the demand for energy is the emergence of countries such as China where economic
expansion is bringing new found purchasing power to a very large population. On
a per capita basis, these
populations use energy at a fraction of the rate of other industrialized
nations. This should change as new products, such as automobiles and electric
appliances, are introduced to these markets which in turn should drive
exponential growth in energy demand.
DESCRIPTION OF THE BUSINESS OF PRECISION
DESCRIPTION OF BUSINESS SEGMENTS
Precision's continuing operations are managed in three segments consisting
of Contract Drilling, Technology Services and Rental and Production. Contract
Drilling includes drilling rigs, service rigs, hydraulic well assist snubbing
units, camp and catering services, procurement and distribution of oilfield
supplies, and manufacture, sale and repair of drilling equipment. Technology
Services includes wireline logging services, slickline services, directional
drilling, measurement-while-drilling/logging-while-drilling (MWD/LWD) services,
controlled pressure drilling (CPD), well testing, and the design and manufacture
of PDC drill bits. Rental and Production includes oilfield equipment rental
services and industrial maintenance.
Effective February 12, 2004, Precision sold the operating assets of Fleet,
the wholly owned subsidiary that carried on the pumping services for cementing,
fracturing and well stimulation, which business was carried on primarily in
Texas. Precision has initiated the process of disposing of Polar Completions
which carries on the design, manufacture, rental and sale of downhole completion
and production equipment business. A definitive agreement dated March 29, 2004
was entered into to sell the Polar Completions assets, and it is anticipated
that this transaction will close in early May 2004. Results of operations of
these businesses have been classified as results from discontinued operations.
The Corporation's revenue by industry and geographic segments are
illustrated in thousands in the following table:
YEARS ENDED DECEMBER 31, 2003 2002 2001
--------------------------------------------------------------------------------
Contract Drilling $ 992,824 $ 770,147 $1,004,265
Technology Services 714,385 603,088 614,152
Rental and Production 210,724 192,840 194,567
Corporate and other -- 1,431 2,224
--------------------------------------------------------------------------------
Total Revenue $1,917,933 $1,567,506 $1,815,208
--------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31, 2003 2002
2001
--------------------------------------------------------------------------------
Canada $1,349,565 $1,022,489 $1,320,989
International 568,368 545,017 494,219
--------------------------------------------------------------------------------
Total $1,917,933 $1,567,506 $1,815,208
--------------------------------------------------------------------------------
The Corporation 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 the prime drivers for pricing and
profitability within the energy services industry. Generally, when commodity
prices are relatively high, demand for the Corporation's services is 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. Natural gas is most economically transported in its
gaseous state via pipeline. Therefore, 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. As illustrated earlier, crude oil and natural gas prices are
quite volatile, which accounts for much of the cyclical nature of the energy
service business. The energy service business cycles are muted somewhat in
non-North American markets where projects tend to be larger and more long term
thus less susceptible to short term commodity price fluctuations.
The Corporation derived 70% of its revenue from the Canadian market in
2003. Energy service activity in Canada is subject to seasonal fluctuation. 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
winter's frost comes out of the ground rendering many secondary roads incapable
of supporting the weight of heavy equipment until they have thoroughly dried
out. The duration of "spring breakup" has a direct impact on the Corporation's
activity levels. In addition, many exploration and production areas in northern
Canada are accessible only in winter months when the ground is frozen hard
enough to support equipment. The timing of freeze up and spring breakup affects
the ability to move equipment in and out of these areas. Equally, wet weather
can also defer commencement of drilling or servicing operations on any given day
or well location.
CONTRACT DRILLING
This segment consists of three main categories of operations; Canadian
Drilling, (which includes contract drilling support), International Drilling and
Canadian Well Servicing, (which includes Live's snubbing operations).
Revenue generated by these operations is as follows:
2003 2002 2001
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Years ended December 31, (In thousands) REVENUE % OF Revenue % of Revenue % of
-------------------------------------------------------------------------------------------------------------------------
Canadian Drilling $ 654,572 66% $ 474,051 61% $ 661,659 66%
International Drilling 114,131 11% 105,108 14% 113,404 11%
Canadian Well Servicing 224,121 23% 190,988 25% 229,202 23%
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$ 992,824 100% $ 770,147 100% $ 1,004,265 100%
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CANADIAN DRILLING
The Corporation owns and operates the largest fleet of land drilling rigs
in Canada, through Precision Drilling, a division of PLP, with 225 actively
marketed rigs located throughout the Western Canada Sedimentary Basin (WCSB),
accounting for approximately 33% of the actively marketed land drilling rigs in
Canada.
Additionally, the operations of Contract Drilling may extend into the Rocky
Mountain area of the U.S. when demand for drilling rigs is high and economic
profit margin targets are attainable. Strategically, the Corporation's interest
within this market is to serve the needs and requests of existing customers. To
this end, the rig fleet is mobile and responsive to opportunity. Based out of
Casper, Wyoming, the Corporation's U.S. drilling business, operates through the
legal entity Precision Drilling Oilfield Services, Inc., and as at December 31,
2003 it had one racked drilling rig and no active operations after running as
many as five rigs during 2002. Subsequent to the year ended December 31, 2003,
the lone remaining rig was sold.
Precision's land drilling rigs have varying configurations and capabilities
which allows it to provide services in virtually all areas of drilling activity
in the WCSB. Precision's rigs have drilling depth capacities of up to 7,600
metres. All of Precision's Canadian drilling rigs are winterized, allowing for
operations in the harsh weather conditions faced in the Canadian drilling
environment. Traditional 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 the
rig drills, the coiled tubing is unwound and when the bit returns to surface the
coiled tubing is rewound onto the reel. Except for connecting the bottom hole
assembly, which usually includes the drill bit and a drilling fluid powered
drilling motor, which provides the rotation for drilling, no other connections
are necessary. As a result coil rigs can drill very fast at shallower depths.
These rigs are well suited for shallow vertical drilling. They are compact, have
a small footprint and can be made ready to move to new locations more quickly
than conventional rigs.
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 which is usually carried out
in western Canada's foothills and Rocky Mountain regions. The deeper rig fleet
includes specialized rigs for deep sour gas well drilling and Arctic class rigs
that, although currently operating in Alberta and British Columbia, are equipped
to operate in very cold temperatures. The remaining rigs in Precision's fleet
are Super Single rigs, which garner an industry market share of 83% within their
rig class. The Super Single rigs are manufactured by Precision and are equipped
with top-drive drilling systems, range 3 drill pipe and automated pipe handling
and are capable of slant drilling.
Slant drilling involves tilting a rig mast from vertical and is primarily
used to drill multiple directional wells from one location. In certain
instances, Super Single rigs allow for drilling to be carried out on a more cost
effective basis than using conventional drilling techniques. Drilling multiple
wells from one location improves the economics of developing shallow heavy oil
reserves in the WCSB. Additionally the same technique also allows for
exploitation of reserves located in environmentally sensitive areas or
inaccessible locations and eliminates the costs of building access roads for
multiple drilling locations. Precision believes Super Single drilling rigs offer
the potential for significant future revenue growth. Precision's Super Single
drilling rigs have been further developed to meet operational needs in the
development of oil sands production in northern Alberta.
Precision has taken a lead role in drilling numerous steam assisted gravity
drainage (SAGD) projects that involve a centralized mud system and other
innovative rig design features. SAGD is used extensively in the production of
heavy oil reserves.
A total of 41 of Precision's drilling rigs are electrically powered and the
remaining rigs mechanically powered. Diesel-electric powered rigs provide
precise rotational control and are considered more power efficient than
mechanical rigs. A diesel-electric rig is well suited for horizontal and
directional drilling. Many of Precision's mechanically powered rigs are also
capable of horizontal and directional drilling by equipping the rigs with
additional equipment which Precision has readily available. Precision
continually seeks to upgrade and modify its rig fleet to
maximize performance. Precision works hard to remain abreast of, and in many
cases, leads advances in specialized drilling techniques and technology to
maximize power output and minimize environmental impact.
To facilitate customer requirements on moderate to deep wells, PD 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. A top drive is suspended in the mast of the drilling rig and is powered
by a hydraulic or electric motor. All Super Single drilling rigs are equipped
with a permanently mounted top drive as part of the rig inventory.
The following table lists the drilling depth capability of Precision's
actively marketed drilling rigs and the total Canadian land drilling industry's
rigs in the WCSB as at December 31, 2003. In addition, the capabilities of the
segment's rigs operating outside Canada are listed.
CANADA INTERNATIONAL
----------------------------------------------------------------------------------------------------------------------------------
PD Market
Drilling PD Canada Industry (2) Share (3) PD %
Type of Drilling Rig Depth Capability # of Rigs % of Fleet # of Rigs % of Fleet by Rig # of Rigs of Fleet
----------------------------------------------------------------------------------------------------------------------------------
Single 1,200m 17 8 93 14 18% 0 0
Super Single(R)(1) 2,500m 15 7 18 2 83% 4 21
Double 3,000m 96 42 322 48 30% 7 37
Light triple 3,600m 47 21 119 17 40% 6 32
Heavy triple 7,600m 39 17 99 15 39% 2 10
Coiled tubing 1,300m 11 5 24 4 46% -- --
----------------------------------------------------------------------------------------------------------------------------------
Total 225 100 675 100 33% 19 100
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NOTES:
(1) SUPER SINGLE(R) EXCLUDES RIGS THAT CANNOT DRILL SLANT, OR DO NOT HAVE
AUTOMATED PIPE HANDLING SYSTEMS, OR DO NOT HAVE A SELF CONTAINED TOP DRIVE,
OR CAN NOT RUN RANGE 3 DRILL PIPE/CASING.
(2) SOURCE: CANADIAN ASSOCIATION OF OILWELL DRILLING CONTRACTORS (CAODC) AS OF
DECEMBER 31, 2003 FOR TOTAL RIG COUNT PER CONTRACTOR SUMMARY SHEET ADJUSTED
BY PRECISION TO INCLUDE NON REPORTING CONTRACTORS. PRECISION HAS ALLOCATED
EACH COMPANY'S RIG FLEET BY CATEGORY - THIS IS NOT TRACKED BY CAODC.
SURFACE HOLE RIGS AND WATER WELL RIGS ARE NOT INCLUDED ABOVE.
(3) MARKET SHARE MEANS PRECISION'S RIGS AS A PERCENTAGE OF THE INDUSTRY'S RIGS.
Precision has consistently been the most active land drilling contractor in
Canada as measured by metres and wells drilled. Since 1997, Precision has
sustained a market share in those categories of greater than 30%. During 2003,
Precision achieved a utilization rate of 52.0% for its drilling rigs compared to
the average industry utilization rate in Canada of 53.1%. Precision's strategy
with respect to its drilling operations emphasizes achieving an industry
equivalent level of utilization for its equipment, thereby enabling Precision to
maintain a stable workforce and a high level of equipment maintenance. In
periods of low equipment utilization, Precision may under-perform industry
utilization in order to preserve reasonable profit margins in certain rig
markets. Precision believes that its efficiently configured and well maintained
drilling rigs should allow it to retain its leading role in the Canadian land
drilling market.
For calendar year 2003, Precision drilled 8,451 exploration and development
wells, accounting for 40.8% of industry wells in western Canada.
The following table lists the drilling rig utilization rates and certain
other drilling statistics for Precision in Canada and the total Canadian land
drilling industry in the WCSB for the years indicated in this table:
Drilling Rig Metres Drilled (000s) Wells Drilled (2)
Utilization Rates (%)(1) % of (1) % of (1)
PD Industry PD Industry Industry PD Industry Industry
---------------------------------------------------------------------------------------------------------------------
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
2000 52.5 55.2 6,771 18,242 37.1 6,143 16,565 37.1
1999 37.4 39.8 4,613 13,018 35.4 3,803 11,816 32.2
---------------------------------------------------------------------------------------------------------------------
NOTES
(1) INDUSTRY NUMBERS EXCLUDE DRILLING RIGS NOT REGISTERED WITH THE CANADIAN
ASSOCIATION OF OILWELL DRILLING CONTRACTORS (CAODC) AND NON-REPORTING CAODC
MEMBER CONTRACTORS.
(2) THE NUMBER OF WELLS DRILLED IS REPORTED ON A RIG RELEASE BASIS.
Oil and gas well drilling contracts are carried out on either a daywork,
meterage or turnkey basis. Under daywork contracts, Precision charges the
customer a fixed charge 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
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 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 except for
the contract in the Burgos Basin of Mexico, which is being carried out on a
turnkey basis for each well drilled.
In conjunction with its customers, PD is working to involve Canada's First
Nations aboriginal people in the delivery of contract drilling services.
Precision's involvement with First Nations communities is directed towards local
employment to meet oilfield service manpower needs and to foster the economic
participation of aboriginals in commerce that is taking place in and around
their traditional lands. The economic arrangements include joint ownership of
one drilling rig through the Four Lakes Precision Drilling Limited Partnership
and sponsorship based on rig activity to support community development in remote
areas.
The Corporation owns three subsidiaries which provide support services to
its contract drilling operations being Columbia Oilfield Supply Ltd., LRG
Catering Ltd. and Rostel Industries Ltd.
Columbia Oilfield Supply Ltd. (Columbia) became a wholly owned subsidiary
of Precision in 1997 and has been in business since 1977 as a general supply
store to the oilfield service industry with drilling contractors as their main
customers. Columbia's prime focus is to facilitate the consumable requirements
of PD, PWS and the other subsidiaries of the Corporation. Increasingly, Columbia
is being relied upon to procure and distribute specialty supply requirements for
international contract drilling rig operations.
LRG Catering Ltd. (LRG) is a camp and catering company providing food and
accommodations to the Canadian oil and gas drilling industry and became a wholly
owned subsidiary of Precision in 1993. A typical drilling camp consists of a
five or six-unit structure that can accommodate 20 field employees and feed up
to 50 workers daily. Established in 1976, LRG has grown significantly over the
past six years. Effective February 1, 2003 LRG acquired all of the operating
assets of MacKenzie Caterers (1984) Ltd. namely, 17 camps complete with
ancillary assets. LRG also added a new six unit electric camp in February 2003.
As a result, the fleet grew by an additional 18 camps during 2003 and operated
88 quality camp facilities as at December 31, 2003. Most of LRG's business is in
support of Precision's drilling rig operations.
Rostel Industries Ltd. (Rostel) was established in 1976 as a machining and
fabricating shop and became a wholly owned subsidiary of Precision in 1996.
Rostel provides drilling and service rig contractors in southern Alberta with
complete equipment manufacture and repair services. The manufacture of drilling
and service rig components is a core business for Rostel. It also repairs and
certifies, as required, rig components such as crowns, handling tools, traveling
blocks and blowout preventers. This business uniquely positions the Corporation
as the only Canadian drilling contractor with in-house rig building capability.
INTERNATIONAL DRILLING
The international drilling operations of Precision, which are carried out
through various international subsidiaries, are focused on expansion into
countries where drilling opportunities fit the Corporation's niche capabilities,
and where it can attain a strategic position in the near to medium term.
In 2003, Precision Drilling International continued its focus on delivering
performance drilling as a key member of Precision's integrated services package
providing turnkey drilling services in the Burgos region of Mexico. In 2003 a
total of 176 wells were drilled by Precision in the Burgos region. In June 2003,
Precision received a contract extension covering the provision of three
additional drilling rigs bringing the total rig count in Mexico to 10, and
adding approximately 186 wells to the existing contract.
In South America, international drilling continued to provide specialty
drilling services to multinational oil companies, many of whom have strategic
alliances with national oil companies. Five of the Corporation's drilling rigs
were operational on contracts of lengths varying from one to five years. In
April 2003, the Corporation's 50% interest in two additional drilling rigs
located in South America and operated by a third party were sold.
In the Middle East, the Corporation owns two drilling rigs, one of which is
operated by a third party and is under contract until February 2006, and the
second rig commenced drilling in November 2003.
In the Asia/Pacific region a Super Single rig was contracted continuously
throughout 2003 and among its achievements drilled the first slant well in the
region from a man-made island. Additionally, the Corporation was awarded a
contract to construct and operate its first offshore platform mounted rig for
the same operator, which commenced drilling in April 2004.
On April 1, 2004, the Corporation entered into an agreement with
GlobalSantaFe Corporation which contemplates the acquisition by the Corporation
of 31 land based drilling rigs located in the Middle East and Venezuela for a
purchase price of US$316,500,000. It is anticipated that the transaction should
close near the end of May 2004.
CANADIAN WELL SERVICING
For the past three years, the Corporation has operated the largest fleet of
services rigs in Canada. As a result of the acquisition of 18 service rigs
through Plains in August, 2000, and a further 164 service rigs in October 2000,
through CenAlta, the Corporation now owns the largest well servicing fleet in
Canada.
The Corporation has a diverse workover rig fleet capable of performing
service and completion jobs in any depth range, including heavy oil wells. It is
also a leader in horizontal re-entry drilling. The characteristics of the fleet,
which currently operates only in the WCSB, is illustrated in the following
table:
2003 2002 2001
--------------------------------------------------------------------------------------------------
# OF % OF # of % of # of % of
Type of Service Rig RIGS FLEET Rigs Fleet Rigs Fleet
--------------------------------------------------------------------------------------------------
Freestanding mobile single 75 31 50 21 23 9
Single 1 -- 1 -- 4 2
Mobile single 29 12 55 23 91 35
Double 57 24 58 24 60 23
Freestanding mobile double 6 3 6 2 5 2
Mobile double 46 19 45 19 48 19
Heavy double 7 3 7 3 9 4
Freestanding heavy double 2 1 2 1 -- --
Slant 16 7 16 7 16 6
Swab -- -- -- -- 1 --
--------------------------------------------------------------------------------------------------
TOTAL 239 100 240 100 257 100
--------------------------------------------------------------------------------------------------
During 2003, the PWS rig fleet generated 439,519 operating hours for a
utilization rate of 50% based on 239 available rigs. The calculation assumes
that available hours per year is 3,650 for each rig.
# of Rigs # of Operating Hours Rig Utilization %
--------------------------------------------------------------------------------
2003 239 439,519 50
2002 240 392,210 45
2001 257 492,480 53
--------------------------------------------------------------------------------
During 2003, PWS maintained an industry market share of 27% based on an
average registered CAODC industry service rig fleet of 887 in western Canada.
The PWS rig fleet has been rationalized over the past two years resulting in the
retirement of 18 rigs that were no longer marketable due to equipment condition
and/or capacity. The current fleet is also being upgraded through initiatives
that include freestanding conversion, new five ton transporters and, new pump
trucks, engines, doghouses and mud pumps. As at December 31, 2003 PWS had 83
freestanding service rigs representing 35% of its service rig fleet. This is an
increase of 25 rigs and 11 percentage points over 2002. A freestanding rig is
more efficient to set up, minimizes surface disturbance and, as there is no need
for mooring, the possibility of striking underground pipelines is reduced.
Well service rigs are typically operated by a crew of four or five workers
and include additional equipment such as circulating pumps, tanks, blowout
preventers and tools. These rigs are mobile 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 in which the
service rig operates, the type of rig and equipment being used, and the amount
of additional services or equipment required. Seven of PWS's well service rigs
are specifically configured for re-entry drilling and have 24-hour operational
capabilities. Service rigs are typically used during the completion phase of a
well, instead of larger, more expensive drilling rigs, to reduce the cost of
completing the well. The demand for well completion services is directly related
to the level of drilling activity in a region, whereas the demand for other well
servicing activities is based upon the total number of active wells, their age
and their production characteristics otherwise referred to as "workover"
service. Consequently, demand for completion services is generally less stable
than demand for workover well servicing activities. Completion services account
for approximately 33% of PWS's well servicing activity in 2003.
Completion services prepare a newly drilled well for production. Completion
services 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
in stimulating 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.
Well workover services are generally provided when a well needs major
repairs or modifications and often 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 during 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, in the well bore.
Workover activities may require a few days to several weeks to complete and
additional equipment and services are provided by PWS or PDTSG during this
process.
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 production tubing. Maintenance services are generally required
throughout the life of a producing well and are typically required more often by
oil wells than 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 gas prices and reservoir depletion.
Furthermore, an increase in drilling activity leads to more producing wells that
require workover and maintenance services in future years.
Live, also a division of PLP, currently markets 25 portable hydraulic rig
assist snubbing units in western Canada. The Live fleet grew by two units on
December 30, 2003 through an asset acquisition from a private company based in
southern Alberta. Rig assist snubbing units are equipped with specialized
pressure control devices, which allows for completions and workover operations
while the well is under pressure. The snubbing unit provided by Live is a
hydraulic rig assist unit, which can be rigged up in less than two hours onto a
service rig floor. Snubbing units are also part of the equipment used in
controlled pressure drilling operations.
