Precision Drilling Corporation Annual Report 2007

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FY2007 Annual Report · Precision Drilling Corporation

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Precision Drilling Trust 2007 Annual Report

MANAGEMENT’S DISCUSSION

AND ANALYSIS

Overview and Outlook 3

Dynamics of the Oilfield Services Industry

Precision’s Development 14

Financial Results 21

Critical Accounting Estimates,

New Accounting Standards

and Business Risks

Disclosure Controls and Procedures 38

Cautionary Statement Regarding

Forward-Looking Information and Statements

FINANCIAL REPORTING

Management’s Report to the Unitholders

Auditors’ Report to the Unitholders 43

Report of Independent

Registered Public Accounting Firm 44

Consolidated Financial Statements

Notes to Consolidated

Financial Statements

SUPPLEMENTAL INFORMATION 68

MD&A

Precision Drilling Trust

MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (“MD&A”),

Canada and the United States are described in Note 16

prepared as at March 20, 2008 focuses on the

to the Consolidated Financial Statements. Additional

Consolidated Financial Statements, and pertains to

information relating to the Trust, including the Annual

known risks and uncertainties relating to the oilfield

Information Form, has been filed with SEDAR and is

services sector. This discussion should not be

available at www.sedar.com.

considered all-inclusive, as it does not include all

changes regarding general economic, political,

governmental and environmental events. Additionally,

other events may or may not occur which could affect

Precision Drilling Trust (the “Trust” or “Precision”) in the

future. In order to obtain an overall perspective, this

discussion should be read in conjunction with the

“Cautionary Statement Regarding Forward-Looking

Information and Statements” on page 39 and the

audited Consolidated Financial Statements and related

notes. The effects on the Consolidated Financial

Statements arising from differences in generally

accepted accounting principles (“GAAP”) between

With the conversion of the continuing assets and

businesses of Precision Drilling Corporation to an

income trust on November 7, 2005 pursuant to a plan

of arrangement, the Trust, as the successor in interest

to Precision Drilling Corporation, has been accounted

for as a continuity of interest. Commencing with the year

ended December 31, 2005 the Consolidated Financial

Statements of the Trust reflect the financial position,

results of operations and cash flows as if the Trust had

always carried on the business formerly carried on by

Precision Drilling Corporation.

P R E C I S I O N D R I L L I N G T R U S T

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

Years ended December 31,

Revenue
Operating earnings (1)
Earnings from continuing operations
Discontinued operations, net of tax (2)
Net earnings
Cash provided by continuing operations
Net capital spending from
continuing operations (3)
Distributions declared – cash
Distributions declared – in-kind
Per diluted unit information:

Earnings from continuing operations
Net earnings
Distributions declared – cash
Distributions declared – in-kind

Drilling rig operating days:

Canada
United States

Service rig operating hours:

Canada

% Increase
(Decrease)

2007

% Increase
(Decrease)

2006

% Increase
(Decrease)

2005

$ 1,009,201
356,351
342,820
2,956
345,776
484,115

181,239
246,485
30,182

2.73
2.75
1.96
0.24

30,475
1,850

(30)
(40)
(40)
n/m
(40)
(21)

(22)
(45)
23

(40)
(40)
(45)
23

(32)
988

$ 1,437,584
595,279
572,512
7,077
579,589
609,744

233,693
447,001
24,523

4.56
4.62
3.56
0.195

44,768
170

13
28
159
n/m
(64)
196

67
n/m
n/m

159
(64)
n/m
n/m

(5)
n/m

$ 1,269,179
465,378
220,848
1,409,715
1,630,563
206,013

140,077
70,510
–

1.76
13.00
0.562
–

46,937
–

355,997

(26)

480,137

477,232

23
40
17
n/m
559
(28)

23
n/m
–

9
516
n/m
–

13
–

(1) Non-GAAP measure. See page 38.

(2) Includes gain on disposition of discontinued operations.

(3) Excludes acquisitions and discontinued operations.

n/m – calculation not meaningful.

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

Years ended December 31,

2007

2006

2005

Working capital
Working capital ratio
Long-term debt (1)
Total assets
Enterprise value (2)
Long-term debt to long-term debt plus equity (1)
Long-term debt to cash provided by continuing operations (1)
Long-term debt to enterprise value (1)
Interest coverage (3)

(1) Excludes current portion of long-term debt which is included in working capital.

140,374
2.1
119,826
$
$ 1,763,477
$ 1,877,139
0.08
0.25
0.06
48.7

166,484
1.8
140,880
$
$ 1,761,186
$ 3,369,860
0.10
0.23
0.04
74.1

152,754
1.4
96,838
$
$ 1,718,882
$ 4,759,289
0.08
0.47
0.02
15.9

(2) Unit price as at December 31 multiplied by the number of units outstanding plus long-term debt minus working capital. See page 29.

(3) Operating earnings divided by net interest expense.

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

MD&A

OVERVIEW AND OUTLOOK

Precision’s 2007 results were impacted by the Canadian industry decline in the drilling and servicing of natural gas

wells with partial offset from successful growth in the United States. After record profitability in 2006, 2007 was a

challenging year with back to basic Canadian business fundamentals. Safety, cost control, competitive bidding and

the drive for more efficient operations dominated Precision’s operating focus in 2007. Robust market conditions in

2005 and 2006 led drilling contractors to expand the number of industry land drilling rigs in Canada by approximately

180 drilling rigs or 25% from the number of rigs available at the end of 2004. For Canada, the decline in 2007 activity

combined with an increase in industry equipment capacity led to some of the lowest equipment utilization in a decade.

The weakness in natural gas prices was substantially the result of an over supply of natural gas as United States

storage levels exceeded the five-year average by as much as 20% early in 2007. To exit 2007, storage levels returned

to more moderate levels at 6% above the five-year average. Soft natural gas fundamentals resulted in a 24% decrease

in Canadian industry drilling operating days over 2006. Crude oil pricing reached record levels in 2007 and created

a slight shift in drilling focus from natural gas to oil. However, conventional North American oilfield service activity is

dependent on natural gas wells. Generally, natural gas wells account for a range of 70% to 80% of land drilling in

Canada and the United States.

In September 2007 a report by the Alberta Royalty Review Panel for the Alberta government proposed increased

royalties on oil and gas production in the province commencing in 2009. About 75% of conventional oilfield services

in the Western Canada Sedimentary Basin (“WCSB”) are conducted in Alberta. In November 2007 the Alberta
government accepted certain of the Panel’s recommendations to change the royalty structure effective January 1,
2009. The new structure unsettled producers just as they began to develop 2008 budgets and prompted many to
reduce their capital spending until they fully understood the new royalty structure and the impact it would have on
drilling economics.

Given these challenging conditions, Precision was still able to generate an operating earnings margin of 35% for the

year, declare cash distributions to unitholders of $246 million, reinvest $181 million in net capital spending and reduce

long-term debt by $21 million. Through the cyclical highs of 2005 and early 2006 and 18 months into the current

down cycle in Canada, Precision has maintained a strong financial position.

P R E C I S I O N D R I L L I N G T R U S T

For Precision fiscal 2007 was a year characterized by reduced customer demand in Canada, growing opportunity

in the United States land drilling market and approaching opportunity for global drilling markets. Given this backdrop,

Precision acted decisively in 2007:

K In August 2007, Kevin Neveu was appointed Chief Executive Officer of Precision. Mr. Neveu has over 25 years

of experience in the oilfield services sector in North America and international operations.

K Robert Phillips was appointed Chairman of the Board of Directors for Precision Drilling Corporation.

K After 22 years as the Chief Executive of Precision, Hank Swartout retired in August 2007. Under Mr. Swartout’s

leadership Precision grew from a four drilling rig operation in 1985 to 241 drilling rigs as at December 2006 and

expanded continuing operations to include service rigs, camp and catering, snubbing, ancillary equipment, rentals

and waste water treatment services.

K Continued at year-end to carry low levels of long-term debt and had access to substantial lines of credit to fund

future investment.

K Achieved the safest year for Precision’s people in its history.

K Focused capital expansion efforts toward growing its high performance rig fleet.

K Delivered growth in drilling rig operations with 16 new Super Series rigs deployed to drilling projects with customers

in Canada and the United States.

K Deployed a drilling rig to Latin America.

K Improved the underlying cost structure in Canadian operations with staff reduction and asset retirements in the

fourth quarter.

K Declared cash distributions of $246 million or $1.96 per diluted unit, 71% of net earnings.

K Generated a return on unitholders’ equity of 27%.

K Monitored the impact of the October 31, 2006 tax measures and subsequent amendments that will change the tax

flow-through nature of Precision’s current income trust structure by January 1, 2011. Precision continued to focus

on its business strategy and will work to ensure it has the optimal capital structure to maximize unitholder value.

In a move to diversify geographic operations and become less dependent on the cyclical nature of oilfield services

in Canada, Precision commenced drilling operations in the United States in June 2006 and continued with a strategic

deployment of drilling rigs throughout 2007. Precision began 2007 with one drilling rig in the United States and ended

with 12 rigs and plans for continued growth. All 12 drilling rigs operating in the United States are working under term

contracts and had a combined utilization rate including move days of 99%. Precision’s growth in the United States is

focused on providing customers with high performance services to meet rising demand and to displace underperforming

competitor rigs.

Notwithstanding plans to continue to diversify geographically, Precision is committed to continuing to be a premier

oilfield service company in the WCSB. The Canadian oil and gas industry represents an important market for Precision

and one in which Precision will continue to upgrade its asset mix.

Strong oil prices have maintained a robust international drilling market and for Precision during 2008 the non-compete

provision from a 2005 divestiture will expire. This will permit Precision to fully pursue global opportunities and consider

certain new business lines. Late in 2007 Precision entered into a contractual arrangement and deployed a drilling

rig to Latin America. This has enabled Precision to begin reestablishing the infrastructure for the international market

and reflects early marketing efforts to identify available diversification opportunities.

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

Low debt levels have enabled Precision to cope with a weakened operating environment in 2007 and remain

opportunistic toward future growth through available debt facilities. A strong balance sheet allows Precision to invest

in meaningful growth opportunities, either organic or through industry consolidation, as they may arise.

Historic Levels of Long-term Debt

$ millions

Long-term Debt (LTD)

Equity

LTD to LTD plus Equity Ratio

Ratio

2,500

2,000

1,500

1,000

500

0.50

0.40

0.30

0.20

0.10

With over $750 million in

debt facilities available

as at December 31, 2007

Precision had borrowing

capacity of over

$600 million.

1999

2000

2001

2002

2003

2004

2005

2006

2007

In December 2007 Precision announced plans to initiate an estimated 2008 capital expenditure program of $370 million.

The proposed investments are comprised of $75 million for upgrade of existing equipment and infrastructure and

$295 million for expansion of its equipment fleet. Most of this expansion capital is targeted for the construction of

19 new drilling rigs for the North American market. The first three rigs in this program have been contracted with

one customer for work in the Rocky Mountain region of the United States pursuant to a multi-year term with deployment

expected to begin in the fourth quarter of 2008.

Looking back on fiscal 2007, Precision moved its “High Performance – High Value” business strategy forward through

noteworthy performance.

Profitability

K Precision benefited from strong industry pricing established in 2006 to generate solid earnings from continuing

operations in 2007 of $343 million or $2.73 per diluted unit compared to $573 million or $4.56 per diluted unit

in 2006.

K Precision generated operating earnings of $356 million, a decrease of $239 million or 40% over 2006. As a percent

of revenue, operating margins were strong at 35%, a decline of six percentage points over record-setting 2006.

Growth

K Net capital investment in 2007 for the purchase of property, plant and equipment decreased 22% or $52 million

from the prior year to $181 million. Before considering proceeds on asset disposals of $6 million, Precision invested

$46 million toward the upgrade of its existing asset base and $141 million on expansionary initiatives.

K Favourable year round weather and customer demand in United States natural gas basins provided attractive

returns on new capital investment.

K Precision grew its contract drilling operation in the United States from one to 12 rigs through the deployment of

seven new build Super Series rigs and four rigs from the Canadian rig fleet.

K Precision added nine new Super Series drilling rigs to its Canadian fleet, six Super Single™ rigs and three Super

Triples. Precision continued to upgrade its asset base and confirm its reputation as a high performance driller

through these new rig additions and the decommissioning of 11 low performing rigs.

P R E C I S I O N D R I L L I N G T R U S T

K Precision mobilized a triple rig from Canada to Latin America late in 2007.

K Precision completed the construction of two service rigs under a long-term customer arrangement and

decommissioned 16 service rigs.

K The camp and catering division continued to broaden its offering towards larger base camp opportunities.

K The snubbing division commissioned its first rack and pinion self-contained unit capable of snubbing and providing

other well servicing operations pursuant to a long-term customer arrangement.

K The wastewater treatment division grew its fleet of equipment by about 25% and diversified its product offering

toward smaller capacity wellsite applications.

K The rental division shifted equipment towards WCSB oil markets to optimize utilization.

Passionately Pursue Target Zero Safety Vision

K Precision made significant strides towards its Target Zero safety vision. The year-over-year improvement in safe

work practices continued for Precision, resulting in a 15% reduction in workplace recordable incident frequency

from the prior year and a 46% reduction in the past five years. Precision’s commitment to its safety programs
and education has not only reduced the incident frequency but the severity of injuries was also lower. In the past

five years, Precision has experienced a 56% reduction in lost time injury frequency.

Build Upon Our Core Group of People

K People are Precision’s most important asset; employees deliver high performance and provide customer value.

A North American shortage of skilled and experienced oilfield employees carried into 2007. Precision focused on

the retention of experienced employees through initiatives that provide a safe and productive work environment,

opportunity for advancement and added wage security through initiatives such as the Designated Driller Program.

K Precision completed its second year of internal control certification over financial reporting pursuant to Canadian

and United States securities regulations. In addition to financial controls, initiatives have reinforced the joint code

of business conduct and ethics policy and provided opportunities for Precision’s management to strengthen its

skill in identifying and managing risk.

K During the fourth quarter, Precision undertook initiatives to align infrastructure with the current operating environment

in Canada and expansion in the United States.

Cash Distributions to Unitholders

K For 2007 Precision declared cash distributions of $246 million or $1.96 per diluted unit compared to $447 million

or $3.56 per diluted unit in 2006.

K Precision generated distributable cash from operations of $311 million compared to $353 million in the prior year.

This calculation started with $484 million in cash provided from continuing operations less $181 million for net

capital expenditures and a recovery of $8 million for unfunded long-term incentive plan obligations.

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

SUMMARY OF CONSOLIDATED STATEMENTS OF EARNINGS
(Stated in thousands of Canadian dollars)

Years ended December 31,

Revenue:

Contract Drilling Services
Completion and Production Services
Inter-segment elimination

Operating earnings: (1)

Contract Drilling Services
Completion and Production Services
Corporate and Other

Interest, net
Premium on redemption of bonds
Loss on disposal of short-term investments
Other

Earnings from continuing operations before income taxes
Income taxes

Earnings from continuing operations
Discontinued operations, net of tax

Net earnings

(1) Non-GAAP measure. See page 38.

Revenue and Operating Earnings

2007

2006

2005

694,340
327,471
(12,610)

$ 1,009,821
441,017
(13,254)

916,221
369,667
(16,709)

1,009,201

1,437,584

1,269,179

284,754
100,596
(28,999)

356,351

7,318
–
–
–

349,033
6,213

342,820
2,956

473,624
163,119
(41,464)

595,279

8,029
–
–
(408)

587,658
15,146

572,512
7,077

404,385
121,643
(60,650)

465,378

29,270
71,885
70,992
–

293,231
72,383

220,848
1,409,715

345,776

579,589

$ 1,630,563

$ millions

Revenue – Contract Drilling

Operating Earnings – Contract Drilling

Revenue – Completion & Production

Operating Earnings – Completion & Production

1,600

1,400

1,200

1,000

800

600

400

200

2003

2004

2005

2006

2007

Capital Expenditures by Type

$ millions

Upgrade

Expansion

300

250

200

150

100

For 2007, industry

conditions in Canada

have reduced Precision’s

operating results from

historic highs.

In the past two years,

Precision has invested

more towards

expansionary initiatives

to grow its fleet of Super

Series drilling rigs.

2003

2004

2005

2006

2007

P R E C I S I O N D R I L L I N G T R U S T

For the year ended December 31, 2007 Precision’s earnings from continuing operations were $343 million or $2.73

per diluted unit compared to $573 million or $4.56 per diluted unit in 2006. The decrease of $1.83 per diluted unit

was due to lower activity and pricing for Precision’s Canadian services in 2007 compared to 2006. The decline in

activity was due to decreased demand for natural gas services in the WCSB brought about by lower natural gas

pricing in North America and less confidence in the short-term future price of natural gas.

For 2007, earnings benefited from a future income tax recovery of $22 million due to enacted Canadian federal tax

rate reductions and were lowered by an asset write down charge of $7 million for decommissioned rigs and a $5 million

expense for personnel reductions. As a result of these three items plus the tax benefit of $4 million from asset write

downs and personnel reductions, net earnings increased by $14 million or $0.11 per diluted unit as compared to

tax recoveries in 2006 of $21 million or $0.17 per diluted unit.

Fiscal 2007 results were indicative of soft natural gas prices and strong oil prices. West Texas Intermediate (“WTI”)

crude oil averaged US$72.45 per barrel in 2007 versus US$66.11 in 2006 and Henry Hub natural gas averaged

US$6.94 per MMBtu in 2007 versus US$6.72 in 2006. On Canadian markets the average price for AECO natural

gas one-year forward was $7.50 per MMBtu in 2007 compared to $8.49 in 2006. The AECO natural gas price for

December 2006 averaged $6.76 per MMBtu and traded as low as $4.69 in September 2007 before increasing steadily

to close out December 2007 at $6.12 per MMBtu.

The weakening of the U.S. dollar compared with the Canadian dollar has also had a negative impact on the cash

flow of many of Precision’s Canadian customers. During 2007 the Canadian dollar appreciated by 18% against the

U.S. dollar.

During 2007 there were 18,342 wells drilled in western Canada on a rig release basis, a 19% decline from the 22,575

drilled in 2006. With the decline in the number and change in the mix of wells drilled, total industry drilling operating

days declined by 24% to 120,961. The average industry drilling operating days per well in 2007 was 6.6 days compared

to 7.0 days in 2006.

In 2007, higher oil and lower gas prices prompted some customers to shift drilling dollars to oil prospects in lieu of

natural gas or natural gas in coal. In the WCSB in 2007 the total number of well licenses issued for oil targets was

6,486 which represented a 10% decline over 2006 and 34% of the total licenses issued compared to 27% in 2006.

Well licenses for natural gas prospects declined 30% in 2007 to 12,740.

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

OUTLOOK

The bearish oilfield services demand that Precision and the Canadian industry faced in 2007 is expected to persist

at least through the first half of 2008. Precision expects continued pressure on pricing and an extremely competitive

seasonal spring break-up. As capacity to provide services continues to exceed demand and pricing becomes more

competitive, any further reductions will have a proportionately greater impact on profit margins. The permanent fleet

reductions and fixed expense reductions in the fourth quarter of 2007 were tailored to size Precision more appropriately

for this level of activity and competition.

Precision is well positioned to manage the existing downturn in the sector due to its strong balance sheet, ability to

control costs and solid platform for future growth with its people, technology and an increasingly diversified geographic

base. Wages and field crew rates are expected to hold at current levels for 2008.

To the end of February 2008, natural gas prices have advanced approximately 25% with storage levels about 10%

below the prior year as winter withdrawals are at normal seasonal levels. Strong natural gas consumption coupled

with reduced Canadian exports and uncertain liquefied natural gas (“LNG”) imports to the United States may lead

to strengthening economic fundamentals for drilling later in 2008 with improved demand for services possible in late

third or fourth quarter.

United States Working Gas in Underground Storage Compared with 5-Year Range

Billion Cubic Feet

Period Storage

5-year Historical Range

3,600

3,200

2,800

2,400

2,000

1,600

1,200

800

400

Storage levels are

moderating after two

years of seasonally

adjusted highs.

Source: U.S. Energy Information
Administration (EIA)

Feb
06

May
06

Aug
06

Nov
06

Feb
07

May
07

Aug
07

Nov
07

Feb
08

Precision will continue its focus on value based high performance services where customers recognize and reward

superior performance. This presents Precision with significant opportunity, especially in technically demanding

unconventional drilling applications. A greater proportion of wells drilled in North America are seeking unconventional

resource plays and due to the complexity of these programs high performance drilling rigs and services are required.

Precision will remain highly focused on United States expansion. Precision will aggressively exploit organic growth

opportunities with customers in Canada and the United States given the continued demand for premium equipment

such as Precision’s Super Series rigs. A clear delineation between underperforming rigs and high performance, highly

mobile, well designed rigs with exceptional crews has emerged. Precision is finding that its operational execution

and safety performance are significant marketing advantages as United States operations grow and its Canadian

fleet remains underutilized.

Precision converted to an income trust in 2005 as the tax rules of the day allowed the market to place a higher value

for unitholders on the flow-through structure than the traditional corporate structure. In light of legislated and proposed

changes the Board of Trustees, along with the Board of Directors and management, are examining whether the current

legal entity structure and capital structure are appropriate for Precision’s business strategy and in the best interests

of unitholders.

P R E C I S I O N D R I L L I N G T R U S T

MD&A

DYNAMICS OF THE OILFIELD SERVICES INDUSTRY

Through this report, management is presenting its views of Precision’s business and the industry in which it operates.

Understanding the oil and gas industry and the factors that impact demand for oilfield services is important to assess

risk factors that affect Precision’s long-term strategy and financial performance.

GLOBAL MARKETS

Global economic growth and prosperity drives energy consumption. Crude oil and to a lesser extent natural gas are

the most dominant and versatile sources of energy in developed countries while crude oil and coal are the dominant

sources of energy in developing countries. Oil and its by-products are currently the most important fuel for the

transportation industry as there are few alternatives that can compete economically. Oil and natural gas are primary

fuel sources for generating heat and electricity and are critical building blocks for countless consumer products.

With 6.6 billion people worldwide and the world population expected to rise 1.1% per year, global energy demand

is unprecedented and rising. From a reference year of 2004, energy consumption is projected by the United States

government Energy Information Administration (“EIA”) to increase 57% by 2030 with oil, natural gas and coal meeting

approximately 86% of global demand. World oil consumption is predicted to rise about 1.9% in 2008 due largely to

growing demand in China, India and other developing countries. Delivering reliable and affordable energy for these

fast-growing and upwardly mobile populations is a major challenge in this century with security of supply becoming

a dominate theme globally. The EIA is forecasting natural gas consumption increases of 1.9% on average per annum

to 2030 as rising oil prices increase the demand for natural gas as an alternative fuel in industrial and electrical sectors

in developed and developing economies.

NORTH AMERICAN MARKETS

The economics of the oilfield service industry are aligned with global and regional fundamentals. Important regional

drivers for the industry in North America include the underlying hydrocarbon make-up of the varied basins and the

existence of established, competitive and efficient service infrastructure. With high service costs per barrel of oil equivalent

production in Canada and increased pipeline takeaway capacity within the United States due to infrastructure investment,

capital allocation by customers has increasingly favoured unconventional natural gas basins in the United States.

