Annual Report
Precision Drilling
Corporation
2013
What’s Inside
6
About Precision
10
2013 Highlights and Outlook
14
Understanding our Business Drivers
The Energy Industry
A Competitive Operating Model
An Effective Strategy
Risks to our Business
26
2013 Results
36
Financial Condition
41
Accounting Policies and Estimates
44
Evaluation of Disclosure
Controls and Procedures
45
Corporate Governance
46
Consolidated Financial
Statements and Notes
86
Supplemental Information
88
Shareholder Information
89
Corporate Information
Management’s
Discussion and Analysis
Consolidated
Financial
Statements and Notes
Precision
Precision
Drilling
Corporation
2013
2013 SHARE TRADING SUMMARY
The Toronto Stock Exchange (TSX)
P D
Volume (millions)
Share Price (Cdn$)
(1)
10
$15
$12
$9
$6
$3
)
$
n
d
C
(
e
c
i
r
P
e
r
a
h
S
0
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
(1)
On December 5, 2013, Precision’s then largest shareholder sold its entire equity position in the Corporation, approximately 56 million shares which contributed to a total volume
of 74 million shares traded that day.
Toronto (TSX: PD)
High: $11.53 Low: $7.47 Close: $9.94 Volume Traded: 297,457,268
The New York Stock Exchange (NYSE)
P DS
Volume (millions)
Share Price (US$)
$15
$12
$9
$6
$3
)
$
S
U
(
e
c
i
r
P
e
r
a
h
S
0
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
New York (NYSE: PDS)
High: US$11.21 Low: US$7.29 Close: US$9.37 Volume Traded: 288,801,100
)
s
n
o
i
l
l
i
m
(
e
m
u
o
V
l
)
s
n
o
i
l
l
i
m
(
e
m
u
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V
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8
6
4
2
0
10
8
6
4
2
0
Precision Drilling Corporation 2013 Annual Report
1
Management’s
Discussion and
Analysis
MD&A
Precision
Drilling
Corporation
2013
This management’s discussion and analysis
(MD&A) contains information to help you
understand our business and financial
performance. Information is as of March 7, 2014.
This MD&A focuses on our consolidated financial
statements and includes a discussion of known
risks and uncertainties relating to the oilfield
services sector. It does not, however, cover the
potential effects of general economic, political,
governmental and environmental events, or other
events that could affect us in the future.
You should read this MD&A with the
accompanying audited consolidated financial
statements and notes, which have been prepared
in accordance with International Financial
Reporting Standards (IFRS) and with the
information in About Forward-Looking Information
on page 3. We adopted IFRS effective January 1,
2011, and restated our 2010 results at that time.
Results for 2009 and prior years were prepared
in accordance with previous Canadian generally
accepted accounting principles (previous
Canadian GAAP).
The terms we, us, our, the Corporation and
Precision mean Precision Drilling Corporation
and our consolidated subsidiaries, and include
any partnerships that we and/or our subsidiaries
are part of.
All amounts are in Canadian dollars unless
otherwise stated.
2 Management’s Discussion and Analysis
ABOUT FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help current and prospective investors understand our future prospects. This
MD&A contains statements about what we believe, intend and expect about developments, results and events that may or
will occur in the future and are forward-looking within the meaning of Canadian securities legislation and the safe harbor
provisions of the United States (U.S.) Private Securities Litigation Reform Act of 1995 (collectively, the forward-looking
information and statements).
Forward-looking information and statements are often, but not always, identified by the use of words and phrases such as
“anticipate”, “could”, “should”, “can”, “expect”, “seek”, “may”, “intend”, “likely”, “will”, “plan”, “estimate”, “believe” and
other similar expressions. In particular, this MD&A includes statements about the following:
our strategic priorities
our new-build and upgradable rigs giving us favourable positioning in the market for premium drilling rigs
continuing improvements in unconventional drilling and completion techniques, allowing customers to realize
favourable economics and drive additional investment capital towards oil and liquids-rich natural gas plays
our capital expenditure plans in 2014 including the amount of funds allocated for expansion capital, rig upgrade
capital and sustaining and infrastructure expenditures
growth opportunities for our Contract Drilling Services land drilling rig fleet both in North America and internationally,
including potential for additional rigs going to work in Mexico, two new-builds being delivered to Kuwait in the
second quarter and rig additions to our Middle East fleet
the completion and production work associated with unconventional oil and natural gas plays providing the most
profitable growth opportunities for our Completion and Production Services segment
the additional supply of drilling rigs potentially intensifying price competition and possibly leading to lower rates in
the oilfield services industry generally and lower utilization of our existing rigs
cost increases, delays in delivery due to the strong activity or financial hardship of our suppliers or contractors, or
other unforeseen circumstances relating to third parties
the outcome from the tax reassessment proceedings in Ontario involving one of our subsidiaries
our expectations regarding our ability to comply with our financial ratio covenants.
The forward-looking information and statements in this MD&A are based on certain factors and assumptions made by us
in light of our experience and our perception of historical trends, current conditions and expected future developments as
well as other factors we believe are appropriate in the circumstances. These include, among other things:
our expectations regarding our customers’ capital budgets and geographical areas of focus
the status of current negotiations with our customers
the demand drivers for natural gas including growing potential of LNG export development
the economic viability of unconventional oil and gas projects in North America
the advantages of our premium rigs in respect of drilling in unconventional oil and natural gas plays
our ability to obtain qualified personnel, equipment and services in a timely and cost-efficient manner
our ability to operate our business in a safe, efficient and effective manner
our ability to obtain capital financing
the ‘retooling’ of the industry-wide fleet having made Tier 3 rigs obsolete in North America
potential customers’ focus on pricing, rig availability and other considerations when selecting a drilling contractor
unconventional drilling being the primary opportunity in the North American marketplace and the suitability of our
Tier 1 rigs for drilling wells in unconventional oil and natural gas plays
new or newer rigs continuing to enter markets where we operate
the inherently challenging cyclical natures of the energy services business
the general stability of the economic and political environment in the places where we operate
our knowledge and understanding of applicable tax legislation and court proceedings.