Traditional well servicing operations requires the pressure in a well to be
neutralized, or killed, prior to performing such operations so that they can be
conducted safely. Certain wells can be damaged if they are killed, as the fluids
used in the process may cause the flow characteristics of the producing
formation to be adversely affected. Consequently, snubbing units have been
developed to perform certain workover, completion and controlled pressure
drilling (CPD) activities without killing the well. The Corporation believes
that the use of snubbing units is increasing as oil and gas companies become
more aware of potential risks of formation damage that can be avoided by using
snubbing units and techniques. Snubbing is typically performed on natural gas
wells. Increasing natural gas well drilling and production in the Western Canada
Sedimentary Basin is having a positive effect on demand for Live's services.
TECHNOLOGY SERVICES
The TS segment carries on business through three main business lines,
being; wireline, directional drilling and separation services. Wireline includes
cased hole, open hole and slickline services. Directional drilling includes MWD,
LWD, directional drilling and rotary steerable services. Separation services
includes well testing and controlled pressure drilling (which includes
underbalanced drilling services). In addition to the three main business lines,
TS manufactures, rents and sells PDC bits and derives revenues from the
provision of project management services on the Burgos Project in Mexico.
Revenue generated by TS operations is as follows:
2003 2002 2001
-----------------------------------------------------------------------------------------------------------------------------
Years ended December 31, (In thousands) REVENUE % OF Revenue % of Revenue % of
-----------------------------------------------------------------------------------------------------------------------------
Wireline $ 298,568 42% $ 227,497 38% $ 308,569 50%
Directional Drilling 223,442 31% 178,675 29% 175,614 29%
Separation Services 95,426 13% 100,670 17% 85,530 14%
Other 96,949 14% 96,246 16% 44,439 7%
-----------------------------------------------------------------------------------------------------------------------------
$ 714,385 100% $ 603,088 100% $ 614,152 100%
-----------------------------------------------------------------------------------------------------------------------------
WIRELINE
Wireline services are offered from numerous locations throughout the world.
Wireline tools are primarily manufactured in Fort Worth, Texas. Once a hole is
drilled, wireline logging services are used to measure the physical properties
of underground formations to help determine the location and potential
deliverability of oil and gas in a reservoir. The provision of Wireline Services
is divided into three categories; open hole services, cased hole services and
slickline services. Open hole logging assists in locating oil and gas by
measuring certain characteristics of geological formations and providing
permanent records called "logs". Cased hole services are performed at various
times throughout the life of the well and include perforating, completion
logging, production logging and well bore integrity services. Wireline services
are provided from surface logging units, which lower tools and sensors into the
well bore on a single or multiple conductor wireline. As the wireline pulls the
tools through the well bore, log measurements are gathered and relayed through
the wireline cable to a computerized surface data acquisition and processing
system. These state-of-the-art systems are an integral component of each
wireline unit.
Open hole logging is performed at different intervals during the well
drilling process or immediately after a well is drilled. This logging data
provides a valuable benchmark that future well procedures may be referenced to.
The open hole sensors and tools are used to determine well lithology and the
presence of hydrocarbons. Formation characteristics such as resistivity, density
and porosity are accurately measured using electrical, nuclear, acoustic,
magnetic and mechanical technologies. This data is then used to characterize the
reservoir and describe it in terms of porosity, oil, gas, or water content and
an estimation of productivity. This information can be further refined at a
later time in one of the Corporation's log interpretation centers. Wireline
services can relay this information on a real time basis via a secure satellite
transmission network and secure internet connection to the client's office for
faster evaluation and decisions. Most of TS's open hole tools and sensors are
proprietary.
After the well bore is cased and cemented, the cased hole division can
perform a number of different services. Perforating the casing allows oil and
gas to flow to the surface. Production logging may be performed throughout the
life of the well to measure temperature, fluid type, flow rate, pressure and
other reservoir characteristics. This helps the operator analyze and monitor
well performance and determine when a well may need a workover or further
stimulation. In addition, cased hole services may involve well bore remediation,
which could include the positioning, and installation of various plugs and
packers to maintain production or repair well problems. Some of the cased hole
tools are proprietary.
At its Fort Worth facility, which is ISO 9001 accredited, TS designs,
assembles and services open hole and cased hole logging tools, and surface
equipment. The specialized truck-mounted and skid-mounted wireline logging units
are manufactured and assembled to the Corporation's specifications by third
parties, primarily in Canada. The focus of wireline research and engineering has
been on the development of new or improved downhole sensors which are currently
being introduced for open hole logging that will take advantage of our new
Wireline Communications System (WCS). In cased hole the Slim Monopole Array
Sonic, Pulsed Neutron Decay Detector, Ultrasonic Cement Scanner, Production
Fluid Identifier, and Casing Inspection Tool, are under research and/or
development.
The AQRIT(TM) (Accurate Quick Reservoir Insitu Testing) technology is
deployed within Canada on electric wireline and enables customers to gather key
hydrocarbon reservoir information from both producing and non-producing well
bores.
Slickline, which utilizes a solid steel, nonconductor line in place of a
single or multiple conductor braided line used in electric logging, is used
primarily in producing wells for running downhole memory tools, manipulating
downhole production devices and fishing services.
TS provides wireline and slickline services with 39 open hole units, 175
cased hole units, 10 combination open hole/cased units, 14 slickline and six
combination slickline/cased hole units deployed from its service centres in
Canada, the U.S,. Mexico, and internationally.
DIRECTIONAL DRILLING
Directional drilling is the use of equipment and engineering to
intentionally change the angle of a well bore so that the trajectory of the well
bore can be accurately controlled, drilling efficiency can be enhanced or
formations or obstructions can be circumvented in order to reach the pay zone.
Directional drilling services offered worldwide, was strengthened with the
acquisitions of BecField Drilling Services Ltd. in January 2001, and the EM/MWD
technology, from Geoservices Incorporated, in October 2000. Directional drilling
equipment is engineered and assembled in Edmonton, Alberta and MWD/LWD tools are
manufactured and assembled in Houston, Texas. TS also has research and
engineering facilities in Forth Worth and Houston, Texas; Hannover, Germany;
Cheltenham, England and Edmonton, Alberta, Canada.
TS supplies specialized equipment including MWD, LWD, rotary steerable
systems and drilling motors along with experienced personnel for directional and
horizontal drilling operations. Those services are available for directional
control, slant well drilling, single and multi-lateral horizontal wells, and
other directional applications.
An MWD system is connected behind the mud motor or rotary steerable system
and relays continuous real time information to the surface to monitor the
trajectory of the well being drilled. An LWD system is connected behind the mud
motor or rotary steerable system and monitors formation characteristics while
drilling, similar to the measurements mode with open hole logging tools. MWD and
LWD information is transmitted to the surface via mud pulses or by
electromagnetic waves. Using MWD information the operator steers the drill bit
to the prescribed target location. Unlike previous technologies, MWD and LWD do
not require the drill string to be tripped out of the hole while the well
trajectory and formation characteristics are being measured, thus saving
valuable time.
New products were the rationale behind the formation of Advantage R & D,
Inc., (Advantage) in 1999. Advantage focuses on the research and engineering of
MWD and LWD technologies and advanced directional drilling systems. The
Advantage research and engineering strategy has initially been directed towards
the high temperature MWD and LWD market with respect to land-based as well as
deep-water drilling markets. Advantage has developed directional, gamma ray,
resistivity, neutron porosity, bulk density, pressure while drilling and
downhole environment severity sensors. Advantage is located in Houston, Texas,
in a research and development facility that has state of the art testing
equipment complete with extensive well simulation capabilities.
The directional drilling facility in Edmonton is responsible for the design
and assembly of mud pulse MWD systems and certain directional survey tools which
are manufactured to company specifications by third parties in Canada. This
Edmonton facility is also responsible for the design of drilling motors which
are manufactured by third parties in Canada to company specifications and
assembled at its Fort Worth facilities. These MWD, survey and drilling motors
are either used by the company or may be sold worldwide.
SEPARATION SERVICES
Northland, a division of PDTSG (Northland) provides separation services,
well testing and controlled pressure drilling (CPD) services to oil and gas
producers.
The separation business supplies personnel and equipment on a well site to
recover a mixture of solids, liquids and gases from oil and gas wells. These
recoveries include oil and gas as well as drilling and workover fluids and well
stimulation by-products. Northland equipment is used to safely separate the
recovered solids, liquids and gases while accurately measuring each component
and ensuring proper well control. These services are used during drilling
operations for "kick control", for well cleanup services after the stimulation
of the well and for well testing operations. The operator requires these
services to properly clean up the well prior to undertaking a flow test to
determine the deliverability potential of the well. Northland is the largest
provider of such services in Canada. With the acquisition of Plains Energy
Services Ltd., in 2000, Northland Energy Corporation acquired the Entest Corp.
personnel and equipment to expand its well testing and CPD operation into low
and medium pressure market segments in Canada. The acquisition of Norward Energy
Services in 2001 increased the capabilities of Northland to provide
high-pressure and sour separation services to Canada as well as gaining a
testing operation in the northwest U.S. In 2001, Northland acquired the assets
of ITS-Testco LLC and an affiliate of that company to establish a separation
services base in Mexico as part of the Burgos region contract and also acquired
the separation assets of Core Laboratories de Venezuela SA. and its affiliates
to establish a separation services base in eastern Venezuela.
An extension to the conventional separation services provided by Northland
is the provision of mobile incineration systems. In applications where the
operator is required to further restrict gas flaring, the use of portable
incineration systems may, in certain circumstances, ensure a 99.95% efficiency
in the destruction of the waste gases. Although incinerators have been used for
decades to destroy waste gases of various compositions, this equipment was
limited to permanent installation applications.
Northland also provides personnel and surface control equipment for CPD
from offices in Canada, U.S., Mexico, South America, Europe/Africa, the Middle
East and Asia/Pacific. It offers a complete service of engineering, data
acquisition, equipment and personnel to drill a CPD well.
The concept of CPD is to use a lighter drilling medium than that normally
used to ensure pressure in the well bore is lowered to reduce drilling related
challenges and formation damage and allow formation characterization during
drilling operations. Often, inert gas such as nitrogen or exhaust gas is
injected downhole with the drilling mud to create the required lighter drilling
medium. Reservoir fluids can be allowed to flow to the surface as the well is
being drilled instead of exposing the reservoir to drilling mud invasion due to
the overpressure nature of a mud column in the well bore. This concept is used
in an attempt to avoid formation damage experienced in many wells, particularly
horizontal wells, which are more susceptible to formation damage problems caused
by the drilling mud itself. With the increase in the number of horizontal wells
being drilled and the increase of sub-hydrostatic reservoirs where drilling
challenges, such as lost circulation and differential sticking are often
encountered, the use of CPD technology has been increasing.
Northland developed its first separation package for CPD in the early
1990s. In the late 1990s, Precision acquired Northland and various other
companies which provided Northland with rotating blowout preventers (RBOP(TM)),
proprietary exhaust gas processors (EGP) and nitrogen membrane systems. The
RBOP(TM) device seals off the well bore at surface by gripping and sealing
around the drill pipe and rotating freely with it, thus diverting the
pressurized flow of drilling fluids, gas, oil and cuttings to the choke manifold
and separation package. The proprietary EGP satisfied the service gas
requirements of CPD and the acquisition of the nitrogen membrane systems
compliments the EGP technology and increases Northland's total CPD service gas
capabilities. In addition, during the last two years, Northland has developed a
new patented 5,000 PSI RBOP(TM) and a next generation patented EGP unit.
OTHER
United Diamond Ltd. designs, manufactures, sells and rents PDC drill bits.
Its design and manufacturing facility is located in Nisku, Alberta. United
Diamond is currently selling and renting its drill bits into the Canadian market
and selected international markets.
United Diamond has developed the torsional impact motor (TorkBuster(TM)) to
increase the drilling performance of PDC bits.
RENTAL AND PRODUCTION
Years ended December 31, (In thousands) 2003 2002 2001
-----------------------------------------------------------------------------------------------------
Rental Services $ 36,478 $ 24,469 $ 42,290
Production Services 174,246 168,371 152,277
-----------------------------------------------------------------------------------------------------
Total $ 210,724 $ 192,840 $ 194,567
-----------------------------------------------------------------------------------------------------
The rental services component of the Rental and Production segment of the
Corporation is carried out through Precision Rentals Ltd. (formerly Montero
Oilfield Services Ltd), which provides a wide array of rental products and
services, including surface, drilling, completion and production equipment;
tubular and well control equipment and field and well site accommodations. The
production services component of this segment is carried out through CEDA, which
is a leading provider of industrial maintenance and turnaround services,
including specialized catalyst handling, both in Canada and the U.S.
RENTAL SERVICES
The businesses of Smoky Oilfield Rentals, Big D Rentals and Ducharme
Oilfield Rentals were combined and now operate as Precision Rentals Ltd.
("Precision Rentals"). Precision Rentals maintains an inventory of rental
equipment including storage tanks, high and low pressure oil and gas separators,
sump and shale tanks and related equipment. Precision Rentals also 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 field and well site accommodation portion of Precision Rentals consists
of a fleet of approximately 281 fully equipped and furnished units. Trailer
units are delivered to rig locations using Precision Rental's own air-ride
trucks and tri-axle trailers.
The tubular and well control business of Precision Rentals consists of the
rental of specialized drilling equipment (approximately 10,000 joints of
specialty drill pipe and collars and 4,000 handling tools, valves, kellys and
floats) to hydrocarbon producers and service and drilling rig contractors
engaged in the Canadian oil and gas industry. The present inventory consists of
various sizes and grades of oilfield tubulars, blowout prevention equipment,
valves, pumps and diverter systems.
PRODUCTION SERVICES
CEDA is a leading provider of industrial maintenance and turnaround
services and other specialized services to various production industries in
Canada and the U.S. The main areas of its operations are industrial cleaning,
catalyst handling and mechanical services, usually carried out in large plants
such as refineries, gas plants, petro-chemical facilities and the pulp and paper
industry. Industrial cleaning encompasses high pressure water blasting, large
scale industrial vacuuming (169 vacuum trucks) and specialized chemical
cleaning. High pressure water blasting equipment (79 units and 14 bundle
blasters) pumps water at pressures up to 40,000 PSI to clean equipment and
systems that are externally accessible. When equipment and systems are not
externally accessible, cleaning requires the circulation of chemical
formulations through a closed system. Specialized chemical cleaning utilizes a
team of chemists, engineers and service technicians who combine their expertise
to provide highly specialized and environmentally sound chemical cleaning
services. Catalyst handling involves the removal and replacement of catalyst in
reactors at refineries or petrochemical facilities. Mechanical services include
bolt tensioning, machining and leak repair services. Specialized mechanical
services utilize technology and equipment to unfasten, repair and refasten
flanges and piping systems with resulting savings of time and money and
reduction of fugitive emissions. These services are usually undertaken at
customer locations, frequently under critical time constraints, during scheduled
shut downs or emergencies.
With many years of experience in providing dredging, dewatering and water
recycling services, CEDA operates a modern fleet of equipment that includes
portable dredges, dewatering centrifuges and unique oil-skimming equipment
capable of assisting companies in dealing with a variety of water-related
maintenance services. The equipment and staff work in a variety of industries
from chemical plants and refineries to mining, utilities and pulp and paper
operations.
In Canada, CEDA and its subsidiaries operate from 18 operating centers plus
a network of five dealerships. In the U.S., CEDA provides a full suite of
services out of 10 major operating centers.
EMPLOYEES
The total number of employees fluctuates with rig utilization in contract
drilling services and well servicing and with seasonal variations in certain of
the Corporation's other businesses but is expected to range between 8,000 and
12,000 employees, consisting of between 4,000 and 6,000 employees in the
Contract Drilling segment, 3,000 and 4,000 employees in the Technology Services
segment and 1,000 and 2,000 employees in the Rental and Production segment.
LEGAL PROCEEDINGS
The Corporation is not involved in any legal proceedings that it believes
might have a material adverse effect on its business or results of operations.
SELECTED CONSOLIDATED FINANCIAL INFORMATION
SUMMARY OF OPERATING RESULTS
The following table sets forth selected financial information of the
Corporation for each of the years ended, as indicated:
Years ended December 31, (millions of CDN $ except per share amounts) 2003 2002 2001
-----------------------------------------------------------------------------------------------------
Revenue 1,917.9 1,567.5 1,815.2
Earnings from continuing operations
before goodwill amortization 191.1 89.5 206.3
Earnings from continuing operations
before goodwill amortization per share:
Basic (2) 3.51 1.67 3.90
Diluted 3.46 1.63 3.81
Earnings from continuing operations 191.1 89.5 175.7
Earnings from continuing operations per share:
Basic (2) 3.51 1.67 3.31
Diluted 3.46 1.63 3.23
Net earnings (3) 188.7 91.3 186.5
Net earnings per share:
Basic (2) 3.47 1.70 3.52
Diluted 3.41 1.66 3.44
Cash flow from operations (4) 258.4 199.2 432.2
Total assets 2,908.4 2,760.0 2,651.4
Long-term debt (5) 399.4 514.9 496.2
-----------------------------------------------------------------------------------------------------
NOTES:
(1) THE DATA SET OUT FOR THE YEARS ENDED DECEMBER 31, 2002 AND 2001 IS
COMPARATIVE IN ALL MATERIAL RESPECTS.
(2) BASIC PER SHARE AMOUNTS WERE CALCULATED USING THE WEIGHTED AVERAGE NUMBER
OF COMMON SHARES OUTSTANDING.
(3) THE YEAR ENDED DECEMBER 31, 2003 INCLUDES GAINS ON DISPOSAL OF INVESTMENTS
AND A WRITEDOWN AND GAIN ON DISPOSAL OF ASSETS HELD AS DISCONTINUED
OPERATIONS. THE YEARS ENDED DECEMBER 31, 2002 AND 2001 INCLUDED A GAIN ON
DISPOSAL OF INVESTMENTS.
(4) CASH FLOW FROM OPERATIONS INCLUDES DISCONTINUED OPERATIONS.
(5) EXCLUDING CURRENT PORTION OF LONG-TERM DEBT.
DIVIDENDS
No dividends have been paid on any Common Shares of the Corporation since
the purchase of the assets of Precision Drilling Limited in 1987. Any decision
to pay dividends on the Common Shares in the future will be made by the Board of
Directors of the Corporation and will be based on the Corporation's earnings,
financial requirements and other conditions at the time.
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, 2003 forms part of the
Corporation's 2003 Annual Report and is incorporated herein by reference and
forms an integral part of this Renewal Annual Information Form. The Management's
Discussion and Analysis appears on pages 43 to 75 of the 2003 Annual Report.
MARKET FOR SECURITIES
The Common Shares of the Corporation are listed for trading on the Toronto
Stock Exchange (TSX) and trade under the symbol PD (and effective February 2,
2004 PD.U); and on the New York Stock Exchange (NYSE) under the symbol PDS. The
share trading summaries for both the TSX and NYSE for the past three years is
located on page 101 of the 2003 Annual Report.
DIRECTORS AND OFFICERS
The following table sets forth all of the current directors and officers of
the Corporation together with the positions currently held by them with the
Corporation, their principal occupation or employment during the last five years
and the year in which they were first elected a director of the Corporation. The
term of office of each director will expire at the end of the next annual
meeting of shareholders of the Corporation.
NAME TITLE PRINCIPAL OCCUPATION DIRECTOR SINCE
--------------------------------------------------------------------------------------------------------------------------
W.C. (Mickey) Dunn Director Chairman, True Energy Ltd. September 1992
Edmonton, Alberta
--------------------------------------------------------------------------------------------------------------------------
Robert J.S. Gibson Director President, Stuart & Company Limited June 1996
Calgary, Alberta
--------------------------------------------------------------------------------------------------------------------------
Murray K. Mullen Director Chairman, President September 1996
Calgary, Alberta and Chief Executive Officer
of Mullen Transportation Inc.
--------------------------------------------------------------------------------------------------------------------------
Patrick M. Murray Director President and Chief Executive Officer July 2002
Dallas, Texas Dresser, Inc.
--------------------------------------------------------------------------------------------------------------------------
Fred W. Pheasey Director Executive Vice President July 2002
Edmonton, Alberta National Oilwell, Inc.