The hydrocarbon basins of North America are diverse and conventional oil and natural gas reservoirs exist at a variety

of depths. These conventional sources are complemented by more costly and challenging unconventional reservoirs

associated with oil sands, heavy oil, natural gas in coal and in shale and in deeper, low permeability formations. About

70% of the proven natural gas reserves in North America are situated in the United States with the remaining 30%

in Canada. In 2007, 83% of drilling activity in the United States and 70% in Canada targeted natural gas.

10 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

Estimated Proved Reserves of Natural Gas

Canadian Basins

United States Basins

Estimated Proved Reserves (Tcf)

Canada

1 Mackenzie/Beaufort

2 Western Canada

3 Eastern Canada

United States

4 Alaska

5 Rocky Mountains

6 Mid-continent/Permian

7 Gulf Region

8 Other Lower-48

Total

207

283

Source: Ziff Energy, as of January 1, 2007

The emergence of LNG as a fungible commodity is an important new source of supply to North America that could

offset production declines from mature reservoirs and help meet rising natural gas demand. There are still technical,

political and environmental challenges for significant LNG developments to occur in North America, but it is widely

projected to be a necessary source of supply as demand for natural gas increases. Less than 5% of the world’s

proven reserves of natural gas exist in North America yet more than 25% of worldwide natural gas consumption

occurs in North America.

With next-door proximity to the world’s biggest energy consumer Canada has become the world’s seventh largest

oil producer and third largest producer of natural gas. With oil sands development, Canada is one of the few countries

with growing oil production. A highly integrated continental energy transportation system, security of supply and access

to United States markets has made Canada one of the largest energy providers to the United States. Currently, over

half of Canadian oil and natural gas production is exported to the United States.

ECONOMIC DRIVERS OF THE OILFIELD SERVICES INDUSTRY

Providing oil and natural gas products to consumers involves a number of players, each taking on different risks in
the exploration, production, refining and distribution processes. Exploration and production companies, Precision’s

customers, assume the risk of finding hydrocarbons in reservoirs of sufficient size to economically develop and produce.

The economics are dictated by the current and expected future margin between the cost to find and develop hydrocarbons

and the eventual price of these products. The wider the margin, the greater the incentive to undertake these risks.

Exploration and development activities include acquiring access to prospective lands, seismic surveying to detect

hydrocarbon bearing structures, drilling wells and completing successful wells for production. Exploration and production

companies hire oilfield service companies to perform the majority of these tasks. The revenue of an oilfield service

company is part of the finding and development costs for an exploration and production company.

The economics of an oilfield service company are largely driven by the price of crude oil and natural gas realized by

its customers. Since oil can be transported relatively easily, it is priced in a global market influenced by an array of

economic and political factors. Natural gas is priced in continental markets with supply from LNG a growing factor

subject to availability.

P R E C I S I O N D R I L L I N G T R U S T

There is a narrowing supply-demand balance for natural gas in North America. Many industry observers believe a

new pricing floor may be set due to the combination of production declines and demand growth. New hydrocarbon

reserves are clearly more costly and difficult to discover and develop and it is becoming increasingly necessary to

use high performance drilling rigs and support services to complete well programs. It has taken record drilling activity

over the last three years in North America to marginally increase overall natural gas production levels. To a large

extent this production growth has been derived from unconventional production with significant first-year decline rates.

Number of Producing Wells in Western Canada

Oil Wells

Natural Gas Wells

200,000

160,000

120,000

80,000

40,000

There has been a steady

increase in the number

of producing natural gas

wells in the WCSB in the

last 10 years.

Source: 1998–2006 Alberta Energy
and Utilities Board, 2007 Precision
estimate

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007
Estimate

Rising energy demand coupled with depletion of conventional resource basins has created an historic shift in the oil

and natural gas industry in North America to develop unconventional resources such as oil sands, natural gas in

shale and in coal and in deeper, low permeability formations. The economics of unconventional resource plays are

enhanced by technology such as multi-well pad locations, high performance drilling rigs and advanced reservoir

stimulation techniques.

Reserves to production ratios, which indicate how quickly reserves are depleting, have flattened after a period of

decline starting in the 1990s. This implies that drilling activity must stay level or increase just to maintain current

production and producers may need to drill deeper, more remote resource plays to secure large gas fields and extend

reserve life.

WCSB Well Completions vs AECO Spot Natural Gas Price

WCSB Completed Wells

Oil

Gas

Dry

Service

AECO Spot Price

C$/MMBtu

The number of natural

25,000

20,000

15,000

10,000

5,000

10.00

gas well completions

8.00

6.00

4.00

2.00

in Canada is directly

impacted by natural

gas prices.

Source: Canadian Association
of Oilwell Drilling Contractors
(“CAODC”), Ziff Energy

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

The graph above compares WCSB well completions and natural gas pricing over the past 10 years. A decline in the

natural gas price in the last two years led to a significant decline in 2007 gas well completions. Soft natural gas prices

were the result of low consumption due to mild winters and marginally higher productivity in the United States which

placed gas storage above the five-year average.

With growing energy demand, the supply of drilling rigs in Canada increased steadily over the past 14 years to an
all-time high of about 900. Customer demand, measured by annual drilling rig operating day utilization, peaked at
71% in 1997 and has since ranged between 38% and 60%. Industry utilization for 2007 was 38%. The current excess

12 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

drilling rig capacity in Canada has prompted some oilfield service providers to consider relocating certain assets in

their drilling fleets to the United States land drilling market. As illustrated below, Canadian rig activity fluctuates with

the seasons, an event which generally does not occur in the United States.

Active and Existing Canadian Drilling Rigs

Total Active

Total Fleet

900

800

700

600

500

400

300

200

100

Canadian rig activity

is seasonal and has

declined from record

levels in 2005 due

to lower natural gas

prices.

Source: CAODC

Q2 Q3 Q4 Q1
2001

Q2 Q3 Q4 Q1
2002

Q2 Q3 Q4 Q1
2003

Q2 Q3 Q4 Q1
2004

Q2 Q3 Q4 Q1
2005

Q2 Q3 Q4
2006

Q2 Q3 Q4
2007

The United States land drilling fleet has steadily increased from about 1,500 rigs in 2002 to a recent peak in 2007

of about 2,200 rigs.

Active and Existing U.S. Drilling Rigs

Total Active

Total Fleet

2,500

2,000

1,500

1,000

500

U.S. rig counts have

maintained a steady

increase in activity in

the past six years.

Source: RigData

Q2 Q3 Q4 Q1
2001

Q2 Q3 Q4 Q1
2002

Q2 Q3 Q4 Q1
2003

Q2 Q3 Q4 Q1
2004

Q2 Q3 Q4 Q1
2005

Q2 Q3 Q4
2006

Q2 Q3 Q4
2007

Precision estimates about 1,200 drilling rigs in the United States fleet were constructed prior to 1990 and underperform

when tasked with drilling unconventional complex resource plays. With increased exploitation of unconventional
resource basins the demand for high performing rigs and crews capturing premium pricing continues to grow, displacing
the underperforming rigs.

Active U.S. Rigs by Well Type

Percentage

Vertical Drilling

Horizontal and Directional

100

The increase in

horizontal and

directional drilling

is indicative of the

increasing demand

for high performance

drilling rigs.

Source: Baker Hughes

P R E C I S I O N D R I L L I N G T R U S T

MD&A

PRECISION’S DEVELOPMENT

PRECISION’S HISTORY OF CONTINUING OPERATIONS

Precision began operating in western Canada as a land drilling contractor in the 1950s. A combination of new equipment

purchases and acquisitions over the last twenty years has expanded fleet capacity and added complementary

businesses. For the past decade, Precision has been Canada’s largest oilfield services provider.

Contract Drilling Services Segment

Precision’s Contract Drilling Services are known within the industry as a part of the upstream sector with operations

at the well location to facilitate the drilling of natural gas, oil and, in rare circumstances, geothermal wells. It is the

underlying well program requirements that determine which rig is best suited to drill a particular prospect for customers.

Precision’s development was founded on the successful integration of acquisitions. In the decade following a 1987

reverse takeover, a series of acquisitions expanded Precision’s Canadian drilling fleet from four to 106 rigs. With the

acquisition of Kenting Energy Services Inc. in 1997, Precision essentially doubled its fleet to 200 rigs representing

approximately 40% of the drilling fleet in Canada. The acquisitions of coil tubing drilling rigs and other shallow drilling

rigs in 2000 rounded out the acquisition history for Precision’s fleet in Canada.

To close out fiscal 2007, after upgrading the fleet through strategic new rig builds and decommissions, Precision’s

232 drilling rigs in Canada comprised 26% of the Canadian market, 12 rigs in the United States represented a U.S.

market start and share of 1% and one rig in Latin America launched a new global direction for Precision.

To better operate ancillary assets and to provide a comprehensive suite of services to customers, Precision acquired

and reorganized assets into complementary businesses. In 1993, Precision entered the camp and catering business

with the acquisition of LRG Oilfield Services Ltd. Along with camps from drilling rig business acquisitions and the

purchase in 2003 of McKenzie Caterers (1984) Ltd., this division now has 102 camps. In 1996 Precision added in-house

capabilities for the design, fabrication and maintenance of rig components with the acquisition of Rostel Industries

Ltd. The 1997 acquisition of Columbia Oilfield Supply Ltd. led to the integration of purchasing systems and qualitative

improvements in product selection and standardization in all of Precision’s businesses.

Completion and Production Services Segment

Precision’s Completion and Production Services are also known within the oil and gas industry to be a part of the

upstream sector with operations at the well location to complete wells that have been drilled and to maintain wells

that have been placed into production. The underlying well program parameters determine the type of service rig

and ancillary services best suited to workover a particular well. Service rigs are versatile and capable of working on

both oil and natural gas wells. Design and technological improvements have made equipment offerings more

competitive through efficiency gains and wide market appeal to a broad range of well requirements.

14 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

In 1996 Precision diversified into businesses that became the foundation for the Completion and Production Services

segment, specifically Precision Well Servicing, Live Well Service and Precision Rentals, through the acquisition of

EnServ Corporation. The acquisition enabled Precision to offer services that tracked the life of a particular oil or natural

gas well, build customer relationships and moderate demand volatility associated with the drilling of new wells. In

2000 Precision became fully vested in the Canadian service rig business with the acquisition of CenAlta Energy Services

Inc. to create a combined fleet of 257 service rigs and an industry-leading market share at the time of 28%. Through

additional acquisitions in the late 1990s the rental businesses grew and in 2002 were combined and branded as

Precision Rentals. In 2006, Precision expanded into the business of remote work site wastewater treatment with the

acquisition of Terra Water Group Ltd.

To close fiscal 2007, after adding two new service rigs and decommissioning 16, Precision’s 223 service rigs and

27 snubbing units comprised 20% and 24% of the Canadian market. In addition to completing and servicing wells,

the segment offers snubbing to service natural gas wells while pressurized, rental equipment and wastewater treatment

for remote accommodations.

Rigs built by Precision are designed for greater safety and operating efficiency to deliver well cost savings to customers.

High performance drilling rigs combine high mobility, automation, advanced control systems, minimal environmental

impact, and highly trained crews. A freestanding service rig lowers costs for customers through set up efficiency and

minimal ground disturbance which reduces the risk of striking underground utilities. Over the past 12 years Precision

has been developing the Super Series drilling rigs and has built 35 Super Single™, seven Super Single™ Light and

eight Super Triple rigs. Precision also manufactured 10 freestanding mobile single and six slant service rigs.

STRATEGIC DIRECTION

Precision is geographically diversifying to the United States and international markets by leveraging its well known

Canadian reputation for “High Performance – High Value” on-shore drilling services for oil and natural gas exploration

and development.

Precision delivers “High Performance” services through excellent people, comprehensive support systems and deploying

technically superior equipment. This unique “High Performance” competitive advantage serves to reduce customer

cost and minimize the operational risks associated with drilling and servicing oil and gas wells. Precision’s reputation

of “High Value” is evident in its leading financial and operational performance, employee retention, safety and

environmental performance and specifically its market share growth in the new entry markets.

Precision’s business strategy includes the following:

K To geographically diversify into markets beyond Canada to reduce seasonality of equipment utilization and

dependence on underlying economics of the WCSB;

K To capitalize on production growth and resulting drilling opportunities in the United States, especially unconventional

natural gas wells;

K To pursue global oil drilling opportunities;

K To invest in asset growth that renders customer value through enhanced service performance:

– New asset deployment results in organic growth and market share gains as onshore oil and gas basins have
matured. Precision’s superior equipment technology delivers significantly better operating performance, especially
in complex and demanding customer well programs;

– Precision seeks consolidation opportunities to implement its core capabilities of employee recruitment, safety,

training, environmental footprint, equipment maintenance, equipment manufacturing, supply chain management

and cost control to upgrade performance of existing equipment fleets.

P R E C I S I O N D R I L L I N G T R U S T

Precision’s core capabilities reside with its employees, systems, and technology. These areas of competence provide

the operating leverage for organic new asset construction growth and for consolidation based growth.

Precision continually reviews assets, retiring those which are less competitive and upgrading others. Precision intends

to continue to build high performance “Super Series” drilling rigs targeted to customers who recognize and reward

the cost saving benefits of these services.

KEY PERFORMANCE DRIVERS

Customer economics are dictated by the current and expected margin between the price at which hydrocarbons

are sold and the cost to find and develop those products. Some of the key business, customer and industry indicators

that Precision focuses on to monitor its performance are:

Safety Management: Precision’s culture is based on the foundation of an all-encompassing Target Zero vision.

Precision’s philosophy states that the workplace and organization can be free from injuries, equipment damage and

negative environmental impact. Safety performance is a fundamental contributor to operating performance and the

financial results Precision generates for unitholders. Safety is tracked through an industry standard recordable frequency

statistic which is measured to benchmark successes and illustrate areas for improvement.

Operating Efficiency: Precision maximizes the efficiency of its operations through its proximity to work sites, its

operating practices and its versatility. Precision’s reliable and well maintained equipment minimizes downtime and

non-productive time during operations. Information is gathered from daily drilling log records stored in a database and

analyzed to measure productivity, efficiency and effectiveness.

Key factors which contribute to lower customer well costs are:

K Mechanical downtime which is managed through preventative maintenance programs, detailed inspection processes,

an extensive fleet of strategically placed spare equipment, an in-house supply chain, and continuous equipment

upgrades; and

K Non-productive time, or move, rig-up and rig-out time, which is minimized by decreasing the number of move loads

per rig, using lighter move loads, and using mechanized equipment for safer and quicker rig component connections.

Customer Demand: Precision’s fleet is geographically dispersed to meet customer demands. Relationships with

customers, industry knowledge and new well licenses provide Precision with the information necessary to evaluate

its marketing strategies. The ability to provide customers with some of the most innovative and advanced rigs in the

industry to reduce total well cost increases the value of the rig to the customer. Industry rig utilization statistics are

also tracked to evaluate Precision’s performance against competitors.

Workforce: Precision closely monitors crew availability for field operations. Precision focuses on initiatives that provide

a safe and productive work environment, opportunity for advancement and added wage security through programs

to retain employees. Precision relies heavily on its safety record and reputation to attract and retain employees as

industry manpower shortages are often experienced in peak operating periods.

Financial Performance: Precision maximizes revenue without sacrificing operating margins. Key financial information

is unitized on a per day or per hour basis and compared to established benchmarks and past performance. Precision

evaluates the relative strength of its financial position by monitoring its working capital and debt ratios. Low debt

levels have allowed Precision to manage the cyclical nature of the industry and provide the financial leverage to invest

in meaningful growth opportunities.

16 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

OPERATING SEGMENTS

In the Contract Drilling Services segment:

K Precision Drilling operates 232 land drilling rigs in Canada;

K Precision Drilling Oilfield Services operates 12 land drilling rigs in the United States;

K A Precision affiliate operates one rig in Latin America;

K LRG Catering operates 102 camps, with food catering, in Canada and the United States;

K Rostel Industries provides engineering, machining, fabrication, component manufacturing and repair services for

drilling and service rigs primarily for Precision’s operations; and

K Columbia Oilfield Supply provides centralized procurement, standardized product selection, and coordinated

distribution of goods for Precision’s operations.

In the Completion and Production Services segment:

K Precision Well Servicing operates 223 well completion and workover service rigs in Canada;

K Live Well Service operates 27 snubbing units in Canada;

K Precision Rentals provides approximately 13,000 rental items in Canada including well control equipment, surface

equipment, specialty tubulars and wellsite accommodation units; and

K Terra Water Systems provides 63 wastewater treatment units.

Precision Drilling

The tables below categorize the capacity and positioning of Precision’s drilling rig fleet for the past two years:

2007

Maximum Depth Rating

Type of Drilling Rig

Metres

Feet

Horsepower

Canada

U.S.

International

Total

Single
Super Single™
Double
Super Triple
Light triple
Heavy triple
Coiled tubing

Total

2006

1,200
3,000
3,000
4,000
3,600
6,700
1,500

4,000
10,000
10,000
13,000
12,000
22,000
5,000

250-300
400-800
300-500
1,200
500-750
1,000-2,000
250-300

14
33
87
8
40
39
11

–
8
–
–
2
2
–

232

–
–
–
–
–
1
–

14
41
87
8
42
42
11

245

Maximum Depth Rating

Type of Drilling Rig

Metres

Feet

Horsepower

Canada

U.S.

International

Total

Single
Super Single™
Double
Super Triple
Light triple
Heavy triple
Coiled tubing

Total

1,200
3,000
3,000
4,000
3,600
6,700
1,500

4,000
10,000
10,000
13,000
12,000
22,000
5,000

250-300
400-600
300-500
1,200
500-750
1,000-2,000
250-300

14
28
94
5
44
44
11

240

–
1
–
–
–
–
–

–
–
–
–
–
–
–

–

14
29
94
5
44
44
11

241

P R E C I S I O N D R I L L I N G T R U S T

The following table lists the drilling depth capability of Precision and industry drilling rigs in western Canada at

December 31, 2007:

Type of Drilling Rig

Single
Super Single™ (2)
Double
Super Triple (5)
Light triple
Heavy triple
Coiled tubing

Total

Precision Fleet

Industry Fleet (1)

Maximum
Depth Rating
(metres)

Number
of Rigs

% of
Total

%
Market
Share (3)

Number
of Rigs

1,200
3,000
3,000
4,000
3,600
6,700
1,500

14
33
87
8
40
39
11

6
14
38
3
17
17
5

232

100

8
89
22
100
34
36
16

165
37
393
8
116
109
70

898

% of
Total

18
4
44
1
13
12
8

100

Change (4)

20
4
29
3
(1)
(4)
5

(1) Source: Daily Oil Bulletin – Rig Locator Report as of January 2008. Precision has allocated the industry rig fleet by rig type and removed 11 decommissioned rigs.

(2) Super Single™ excludes single rigs that do not have automated pipe-handling, a self-contained top drive or run extended length drill pipe/casing.

(3) Market share means Precision’s rigs as a percent of industry rigs estimated by Precision.

(4) Change in number of industry rigs as compared to the prior year.
(5) Super Triple includes features such as extended length drill pipe, AC power, iron roughneck, mobility without cranes, top drive and an advanced control system.

Precision Well Servicing

The configuration of Precision Well Servicing’s Canadian fleet for the past four years is illustrated in the following

table:

Type of Service Rig

Singles:

Mobile
Freestanding mobile

Doubles:
Mobile
Freestanding mobile
Skid
Slants:

Freestanding

Total

Horsepower

2007

2006

2005

2004

150-400
150-400

250-550
200-550
300-860

250-400

5
94

43
9
55

223

12
92

44
9
65

237

17
88

44
8
65

237

19
86

42
9
67

239

CAPACITY TO DELIVER

Precision is a major supplier of services to oil and gas companies and its success is dependant on providing a

complement of oilfield services that are cost effective to its customers. Precision prides itself on providing quality

equipment operated by highly experienced and well trained crews. Maintaining customer relationships is fundamental

to Precision’s success and is based in large part upon the ability to deliver.

High Performance Drilling Rigs

Precision Drilling is focused on providing efficient, cost-reducing drilling technology. Design innovations and technology

improvements capture incremental time savings during all phases of the well drilling process, including moving

between wells.

18 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

The versatile Super Single™ design comprises technical innovations in safety and drilling efficiency and outpaces

competition in slant or directional drilling on single or multiple well pad locations in shallow to medium depth wells. It is

extremely proficient on conventional vertical wells and has drilled in many regions of the world. Super Single™ rigs utilize

extended length tubulars, integrated top drive, innovative unitization to facilitate quick moves between well locations,

a small footprint to minimize environmental impact and enhanced safety features such as automated pipe handling

and remotely operated torque wrenches.

A scaled-down version without slant capability, the Super Single™ Light, also features an integrated top drive and

automated pipe handling and is unitized and trailer mounted to reduce the load count for efficient moving, rig up

and tear down for the shallow well depth market.

Triple rigs have greater hoisting capacity and are used in deeper exploration and development drilling. The Super Triple
electric rigs are fabricated to keep the load count as low as possible using widely available conventional rig moving

equipment. Power capabilities are a major design criterion for the new Super Triple rigs. Drilling productivity and reliability

with AC power drive systems provides added precision and measurability along with a computerized electronic auto

driller feature that precisely controls weight, rotation and torque on the drill bit. These rigs use extended length drill

pipe, an integrated top drive, automated pipe handling with iron roughnecks and control automation off the rig floor.

Large Diversified Rig Fleets

Precision’s large diverse fleet of rigs is strategically deployed across the most active regions of the WCSB, and in

targeted basins in the United States. When an oil and gas company needs a specific type or size of rig in a given

area, there is a high likelihood that a Precision rig will be readily available. Geographic proximity and fleet versatility

make Precision a premium service provider. Precision’s fleet can drill virtually all types of on-shore conventional and

unconventional oil and natural gas wells in North America.

Precision’s service rigs provide completion, workover, abandonment, well maintenance, high pressure and critical

sour gas well work and well re-entry preparation across the WCSB. The rigs are supported by three field locations

in Alberta, two in Saskatchewan and one in British Columbia.

Snubbing complements traditional natural gas well servicing by allowing customers to work on wells while they are

pressurized and production has been suspended. Precision has two types of snubbing units – rig assist and self-

contained. Self-contained units do not require a service rig on site and are capable of snubbing and performing many

other well servicing procedures.

Inventory of Ancillary Equipment

Precision has a large inventory of equipment, including portable top drives, loaders, boilers, tubulars and well control
equipment, to support its fleet of drilling and service rigs to meet customer requirements. Precision also maintains

an inventory of key rig components to minimize downtime in the event of equipment failures.

In support of drilling rig operations, LRG Catering supplies meals and provides accommodation for rig crews at remote

worksites. Terra Water Systems plays an essential role in providing wastewater treatment services for LRG Catering

and other camp facilities. Precision Rentals supplies customers with an inventory of 13,000 pieces of specialized

equipment and wellsite accommodations.

Industry Leading Safety Program

Safety is critical for Precision and its customers. The focus on working safely is one of Precision’s most enduring values.