Precision Drilling Corporation 2013 Annual Report
3
Since forward-looking information and statements address future events and conditions, by their very nature they involve
inherent risks and uncertainties. Actual results may differ materially from those currently anticipated or implied by such
forward-looking information and statements due to a number of factors and risks including the following:
volatility in the price and demand for oil and natural gas
delays or changes in plans with respect to our customers’ exploration or production projects or capital expenditures
liquidity of the capital markets to fund our customers’ drilling programs
the availability of cash flow, debt and equity sources to fund our capital and operating requirements, as needed
the impact of weather and seasonal conditions on our operations and facilities
changes in rig technology and our ability to integrate such technologies on a timely and cost-effective basis
general economic, market or business conditions
changes in tax, health and safety and environmental legislation including potentially more stringent regulation or
restriction of hydraulic fracturing
the availability of qualified personnel, management or other key inputs
a decline in our safety performance possibly resulting in lower demand for our services
fluctuations in foreign exchange, interest rates and tax rates
operating in foreign countries
uncertainty in judicial decision-making and proceedings
other unforeseen conditions that could affect the use of our services
other risks and uncertainties set out in this MD&A under the heading Risks to our Business.
You are cautioned that the foregoing list of assumptions, risks and uncertainties is not exhaustive. Additional information
on these and other factors that could affect our business, operations or financial results are also discussed in our annual
information form (AIF) on file with the Canadian securities commissions on SEDAR (www.sedar.com) and with the U.S.
Securities and Exchange Commission on EDGAR (www.sec.gov). Our AIF may also be accessed from our corporate
website (www.precisiondrilling.com).
The forward-looking information and statements contained in this MD&A are made as of the date hereof and Precision
undertakes no obligation to update publicly or revise this forward-looking information as a result of new information, future
events or otherwise, unless we are required to do so by law.
4 Management’s Discussion and Analysis
ADDITIONAL GAAP MEASURES
In this MD&A, we reference additional GAAP measures that are not defined terms under IFRS to assess performance
because we believe they provide useful supplemental information to investors.
Adjusted EBITDA
We believe that Adjusted EBITDA (earnings before income taxes, finance charges, foreign exchange, impairment of
goodwill, loss on asset decommissioning, and depreciation and amortization), as reported in the Consolidated Statement
of Earnings, is a useful supplemental measure because it gives us, and our investors, an indication of the results from our
principal business activities before consideration of how our activities are financed and excluding the impact of foreign
exchange, taxation, non-cash depreciation and amortization charges, and non-cash decommissioning charges.
Operating Earnings
We believe that operating earnings, as reported in the Consolidated Statement of Earnings, is a useful measure of our
income because it gives us, and our investors, an indication of the results of our principal business activities before
consideration of how our activities are financed and excluding the impact of foreign exchange and taxation.
Funds Provided by Operations
We believe that funds provided by operations, as reported in the Consolidated Statement of Cash Flow, is a useful measure
because it gives us, and our investors, an indication of the funds our principal business activities generated prior to
consideration of working capital, which is primarily made up of highly liquid balances.
Precision Drilling Corporation 2013 Annual Report
5
About Precision
Management’s
Discussion and
Analysis
1
Precision Drilling Corporation provides onshore drilling, completion and production services to exploration and production
companies in the oil and natural gas industry.
Headquartered in Calgary, Alberta, Canada, we are Canada’s largest oilfield services company and one of the largest in
the U.S. We also have operations in Mexico and the Middle East.
Our shares trade on the Toronto Stock Exchange, under the symbol PD, and on the New York Stock Exchange, under the
symbol PDS.
Strength and Flexibility
From our founding as a private drilling contractor in the 1950s, Precision Drilling has grown to become one of the most
active drillers in North America.
our High Performance, High Value operating model drives efficiency and quality of service
size and scale provide higher margins and better service capabilities
liquidity allows us to take advantage of business cycle opportunities
capital structure provides long-term stability and flexibility
Vision
Our vision is to be recognized as the High Performance, High Value provider of services for global energy exploration
and development.
Strategic Priorities
1. Execute our High Performance, High Value strategy – Invest in Precision’s physical and human capital infrastructure
to advance field level professional development, provide industry leading service to customers and promote safe
operations. Continue to measure and benchmark performance with a view to exceeding the high standards we set.
2. Leverage our scale in operations – Utilize established systems to promote consistent and reliable service and to
improve operating efficiencies across all geographies and service lines.
3. Execute on existing organic growth opportunities – Deliver new-build and upgraded rigs to customer contracts,
expand international activity in existing operating regions and grow our Canadian LNG drilling leadership position.
Be a recognized leader in the integrated directional drilling transformation.
4. Increase returns for our investors.
6 Management’s Discussion and Analysis
Two Business Segments
We operate our business in two segments, supported by vertically integrated business support systems.
Precision Drilling Corporation
Completion and Production Services
(cid:127) Canada and U.S.
– Service rigs, snubbing and coil tubing
– Equipment rentals
– Camps, catering and water systems
Contract Drilling Services
(cid:127) Drilling rig operations
– Canada
– U.S.