--------------------------------------------------------------------------------------------------------------------------
Robert L. Phillips Nominee Director President and CEO, BCR Group of Companies Nominee
Vancouver, since March 2001. Prior to that, from March 1999 to March 2001,
British Columbia Mr. Phillips was Executive Vice President at MacMillan Bloedel
Limited; prior to that, from March 1998 to March 1999 Mr. Phillips
was President and CEO of PTI Group Inc.; prior to that, from April
1994 to March 1998
--------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------
Mr. Phillips was President and CEO of Dreco Energy Services
Ltd.
--------------------------------------------------------------------------------------------------------------------------
Hank B. Swartout Chairman of the Officer of the Corporation July 1987
Calgary, Alberta Board President and
Chief Executive
Officer
--------------------------------------------------------------------------------------------------------------------------
H. Garth Wiggins Director Principal, Kenway Mack Slusarchuk Stewart, September 1997
Calgary, Alberta Chartered Accountants
--------------------------------------------------------------------------------------------------------------------------
Jan M. Campbell Corporate Secretary Officer of the Corporation N/A
Calgary, Alberta
--------------------------------------------------------------------------------------------------------------------------
R.T. (Bob) German Vice President and Officer of the Corporation N/A
Calgary, Alberta Chief Accounting
Officer
--------------------------------------------------------------------------------------------------------------------------
John R. King Senior Vice President Officer of the Corporation since March 2003. N/A
Calgary, Alberta Technology Services Prior to joining Precision, Mr. King was a Founder and
Managing Director of RedTree Capital Corporation since
February 1998.
--------------------------------------------------------------------------------------------------------------------------
M.J. (Mick) McNulty Senior Vice President Officer of the Corporation N/A
Calgary, Alberta Operations Finance
--------------------------------------------------------------------------------------------------------------------------
Dale E. Tremblay Senior Vice President Officer of the Corporation N/A
Airdrie, Alberta Finance and Chief
Financial Officer
--------------------------------------------------------------------------------------------------------------------------
As of the date hereof, the directors and officers of the Corporation, as a
group, beneficially owned, directly or indirectly, or exercise control or
direction over 529,623 Common Shares, which represents 0.95% of the issued and
outstanding common shares. The information as to shares beneficially owned has
been furnished by the respective directors and officers of the Corporation
individually.
The Corporation is required to have an Audit Committee. The directors who
are currently members of that Committee are Robert J.S. Gibson, Patrick M.
Murray and H. Garth Wiggins. In addition, the Corporation has a Compensation
Committee whose members are W.C. (Mickey) Dunn and Murray K. Mullen, and a
Corporate Governance and Nominating Committee whose members are Robert J.S.
Gibson, W.C. (Mickey) Dunn and Fred W. Pheasey.
ADDITIONAL INFORMATION
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
As of the end of Precision's fiscal year ended December 31, 2003, an
evaluation of the effectiveness of Precision'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 Precision's principal executive officer and principal financial
officer. Based upon that evaluation, the principal executive officer and
principal financial officer have concluded that as of the end of that fiscal
year, Precision's disclosure controls and procedures are effective to ensure
that information required to be disclosed by Precision in reports that it files
or submits under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in Securities and Exchange Commission
rules and forms.
During the fiscal year ended December 31, 2003, there were no changes in
Precision's internal control over financial reporting that have materially
affected, or are reasonably likely to materially affect, Precision's internal
control over financial reporting.
It should be noted that while Precision's principal executive officer and
principal financial officer believe that Precision's disclosure controls and
procedures provide a reasonable level of assurance that they are effective, they
do not expect that Precision'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.
REQUEST FOR ADDITIONAL INFORMATION
Additional information, including information as to directors and officers
remuneration and indebtedness, principal holders of the Corporation's
securities, options to purchase securities and interests of insiders in material
transactions is contained in the Management Information Circular of the
Corporation provided for the Annual and Special Meeting of shareholders of the
Corporation to be held on May 11, 2004. Additional financial information is
provided in the Corporation's Financial Statements for the year ended December
31, 2003, which are contained in the Annual Report of the Corporation for the
year ended December 31, 2003.
Upon request the Corporation will provide to any person:
1. one copy of this Renewal Annual Information Form;
2. one copy of the Corporation's audited financial statement for year
ended December 31, 2003, together with the report of the auditors
thereon contained in the Annual Report, and one copy of any of the
Corporation's interim financial statements subsequent to such audited
financial statements;
3. one copy of the Corporation's Management Information Circular provided
for the Annual and Special Meeting of the shareholders of the
Corporation to be held on May 11, 2004; and
4. when the Corporation's securities are in the course of a distribution
pursuant to a short form prospectus or when a preliminary short form
prospectus has been filed in respect of a distribution of the
Corporation's securities, also upon request to the Corporate Secretary,
one copy of any other document that is incorporated by reference in the
preliminary short form prospectus or short form prospectus.
Copies of these documents may be obtained upon request to the Corporate
Secretary, Precision Drilling Corporation, 4200, 150 - 6th Avenue S.W., Calgary,
Alberta, T2P 3Y7, Telephone (403) 716-4500 or Facsimile (403) 264-0251.
Precision Drilling Corporation
4200, 150-6th Avenue SW
Calgary, Alberta, Canada T2P 3Y7
Telephone: 403-716-4500
Facsimile: 403-264-0251
Website: www.precisiondrilling.com
MANAGEMENT'S DISCUSSION AND ANALYSIS
The Management's Discussion and Analysis has been prepared taking into
consideration information available to February 10, 2004. The discussion focuses
on key statistics from the Consolidated Financial Statements, and pertains to
known risks and uncertainties relating to the oilfield and industrial service
sectors. 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
the Corporation 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 audited Consolidated Financial
Statements. 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 15 to the Consolidated Financial
Statements.
HIGHLIGHTS(1)
(STATED IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT PER SHARE AMOUNTS,
WHICH ARE PRESENTED ON A DILUTED BASIS)
Increase Increase Increase
Years ended December 31, 2003 (DECREASE) 2002 (Decrease) 2001 (Decrease)
---------------------------------------------------------------------------------------------------------------------------
Revenue 1,917,933 350,427 1,567,506 (247,702) 1,815,208 504,234
% change 22% (14%) 45%
Operating earnings (2) 297,110 141,551 155,559 (206,226) 361,785 115,840
% change 91% (57%) 47%
Earnings from continuing operations
before goodwill amortization 191,131 101,597 89,534 (116,763) 206,297 59,439
% change 113% (57%) 40%
Earnings from continuing operations 191,131 101,597 89,534 (86,176) 175,710 50,694
% change 113% (49%) 41%
Net earnings 188,676 97,411 91,265 (95,269) 186,534 56,421
% change 107% (51%) 43%
Earnings per share from
continuing operations 3.46 1.83 1.63 (1.60) 3.23 0.75
% change 112% (50%) 30%
Net earnings per share 3.41 1.75 1.66 (1.78) 3.44 0.86
% change 105% (52%) 33%
Cash flow from operations 258,427 59,204 199,223 (233,007) 432,230 195,345
% change 30% (54%) 82%
Net capital spending 290,504 50,961 239,543 (101,418) 340,961 160,207
% change 21% (30%) 89%
---------------------------------------------------------------------------------------------------------------------------
(1) QUARTERLY FINANCIAL INFORMATION FOR THE TWO-YEAR PERIOD ENDED DECEMBER 31,
2003 IS PRESENTED ON PAGE 104 OF THIS ANNUAL REPORT.
(2) 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 CORPORATION'S
PRINCIPAL BUSINESS ACTIVITIES PRIOR TO CONSIDERATION OF HOW THOSE
ACTIVITIES ARE FINANCED OR HOW THE RESULTS ARE TAXED IN VARIOUS
JURISDICTIONS. 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 COMPANIES AND, ACCORDINGLY, OPERATING EARNINGS MAY NOT BE
COMPARABLE TO MEASURES USED BY OTHER COMPANIES.
20
FINANCIAL POSITION AND RATIOS
(STATED IN THOUSANDS OF CANADIAN DOLLARS)
Years ended December 31, 2003 2002 2001
-------------------------------------------------------------------------------
Working capital 248,261 210,256 215,919
Working capital ratio 1.6 1.5 1.6
Long-term debt (1) 399,422 514,878 496,200
Long-term debt to long-term debt
plus equity (1) 0.19 0.25 0.26
Long-term debt to cash flow
from operations (1) 1.5 2.6 1.1
Interest coverage (2) 8.5 4.4 8.4
--------------------------------------------------------------------------------
(1) EXCLUDING CURRENT PORTION OF LONG-TERM DEBT WHICH IS INCLUDED IN WORKING
CAPITAL.
(2) OPERATING EARNINGS DIVIDED BY NET INTEREST EXPENSE.
The 107% increase in net earnings in 2003 over 2002 was driven largely by
the strong Canadian market where drilling activity increased by 30% year over
year. Technology Services (TS) return to profitability was also a contributor to
the improvement. While not as significant quantitatively, this milestone
provides a measure of success for management's efforts to re-focus that business
from top line growth to bottom line profitability.
Interim objectives in the Corporation's five year plan to develop the
Technology Services segment have been achieved, the most significant of which
relate to technological advancements. Our new logging-while-drilling (LWD),
measurement-while-drilling (MWD) and rotary steerable tools have set new
standards for operating in high temperature and high pressure environments and
have demonstrated superior information gathering and steering response
capabilities. The tools are now being put to work by our customers and revenues
should increase as the number of systems deployed to operations increases and as
we fill out our fleet with the full complement of tool sizes.
Our research and engineering programs were successful at mitigating the
technology risk associated with the TS development plan. However, it was
recognized that insufficient attention had been paid to managing factors that
put achievement of profitability objectives at risk. As is often the case,
achievement of one set of objectives requires different skills than achieving
another set of objectives. As a result, changes were made at various levels of
the TS management team to add the experience required to focus on delivering a
consistent product to our customers in a systematic and profitable manner.
Change was not isolated to the Technology Services segment. Early in the
year, the Corporation sold its gas compression business, which was carried on by
Energy Industries Inc. Although Energy Industries had been profitable since its
acquisition by Precision in 1996, the compression packaging business was
determined to be not core to the Corporation's energy services globalization
strategy. In September the Corporation's rental businesses were brought under
one umbrella to form Precision Rentals Ltd. This served to simplify purchasing
decisions for our customers by providing one point of contact for all their
rental needs.
SUMMARY INCOME STATEMENT
(STATED IN THOUSANDS OF CANADIAN DOLLARS)
Years ended December 31, 2003 2002 2001
---------------------------------------------------------------------------------------------------------------
Operating earnings (loss)
Contract Drilling $ 285,753 $ 184,553 $ 298,737
Technology Services 4,842 (31,733) 52,257
Rental and Production 39,350 30,090 39,365
Corporate and Other (32,835) (27,351) (28,574)
---------------------------------------------------------------------------------------------------------------
297,110 155,559 361,785
Interest, net 35,050 35,123 43,059
Dividend income -- (39) (1,106)
Gain on disposal of investments (3,355) (900) (1,805)
Earnings from continuing operations before
income taxes, non-controlling interest
and goodwill amortization 265,415 121,375 321,637
Income taxes 72,532 30,690 114,472
---------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
non-controlling interest and
goodwill amortization 192,883 90,685 207,165
Non-controlling interest 1,752 1,151 868
---------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
goodwill amortization 191,131 89,534 206,297
Goodwill amortization, net of tax -- -- 30,587
---------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 191,131 89,534 175,710
Gain on disposal of discontinued operations 17,460 -- --
Discontinued operations (19,915) 1,731 10,824
Net earnings $ 188,676 $ 91,265 $ 186,534
---------------------------------------------------------------------------------------------------------------
ECONOMIC DRIVERS OF THE OILFIELD SERVICES BUSINESS
Crude oil and natural gas (hydrocarbons) are the primary sources of energy
in the world. The provision of these commodities to the consuming public
involves a number of players, each of whom take on different risks in the
process of exploring for, producing, refining and distributing hydrocarbons and
its associated refined by-products. Exploration and production companies assume
the risk of finding hydrocarbons in pools of sufficient size to economically
develop and produce the 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 finding, producing, refining and distributing energy
to residential and business users.
The worldwide oilfield services industry (broadly defined) is a 100 billion
business that provides a wide array of services and equipment to support oil and
gas exploration and production activities.
[GRAPHIC OMITTED - PIE CHART] [GRAPHIC OMITTED - PIE CHART]
[OILFIELD SPENDING WORLDWIDE] [SOURCES OF ENERGY USED WORLDWIDE]
------------------------------- --------------------------------------
Reservoir Info 5% Crude Oil 39%
Drilling 26% Natural Gas 23%
Drilling Related 17% Coal 23%
Completion 16% Hydroelectric Power 7%
Infrastructure 16% Nuclear Electric Power 7%
Production/Maintenance 14% Geothermal, Solar, Wind and
Logisitical Support 6% Wood and Waste Electric Power 1%
------------------------------- --------------------------------------
These activities include acquiring access to prospective lands, shooting
seismic to detect the presence of hydrocarbons, drilling wells and measuring the
characteristics of subsurface geological formations. If a well is evaluated to
be commercially viable, additional oilfield services are required to complete
the new well and then subsequently to maintain production. Exploration and
production companies hire oilfield service companies to perform the majority of
these services, hence, they are Precision's customers. The revenue for an
oilfield service company is therefore, our customer's finding and development
cost.
Providing these 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 ever changing surface and subsurface
conditions. Developing technology and building equipment that can withstand
increasing physical challenges and operate more efficiently is key to
maintaining and improving 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 it earns.
The economics of a service company is thus largely driven by the current
and expected price of crude oil and natural gas, which is determined by the
supply and demand for the commodity. 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.
[GRAPHIC OMITTED - LINE CHART]
[WTI OIL AND HENRY HUB GAS PRICES]
--------------------------------------------------------------------------------------------------
Date Jan-85 Jan-86 Jan-87 Jan-88 Jan-89 Jan-90 Jan-91 Jan-92 Jan-93 Jan-94
--------------------------------------------------------------------------------------------------
US$/Bbl 25.75 23.63 18.48 17.01 17.98 22.87 25.78 18.82 19.15 14.97
--------------------------------------------------------------------------------------------------
US$/MMBtu 2.82 2.06 1.47 1.84 1.83 2.23 1.57 1.29 1.77 2.08
--------------------------------------------------------------------------------------------------
4 Year Gas Avg 1.77 1.77 1.77 1.77 1.53 1.53 1.53 1.53 1.89 1.89
--------------------------------------------------------------------------------------------------
4 Year Oil Avg 19.54 19.54 19.54 19.54 21.53 21.53 21.53 21.53 19.06 19.06
--------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------
Date Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03
-----------------------------------------------------------------------------------------
US$/Bbl 17.98 18.88 25.13 16.7 12.49 27.27 29.55 19.57 32.87
-----------------------------------------------------------------------------------------
US$/MMBtu 1.33 2.34 3.46 2.02 1.75 2.26 8.72 2.14 5.15
-----------------------------------------------------------------------------------------
4 Year Gas Avg 1.89 1.89 2.66 2.66 2.66 2.66 4.07 4.07 4.07
-----------------------------------------------------------------------------------------
4 Year Oil Avg 19.06 19.06 21.15 21.15 21.15 21.15 26.77 26.77 26.77
-----------------------------------------------------------------------------------------
Although, as illustrated above, crude oil and natural gas prices have
historically been quite volatile, the consensus of industry observers is that
the relatively high current price environment appears to be sustainable for the
foreseeable future. Oil prices, which during 2003 averaged US$31.10 per barrel
for West Texas Intermediate (WTI), are the result of political instability in
some OPEC member nations (Venezuela, Iraq and Nigeria) and from a generally
improving world economy with energy demand growth particularly strong in China
and Southeast Asia. Another important factor in the crude oil pricing equation,
and one that has seen a fundamental change from past pricing scenarios, is the
value of the U.S. dollar. Since oil prices are denominated in U.S. dollars
around the world, the devaluation of the U.S. dollar that has occurred over the
past year has implications for both the seller and buyer of the commodity. Oil
producing nations, with OPEC members taking the lead in controlling supplies and
prices, are motivated to see an increase in the U.S. dollar price of oil to
maintain their purchasing power in other currencies such as the Euro. From a
buyer's perspective, the devaluation of the U.S. dollar has made oil a cheaper
commodity for those who spend Euros and Japanese Yen thus supporting the
increased demand.
North American natural gas prices are also being supported by strong
fundamentals. Demand is increasing with improved economic growth while supply
from relatively mature producing basins is starting to decline. The near record
gas drilling activity in 2003 served only 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 benefit of switching between the two fuels is minimal. The importation
of liquefied natural gas into the North American market, once thought to be the
competitive product that would cause gas prices to decline, is now viewed by
many industry analysts as a requirement to fill the gap between demand and
conventional production capabilities.
THE CANADIAN MARKET - PRECISION'S PLATFORM
The Western Canada Sedimentary Basin (WCSB) is maturing and our Canadian
business units are adapting to this change. Overall production in the WCSB is
growing, however, conventional oil is on the decline and natural gas reserve
growth is struggling to replace 2003 production volumes. Growth opportunities
exist in oil sands, heavy oil and tight gas drilling, coal bed methane drilling
in particular. Longer-term medium to deep drilling prospects will be long
awaited opportunity for oilfield service providers. With strong commodity
prices, our customers first exploit low risk quick tie-in production. For
western Canada this is shallow natural gas and the statistics prove this out.
The number of wells drilled in 2003 set an all-time high with 19,851 completed
wells. Note that well statistics on a completion basis differ from rig releases
due to delays in reporting. While the statistics vary, well completion
statistics accurately profile work opportunity over longer periods of time.
The following chart profiles the type of wells drilled in Canada over the
past 10 years.
[GRAPHIC OMITTED - BAR CHART]
[WESTERM CANADA SEDIMENTARY BASIN]
[NUMBER OF INDUSTRY WELLS DRILLED ON A COMPLETION BASIS]
------------------------------------------------------------------------
Oil Gas Dry Service
--- --- --- -------
1994 3853 5370 2503 145
1995 4843 3618 2414 187
1996 6332 3726 2459 178
1997 8558 4857 2777 292
1998 3142 4585 1850 167
1999 2730 6309 1427 139
2000 5462 8934 1903 186
2001 4689 11177 1759 308
2002 3832 9073 1289 265
2003 4473 13944 1233 201
------------------------------------------------------------------------
The steady growth in natural gas drilling has fueled activity for the past
decade. The shift from oil to natural gas wells impacts the underlying nature of
the energy services that companies like Precision provide. It has created higher
demand for snubbing and in general, lower demand for service rigs, as natural
gas wells do not need to be worked over as frequently as oil wells.
The following chart profiles 10-year drilling rig activity trends as
measured by spud to rig release operating days by category of drilling rig depth
rating.
[GRAPHIC OMITTED - BAR CHART]
[WESTERN CANADA SEDIMENTARY BASIN]
[INDUSTRY OPERATING DAYS]
[BY DRILLING RIG DEPTH RATING]
--------------------------------------------------------------------------------
0-950 951 - 1850 1851-2450 2451-3050 3051-3700 3701-4600 4601+
----- ---------- --------- --------- --------- --------- -----
1994 14273 38573 22592 12433 5557 3407 587
1995 14056 35205 17349 9980 4788 2963 1955
1996 19393 37593 20276 10615 5169 2944 1407
1997 24996 43085 27204 18797 5729 5670 2563
1998 13023 24323 20697 17292 5828 6265 1973
1999 14976 21422 17541 14378 4930 6464 2037
2000 22198 32103 23848 19390 9214 6646 4047
2001 22529 30300 23301 23320 9719 6988 4288
2002 18894 21877 17327 17299 8004 4228 4358
2003 27543 31431 21842 22002 13987 5188 4505
--------------------------------------------------------------------------------
While the year 2003 set the WCSB well count record, it is 1997 that
continues to hold the high mark for drilling rig work in terms of utilization
and operating days. At 33% of industry drilling rigs, Precision's activity
tracks very close to industry. While the well count is important, the reduction
in time to drill a well deserves emphasis.
It is the development of shallow well oil and natural gas prospects that
underpins the Canadian market and continues to be the agent for activity
volatility. The trend towards deeper drilling prospects is progressing at a slow
pace. However as our customers drill out the shallow well inventories that they
hold today, they will be forced to pursue deeper prospects. We believe that we
are beginning to see this shift as demand for medium depth light triple type
drilling rigs has never been stronger than it is in the first quarter of 2004.
The following chart profiles the 10-year trend in terms of average well
depth and average operating days to drill a well.