The goal of Target Zero – Precision’s safety vision for eliminating workplace incidents – is a fundamental belief that

all injuries can be prevented. In 2007, 363 of Precision’s drilling and service rigs achieved Target Zero. Precision is

a leader in adopting technological advancements which have made drilling rigs, service rigs and snubbing units safer.

P R E C I S I O N D R I L L I N G T R U S T

Well-maintained Equipment

Precision consistently reinvests capital to sustain and upgrade existing property, plant and equipment.

Upgrade Capital Expenditures

$/day

1,400

1,200

1,000

800

600

400

200

Upgrade Spending per
Drilling Rig Operating Day

Upgrade Spending per
Service Rig Operating Hour

$/hour

Well maintained

equipment minimizes

mechanical downtime

and non-productive time.

2003

2004

2005

2006

2007

In addition to capital expenditures as illustrated above, equipment repair and maintenance expenses are benchmarked
to activity levels in accordance with Precision’s maintenance and certification programs. Precision employs computer

systems to track key preventative maintenance indicators for major rig components to record equipment performance

history, schedule equipment certifications, reduce downtime and allow for better asset management.

Precision benefits from internal services for equipment certifications and component manufacturing provided by Rostel

Industries and for standardization and distribution of consumable oilfield products through Columbia Oilfield Supply.

Employees

As a service company, Precision is as good as its people. An experienced, competent crew is a competitive strength

and highly valued by customers. To recruit rig employees, Precision has centralized personnel departments and

orientation and training programs.

Information Systems

Precision’s commitment to invest in a fully integrated enterprise-wide reporting system has improved business

performance through real-time access to information across all functional areas. All divisions operate on a common

integrated system using standardized business processes across finance, payroll, equipment maintenance, procurement

and inventory control.

Precision continues to invest in information systems that provide competitive advantages. Electronic links between

field and financial systems provide accuracy and timely processing. This repository of rig data improves response

time to customer enquires. Rig manufacturing projects benefit from scheduling and budgeting tools as economies

of scale can be identified and leveraged as construction demands increase.

20 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

MD&A

FINANCIAL RESULTS

CONTRACT DRILLING SERVICES SEGMENT
(Stated in thousands of Canadian dollars, except where indicated)

Years ended December 31,

Revenue
Expenses:

Operating
General and administrative
Depreciation
Foreign exchange

2007

% of
Revenue

2006

% of
Revenue

2005

% of
Revenue

$ 694,340

$ 1,009,821

$ 916,221

345,043
19,946
43,120
1,477

49.7
2.9
6.2
0.2

41.0

470,713
27,225
38,573
(314)

$ 473,624

46.6
2.7
3.8
–

46.9

448,930
23,911
39,233
(238)

$ 404,385

49.0
2.6
4.3
–

44.1

Operating earnings (1)

$ 284,754

% Increase
2007 (Decrease)

245

1.7

30,475
1,850

(31.9)
988.2

2006

241

44,768
170

% Increase
(Decrease)

4.8

(4.6)
–

2005

230

46,937
–

% Increase
(Decrease)

0.4

12.8
–

19,096

(7.0)

20,528

13.8

18,034

9.3

4,718
6.5
5,813
1,232

(23.7)
(9.7)
(25.6)
(2.5)

6,180
7.2
7,810
1,264

(20.4)
20.0
(12.3)
10.3

7,766
6.0
8,901
1,146

3.2
9.1
11.0
7.5

Number of drilling rigs (end of year)
Drilling operating days:

Canada
United States

Drilling revenue per operating day:

Canada
Drilling statistics: (2)

Number of wells drilled
Average days per well
Number of metres drilled (000s)
Average metres per well

(1) Non-GAAP measure. See page 38.

(2) Canadian operations only.

P R E C I S I O N D R I L L I N G T R U S T

2007 Compared to 2006

The Contract Drilling Services segment generated revenue of $694 million in 2007, 31% less than the record revenue

of $1.0 billion in 2006. The decrease was due to lower equipment utilization and reduced pricing resulting from lower

customer demand for natural gas drilling in Canada, partially offset by additional rigs and strong utilization in the

United States.

Operating earnings of $285 million decreased $189 million or 40% from $474 million in 2006 and were 41% of revenue

in 2007 compared to 47% in 2006 primarily due to lower pricing in the final nine months of 2007. Operating expenses

increased from 47% of revenue in 2006 to 50% in 2007. On an operating day basis, costs increased due to crew

wage rate increases in October 2006 and an overall increase in the cost of materials. Lower equipment utilization

also resulted in increased daily operating costs associated with fixed operating cost components.

Capital expenditures for the Contract Drilling Services segment in 2007 were $159 million and included $126 million

to expand the underlying asset base and $33 million to upgrade existing equipment. The majority of the expansion

capital was associated with new drilling rig construction for operations in the United States and Canada. During 2007

the segment commissioned 16 new rigs backed by customer term arrangements and decommissioned 11 rigs.

The Precision Drilling division revenues decreased $337 million or 37% over 2006 to $582 million. This decline was

due to a decrease in customer demand resulting in lower utilization for Precision. Precision’s Canadian drilling rig

activity in 2007 was down 14,293 operating days or 32% overall compared to 2006 as customers curtailed drilling

due to low natural gas prices, changing royalty rates resulting from the Alberta government royalty review, a strong

Canadian dollar relative to the U.S. dollar, record industry rig capacity and customer concern over high service costs.

Industry operating days in Canada were 120,961, a decline of 24% from 158,416 in 2006. With an industry fleet

expanded by 7% to 898 rigs at the end of 2007, the industry operating day utilization declined to 38% in 2007 from

55% in 2006.

Average drilling rig operating day rates for Precision in Canada decreased 7% in 2007 from 2006. Rates held up

well due to pricing for rigs under term contracts for Precision’s versatile, high performing rigs and strong pricing in

the first quarter of 2007.

Operating earnings decreased by 45% over 2006 due mainly to the 32% decrease in activity, the 7% decrease in

the average operating day rate and 4% crew wage rate increase in October 2006. Depreciation expense for the year

was $1 million higher than in 2006 as the impact of lower activity was offset by a $3 million write down charge for

decommissioned rigs and a change in rig mix.

Precision Drilling Oilfield Services in the United States generated revenue of $51 million in 2007, a ten-fold increase
over 2006. The rig fleet grew from one rig at the end of 2006 to 12 rigs at the end of 2007 and operated at 99%
utilization including move days. The fleet increase included seven new Super Single™ drilling rigs and four rigs deployed

from Canada. United States operations are in the Rocky Mountain region based out of Colorado and the South Central

region based out of Texas.

LRG Catering experienced activity declines of 51% in 2007 from a record 2006, with revenue decreasing 43%. As

a result of the lower industry activity, LRG experienced downward pricing pressure, however increased base camp

activity mitigated average day rate declines.

Rostel Industries and Columbia Oilfield Supply divisions provided valuable support, best measured by the efficiencies

and contributions made to Precision through cost savings. Rostel’s expertise provided Precision control over rig

construction and enhanced cost control. Columbia leveraged its volume purchasing advantage and supplier relationships

to provide timely and reliable supplies to keep Precision’s rigs operating and allowed Precision to standardize product

use and quality.

22 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

2006 Compared to 2005

The Contract Drilling Services segment generated record financial results in 2006. Revenue was $1.0 billion in 2006,

an increase of $94 million or 10% from 2005 due to an increase in average pricing for Precision’s services.

Operating earnings increased by $69 million or 17% to $474 million and were 47% of revenue in 2006 compared

to 44% in 2005 primarily due to pricing improvements. Operating expenses declined from 49% of revenue in 2005

to 47% in 2006, but increased per operating day due to higher crew wages and cost of materials.

Capital expenditures for the segment in 2006 were $220 million and included $158 million to expand the underlying
asset base and $62 million to upgrade existing equipment. The majority of the expansion capital expenditure was
associated with new drilling rig construction.

The Precision Drilling division revenue increased by $73 million or 9% over 2005 to $919 million, with the decrease

in activity for 2006 more than offset by increased rates.

Operating earnings in the division increased by 17% over 2005 due mainly to a 14% increase in the average operating
rate offset by a 5% decline in activity. Depreciation expense for the year was $3 million higher due to the change in
rig mix in the year with increased deep rig activity and commissioning of new built rigs. Cost per operating day increased

by 7% mainly due to hourly crew labour rate increases in October 2005 and 2006 of 7% and 4%, respectively and

cost escalations for third party labour and materials associated with equipment maintenance programs.

The division commissioned 13 new rigs under customer term arrangements. Precision spent $203 million in capital

expenditures in 2006, nearly twice the spending of 2005.

Precision Drilling Oilfield Services, Inc. began operations in the United States in June 2006, with one rig.

LRG Catering achieved record growth in 2006 with activity increasing by 11% and revenue by 25% due in part to

rate increases implemented in the fourth quarter of 2005. LRG expanded its fleet by 10 to 101 camps in 2006.

COMPLETION AND PRODUCTION SERVICES SEGMENT
(Stated in thousands of Canadian dollars, except where indicated)

Years ended December 31,

Revenue
Expenses:

Operating
General and administrative
Depreciation
Foreign exchange

2007

% of
Revenue

2006

% of
Revenue

2005

% of
Revenue

$ 327,471

$ 441,017

$ 369,667

183,661
11,780
31,421
13

56.1
3.6
9.6
–

30.7

231,602
14,242
32,013
41

$ 163,119

52.5
3.2
7.3
–

37.0

209,657
11,021
27,402
(56)

$ 121,643

56.7
3.0
7.4
–

32.9

Operating earnings (1)

$ 100,596

% Increase
2007 (Decrease)

% Increase
(Decrease)

2006

% Increase
(Decrease)

2005

Number of service rigs (end of year)
Service rig operating hours
Revenue per operating hour

223
355,997
730

(5.9)
(25.9)
2.5

237
480,137
712

–
0.6
18.7

237
477,232
600

(0.8)
1.1
17.0

(1) Non-GAAP measure. See page 38.

P R E C I S I O N D R I L L I N G T R U S T

2007 Compared to 2006

The Completion and Production Services segment revenue decreased by $114 million to $327 million mainly due

to a decline in activity.

Operating earnings decreased by $63 million or 38% and were 31% of revenue in 2007 compared to 37% in 2006

due mainly to lower service activity during the year. Operating expenses increased from 53% of revenue in 2006 to

56% in 2007. On a daily or hourly operating basis, costs increased due to crew wage rate increases in October

2006 and an overall increase in the cost of materials. Lower equipment utilization resulted in increased daily or hourly

operating costs associated with fixed operating cost components.

Reinvestment in equipment in recent years has helped to position the Completion and Production Services segment
as an industry leader. Capital spending in 2007 of $27 million, down 32% from $39 million in 2006, included $15 million
for the construction of slant service rigs, self-contained snubbing units, storage tanks and wastewater treatment units,

and $12 million for replacement transporter trucks, doghouses, snubbing unit trucks, drill pipe for rental, tanks and

a new operating facility.

The Precision Well Servicing division revenue decreased by $82 million or 24% over 2006 to $260 million as

moderately higher hourly operating rates could not offset reduced activity levels. Price increases established in the

fourth quarter of 2006 were maintained through most of 2007, with downward adjustments in the second half.

A total of 18,540 wells were rig released in 2007, a decrease of 18% from the 22,575 wells the prior year. However,

with a lag between the drilling and completion of a well, the industry reported 19,272 well completions in 2007, a

decline of 13% from 22,171 completions in 2006. Over the last five years, there were over 100,000 wells completed

in western Canada which added to the ongoing maintenance demand to ensure continuous and efficient operation

of producing wells. There are currently about 200,000 producing wells within the WCSB.

Service rig contractors in western Canada increased the industry fleet capacity by about 5% to about 1,100 rigs at

the end of 2007. Increased capacity coupled with fewer well completions due to depressed natural gas prices kept

market pricing competitive.

Operating earnings decreased by 33% over 2006 due mainly to the 26% decrease in activity and 6% crew wage rate

increase in October 2006 offset by a 3% increase in the average operating hourly rate. Depreciation expense for the

year decreased $1 million due to lower activity offset by a $4 million write down charge for 16 decommissioned rigs.

Capital expenditures in 2007 were $12 million and included $3 million to construct two new service rigs and $9 million

to upgrade pump trucks, transporters and mobile doghouses and build a new operating facility due for completion

in late 2008.

Live Well Service revenue for 2007 was $19 million as activity decreased by 36% over 2006 due to weak natural

gas prices and an industry shift from rig-assist snubbing units to lower cost self-contained snubbing units. In 2007,

Live Well converted three rig-assist to three self-contained picker style units and one self-contained rack and pinion unit.

Precision Rentals revenue decreased to $44 million, which was $18 million or 29% lower than 2006. Each of Precision

Rental’s three major product lines, surface equipment, tubulars and well control equipment, and wellsite accommodations,

experienced year-over-year declines in revenue due to low utilization from excess industry equipment and lower pricing.

Terra Water Systems generated revenue of $5 million in 2007 compared to $2 million in the period following the

date of acquisition in 2006. Terra Water had 63 wastewater treatment units at the end of 2007, an increase of 12

units over 2006.

24 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

2006 Compared to 2005

The Completion and Production Services segment generated revenue of $441 million, an increase of $71 million

or 19% over 2005 while operating earnings increased by $41 million or 34% to $163 million. Operating earnings increased

to 37% of revenue in 2006 compared to 33% in 2005. The margin increase was mainly attributable to price increases

established during the year.

Operating expenses declined from 57% of revenue in 2005 to 53% in 2006, but on a per operating hour basis,

increased due to higher crew labour costs and higher costs associated with repair and maintenance.

During 2006, Precision acquired Terra Water Group Ltd., a wastewater treatment business. Terra Water had 41 treatment
units at the time of the acquisition and closed the year with 51. The service provided by Terra Water complements
those provided by LRG Catering and Precision Rentals and strengthened the diversity of Precision’s services.

Excluding the business acquisition, capital spending in 2006 was $39 million, an increase of 11% over 2005. The

total included expansion capital of $13 million for pump trucks, slant service rigs, self-contained snubbing units, wellsite

accommodations, storage tanks and wastewater treatment units and upgrade capital of $26 million for replacement

pump and transporter trucks, snubbing unit trucks, drill pipe for rental and tanks.

The Precision Well Servicing division increased revenue by $56 million or 20% over 2005 to $342 million primarily

due to higher hourly rig rates. Operating earnings improved by $36 million or 41% over 2005. Costs per operating

hour were higher year-over-year due to increased crew and rig manager labour expenses and equipment repair

and maintenance costs. Capital expenditures in 2006 were a continuation of long-term plans to upgrade and

standardize equipment.

Live Well Service’s activity decreased by 14% over 2005 with revenues for the year of $35 million due to the weakening

of natural gas prices in 2006 which led to a cost savings shift by customers away from rig-assist units toward self-

contained snubbing services.

Precision Rentals generated revenues of $62 million, which was $11 million or 21% higher than in 2005. Each of

Precision Rental’s product categories experienced year-over-year revenue increases. Total capital expenditures for

2006 increased 26% from 2005 and included 79 tanks and 10 new wellsite trailers.

Terra Water Systems generated revenues of $2 million for the period subsequent to acquisition in August 2006.

OTHER ITEMS

2007 Compared to 2006

Corporate and Other Expenses

Corporate and other expenses decreased by $12 million or 30% from 2006 to $29 million. This reduction was primarily

due to a $4 million recovery of long-term incentive plan accruals in 2007 compared to a $10 million expense in 2006.

A portion of the award payable under the long-term incentive plan is dependent on the growth in certain defined

financial targets over a three year period. The amounts distributed in 2007 were below the target, resulting in a partial

recovery of amounts previously accrued. Additional reductions achieved from lower accruals for recurring near-term

incentive plans were offset by one time costs associated with hiring a new Chief Executive Officer and costs associated

with workforce restructuring in November 2007. Gains associated with 2006 disposals and increased foreign exchange

losses from a weakening U.S. dollar offset by lower support costs in 2007 made up the remaining decrease.

Interest Expense

Net interest expense of $7 million declined by $1 million or 9% in 2007 compared to 2006. This reduction was primarily
attributable to the lower average debt outstanding during 2007 compared to the prior year.

P R E C I S I O N D R I L L I N G T R U S T

Income Taxes

The Trust’s effective income tax rate, before enacted tax rate reductions, on earnings from continuing operations
before income taxes was 8% in 2007 compared to 6% in 2006. The comparatively low effective income tax rate

was primarily a result of the shifting of the income tax burden of the Trust to its unitholders. The year-over-year increase

in the effective income tax rate was largely a result of taxes associated with Precision’s United States operations.

The Trust incurs taxes to the extent there are certain provincial capital taxes, as well as taxes on the taxable income,

of its underlying subsidiaries. In addition, future income taxes arise from differences between the accounting and tax

basis of the Trust and its operating entities’ assets and liabilities.

During 2007 the Government of Canada passed legislation to reduce the federal income tax rates to 15% by 2012.

These enacted tax rate reductions resulted in a $22 million future tax recovery in 2007, comparable to the $21 million

recorded in 2006.

Discontinued Operations

A $3 million gain, net of tax, on discontinued operations was recorded in 2007. The gain arose on the receipt of additional

consideration associated with a 2005 business divestiture. Additional consideration on 2004 and 2005 business

divestitures resulted in a $7 million gain in 2006.

2006 Compared to 2005

Corporate and Other Expenses

Corporate and other expenses decreased by $19 million or 32% in 2006 as compared to 2005. Included in the 2005

expenses were $18 million in costs related to the conversion to an income trust. Excluding these conversion costs,

corporate and other expenses decreased $1 million or 4% year-over-year. Incentive plans introduced in 2006 added

$7 million in costs over the prior period stock option plan expense. Disposals of corporate property, plant and equipment

in 2005 and 2006 contributed to a $2 million reduction in depreciation expense. Significant reductions in Precision’s

net foreign currency position related to 2005 divestitures and the repayment of U.S. dollar debentures led to a $3 million

reduction in foreign exchange gains in 2006. The remaining $9 million reduction in costs was mostly attributable to

the absence of severance and retention bonuses incurred in 2005, lower legal, advisory and support costs in 2006

and the recovery of certain liability provisions expensed in prior periods.

Interest Expense

Net interest expense of $8 million declined by $21 million or 73% in 2006 compared to 2005. This reduction was

primarily attributable to the repayment of the outstanding bonds (debentures) in October 2005 which resulted in lower

subsequent debt levels. Precision was in a significant surplus cash position, to the date of trust conversion, which

generated $10 million in interest income.

Premium on Redemption of Bonds and Loss on Disposal of Short-term Investments
In 2005 outstanding bonds were repaid resulting in a charge of $72 million.

In 2005 Precision received 26 million shares of Weatherford International Ltd. as part of the consideration for the

disposal of the Energy Services and International Contract Drilling divisions. Substantially all of the shares were

transferred to shareholders in conjunction with the November 7, 2005 plan of arrangement and a $71 million loss

was incurred.

Discontinued Operations

A $7 million gain, net of tax, on discontinued operations was recorded in 2006 and related to the receipt of contingent

consideration and working capital adjustments related to prior year business disposals. The 2005 business divestitures

contributed $74 million in net earnings and $1.3 billion in gains on disposition towards the financial results in fiscal 2005.

26 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

Income Taxes

The Trust’s effective income tax rate, before enacted tax rate reductions, on earnings from continuing operations
before income taxes was 6% in 2006 compared to 25% in 2005. The comparatively low effective income tax rate

was primarily a result of the conversion to an income trust which had the effect of shifting the income tax burden of

the Trust to its unitholders.

In the second quarter of 2006 the enactment of federal and certain provincial governments tax rate reductions resulted

in a $21 million future tax recovery.

LIQUIDITY AND CAPITAL RESOURCES

The Trust’s liquidity and solvency position remained strong as working capital exceeded long-term debt by $21 million

as at December 31, 2007 compared to $26 million as at December 31, 2006. The Trust’s financial position has been

sustained despite a decrease in activity as a significant percentage of operating costs are variable in nature and the

Trust curtailed spending and distributions in-line with financial performance.

In 2007 the Trust generated cash from continuing operations of $484 million and received proceeds related to the

disposal of operations discontinued in previous periods of $3 million. The cash was used to repay long-term debt

of $21 million and bank indebtedness of $23 million, purchase property, plant and equipment net of disposal proceeds

and related non-cash working capital of $194 million and make cash distributions to unitholders of $249 million.

The Trust exited 2007 with a long-term debt to long-term debt plus equity ratio of 0.08 compared to 0.10 in 2006

and a ratio of long-term debt to cash provided by continuing operations of 0.25 compared to 0.23 in 2006.

Precision has a number of credit facilities available to finance its activities. The committed facilities consist of a

$700 million three-year revolving unsecured credit facility with a syndicate led by a Canadian chartered bank. The

facility matures in November 2009 and is extendible annually with the consent of lenders. The facility has three financial

covenants which are tested quarterly: total liabilities to equity of less than 1:1; total debt to the trailing four quarters’

cash flow of less than 2.75:1; and total distributions to unitholders of less than 100% of consolidated cash flow, as

defined in the credit facility agreement. As at December 31, 2007 Precision was well within the financial covenant

levels, and is expected to remain so for 2008. There was $120 million outstanding under the committed facilities at

December 31, 2007. In addition to the committed facilities, Precision also has a number of uncommitted operating

facilities which total approximately $65 million equivalent and are utilized for working capital management and the

issuance of letters of credit.

Precision’s contractual obligations are outlined in the following table:

Payments Due by Period

(Stated in thousands of Canadian dollars)

Total

Less Than 1 Year

1 – 3 Years

4 – 5 Years

After 5 Years

Long-term debt
Operating leases
Long-term incentive plans (1)

Total contractual obligations

$ 119,826
22,640
21,147

$ 163,613

–
7,754
917

8,671

$ 119,826
11,407
20,230

$ 151,463

–
3,479
–

3,479

–
–
–

–

(1) Includes amounts not yet accrued at December 31, 2007 but payable at the end of the contract term. Unit based compensation amounts disclosed at year-end unit price.

Precision has multiple long-term incentive plans (“LTIP”) which compensate officers and key employees through cash

payments at the end of a three-year term. The compensation is comprised of two components, a retention award

and a performance award. The retention awards are lump sum amounts determined at the date of commencement

in the LTIP. The retention components are accrued evenly over their respective three-year terms. The performance

components are accrued based on actual results compared to the targets. There is no assurance that the performance

component will be paid. In addition, the Chief Executive Officer has a separate unit-based plan with anticipated

payments of $0.9 million annually, based on the year end unit price of Precision, commencing September 2008 and

ending September 2010.