– International
(cid:127) Directional drilling operations
– Canada
– U.S.
Business support systems
(cid:127) Sales and
marketing
(cid:127) Procurement
and distribution
(cid:127) Manufacturing
(cid:127) Equipment
maintenance
and certification
(cid:127) Engineering
Corporate support
(cid:127) Governance
(cid:127) Information
systems
(cid:127) Health, safety
and environment
(cid:127) Human
resources
(cid:127) Finance
(cid:127) Enterprise risk
management
2013 Adjusted EBITDA by Operating Segment
2013 Revenue by Region
Contract
Drilling
Services
91%
Completion
and Production
Services
9%
International
7%
Canada
49%
U.S.
44%
Precision Drilling Corporation 2013 Annual Report
7
CONTRACT DRILLING SERVICES
We provide onshore drilling services to exploration and production companies in the oil and natural gas industry, operating
in the U.S., Canada and internationally.
We are the second largest land drilling contractor in North America, servicing approximately 23% of the active land drilling
market in Canada and 5% of the active U.S. land drilling market. We also have an international presence with operations
in Mexico and the Middle East.
At December 31, 2013, our Contract Drilling Services segment consisted of:
327 land drilling rigs, including:
– 187 in Canada
– 127 in the U.S.
– 8 in Mexico
– 3 in Saudi Arabia
– 2 in the Kurdistan region of northern Iraq
capacity for approximately 88 concurrent directional drilling jobs in Canada and the U.S.
engineering, manufacturing and repair services primarily for Precision’s operations
centralized procurement, inventory and distribution of consumable supplies primarily for our Canadian, U.S. and
Mexican operations.
Drilling Rigs at December 31, 2013
Horsepower
Tier 1
Tier 2
PSST
Total
< 1000
1000-1500
>1500
96
63
15
174
101
21
4
126
3
19
5
27
Geographic location
Canada
U.S.
International
Tier 1
Tier 2
PSST
Total
110
62
15
187
87
31
9
127
3
10
–
13
Total
200
103
24
327
Total
200
103
24
327
Contract Drilling
Revenue
Contract Drilling
Adjusted EBITDA
$ Millions
$2,000
$1,500
$1,000
$500
0
$ Millions
$800
$600
$400
$200
0
Contract Drilling
Utilization Days
Utilization Days
80,000
60,000
40,000
20,000
0
2009 2010
2011
2012
2013
2009 2010
2011
2012
2013
2009 2010
2011
2012
2013
Note: 2009 was prepared under previous Canadian
generally accepted accounting principles
8 Management’s Discussion and Analysis
COMPLETION AND PRODUCTION SERVICES
We provide completion and workover services and ancillary services and equipment rentals to oil and natural gas
exploration and production companies primarily in Canada, with a growing presence in the U.S.
Service rigs and snubbing units each serve about 18% of the market for these services in Canada.
At December 31, 2013, our Completion and Production Services segment consisted of:
191 well completion and workover service rigs, including:
– 184 in Canada
– 7 in the U.S.
19 snubbing units, including:
– 17 in Canada
– 2 in the U.S.
12 coil tubing units, including:
– 4 in Canada
– 8 in the U.S.
approximately 3,800 oilfield rental items including surface storage, small-flow wastewater treatment, power generation,
and solids control equipment primarily in Canada
235 wellsite accommodation units in Canada and 67 in the U.S.
50 drilling camps and three base camps in Canada and two drilling camps and one base camp in the U.S.
10 large-flow wastewater treatment units, 24 pump houses and seven potable water production units in Canada.
Well Servicing Fleet as at December 31
Type of Service Rig
Singles:
Freestanding mobile
Doubles:
Mobile
Freestanding mobile
Skid
Slants:
Freestanding
Total service rigs
Snubbing units
Coil tubing units
Total service rigs, snubbing units
and coil tubing units
Horsepower
2009
2010
2011
2012
2013
150-400
250-550
200-550
300-860
250-400
94
28
30
30
18
200
20
–
220
94
25
35
28
18
200
20
–
220
90
19
40
22
18
189
18
–
207
90
19
40
22
19
190
19
5
214
90
19
40
22
20
191
19
12
222
Completion and Production
Revenue
Completion and Production
Adjusted EBITDA
Completion and Production
Service Rig Hours
$ Millions
$400
$300
$200
$100
0
$ Millions
$125
$100
$75
$50
$25
0
Hours
400,000
300,000
200,000
100,000
0
2009 2010
2011
2012
2013
2009 2010
2011
2012
2013
2009 2010
2011
2012
2013
Note: 2009 was prepared under previous Canadian
generally accepted accounting principles
Precision Drilling Corporation 2013 Annual Report
9
2013 Highlights and Outlook
Management’s
Discussion and
Analysis
2
Adjusted EBITDA and funds provided by operations are additional GAAP measures. See page 5 for more information.