[GRAPHIC OMITTED - LINE CHART]
[WESTERN CANADA SEDIMENTARY BASIN]
AVERAGE INDUSTRY WELL DEPTH VERSUS TIME TO DRILL
------------------------------------------------------
Days Depth
---- -----
1994 8.21 1994 1152
1995 7.8 1995 1162
1996 7.67 1996 1107
1997 7.77 1997 1108
1998 9.17 1998 1240
1999 7.71 1999 1078
2000 7.12 2000 1068
2001 6.72 2001 1062
2002 6.36 2002 1067
2003 6.37 2003 1032
------------------------------------------------------
On average, oil and gas well depths are increasingly shallow. This is
entirely consistent with the production shift to natural gas in the WCSB.
Experience shows that our customers, the producers, first develop low risk close
to market prospects such as those in southern Alberta. The average time to drill
a well in the WCSB in 2003 was just over six days. For Precision in Canada, the
average time is 5.1 days. The average drilling time per well has shown
considerable reduction since 1999 as drilling contractors continue to search for
niche equipment solutions to specific well parameters. Precision's coil tubing
drilling rigs, since their emergence in the year 2000, have had a significant
impact on industry drilling statistics and in some ways have diminished the
meaning of a well count in terms of drilling rig activity.
Improvements in drilling equipment and processes in combination with better
downhole tools like MWD, LWD and the drill bit have provided productivity gains
that lower customer costs. Precision's coil tubing drilling rigs is a case in
point. Available rigs averaged 10.5 in 2003 and all together they drilled 2,641
wells during the year. Each well averaged a well depth of 614 metres, took 16.8
hours to drill with an operating utilization of 48%, move time excluded. These
types of drilling solutions are applicable to specific drilling programs only
and have filled a customer need to better exploit shallow natural gas. Another
example is oil sands drilling in northeast Alberta where Precision has taken a
lead industry role in the development of specialized equipment configuration
with our Super Single(R) drilling rig to meet the drilling requirement for
programs that enable recovery techniques such as Steam Assisted Gravity Drainage
(SAGD).
Innovations such as these may reduce our drilling revenue days in the near
term, however it balances out as we enable our customers to pursue more
prospects in the exploitation of hydrocarbons within the WCSB.
The following chart profiles the 10-year trend in terms of available
drilling rigs and operating day rig utilization.
[GRAPHIC OMITTED - LINE/BAR CHART]
[WESTERN CANADA SEDIMENTARY BASIN]
[INDUSTRY UTILIZATION VERSUS NUMBER OF DRILLING RIGS AVAILABLE]
---------------------------------------------------------------
Drilling Rigs Rig Operating
Available at Day
Year End Utilization
-------- -----------
1994 445 1994 62
1995 458 1995 51
1996 479 1996 58
1997 545 1997 69
1998 579 1998 43
1999 588 1999 39
2000 615 2000 54
2001 652 2001 52
2002 662 2002 38
2003 681 2003 52
---------------------------------------------------------------
The supply of drilling rigs in Canada has steadily increased over the past
10 years to almost 700, an all-time high. Customer demand as measured by
operating day utilization peaked in 1997 and has languished between 38% and 56%
since. This has not deterred the industry from adding rigs as drilling
contractors have continued to build capacity. In the short term the capacity is
geared toward peak winter demand in January and February. In the medium to
long-term it provides the capacity to drill more wells through better
utilization in the other ten months of the year. If commodity prices weaken for
a prolonged period the industry may have a large supply 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 in good stead.
Within the Contract Drilling segment, Precision underwent tremendous growth
in Canada up to 1997. Subsequently we diversified our service offering through
service rigs and snubbing units to service and work-over the increasing number
of wells drilled and in production. This included camp and catering capabilities
to meet the logistical reality of remote drilling locations and the need to
reduce travel incidents for field employees at the well site. Precision's
drilling rig fleet represented 40% of the industry in 1997. Our market share has
eroded to 33% in 2003. Precision is comfortable at this level and we acknowledge
that it would take the acquisition of 55 existing rigs to regain lost market
share.
With a lead industry market share in Canada and reduced acquisition
opportunities within Canada our focus has been to reach out and gain experience
in the international drilling market. We have gained considerable work
experience and projects like the Burgos Basin in Mexico demonstrate our ability
to deploy and operate on a large scale in the global arena.
PRECISION'S DEVELOPMENT IN THE OILFIELD SERVICES BUSINESS
Precision's development is best described in the context of its three
business segments which are distinguished by not only by the types of services
provided but also by their position on the continuum from start-up to maturity.
Contract Drilling includes drilling rigs, service rigs, hydraulic well assist
snubbing units, procurement and distribution of oilfield supplies, camp and
catering services, and manufacture, sale and repair of rig equipment. Technology
Services includes wireline, directional drilling, MWD, LWD services, separation
services, controlled pressure drilling, and the design, manufacture and
marketing of polycrystalline diamond compact drill bits. Rental and Production
includes oilfield equipment rental services and industrial process services.
The following graphs illustrate how each of the Contract Drilling,
Technology Services and Rental and Production segments have historically
contributed to Precision's profitability and investment.
[GRAPHIC OMITTED - BAR CHART]
[REVENUE ($ millions)]
------------------------------------------------
CD TS R&P
-- -- ---
1999 428.15 125.95 113.15
2000 739.61 352.10 159.00
2001 1004.27 614.15 194.57
2002 777.15 603.09 192.84
2003 992.82 714.39 210.72
------------------------------------------------
[GRAPHIC OMITTED - BAR CHART]
[OPERATING EARNINGS ($ millions)]
------------------------------------------------
CD TS R&P
-- -- ---
1999 98.42 6.80 9.99
2000 211.03 30.62 32.62
2001 298.73 52.26 39.36
2002 184.55 31.73 30.09
2003 285.73 4.84 39.35
------------------------------------------------
[GRAPHIC OMITTED - BAR CHART]
[CAPITAL SPENDING ($ millions)]
------------------------------------------------
CD TS R&P
-- -- ---
1999 27.67 9.138 15.8
2000 97.50 78.46 21.28
2001 122.58 203.54 27.35
2002 50.00 189.09 22.35
2003 99.03 177.75 15.16
------------------------------------------------
CONTRACT DRILLING - CANADA IS THE CORE - WORLDWIDE DRILLING IS IN SIGHT
The Contract Drilling segment is the current financial foundation of the
Corporation. Canadian business units within the segment are well established.
Each core business unit has undergone asset growth and has a lead market role
within Canada. Using the financial and operational leverage gained, the segment
continues to evolve within Canada with a view to exporting its capabilities to
niche markets worldwide.
Within Canada the segment has individual business units that are tightly
integrated in terms of operational management, safety, engineering, accounting
and senior management supervision and governance. Communication is a skill that
has been refined and ingrained in the operating culture. The strength to
successfully integrate acquisitions with vertical integration within and between
related ancillary business units has been developed through the handling of
acquisitions over the past 15 years.
Precision's roots began in Western Canada as a land drilling contractor and
the Corporation's 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 a 40% market share of
industry rigs. International operations in Venezuela commenced in 1992 with the
Sierra Drilling acquisition. Diversification into service rig 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 lead industry market share of 28%. The
additional acquisition in 2000 of coil tubing drilling rigs and other shallow
drilling rigs rounds out key milestones in our asset base growth.
While each business unit is at its own stage in the business life cycle
continuum, drilling has matured over the past three years. Today the business
has developed critical equipment mass and employee depth. It has developed
integrity-based systems that enable the business to evolve in meeting
fundamental industry challenges while delivering better profit and safety
performance. Employee retention and seasonal cycles remain a huge manpower
challenge for the industry. This condition is rather unique in that there is a
reasonable supply of equipment; it is the people element that keeps the market
in tight supply. The supply of experienced people yields profit leverage for
oilfield service companies, not just the "iron".
CORE BUSINESS ASSETS
Five Year History, end of year status
---------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
---------------------------------------------------------------------------------------------------------------------------
International (beyond Canada and the U.S.)
Drilling Rigs 19 16 15 12 11
United States
Drilling Rigs 1 1 4 2 0
Canada
Drilling Rigs - 33% of industry 225 226 229 230 211
Service Rigs - 28% of industry 239 240 257 257 76
Rig Assist Snubbing Units - 33% of industry 25 23 24 19 20
Oilfield Drilling Camps - 25% of industry 88 74 74 74 75
Enabling Infrastructure (Canada - in square feet)
Equipment Manufacture Facility 48,000 48,000 48,000 38,000 38,000
Consumable Supply Procurement and
Distribution Facility 40,000 40,000 40,000 40,000 40,000
---------------------------------------------------------------------------------------------------------------------------
The following tables provide a worldwide summary of Precision's drilling and
service rig fleets.
2003 2002
Type of Drilling Rig Depth CANADA/U.S. INTERNATIONAL TOTAL Canada/U.S. International Total
---------------------------------------------------------------------------------------------------------------------------
Single to 1,200 m 18 -- 18 17 -- 17
Super Single(R) to 2,500 m 15 4 19 16 4 20
Double to 3,000 m 96 7 103 96 6 102
Light triple to 3,600 m 47 6 53 48 5 53
Heavy triple to 7,600 m 39 2 41 39 1 40
Coiled tubing 11 -- 11 11 -- 11
---------------------------------------------------------------------------------------------------------------------------
Total fleet 226 19 245 227 16 243
---------------------------------------------------------------------------------------------------------------------------
Type of Service Rig - Canada 2003 2002 2001 2000 1999
---------------------------------------------------------------------------------------------------------------------------
Single 1 1 4 4 --
Freestanding mobile single 75 50 23 8 4
Mobile single 29 55 91 105 42
Double 57 58 60 59 24
Freestanding mobile double 6 6 5 4 --
Mobile double 46 45 48 50 --
Heavy double 7 7 9 9 2
Freestanding heavy double 2 2 -- -- --
Freestanding slants 16 16 16 16 4
Swab -- -- 1 2 --
---------------------------------------------------------------------------------------------------------------------------
Total fleet 239 240 257 257 76
---------------------------------------------------------------------------------------------------------------------------
As shallow natural gas drilling runs its course in Canada, our diverse and
versatile fleet of drilling and service rigs are very well positioned for the
eventual shift to deeper drilling prospects.
TECHNOLOGY SERVICES
The acquisition of Computalog Ltd. in 1999 marked the initial step in a
five-year strategy to develop the Technology Services business. The market for
downhole services was and still is dominated by three large multi-national
oilfield service companies. However, oil and gas exploration and production
companies are keen to see competition in the ranks of their service providers
and a niche was available to a smaller participant that could deliver quality
products and service. Precision's mature drilling operation provided the
reputation of a respected service provider and the financial backing required to
take on such a venture. In addition, the TS business provided the means to
participate in the offshore oil and gas exploration and production market.
The objectives of TS are the same today as they were in 1999. They are to
expand our product offering, globalize the presence of the whole Precision group
outside of Canada, and introduce a step change in technological capabilities of
what existed in TS and the industry. An advantage that TS had as a new
"greenfield" participant in the market was that it was not burdened by the
challenge of integrating new technology with old, nor need it be concerned with
the impact new technology might have on the economics of a substantial
investment in earlier generation technologies.
Initially, activities aimed at achieving TS objectives were undertaken
across a broad front. Since 1999 Precision has spent $133 million on its
research and engineering efforts. Much of this work was centered around
Advantage R&D, Inc. in Houston, Texas, which was established by Precision in
2000 with the mandate to develop the next generation of LWD and MWD tools.
Another significant element of the research and engineering program focused on
the development of our Rotary Steerable tools, which work was undertaken by
Smart Stabilizer Systems Ltd., a Precision subsidiary based in Cheltenham,
England.
Acquisitions, including Geoservices S.A in October 2000 and BecField
Drilling Services Ltd. in January 2001, were completed to gain access to
innovative technologies and to establish a presence in certain regional
international markets. By early 2001, TS had established regional centers in
seven strategic geographic areas around the world, namely Canada, the U.S.,
Mexico, Latin America, Europe/Africa, the Middle East and Asia/Pacific.
Technology Services revenue grew from $126 million in 1999 to $603 million
in 2002. A significant amount of this expansion came outside of the Canadian and
U.S. markets with the other regional operations accounting for 38% of revenue in
2002 compared to 14% in 1999. However, the scope of TS growth initiatives, in
terms of both geography and product lines, combined with the impact of delays in
the deployment of new technologies, resulted in operations support and
administrative organizations that were uneconomic for the start-up revenue
levels realized.
Fiscal 2003 can best be characterized as a "year of re-focus" for TS. A
number of management changes occurred during the year which changed the style
and culture of the TS segment. No longer is the segment purely focused on
revenue growth and geographic expansion. The renewed goal is profitable growth
in areas where we believe we can achieve an acceptable long-term return on our
investment.
RENTAL AND PRODUCTION
Precision entered this segment of its business in 1996 when it acquired
EnServ Corporation. Since then the Corporation has reduced the operations
carried on by this segment through strategic divestitures that took advantage of
attractive valuations to dispose of operations determined to be not core to
Precision's future growth plans. The industrial rental division was sold in
February 1999 and the gas compression operation was sold in March 2003. Each of
these transactions produced gains for the Corporation. Both of the businesses
currently carried on by the segment, namely, industrial plant maintenance and
oilfield equipment rental, have grown through acquisitions and the pursuit of
internal growth opportunities.
CEDA's plant maintenance operations have become increasingly focused on the
expanding activity in northern Alberta's oilsands regions. The acquisition of
JJay Exchanger Industries Ltd. in the second quarter of 2000 solidified the
segment's position in this market as a provider of all the required services in
a major refinery or petro-chemical plant turnaround/shutdown.
Innovation has also played an important role in CEDA's steady growth. Their
research and development efforts have grown out of their unique knowledge and
experience, with the focus on developing new tools and applications that are
marketable in the field. Examples of products that CEDA has introduced to the
market include the SuperLance(TM) System, which combined Precision's experience
in coil tubing drilling with water blasting technology to increase the
efficiency of cleaning coker units in refineries, and various adaptations of
robotics technology to increase the safety and timeliness of tank cleaning
operations.
The oilfield equipment rental business expanded its product offerings in
1997 with the acquisition of substantially all of the business assets of
Ducharme Oilfield Rentals Ltd. whose primary product line was the rental of
portable industrial housing, which is used at many remote drilling locations in
western Canada. Since then many initiatives have been undertaken to integrate
the delivery of products to customers and increase the profitability of
operations. Among them is the closure of the wellsite trailer manufacturing
facility in favour of less costly outsourcing arrangements in 2002 and more
recently the consolidation of all rental product lines to form Precision Rentals
Ltd. This latter move was in response to changing and growing customer needs to
simplify their purchasing decisions by providing one point of contact to access
all their rental needs.
RESULTS OF OPERATIONS
CONTRACT DRILLING
(STATED IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT PER DAY/HOUR AMOUNTS)
% OF % of % of
Years ended December 31, 2003 REVENUE 2002 Revenue 2001 Revenue
-----------------------------------------------------------------------------------------------------------------------------
Revenue $ 992,824 $ 770,147 $1,004,265
Expenses:
Operating 602,418 60.7 491,433 63.8 599,159 59.7
General and administrative 29,364 3.0 29,769 3.9 32,453 3.2
Depreciation 77,725 7.8 62,524 8.1 75,170 7.5
Foreign exchange (2,436) (0.3) 1,868 0.2 (1,254) (0.1)
-----------------------------------------------------------------------------------------------------------------------------
Operating earnings $ 285,753 28.8 $ 184,553 24.0 $ 298,737 29.7
-----------------------------------------------------------------------------------------------------------------------------
% INCREASE % Increase % Increase
2003 (DECREASE) 2002 (Decrease) 2001 (Decrease)
-----------------------------------------------------------------------------------------------------------------------------
Number of drilling rigs (end of year) 245 0.8 243 (2.0) 248 1.6
Drilling operating days (worldwide) 46,715 33.2 35,081 (25.6) 47,142 8.7
Revenue per operating day $ 15,984 (0.1) $ 16,008 (0.1) $ 16,097 15.3
Number of service rigs (end of year) 239 (0.4) 240 (6.6) 257 --
Service rig operating hours 439,519 12.1 392,210 (20.4) 492,480 121.3
Revenue per operating hour $ 462 3.6 $ 446 4.4 $ 427 12.4
-----------------------------------------------------------------------------------------------------------------------------
2003 COMPARED TO 2002
In financial terms, the Contract Drilling segment had a very good year in
2003 with a sharp rebound in Canadian drilling activity to 2001 levels, higher
international rig activity with fourth quarter growth and a moderate increase in
Canadian service rig activity. Snubbing and camps services were also more active
with equipment utilization improvement similar to drilling. While international
conditions were positive, seasonally adjusted Canadian performance strengthened
throughout 2003. In 2002, the quarterly trend was quite the opposite where in
Canada conditions were deteriorating after the torrid pace of 2001. For 2003,
segment revenues increased by 29% to $993 million, an improvement of $223
million over the prior year. Operating earnings increased by 55% to $286
million, an improvement of $101 million and 4.8 percentage points of revenue for
a margin improvement of 20%. Of the $101 million improvement in operating
earnings, 70% or $70 million of this is attributable to Canadian drilling rig
and service rig operations. This earnings improvement is attributable to more
equipment activity and higher pricing. The equipment activity increase, volume
factor, generated incremental operating earnings of $50 million over prior year
with higher pricing, price factor, generating $20 million virtually all of which
was generated in the second half of the year. Service rig performance is
noteworthy, as the operating earnings margin improvement was almost half the
total at $9 million or $21 per service rig operating hour.
International drilling operations experienced significant expansion in 2003
as operating earnings and operating days increased by 31% and 32%, respectively,
over 2002. The increased activity is attributable to additional rigs working in
Mexico and the commencement of operations in the Middle East and the
Asia/Pacific region.
In summary, current year performance is significantly ahead of 2002, and
close to the record setting performance of fiscal 2001.
Coming off a relatively weak 2002, fiscal 2003 steadily gained strength as
our customers stepped up field activity to increase production in an environment
where commodity price strength became more entrenched. With firm global oil
pricing and firm North American natural gas pricing, sustained demand for
Canadian Contract Drilling services throughout the year has allowed for strong
revenue rates as we exit the fourth quarter of 2003. In the Canadian market,
this is in sharp contrast to 2002, where rates were being undermined to start
the year and continued to erode during the year.
During 2003 Contract Drilling kept tight control on capital expenditures
with a focus to strengthen the existing asset base, grow international drilling
and be opportunistic to acquisitions within Canada. Capital expenditures,
including business acquisitions, totaled $106 million, representing an increase
of $55 million or 108% compared with 2002. The increase is primarily
attributable to asset base growth as the level of expenditure to upgrade our
existing asset base is a continual priority.
International drilling operations continued along a path of patient growth.
The rig count increased by three to exit the year at 19, with 10 in Mexico, two
in the Middle East, two in Asia/Pacific, and five in South America. There were
four additions and net one rig disposal. Three new rigs were built in Canada
with one deployed to Mexico, one to the Middle East and one platform rig to the
Asia/Pacific region. The fourth rig is a retrofitted mechanical light triple
deployed to Mexico from the Canadian fleet. A net one rig ownership interest in
Argentina was disposed of during the year. The platform-mounted rig 703 is of
particular interest as it is Precision's first offshore drilling rig. The rig
was mobilized for Asia/Pacific late in the year and is not expected to start
operations until the second quarter of 2004.
[GRAPHIC OMITTED - PIE CHART]
[GEOGRAPHIC DISTRIBUTION OF
CONTRACT DRILLING REVENUE (2003)]
-----------------------------------
Canada Mexico Rest of World
------ ------ -------------
88 7 5
-----------------------------------
In Canada, our asset base expanded with the acquisition of two snubbing
units, 19 oilfield camps and the construction of one new generation single
drilling rig, a Super Single(R) Light with a 1,200 metre depth rating. A second
such rig commenced drilling in February 2004. Asset reductions include the
decommissioning of one drilling and one service rig, the sale of one surface
hole drilling rig and one camp and the transformation of certain four unit camps
into six unit configurations.
Canada spurred the improved financial performance on the strength of record
shallow natural gas well drilling activity.
o Canadian drilling rig activity increased 36% over prior year to 42,725
operating days and 52% utilization, an improvement of 11,362 days and 14
utilization percentage points.
o Service rig activity increased 12% over prior year to 439,519 operating
hours and 50% utilization, an improvement of 47,309 hours and five
utilization percentage points.
o Snubbing unit activity increased 39% over prior year to 4,322 utilization
days and 54% utilization, an improvement of 1,210 days and 12 utilization
percentage points.
o Camp activity increased 38% over prior year to 12,451 camp days and 39%
utilization, an improvement of 3,406 days and 6 utilization percentage
points.