P R E C I S I O N D R I L L I N G T R U S T

Outstanding Unit Data

Trust units
Exchangeable LP units

Total units outstanding

February 29,
2008

December 31,
2007

December 31,
2006

December 31,
2005

125,588,717
169,207

125,587,919
170,005

125,536,329
221,595

124,352,921
1,108,382

125,757,924

125,461,303

Deferred Trust units outstanding

18,523

18,280

–

DISTRIBUTIONS

Upon Precision’s conversion to an income trust effective November 7, 2005 the Trust adopted a policy of making

monthly distributions to holders of Trust units and holders of exchangeable LP units (together “unitholders”). Precision

has a legal entity structure whereby the trust entity, Precision Drilling Trust, effectively must flow its taxable income

to unitholders pursuant to its Declaration of Trust. Distributions, including special distributions, may be declared in

cash or “in-kind” or a combination of both and reduced, increased or suspended entirely depending on the operations

of Precision, the performance of its assets, or legislative changes in tax laws. The actual cash flow available for

distribution to unitholders is a function of numerous factors, including the Trust’s: financial performance; debt covenants

and obligations; working capital requirements; upgrade and expansion capital expenditure requirements for the

purchase of property, plant and equipment; and number of units outstanding. The Trust considers these factors on

a monthly basis in determining future distributions. In 2007 cash distributions declared, including a special year-end

cash distribution, were $246 million or $1.96 per diluted unit, a decrease of $201 million or $1.60 per diluted unit

from the previous year. A special year-end “in-kind” distribution, as explained below, payable in Trust units (“units”),

of $30 million or $0.24 per diluted unit (2006 – $25 million or $0.195 per diluted unit) was also declared.

In the event that a distribution is declared in the form of “in-kind” units, the terms of the Declaration of Trust requires

that the outstanding units be consolidated immediately subsequent to the distribution. Accordingly, the number of

outstanding units would remain at the number outstanding immediately prior to the distribution. As a result, unitholders

would not receive additional units and the declared amount of the “in-kind” distribution would be retained in Precision.

Holders of exchangeable LP units receive economic equivalent treatment.

Key factors for consideration in determining actual cash flow available for distribution, in an historical context, are

disclosed within the consolidated statements of cash flow. In calculating distributable cash Precision makes the following

adjustments to cash provided by continuing operations:

K Deducts the purchase of property, plant and equipment for upgrade capital as the minimum capital reinvestment

required to maintain current operating capacity;

K Deducts the purchase of property, plant and equipment for expansion initiatives to grow capacity;

K Adds the proceeds on the sale of property, plant and equipment which are incidental transactions occurring within

the normal course of operations; and

K Deducts long-term incentive plan changes as an unfunded liability resulting from the operating activities in the

current period with payments beginning March 2009.

28 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

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

Years ended December 31,
(Stated in thousands of Canadian dollars, except per diluted unit amounts)

Cash provided by continuing operations
Deduct:

Purchase of property, plant and equipment for upgrade capital
Purchase of property plant and equipment for expansion initiatives

Add:

Proceeds on the sale of property, plant and equipment

Standardized distributable cash (1)
Unfunded long-term incentive plan compensation

Distributable cash from continuing operations (1)

Cash distributions declared

Per diluted unit information:

Cash distributions declared
Standardized distributable cash (1)
Distributable cash from continuing operations (1)

(1) Non-GAAP measure. See page 38.

2007

2006

484,115

609,744

(45,970)
(141,003)

5,767

302,909
8,496

311,405

246,485

1.96
2.41
2.48

$
$
$

(92,123)
(170,907)

29,337

376,051
(22,699)

353,352

447,001

3.56
3.00
2.81

$
$
$

Upgrade capital expenditures allow the Trust to maintain its existing service levels. These expenditures consist of

betterments and replacements to existing assets and capitalized costs relating to the underlying support infrastructure.

The upgrade capital expenditure strategy of Precision also involves costs that are charged directly to the income

statement. These costs are related to the scheduled maintenance and certification processes within the various

operating divisions. The level of these expenditures is driven by activity levels and can be scaled back in times of

low activity without jeopardizing the long-term productive capacity of Precision and its underlying assets.

Years ended December 31,
(Stated in thousands of Canadian dollars)

Cash provided by continuing operations (A)
Net earnings (B)
Distributions declared (C)

Excess of cash provided by operations over distributions declared (A-C)

Excess of net earnings over distributions declared (B-C)

2007

2006

$
$
$

484,115
345,776
276,667

207,448

69,109

$
$
$

609,744
579,589
471,524

138,220

108,065

The Trust maintains a strong balance sheet and has sufficient debt facilities to manage short-term funding needs as

well as planned equipment additions. Part of the debt management strategy involves retaining sufficient funds from

available distributable cash to finance upgrade capital expenditures as well as working capital needs. Planned asset

growth will generally be financed through existing debt facilities or cash retained from continuing operations.

(Stated in thousands of Canadian dollars except per unit amounts)

2007

2006

2005

Units outstanding
Year-end unit price

Units at market
Long-term debt
Less: Working capital

Enterprise value

125,757,924
15.09
$

$ 1,897,687
119,826
(140,374)

125,757,924
27.00
$

$ 3,395,464
140,880
(166,484)

125,461,303
38.38
$

$ 4,815,205
96,838
(152,754)

$ 1,877,139

$ 3,369,860

$ 4,759,289

Precision carried a long-term debt to enterprise value ratio of 0.06 at December 31, 2007. This represents a slight

increase over the 2006 ratio of 0.04.

P R E C I S I O N D R I L L I N G T R U S T

QUARTERLY FINANCIAL SUMMARY
(Stated in thousands of Canadian dollars, except per diluted unit amounts)

Year ended December 31, 2007

Year

Revenue
Operating earnings (1)
Earnings from continuing operations

Per diluted unit

Net earnings

Per diluted unit

Cash provided by continuing operations
Distributions to unitholders – declared

$ 410,542
178,179
158,067
1.26
158,067
1.26
156,298
71,682

$ 122,005
27,074
25,722
0.20
25,722
0.20
229,073
56,591

$ 227,928
73,402
69,702
0.55
72,658
0.58
20,270
49,046

$ 248,726
77,696
89,329
0.71
89,329
0.71
78,474
99,348

$ 1,009,201
356,351
342,820
2.73
345,776
2.75
484,115
$ 276,667

Year ended December 31, 2006

Year

Revenue
Operating earnings (1)
Earnings from continuing operations

Per diluted unit

Net earnings

Per diluted unit

Cash provided by continuing operations
Distributions to unitholders – declared

(1) Non-GAAP measure. See page 38.

$ 536,408
245,909
224,183
1.79
224,183
1.79
40,940
$ 101,623

$ 223,569
74,543
88,303
0.70
88,303
0.70
339,619
$ 111,681

$ 349,558
142,431
133,552
1.06
139,667
1.11
74,952
$ 116,785

$ 328,049
132,396
126,474
1.01
127,436
1.01
154,233
$ 141,435

$ 1,437,584
595,279
572,512
4.56
579,589
4.62
609,744
$ 471,524

The Canadian drilling industry is subject to seasonality with activity peaking during the winter months in the fourth and

first quarters. As temperatures rise in the spring, the ground thaws and becomes unstable. Government road bans

severely restrict activity in the second quarter before equipment is moved for summer drilling programs in the third

quarter. These seasonal trends typically lead to quarterly fluctuations in operating results and working capital requirements.

FOURTH QUARTER DISCUSSION

Throughout 2007 Precision has experienced lower equipment utilization resulting in lower quarterly revenues from

the prior year comparative quarter. The decline in natural gas well spending by producers has curtailed oilfield service

activity at a time when record rig capacity exists in the WCSB. The result for the service sector in Canada was low

equipment utilization and increasingly competitive pricing throughout the year. Overall the business environment for

oilfield services in western Canada for 2007 was challenging as market conditions and fundamentals were depressed.

Precision’s expanding market presence in the United States land drilling market helped to mitigate the lower activity

and earnings in Canada.

Revenue of $249 million and operating earnings of $78 million in the fourth quarter of 2007 represented decreases

of 24% and 41% respectively compared to the same period in 2006. Operating earnings have declined by more

than revenue due to a reduction in industry utilization rates and a more competitive customer pricing environment.

Net earnings in the fourth quarter of 2007 were $89 million compared with $127 million in 2006, a decrease of $0.30
per diluted unit. Fourth quarter 2007 net earnings benefited from a future income tax recovery of $20 million associated
with enacted Canadian federal income tax rate reductions and was lowered by an asset write down charge of $7 million
for decommissioned rigs and $5 million expense for salaried personnel reductions. Adjusted for the $12 million increase
in net earnings from these items, the current quarter represented a decrease of $0.40 per diluted unit or 39% over
the prior year.

30 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

Contract Drilling Services segment revenue of $175 million and operating earnings of $69 million decreased by 22%

and 33% respectively in the fourth quarter of 2007 compared to the same period in 2006. Average customer pricing

was 12% lower in 2007 compared to the fourth quarter of 2006. Drilling rig operating days, spud to rig release, for

Precision in Canada in the fourth quarter of 2007 were 7,612, a decrease of 20% compared with 9,568 in the same

quarter in 2006. Utilization declined to 34% in the fourth quarter of 2007 compared with 43% a year ago. Lower

activity and lower average day rates were partially offset by lower daily costs as Precision continued to tightly monitor

spending. United States land drilling operations contributed 12% of the segment’s current quarter revenue while LRG

Catering followed Canadian industry trends and experienced a decline in revenue of 35% over the prior year.

Completion and Production Services segment revenue of $78 million and operating earnings of $17 million decreased

by 28% and 57% respectively in the fourth quarter of 2007 compared to the same period in 2006. Precision’s service

rig operating hours during the fourth quarter of 2007 were 86,416 compared to 109,737 in 2006, a decrease of

21%. The reduction was a result of lower demand as customers scaled back well completion work in-line with drilling

activity and moderated spending on production maintenance of existing wells, particularly natural gas wells. New

well completions accounted for 33% of service rig operating hours in the fourth quarter compared to 39% in 2006.
Lower customer demand and the resulting competitive bidding environment led to a price reduction of 10% compared
to the prior year. Demand for rental equipment followed industry trends as revenue in the quarter was 25% lower
than the fourth quarter of 2006 while revenue for the snubbing division was down 27% and the wastewater treatment

division was lower by 1%.

Total operating costs increased from 47% of revenue in the fourth quarter of 2006 to 51% in 2007 due to lower

customer pricing and fixed overhead costs. Operating costs remained highly variable to activity levels and, in the

quarter, service rig costs per hour were unchanged while drilling rig costs per day were lower by 7%.

General and administrative expense for the fourth quarter was $19 million, a decrease of $4 million from the same

period in 2006. The decrease was due primarily to lower employee incentive compensation costs offset by charges

associated with workforce reductions in early November 2007.

Depreciation and amortization expense in the fourth quarter of 2007 was $25 million, which included a charge of

$7 million for decommissioned assets, compared with $18 million in the same period of 2006. Although Canadian

rig utilization in the quarter was lower by about 20% compared to 2006 the utilization impact was offset by a higher

cost base for active rigs.

The Trust’s effective income tax rate on earnings before income taxes for fiscal 2007 was 8%, before enacted tax

rate reductions, compared to 6% for 2006. Compared to a corporate income tax rate, the low effective income tax

rate is primarily the result of the income trust structure shifting all or a portion of the income tax burden of the Trust

to its unitholders.

During the fourth quarter of 2007 the Government of Canada enacted legislation reducing federal income tax rates

to 15% by 2012. The enacted tax rate reductions resulted in a $20 million future income tax recovery in the fourth

quarter of 2007.

In the fourth quarter of 2007 capital expenditures were $38 million, a decrease of $35 million over the same period

in 2006. Capital spending for the quarter included $9 million in upgrade and $29 million in expansion initiatives.

Fourth quarter monthly cash distributions declared were $0.13 per diluted unit for aggregate quarterly cash distributions

declared of $49 million or $0.39 per unit. In addition the Trust declared a special year-end distribution of $50 million

or $0.40 per unit settled $0.24 per unit “in-kind” and $0.16 per unit in cash. The special “in-kind” distribution was

made to minimize debt levels and retain balance sheet strength to fund planned asset growth.

P R E C I S I O N D R I L L I N G T R U S T

MD&A

CRITICAL ACCOUNTING ESTIMATES, NEW ACCOUNTING STANDARDS
AND BUSINESS RISKS

CRITICAL ACCOUNTING ESTIMATES

This Management’s Discussion and Analysis of Precision’s financial condition and results of operations is based on

Precision’s consolidated financial statements which are prepared in accordance with Canadian GAAP. These principles

differ in certain respects from U.S. GAAP and these differences are described and quantified in Note 16 to the

consolidated financial statements.

The Trust’s significant accounting policies are described in Note 2 to the consolidated financial statements. The

preparation of the financial statements requires that certain estimates and judgments be made that affect the reported

assets, liabilities, revenues and expenses. These estimates and judgments are based on historical experience and

on various other assumptions that are believed to be reasonable under the circumstances. Anticipating future events

cannot be done with certainty, therefore, these estimates may change as new events occur, more experience is acquired

and as the Trust’s operating environment changes.

Following are the accounting estimates believed to require the most difficult, subjective or complex judgments and

which are the most critical to Precision’s reporting of results of operations and financial positions.

Allowance for Doubtful Accounts Receivable

Precision performs ongoing credit evaluations of its customers and grants credit based upon past payment history,

financial condition and anticipated industry conditions. Customer payments are regularly monitored and a provision
for doubtful accounts is established based upon specific situations and overall industry conditions. Precision’s history
of bad debt losses has been within expectations and generally limited to specific customer circumstances. However,
given the cyclical nature of the oil and natural gas industry in Canada and the inherent risk of successfully finding
hydrocarbon reserves, a customer’s ability to fulfill its payment obligations can change suddenly and without notice.

In cases where creditworthiness is uncertain, services are provided on receipt of cash in advance, on receipt of a

letter of credit, on deposit of monies in trust or services are declined.

Impairment of Long-lived Assets

Long-lived assets, which include property, plant and equipment, intangibles and goodwill, comprise the majority of

Precision’s assets. The carrying value of these assets is periodically reviewed for impairment or whenever events or

changes in circumstances indicate that their carrying amounts may not be recoverable. This requires Precision to

forecast future cash flows to be derived from the utilization of these assets based upon assumptions about future

business conditions and technological developments. Significant, unanticipated changes to these assumptions could

require a provision for impairment in the future. During the fourth quarter of 2007, Precision completed its assessment

and concluded that there was no impairment of the carrying value.

32 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

Depreciation and Amortization

Precision’s property, plant and equipment and its intangible assets are depreciated and amortized based upon estimates

of useful lives and salvage values. These estimates may change as more experience is gained, market conditions

shift or new technological advancements are made.

Income Taxes

The Trust and its subsidiaries follow the liability method which takes into account the differences between financial

statement treatment and tax treatment of certain transactions, assets and liabilities. Future tax assets and liabilities

are recognized for the future tax consequences attributable to differences between the financial statement carrying

amounts of existing assets and liabilities and their respective tax bases. Valuation allowances are established to reduce

future tax assets when it is more likely than not that some portion or all of the asset will not be realized. Estimates

of future taxable income and the continuation of ongoing prudent tax planning arrangements have been considered

in assessing the utilization of available tax losses. Changes in circumstances and assumptions and clarifications of

uncertain tax regimes may require changes to the valuation allowances associated with Precision’s future tax assets.

The business and operations of Precision are complex and Precision has executed a number of significant financings,

business combinations, acquisitions and dispositions over the course of its history. The computation of income taxes

payable as a result of these transactions involves many complex factors as well as Precision’s interpretation of relevant

tax legislation and regulations. Precision’s management believes that the provision for income tax is adequate.

Long-term Incentive Plan Compensation

The Trust instituted an annual long-term incentive plan which compensates officers and key employees through cash

payments at the end of a three-year term. The compensation includes two components, a retention award and a

performance award. The performance component is based on growth over the three-year term measured against

targets as determined by the Compensation Committee of Precision. As a result of actual results in the subsequent

years, the accrued amount for the performance component may be reduced or increased.

NEW ACCOUNTING STANDARDS

The Canadian Institute of Chartered Accountants issued certain new accounting standards which will be in effect

for fiscal years beginning on or after January 1, 2008 for recognition and measurement of inventories and disclosure

of information regarding capital management.

K Section 3031, “Inventories”, provides guidance on measurement and disclosure of inventories. This section also

provides guidance on the determination of cost and recognition in the financial statements.

K Section 1535, “Capital Disclosures”, establishes standards for disclosing quantitative and qualitative information

regarding objectives, policies and processes for managing capital.

The Trust does not expect that the adoption of these standards will have a material impact on the consolidated

financial statements.

P R E C I S I O N D R I L L I N G T R U S T

In January 2006 the Canadian Accounting Standards Board (“AcSB”) announced its decision to replace Canadian

GAAP with International Financial Reporting Standards (“IFRS”) for all Canadian Publicly Accountable Enterprises

(“PAE”). PAE include listed companies and any other organizations that are responsible to large or diverse groups

of stakeholders, including non-listed financial institutions, securities dealers and many cooperative enterprises. The

goal of IFRS is to improve financial reporting internationally by establishing a single set of high quality, consistent,

and comparable reporting standards.

To allow affected companies sufficient time to prepare for the transition, the AcSB announced a five-year transition

period, with a changeover date of January 1, 2011, effective for fiscal years beginning on or after that date.

Although many elements of Canadian GAAP and IFRS are similar, Precision expects its transition to IFRS to take
considerable effort. Precision has commenced its assessment of and planning for the impacts of IFRS on its financial
reporting processes.

BUSINESS RISKS

The discussion of risk that follows is not a complete representation. Additional information related to risks are disclosed

in the 2007 Annual Information Form with SEDAR and available at www.sedar.com. Refer to the “Cautionary Statement

Regarding Forward-Looking Information and Statements” on page 39.

Certain activities of Precision are affected by factors that are beyond its control or influence. The drilling rig, camp

and catering, service rig, snubbing, wastewater treatment, rentals, and related service businesses and activities of

Precision in Canada and the drilling rig, camp and catering and rentals businesses and activities of Precision in the

United States are directly affected by fluctuations in the levels of exploration, development and production activity

carried on by its customers which, in turn, is dictated by numerous factors, including world energy prices and

government policies. The addition, elimination or curtailment of government regulations and incentives could have

a significant impact on the oil and gas business in Canada and the United States. These factors could lead to a

decline in the demand for Precision’s services, resulting in a material adverse effect on revenues, cash flows, earnings

and cash distributions to unitholders. The majority of Precision’s operating costs are variable in nature which minimizes

the impact of downturns on its operational results.

Crude Oil and Natural Gas Prices

Precision’s revenue, cash flow and earnings are substantially dependent upon, and affected by, the level of activity

associated with oil and natural gas exploration and production. Both short-term and long-term trends in oil and natural

gas prices affect the level of such activity. Oil and natural gas prices and, therefore, the level of drilling, exploration

and production activity have been volatile over the past few years and likely will continue to be volatile. Military, political,
weather, economic and other events in certain parts of the world, including initiatives by the Organization of Petroleum
Exporting Countries or other major petroleum exporting countries, may affect both the demand for, and the supply
of, oil and natural gas. North American petroleum service activity is largely focused on natural gas. Weather conditions,
governmental regulation (both in Canada and elsewhere), levels of consumer demand, the availability of pipeline
capacity, storage levels and other factors beyond Precision’s control may also affect the supply of and demand for
oil and natural gas and thus lead to future price volatility. Precision believes that any prolonged reduction in oil and
natural gas prices would depress the level of exploration and production activity. Lower oil and natural gas prices
could also cause Precision’s customers to seek to terminate, renegotiate or fail to honour drilling contracts with Precision
which could affect the fair market value of its rig fleet which in turn could trigger a write down for accounting purposes,
Precision’s ability to retain skilled rig personnel, and Precision’s ability to obtain access to capital to finance and grow
its businesses. There can be no assurance that the future level of demand for Precision’s services or future conditions
in the oil and natural gas industry will not decline.

34 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

Workforce Availability

Precision’s ability to provide reliable services is dependent upon the availability of well-trained, experienced crews to

operate its field equipment. Precision must also balance the requirement to maintain a skilled workforce with the

need to establish cost structures that fluctuate with activity levels.

Within Precision, the most experienced people are retained during periods of low utilization by having them fill lower

level positions on field crews. Precision has established training programs for employees new to the oilfield service

sector and works closely with industry associations to ensure competitive compensation levels and to attract new

workers to the industry as required. Many of Precision’s businesses regularly experience manpower shortages in

peak operating periods.

Business is Seasonal
In Canada, the level of activity in the oilfield service industry is influenced by seasonal weather patterns. During the

spring months, wet weather and the spring thaw make the ground unstable. Consequently, municipalities and provincial

transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby

reducing activity levels and placing an increased level of importance on the location of Precision’s equipment prior

to imposition of road bans. The timing and length of road bans is dependant upon the weather conditions leading

to the spring thaw and the weather conditions during the thawing period.

Additionally, certain oil and natural gas producing areas are located in sections of the WCSB that are inaccessible,

other than during the winter months, because the ground surrounding or containing the drilling sites in these areas

consists of terrain known as muskeg. Until the muskeg freezes, the rigs and other necessary equipment cannot cross

the terrain to reach the drilling site. Precision’s business results depend, at least in part, upon the severity and duration

of the Canadian winter.

Technology

Complex drilling programs for the exploration and development of remaining conventional and unconventional oil

and natural gas reserves in North America demand high performance drilling rigs. The ability of drilling rig service

providers to meet this demand will depend on continuous improvement of existing rig technology such as drive systems,

control systems, automation, mud systems and top drives to improve drilling efficiency. Precision’s ability to deliver

equipment and services that are more efficient is critical to continued success. There is no assurance that competitors

will not achieve technological improvements which are more advantageous, timely or cost effective than improvements

developed by Precision.

Customer Merger and Acquisition Activity

Merger and acquisition activity in the oil and natural gas exploration and production sector can impact demand for

Precision’s services as customers focus on internal reorganization activities prior to committing funds to significant

drilling and maintenance projects.

Competitive Industry

The oilfield services industry in which Precision operates is, and will continue to be, very competitive. There is no

assurance that Precision will be able to continue to compete successfully or that the level of competition and pressure

on pricing will not affect its margins.

Capital Overbuild in the Drilling Industry
As at December 31, 2007 there were about 900 industry drilling rigs in Canada and about 2,160 marketed drilling
rigs in the United States. There is no assurance that the level of demand for drilling rigs in the future will be able to
support the size of the current industry drilling rig fleet in Canada and the United States. Any decline in demand for
drilling services within the services industry, directly or indirectly related to the current drilling rigs available, could
also lead to a decline in the demand for Precision’s services, resulting in a material adverse effect on Precision’s
revenues, cash flows, earnings and cash distributions to unitholders.

P R E C I S I O N D R I L L I N G T R U S T

Tax Consequences of Previous Transactions Completed by Precision

The business and operations of Precision prior to completion of the Plan of Arrangement were complex and Precision

has executed a number of significant financings, business combinations, acquisitions and dispositions over the course

of its history. The computation of income taxes payable as a result of those transactions involves many complex

factors as well as Precision’s interpretation of relevant tax legislation and regulations. Precision’s management believes

that the provision for income tax is adequate and in accordance with GAAP and applicable legislation and regulations.

However, there are a number of tax filing positions that can still be the subject of review by taxation authorities who

may successfully challenge Precision’s interpretation of the applicable tax legislation and regulations, with the result

that additional taxes could be payable by Precision and the amount payable, before interest and penalties, could be

up to $300 million. Any increase in Precision’s tax liability would reduce the funds available for distributions.