Financial Highlights
Year ended December 31
(thousands of dollars, except where noted)
% increase/
2013
(decrease)
2012
% increase/
(decrease)
2,029,977
638,833
31.5%
191,150
428,086
461,973
282,145
141,132
112,527
(13,372)
522,432
(0.5)
(4.8)
265.1
(32.6)
(22.9)
(52.7)
8.5
(20.6)
(57.4)
(37.6)
2,040,741
670,792
32.9%
52,360
635,286
598,812
596,194
130,094
141,769
(31,423)
836,634
4.6
(3.5)
(72.9)
19.2
1.1
30.9
(13.2)
16.9
96.6
17.8
–
(100.0)
25
(100.0)
92,886
0.69
0.66
0.21
263.2
266.7
320.0
0.19
0.18
0.05
(72.9)
(73.1)
n/m
0.70
0.67
–
2011
1,951,027
695,064
35.6%
193,477
532,772
592,388
455,302
149,811
121,244
(15,983)
710,374
% increase/
(decrease)
36.5
59.8
344.4
74.0
46.6
539.7
174.0
142.3
30.4
334.1
n/m
337.5
346.7
–
% increase/
2013
(decrease)
327
1.9
30,530
30,268
3,555
222
283,576
(5.6)
(12.5)
70.4
3.7
(3.8)
2012
321
32,352
34,597
2,086
214
294,681
% increase/
(decrease)
(4.7)
(14.8)
(8.7)
197.2
3.4
(7.2)
2011
337
37,970
37,887
702
207
317,418
% increase/
(decrease)
(5.1)
21.8
16.8
16.6
(5.9)
7.9
Revenue
Adjusted EBITDA
Adjusted EBITDA % of revenue
Net earnings
Cash provided by operations
Funds provided by operations
Investing activities
Capital spending
Expansion
Upgrade
Maintenance and infrastructure
Proceeds on sale
Net capital spending
Business acquisitions (net of cash
acquired)
Earnings per share ($)
Basic
Diluted
Dividends per share ($)
n/m – calculation not meaningful.
Operating Highlights
Year ended December 31
Contract drilling rig fleet
Drilling rig utilization days
Canada
U.S.
International
Service rig fleet
Service rig operating hours
10 Management’s Discussion and Analysis
Financial Position and Ratios
Year ended December 31
(thousands of dollars, except ratios)
Working capital
Working capital ratio
Long-term debt
Total long-term financial liabilities
Total assets
Enterprise value1
Long-term debt to long-term debt plus equity
Long-term debt to cash provided by operations
Long-term debt to enterprise value
2013
305,783
1.9
1,323,268
1,355,535
4,579,123
3,919,763
0.36
3.09
0.34
2012
278,021
1.7
1,218,796
1,245,290
4,300,263
3,213,406
0.36
1.92
0.38
2011
610,429
2.4
1,239,616
1,267,040
4,427,874
3,528,046
0.37
2.33
0.35
1 Share price multiplied by the number of shares outstanding plus long-term debt minus working capital. See page 40 for more information.
2013 OVERVIEW
Net earnings in 2013 were $191 million, or $0.66 per diluted share, compared to $52 million or $0.18 per diluted share in
2012. The 2012 results include the impact of charges associated with asset decommissioning and an impairment charge
to the goodwill attributable to our Canadian directional drilling operations.
Revenue in 2013 was $2,030 million, 1% lower than 2012, mainly due to lower utilization days in North America, although
this loss was partially offset by improved drilling rig revenue per day in both Canada and the United States and growth in
international operations. Contract Drilling Services revenue was down less than 1%, while revenue from Completion and
Production Services was down 1%. Our international drilling activity increased 70% with an average of 10 rigs working in
2013 compared to six in 2012.
Adjusted EBITDA in 2013 was $639 million, 5% lower than 2012. Our adjusted EBITDA margin was 31%, compared to
33% in 2012. The decrease in adjusted EBITDA margin was mainly the result of reduced margin in the Completion and
Production Services segment. Lower activity, costs associated with starting up in the United States and fixed costs all
contributed to lower margin in our Completion and Production Services segment. EBITDA margin for the year in our
Contract Drilling Services segment was 38%, in line with the prior year. Our portfolio of term customer contracts, a scalable
operating cost structure, and economies achieved through vertical integration of the supply chain all help us manage our
adjusted EBITDA margin.
North American industry activity was down from the prior year as a result of volatile oil and natural gas prices, oil
transportation bottlenecks resulting in regional oil price discounts, record inventory levels resulting in depressed natural
gas prices, and general global economic uncertainty persisting for much of the year.
In the fourth quarter of 2013, we increased our quarterly dividend to $0.06 per common share.
Outlook
Contracts
Our strong portfolio of term customer contracts provides a base level of activity and revenue and, as of March 7, 2014,
we had term contracts in place for an average of 101 rigs: 51 in Canada, 43 in the United States and seven internationally
for 2014. In Canada, term contracted rigs normally generate 250 utilization days per rig year because of the seasonal
nature of wellsite access. In most regions in the United States and internationally, term contracts normally generate 365
utilization days per rig year. In 2013, approximately 58% of our total contract drilling revenue was generated from rigs under
term contract.
Pricing, Demand and Utilization
The demand for energy has been rising with the improvement in the global economic situation, and per capita energy
consumption has increased in many countries. These demand fundamentals, along with the challenges of maintaining or
growing global supply, have supported stronger oil prices since 2009.
Precision Drilling Corporation 2013 Annual Report 11
Natural gas prices, however, have been depressed, reaching 10-year lows in 2012 before recovering slightly in 2013 to
average US$3.73 per MMBtu at Henry Hub. Lower natural gas prices have persisted due to increased production from
unconventional resource development, higher than average storage levels, and the lack of an export market from North
America. Despite the industry-wide decline in natural gas drilling activity, production remained stable and kept prices low.
Natural gas demand largely depends on the weather. Moderate North American winter temperatures in 2011 and 2012
hampered overall demand, but colder weather at the end of 2013 resulted in near-term reduction of inventories and caused
spot prices to rise. Other demand drivers, however, such as natural gas fired power generation, industrial applications
and transport, have shown positive growth over the past several years driven by a preference for natural gas over coal,
favourable regulation and lower prices. As well, the growing potential of liquefied natural gas (LNG) export development in
both Canada and the U.S. could serve as a catalyst for natural gas directed drilling activity over the medium to long term.