International drilling rig activity increased 32% over prior year to 3,990
operating days, an improvement of 975 days. Two thirds of the additional days
occurred in the Mexico operations where additional rigs were put to work with
the extension of the Burgos integrated services project. Drilling operations ran
for a full year in the Asia/Pacific region adding 280 days to the increase in
2003 while Middle East operations commenced in the fourth quarter of 2003.
Looking ahead to 2004 we carry strong momentum in all business lines within
the segment.
o Precision Drilling International's drilling operation is expected to
benefit from a full year of 2003 growth in the Middle East and Asia/Pacific
regions. We expect operations in Venezuela to carry forward at current
levels.
o Precision Drilling in Canada is off to an excellent first quarter start
with drilling rig activity 4% ahead of 2003 and superior operating earning
margins.
o Precision Well Servicing in Canada is off to an even better first quarter
start with service rig activity 8% ahead of 2003 and superior operating
earnings margins.
o Live Well Service and LRG Catering are also ahead of last year's pace as
natural gas drilling and production activity is generating strong demand
for snubbing and camp/catering services.
2002 COMPARED TO 2001
The asset base for Contract Drilling was virtually unchanged during 2002,
as there were no additions and certain rigs, 4 drilling and 17 service, were
taken out of service. The reasons for the decline in activity in 2002 compared
to 2001 were two-fold. First, competition and industry capacity continued to
increase, albeit at a slower pace, as competitors continued to build new
equipment. Available rigs in Canada reached an all-time record high. Second,
although the fourth best year ever in western Canada in terms of well
completions, 2002 was characterized by low risk drilling whereby short duration
shallow gas wells were dominant. A lack of confidence in energy commodity
pricing triggered conservative spending by our customers. This was noteworthy as
drilling parameters serve as a lead indicator for most future energy services
within a region. There were 14,459 wells drilled in Canada in 2002, a mark that
resulted in a drilling rig activity decline of 27% to 31,363 operating days for
Precision in Canada representing a 38% utilization rate, a post-1992 low.
Service rig activity declined 20% to 392,210 hours in Canada (44% utilization).
Our service rig work was split one-third new well completion with the remaining
two-thirds directed towards the workover of existing wells in production.
Snubbing unit activity declined 15% and camp and catering days declined 37% to
9,041 days (33% utilization).
Capital expenditures were managed to closely match changes in demand for
our existing asset base. Measures of demand include utilization, revenue and
operating earnings. Compared to the prior year service and drilling rig
utilization declined a combined 24%, capital expenditures declined 59%, revenue
decline of 23% and operating earnings declined 38%.
In terms of operating earnings, the $114 million dollar decline over prior
year was due to a volume reduction of $71 million due to lower equipment
utilization, with the remaining $43 million due to price competitiveness
resulting in lower rig dayrates and less coverage of fixed infrastructure costs.
Drilling and service rig dayrates were strong in the first quarter of 2002 as
record 2001 performance momentum carried forward through winter drilling.
However, as the remaining three quarters progressed, steadily softening demand
continued to erode operating margins and Contract Drilling exited the year with
margins at 52 week lows.
TECHNOLOGY SERVICES
(STATED IN THOUSANDS OF CANADIAN DOLLARS)
% OF % of % of
Years ended December 31, 2003 REVENUE 2002 Revenue 2001 Revenue
------------------------------------------------------------------------------------------------------------------------------
Revenue $ 714,385 $ 603,088 $ 614,152
Expenses:
Operating 523,105 73.2 463,632 76.9 404,577 65.9
General and administrative 70,619 9.9 80,751 13.4 75,468 12.3
Depreciation and amortization 75,578 10.6 53,347 8.8 47,694 7.8
Research & engineering 42,419 5.9 34,862 5.8 31,677 5.1
Foreign exchange (2,178) (0.3) 2,229 0.4 2,479 0.4
Operating earnings (loss) $ 4,842 0.7 $ (31,733) (5.3) $ 52,257 8.5
------------------------------------------------------------------------------------------------------------------------------
% INCREASE % Increase % Increase
2003 (DECREASE) 2002 (Decrease) 2001 (Decrease)
------------------------------------------------------------------------------------------------------------------------------
Wireline jobs performed 38,403 24.6 30,813 (18.6) 37,845 28.6
Directional wells drilled 2,954 78.6 1,654 44.1 1,148 15.1
Well testing/CPD man days (Canada only) (1) 53,377 8.4 49,227 (18.1) 60,135 43.9
------------------------------------------------------------------------------------------------------------------------------
(1) CONTROLLED PRESSURE DRILLING (CPD).
2003 COMPARED TO 2002
As noted earlier, 2003 was a year of transition for Technology Services
with new management changing the focus of the business from top line growth and
geographic expansion to enhanced bottom line profitability. Return on capital
employed is now the yardstick by which success is measured and investment
decisions are guided. The transition is not complete, however, significant
improvements were achieved in all regions and we will strive to make further
progress in 2004.
Notable accomplishments in 2003 include the following:
o Non-profitable product lines were shut down in many regions. This is
consistent with another key element of the Technology Services strategy
going forward. That being, not trying to be everything to everybody
everywhere. The segment will focus on what it is good at in regions where
economies of scale will contribute to profitable operations.
o Other businesses were rationalized and re-focused. In some instances this
involved consolidating management functions where geographically possible.
In others it meant trimming cost structures to better match anticipated
revenue levels and renegotiating customer contracts to recognize additional
services being provided.
o Non-core businesses were identified. The sale of one such business, Fleet
Cementers, Inc., was completed in February 2004, and a similar transaction
is being pursued with respect to Polar Completions.
o TS was successful in signing a number of large contracts throughout the
world on which the Corporation will use its new technologies.
o A technology review was completed in the third quarter which provided the
direction for our research and engineering work for the next few years.
This review centered on a road map for a development plan that considers
key customer needs and requirements, identifies the related project
parameters, and set priorities.
o The first phase of the segment's Enterprise Resource Planning information
system implementation project was completed in the fourth quarter when the
Canadian operations went live on the software. The new system and processes
are already beginning to pay dividends in terms of expense analysis and
additional information available to manage the business.
One critical factor that hampered the roll out of our new suite of tools in
the first part of 2003 was the ability for the hostile environment logging
(HEL(TM))/LWD tool to demonstrate that it could reliably perform in many
different geological environments. The fourth quarter saw a step change in the
reliability of these tools. The mean time between failure almost quadrupled in
December and that success has continued in early 2004. This operating
reliability allows our customers to also see the technological advantages of our
tools which are demonstrating logging speeds well in excess of existing industry
standards. The HEL(TM)/LWD tools now appear to be nearing the end of the process
of evolving from a science project to a viable business. We began the project by
designing and building tools to collect high quality geological and geophysical
information. The next phase focused on collecting that information in a reliable
and efficient manner, which is what we accomplished in the latter half of 2003.
We are now starting to generate advanced interpretation products from that
information and should be able to grow the business using our existing wireline
infrastructure such as our computing and interpretation centers in Calgary and
Houston.
With respect to our Rotary Steerable tool, although several runs have been
completed with over 125 hours in the hole, we are having some reliability
challenges of the same nature as we experienced with the HEL(TM)/LWD tools in
early 2003. The tools have demonstrated superior capability to generate high
build angles and to kick off directionally from a vertical wellbore, both of
which add efficiencies to our customers' drilling operations.
[GRAPHICS OMITTED - BAR CHARTS]
[GEOGRAPHICAL DISTRIBUTION OF REVENUE]
[2003, 2002, 2001]
----------------------------------------------------------------------------
Canada US Mexico Rest of World TOTAL REVENUE
------ -- ------ ------------- -------------
2003 44 22 19 15 $714 MILLION
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canada US Mexico Rest of World TOTAL REVENUE
------ -- ------ ------------- -------------
2002 38 22 19 21 $603 MILLION
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canada US Mexico Rest of World TOTAL REVENUE
------ -- ------ ------------- -------------
2001 47 29 6 18 $614 MILLION
----------------------------------------------------------------------------
Revenue increased by $111 million or 18% in 2003 over 2002. All of the
increase came from the Canada, U.S. and Mexico operations. Operations in Canada
increased in conjunction with increased drilling activity. This increased demand
for services also resulted in generally improved pricing. Similarly, revenue and
pricing in the U.S. operation responded to the increase in the average rig count
from 830 in 2002 to 1,030 in 2003. The Mexico business benefited from the
extension of the Burgos integrated services project and from the award of
additional contracts outside of that project.
Combined revenue from the segment's other regional operations was flat year
over year. Increased revenue associated with a large wireline contract with a
Canadian-based company in the Middle East was offset by reduced controlled
pressure drilling work in the North Sea. Although it improved late in the year,
activity in Venezuela was also lower than 2002 as a result of the political
unrest in that country. Other countries in the region have improved over the
last half of the year.
Profitability of the segment improved year over year moving from an
operating loss in 2002 of $32 million to earnings of $5 million in 2003. The
effort to review and rationalize businesses in TS brought with it incremental
expenses in the form of severance and closure costs and write-downs of unusable
assets. These expenses totaled $15 million in 2003. Operating and general and
administrative expenses declined as a percentage of revenue due to cost
reduction initiatives and economies of scale associated with certain fixed
infrastructure costs. However, continued improvements are anticipated as we
further develop our execution plan. This involves refining our personnel
development, recruiting and training programs to make sure we have the
appropriate people in place to facilitate the utilization of assets. It also
involves standardizing our maintenance systems and operating procedures, all
standard things that must be put in place to provide the foundation upon which
to grow.
An important element in continuing the profitability improvements in TS is
increased utilization of the new tools being put into service. Currently the
jobs being performed are usually isolated from one another requiring backup
equipment for every location. As customer acceptance increases, more jobs will
be occurring simultaneously in one geographic region requiring less backup
equipment on a per job basis. Plans are also in place to refine our
manufacturing processes to reduce the overall cost of tools being built. These
developments should serve to reduce depreciation expense as a percentage of
revenue.
Research and engineering expenditures increased in 2003 as tool development
programs moved from the laboratory to field operations. During the initial
stages of the roll out, product support initiatives were being performed by the
research and engineering teams. With the commercialization of operations, this
work has been transferred to the operations groups. The target for sustained
research and engineering expenditures is 5% of revenue.
2002 COMPARED TO 2001
TS continued its geographic diversification efforts in 2002. Revenue
declined by $11 million or 1.8% in 2002 compared to 2001. The Canadian and U.S.
operations saw revenue decline as a result of reduced activity levels. The year
over year decline in the number of wells drilled amounted to approximately 20%
in both markets. The U.S. operations were also hampered by delays in the roll
out of the new suite of tools.
Revenue increased in all regions outside of Canada and the U.S. as the
segment's expanded international presence facilitated the participation in a
broader spectrum of projects. The political situation in Venezuela did have a
negative effect on revenue as oil and gas production activity in that country
was virtually shut down in the last six weeks of the year.
Having set up regional operations centers in 2001, the strategy was to
establish brand recognition for Precision through successful completion of
competitively bid projects. With these expanded operations, Precision increased
its recognition as a viable alternative to the historical group of oilfield
service providers in many international markets. However, the scope of the TS
growth initiatives, in terms of both geography and product lines, combined with
the impact of delays in the deployment of new technologies, resulted in
operations support and administrative organizations that were uneconomic for the
start-up revenue levels realized. This is also reflected in operating and
general and administrative expense which grew 13.4% while revenue declined by
1.8%.
RENTAL AND PRODUCTION
(STATED IN THOUSANDS OF CANADIAN DOLLARS)
% OF % of % of
Years ended December 31, 2003 REVENUE 2002 Revenue 2001 Revenue
-----------------------------------------------------------------------------------------------------------------------
Revenue $ 210,724 $ 192,840 $ 194,567
Expenses:
Operating 147,911 70.2 139,781 72.5 132,832 68.3
General and administrative 10,479 5.0 9,518 4.9 9,484 4.9
Depreciation 12,533 5.9 13,159 6.8 13,388 6.9
Foreign exchange 451 0.2 292 0.2 (502) (0.3)
-----------------------------------------------------------------------------------------------------------------------
Operating earnings $ 39,350 18.7 $ 30,090 15.6 $ 39,365 20.2
-----------------------------------------------------------------------------------------------------------------------
% INCREASE % Increase % Increase
2003 (DECREASE) 2002 (Decrease) 2001 (Decrease)
-----------------------------------------------------------------------------------------------------------------------
Equipment rental days (000's) 820 35.1 607 (34.4) 925 37.9
Plant maintenance man-days (000's) 272 5.0 259 12.6 230 15.0
----------------------------------------------------------------------------------------------------------------------
2003 COMPARED TO 2002
Revenue in the Rental and Production segment increased by 9% in 2003
compared to 2002. Both the oilfield equipment rental and industrial plant
maintenance operations contributed to the increase. Equipment rental days
increased in conjunction with increased drilling activity and operating earnings
in this business improved significantly as most expenses are fixed in nature.
The cornerstone to the plant maintenance operations continues to be the
work performed at the oilsands projects in northern Alberta. The division's
ability to offer the complete suite of cleaning, mechanical, catalyst and
dredging services required to maintain these large projects, and the continued
training and development of its employees, differentiates it from its
competitors. Recognition of the value this business brings to its customers has
resulted in continued steady revenue growth and consistent operating margins.
2002 COMPARED TO 2001
Revenue declined modestly as reductions in the oilfield equipment rental
business was only partially offset by increases in the industrial plant
maintenance operation. The rental business saw revenue decline in conjunction
with reduced Canadian drilling activity. This also impacted overall segment
profitability as the rental business has higher margins than the plant
maintenance business.
The plant maintenance business benefited from commissioning work performed
at a new heavy oil upgrading plant and continued high levels of maintenance work
at oil sands projects in northern Alberta. Operating margins were consistent
with 2001. During the year, this business was expanded through the acquisition
of a vacuum truck operation in northern Alberta.
OTHER ITEMS
2003 COMPARED TO 2002
CORPORATE AND OTHER EXPENSES
Expenses in the Corporate and Other segment increased by $4.1 million in
2003 compared to 2002. In contrast to last year, variable compensation payments
tied to corporate performance increased in 2003. In addition, directors and
officers insurance premiums have increased as a result of increased scrutiny of
corporate governance practices of public equity market participants in North
America and around the world. General and administrative expenses are also
affected by the ongoing requirements surrounding Sarbanes-Oxley legislation.
INTEREST EXPENSE
Net interest expense remained constant at $35 million in 2003 and 2002. The
impact of a $24 million increase in average debt outstanding was offset by
reduced interest rates. As anticipated at the end of last year, interest
coverage, defined as operating earnings divided by net interest expense,
returned to 2001 levels. Interest coverage in 2003, 2002 and 2001 was
approximately 9, 4 and 8 times respectively, and is expected to improve in 2004
with the free cash flow being generated.
INCOME TAXES
The Corporation's effective tax rate on earnings from continuing operations
before income taxes, non-controlling interest and goodwill amortization in 2003
was 27.3% compared to 25.3% in 2002. The Alberta government reduced tax rates by
0.5% in each of 2003 and 2002. Canadian GAAP requires that the effect of these
rate reductions be reflected as a decrease of future tax expense. The impact of
these rate reductions on tax expense was similar in 2003 and 2002 at $3 million
and $2.6 million respectively. However, given the higher before tax earnings in
2003 compared to 2002, the impact of the reductions on the Corporation's
effective tax rate amounted to 1.1 percentage points in 2003 versus 2.1 in 2002.
Similarly, the Corporation's organization structure generates tax savings
which, in absolute dollar terms, are relatively consistent from year to year. In
2003 these tax savings reduced the effective tax rate by 4.1 percentage points
compared to 9.4 in 2002.
In the absence of the above factors the Corporation's effective tax rate
would have been 32.6% in 2003 compared to 36.8% in 2002. This decrease is a
reflection of the tax rate reduction initiatives of the Canadian Federal and
Alberta Provincial governments and of the mix of income from different tax rate
jurisdictions. The Corporation's effective tax rate is expected to be in the
range of 32 - 34% in 2004.
2002 COMPARED TO 2001
CORPORATE AND OTHER EXPENSES
Net expenses for Corporate and Other declined by $1.2 million in 2002
compared to 2001. The primary reason was the reduction in variable compensation
payments, which are tied to corporate performance.
INTEREST EXPENSE
Net interest expense declined by $7.9 million in 2002 as a result of
reduced cost of borrowing due to declining interest rates and reduced borrowing
levels. The average debt outstanding in 2002 was $568.4 million compared to
$630.8 million in 2001. Interest coverage, defined as operating earnings divided
by net interest expense, declined to 4 times in 2002 compared to 8 times in
2001.
INCOME TAXES
The effective tax rate on earnings before income taxes and goodwill
amortization was 25.3% in 2002 compared to 35.6% in 2001. This reduction is due
to the combined impact of tax rate reductions instituted by both the Alberta and
Canadian governments and income taxed in jurisdictions with lower tax rates.
The effective tax rate in 2002 and 2001 was reduced by 0.5% and 2%,
respectively, as a result of tax rate decreases enacted by the Alberta
government in those years. Canadian GAAP required that the effect of these rate
reductions be reflected as a decrease of future tax expense. The impact of these
rate reductions was $2.6 million in 2002 and $6.0 million in 2001.
GOODWILL AMORTIZATION
In 2001, standards under both Canadian and U.S. GAAP were issued that
eliminated the amortization of goodwill. These rules were adopted January 1,
2002 by the Corporation.
LIQUIDITY AND CAPITAL RESOURCES
Historically the oilfield services business has been very cyclical. In
managing the risk of this volatility, Precision has adhered to its philosophy of
maintaining a strong balance sheet. In addition, a strong balance sheet has
allowed the Corporation to grow through acquisition by providing the financial
flexibility to respond to attractive investment opportunities in the form of
both acquisitions and internal growth. The following graph gives a historical
perspective on how Precision has managed its cash flows and its debt levels.
[GRAPHIC OMMITTED - BAR/LINE CHART]
[INVESTMENT, CASH FLOW and CAPITALIZATION]
--------------------------------------------------------------------------------
Debt to Capitalization Investment Equals Net
Equals the Ratio of Cash Cost of Capital
Long-term Debt to Long- Expenditures and Business Cash Flow Equals Funds
term Debt Plus Equity Acquisitions From Operations
----------------------- ------------------------- ----------------------
1999 20 39 101
2000 31 545 298
2001 26 372 449
2002 25 244 188
2003 19 297 358
--------------------------------------------------------------------------------
In 2004 the Corporation expects cash flow from operations to approach $400
million and net capital expenditures to amount to approximately $320 million.
Another significant source of cash has been proceeds from the exercise of
employee stock options, which has contributed an average of $23 million over
each of the past three years ended December 31, 2003. In January 2004 the
Corporation received $25 million from the exercise of options and the total
amount for the year is anticipated to exceed $50 million.
As a Corporation with multiple lines of business, Precision also regularly
assesses each unit from the perspective of strategic fit with future growth
plans and profitability improvement initiatives. In 2003 the Corporation
received $67 million from the sale of business units identified as non-core,
primarily the gas compression business carried on by Energy Industries Inc. In
February 2004, the Corporation completed the sale of substantially all of the
assets of Fleet Cementers, Inc. realizing proceeds of approximately $26 million
(US$20 million). A similar transaction is being pursued with respect to the
Polar Completions division.
The Corporation exited 2003 with a long-term debt to long-term debt plus
equity ratio of 19% and a ratio of long-term debt to trailing cash flow from
operations of 155%. Both measures showed improvement over 2002 when these ratios
amounted to 25% and 258% respectively. Continued improvement is expected in
2004, barring the impact of any significant acquisitions.
Precision has a number of lines of credit available to finance its
activities, the most significant of which is a $350 million extendable revolving
unsecured facility with a syndicate led by a Canadian chartered bank. At
December 31, 2003, $140 million had been borrowed under this facility, the
majority of which was used to finance working capital requirements. Canadian
oilfield activity peaks in the first quarter of every year with a
swift reduction in the second quarter due to spring breakup which precludes the
movement of heavy equipment. As a result, accounts receivable are expected to
increase by approximately $175 million during the first quarter with a similar
reduction in the second quarter.