Subsequent to year end Precision received, from a provincial taxing authority, Notices of Reassessment relating to

a prior period tax filing position for $55 million. The income tax related portion of the reassessments is $36 million

and is included in the $300 million tax contingency disclosed in Note 20 to the financial statements. Precision is of

the opinion that the provincial tax authority’s position is without merit and will be challenging these reassessments.

Credit Risk

Precision’s accounts receivable are with customers involved in the oil and natural gas industry, whose revenues may

be impacted by fluctuations in commodity prices. Although collection of these receivables could be influenced by

economic factors affecting this industry, management considers the risk of a significant loss due to uncollectible

receivables to be remote at this time.

Capital Expenditures

The timing and amount of capital expenditures by Precision will directly affect the amount of cash available for

distribution to unitholders. The cost of equipment has escalated over the past several years as a result of, among

other things, high input costs. There is no assurance that Precision will be able to recover higher capital costs through

rate increases to its customers, in which case cash distributions may be reduced.

Access to Additional Financing

Precision may find it necessary in the future to obtain additional debt or equity financing through the Trust to support

ongoing operations, to undertake capital expenditures or undertake acquisitions or other business combination

transactions. There can be no assurance that additional financing will be available to Precision when needed or on

terms acceptable to Precision. Precision’s inability to raise financing to support ongoing operations or to fund capital

expenditures or acquisitions or other business combination transactions could limit Precision’s growth and may have

a material adverse effect upon Precision.

Taxation of Distributions

In June 2007 the Government of Canada’s Bill C-52 Budget Implementation Act 2007 was enacted and included

legislative provisions that impose a tax on certain distributions from publicly traded specified investment flow-through

(“SIFT”) trusts at a rate equal to the applicable federal corporate tax rate plus a provincial SIFT tax factor. After the

enactment of federal tax rate reductions in December 2007 the combined SIFT tax would be 29.5% in 2011, reducing

to 28% in 2012. Precision will be a SIFT trust on the earlier of January 1, 2011 or the first day after it exceeds the

normal growth guidelines announced by the federal Department of Finance on December 15, 2006.

Environmental

There is growing concern about the apparent connection between the burning of fossil fuels and climate change.

The issue of energy and the environment has created intense public debate in Canada and around the world in recent

years that is likely to continue for the foreseeable future and could potentially have a significant impact on all aspects

of the economy including the demand for hydrocarbons and the resulting lower demand for Precision’s services.

36 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

U.S. Dollar Exchange Exposure

Precision’s operations in the United States have revenue, expenses, assets and liabilities denominated in U.S. dollars.

As a result Precision’s income statement, balance sheet and statement of cash flow are impacted by changes in

exchange rates between Canadian and U.S. currencies in three main aspects.

K Translation of U.S. Currency Assets and Liabilities to Canadian Dollars

For Precision’s integrated operations, non-monetary assets and liabilities are recorded in the financial statements

at the exchange rate in effect at the time of the acquisition or expenditure. As a result the book value of these

assets and liabilities are not impacted by changes in exchange rates. Monetary assets and liabilities are converted

at the exchange rate in effect at the balance sheet dates, and the unrealized gains and losses are shown on the

statements of earnings as “Foreign exchange”. Precision has a net monetary asset position for its U.S. operations,

which are U.S. dollar based. As a result, if the Canadian dollar strengthens versus the U.S. dollar, Precision will

incur a foreign exchange loss from translation of net monetary assets;

K Translation of U.S. Currency Statement of Earnings Items to Canadian Dollars

Precision’s United States operations generate revenue and incur expenses in U.S. dollars and the U.S. dollar based

earnings are converted into Canadian dollars for purposes of financial statement consolidation and reporting. The

conversion of the U.S. dollar based revenue and expenses to a Canadian dollar basis does not result in a foreign

exchange gain or loss but does result in lower or higher net earnings from United States operations than would

have occurred had the exchange rate not changed. If the Canadian dollar strengthens against the U.S. dollar, the

Canadian dollar equivalent of net earnings from United States operations will be negatively impacted. Precision

does not currently hedge any of its exposure related to the translation of United States based earnings into Canadian

dollars; and

K Transaction Exposure

The majority of Precision’s United States operations are transacted in U.S. dollars. Transactions for Precision’s

Canadian operations are primarily transacted in Canadian dollars. However, Precision occasionally purchases goods

and supplies in U.S. dollars. These transactions and foreign exchange exposure would not typically have a material

impact on the Canadian operation’s financial results.

Safety Risk

Standards for the prevention of incidents in the oil and gas industry are governed by service company safety policies

and procedures, accepted industry safety practices, customer specific safety requirements, and health and safety

legislation. The safety policies and procedures adopted by Precision meet or exceed those imposed by industry,

customers or legislation. Precision maintains a safety program which reinforces workplace safety through training,

observation and communication. Precision’s drilling and well servicing businesses are highly competitive with numerous

competitors. A key factor considered by Precision’s customers in selecting oilfield service providers is safety. Precision’s

safety record in North America, backed by the experience of its employees and the quality of its equipment, differentiates

Precision from its oilfield service competitors. Deterioration in Precision’s safety performance could result in a decline

in the demand for Precision’s services and could have a material adverse effect on its revenues, cash flows, profitability

and funds available for cash distributions.

Dependence on Third Party Suppliers

Precision sources certain key rig components, raw materials, equipment and component parts from a variety of suppliers

located in Canada, the United States and overseas. Precision also outsources some or all services for the construction

of drilling and service rigs. While alternate suppliers exist for most of these components, materials, equipment, parts

and services, cost increases, delays in delivery due to high activity or unforeseen circumstances may be experienced.

Precision maintains relationships with a number of key suppliers and contractors, maintains an inventory of key

components, materials, equipment and parts and orders long lead time components in advance. However, if the

current or alternate suppliers are unable to provide or deliver the necessary components, materials, equipment, parts

and services, any resulting delays by Precision in the provision of services to its customers may have a material adverse

effect on Precision’s business, results of operations, prospects and funds available for cash distributions.

P R E C I S I O N D R I L L I N G T R U S T

MD&A

DISCLOSURE CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures are designed to provide reasonable assurance that information required to be

disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized
and reported within the time periods specified under Canadian and United States securities laws. The information

is accumulated and communicated to management, including the principal executive officer and principal financial
and accounting officer, to allow timely decisions regarding required disclosure.

As of December 31, 2007, an evaluation was carried out, under the supervision of and with the participation of

management, including the principal executive officer and principal financial and accounting officer, of the effectiveness

of Precision’s disclosure controls and procedures as defined under the rules adopted by the Canadian securities

regulatory authorities and by the United States Securities and Exchange Commission. Based on that evaluation, the

principal executive officer and principal financial and accounting officer concluded that the design and operation of

Precision’s disclosure controls and procedures were effective as at December 31, 2007.

During the fourth quarter of 2007, there were no changes in internal control over financial reporting that materially

affected, or are reasonably likely to materially affect, Precision’s internal control over financial reporting.

NON-GAAP MEASURES

Precision uses certain measures that are not recognized under Canadian generally accepted accounting principles

to assess performance and believe these non-GAAP measures provide useful supplemental information to investors.

Following are the non-GAAP measures Precision uses in assessing performance.

Operating Earnings
Management believes that in addition to net earnings, operating earnings as reported in the Consolidated Statements
of Earnings and Retained Earnings (Deficit) is a useful supplemental measure as it provides an indication of the results
generated by Precision’s principal business activities prior to consideration of how those activities are financed or
how the results are taxed.

Standardized Distributable Cash, Distributable Cash from Continuing Operations, Standardized

Distributable Cash per Diluted Unit and Distributable Cash from Continuing Operations per Diluted Unit

Management believes that in addition to cash provided by continuing operations, standardized distributable cash

and distributable cash from continuing operations are useful supplemental measures. They provide an indication of

the funds available for distribution to unitholders after consideration of the impacts of capital expenditures and long-term

unfunded contractual obligations. In prior years, instead of deducting total capital expenditures in the calculation of

distributable cash, Precision only excluded upgrade capital but as a result of new guidance expansion capital is now

also deducted.

Precision’s method of calculating these measures may differ from other entities and, accordingly, may not be comparable
to measures used by other entities. Investors should be cautioned that these measures should not be construed as
an alternative to measures determined in accordance with GAAP as an indicator of Precision’s performance.

38 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

MD&A

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
AND STATEMENTS

This Annual Report contains certain forward-looking information and statements, including statements relating to

matters that are not historical facts and statements of our beliefs, intentions and expectations about developments,

results and events which will or may occur in the future, which constitute “forward-looking information” within the

meaning of applicable Canadian securities legislation and “forward-looking statements” within the meaning of the
“safe harbor” provisions of the United States Private Securities Litigation Reform Act of 1995 (collectively the “forward-
looking information and statements”). Forward-looking information and statements are typically identified by words

such as “anticipate”, “could”, “should”, “expect”, “seek”, “may”, “intend”, “likely”, “will”, “plan”, “estimate”, “believe”

and similar expressions suggesting future outcomes or statements regarding an outlook.

Forward-looking information and statements are included throughout this Annual Report including under the headings

“Overview and Outlook”, “Dynamics of the Oilfield Services Industry”, “Precision’s Development”, “Financial Results”,

“Critical Accounting Estimates, New Accounting Standards and Business Risks” and “Disclosure Controls and

Procedures” and include, but are not limited to statements with respect to: 2008 expected cash provided by continuing

operations; 2008 capital expenditures, including the amount and nature thereof; 2008 distributions on Trust Units

and payments on Exchangeable Units; performance of the oil and natural gas industry, including oil and natural gas

commodity prices and supply and demand; expansion, consolidation and other development trends of the oil and

natural gas industry; demand for and status of drilling rigs and other equipment in the oil and natural gas industry;

costs and financial trends for companies operating in the oil and natural gas industry; world population and energy

consumption trends; our business strategy, including the 2008 strategy and outlook for our business segments;

expansion and growth of our business and operations, including diversification of our earnings base, safety and

operating performance, the size and capabilities of our drilling and service rig fleet, our market share and our position

in the markets in which we operate; demand for our products and services; our management strategy, including

transitions in executive roles; labour shortages; climatic conditions; the maintenance of existing customer, supplier

and partner relationships; supply channels; accounting policies and tax liabilities; expected payments pursuant to

contractual obligations; the prospective impact of recent or anticipated regulatory changes; financing strategy and

compliance with debt covenants; credit risks; and other such matters.

P R E C I S I O N D R I L L I N G T R U S T

All such forward-looking information and statements are based on certain assumptions and analyses made by us
in light of our experience and perception of historical trends, current conditions and expected future developments,
as well as other factors we believe are appropriate in the circumstances. These statements are, however, subject to

known and unknown risks and uncertainties and other factors. As a result, actual results, performance or achievements

could differ materially from those expressed in, or implied by, these forward-looking information and statements and,

accordingly, no assurance can be given that any of the events anticipated by the forward-looking information and

statements will transpire or occur, or if any of them do so, what benefits will be derived therefrom. These risks,

uncertainties and other factors include, among others: the impact of general economic conditions in Canada and

the United States; world energy prices and government policies; industry conditions, including the adoption of new

environmental, taxation and other laws and regulations and changes in how they are interpreted and enforced; the

impact of initiatives by the Organization of Petroleum Exporting Countries and other major petroleum exporting

countries; the ability of oil and natural gas companies to access external sources of debt and equity capital; the

effect of weather conditions on operations and facilities; the existence of operating risks inherent in well servicing,

contract drilling and ancillary oilfield services; volatility of oil and natural gas prices; oil and natural gas product supply

and demand; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future

obligations; increased competition; consolidation among our customers; risks associated with technology; political

uncertainty, including risks of war, hostilities, civil insurrection, instability or acts of terrorism; the lack of availability of

qualified personnel or management; credit risks; increased costs of operations, including costs of equipment;

fluctuations in interest rates; stock market volatility; safety performance; foreign operations; foreign currency exposure;

dependence on third party suppliers; opportunities available to or pursued by us; and other factors, many of which

are beyond our control.

These risk factors are discussed in the Annual Information Form and Form 40-F on file with the Canadian securities

commissions and the United States Securities and Exchange Commission and available on SEDAR at www.sedar.com
and the website of the U.S. Securities and Exchange Commission at www.sec.gov, respectively. Except as required
by law, Precision Drilling Trust, Precision Drilling Limited Partnership and Precision Drilling Corporation disclaim any
intention or obligation to update or revise any forward-looking information or statements, whether as a result of new

information, future events or otherwise.

The forward-looking information and statements contained in this Annual Report are expressly qualified by this

cautionary statement.

40 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

Financial
Reporting

Precision Drilling Trust

FINANCIAL REPORTING

MANAGEMENT’S REPORT TO THE UNITHOLDERS

The accompanying consolidated financial statements and all information in the Annual Report are the responsibility of
management. The consolidated financial statements have been prepared by management in accordance with the accounting
policies in the notes to the consolidated financial statements. When necessary, management has made informed judgments
and estimates in accounting for transactions which were not complete at the balance sheet date. In the opinion of management,
the consolidated financial statements have been prepared within acceptable limits of materiality, and are in accordance with
Canadian generally accepted accounting principles (“GAAP”) appropriate in the circumstances. The financial information
elsewhere in the Annual Report has been reviewed to ensure consistency with that in the consolidated financial statements.

Management has prepared the Management’s Discussion and Analysis (“MD&A”). The MD&A is based upon Precision Drilling
Trust’s (the “Trust”) financial results prepared in accordance with Canadian GAAP. The MD&A compares the audited financial
results for the years ended December 31, 2007 to December 31, 2006 and the years ended December 31, 2006 to December 31,
2005. Note 16 to the consolidated financial statements describes the impact on the consolidated financial statements of
significant differences between Canadian and United States GAAP.

Management is responsible for establishing and maintaining adequate internal control over the Trust’s financial reporting.
Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of consolidated financial statements for external reporting purposes in accordance
with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable
assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness
to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.

P R E C I S I O N D R I L L I N G T R U S T

Under the supervision and with direction from our principal executive officer and principal financial and accounting officer,
management conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting.
Management’s evaluation of internal control over financial reporting was based on the Internal Control – Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation,
management concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2007.
Also management determined that there were no material weaknesses in the Trust’s internal control over financial reporting
as of December 31, 2007.

KPMG LLP, an independent firm of Chartered Accountants, was engaged, as approved by a vote of unitholders at the Trust’s
most recent annual meeting, to audit the consolidated financial statements and provide an independent professional opinion.

KPMG LLP completed an assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31,
2007 as stated in their report included herein and expressed an unqualified opinion on the effectiveness of internal control
over financial reporting as of December 31, 2007.

The Audit Committee of the Board of Directors, which is comprised of three independent directors who are not employees
of the Trust, provides oversight to the financial reporting process. Integral to this process is the Audit Committee’s review
and discussion with management and the external auditors of the quarterly and annual financial statements and reports
prior to their respective release. The Audit Committee is also responsible for reviewing and discussing with management
and the external auditors major issues as to the adequacy of the Trust’s internal controls. The consolidated financial statements
have been approved by the Board of Trustees on the recommendation of the Board of Directors of Precision Drilling
Corporation and its Audit Committee.

Kevin A. Neveu
Chief Executive Officer
Precision Drilling Corporation,
Administrator to Precision Drilling Trust

Doug J. Strong
Chief Financial Officer
Precision Drilling Corporation,
Administrator to Precision Drilling Trust

March 20, 2008

C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

Precision Drilling Trust

AUDITORS’ REPORT TO THE UNITHOLDERS

To the Unitholders of Precision Drilling Trust

We have audited the consolidated balance sheets of Precision Drilling Trust (“the Trust”) as at December 31, 2007 and
2006 and the consolidated statements of earnings and retained earnings (deficit) and cash flow for each of the years in the
three-year period ended December 31, 2007. These financial statements are the responsibility of the Trust’s management.
Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. With respect to the consolidated
financial statements for the years ended December 31, 2007 and 2006, we also conducted our audits in accordance with
the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan
and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the
Trust as at December 31, 2007 and 2006 and the results of its operations and its cash flow for each of the years in the
three-year period ended December 31, 2007 in accordance with Canadian generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the Trust’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
and our report dated March 20, 2008 expressed an unqualified opinion on the effectiveness of the Trust’s internal control
over financial reporting.

Chartered Accountants
Calgary, Canada

March 20, 2008

P R E C I S I O N D R I L L I N G T R U S T

Precision Drilling Trust

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Precision Drilling Corporation, as Administrator to Precision Drilling Trust and

the Unitholders of Precision Drilling Trust

We have audited Precision Drilling Trust (“the Trust”)’s internal control over financial reporting as of December 31, 2007,
based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Trust’s management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included
in the accompanying Management’s Report to the Unitholders. Our responsibility is to express an opinion the Trust’s internal
control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding
of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating
the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing
such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.

An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. An entity’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts
and expenditures of the entity are being made only in accordance with authorizations of management and directors of the
entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the entity’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31,
2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).

We also have conducted our audits on the consolidated financial statements in accordance with Canadian generally
accepted auditing standards. With respect to the years ended December 31, 2007 and 2006, we also have conducted our
audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our report dated
March 20, 2008 expressed an unqualified opinion on those consolidated financial statements.

Chartered Accountants
Calgary, Canada

March 20, 2008

C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

Precision Drilling Trust

CONSOLIDATED BALANCE SHEETS

As at December 31,

(Stated in thousands of Canadian dollars)

ASSETS
Current assets:

Accounts receivable
Income taxes recoverable
Inventory

Property, plant and equipment, net of accumulated depreciation
Intangibles, net of accumulated amortization of $593 (2006 – $503)
Goodwill

LIABILITIES AND UNITHOLDERS’ EQUITY
Current liabilities:

Bank indebtedness
Accounts payable and accrued liabilities
Distributions payable

Long-term incentive plan payable
Long-term debt
Future income taxes

2007

2006

(Note 19)

(Note 4)

256,616
5,952
9,255

271,823
1,210,587
318
280,749

354,671
8,701
9,073

372,445
1,107,617
375
280,749

$ 1,763,477

$ 1,761,186

(Note 5)

(Note 19)

(Note 6)

(Note 7)

(Note 8)

14,115
80,864
36,470

131,449
13,896
119,826
181,633

446,804

36,774
130,202
38,985

205,961
22,699
140,880
174,571

544,111

Commitments and contingencies

(Notes 12 and 20)

Unitholders’ equity:

Unitholders’ capital
Contributed surplus
Deficit

See accompanying notes to consolidated financial statements.

Approved by the Board of Trustees:

(Note 9(b))

(Note 9(c))

1,442,476
307
(126,110)

1,316,673

1,412,294
–
(195,219)

1,217,075

$ 1,763,477

$ 1,761,186

Robert J.S. Gibson
Trustee

Patrick M. Murray
Trustee

P R E C I S I O N D R I L L I N G T R U S T

Precision Drilling Trust

CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS (DEFICIT)

Years ended December 31,

(Stated in thousands of Canadian dollars, except per unit amounts)

2007

2006

2005

Revenue
Expenses:

Operating
General and administrative
Depreciation and amortization
Foreign exchange
Reorganization costs

Operating earnings
Interest:

Long-term debt
Other
Income

Premium on redemption of bonds
Loss on disposal of short-term investments
Other

Earnings from continuing operations before income taxes
Income taxes:
Current
Future

(Note 4)

(Note 23)

(Note 7)

(Note 24)

(Note 8)

Earnings from continuing operations
Gain on disposal of discontinued operations, net of tax
Discontinued operations, net of tax

(Note 24)

Net earnings
Retained earnings (deficit), beginning of year
Adjustment on cash purchase of employee stock

options, net of tax of $22,060

Reclassification from contributed surplus on cash

buy-out of employee stock options

Distribution of disposal proceeds
Repurchase of common shares of

dissenting shareholders

Distributions declared

Deficit, end of year

(Note 23(c))

(Note 24)

(Note 23(a))

(Note 6)

Earnings per unit from continuing operations:

(Note 13)

$ 1,009,201

$ 1,437,584

$ 1,269,179

516,094
56,032
78,326
2,398
–

652,850

356,351

7,767
106
(555)
–
–
–

688,207
81,217
73,234
(353)
–

842,305

595,279

8,800
171
(942)
–
–
(408)

641,805
76,397
71,561
(3,474)
17,512

803,801

465,378

38,735
558
(10,023)
71,885
70,992
–

349,033

587,658

293,231

(737)
6,950

6,213

342,820
2,956
–

345,776
(195,219)

–

–
–

34,526
(19,380)

15,146

572,512
7,077
–

579,589
(303,284)

–

–
–

241,402
(169,019)

72,383

220,848
1,335,382
74,333

1,630,563
1,041,683

(42,087)

23,215
(2,851,784)

–
(276,667)

–
(471,524)

(34,364)
(70,510)

(126,110)

(195,219)

(303,284)

Basic
Diluted

Earnings per unit:

Basic
Diluted

(Note 13)

$
$

2.73
2.73

2.75
2.75

$
$

4.56
4.56

4.62
4.62

$
$

1.79
1.76

13.22
13.00

See accompanying notes to consolidated financial statements.

C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

Precision Drilling Trust

CONSOLIDATED STATEMENTS OF CASH FLOW

Years ended December 31,

(Stated in thousands of Canadian dollars)

Cash provided by (used in):
Continuing operations:

Earnings from continuing operations
Adjustments and other items not involving cash:
Long-term incentive plan compensation
Depreciation and amortization
Future income taxes
Stock-based compensation
Write-off of deferred financing costs
Loss in market value of short-term investments
Amortization of deferred financing costs
Unrealized foreign exchange gain on long-term monetary items
Other

Changes in non-cash working capital balances

(Note 19)

Discontinued operations:

(Note 24)

Funds provided by discontinued operations
Changes in non-cash working capital balances

of discontinued operations

2007

2006

2005

342,820

572,512

220,848

(8,496)
78,326
6,950
–
–
–
–
–
112
64,403

22,699
73,234
(19,380)
–
–
–
–
–
(408)
(38,913)

484,115

609,744

–

–
71,561
(169,019)
11,229
7,664
70,992
1,453
(4,740)
–
(3,975)

206,013

183,330

(86,310)

97,020

(Notes 15 and 24)

(Note 24)

–
(186,973)
5,767
2,956
–

(16,428)
(263,030)
29,337
7,337
510

(30,421)
(155,231)
15,174
1,306,799
14,569

Investments:

Business acquisitions, net of cash acquired
Purchase of property, plant and equipment
Proceeds on sale of property, plant and equipment
Proceeds on disposal of discontinued operations
Proceeds on disposal of investments
Purchase of property, plant and equipment of

discontinued operations

Proceeds on sale of property, plant and equipment

of discontinued operations

Purchase of intangibles
Changes in non-cash working capital balances

Financing:

Distributions paid
Repayment of long-term debt
Increase in long-term debt
Issuance of Trust units
Issuance of Trust units on exercise of options
Issuance of Trust units on purchase of options
Distribution of disposal proceeds
Cash buy-out of employee stock options
Repurchase of common shares of dissenting shareholders
Issuance of common shares on exercise of options
Changes in non-cash working capital balances
Change in bank indebtedness

(Note 19)

(Note 6)

(Note 24)

–

(128,214)

–
(33)
(13,119)

–
–
7,551

17,785
(20)
(2,912)

(191,402)

(234,723)

1,037,529

(249,000)
(99,700)
78,646
–
–
–
–
–
–
–
–
(22,659)

(292,713)

(444,651)
(204,910)
248,338
9,896
–
–
–
–
–
–
–
16,306

(375,021)

–
–

–

(33,875)
(703,970)
96,826
–
8,263
5,504
(844,334)
(64,147)
(43,299)
73,930
22,060
20,468

(1,462,574)

(122,012)
122,012

–

P R E C I S I O N D R I L L I N G T R U S T

Decrease in cash and cash equivalents
Cash and cash equivalents, beginning of year

Cash and cash equivalents, end of year

–
–

–

See accompanying notes to consolidated financial statements.