Industry wide, drilling utilization has declined year-over-year in North America; however, demand for higher specification
Tier 1 drilling assets has remained strong, supporting improved dayrates charged to customers. We have deployed 69
new-build Tier 1 Super Series drilling rigs since the beginning of 2010. As at March 7, 2014 we had a total fleet of 203 Tier 1
drilling rigs, and we have additional upgradable rigs within our fleet, which we believe favourably positions us in the market
for premium drilling rigs.
The oil rig count at March 7, 2014 was 8% higher in the U.S. than it was a year ago, and 14% lower in Canada. The overall
North American land oil directed rig count on March 7, 2014 was more than five times higher than it was on March 6,
2009, supported by unconventional oil and liquids-rich natural gas drilling in plays such as Bakken, Cardium, Montney,
Duvernay, Eagle Ford, Granite Wash, Niobrara and Permian. As exploration and production companies continue to improve
unconventional oil drilling and completion techniques, we expect that the favourable economics that our customers realize
will drive additional investment capital toward these unconventional plays, supporting continued drilling activity, and
especially demand for Tier 1 rigs.
International
We currently have 13 rigs in international locations, in Mexico and the Middle East, and expect our active rig count to grow
over the next two quarters as two new-build drilling rigs on long-term contract for the Kuwait market are delivered in the
second quarter. Additionally, we see potential for additional rigs going to work in Mexico in 2014 and potential rig additions
to our Middle East fleet.
Upgrading the Fleet
We and some of our competitors have been upgrading the drilling rig fleet by building new rigs and upgrading existing
rigs. We believe this ‘retooling’ of the industry-wide fleet has made Tier 3 rigs virtually obsolete in North America. In the
fourth quarter of 2012, we decommissioned 42 Tier 3 rigs and 10 Tier 2 rigs from our fleet, exiting the Tier 3 contract drilling
business. Our focus on the Tier 1 and Tier 2 market is aligned with our corporate strategy, customer relationships and
competitive position.
Capital Spending
We expect capital spending in 2014 to be approximately $582 million ($545 million in the Contract Drilling Services segment
and $37 million in the Completion and Production Services segment):
$268 million for expansion capital, which includes:
– six new-build rigs for the Canadian market and two for the U.S.
– one new-build rig that will only be completed once a firm customer contract is secured
– the costs to complete two new-build rigs going to Kuwait
– new equipment in our Completion and Production Services segment and
– long-lead items.
$119 million for upgrade capital for 15 to 19 upgrades, four of which represent the completion of the 2013 rig
upgrade program
$195 million for sustaining and infrastructure expenditures, which is based on currently anticipated activity levels, and
includes the cost to consolidate and upgrade our operations facility in Nisku, Alberta. The Nisku facility will support Canadian
operations for several decades. The portion of the 2014 budget allocated to this facility is approximately $30 million.
12 Management’s Discussion and Analysis
i
%
n
g
r
a
M
50
40
30
20
10
0
2009
2010
2011
2012
2013
Revenue and
Adjusted EBITDA
Adjusted EBITDA Margin
Adjusted EBITDA
Revenue
Source: Precision Drilling
Funds From Operations
Note: 2009 was prepared under
previous Canadian GAAP
2,500
2,000
s
n
o
i
l
l
i
m
$
1,500
1,000
500
0
700
600
500
400
300
200
100
0
s
n
o
i
l
l
i
M
$
Source: Precision Drilling
2009
2010
2011
2012
2013
Drilling Utilization Days
80,000
60,000
s
y
a
D
40,000
20,000
0
International
USA
Canada
Source: Precision Drilling
2009
2010
2011
2012
2013
Precision Drilling Corporation 2013 Annual Report 13
Understanding our Business Drivers
Management’s
Discussion and
Analysis
3
THE ENERGY INDUSTRY
Precision operates in the energy services business, which is an inherently challenging cyclical industry. Customer demand
depends on the end price for their products: crude oil, natural gas, and natural gas liquids.
We depend on oil and natural gas exploration and production companies to contract our services as part of their
development activities. The economics of their business are dictated by the current and expected future margin between
their finding and development costs and the eventual market price for the commodities they produce.
Commodity Prices
Our customers’ cash flow to fund exploration and development is dependent on commodity prices: higher prices increase
cash flow and funding.
Oil can be transported relatively easily, so it is generally priced in a global market that is influenced by an array of economic
and political factors. Oil prices moved lower during the economic crisis of 2008, but have increased since the beginning of
2009 as supply and demand fundamentals have tightened.
Natural gas and natural gas liquids continue to be priced regionally. In 2013, natural gas prices remained at depressed
levels for most of the year as supplies of unconventional natural gas, particularly in North America, are keeping markets
well supplied. The onset of colder weather late in 2013 and early 2014 increased demand for natural gas and caused
spot prices to rise at the beginning of 2014. Overall, natural gas prices remain depressed compared to oil, supporting the
projected growth in worldwide natural gas consumption.
160
140
120
100
80
60
40
20
0
l
e
r
r
a
b
/
$
S
U
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
WTI Oil Prices and
Henry Hub Natural
Gas Prices
Henry Hub Natural Gas Prices
West Texas Intermediate (“WTI”)
Oil Prices
Source: Precision Drilling
16
14
12
10
8
6
4
2
t
u
B
M
M
/
$
S
U
0
Jan-09
14 Management’s Discussion and Analysis
New Technology
Technological advancements in fracturing, stimulation and horizontal drilling have brought about a shift in development
from conventional to unconventional natural gas and oil reservoirs. This is giving companies cost-effective access to more
complex wells in North America, in existing basins and in new basins that haven’t been economic in the past.