The Corporation's contractual obligations are outlined in the following
table:
(STATED IN THOUSANDS OF CANADIAN DOLLARS) Payments Due by Period
Less Than After
Total 1 Year 1 - 3 Years 4 - 5 Years 5 Years
---------------------------------------------------------------------------------------------------------------------------
Long-term debt $ 415,951 $ 16,566 $ 239,570 $ -- $ 159,815
Capital lease obligations 629 592 37 -- --
Operating leases 110,500 28,104 49,566 11,168 21,662
---------------------------------------------------------------------------------------------------------------------------
Total contractual obligations $ 527,080 $ 45,262 $ 289,173 $ 11,168 $181,477
---------------------------------------------------------------------------------------------------------------------------
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 Corporation's significant accounting policies are
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
Corporation'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
The Corporation 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. The Corporation'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 gas industry
and the inherent risk of successfully finding hydrocarbon reserves, a customer's
ability to fulfill its payment obligations can change suddenly and without
notice. In addition, many of our customers are located in international areas
that are inherently subject to risks of economic, political and civil
instabilities, which may impact our ability to collect those accounts
receivable.
EXCESS AND OBSOLETE INVENTORY PROVISIONS
Quantities of inventory on hand are regularly reviewed and provisions for
excess or obsolete inventory are established based on historical usage patterns
and known changes to equipment or processes that would render specific items no
longer usable in operations. Significant or unanticipated changes in business
conditions could impact the amount and timing of any additional provision for
excess or obsolete inventory that may be required. The TS segment of our
operations involves the application of new technologies in its efforts to
deliver superior products to our customers and therefore has a greater risk of
obsolescence due to finding or developing better products. The TS inventories
comprise 87% of our total inventory of $99 million. These inventories are
reviewed on a quarterly basis to assess the appropriateness of quantities and
valuation.
IMPAIRMENT OF LONG-LIVED ASSETS
Long-lived assets, which includes property, plant and equipment,
intangibles and goodwill, comprise the majority of the Corporation'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 the Corporation 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 2003 the Corporation
completed its goodwill assessment incorporating the work of independent
valuation experts resulting in the conclusion that there was no impairment of
the carrying value.
DEPRECIATION AND AMORTIZATION
The Corporation'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. The high
depreciation expense associated with the TS segment is anticipated to improve
with the optimization of equipment fleet sizes in each geographic region.
INCOME TAXES
The Corporation uses 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 clarification of uncertain tax regimes may require changes
to the valuation allowances associated with the Corporation's future tax assets.
NEW ACCOUNTING STANDARDS
In 2003 the Canadian Institute of Chartered Accountants issued revised
recommendations with respect to accounting for stock based compensation.
Effective January 1, 2004 the Corporation will retroactively apply these new
standards to all common share purchase options granted in 2002 and subsequent
years. Under the new standard, the fair value of common share purchase options
will be calculated at the date of grant and that value will be recorded as
compensation expense over the vesting period of those grants. Under the previous
Canadian accounting standard, the Corporation had the choice of using the
intrinsic value method of accounting for grants of common share purchase
options, which resulted in no associated compensation expense being recognized,
and disclosing in a note to the financial statements the impact of expensing the
fair value of option grants. This alternative still exists under U.S. generally
accepted accounting principles.
BUSINESS RISKS
CRUDE OIL AND NATURAL GAS PRICES
The price received by our customers for the crude oil and natural gas they
produce has a direct impact on cash flow available for them to finance the
acquisition of services provided by the Corporation.
Prices for crude oil are established in a worldwide market in which supply
and demand are subject to a vast array of economic and political influences.
This results in very volatile pricing; a prime example of which is West Texas
Intermediate crude oil trading at US$12 per barrel in late 1998 and in excess of
US$40 per barrel at one point in 2000. Natural gas prices are established in a
more "local" North American market due to the requirement to transport this
gaseous product in pressurized pipelines. Demand for natural gas is seasonal and
is correlated to heating and electricity generation requirements. Demand for
natural gas and fuel oils is also affected by consumers ability to switch from
one to the other to take advantage of relative price variations.
The Corporation partially manages the risk of volatile commodity prices,
and thus volatile demand for its services, by striving to maintain cost
structures that are scalable to activity levels. However, cost structures in
Contract Drilling are more variable in nature than those within TS. In addition,
our strong balance sheet and adherence to conservative financing practices
provide the resilience to withstand and benefit from downturns and upturns in
the business cycle.
North American oilfield service activity is focused on natural gas. One
objective of the Corporation's international growth initiatives is to increase
our exposure to crude oil activity in less cyclical markets.
WORKFORCE AVAILABILITY
The Corporation's ability to provide reliable services is dependent upon
the availability of well trained, experienced crews to operate our field
equipment. We must also balance the requirement to maintain a skilled workforce
with the need to establish cost structures that vary as much as possible with
activity levels.
Within Contract Drilling, our most experienced people are retained during
periods of low utilization by having them fill lower level positions on our
field crews. The Corporation has established training programs for employees new
to the oilfield service sector and we work closely with industry associations to
ensure competitive compensation levels and to attract new workers to the
industry as required.
Many of our Canadian businesses are currently experiencing manpower
shortages. Over 50 drilling rigs have been running without relief crews,
requiring them to shut down when crews need time off. Technology Services
Canadian operations have been supported by additional people and equipment
brought in from other regional operations to meet peak winter demand.
WEATHER
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 winter's frost comes out of the ground rendering many secondary
roads incapable of supporting the weight of heavy equipment until they have
thoroughly dried out. The duration of this "spring breakup" has a direct impact
on the Corporation's activity levels. In addition, many exploration and
production areas in northern Canada are accessible only in winter months when
the ground is frozen hard enough to support equipment. The timing of freeze up
and spring breakup affects the ability to move equipment in and out of these
areas.
Working with customers, we strive to position equipment where possible such
that it can be working on location during spring breakup, limiting the need to
move equipment during this time period as much as possible. However, many
uncontrollable factors affect our ability to plan in this fashion and the spring
breakup, which can occur any time from late March through May, is traditionally
our slowest time.
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. Recently, development of directional and horizontal
drilling, controlled pressure drilling, coil tubing drilling, and methods of
providing real time data during drilling and production operations have
increased production volumes and the recoverable amount of discovered reserves.
Innovations such as 3-D and 4-D seismic have improved the success rate of
exploration wells partially offsetting the decline in the quantity of drillable
prospects.
Our ability to deliver more efficient services is critical to our continued
success. The Corporation has continuously built upon its experience and teamed
with customers to provide solutions to their unique problems. Our ability to
design and build specialized equipment has kept us on the leading edge of
technology. The success of our in-house designed and built Super Single(R) rig,
both in Canada and abroad, is testimony of our dedication to these efforts.
The continued development of our Technology Services segment, and in
particular the research and development work of Advantage R&D, Inc., puts the
Corporation at another level where high-end technological innovation is
paramount to success. We have a team of highly qualified experienced
professionals, that has been assembled and working together for over two years
in state-of-the-art testing facilities. The technologies they have developed
over this time are at or near the commercial deployment stage, however, the
success of future technological endeavours is never certain.
ACQUISITION INTEGRATION
The Corporation has worked towards its strategic objective of becoming an
integrated service provider of sufficient size to benefit from economies of
scale and to provide the foundation from which to pursue international
opportunities. Business acquisitions have been an important tool in this pursuit
and will continue to be so in the future. Continued successful integration of
new businesses, people and systems is key to our future success.
FOREIGN OPERATIONS
The Corporation is working hard to export its expertise and technologies to
oil and gas producing regions around the world. With this comes the risk of
dealing with business and political systems that are much different than we are
accustomed to in North America. The Corporation has hired employees who have
experience working in the international arena and it is committed to recruiting
qualified resident nationals on the staffs of all of its international
operations.
FOREIGN CURRENCY EXCHANGE RATES
The Corporation has a number of sources of foreign currency exchange risk.
On international contracts, attempts are made to structure revenue streams such
that a portion sufficient to match local expenditures is denominated in the
local currency, with the remainder being denominated in U.S. dollars. In
addition, many of our business units buy a portion of their parts and supplies
from suppliers in the United States. Also, the manufacturing effort associated
with the deployment of the new suite of tools is taking place in the U.S. As a
result, the Corporation is presently a net payer of U.S. dollars.
MERGER AND ACQUISITION ACTIVITY
Merger and acquisition activity in the oil and gas exploration and
production sector can impact demand for our services as customers focus on
reorganization activities prior to committing funds to significant drilling and
maintenance projects. Future merger and acquisition activity could have a
short-term impact on our business, but in the long-term should result in a
stronger, more active market.
OUTLOOK
The fortunes of the oilfield services business are dictated by current and
anticipated future crude oil and natural gas prices. The supply and demand
fundamentals that have brought prices to today's relatively high levels are not
expected to change rapidly. Energy price prognosticators have historically
focused on the supply side of the equation where geopolitical events can have a
large impact on short-term supply and where consensus was generally that there
was abundant supply to fill long-term requirements. This view is now starting to
be questioned in some corners. The surplus crude oil production capacity of the
Middle East is being examined with suggestions that it is not as high as once
thought. Similarly, the ability to rapidly increase production of the vast crude
oil reserves in the former Soviet Union is being slowed by the recognition of
the large amount of infrastructure investment required. Recent world events have
also brought security of supply issues to the top of the energy agenda for many
countries.
The North American natural gas market is also facing supply challenges.
Natural gas directed drilling activity has increased significantly in recent
years, however this has only served to maintain production. Liquefied natural
gas, once viewed as the element that would increase gas supplies and thus reduce
prices, is now being thought of as a requirement to fill the void between future
demand requirements and conventional production capabilities. It is not
anticipated that the price of natural gas will experience sustained downward
pressure from the supply side of the pricing equation any time soon.
Many analysts are now looking at the demand elements of energy pricing
economics. Commodity prices have risen over the last number of years in an
environment where the major economies of the world were generally in a period of
slow growth. This is changing as growth rates in the major industrialized
countries are beginning to recover. Of particular importance to the outlook for
the demand for energy is the emergence of countries such as China where economic
expansion is bringing new found purchasing power to a very large population. On
a per capita basis, these populations use energy at a fraction of the rate of
other industrialized nations. This should change as new products, such as
automobiles and electric appliances, are introduced to these markets which in
turn should drive exponential growth in energy demand.
On the basis of these fundamentals, Precision is optimistic about the
prospects to operate and grow our businesses profitably. Canada will play a
major role in supplying the energy needs of North America and our dominant
position in that market will continue to be the cornerstone of the Corporation.
From this strong foundation we will continue to step out into international
markets where the opportunities are such that operations can reach an efficient
size in a reasonable time frame. The strength of our balance sheet will allow us
to examine acquisition opportunities that may allow this process to be
accelerated.
MANAGEMENT'S REPORT TO THE SHAREHOLDERS
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 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 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 Corporation's financial results prepared in accordance
with Canadian GAAP. The MD&A compares the audited financial results for the
twelve months ended December 31, 2003 to December 31, 2002 and the twelve months
ended December 31, 2002 to December 31, 2001. Note 15 to the consolidated
financial statements describes the impact on the consolidated financial
statements of significant differences between Canadian and United States GAAP.
Management maintains appropriate systems of internal control. Policies and
procedures are 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 Corporation's most recent Annual and
Special Meeting, to audit the consolidated financial statements in accordance
with generally accepted auditing standards in Canada and provide an independent
professional opinion.
The Audit Committee of the Board of Directors, which is comprised of three
independent and unrelated directors who are not employees of the Corporation,
has discussed the consolidated financial statements, including the notes
thereto, with management and external Auditors. The consolidated financial
statements have been approved by the Board of Directors on the recommendation of
the Audit Committee.
/s/ Hank B. Swartout /s/ Dale E. Tremblay
-------------------------------- ----------------------------------
HANK B. SWARTOUT (signed) DALE E. TREMBLAY (signed)
Chairman of the Board, President Senior Vice President Finance
and Chief Executive Officer and Chief Financial Officer
February 10, 2004
39
AUDITORS' REPORT TO THE SHAREHOLDERS
We have audited the consolidated balance sheets of Precision Drilling
Corporation as at December 31, 2003 and 2002 and the consolidated statements of
earnings and retained earnings and cash flow for each of the years in the
three-year period ended December 31, 2003. These consolidated financial
statements are the responsibility of the Corporation'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 Corporation as at December
31, 2003 and 2002 and the results of its operations and its cash flow for each
of the years in the three-year period ended December 31, 2003 in accordance with
Canadian generally accepted accounting principles.
/s/ KPMG LLP
---------------------
KPMG LLP (signed)
Chartered Accountants
Calgary, Canada
February 10, 2004
CONSOLIDATED BALANCE SHEETS
------------------------------
As at December 31, (stated in thousands of dollars) 2003 2002
--------------------------------------------------------------------------------------------------------------
ASSETS
Current assets:
Cash $ 21,370 $ 17,315
Accounts receivable 544,850 431,331
Income taxes recoverable -- 8,712
Inventory (NOTE 3) 99,088 92,744
Assets of discontinued operations (NOTE 20) 21,150 51,725
--------------------------------------------------------------------------------------------------------------
686,458 601,827
Property, plant and equipment, net of accumulated depreciation (NOTE 4) 1,588,250 1,457,273
Intangibles, net of accumulated amortization of $19,844 (2002 - $13,792) 65,262 71,355
Goodwill 527,443 527,443
Other assets (NOTE 5) 8,932 17,443
Assets of discontinued operations (NOTE 20) 32,040 84,674
$2,908,385 $2,760,015
--------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Bank indebtedness (NOTE 6) $ 147,909 $ 95,321
Accounts payable and accrued liabilities (NOTE 18) 260,545 257,913
Incomes taxes payable 7,373 --
Current portion of long-term debt (NOTE 7) 17,158 27,098
Liabilities of discontinued operations (NOTE 20) 5,212 11,239
--------------------------------------------------------------------------------------------------------------
438,197 391,571
Long-term debt (NOTE 7) 399,422 514,878
Future income taxes (NOTE 11) 320,599 311,164
Future income taxes of discontinued operations (NOTE 20) 1,107 7,383
Non-controlling interest 3,771 2,019
Shareholders' equity:
Share capital (NOTE 8) 936,529 912,916
Retained earnings 808,760 620,084
--------------------------------------------------------------------------------------------------------------
Commitments and contingencies (NOTES 10 AND 19) 1,745,289 1,533,000
--------------------------------------------------------------------------------------------------------------
$2,908,385 $2,760,015
--------------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Approved by the Board:
/s/ Hank B. Swartout /s/ H. Garth Wiggins
-------------------------------- ----------------------------------
HANK B. SWARTOUT (signed) H. GARTH WIGGINS (signed)
Director Director
CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS
Years ended December 31,
(stated in thousands of dollars, except per share amounts) 2003 2002 2001
----------------------------------------------------------------------------------------------------------------------
(RESTATED - NOTE 2)
Revenue $ 1,917,933 $ 1,567,506 $ 1,815,208
Expenses:
Operating 1,273,434 1,094,846 1,138,231
General and administrative 136,747 144,466 143,521
Depreciation and amortization 170,788 133,384 139,271
Research and engineering 42,419 34,862 31,677
Foreign exchange (2,565) 4,389 723
----------------------------------------------------------------------------------------------------------------------
1,620,823 1,411,947 1,453,423
Operating earnings 297,110 155,559 361,785
Interest:
Long-term debt 34,492 34,378 43,577
Other 1,425 1,334 556
Income (867) (589) (1,074)
Dividend income -- (39) (1,106)
Gain on disposal of investments (3,355) (900) (1,805)
----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before income taxes,
non-controlling interest and goodwill amortization 265,415 121,375 321,637
Income taxes: (NOTE 11)
Current 59,681 64,762 17,841
Future 12,851 (34,072) 96,631
----------------------------------------------------------------------------------------------------------------------
72,532 30,690 114,472
Earnings from continuing operations before
non-controlling interest and goodwill amortization 192,883 90,685 207,165
Non-controlling interest 1,752 1,151 868
----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations
before goodwill amortization 191,131 89,534 206,297
Goodwill amortization, net of tax (NOTE 2) -- -- 30,587
----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 191,131 89,534 175,710
Gain on disposal of discontinued operations (NOTE 20) 17,460 -- --
Discontinued operations, net of tax (NOTE 20) (19,915) 1,731 10,824
Net earnings 188,676 91,265 186,534
Retained earnings, beginning of year (NOTE 2) 620,084 528,819 342,285
----------------------------------------------------------------------------------------------------------------------
Retained earnings, end of year $ 808,760 $ 620,084 $ 528,819
----------------------------------------------------------------------------------------------------------------------
Earnings per share from continuing operations
before goodwill amortization (NOTE 12)
Basic $ 3.51 $ 1.67 $ 3.90
Diluted $ 3.46 $ 1.63 $ 3.81
----------------------------------------------------------------------------------------------------------------------
Earnings per share from continuing operations (NOTE 12)
Basic $ 3.51 $ 1.67 $ 3.31
Diluted $ 3.46 $ 1.63 $ 3.23
----------------------------------------------------------------------------------------------------------------------
Earnings per share: (NOTE 12)
Basic $ 3.47 $ 1.70 $ 3.52
Diluted $ 3.41 $ 1.66 $ 3.44
----------------------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF CASH FLOW
Years ended December 31,
(stated in thousands of dollars) 2003 2002 2001
--------------------------------------------------------------------------------------------------------------
(RESTATED - NOTE 2)
Cash provided by (used in):
Continuing operations:
Earnings from continuing operations $ 191,131 $ 89,534 $ 175,710
Items not affecting cash:
Depreciation and amortization 170,788 133,384 139,271
Goodwill amortization -- -- 30,587
Future income taxes 12,851 (34,072) 96,631
Gain on disposal of investments (3,355) (900) (1,805)
Amortization of deferred financing costs 1,286 1,294 1,302
Unrealized foreign exchange loss (gain)
on long-term monetary items (16,433) (2,039) 6,576
Non-controlling interest 1,752 1,151 868
--------------------------------------------------------------------------------------------------------------
Funds provided by continuing operations 358,020 188,352 449,140
Changes in non-cash working capital balances (NOTE 18) (101,146) (601) (22,600)
--------------------------------------------------------------------------------------------------------------
256,874 187,751 426,540
Discontinued operations: (NOTE 20)
Funds provided by (used in) discontinued operations (5,692) 6,868 17,261
Changes in non-cash working capital balances of
discontinued operations 7,245 4,604 (11,571)
--------------------------------------------------------------------------------------------------------------
1,553 11,472 5,690
Investments:
Business acquisitions, net of cash acquired (NOTE 14) (6,800) (4,594) (35,557)
Purchase of property, plant and equipment (314,921) (267,794) (366,019)
Purchase of intangibles (6) (4,198) (5,673)
Proceeds on sale of property, plant and equipment 24,423 32,449 31,001
Proceeds on disposal of investments 10,966 1,872 2,283
Investments (1,080) (5,672) 227
Proceeds on disposal of discontinued operations 67,274 -- --
--------------------------------------------------------------------------------------------------------------
(220,144) (247,937) (373,738)
Financing:
Increase in long-term debt 85,228 119,380 22,083
Repayment of long-term debt (145,657) (102,275) (83,437)
Deferred financing costs on long-term debt -- -- (38)
Issuance of common shares on exercise of options 23,613 25,756 20,294
Issuance of common shares on exercise of warrants -- -- 2,371
Change in bank indebtedness 2,588 9,937 (27,236)
--------------------------------------------------------------------------------------------------------------
(34,228) 52,798 (65,963)
--------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash 4,055 4,084 (7,471)
Cash, beginning of year 17,315 13,231 20,702
Cash, end of year $ 21,370 $ 17,315 $ 13,231
--------------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(TABULAR AMOUNTS STATED IN THOUSANDS OF DOLLARS EXCEPT PER SHARE AMOUNTS)
Precision Drilling Corporation (the "Corporation") is a global oilfield
services company providing a broad range of drilling, production and evaluation
services with focus on fulfilling customer needs through fit-for-purpose
technologies.
The financial statements are prepared in accordance with generally
accepted accounting principles (GAAP) in Canada. Management is required to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reported period. Actual results could differ from these estimates.
NOTE 1: SIGNIFICANT ACCOUNTING POLICIES
(a) PRINCIPLES OF CONSOLIDATION:
The consolidated financial statements include the accounts of the
Corporation and its subsidiaries, all of which, except one, are
wholly-owned.
(b) INVENTORY:
Inventory is carried at the lower of average cost and replacement
cost.
(c) PROPERTY, PLANT AND EQUIPMENT:
Drilling rig equipment is depreciated by the unit-of-production
method based on 3,650 drilling days with a 20% salvage value.
Drill pipe and drill collars are depreciated over 1,100 drilling
days 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.
Field technical equipment is depreciated by the straight-line
method over periods ranging from 2 to 10 years.
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
3 to 10 years.
Light duty vehicles are depreciated by the straight-line method
over 4 years. Heavy-duty vehicles are depreciated by the
straight-line method over periods ranging from 7 to 10 years.