Precision Drilling Trust

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular amounts are stated in thousands of Canadian dollars except unit/share numbers and per unit/share amounts)

NOTE 1. DESCRIPTION OF BUSINESS

Precision Drilling Trust (the “Trust”) is a provider of contract drilling and completion and production services to oil and natural
gas exploration and production companies in Canada and the United States.

The Trust is an unincorporated open-ended investment trust governed by the laws of Alberta and created pursuant to the
Declaration of Trust dated September 22, 2005. On September 29, 2005 the Trust, Precision Drilling Limited Partnership
(“PDLP”), 1194312 Alberta Ltd., 1195309 Alberta ULC., and Precision Drilling Corporation (“Precision”) entered into an
Arrangement Agreement (“Plan of Arrangement” or the “Plan”) to convert Precision to an income trust. As part of the Plan
of Arrangement, on November 7, 2005 Precision Drilling Corporation and certain of its subsidiaries amalgamated, and
continued as one corporation (“PDC”). After giving effect to the Plan, and related transactions, all of the shares of PDC are
owned by PDLP and indirectly by the Trust.

Prior to the Plan of Arrangement effective date of November 7, 2005 the consolidated financial statements included the
accounts of Precision, its subsidiaries and its partnerships, substantially all of which were wholly-owned. The conversion
to a trust has been accounted for on a continuity of interest basis and accordingly, the consolidated financial statements
reflect the financial position, results of operations and cash flows as if the Trust had always carried on the business formerly
carried on by Precision.

Pursuant to the Plan of Arrangement, shareholders ultimately received either Trust units or a combination of Trust units and
exchangeable LP units of PDLP for each previously held common share of Precision (other than dissenting shareholders,
who received cash equal to the fair value of their shares). After giving effect to the Plan, the consolidated financial statements
include the accounts of the Trust and its subsidiaries.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES

(a) Basis of presentation
The Trust’s accounting policies are in accordance with Canadian generally accepted accounting principles (“GAAP”). These
policies are consistent with accounting principles generally accepted in the United States in all material respects except as
outlined in Note 16.

The preparation of the consolidated financial statements requires management to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingencies. Significant
estimates used in the preparation of the financial statements include, but are not limited to, depreciation of property, plant
and equipment, valuation of long-lived assets and goodwill, allowance for doubtful accounts, accrual for long-term incentive
plan, and income taxes. Actual results could differ from these and other estimates, the impact of which would be recorded
in future periods.

(b) Principles of consolidation
The consolidated financial statements include the accounts of the Trust and its subsidiaries substantially all of which are
wholly-owned. All significant intercompany balances and transactions have been eliminated.

The Trust does not hold investments in any companies where it exerts significant influence and does not hold interests in
any variable interest entities.

(c) Cash and cash equivalents
Cash and cash equivalents consist of cash and short-term investments with original maturities of three months or less.

(d) Inventory
Inventory is primarily comprised of operating supplies and is carried at the lower of average cost, being the cost to acquire
the inventory, and replacement cost. Inventory is charged to operating expenses as items are sold or consumed at the
amount of the average cost of the item.

C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

(e) Property, plant and equipment
Property, plant and equipment are carried at cost, including costs of direct material and labour. Where costs are incurred
to extend the useful life of property, plant and equipment or to upgrade its capabilities, the amounts are capitalized to the
related asset. Costs incurred to repair or maintain property, plant and equipment are expensed as incurred.

Property, plant, and equipment are depreciated as follows:

Expected life

Salvage value

Basis of depreciation

Drilling rig equipment
Drill pipe and drill collars
Service rig equipment
Drilling rig spare equipment
Service rig spare equipment
Rental equipment
Other equipment
Light duty vehicles
Heavy duty vehicles
Buildings

5,000 utilization days
1,500 operating days
24,000 service hours
15 years
10 years
10 to 15 years
3 to 10 years
4 years
7 to 10 years
10 to 20 years

20%
–
20%
–
–
–
–
–
–
–

unit-of-production
unit-of-production
unit-of-production
straight-line
straight-line
straight-line
straight-line
straight-line
straight-line
straight-line

(f) Intangibles
Intangibles, which are comprised primarily of patents, are recorded at cost and amortized by the straight-line method over
their useful lives of 10 years. Amortization over the next five years is anticipated to be $93,000 per year for years one through
three, $13,000 for year four and $5,000 for year five.

(g) Goodwill
Goodwill is the amount that results when the purchase price of an acquired business exceeds the sum of the amounts
allocated to the assets acquired, less liabilities assumed, based on their fair values. Goodwill is allocated as of the date of
the business combination to the Trust’s reporting segments that are expected to benefit from the business combination.

Goodwill is not amortized and is tested for impairment annually in the fourth quarter, or more frequently if events or changes
in circumstances indicate that the asset might be impaired. The impairment test is carried out in two steps.

In the first step, the carrying amount of the reporting segment is compared with its fair value. When the fair value of a reporting
segment exceeds its carrying amount, goodwill of the reporting segment is considered not to be impaired and the second
step of the impairment test is unnecessary. The second step is carried out when the carrying amount of a reporting segment
exceeds its fair value, in which case the implied fair value of the reporting segment’s goodwill is compared with its carrying
amount to measure the amount of the impairment loss, if any. The implied fair value of goodwill is determined in the same
manner as the value of goodwill is determined in a business combination using the fair value of the reporting segment as
if it was the purchase price. When the carrying amount of a reporting segment’s goodwill exceeds the implied fair value of
the goodwill, an impairment loss is recognized in an amount equal to the excess.

(h) Long-lived assets
On a periodic basis, management assesses the carrying value of long-lived assets for indications of impairment. Indications
of impairment include an ongoing lack of profitability and significant changes in technology. When an indication of impairment
is present, the Trust tests for impairment by comparing the carrying value of the asset to its net recoverable amount. If the
carrying amount is greater than the net recoverable amount, the asset is written down to its estimated fair value.

(i) Income taxes
The Trust and its subsidiaries follow the liability method of accounting for future income taxes. Under the liability method,
future income tax assets and liabilities are determined based on “temporary differences” (differences between the accounting
basis and the tax basis of the assets and liabilities), and are measured using current or substantively enacted tax rates and
laws expected to apply when these differences reverse. The effect of a change in income tax rates on future tax liabilities
and assets is recognized in income in the period in which the change occurs.

For 2007 income earned directly by PDLP is not subject to income taxes as its income is taxed directly to the PDLP partners.
The Trust is a taxable entity under the Income Tax Act (Canada) and income earned is taxable only to the extent it is not
distributed or distributable to its holders of Trust units. In June 2007, the government of Canada’s Bill C-52 Budget
Implementation Act, 2007 was enacted and included legislative provisions that impose a tax on certain distributions from
publicly traded specified investment flow-through (“SIFT”) trusts at a rate equal to the applicable federal corporate tax rate

P R E C I S I O N D R I L L I N G T R U S T

plus a provincial SIFT factor. Precision will be a SIFT trust on the earlier of January 1, 2011 or the first day after it exceeds
the normal growth guidelines announced by the federal Department of Finance on December 15, 2006. The enacted SIFT
tax had no significant impact on Precision’s future tax liability.

(j) Revenue recognition
The Trust’s services are generally sold based upon service orders or contracts with a customer that include fixed or
determinable prices based upon daily, hourly or job rates. Customer contract terms do not include provisions for significant
post-service delivery obligations. Revenue is recognized when services and equipment rentals are rendered and only when
collectability is reasonably assured.

(k) Employee benefit plans
At December 31, 2007, approximately 42% (2006 – 37%) of the employees of the Trust’s subsidiaries were enrolled in defined
contribution retirement plans.

Employer contributions to defined contribution plans are expensed as employees earn the entitlement and contributions
are made.

(l) Long-term incentive plan
In 2006 the Trust instituted an annual long-term incentive plan (the “LTIP”) which compensates officers and key employees
through cash payments at the end of a three-year term. The compensation is comprised of two components, a retention
award and a performance award. The retention award is a lump sum amount determined at the date of commencement
in the LTIP and is accrued and charged to earnings on a straight-line basis over the three-year term. The performance
components are based on the growth targets as determined by the Compensation Committee of Precision and is accrued
over the three-year term of the plans.

(m) Foreign currency translation
Accounts of the Trust’s integrated foreign operations are translated to Canadian dollars using average exchange rates for
the month of the respective transaction for revenue and expenses. Monetary assets and liabilities are translated at the year-
end current exchange rate and non-monetary assets and liabilities are translated using historical rates of exchange. Gains
or losses resulting from these translation adjustments are included in net earnings.

Transactions in foreign currencies are translated at rates in effect at the time of the transaction. Monetary assets and liabilities
are translated at current rates. Gains and losses are included in net earnings.

(n) Unit-based compensation plans
An equity settled deferred trust unit plan has been established whereby non-management directors of Precision can elect
to receive all or a portion of their compensation in fully-vested deferred trust units. Under this plan, the number of deferred
trust units are adjusted for distributions to unitholders declared prior to redemption by issuing additional trust units based
on the closing market price of Precision’s Trust units on the Toronto Stock Exchange on the immediately prior trading day.
Compensation expense is recognized based on the current trading price of the Trust units at the date of grant with a
corresponding increase to contributed surplus. Upon redemption of the deferred trust units into Trust units, the amount
previously recognized in contributed surplus is recorded as an increase to unitholders’ capital.

A cash settled deferred trust unit plan has been established whereby eligible participants of Precision’s Performance Savings
Plan may elect to receive a portion of their annual performance bonus in the form of deferred trust units (“DTU”). These notional
units are adjusted for each distribution to unitholders by issuing additional DTUs based on the weighted average trading price
of Trust units on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. The values of
these DTUs are adjusted monthly based on the period-end trading price of Trust units and the resulting amount is included
in accounts payable and accrued liabilities. Gains or losses resulting from these adjustments are charged to earnings.

A cash settled Deferred Signing Bonus Unit Plan has been established for the Chief Executive Officer. Under this plan deferred
trust units are vested on the date of grant and are redeemable over a three-year period. These notional units are adjusted
for each distribution to unitholders by issuing additional DTUs based on the weighted average trading price of Trust units
on the Toronto Stock Exchange for the five days immediately following the ex-distribution date. The values of these DTUs
are adjusted monthly based on the period-end trading price of Trust units and the resulting amount that is redeemable in
the current year is included in accounts payable and accrued liabilities and the remainder is included in long-term incentive
plan payable. Gains or losses resulting from these adjustments are charged to earnings.

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

(o) Stock-based compensation plans
The Trust had equity incentive plans in 2005 and prior periods, which are described in Note 23(c). The fair value of common
share purchase options was calculated at the date of grant using the Black-Scholes option pricing model and that value
was recorded as compensation expense on a straight-line basis over the grant’s vesting period with an offsetting credit to
contributed surplus. Upon exercise of the equity purchase option, the associated amount was reclassified from contributed
surplus to unitholders’ capital as appropriate. Consideration paid by employees upon exercise of equity purchase options
was credited to unitholders’ capital as appropriate.

(p) Exchangeable LP units
Exchangeable LP units are presented as equity of the Trust as their features make them economically equivalent to Trust units.

(q) Per unit amounts
Basic per unit amounts are calculated using the weighted average number of Trust units outstanding during the year. Diluted
per unit amounts are calculated based on the treasury stock method, which assumes that any proceeds obtained on exercise
of equity based compensation arrangements would be used to purchase Trust units at the average market price during
the period. The weighted average number of units outstanding is then adjusted by the difference between the number of
units issued from the exercise of equity based compensation arrangements and units repurchased from the related proceeds.

NOTE 3. CHANGES IN ACCOUNTING POLICIES

(a) 2007 changes
Effective January 1, 2007 the Trust adopted new accounting standards issued by The Canadian Institute of Chartered
Accountants (“CICA”). The standards regarding the disclosure of comprehensive income (Sections 1530 and 3251) require
a statement of comprehensive income, which is comprised of net earnings and other comprehensive income. The Trust
does not have any amounts that would be included in comprehensive income, therefore, comprehensive income is equivalent
to net earnings and no statement of comprehensive income is presented.

The adoption of the standards relating to the recognition, measurement, disclosure and presentation of financial instruments
(Sections 3855 and 3861), and hedge accounting (Section 3865) did not have a material impact on the consolidated financial
statements. Upon adoption of Sections 3855 and 3861 the Trust has designated its financial instruments into the following
classifications:

• Cash and cash equivalents are classified as “held for trading” and any period change in fair value is recorded through

net earnings;

• Accounts receivable are classified as “loans and receivables”. After their initial fair value measurement, they are measured
at amortized cost using the effective interest rate method. For the Trust, the measured amount generally corresponds
to historical cost; and

• Accounts payable and accrued liabilities, bank indebtedness, distributions payable and long-term debt are classified as
“other financial liabilities”. After their initial fair value measurement, they are measured at amortized cost using the effective
interest rate method. For the Trust, the measured amount generally corresponds to historical cost.

In addition, the Trust early adopted new accounting standards related to the disclosure and presentation of financial instruments
(Sections 3862 and 3863). These standards, which replace Section 3861, provide enhanced disclosure around the nature
and extent of risks arising from financial instruments to which the entity is exposed and how the entity manages those risks.
Adoption of these standards did not have a material impact on the consolidated financial statements.

(b) Future accounting pronouncements
Effective January 1, 2008 the Trust is required to adopt new Canadian accounting standards relating to inventories (Section
3031) and capital disclosures (Section 1535). Section 3031 will require inventories to be measured at the lower of cost or
net realizable value and the reversal of previously recorded write downs to realizable value when the circumstances that
caused the write down no longer exist. This new standard is not expected to have a material impact on the Trust’s financial
statements. Section 1535 will require the Trust to provide additional quantitative and qualitative information regarding its
objectives, policies and processes for managing its capital.

P R E C I S I O N D R I L L I N G T R U S T

NOTE 4. PROPERTY, PLANT AND EQUIPMENT

2007

Rig equipment
Rental equipment
Other equipment
Vehicles
Buildings
Assets under construction
Land

2006

Rig equipment
Rental equipment
Other equipment
Vehicles
Buildings
Assets under construction
Land

Cost

Accumulated
Depreciation

$ 1,464,145
95,435
97,397
76,387
30,614
77,096
10,121

485,822
45,917
69,483
27,892
11,494
–
–

Net Book
Value

978,323
49,518
27,914
48,495
19,120
77,096
10,121

$ 1,851,195

640,608

$ 1,210,587

Cost

Accumulated
Depreciation

$ 1,294,289
94,184
95,137
78,675
29,583
76,239
10,110

434,491
40,658
61,317
24,461
9,673
–
–

Net Book
Value

859,798
53,526
33,820
54,214
19,910
76,239
10,110

$ 1,678,217

570,600

$ 1,107,617

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

NOTE 5. BANK INDEBTEDNESS

At December 31, 2007 and 2006 the Trust had available $60.0 million and US$5.0 million under unsecured credit facilities,
of which $14.1 million had been drawn (2006 – $36.8 million). Availability of these facilities were reduced by outstanding
letters of credit in the amount of $2.0 million (2006 – $4.0 million). Advances under the facilities are available at the bank’s
prime lending rate, U.S. base rate, U.S. Libor plus applicable margin or Banker’s Acceptance plus applicable margin, or in
combination. As at December 31, 2007 and 2006 the amounts drawn under these facilities were at the bank’s prime lending
rate of 6% .

NOTE 6. DISTRIBUTIONS

The beneficiaries of the Trust are the holders of Trust units and the partners of PDLP are the holders of exchangeable LP
units exchangeable into units (together “unitholders”) of the Trust. The monthly distributions made by the Trust to unitholders
are determined by the Trustees. PDLP earns interest income from a promissory note issued by its subsidiary PDC at a rate
which is determined by the terms of the promissory note. PDLP in substance pays distributions to holders of exchangeable
LP units in amounts equal to the distributions paid to the holders of Trust units. All distributions are made to unitholders of
record on the last business day of each calendar month.

The Declaration of Trust provides that an amount equal to the taxable income of the Trust not already paid to unitholders
in the year will become payable on December 31 of each year such that the Trust will not be liable for ordinary income taxes
for such year.

A distribution reinvestment plan (the “DRIP”) was approved by the Board of Trustees in February 2006, and implemented
in March 2006. The DRIP allows certain holders of Trust units, at their option, to reinvest monthly cash distributions to acquire
additional Trust units at the average market price as defined in the DRIP. Unitholders who are not resident in Canada or
hold exchangeable LP units are not eligible to participate in the DRIP. The Trust reserved the right to amend, suspend, or
terminate the DRIP at any time. The DRIP was suspended in December 2006.

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

A summary of the distributions is as follows:

Declared
Paid
Payable in cash at December 31
Payable in units at December 31

2007

2006

$
$
$
$

276,667
249,000
36,470
30,182

$
$
$
$

471,524
444,651
38,985
24,523

$
$
$
$

2005

70,510
33,875
36,635
–

Included in the 2007 distributions declared is a special non-cash distribution of $30.2 million ($0.24 per unit) (2006 –
$24.5 million or $0.195 per unit). This special distribution was settled on January 15, 2008 through the issuance of units.
Immediately following the issuance of these units, the Trust consolidated the units such that the number of Trust units remained
unchanged from the number outstanding prior to the special distribution. The exchangeable LP units received equivalent
economic treatment.

NOTE 7. LONG-TERM DEBT

Extendible revolving unsecured facility:
At December 31, 2007 and 2006 PDC, a subsidiary of the Trust, has available a three-year revolving unsecured facility of
$700.0 million (or U.S. equivalent) with a syndicate led by a Canadian chartered bank, which is guaranteed by the Trust.
The facility matures on November 2, 2009 and is renewable annually at the option of the lenders. Advances are available
to PDC under this facility either at the bank’s prime lending rate, U.S. base rate, U.S. Libor plus applicable margin or Bankers’
Acceptance plus applicable margin or in combination. The applicable margin is dependent on the Trust’s consolidated debt
to cash flow ratio and the percentage of the total facility outstanding, which at December 31, 2007 and 2006 was 75 basis
points. The facility requires that the Trust maintain a ratio of total liabilities to total equity of less than 1:1, a trailing 12 month
ratio of consolidated debt to cash flow of less than 2.75:1 and total distributions to unitholders of less than 100% of
consolidated cash flow as defined in the facility agreement. As at December 31, 2007, the Trust had drawn $119.8 million
(2006 – $140.9 million) under this facility.

Unsecured debentures and notes:
During the fourth quarter of 2005 Precision repaid all of its outstanding debentures and notes pursuant to the early redemption
provisions of the related agreements. The difference between the $766.7 million redemption price and the carrying value
of the debentures was charged to income.

NOTE 8. INCOME TAXES

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

Earnings from continuing operations before income taxes
Federal and provincial statutory rates

Tax at statutory rates
Adjusted for the effect of:

Non-deductible expenses
Non-deductible stock-based compensation
Income to be distributed to unitholders,

not subject to tax in the Trust

Utilization of losses and surcharge credits
Other

Income tax expense before tax rate reductions
Reduction of future income tax balances due to

enacted tax rate reductions

Income tax expense

2007

2006

2005

349,033
33%

115,181

587,658
33%

193,927

293,231
34%

99,699

1,080
–

(91,013)
–
3,426

28,674

297
–

(155,354)
–
(2,896)

35,974

2,795
3,216

(23,980)
(10,550)
1,203

72,383

(22,461)

(20,828)

–

6,213

15,146

72,383

Effective income tax rate before enacted tax rate reductions

25%

P R E C I S I O N D R I L L I N G T R U S T

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

The net future tax liability is comprised of the tax effect of the following temporary differences:

2007

2006

Future income tax liability:

Property, plant and equipment and intangibles

209,772

213,281

Future income tax assets:

Bond redemption premium
Losses
Share issue costs
Long-term incentive plan
Accrued liabilities

9,185
9,128
817
5,743
3,266

28,139

13,314
9,879
1,966
10,614
2,937

38,710

Net future income tax liability

181,633

174,571

PDC and its subsidiaries have available net capital losses of $33.8 million of which, after valuation allowances, the benefit
of $33.8 million (2006 – $33.4 million) has been recognized. Net capital losses can be carried forward indefinitely.

NOTE 9. UNITHOLDERS’ CAPITAL

(a) Authorized – unlimited number of voting Trust units

– unlimited number of voting exchangeable LP units

(b) Unitholders’ capital

Trust units

Balance, November 7, 2005

Issued pursuant to the Plan
Options exercised – cash consideration

– reclassification from contributed surplus

Issued for cash

Balance, December 31, 2005

Issued pursuant to distribution reinvestment plan (Note 6)
Issued on retraction of exchangeable LP units
Issued and consolidated pursuant to special distribution (Note 6)

Balance, December 31, 2006

Issued on retraction of exchangeable LP units
Issued and consolidated pursuant to special distribution (Note 6)

Number

Amount

–
122,512,799
1,676,616
–
163,506

124,352,921
296,621
886,787
–

125,536,329
51,590
–

–
1,339,646
8,263
12,342
5,504

1,365,755
9,896
9,697
24,480

1,409,828
574
30,141

Balance, December 31, 2007

125,587,919

$ 1,440,543

Trust units are redeemable at the option of the holder, at which time all rights with respect to such units are cancelled. Upon
redemption, the unitholder is entitled to receive a price per unit equal to the lesser of 90% of the average market price of
the Trust’s units for the 10 trading days just prior to the date of redemption, and the closing market price of the Trust’s units
on the date of redemption. The maximum value of units that can be redeemed for cash is $50,000 per month. Redemptions,
if any, in excess of this amount are satisfied by issuing a note from PDC to the unitholder, payable over 15 years and bearing
interest at a market rate set by the Board of Directors.

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

Exchangeable LP units

Balance, November 7, 2005

Issued pursuant to the Plan

Balance, December 31, 2005

Redeemed on retraction of exchangeable LP units
Issued and consolidated pursuant to special distribution (Note 6)

Balance, December 31, 2006

Redeemed on retraction of exchangeable LP units
Issued and consolidated pursuant to special distribution (Note 6)

Number

–
1,108,382

1,108,382
(886,787)
–

221,595
(51,590)
–

Balance, December 31, 2007

170,005

Amount

–
12,120

12,120
(9,697)
43

2,466
(574)
41

1,933

Exchangeable LP units have voting rights and were exchangeable, after May 6, 2006, for Trust units on a one-for-one basis
at the option of the holder. Holders are entitled to monthly cash distributions equal to those paid to holders of Trust units.