The following chart shows the consistent trend away from vertical wells to more demanding directional/horizontal well
programs, which require higher capacity equipment and greater technical expertise for drilling. These trends are driving the
demand for high performing drilling rigs, which garner premium contract rates.
Rigs Drilling
Directional/Horizontal
Wells in Canada
Precision’s capabilities are
demonstrated by the high
proportion of rigs drilling
complex wells.
Precision Canada Active Land Rigs
Canada Industry Excluding Precision
Source: Whelby Data
100
90
80
70
60
50
40
30
20
10
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Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
These technical innovations have been a major factor in the increase in natural gas production in the U.S., which is
becoming less reliant on Canada as a source of natural gas. Natural gas production in Canada has been declining
because of lower natural gas directed drilling due to pricing pressure and Canada’s lack of an export market other than
the U.S.
U.S. Lower 48 Production
80
70
60
50
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U.S. Lower 48 Natural Gas Production
U.S. Crude Oil Production
Source: Energy Information Administration
40
Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
8
7
6
5
4
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Precision Drilling Corporation 2013 Annual Report 15
Canadian Production
18
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a
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t
16
14
Canadian Natural Gas Production
Canadian Crude Oil Production
Source: Energy Information Administration
and First Energy Capital
12
Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
4.0
3.0
2.0
1.0
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Drilling Activity
The graphs below show that, since 2010, drilling activity in the U.S. and Canada has been shifting from natural gas to oil.
The Canadian drilling rig activity graph also shows how Canadian drilling activity fluctuates with the seasons, a market
dynamic that in general is not present in the U.S.
U.S. Drilling Rig Activity
1,600
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k
r
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W
s
g
R
i
1,200
800
400
0
Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
Natural Gas Rigs
Crude Oil Rigs
Source: Baker Hughes, Inc.
Canadian Drilling Rig Activity
600
i
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n
k
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s
g
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i
400
200
0
Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
Natural Gas Rigs
Crude Oil Rigs
Source: Baker Hughes, Inc.
16 Management’s Discussion and Analysis
A COMPETITIVE OPERATING MODEL
The contract drilling business is highly competitive, with numerous industry participants. We compete for long-term drilling
contracts that are often awarded based on a competitive bid process.
We believe potential customers focus on pricing and rig availability when selecting a drilling contractor, but also consider
many other things, including drilling capabilities and condition of rigs, quality of rig crews, breadth of service, safety record
and adaptability, among others.
Providing High Performance, High Value services to our customers is the core of our competitive strategy. We deliver
High Performance by employing passionate people supported by superior systems and equipment designed to maximize
productivity and reduce risks. We create High Value by operating safely, lowering customer risks and costs, developing
people, generating financial growth, and attracting investment.
Operating Efficiency
We keep customer well costs down by maximizing the efficiency of operations in several ways:
using innovative and advanced drilling technology that’s efficient and reduces costs
having equipment that’s geographically dispersed, reliable and well maintained
monitoring and maintaining our equipment to minimize mechanical downtime
effectively managing operations to keep non-productive time to a minimum
compensating our executive and eligible employees based on performance against safety, operational, employee
retention and financial measures.
Efficient, Cost-Reducing Technology
We focus on providing efficient, cost-reducing drilling technology. Design innovations and technology improvements, such
as multi-well pad capability and mobility between wells, capture incremental time savings during the drilling process.
The versatile Precision Super Single design features technical innovations in safety and drilling efficiency for drilling slant
or directional wells on single or multiple well pad locations in shallow to medium depth well applications. Precision Super
Single rigs use extended length tubulars, an 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.
Triple rigs have greater hoisting capacity and are used in deeper exploration and development drilling. Our Super Triple
electric rigs (ST-1200, ST-1500 and ST-3000) are designed 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, while a computerized
electronic auto driller feature precisely controls weight, rotation and torque on the drill bit. These rigs use extended length
drill pipe and have an integrated top drive, automated pipe handling with iron roughnecks, and automated control.
Broad Geographic Footprint
Geographic proximity and fleet versatility make us a comprehensive provider of High Performance, High Value services
to our customers. Our large diverse fleet of rigs is strategically deployed across the most active drilling regions in North
America, including all the major unconventional oil and natural gas basins.
Managing Downtime
Reliable and well-maintained equipment minimizes downtime and non-productive time during operations.
We manage mechanical downtime through preventative maintenance programs, detailed inspection processes, an
extensive fleet of strategically located spare equipment, and an in-house supply chain.
We minimize non-productive time (move, rig-up and rig-out time) by utilizing walking and skidding systems, reducing
the number of move loads per rig, having lighter move loads, and using mechanized equipment for safer and quicker rig
component connections.
Precision Drilling Corporation 2013 Annual Report 17
Tracking Our Results
We unitize key financial information per day and per hour, and compare these measures to established benchmarks and
past performance. We evaluate the relative strength of our financial position by monitoring our working capital, debt ratios,
and returns on capital employed. We track industry rig utilization statistics to evaluate our performance against competitors.
We link incentive compensation for our senior team to returns generated compared to established benchmarks.
We reward executives and eligible employees through incentive compensation plans for performance against the
following measures:
Safety performance – total recordable incident frequency per 200,000 man-hours. Measured against prior year
performance and current year industry performance in Canada and the U.S.
Operational performance – rig down time for repair as measured by time not billed to the customer. Measured
against predetermined target of available billable time.
Key field employee retention – senior field employee retention rates. Measured against predetermined target of retention.