Buildings are depreciated by the straight-line method over
periods ranging from 10 to 30 years.
(d) INTANGIBLES:
Intangibles, which are comprised of acquired patents, are
recorded at cost and amortized by the straight-line method over
their useful lives ranging from 5 to 15 years.
(e) GOODWILL:
Goodwill is the residual 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 Corporation'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 the reporting segment's goodwill exceeds the
implied fair value of the goodwill, an impairment loss is
recognized in an amount equal to the excess.
(f) INVESTMENTS:
Investments in shares of associated companies, over which the
Corporation 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.
(g) 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.
(h) INCOME TAXES:
The Corporation follows 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. Income tax
expense is the sum of the Corporation's provision for current
income taxes and the difference between opening and ending
balances of the future income tax assets and liabilities.
(i) REVENUE RECOGNITION:
The Corporation'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.
(j) RETIREMENT ALLOWANCE:
The Corporation has entered into an employment agreement with a
senior officer, which provides for a one-time payment upon
retirement. The amount of this retirement allowance increases by
a fixed amount for each year of service over a ten year period
commencing April 30, 1996. The estimated cost of this benefit is
accrued and charged to earnings on a straight-line basis over the
10-year period.
(k) FOREIGN CURRENCY TRANSLATION:
Accounts of foreign operations, all of which are considered
financially and operationally integrated, 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.
(l) STOCK-BASED COMPENSATION PLANS:
The Corporation has equity incentive plans, which are described
in Note 8. No compensation expense is recognized for these plans
when stock options are issued. Any consideration received on
exercise of the stock options is credited to share capital. The
Corporation discloses the pro forma effect of stock options
grants, had those grants been accounted for following the fair
value method.
Effective January 1, 2004, the Corporation will retroactively
adopt new required Canadian accounting standards that will apply
the fair value method to all stock options granted in 2002 and
subsequent years.
Under the fair value method, the Corporation will calculate the
fair value of stock option grants and record that fair value as
compensation expense over the vesting period of those grants.
(m) RESEARCH AND ENGINEERING:
Research and engineering costs are charged to income as incurred.
Costs associated with the development of new operating tools and
systems are expensed during the period unless the recovery of
these costs can be reasonably assured given the existing and
anticipated future industry conditions. Upon successful
completion and field testing of the tools any deferred costs are
transferred to the related capital asset accounts.
(n) PER SHARE AMOUNTS:
Basic per share amounts are calculated using the weighted average
number of shares outstanding during the year. Diluted per share
amounts are calculated based on the treasury stock method, which
assumes that any proceeds obtained on exercise of options would
be used to purchase common shares at the average market price
during the period. The weighted average number of shares
outstanding is then adjusted by the net change.
(o) COMPARATIVE FIGURES:
Certain comparative figures have been reclassified to conform
with the current financial statement presentation.
NOTE 2: ACCOUNTING CHANGES
(a) ACCOUNTING FOR BUSINESS COMBINATIONS, GOODWILL AND OTHER
INTANGIBLE ASSETS:
Effective January 1, 2002, the Corporation prospectively adopted
the new Canadian accounting standards relating to business
combinations and goodwill and other intangible assets, as
outlined in Note 1(e).
(b) FOREIGN CURRENCY TRANSLATION:
Effective January 1, 2002, the Corporation adopted, on a
retroactive basis, a new Canadian accounting standard whereby
unrealized gains or losses are not deferred and amortized as
previously required but rather expensed as incurred.
As a result of this change, unrealized gains and losses related
to translation of foreign currency denominated long-term debt are
no longer deferred and amortized over the term of the debt but
are expensed as incurred. Prior period results have been restated
to reflect this change. The retroactive application of this
standard has reduced the opening balance of retained earnings by
$1.6 million and $115,000 at January 1, 2002 and January 1, 2001
respectively.
NOTE 3: INVENTORY
2003 2002
Operating supplies and spare parts $ 95,254 $ 86,002
Manufacturing parts and materials 3,834 6,742
----------------------------------------------------------------------
$ 99,088 $ 92,744
----------------------------------------------------------------------
NOTE 4: PROPERTY, PLANT AND EQUIPMENT
ACCUMULATED NET BOOK
2003 COST DEPRECIATION VALUE
-------------------------------------------------------------------------------------------------
Rig equipment $1,128,300 $ 324,097 $ 804,203
Field technical equipment 601,752 113,617 488,135
Rental equipment 77,640 30,128 47,512
Other equipment 201,533 95,980 105,553
Vehicles 88,329 23,444 64,885
Buildings 77,839 15,799 62,040
Land 15,922 -- 15,922
-------------------------------------------------------------------------------------------------
$ 2,191,315 $ 603,065 $ 1,588,250
-------------------------------------------------------------------------------------------------
Accumulated Net Book
2002 Cost Depreciation Value
Rig equipment $ 1,059,772 $ 267,174 $ 792,598
Field technical equipment 472,957 65,528 407,429
Rental equipment 76,328 27,900 48,428
Other equipment 163,361 78,890 84,471
Vehicles 77,360 19,240 58,120
Buildings 64,211 12,967 51,244
Land 14,983 -- 14,983
-------------------------------------------------------------------------------------------------
$ 1,928,972 $ 471,699 $ 1,457,273
-------------------------------------------------------------------------------------------------
NOTE 5: OTHER ASSETS
2003 2002
----------------------------------------------------------------------------------------
Investments, at cost less provision for impairment $ 3,539 $ 8,960
Investments, at equity 310 2,114
Deferred financing costs, net of accumulated amortization 5,083 6,369
----------------------------------------------------------------------------------------
$ 8,932 $ 17,443
----------------------------------------------------------------------------------------
NOTE 6: BANK INDEBTEDNESS
The Corporation has available a revolving credit loan facility
of US$25.0 million. Advances under this facility bear interest at the
bank's prime lending rate less 0.75%. The facility is renewable and
extendable annually at the option of the lenders. As at December 31,
2003 $17.9 million (US$13.7 million) was drawn on this facility as
compared to $14.3 million (US$9.2 million) at December 31, 2002.
Availability of this facility is further reduced by outstanding
letters of credit in the amount of $1.1 million (US$850,000).
As at December 31, 2003 the Corporation has included $130.0
million (December 31, 2002 - $80.0 million) of its extendable
revolving unsecured facility in bank indebtedness, as the funds were
used to finance working capital.
NOTE 7: LONG-TERM DEBT
2003 2002
-------------------------------------------------------------------------------------------
Unsecured debentures - Series 1 $ 200,000 $ 200,000
Unsecured debentures - Series 2 150,000 150,000
EDC facility (2003 - US$2,639; 2002 - US$7,917) 3,459 12,255
EDC facility (2003 - US$20,000; 2002 - US$30,000) 26,214 46,440
EDC facility (US$20,190) 26,463 --
Extendable revolving unsecured facility 9,815 128,318
Other 629 4,963
-------------------------------------------------------------------------------------------
416,580 541,976
Less amounts due within one year 17,158 27,098
-------------------------------------------------------------------------------------------
$ 399,422 $ 514,878
-------------------------------------------------------------------------------------------
The $200.0 million 6.85% Series 1 unsecured debentures mature
June 26, 2007 and have an effective interest rate of 7.44% after
taking into account deferred financing costs. The debentures are
redeemable at any time at the option of the Corporation 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.
The $150.0 million 7.65% Series 2 unsecured debentures mature
October 27, 2010 and have an effective interest rate of 7.71% after
taking into account deferred financing costs. The debentures are
redeemable at any time at the option of the Corporation 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.
The $3.5 million unsecured term financing facility with Export
Development Canada (EDC) is repayable in semi-annual installments,
matures on January 20, 2004 and bears interest at six-month U.S.
Libor plus applicable margin. The margin is dependent upon the
Corporation's credit rating, which at December 31, 2003 resulted in a
margin of 0.8%.
The $26.2 million unsecured term financing facility with EDC is
repayable over five years in semi-annual installments, matures
September 15, 2005 and bears interest at six-month U.S. Libor plus
applicable margin. The margin is dependent upon the Corporation's
credit rating, which at December 31, 2003 results in a margin of
0.9%.
The $26.5 million unsecured financing facility with EDC matures
on October 24, 2004 and bears interest at six-month U.S. Libor plus
applicable margin. The margin is dependent upon the Corporation's
margin on its $350.0 million extendable revolving unsecured credit
facility, which at December 31, 2003 resulted in a margin of 0.8%.
The facility is extendable upon mutual agreement between the
Corporation and the Lender, or can be converted, at the Corporation's
option, to a term loan repayable in two equal semi-annual
installments, with the first payment due April 25, 2005.
The Corporation has an extendable revolving unsecured facility
of $350.0 million (or U.S. equivalent) with a syndicate led by a
Canadian chartered bank. Advances are available at either 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 Corporation's credit rating and
the percentage of the total facility outstanding, which at December
31, 2003 resulted in a margin of 0.8%. The facility is extendable
annually at the option of the lenders. Should this facility not be
extended, outstanding amounts will be transferred to a two-year term
facility repayable in equal quarterly installments. As at December
31, 2003 the Corporation had drawn $139.8 million under this
facility, of which $130.0 million has been included in bank
indebtedness as the funds were used to finance working capital.
Principal repayments over the next five years are as follows:
2004 $ 17,158
2005 39,588
2006 19
2007 200,000
2008 --
Thereafter 159,815
------------------------------------------------------------------
$ 416,580
------------------------------------------------------------------
NOTE 8: SHARE CAPITAL
(a) AUTHORIZED:
o unlimited number of non-voting cumulative convertible
redeemable preferred shares without nominal or par value;
o unlimited number of common shares without nominal or par
value.
(b) ISSUED:
Common Shares: Number Amount
---------------------------------------------------------------------------
Balance, December 31, 2000 52,283,053 $ 864,495
Options exercised 855,935 20,294
Warrants exercised 37,050 2,371
---------------------------------------------------------------------------
Balance, December 31, 2001 53,176,038 $ 887,160
Options exercised 890,715 25,756
---------------------------------------------------------------------------
Balance, December 31, 2002 54,066,753 $ 912,916
Options exercised 778,925 23,613
---------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2003 54,845,678 $ 936,529
---------------------------------------------------------------------------
(c) EQUITY INCENTIVE PLANS:
The Corporation has equity incentive plans under which a
combined total of 3,966,711 options to purchase common shares
are reserved to be granted to employees and directors. Of the
amount reserved, 3,393,194 options have been granted. Under
these plans, the exercise price of each option equals the
market value of the Corporation's stock on the date of the
grant and an option's maximum term is 10 years. Options vest
over a period from 1 to 4 years from the date of grant as
employees or directors render continuous service to the
Corporation.
A summary of the equity incentive plans as at December 31,
2001, 2002 and 2003, and changes during the periods then ended
is presented below:
Weighted
Range of Average
Options Exercise Exercise Options
Outstanding Price Price Exercisable
--------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2000 4,474,103 $ 13.50 - 54.20 $ 31.18 946,087
Granted 1,055,350 31.05 - 65.90 44.03
Exercised (855,935) 13.50 - 44.38 23.71
Cancelled or expired (267,237) 25.50 - 52.39 38.63
--------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2001 4,406,281 $ 13.50 - 65.90 $ 35.21 1,217,428
Granted 786,050 41.06 - 52.61 48.77
Exercised (890,715) 13.50 - 44.38 28.92
Cancelled or expired (182,288) 25.50 - 65.90 40.19
--------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2002 4,119,328 $ 13.50 - 65.90 $ 38.93 1,627,777
Granted 416,000 49.28 - 51.04 50.61
Exercised (778,925) 13.50 - 51.00 30.34
Cancelled or expired (363,209) 31.05 - 65.90 44.89
--------------------------------------------------------------------------------------------------------------
OUTSTANDING AT DECEMBER 31, 2003 3,393,194 $ 13.50 - 65.90 $ 41.69 2,038,198
--------------------------------------------------------------------------------------------------------------
The range of exercise prices for options outstanding at
December 31, 2003 are as follows:
Total Options Outstanding Exercisable Options
----------------------------------------------------------------------------------------------------------------
Weighted
Weighted Average Weighted
Average Remaining Average
Exercise Contractual Exercise
Range of Exercise Prices: Number Price Life (Years) Number Price
----------------------------------------------------------------------------------------------------------------
$ 13.50 - 19.99 161,486 $ 14.12 0.39 161,486 $ 14.12
20.00 - 29.99 51,300 28.98 0.79 51,300 28.98
30.00 - 39.99 1,089,665 34.96 1.21 907,940 35.29
40.00 - 49.99 1,029,943 42.86 3.34 557,172 42.29
50.00 - 59.99 1,038,300 51.98 4.69 359,050 53.24
60.00 - 65.90 22,500 65.81 2.55 1,250 65.10
----------------------------------------------------------------------------------------------------------------
$ 13.50 - 65.90 3,393,194 $ 41.69 2.89 2,038,198 $ 38.55
----------------------------------------------------------------------------------------------------------------
In accordance with the Corporation's stock option plans, these
options have an 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, 2003
was $19.48 (2002 - $20.85) based on the date of grant using the
Black-Scholes option pricing model with the following
assumptions: average risk-free interest rate of 3.47% (2002 -
4.53%), average expected life of 3.42 years (2002 - 3.88 years)
and expected volatility of 47% (2002 - 49%).
Had the Corporation determined compensation costs based on the
fair value at the date of grant for stock options granted since
January 1, 2002; net earnings and earnings per share (EPS)
would have decreased to the pro forma amounts indicated below.
These pro forma amounts reflect compensation cost amortized
over the option's vesting period.
2003 2002
------------------------------------------------------------------------------------------------------
Years Ended December 31 AS REPORTED PRO FORMA As Reported Pro forma
------------------------------------------------------------------------------------------------------
Net earnings $ 188,676 $ 178,993 $ 91,265 $ 85,071
Basic EPS $ 3.47 $ 3.29 $ 1.70 $ 1.59
Diluted EPS $ 3.41 $ 3.24 $ 1.66 $ 1.55
------------------------------------------------------------------------------------------------------
NOTE 9: EMPLOYEE BENEFIT PLANS
The Corporation has a defined contribution employee benefit
plan covering a significant number of its employees. The Corporation
matches individual employee contributions up to 5% of the employee's
compensation. Employer matching contributions under the plan totalled
$7.5 million for the year ended December 31, 2003 (year ended
December 31, 2002 - $6.9 million; year ended December 31, 2001 - $6.3
million).
With respect to the retirement allowance described in Note
1(j), the Corporation charged $351,000 to earnings in 2003 (2002 -
$371,000; 2001 - $360,000) and at December 31, 2003 had accrued a
total of $2.5 million, which amount is included in accounts payable
and accrued liabilities.
NOTE 10: COMMITMENTS
The Corporation has commitments for operating lease agreements,
primarily for vehicles and office space, in the aggregate amount of
$110.5 million. Payments over the next five years are as follows:
---------------------------------------------------------------------
2004 $ 28,104
2005 21,439
2006 15,948
2007 12,179
2008 11,168
---------------------------------------------------------------------
Rent expense included in the statements of earnings is as follows:
2003 $ 23,924
2002 18,085
2001 16,923
---------------------------------------------------------------------
NOTE 11: 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:
2003 2002 2001
-------------------------------------------------------------------------------------------------------------------
Earnings before income taxes, non-controlling interest,
discontinued operations and goodwill amortization $ 265,415 $ 121,375 $ 321,637
Income tax rate 36% 39% 42%
-------------------------------------------------------------------------------------------------------------------
Expected income tax provision $ 95,549 $ 47,336 $ 135,088
Add (deduct):
Non-deductible expenses 2,380 2,084 3,861
Income taxed in jurisdictions with lower tax rates (14,062) (13,450) (14,302)
Non-taxable disposition of investment (2,327) -- --
Other (6,020) (2,729) (4,211)
-------------------------------------------------------------------------------------------------------------------
75,520 33,241 120,436
Reduction of future tax balances due to
substantively enacted tax rate reductions (2,988) (2,551) (5,964)
-------------------------------------------------------------------------------------------------------------------
$ 72,532 $ 30,690 $ 114,472
-------------------------------------------------------------------------------------------------------------------
In both 2003 and 2002, the Province of Alberta enacted a 0.5%
reduction in tax rates and in 2001 it enacted a 2% reduction in tax
rates. These rate changes have been reflected as a reduction in
future tax expense in 2003, 2002 and 2001.
The Corporation's operations are complex and computation of the
provision for income taxes involves tax interpretations, regulations
and legislation that are continually changing. There are tax matters
that have not yet been confirmed by taxation authorities, however,
management believes the provision for income taxes is adequate.
The net future tax liability is comprised of the tax effect of
the following temporary differences:
2003 2002
-------------------------------------------------------------------------------------------------
Liabilities:
Property, plant and equipment and intangibles $ 290,371 $288,720
Assets held in partnership with different tax year 92,163 50,640
Deferred financing costs 1,774 2,385
-------------------------------------------------------------------------------------------------
$ 384,308 $341,745
-------------------------------------------------------------------------------------------------
Assets:
Losses carried forward $ 63,431 $ 29,070
Accrued liabilities 278 1,511
-------------------------------------------------------------------------------------------------
63,709 30,581
-------------------------------------------------------------------------------------------------
$ 320,599 $311,164
-------------------------------------------------------------------------------------------------
The Corporation has available losses of $251.4 million of which
the benefit of $181.9 million has been recognized. These losses
expire depending upon the year incurred and various limitations under
tax codes in the jurisdictions in which the losses were incurred.
NOTE 12: PER SHARE AMOUNTS
Per share amounts have been calculated on the weighted average
number of common shares outstanding. The weighted average shares
outstanding for the year ended December 31, 2003 was 54,430,468 (year
ended
December 31, 2002 - 53,701,873; year ended December 31, 2001 -
52,952,879).
Diluted per share amounts reflect the dilutive effect of the
exercise of the options outstanding. The diluted shares for the year
ended December 31, 2003 was 55,299,920 (year ended December 31, 2002
- 54,815,167; year ended December 31, 2001 - 54,198,348).
NOTE 13: SIGNIFICANT CUSTOMERS
During the years ended December 31, 2003, 2002 and 2001, no one
customer accounted for more than 10% of the Corporation's revenue.
NOTE 14: 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.
In February 2003, the Corporation 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.
During the year ended December 31, 2002, the Corporation
completed the following business acquisitions:
(a) Acquisition of the business assets of NightHawk Vacuum
Services Ltd. (NightHawk) in September 2002. NightHawk
provides oilfield vacuum services in northern Alberta and
British Columbia.
(b) Paid additional consideration in conjunction with an
acquisition made in 2001. This additional consideration
was payable based on the development of a commercially
viable technology.
NightHawk Other Total
--------------------------------------------------------------------------------------------------------------
Net assets acquired at assigned values:
Working capital $ (47) $ -- $ (47)
Property, plant and equipment 3,097 -- 3,097
Goodwill -- 1,544 1,544
--------------------------------------------------------------------------------------------------------------
3,050 1,544 4,594
--------------------------------------------------------------------------------------------------------------
Consideration:
Cash $ 3,050 $ 1,544 $ 4,594
--------------------------------------------------------------------------------------------------------------
During the year ended December 31, 2001, the Corporation
completed business acquisitions, the most significant of which was
the acquisition of all the issued and outstanding shares of BecField
Drilling Services Ltd. (BecField) in January 2001. BecField provides
directional drilling and measurement-while-drilling services through
its technical field and support personnel to the onshore and offshore
oil and gas industry. It has established operations in Europe and the
Middle East.
BecField Other Total
--------------------------------------------------------------------------------------------------------------
Net assets acquired at assigned values:
Working capital $ 2,446(a) $ 1,136(b) $ 3,582
Property, plant and equipment 5,036 4,074 9,110
Goodwill 23,877 2,783 26,660
Future income taxes -- (800) (800)
--------------------------------------------------------------------------------------------------------------
$ 31,359 $ 7,193 $ 38,552
--------------------------------------------------------------------------------------------------------------
Consideration:
Cash $ 31,359 $ 7,193 $ 38,552
--------------------------------------------------------------------------------------------------------------
(a) INCLUDES CASH OF $ 1,880
(b) INCLUDES CASH OF $ 1,115
NOTE 15: UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
These financial statements have been prepared in accordance
with Canadian GAAP which, in the case of the Corporation conform with
United States generally accepted accounting principles (U.S. GAAP) in
all material respects, except as follows:
a) INCOME TAXES:
In 2000 the Corporation adopted the liability method as
described in Note 1 without restatement of prior years. As a
result, the Corporation recorded an adjustment to retained
earnings and future tax liability in the amount of $70 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 with the
Canadian GAAP accounting standard adopted in 2000. Application
of U.S. GAAP in years prior to 2000 would have resulted in $70
million of additional goodwill being recognized at January 1,
2000 as opposed to an implementation adjustment to retained
earnings allowed under Canadian GAAP. In 2001, 2002 and 2003
the U.S. GAAP financial statements would reflect an increase in
goodwill of $63 million and a corresponding increase in
retained earnings. An additional charge to earnings of $3.5
million in 2001 would be required related to the amortization
of the goodwill.