Summary as at December 31,

Number

Amount

Number

Amount

2007

2006

Trust units
Exchangeable LP units

Unitholders’ capital

Balance, December 31, 2006

Unit based compensation expense (Note 10(c))

Balance, December 31, 2007

125,587,919
170,005

$ 1,440,543
1,933

125,536,329
221,595

$ 1,409,828
2,466

125,757,924

$ 1,442,476

125,757,924

$ 1,412,294

–
307

307

NOTE 10. UNIT BASED COMPENSATION PLANS

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

During 2007, Precision issued 87,340 DTUs, including additional DTUs issued in lieu of cash distributions and redeemed
10,611 DTUs on employee resignations and employee withdrawals. As at December 31, 2007 $1.2 million is included in
accounts payable and accrued liabilities for outstanding DTUs. Included in net earnings for the year ended December 31,
2007 is a recovery of $0.8 million.

(b) Executive
In 2007 Precision instituted a Deferred Signing Bonus Unit Plan for its Chief Executive Officer. Under the plan 178,336 notional
DTUs were granted on September 1, 2007. The units are redeemable one-third annually beginning September 1, 2008
and are settled for cash based on the Trust unit trading price on redemption. The number of notional DTUs is adjusted
for each distribution to unitholders by issuing additional notional DTUs based on the weighted average trading price on
the Toronto Stock Exchange for the five days immediately following the ex-distribution date. As at December 31, 2007
$0.9 million is included in accounts payable and accrued liabilities and $1.9 million in long-term incentive plan payable for
the 182,372 outstanding DTUs. Included in net earnings for the year ended December 31, 2007 is an expense of $2.8 million.

(c) Non-management directors
In 2007 a deferred trust unit plan was established for non-management directors. Under the plan fully vested deferred trust
units are granted quarterly based upon an election by the non-management director to receive all or a portion of their
compensation in deferred trust units. Distributions to unitholders declared by the Trust prior to redemption are reinvested
into additional deferred trust units on the date of distribution. These deferred trust units are redeemable into an equal number
of Trust units any time after the director’s retirement.

P R E C I S I O N D R I L L I N G T R U S T

A summary of this unit based incentive plan is presented below:

Balance, December 31, 2006

Granted
Issued as a result of distributions

Balance, December 31, 2007

Deferred
Trust Units
Outstanding

–
17,855
425

18,280

For the year ended December 31, 2007 the Trust expensed $307,000 as unit based compensation, with a corresponding
increase in contributed surplus.

NOTE 11. EMPLOYEE BENEFIT PLANS

The Trust has registered pension plans covering a significant number of its employees.

(a) Defined contribution plan
Under the defined contribution plan, the Trust matches individual contributions up to 5% of the employee’s compensation.
Total expense under the defined contribution plan in 2007 was $5.3 million (2006 – $5.5 million; 2005 – $8.5 million), of
which $nil (2006 – $nil; 2005 – $3.2 million) relates to discontinued operations.

(b) Retirement allowance
The Trust had entered into an employment agreement with a senior officer, which provided for a one-time payment upon
retirement. The amount of this retirement allowance increased by a fixed amount for each year of service over a ten year
period commencing April 30, 1996. The estimated cost of this benefit was being accrued and charged to earnings on a
straight-line basis over the ten year period. During the year ended December 31, 2005, the Trust charged $201,000 and
paid $2.9 million as final settlement of this liability.

NOTE 12. COMMITMENTS

The Trust has commitments for operating lease agreements, primarily for vehicles and office space, in the aggregate amount
of $22.6 million. Payments over the next five years are as follows:

2008
2009
2010
2011
2012

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

2007
2006
2005

7,754
6,329
5,078
3,463
16

Total

3,838
4,189
15,819

Continuing
Operations

Discontinued
Operations

3,838
4,189
3,836

–
–
11,983

NOTE 13. PER UNIT AMOUNTS

The following table summarizes the units, adjusted retroactively for a 2 for 1 stock split on May 18, 2005, used in calculating
earnings per unit:

(Stated in thousands)

Weighted average units outstanding – basic
Effect of stock options and other equity compensation plans

Weighted average units outstanding – diluted

2007

2006

2005

125,758
2

125,760

125,545
–

125,545

123,304
2,108

125,412

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

NOTE 14. SIGNIFICANT CUSTOMERS

During the year ended December 31, 2007 one customer (2006 and 2005 – no customers) accounted for approximately
10% of the Trust’s revenue and year-end trade accounts receivable balance.

NOTE 15. BUSINESS ACQUISITIONS

Acquisitions have been accounted for by the purchase method with results of operations acquired included in the consolidated
financial statements from the closing date of acquisition. Acquisitions relating to discontinued operations are reflected in
Note 24.

On August 17, 2006, the Trust acquired all of the shares of Terra Water Group Ltd. (“Terra”), a privately owned provider of
wastewater treatment units for the traditional drilling rig camp market in western Canada. The Terra operations are included
in the Completion and Production Services segment. The details of the acquisition are as follows:

Net assets acquired at assigned values:

Working capital (1)
Property, plant and equipment
Goodwill (no tax basis)
Long-term debt
Future income taxes

Consideration:

Cash

(1) Working capital includes cash of $43

207
3,168
13,922
(614)
(212)

16,471

NOTE 16. UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

These financial statements have been prepared in accordance with Canadian GAAP which conform with United States
generally accepted accounting principles (“U.S. GAAP”) in all material respects, except as follows:

(a) Income taxes
Precision adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48 (“FIN 48”) Accounting for Uncertainty
in Income Taxes, for the fiscal year beginning January 1, 2007. The implementation of FIN 48 did not have a material impact
on Precision’s U.S. GAAP reconciliation and no adjustment has been made to the January 1, 2007 deficit balance.

On December 31, 2007 Precision had $44.4 million (2006 – $40.0 million) of unrecognized tax benefits that, if recognized,
would have a favourable impact on Precision’s effective income tax rate in future periods. Precision classifies interest accrued
on unrecognized tax benefits and income tax penalties as income tax expense. Included in the unrecognized tax benefit
as at December 31, 2007 is interest and penalties of $7.0 million (2006 – $3.2 million). Under FIN 48, unrecognized tax
benefits are classified as current or long-term liabilities as opposed to future income tax liabilities.

Reconciliation of unrecognized tax benefits

Year ended December 31,

Unrecognized tax benefits, beginning of year

Additions:

Prior year’s tax positions

Reductions:

Prior year’s tax positions

Unrecognized tax benefits, end of year

2007

40,047

5,770

(1,410)

44,407

It is anticipated that approximately $8.4 million of an unrecognized tax position that relates to past reorganization activities
will be realized during the next 12 months and has been classified as a current liability. Subject to the results of audit
examinations by taxing authorities and/or legislative changes by taxing jurisdictions, Precision does not anticipate further
adjustments of unrecognized tax positions during the next 12 months that would have a material impact on the consolidated
financial statements.

P R E C I S I O N D R I L L I N G T R U S T

Precision and its subsidiaries are subject to federal, regional and local taxes in Canada, the United States and other international
jurisdictions. Precision has substantially settled all Canadian, U.S. and international income tax matters for taxation years
ending before 2000.

In 2000 the Trust adopted the liability method of accounting for future income taxes without restatement of prior years. As
a result, the Trust recorded an adjustment to retained earnings and future tax liability in the amount of $70.0 million at January 1,
2000. U.S. GAAP requires the use of the liability method prescribed in the Statement of Financial Accounting Standards
(SFAS) No. 109, which substantially conforms to the Canadian GAAP accounting standard adopted in 2000. Application
of U.S. GAAP in years prior to 2000 would have resulted in $70.0 million of additional goodwill being recognized at January 1,
2000 as opposed to an implementation adjustment to retained earnings allowed under Canadian GAAP. Prior to 2002 goodwill
was amortized under Canadian and U.S. GAAP. As a result, $7.0 million of amortization was recorded on the additional
goodwill in 2000 and 2001 under U.S. GAAP. In 2006 and 2007 the U.S. GAAP financial statements reflect an increase in
goodwill of $63.0 million and a corresponding increase in retained earnings.

(b) Equity settled unit based compensation
As described in Note 10(c), the Trust has initiated an equity settled unit based compensation plan for non-management
directors. Trust units issued upon settlement of this plan are redeemable (see Note 16(d)) therefore under U.S. GAAP the
plan is accounted for as a liability based award. The liability is re-measured, until settlement, at the end of each reporting
period with the resultant change being charged or credited to the statement of earnings as compensation expense.

(c) Stock-based compensation
In 2004, under Canadian GAAP, the Trust adopted the fair value of accounting for stock-based compensation with restatement
of prior years for share purchase options granted after January 1, 2002. U.S. GAAP allows the use of either the intrinsic
method, as prescribed by Accounting Principles Board (“APB”) Opinion 25, or the fair value method as prescribed by SFAS 123.
Where companies elect to use the intrinsic method, disclosure of the impact of using the fair value method is required.

Application of the intrinsic method in accordance with APB Opinion 25 would have resulted in an increase in net earnings
of $21.3 million for 2005 with a corresponding increase in unitholders’ equity. Had the Trust determined compensation based
on the fair value at the date of grant for its options under SFAS 123, net earnings in accordance with U.S. GAAP would
have decreased to $1,588.5 million in 2005. Basic earnings per unit/share would have been $12.88 in 2005.

Under Financial Accounting Standards Board (“FASB”) Interpretation No. 44 (“FIN 44”) Accounting for Certain Transactions
Involving Stock Compensation, compensation expense is required to be recognized on certain modifications to stock-based
compensation plans. During the year ended December 31, 2005, employee stock options (“options”) were subjected to a
variety of changes or restructurings which included accelerated vesting, repricing on the date of conversion to an income
trust to reflect the distribution of disposal consideration to Precision’s shareholders just prior to conversion, or repurchase
for cash depending on elections made by the option holders. Under Canadian GAAP, even with repricing, the options were
treated as equity awards and were not accounted for under a variable accounting method. However, under U.S. GAAP,
the accelerated vesting represents a restructuring in the form of a modification that would result in a new measurement of
compensation expense on the date of the modification to the date of exercise using the intrinsic method. For award repricing,
this restructuring only results in additional expense provided that the aggregate intrinsic value of the awards immediately
after the change is not greater than that immediately before, and the ratio of exercise price per unit/share to the market
value per unit/share is not reduced. To the extent that both criteria are not met, the awards are accounted for under ABP
Opinion 25 as a variable award from the date of restructuring to the date the award was exercised. For restructuring in the
form of cash buy-out of the options, the intrinsic value was charged to retained earnings under Canadian GAAP, however,
under U.S. GAAP the amount was charged to earnings.

(d) Redemption of Trust units
Under the Declaration of Trust, Trust units are redeemable at any time on demand by the unitholder for cash and notes
(see Note 9). Under U.S. GAAP, the amount included on the consolidated balance sheet for unitholders’ equity would be
moved to temporary equity and recorded at an amount equal to the redemption value of the Trust units as at the balance
sheet date. The same accounting treatment would be applicable to the exchangeable LP units. The redemption value of
the Trust units and the exchangeable LP units is determined with respect to the trading value of the Trust units as at each
balance sheet date, and the amount of the redemption value is classified as temporary equity. Changes (increases and
decreases) in the redemption value during a period results in a change to temporary equity and is charged to retained earnings.

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

(e) Recently issued accounting pronouncements
In December 2007, FASB issued SFAS 160, Non-controlling Interest in Consolidated Financial Statements. The statement
clarifies the classification of non-controlling interests in the financial statements and the accounting for and reporting of
transactions between the reporting entity and the holders of the non-controlling interests. The statement is effective for
fiscal years beginning after December 15, 2008, and will be effective for the Trust’s December 31, 2009 year end. At this
time management does not expect this statement to have a material impact on the consolidated financial statements.

In December 2007, FASB issued SFAS 141(R), Business Combinations. The statement requires most identifiable assets,
liabilities, non-controlling interests and goodwill acquired in a business combination be recorded at fair value. In addition
the new standard requires all business combinations be accounted for by applying the acquisition method and that all
transaction costs be expensed as incurred. The statement is applicable for all business combinations occurring in fiscal
years beginning after December 15, 2008 and will be effective for the Trust’s December 31, 2009 year end.

In February 2007 FASB issued SFAS 159, The Fair Value Option for Financial Assets and Liabilities – including an amendment
of FASB Statement No. 115. The statement provides entities with an irrevocable option to report selected financial assets
and liabilities at fair value. The objective is to improve financial reporting by reducing both the complexity in accounting and
the volatility in earnings caused by differences in existing accounting rules. The new standard is effective for fiscal years
beginning after November 15, 2007 and will be effective for the Trust’s December 31, 2008 year end. The effective date for
SFAS 157 as it relates to fair value measurement requirements for non-financial assets and liabilities that are not re-measured
at fair value on a recurring basis has been deferred to fiscal years beginning after December 31, 2008. Management does
not expect this statement to have a material impact on the consolidated financial statements.

On September 15, 2006 FASB issued SFAS 157, Fair Value Measurements. The statement provides enhanced guidance
for using fair value to measure assets and liabilities, but does not expand the use of fair value in any new circumstances.
The new standard is effective for fiscal years beginning after November 15, 2007 and will be effective for the Trust’s
December 31, 2008 year end. Management does not expect this statement to have a material impact on the consolidated
financial statements.

The application of U.S. GAAP accounting principles would have the following impact on the consolidated financial statements:

Consolidated Statements of Earnings

Years ended December 31,

Earnings from continuing operations under Canadian GAAP
Adjustments under U.S. GAAP:

Equity-based compensation expense
Cash buy-out of options
Intrinsic value recognized on options exercised and/or repriced

Earnings from continuing operations under U.S. GAAP

Earnings from discontinued operations under Canadian GAAP
Adjustments under U.S. GAAP:

Stock-based compensation expense
Cash buy-out of options
Intrinsic value recognized on options exercised and/or repriced

Earnings from discontinued operations under U.S. GAAP

Net earnings and comprehensive income under U.S. GAAP

Earnings from continuing operations per unit under U.S. GAAP:

Basic
Diluted

Earnings per unit under U.S. GAAP:

Basic
Diluted

2007

2006

2005

342,820

572,512

220,848

35
–
–

342,855

2,956

–
–
–

2,956

345,811

2.73
2.73

2.75
2.75

$
$

–
–
–

572,512

7,077

–
–
–

11,229
(22,119)
(2,270)

207,688

1,409,715

10,109
(19,968)
(11,796)

7,077

1,388,060

579,589

$ 1,595,748

4.56
4.56

4.62
4.62

$
$

1.68
1.66

12.94
12.72

$
$

P R E C I S I O N D R I L L I N G T R U S T

Consolidated Statements of Retained Earnings (Deficit)

Years ended December 31,

2007

2006

2005

Retained earnings (deficit) under U.S. GAAP, beginning of year
Net earnings under U.S. GAAP
Distributions declared
Distribution of disposal proceeds
Repurchase of common shares of dissenting shareholders
Opening temporary equity on conversion to an income trust
Change in redemption value of temporary equity

$ (1,873,490)
345,811
(276,667)
–
–
–
1,453,448

$ (3,167,045)
579,589
(471,524)
–
–
–
1,185,490

$ 1,133,030
1,595,748
(70,510)
(2,851,784)
(34,364)
(2,560,709)
(378,456)

Deficit under U.S. GAAP, end of year

(350,898)

$ (1,873,490)

$ (3,167,045)

Consolidated Balance Sheets

As at December 31,

As reported

U.S. GAAP

As reported

U.S. GAAP

2007

2006

Current assets
Property, plant and equipment
Intangibles
Goodwill

Current liabilities
Long-term incentive plan payable
Long-term debt
Future income taxes
Other long-term liabilities
Temporary equity
Unitholders’ capital
Contributed surplus
Deficit

271,823
1,210,587
318
280,749

271,823
1,210,587
318
343,778

372,445
1,107,617
375
280,749

372,445
1,107,617
375
343,778

$ 1,763,477

$ 1,826,506

$ 1,761,186

$ 1,824,215

131,449
13,896
119,826
181,633
–
–
1,442,476
307
(126,110)

140,117
13,896
119,826
137,226
36,011
1,730,328
–
–
(350,898)

205,961
22,699
140,880
174,571
–
–
1,412,294
–
(195,219)

205,961
22,699
140,880
174,571
–
3,153,594
–
–
(1,873,490)

$ 1,763,477

$ 1,826,506

$ 1,761,186

$ 1,824,215

NOTE 17. SEGMENTED INFORMATION

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

2007

Revenue
Operating earnings
Depreciation and amortization
Total assets
Goodwill
Capital expenditures

Contract
Drilling
Services

Completion and
Production
Services

694,340
284,754
43,120
1,282,865
172,440
159,004

327,471
100,596
31,421
457,587
108,309
26,772

Corporate
and Other

Inter-segment
Eliminations

–
(28,999)
3,785
23,025
–
1,230

(12,610)
–
–
–
–
–

Total

$ 1,009,201
356,351
78,326
1,763,477
280,749
187,006

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

2006

Revenue
Operating earnings
Depreciation and amortization
Total assets
Goodwill
Capital expenditures*

* Excludes business acquisitions

2005

Revenue
Operating earnings
Depreciation and amortization
Total assets
Goodwill
Capital expenditures*

* Excludes business acquisitions

Contract
Drilling
Services

Completion and
Production
Services

$ 1,009,821
473,624
38,573
1,198,284
172,440
220,397

441,017
163,119
32,013
507,510
108,309
39,273

Contract
Drilling
Services

Completion and
Production
Services

916,221
404,385
39,233
1,159,687
172,440
106,986

369,667
121,643
27,402
486,701
94,387
34,576

Corporate
and Other

Inter-segment
Eliminations

–
(41,464)
2,648
55,392
–
3,360

(13,254)
–
–
–
–
–

Corporate
and Other

Inter-segment
Eliminations

–
(60,650)
4,926
72,494
–
13,689

(16,709)
–
–
–
–
–

Total

$ 1,437,584
595,279
73,234
1,761,186
280,749
263,030

Total

$ 1,269,179
465,378
71,561
1,718,882
266,827
155,251

NOTE 18. FINANCIAL INSTRUMENTS

(a) Fair value
The carrying value of accounts receivable, bank indebtedness, accounts payable and accrued liabilities and distributions
payable approximate their fair value due to the relatively short period to maturity of the instruments. The fair value of long-term
debt approximates its carrying value as it bears floating rates.

(b) Credit risk
Accounts receivable includes balances from a large number of customers primarily operating in the oil and gas industry.
The Trust assesses the creditworthiness of its customers on an ongoing basis as well as monitoring the amount and age
of balances outstanding. Accordingly, the Trust views the credit risks on these amounts as normal for the industry.

As at December 31, 2007 the Trust’s allowance for doubtful accounts was $6.4 million (2006 – $5.6 million). Included in
net earnings for the year ended December 31, 2007 is a charge for $1.2 million (2006 – $0.7 million) related to a provision
for doubtful accounts.

(c) Interest rate risk
The Trust is exposed to interest rate risk with respect to interest expense on its credit facilities. If interest rates applying to
long-term debt during the year had been one percent lower or higher, with all other variables held constant, earnings from
continuing operations would have changed by approximately $1.1 million (2006 – $1.0 million), net of income tax.

(d) Foreign currency risk
The Trust was exposed to foreign currency fluctuations in relation to its international operations prior to their disposal in
2005 (see Note 24). To manage a portion of this exposure, the Trust designated US$300.0 million notes as a hedge against
foreign currency fluctuations of its investment in self-sustaining foreign operations. A net foreign exchange gain of $10.1 million
associated with these notes was included in the cumulative translation account during 2005. The cumulative translation
account at August 31, 2005 of $24.8 million was charged to the gain on disposal of discontinued operations in 2005.

P R E C I S I O N D R I L L I N G T R U S T

NOTE 19. SUPPLEMENTAL INFORMATION

Interest paid:

– continuing operations
– discontinued operations

Income taxes paid:

– continuing operations
– discontinued operations

Components of change in non-cash working capital balances:

Accounts receivable
Inventory
Accounts payable and accrued liabilities
Income taxes

The components of accounts receivable are as follows:

Trade
Accrued trade
Prepaids and other

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

Accounts payable
Accrued liabilities:

Payroll
Other

2007

2006

2005

7,870
–

7,870

4,307
–

4,307

98,055
(182)
(49,338)
2,749

8,929
–

8,929

207,160
–

207,160

148,046
(2,038)
(4,736)
(172,634)

43,232
304

43,536

91,496
35,176

126,672

(171,363)
699
13,871
149,906

51,284

(31,362)

(6,887)

2007

2006

144,468
96,869
15,279

220,623
93,308
40,740

256,616

354,671

2007

2006

36,742

60,650

28,527
15,595

80,684

47,001
22,551

130,202

NOTE 20. CONTINGENCIES

The business and operations of the Trust are complex and the Trust has executed a number of significant financings, business
combinations, acquisitions and dispositions over the course of its history. The computation of income taxes payable as a
result of these transactions involves many complex factors as well as the Trust’s interpretation of relevant tax legislation and
regulations. The Trust’s management believes that the provision for income tax is adequate and in accordance with generally
accepted accounting principles and applicable legislation and regulations. However, there are a number of tax filing positions
that can still be the subject of review by taxation authorities who may successfully challenge the Trust’s interpretation of the
applicable tax legislation and regulations, with the result that additional taxes could be payable by the Trust and the amount
payable, before interest and penalties, could be up to $300 million.

Subsequent to year end Precision received, from a provincial taxing authority, Notices of Reassessment relating to prior
period tax filing positions for $55 million. The income tax related portion of the reassessments is $36 million and is included
in the tax contingency noted above. Precision is of the opinion that the provincial tax authority’s position is without merit
and will be challenging these reassessments.

The Trust, through the performance of its services, product sales and business arrangements, is sometimes named as a
defendant in litigation. The outcome of such claims against the Trust is not determinable at this time, however, their ultimate
resolution is not expected to have a material adverse effect on the Trust.

The Trust maintains a level of insurance coverage deemed appropriate by management for matters for which insurance
coverage can be acquired.

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

NOTE 21. GUARANTEES

The Trust has entered into agreements indemnifying certain parties primarily with respect to tax and specific third party
claims associated with businesses sold by the Trust. Due to the nature of the indemnifications, the maximum exposure
under these agreements cannot be estimated. No amounts have been recorded for the indemnities as the Trust’s obligations
under them are not probable or estimable.

NOTE 22. RELATED PARTY TRANSACTIONS

During the year ended December 31, 2005 the Trust incurred a total of $6.1 million in legal fees with a law firm for various
legal matters where a director of Precision Drilling Corporation was a partner. These transactions were incurred in the normal
course of business and were recorded at the exchange amounts.