Financial performance – return on capital employed calculated as a percentage of pre-tax operating earnings divided
by total assets less current liabilities. Measured against predetermined target percentage.
Investment returns – total shareholder return performance against an industry peer group, including dividends, over
a three year period. Measured against predetermined competitors in the established peer group.
Top Tier Service
We pride ourselves on providing quality equipment operated by experienced and well trained crews. We also strive to align
our capabilities with evolving technical requirements associated with more complex well bore programs.
High Performance Rig Fleet
Our fleet of drilling rigs is well positioned to address the unconventional drilling programs of our customers. The vast majority
of our drilling rigs have been designed or significantly upgraded to drill horizontal wells. With a breadth of horsepower
types and drilling depth capabilities, our large fleet can address every type of onshore unconventional oil and natural gas
drilling in North America.
In 2013, we high-graded our drilling rig fleet by:
adding seven Tier 1 new-build drilling rigs
upgrading 19 drilling rigs – about a quarter of these were Tier upgrades.
As at December 31, 2013, 93% of our 327 drilling rigs were Tier 1 or Tier 2 rigs.
Tier 1 – 200 drilling rigs
Rigs are better suited to meet the
challenges of complex customer
requirements for resource
exploitation in North American
shale and unconventional plays
High performance Super Series rigs, innovative in design, capable of drilling directionally or horizontally,
highly mobile (move with pad walking or skidding systems or require fewer trucking loads)
Features
highly mechanized tubular handling equipment
integrated top drive or top drive adaptability
advanced AC, silicone controlled rectifier (SCR) and mechanical power distribution and control efficiencies
electronic or hydraulic control of the majority of operating parameters
specialized drilling tubulars
high-capacity mud pumps
majority use Range III drill pipe
Tier 2 – 103 drilling rigs
High performance rigs, capable of drilling directionally or horizontally, generally less mobile than Tier 1 rigs
High performance rigs with new
equipment and modifications
to improve performance and
enhance directional and
horizontal drilling capability
PSST (Precision seasonal,
stratigraphic and turnkey)
– 24 drilling rigs
Typically, conventional mechanical
rigs with no automation and lower
pumping capacity
Features
some mechanization of tubular handling equipment
top drive adaptability
SCR or mechanical type power systems
increased hookload and or racking capabilities
upgraded power generating, control systems and other major components
high-capacity mud pumps
Acceptable level of performance for certain drilling requirements but would require major equipment
upgrades to meet the criteria of a Tier 2 or Tier 1 rig
Other than 24 rigs retained for seasonal, stratification and turnkey drilling work, we have exited the Tier 3
market. We believe that developments in the land drilling industry have made the Tier 3 rigs virtually
obsolete in North America.
18 Management’s Discussion and Analysis
Our service rigs provide completion, workover, abandonment, well maintenance, high pressure operations and critical sour
gas well work, and well re-entry preparation across the Western Canada Sedimentary Basin, Texas and the northern U.S.
Service rigs are supported by three field locations in Alberta, two in Saskatchewan, and one in each of Manitoba, British
Columbia, North Dakota, Texas, and Pennsylvania.
Snubbing units complement traditional natural gas well servicing by allowing customers to work on wells while they are
pressurized and production has been suspended. We have two kinds 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.
Coil tubing units have the ability to service horizontal wells by pushing the tubing rather than relying on gravity. Coil tubing
often works more effectively in the unconventional horizontal wells that are becoming more common. We began using our
first coil tubing unit in the first quarter of 2012 and by the end of 2013 we had 12 units operating.
Ancillary Equipment and Services
An inventory of equipment (portable top drives, loaders, boilers, tubulars and well control equipment) supports our
fleet of drilling and service rigs. We also maintain an inventory of key rig components to minimize downtime due to
equipment failure.
We benefit 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 in Canada and
Precision Supply in the U.S.
Precision Rentals supplies customers with an inventory of specialized equipment and wellsite accommodations. Precision
Camp Services supplies meals and provides accommodation for crews at remote oilfield worksites. Terra Water Systems
plays an essential role in providing water treatment services as well as potable water production plants for Precision Camp
Services and other camp facilities.
Systematic Maintenance
We consistently reinvest capital to sustain existing property, plant and equipment. Also we match equipment repair and
maintenance expenses to activity levels under our maintenance and certification programs.
We use computer systems to track key preventative maintenance indicators for major rig components, record equipment
performance history, schedule equipment certifications, reduce downtime, and better manage our assets.
We have a continuous maintenance program for essential elements, such as tubulars and engines.
Upgrade Opportunities
We leverage our internal manufacturing and repair capabilities and inventory of quality rigs to address market demand
through upgraded drilling and service rigs. For drilling rigs, the upgrade is typically performed at the request of a customer
and includes a term contract. The upgrade may result in a change in tier classification.
People
Having an experienced, high performance crew is a competitive strength and highly valued by our customers. There
are often shortages of industry manpower in peak operating periods. We rely heavily on our safety record, investment
in employee development, and reputation to attract and retain employees. Our people strategies focus on initiatives
that provide a safe and productive work environment, opportunity for advancement, and added wage security. We have
centralized personnel, orientation, and training programs in Canada. In the U.S., these functions are managed to align
with regional labour and customer service requirements. In 2008, we launched Toughnecks (www.toughnecks.com), our
highly successful field recruiting program.
Precision Drilling Corporation 2013 Annual Report 19
Systems
Our fully integrated, enterprise-wide reporting system has improved business performance through real-time access to
information across all functional areas. All of our divisions operate on a common integrated system using standardized
business processes across finance, payroll, equipment maintenance, procurement, and inventory control functions.