Under Canadian GAAP, future tax liabilities and assets are
calculated by reference to current tax legislation and proposed
legislation that is considered substantively enacted but not
yet enacted into law. U.S. GAAP requires that only enacted
income tax legislation be used for calculation of future tax
amounts. In 2000 the Federal Government of Canada introduced
tax rate reductions that were substantively enacted at December
31, 2000 but that were not passed into legislation until 2001.
The resulting reduction of future tax balances recognized under
Canadian GAAP in 2000 would not be recognized under U.S. GAAP
until 2001.
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, 2003 2002 2001
----------------------------------------------------------------------------------------------------------
Net earnings under Canadian GAAP $ 188,676 $ 91,265 $ 186,534
Adjustments under U.S. GAAP:
Goodwill amortization -- -- (3,502)
Income tax rate -- -- 19,934
----------------------------------------------------------------------------------------------------------
Net income and comprehensive income
under U.S. GAAP $ 188,676 $ 91,265 $ 202,966
----------------------------------------------------------------------------------------------------------
Earnings per share under U.S. GAAP:
Basic $ 3.47 $ 1.70 $ 3.83
Diluted $ 3.41 $ 1.66 $ 3.74
----------------------------------------------------------------------------------------------------------
BALANCE SHEETS
DECEMBER 31, 2003 December 31, 2002
AS REPORTED U.S. GAAP As reported U.S. GAAP
-------------------------------------------------------------------------------------------------------------------
Current assets $ 686,458 $ 686,458 $ 601,827 $ 601,827
Property, plant and equipment 1,588,250 1,588,250 1,457,273 1,457,273
Intangibles 65,262 65,262 71,355 71,355
Goodwill 527,443 590,472 527,443 590,472
Other assets 8,932 8,932 17,443 17,443
Long-term assets
of discontinued operations 32,040 32,040 84,674 84,674
-------------------------------------------------------------------------------------------------------------------
$2,908,385 $2,971,414 $2,760,015 $2,823,044
-------------------------------------------------------------------------------------------------------------------
Current liabilities $ 438,197 $ 438,197 $ 391,571 $ 391,571
Long-term debt 399,422 399,422 514,878 514,878
Future income taxes 320,599 320,599 311,164 311,164
Liabilities of discontinued operations 1,107 1,107 7,383 7,383
Non-controlling interest 3,771 3,771 2,019 2,019
Shareholders' equity 1,745,289 1,808,318 1,533,000 1,596,029
-------------------------------------------------------------------------------------------------------------------
$2,908,385 $2,971,414 $2,760,015 $2,823,044
-------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF CASH FLOWS
The application of U.S. accounting principles would have no
impact on the consolidated statement of cash flows.
STOCK COMPENSATION
In 2003 and 2002 Canadian GAAP and U.S. GAAP were substantially
the same with respect to stock compensation. Prior to 2002,
U.S. GAAP required the disclosure of the impact of using fair
value accounting for stock options if in fact this alternative
was not used. Canadian GAAP did not require such disclosure.
The per share weighted average fair value of stock options
granted during the year ended December 31, 2001 was $19.87 on
the date of grant using the Black-Scholes option pricing model
with the following assumptions: risk free interest rate of
5.75%, expected life of 5 years and expected volatility of 49%.
Had the Corporation determined compensation cost based on the
fair value at the date of grant for its stock options under
SFAS 123, net earnings in accordance with U.S. GAAP would have
decreased by $12.2 million to $190.8 million (basic EPS -
$3.60) for the year ended December 21, 2001.
NOTE 16: SEGMENTED INFORMATION
The Corporation operates in three industry segments. Contract
Drilling includes drilling rigs, service rigs and hydraulic well
assist snubbing units, procurement and distribution of oilfield
supplies, camp and catering services, and manufacture, sale and
repair of drilling equipment. Technology Services includes wireline,
directional drilling,
measurement-while-drilling/logging-while-drilling services,
separation services, and the design, manufacture and marketing of
polycrystalline diamond compact drill bits. Rental and Production
includes oilfield equipment rental services and industrial process
services.
CONTRACT TECHNOLOGY RENTAL AND CORPORATE
2003 DRILLING SERVICES PRODUCTION AND OTHER TOTAL
---------------------------------------------------------------------------------------------------------------------
Revenue $ 992,824 $ 714,385 $ 210,724 -- $ 1,917,933
Operating earnings 285,753 4,842 39,350 (32,835) 297,110
Research and engineering -- 42,419 -- -- 42,419
Depreciation and
amortization 77,725 75,578 12,533 4,952 170,788
Total assets 1,423,036 1,257,235 166,300 61,814 2,908,385
Goodwill 257,531 241,340 28,572 -- 527,443
Capital expenditures* 99,034 177,756 15,158 22,979 314,927
---------------------------------------------------------------------------------------------------------------------
Contract Technology Rental and Corporate
2002 Drilling Services Production and Other Total
---------------------------------------------------------------------------------------------------------------------
Revenue $ 770,147 $ 603,088 $ 192,840 $ 1,431 $ 1,567,506
Operating earnings 184,553 (31,733) 30,090 (27,351) 155,559
Research and engineering -- 34,862 -- -- 34,862
Depreciation and
amortization 62,524 53,347 13,159 4,354 133,384
Total assets 1,312,459 1,127,550 240,842 79,164 2,760,015
Goodwill 257,531 241,340 28,572 -- 527,443
Capital expenditures* 50,686 189,092 22,346 9,868 271,992
---------------------------------------------------------------------------------------------------------------------
Contract Technology Rental and Corporate
2002 Drilling Services Production and Other Total
---------------------------------------------------------------------------------------------------------------------
Revenue $ 1,004,265 $ 614,152 $ 194,567 $ 2,224 $ 1,815,208
Operating earnings 298,737 52,257 39,365 (28,574) 361,785
Research and engineering -- 31,677 -- -- 31,677
Depreciation and
amortization 75,170 47,694 13,388 3,019 139,271
Total assets 1,367,682 987,061 241,044 55,571 2,651,358
Goodwill 257,531 239,796 28,572 -- 525,899
Capital expenditures* 122,575 203,547 27,352 18,218 371,692
---------------------------------------------------------------------------------------------------------------------
* EXCLUDES BUSINESS ACQUISITIONS
The Corporation's operations are carried on in the following
geographic locations:
2003 CANADA INTERNATIONAL TOTAL
----------------------------------------------------------------------
Revenue $ 1,349,565 $ 568,368 $ 1,917,933
Assets 2,121,832 786,553 2,908,385
----------------------------------------------------------------------
2002 Canada International Total
----------------------------------------------------------------------
Revenue $ 1,022,489 $ 545,017 $ 1,567,506
Assets 2,081,200 678,815 2,760,015
----------------------------------------------------------------------
2001 Canada International Total
----------------------------------------------------------------------
Revenue $ 1,320,989 $ 494,219 $ 1,815,208
Assets 2,175,877 475,481 2,651,358
----------------------------------------------------------------------
NOTE 17: FINANCIAL INSTRUMENTS
(a) FAIR VALUE
The carrying value of cash, accounts receivable and accounts
payable and accrued liabilities approximate their fair value
due to the relatively short period to maturity of the
instruments. The fair value of long-term debt, exclusive of the
unsecured debentures, approximates its carrying value as it
bears interest at floating rates. The $200 million Series 1
debentures have a fair value of approximately $216.2 million as
at December 31, 2003 (December 31, 2002 - $210.5 million) and
the $150 million Series 2 unsecured debentures have a fair
value of approximately $170.8 million at December 31, 2003
(December 31, 2002 - $161.1 million). As at December 31, 2003
investments have a carrying value of $3.8 million (December 31,
2002 - $11.1 million) and a fair value of approximately $5.2
million (December 31, 2002 - $12.7 million).
(b) CREDIT RISK
Accounts receivable includes balances from a large number of
customers. The Corporation assesses the credit worthiness of
its customers on an ongoing basis as well as monitoring the
amount and age of balances outstanding. Accordingly, the
Corporation views the credit risks on these amounts as normal
for the industry. As at December 31, 2003 the Corporation's
allowance for doubtful accounts was $16.0 million (December 31,
2002 - $14.9 million).
(c) INTEREST RATE RISK
The Corporation manages its exposure to interest rate risks
through a combination of fixed and floating rate borrowings. As
at December 31, 2003, 39% of its total borrowings was at
floating rates.
(d) FOREIGN CURRENCY RISK
The Corporation is exposed to foreign currency fluctuations in
relation to its international operations; however, management
believes this exposure is not material to its overall
operations.
NOTE 18: SUPPLEMENTAL INFORMATION
2003 2002 2001
-----------------------------------------------------------------------------------------------------------
Cash interest paid $ 36,721 $ 35,660 $ 45,967
Cash income taxes paid 43,994 89,856 11,066
Components of change in non-cash working capital balances:
Accounts receivable $(113,519) $ 14,231 $ (35,607)
Inventory (6,344) (13,982) (18,245)
Accounts payable and accrued liabilities 2,632 20,000 15,878
Income taxes payable 16,085 (20,850) 15,374
-----------------------------------------------------------------------------------------------------------
$(101,146) $ (601) $ (22,600)
-----------------------------------------------------------------------------------------------------------
The components of accounts payable and accrued liabilities are as
follows:
2003 2002
----------------------------------------------------------------------------------------------------------
Accounts payable $ 62,958 $ 66,015
Accrued liabilities
Payroll 43,901 43,547
Other 153,686 148,351
----------------------------------------------------------------------------------------------------------
$ 260,545 $257,913
----------------------------------------------------------------------------------------------------------
NOTE 19: CONTINGENCIES
The Corporation, through the performance of its services and
product sales obligations, is sometimes named as a defendant in
litigation. One such case relates to a former agent of the
Corporation in Indonesia who filed a suit in Indonesian courts
seeking a pronouncement that they be the sole agent for certain of
the Corporation's product lines in Indonesia and they are seeking
damages of US$17.5 million. This matter is at trial and all written
evidence and oral testimony has been presented by all parties. The
outcome of this and other claims is not determinable at this time;
however, their ultimate resolution is not expected to have a material
adverse effect on the Corporation.
The Corporation maintains a level of insurance coverage deemed
appropriate by management and for matters for which insurance
coverage can be acquired.
NOTE 20: DISCONTINUED OPERATIONS
On March 6, 2003, the Corporation sold Energy Industries Inc.,
a wholly-owned subsidiary included in the Rental and Production
segment, for $60.0 million cash. The effective date of the
transaction was January 1, 2003. Energy Industries designed and
manufactured modularized natural gas compression packages. Although
Energy Industries had been profitable since its acquisition by
Precision in 1996, the compression packaging business was determined
to be not core to the Corporation's energy services globalization
strategy.
In May 2003 the Corporation 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.
The review of the business plan for the Technology Services
segment was completed in the fourth quarter of 2003. One of the
outcomes of this process was the identification of two product lines,
namely pressure pumping and completion services carried on by the
Fleet Cementers and Polar Completions divisions respectively, as
being not core to the segment's ongoing growth initiatives. As a
result, a program has been initiated to dispose of these businesses
and discussions are being held with interested parties.
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:
2003 2002 2001
-------------------------------------------------------------------------------------------------------------
Gain on disposal of Energy Industries $ 13,071 $ -- $ --
Gain on disposal of EER and OD&E 4,389 -- --
-------------------------------------------------------------------------------------------------------------
$ 17,460 $ -- $ --
-------------------------------------------------------------------------------------------------------------
Revenue
Gas compression $ -- $ 81,563 $ 77,313
Pressure pumping and completion services 48,150 36,279 55,287
Other 560 3,802 5,755
-------------------------------------------------------------------------------------------------------------
Discontinued operations before income taxes $ 48,710 $ 121,644 $ 138,355
-------------------------------------------------------------------------------------------------------------
Results of operations before income taxes
Gas compression $ -- $ 13,545 $ 11,685
Pressure pumping and completion services (15,585) (9,042) 7,078
Other 49 (1,154) (637)
Writedown of assets held for sale (10,799) -- --
-------------------------------------------------------------------------------------------------------------
(26,335) 3,349 18,126
Income tax expense (recovery) (6,420) 1,618 7,302
-------------------------------------------------------------------------------------------------------------
Discontinued operations $ (19,915) $ 1,731 $ 10,824
-------------------------------------------------------------------------------------------------------------
The following table provides additional information with
respect to amounts included in the balance sheet as
assets/liabilities held for sale:
2003 2002
----------------------------------------------------------------------------------------------
Accounts receivable $ 7,157 $ 12,468
Inventory 12,482 40,165
Other 1,511 (908)
----------------------------------------------------------------------------------------------
$ 21,150 $ 51,725
----------------------------------------------------------------------------------------------
Capital assets $ 27,010 $ 64,171
Goodwill 4,267 19,478
Other 763 1,025
----------------------------------------------------------------------------------------------
$ 32,040 $ 84,674
----------------------------------------------------------------------------------------------
Accounts payable $ 4,473 $ 10,655
Other 739 584
----------------------------------------------------------------------------------------------
$ 5,212 $ 11,239
----------------------------------------------------------------------------------------------
Future income taxes $ 1,107 $ 7,383
----------------------------------------------------------------------------------------------
The following table provides additional information with
respect to amounts included in the cash flow statement of funds
provided by (used in) assets classified as discontinued operations:
2003 2002 2001
-----------------------------------------------------------------------------------------------------------
Net earnings of discontinued operations $ (2,455) $ 1,731 $ 10,824
Items not affecting cash:
Gain on disposal of discontinued operations (17,460) -- --
Depreciation and amortization 8,340 8,045 5,849
Goodwill amortization -- -- 1,198
Writedown of assets of discontinued operations 10,799 -- --
Future income taxes (4,916) (2,908) (610)
-----------------------------------------------------------------------------------------------------------
Funds provided (used in) by discontinued operations $ (5,692) $ 6,868 $ 17,261
-----------------------------------------------------------------------------------------------------------
Components of change in non-cash working capital balances
related to discontinued operations:
2003 2002 2001
---------------------------------------------------------------------------------------
Accounts receivable $ 2,843 $ 16,598 $ (6,002)
Inventory 3,243 (7,534) (5,477)
Accounts payable and accrued liabilities 1,931 (4,742) 596
Income taxes payable (772) 282 (688)
---------------------------------------------------------------------------------------
$ 7,245 $ 4,604 $(11,571)
---------------------------------------------------------------------------------------
NOTE 21: GUARANTEES
The Corporation has entered into agreements indemnifying
certain parties primarily with respect to tax and specific third
party claims associated with businesses sold by the Corporation. Due
to the nature of the indemnifications, the maximum exposure under
these agreements cannot be estimated. No amounts have been recorded
for such indemnities as the Corporation's obligations under them are
not probable and estimable.
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, 2003, 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 recorded, processed, summarized and reported within
the time periods specified in Securities and Exchange Commission rules
and forms.
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, 2003, 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.
The registrant's board of directors has determined that H. Garth Wiggins, a
member of the registrant's audit committee, qualifies as an "audit committee
financial expert" (as such term is defined in Form 40-F). Mr. Wiggins is
"independent" as such term is defined in the 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 "Business Conduct and Ethics Practice" (the "Code of
Ethics"), that applies to its principal executive officer, principal financial
officer, principal accounting officer or controller, and persons performing
similar functions (together, the "Financial Supervisors").
The Code of Ethics is available for viewing on the registrant's website at
www.precisiondrilling.com.
Since the adoption of the Code of Ethics, there have not been any amendments to
the Code of Ethics or waivers, including implicit waivers, from any provision of
the Code of Ethics.
PRINCIPAL ACCOUNTANT FEES AND SERVICES.
40
The following table provides information about the fees billed to the registrant
for professional services rendered by KPMG LLP during fiscal 2003 and 2002:
(CANADIAN $000) 2003 2002
--------------------------------------------------------------------------------
Audit Fees $1,295 $1,088
Audit-Related Fees -- $67
Tax Fees $703 $535
All Other Fees $618 $135
--------------------------------------------------------------------------------
Total $2,616 $1,825
================================================================================
AUDIT FEES. Audit fees consist of fees for the audit of the registrant's annual
financial statements or services that are normally provided in connection with
statutory and regulatory filings or engagements.
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.
During fiscal 2002, the services provided in this category related to
consultation and research of accounting and audit-related issues.
TAX FEES. Tax fees consist of fees for tax compliance services, tax advice and
tax planning. During fiscal 2003 and 2002, the services provided in this
category included assistance and advice in relation to the preparation of
corporate income tax returns for the company and its subsidiaries, tax advice
and planning, commodity tax and property tax consultation.
ALL OTHER FEES.
Other fees in 2003 included investigative and forensic services, translation of
financial statements and information, consultation regarding compliance with
Sarbanes Oxley implementation and advice on foreign registrations. In 2002 other
fees included translation of financial statements and information, investigative
and forensic services and advice on foreign registrations.
PRE-APPROVAL POLICIES AND PROCEDURES
For audit services related to the consolidated financial statements, the
independent auditor provides the committee with an audit engagement letter
outlining the scope of the audit to be performed relating to the fiscal year. If
agreed to by the committee, the engagement letter is formally accepted. After
acceptance of the engagement letter the committee reviews an audit plan,
presented by the auditor, including an audit services fee proposal.
The company's auditor presents, at each audit committee meeting a list of
services which management has requested the auditor perform. The auditor and
management each confirm to the committee that each service proposed is
permissible under all applicable legal requirements. If the committee is
satisfied that it is appropriate for the auditor to perform the services, the
services are approved, enabling the auditor to commence provision of those
services.
In circumstances where the auditor is requested to perform non-audit services
not previously approved by the committee, the audit committee chair, or another
auditor committee member so delegated, is authorized to approve the service
after discussion with the auditor and management. Services so approved are
reported to the full committee at the next scheduled meeting for ratification by
the full committee.
The auditor must ensure that all services provided by the auditor's firm,
throughout the world, are appropriately pre-approved by the audit committee.
41
The committee is informed routinely as to the services performed pursuant to the
pre-approval process.
OFF-BALANCE SHEET ARRANGEMENTS.
The registrant has no off-balance sheet arrangements.
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS.
The required disclosure is included on page 69 of the registrant's Management's
Discussion and Analysis of Financial Condition and Results of Operations for the
fiscal year ended December 31, 2003, included in this Annual Report on Form
40-F.
IDENTIFICATION OF THE AUDIT COMMITTEE.
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
The registrant schedules regular executive sessions in which the registrant's
"non-management directors" (as that term is defined in the rules of the New York
Stock Exchange) meet without management participation. The Board of Directors of
the registrant 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 the
registrant's non-management directors is "unrelated" as such term is used in the
rules of the Toronto Stock Exchange
CATEGORICAL STANDARDS OF DIRECTOR INDEPENDENCE
The registrant's Board of Directors has adopted categorical standards for
director independence. These categorical standards are attached hereto as
Exhibit 99.6.
COMMUNICATION WITH NON-MANAGEMENT DIRECTORS
Shareholders may send communications to the registrant's non-management
directors by writing to the Lead Director, c/o Jan Campbell, Corporate
Secretary, Precision Drilling Corporation, 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.
42
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 has adopted the required guidelines and has posted them on its
website at www.precisiondrilling.com.
BOARD COMMITTEE MANDATES
The Mandates of the registrant's audit committee, and compensation committee,
and corporate governance and nominating committee are each available for viewing
on the registrant's website at www.precisiondrilling.com, and are available in
print to any shareholder who requests them. Requests for copies of these
documents should be made by contacting: Jan Campbell, Corporate Secretary,
Precision Drilling Corporation, 4800, 150-6th Avenue S.W., Calgary, Alberta,
Canada T2P 3Y7.
43
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 Company 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 April 26, 2004.
PRECISION DRILLING CORPORATION
By: /s/ Hank B. Swartout
-----------------------------
Name: Hank B. Swartout
Title: Chairman, President and Chief
Executive Officer
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 Section 1350 Certification of Chief Executive Officer
99.4 Section 1350 Certification of Chief Financial Officer
99.5 Consent of KPMG LLP
99.6 Categorical Standards of Director Independence