NOTE 23. REORGANIZATION INTO A TRUST

To effect the reorganization into a trust, for the year ended December 31, 2005, the Trust incurred $17.5 million of reorganization
costs comprised as follows:

Severance
Legal, accounting, financial advisory services and other

12,600
4,912

17,512

Share capital of Precision prior to reorganization into the Trust included:

(a) Common shares
On November 7, 2005, Precision converted to an unincorporated, open-ended investment trust pursuant to the Plan, which
resulted in shareholders receiving one Trust unit or one exchangeable LP unit or a combination thereof, for each previously
held common share. Common shares held by shareholders who dissented to the Plan were repurchased and cancelled
on the effective date of the Plan. All outstanding common share purchase options were converted to options to acquire
Trust units. The holder then had three options; exercise the options, have the Trust repurchase them for cash using the
closing market price of the Trust one day prior to cash-out, or have the Trust repurchase the options as set-out above and
use the proceeds to purchase an equivalent number of Trust units.

Balance, December 31, 2004

Options exercised – cash consideration

– reclassification from contributed surplus

Balance, May 18, 2005

Issued on 2:1 stock split
Options exercised – cash consideration

– reclassification from contributed surplus

Adjustment to number of shares outstanding
Cancellation of shares owned by dissenting shareholders

Balance, November 7, 2005, before conversion to units

Conversion to Trust units
Conversion to exchangeable LP units

Number

Amount

60,790,212
578,346
–

61,368,558
61,368,558
1,679,110
–
21,960
(817,005)

123,621,181
(122,512,799)
(1,108,382)

$ 1,274,967
24,516
1,521

1,301,004
–
49,414
10,284
–
(8,936)

1,351,766
(1,339,646)
(12,120)

Balance, November 7, 2005, after conversion to units

–

Pursuant to the Plan, any shareholders of Precision could dissent and be paid the fair value of the shares, being the trading
price at the close of business on the last business day prior to the Special Meeting of Securityholders on October 31, 2005.
As a result, the Trust repurchased for cancellation a total of 817,005 shares for $43.3 million, of which a premium of
$34.4 million over the stated capital was charged to retained earnings.

P R E C I S I O N D R I L L I N G T R U S T

(b) Contributed surplus:

Balance, December 31, 2004

Stock-based compensation expense
Accelerated vesting of options on disposal of discontinued operations
Reclassification to common shares on exercise of options prior to the Plan
Accelerated vesting of options pursuant to the Plan
Reclassification to Trust units on exercise of options
Reclassification to retained earnings on cash buy-out of options

Balance, December 31, 2005

26,024
13,077
5,205
(11,805)
3,056
(12,342)
(23,215)

–

(c) Equity incentive plans
Prior to conversion to a Trust, Precision had equity incentive plans under which the exercise price of each option equaled
the market value of the Corporation’s share on the date of grant and an option’s maximum term was 10 years. Options
vested over a period of 1 to 4 years from the date of grant as employees or directors rendered continuous service to Precision.

Options held by employees of the Energy Services and International Contract Drilling Divisions and of CEDA International
Corporation (“CEDA”) became fully vested when these businesses were sold during the third quarter of 2005 (see Note 24).
Pursuant to the Plan, the remaining outstanding options were exchanged for newly vested options to acquire Trust units.
The exercise prices of the options to acquire Trust units were adjusted downward to reflect the value of the distribution of
certain assets to shareholders as part of the Plan. The options to acquire Trust units expired on November 22, 2005.

Upon acceleration of the vesting of options, options holders were given the choice to pay the exercise price and receive a
common share or Trust unit, as applicable, or to surrender their option for a cash payment equal to the difference between
the closing market value of the common share or Trust unit one day prior to cash buy-out and the exercise price. All outstanding
options were exercised prior to December 31, 2005.

A summary of the equity incentive plans, adjusted retroactively to reflect the 2 for 1 stock split on May 18, 2005 as at
December 31, 2005 and changes during the period then ended is presented below:

Common Share Purchase Options

Outstanding at December 31, 2004

Granted
Exercised
Cancelled
Purchased
Exchanged for Trust unit purchase options

Options
Outstanding

6,695,120
696,200
(2,835,802)
(141,650)
(1,105,018)
(3,308,850)

Range of
Exercise Price

$ 15.53 – 36.32
37.76 – 48.29
15.53 – 48.29
15.53 – 31.87
15.53 – 45.25
15.53 – 48.29

Weighted
Average
Exercise Price

27.44
41.42
26.07
30.26
31.30
30.14

Options
Exercisable

2,580,302

Outstanding at December 31, 2005

–

Trust Unit Purchase Options

Options
Outstanding

Range of
Exercise Price

Weighted
Average
Exercise Price

Options
Exercisable

Outstanding at November 7, 2005

–

Granted in exchange for common share
purchase options pursuant to the Plan

Granted on repricing of common share options
Exercised
Purchased

3,308,850
5,600
(1,676,616)
(1,637,834)

nil – 27.25
nil
nil – 27.25
nil – 27.25

9.16
nil
4.93
13.46

3,308,850

Outstanding at December 31, 2005

–

In accordance with the Trust’s common share purchase option plans, options had an initial exercise price equal to the market
price at date of grant. The per share weighted average fair value of stock options granted during the year ended December
31, 2005 was $8.30 based on the date of grant valuation using the Black-Scholes option pricing model with the following
assumptions: average risk-free interest rate of 3.28%, average expected life of 2.92 years and expected volatility of 28.04%.

For the year ended December 31, 2005 stock-based compensation costs included in net earnings totaled $21.3 million,
of which $10.1 million related to discontinued operations.

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

NOTE 24. DISCONTINUED OPERATIONS

A summary of discontinued operations is presented below including: disposal transactions; financial information with respect
to amounts included in the statements of earnings and statements of cash flows; significant accounting policies relating
specifically to discontinued operations; and business acquisitions included in discontinued operations.

The details of disposals of discontinued operations are as follows:

2007
In September 2007 the Trust received $3.0 million as partial settlement of an outstanding matter associated with a previous
business divestiture.

2006
In January 2007, the Trust received $21.3 million as payment of the working capital adjustment related to the 2005 disposition
of its Energy Services and International Contract Drilling divisions to Weatherford International Ltd. (“Weatherford”). This
amount had been recorded in accounts receivable at December 31, 2006 (2005 – $20.0 million).

In August 2006, the Trust received $4.8 million as settlement of the working capital adjustment arising from the 2005 disposal
of CEDA and $2.5 million as final payment of the contingent consideration associated with the 2004 disposal of United
Diamond Ltd.

In total these amounts resulted in a gain of $8.3 million ($7.1 million net of tax).

2005
On August 31, 2005, the Trust sold its Energy Services and International Contract Drilling divisions to Weatherford for proceeds
of approximately $1.13 billion cash and 26 million common shares of Weatherford, valued at $2.1 billion. In conjunction
with the Plan of Arrangement, the Trust then distributed a total of $2.9 billion of this consideration to unitholders, being
$844.3 million in cash and 25.7 million Weatherford common shares, valued at $2.0 billion which represented the fair value
of the shares at the date of distribution. Included in the statement of earnings for the year ended December 31, 2005 was
a loss on disposal of these shares of $71.0 million. In conjunction with this sale, a working capital adjustment was included
as part of the purchase and sale agreement. This adjustment was substantially settled in January 2007.

In addition on September 13, 2005 the Trust sold its industrial plant maintenance business carried on by CEDA to Borealis
Investments Inc., an investment entity of the Ontario Municipal Employees Retirement System, for proceeds of approximately
$274.0 million. Included in the CEDA proceeds was $26.8 million for the purchase of CASCA Electric Ltd. and CASCA
Tech Inc., a transaction undertaken by CEDA on July 29, 2005. A working capital adjustment relating to this disposal was
received in August 2006.

The Energy Services, International Contract Drilling and CEDA assets were included in the Energy Services, Contract Drilling
and Rental and Production segments respectively and were disposed in accordance with an extensive process undertaken
by the Trust’s Board of Directors to investigate avenues of value creation for the Trust’s unitholders.

Results of the operations of these businesses have been classified as results of discontinued operations.

P R E C I S I O N D R I L L I N G T R U S T

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

Revenue:

Energy services
International contract drilling
Industrial plant maintenance

Gain on disposal:

Gain on disposal of United Diamond
Gain on disposal of Energy services and International contract drilling
Gain on disposal of Industrial plant maintenance

Results of operations before income taxes:

Energy services
International contract drilling
Industrial plant maintenance
Other

Income tax expense

Results of operations

2007

2006

2005

–
–
–

–

–
2,956
–

2,956

–
–
–
–

–
–

–

–
–
–

–

689,319
204,987
149,371

$ 1,043,677

2,070
962
4,045

7,077

–
1,203,309
132,073

1,335,382

–
–
–
–

–
–

–

76,607
41,171
18,135
(22,298)

113,615
39,282

74,333

Net earnings of discontinued operations

2,956

7,077

$ 1,409,715

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

Net earnings of discontinued operations
Items not affecting cash:

Gain on disposal of discontinued operations
Depreciation and amortization
Stock-based compensation
Future income taxes
Unrealized foreign exchange loss on long-term monetary items

2007

2006

2005

2,956

7,077

$ 1,409,715

(2,956)
–
–
–
–

(7,077)
–
–
–
–

(1,335,382)
95,794
10,109
(1,735)
4,829

Funds provided by discontinued operations

–

183,330

Components of changes in non-cash working capital balances of discontinued operations:

Accounts receivable
Inventory
Accounts payable and accrued liabilities
Income taxes payable

2007

2006

2005

–
–
–
–

–

–
–
–
–

–

(60,912)
(23,463)
1,688
(3,623)

(86,310)

Significant accounting policies relating to discontinued operations included:

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

(a) Employee benefit plans
Employer contributions to defined contribution plans were expensed as employees earned the entitlement and contributions
were made.

The Trust accrued the cost of pensions earned by employees under its defined benefit plan, which was actuarially determined
using the projected benefit method pro-rated on services and management’s best estimate of expected plan investment
performance, salary escalation and retirement ages of employees. For the purpose of calculating the expected return on
plan assets, those assets were valued at quoted market value at the balance sheet date. The discount rate used to calculate
the interest cost on the accrued benefit obligation was the long-term market rate at the balance sheet date. Past service
costs from plan amendments were amortized on a straight-line basis over the average remaining service period of employees
active at the date of amendment (“EARSL”). The excess of the net cumulative unamortized actuarial gain or loss over 10%
of the greater of the accrued benefit obligation and the market value of plan assets was amortized over EARSL.

(b) Foreign currency translation
Accounts of the Trust’s self-sustaining operations were translated to Canadian dollars using average exchange rates for
the year for revenue and expenses. Assets and liabilities were translated at the year-end current exchange rate.

Gains or losses resulting from these translation adjustments were included in the cumulative translation account in unitholders’
equity.

Gains and losses arising on translation of long-term debt designated as a hedge of self-sustaining foreign operations were
deferred and included in the cumulative translation account in unitholders’ equity on a net of tax basis.

(c) Hedging relationships
The Trust utilized foreign currency long-term debt to hedge its exposure to changes in the carrying values of the Trust’s net
investment in certain self-sustaining foreign operations as a result of changes in foreign exchange rates.

To be accounted for as a hedge, the foreign currency long-term debt must be designated and documented as a hedge,
and must be effective at inception and on an ongoing basis. The documentation defined the relationship between the foreign
currency long-term debt and the net investment in the foreign operations, as well as the Trust’s risk management objective
and strategy for undertaking the hedging transaction. The Trust formally assessed, both at the hedge’s inception and on
an ongoing basis, whether the changes in fair value of the foreign currency long-term debt was highly effective in offsetting
changes in the fair value of the net investment in the foreign operations. If the hedging relationship was terminated or ceased
to be effective, hedge accounting was not applied to subsequent gains or losses. Any previously deferred amounts were
carried forward and recognized in earnings in the same period as the hedged item.

(d) Research and engineering
Research and engineering costs were charged to income as incurred. Costs associated with the development of new operating
tools and systems were expensed during the period unless the recovery of these costs could be reasonably assured given
the existing and anticipated future industry conditions. Upon successful completion and field testing of the tools, any deferred
costs were transferred to the related capital asset accounts.

The details of business acquisitions completed in 2005 that have been included in discontinued operations are as follows:

On July 29, 2005, the Trust completed the acquisition of all the issued and outstanding shares of CASCA Electric Ltd. and
CASCA Tech Inc. for $30.4 million. No value was assigned to intangibles or goodwill.

P R E C I S I O N D R I L L I N G T R U S T

Supplemental
Information

PD.UN

Volume

3.0

2.5

2.0

1.5

1.0

0.5

Precision Drilling Trust

SUPPLEMENTAL INFORMATION

UNIT TRADING SUMMARY – 2007

The Toronto Stock Exchange (TSX)

Unit Price (Cdn$)

Volume (millions)

$35

$30

$25

$20

$15

$10

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

The New York Stock Exchange (NYSE)

Unit Price (US$)

Volume (millions)

$30

$25

$20

$15

$10

PDS

Volume

3.0

2.5

2.0

1.5

1.0

0.5

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

S U P P L E M E N T A L I N F O R M A T I O N

Precision Drilling Trust

CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS (DEFICIT)

Years ended December 31,

(Stated in millions of Canadian dollars,
except per unit/share amounts)

Revenue

Expenses:

Operating

General and administrative

Depreciation and amortization

Foreign exchange

Reorganization costs

Operating earnings

Interest, net

Premium on redemption of bonds

Loss on disposal of

short-term investments

Other

Earnings from continuing operations

before income taxes

Income taxes

Earnings from continuing operations

Discontinued operations, net of tax

Net earnings

Retained earnings (deficit),

beginning of year

Adjustment on cash purchase of

employee stock options, net of tax

Reclassification from contributed

surplus on cash buy-out of

employee stock options

Distribution of disposal proceeds

Repurchase of common shares of

dissenting shareholders

Distributions declared

2007

2006

2005

2004

2003

1,009.2

1,437.6

1,269.2

1,028.5

915.2

516.1

56.0

78.3

2.4

–

356.4

7.4

–

349.0

6.2

342.8

3.0

345.8

688.2

81.2

73.2

(0.3)

–

595.3

8.0

–

(0.4)

587.7

15.2

572.5

7.1

579.6

641.8

76.4

71.6

(3.5)

17.5

465.4

29.3

71.9

71.0

–

293.2

72.4

220.8

1,409.8

1,630.6

566.3

64.2

74.8

(8.1)

–

331.3

46.3

–

544.2

42.7

78.1

(2.2)

–

252.4

34.0

–

(4.9)

(1.5)

289.9

101.8

188.1

59.3

247.4

219.9

75.7

144.2

36.3

180.5

(195.2)

(303.3)

1,041.7

794.3

613.8

–

(276.7)

(471.5)

(42.1)

23.2

(2,851.8)

(34.4)

(70.5)

–

Retained earnings (deficit), end of year

(126.1)

(195.2)

(303.3)

1,041.7

794.3

Earnings per unit/share from

continuing operations:

Basic
Diluted

Earnings per unit/share:

Basic

Diluted

2.73

2.75

4.56

4.62

1.79

1.76

13.22

13.00

1.63

1.61

2.14

2.11

1.33

1.31

1.66

1.63

P R E C I S I O N D R I L L I N G T R U S T

Precision Drilling Trust

ADDITIONAL SELECTED FINANCIAL INFORMATION

Years ended December 31,

(Stated in millions of Canadian dollars,
except per unit/share amounts)

Return on sales – % (1)
Return on assets – % (2)
Return on equity – % (3)
Working capital

Current ratio

PP&E and intangibles

Total assets

Long-term debt
Unitholders’ equity

Long-term debt to long-term debt

plus equity
Interest coverage (4)
Net capital expenditures from

continuing operations excluding

business acquisitions

EBITDA (5)
EBITDA – % of revenue
Operating earnings

Operating earnings – % of revenue

Cash flow from continuing operations
Cash flow from continuing operations

per unit/share

Basic

Diluted

Book value per unit/share (6)
Price earnings ratio (7)
Basic weighted average units/shares

2007

34.0

19.9

27.0

140.4

2.1

1,210.9

1,763.5

119.8

1,316.7

0.08
48.7

181.2

434.7

43.1

356.4

35.3

484.1

3.85

10.47

5.49

2006

39.8

33.6

49.4

166.5

1.81

1,108.0

1,761.2

140.9

1,217.1

0.10
74.1

233.7

668.5

46.5

595.3

41.4

609.7

4.86

9.68

5.84

2005

17.4

43.3

66.1

152.8

1.43

944.4

1,718.9

96.8

1,074.6

0.08
15.9

140.1

536.9

42.3

465.4

36.7

206.0

1.67

1.64

8.57

2.90

2004

18.3

7.3

12.3

557.3

2.47

898.1

3,852.0

718.9

2,321.7

0.24
7.2

113.9

406.1

39.5

331.3

32.2

286.4

2.48

2.44

19.10

17.6

2003

15.8

6.3

11.0

249.0

1.57

887.7

2,932.0

399.4

1,745.3

0.19
7.4

84.9

330.6

36.1

252.4

27.6

200.9

1.85

1.82

15.91

17.1

outstanding (000’s)

125,758

125,545

123,304

115,654

108,860

(1) Return on sales was calculated by dividing earnings from continuing operations by total revenues.

(2) Return on assets was calculated by dividing net earnings by quarter average total assets.

(3) Return on equity was calculated by dividing net earnings by quarter average total unitholders’ equity.

(4) Interest coverage was calculated by dividing operating earnings by net interest expense.

(5) Earnings before net interest, taxes, depreciation, amortization, non-controlling interest, premium on redemption of bonds, gain/loss on disposal of investments and discontinued

operations. EBITDA is not a recognized measure under Canadian GAAP. Management believes that in addition to net earnings, EBITDA is a useful supplemental measure

as it provides an indication of the results generated by the Trust’s principal business activities prior to consideration of how those activities are financed or how the results

are taxed in various jurisdictions and prior to the impact of depreciation and amortization. Investors should be cautioned, however, that EBITDA should not be construed

as an alternative to net earnings determined in accordance with GAAP as an indicator of Precision’s performance. Precision’s method of calculating EBITDA may differ

from other companies and, accordingly, EBITDA may not be comparable to measures used by other companies.

(6) Book value per unit/share was calculated by dividing unitholders’ equity by units/shares outstanding.

(7) Year end closing price divided by basic earnings per unit/share.

S U P P L E M E N T A L I N F O R M A T I O N

Precision Drilling Trust

UNITHOLDER INFORMATION

STOCK EXCHANGE LISTINGS

Or you can email Precision’s Transfer Agent at:

Units of Precision Drilling Trust are listed on the Toronto

service@computershare.com

Stock Exchange under the trading symbol PD.UN and

on the New York Stock Exchange under the trading

symbol PDS.

VOTING RIGHTS

Unitholders receive one vote for each Trust unit or

Precision Drilling Limited Partnership Class B limited

partnership unit held.

TRUST UNIT TRADING PROFILE

Toronto (TSX: PD.UN)

January 1, 2007 to December 31, 2007:

High: $30.93, Low: $14.82

Volume Traded: 145,535,269

New York (NYSE: PDS)

January 1, 2007 to December 31, 2007:

High: US$27.89, Low: US$14.91

Volume Traded: 174,780,109

ACCOUNT QUESTIONS

As a Precision Drilling Trust unitholder or as a holder of

Class B limited partnership units of Precision Drilling

Limited Partnership which are exchangeable on a one

for one basis with units of the Trust, you are invited to
take advantage of unitholder services or to request more
information about Precision.

Precision’s Transfer Agent can help you with a variety
of unitholder related services, including:

K Change of address

K Lost unit certificates

K Transfer of trust units to another person

K Estate settlement

You can call Precision’s Transfer Agent toll free at:
1-800-564-6253

You can write to Precision’s Transfer Agent at:
Computershare Trust Company of Canada
100 University Avenue, 9th Floor
Toronto, Ontario M5J 2Y1

Unitholders of record who receive more than one copy

of this annual report can contact Precision’s Transfer

Agent and arrange to have their accounts consolidated.

Unitholders who own Precision Drilling Trust units

through a brokerage firm can contact their broker to

request consolidation of their accounts.

QUARTERLY UPDATES

If you would like to receive interim reports but are not

a registered unitholder, please write or call Precision with

your name and address. To receive news releases by

fax, please forward your fax number to Precision.

ONLINE INFORMATION

To receive Precision’s news releases by email, or to view

this annual report online, please visit Precision’s website

at www.precisiondrilling.com and refer to the Investor

Relations section.

PUBLISHED INFORMATION

If you wish to receive copies of the 2007 Annual

Information Form as filed with the Canadian securities

commissions and as filed under Form 40-F with the

United States Securities and Exchange Commission, or

additional copies of this annual report, please contact:

Vice President, Corporate Services
and Corporate Secretary
Precision Drilling Corporation

4200, 150 – 6th Avenue SW

Calgary, Alberta, Canada T2P 3Y7

Telephone: 403-716-4500

Facsimile: 403-264-0251

ESTIMATED INTERIM RELEASE DATES

2008 First Quarter – April 24, 2008

2008 Second Quarter – July 24, 2008

2008 Third Quarter – October 23, 2008

P R E C I S I O N D R I L L I N G T R U S T

SENIOR MANAGEMENT

Doug Evasiuk

Vice President, Sales and Marketing

Grant Hunter

Vice President, USA Operations

Rolly Marks
Vice President, Operations

Ross Pickering

Vice President, Operations

Steve James
Vice President, Health, Safety and Environment

and Human Resources

Len Gambles

Chief Accounting Officer

Terry Sakamoto

Vice President, Finance, Operations

Wane Stickland

Vice President, Finance

LEAD BANK

Royal Bank of Canada

Calgary, Alberta

AUDITORS

KPMG LLP
Calgary, Alberta

TRANSFER AGENT AND REGISTRAR

Computershare Trust Company of Canada

Calgary, Alberta

TRANSFER POINT

Computershare Trust Company NA

Denver, Colorado

Precision Drilling Trust

CORPORATE INFORMATION

HEAD OFFICE

Precision Drilling Trust

4200, 150 – 6th Avenue SW

Calgary, Alberta, Canada T2P 3Y7

Telephone: 403-716-4500

Facsimile: 403-264-0251

Email: info@precisiondrilling.com

www.precisiondrilling.com

TRUSTEES

Robert J.S. Gibson

Patrick M. Murray
Allen R. Hagerman, FCA

DIRECTORS

W.C. (Mickey) Dunn

Brian A. Felesky, CM, Q.C.

Robert J.S. Gibson

Allen R. Hagerman, FCA

Stephen J.J. Letwin

Patrick M. Murray

Kevin A. Neveu

Frederick W. Pheasey

Robert L. Phillips

OFFICERS

Kevin A. Neveu

Chief Executive Officer

Gene C. Stahl

President and Chief Operating Officer

Douglas J. Strong

Chief Financial Officer

Darren J. Ruhr

Vice President, Corporate Services

and Corporate Secretary

Kenneth J. Haddad

Vice President, Business Development

C O R P O R A T E I N F O R M A T I O N

TSX

PD.UN

NYSE

PDS

Precision Drilling Trust www.precisiondrilling.com