We continue 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
inquiries. Rig manufacturing projects also benefit from scheduling and budgeting tools as economies of scale can be
identified and leveraged as construction demands increase.
Safe Operations
Safety, environmental stewardship and employee wellness are critical for us and for our customers and are the foundation
of our culture.
Safety performance is a fundamental contributor to operating performance and the financial results we generate for our
shareholders. Target Zero – our safety vision for eliminating workplace incidents – is a core belief that all injuries can
be prevented. We track safety using an industry standard recordable frequency statistic that benchmarks successes
and isolates areas for improvement. We have taken it to another level by tracking and measuring all injuries, regardless
of severity, because they are leading indicators of the potential for a more serious incident. In 2013, 252 of our drilling
rigs and 208 of our service rigs achieved Target Zero. We continue to embrace technological advancements that make
operations safer.
Together with our customers, we are continuously looking for opportunities to reduce our consumption of non-renewable
resources and reduce our environmental footprint. We use technology to minimize our impact on the environment, including:
heat recovery and distribution systems
power generation and distribution
fuel management
fuel type
noise reduction
recycling of used materials
use of recycled materials
efficient equipment designs
spill containment.
20 Management’s Discussion and Analysis
AN EFFECTIVE STRATEGY
Precision’s vision is to be recognized as the High Performance, High Value provider of services for global energy exploration
and development.
We work toward this vision by defining and measuring our results against strategic priorities we establish at the beginning
of every year.
Strategic Priorities
2013 Results
Plans for 2014
Execute our High Performance,
High Value strategy
Continue to drive execution excellence in our
people, internal systems and infrastructure.
Improved safety performance in both
operating segments in 2013, matching the
best results in our history.
Began construction of our Nisku Centre.
Support our world class safety, training and
development programs.
Upgrade and consolidate our Nisku
operations and leverage our investments
in our Houston and Red Deer Technology
Centres.
Execute on existing organic
growth opportunities
Remain poised to seize growth opportunities,
leveraging our balance sheet strength and
flexibility.
Deliver new-build rigs to the North American
market and upgrade existing drilling rigs
to higher specification assets on customer
contracts.
Grow High Performance, High Value service
lines for unconventional field development,
such as integrated directional drilling, coil
tubing and rentals.
Build our brand
Uphold our reputation and market breadth
in North America while strengthening
our presence in select oilfield markets
internationally.
Delivered seven new-build Super Series
rigs to customers on term contracts and
upgraded 19 existing drilling rigs to higher
specification assets under term contracts.
Expanded international operations with rig
additions to Mexico and the Middle East.
Expanded service lines in Completion and
Production Services by adding higher end
rental offerings and expanding our coil tubing
business. Expanded penetration into northern
U.S. markets.
Delivered strong Canadian and U.S.
dayrates throughout 2013 and exceeded
employee retention goals across all targeted
skill positions.
Increased recognition from U.S. and
international investors while retaining strong
support from Canadian base.
Invest in our physical and human capital
infrastructure to advance field level
professional development, provide industry
leading service to customers and demand
safe operations.
Leverage our scale of operations and utilize
established systems to promote consistent
and reliable service.
Increase returns for our investors.
Deliver new-build and upgraded drilling rigs
to customer contracts, expand international
activity in existing locations and grow
our LNG drilling leadership position. Be
a recognized leader in the integrated
directional drilling transformation. Grow
our U.S. presence in Completion and
Production Services.
Uphold our reputation and market breadth in
North America while improving our visibility in
select oilfield markets internationally.
Our corporate and competitive growth strategies are designed to optimize resource allocation and differentiate us from the
competition, generating value for investors.
We see opportunities for growth in our Contract Drilling Services land drilling rig fleet both in North America and
internationally. Unconventional drilling is the primary opportunity in the North American marketplace. Unconventional
resource development requires advanced Tier 1 drilling rigs and other highly developed services that facilitate the drilling
of reliable, predictable and repeatable horizontal wells.
The completion and production work associated with unconventional wells provides the most profitable growth opportunities
for Completion and Production Services.
Precision Drilling Corporation 2013 Annual Report 21
RISKS TO OUR BUSINESS
Our key business risks are summarized below. You’ll find more information and other risks to our business in our annual
information form, which is on file with the Canadian securities commissions on SEDAR (www.sedar.com) and with the
U.S. Securities and Exchange Commission on EDGAR (www.sec.gov).
Price of Oil and Natural Gas
We sell our services to oil and natural gas exploration and production companies. Macroeconomic and geopolitical factors
associated with oil and natural gas supply and demand are the primary factors driving pricing and profitability in the oilfield
services industry. Generally, we experience high demand for our services when commodity prices are relatively high and
the opposite is true when commodity prices are low. The volatility of crude oil and natural gas prices accounts for much of
the cyclical nature of the energy services business.
The markets for oil and natural gas are separate and distinct. Oil is a global commodity with a vast distribution network,
although the differential between benchmarks such as West Texas Intermediate and European Brent crude oil can fluctuate.
As in all markets, when supply, demand and other market factors change, so can the spreads between benchmarks. The
most economical way to transport natural gas is in its gaseous state by pipeline, and the natural gas market depends on
pipeline infrastructure and regional supply and demand. However, recent developments in the transportation of liquefied
natural gas in ocean-going tanker ships have introduced an element of globalization to the natural gas market.
We try to manage this risk by keeping our cost structure as variable as we can while still being able to maintain the level of
service our customers require.
Weather Patterns
Seasonal weather patterns in Canada and the northern U.S. affect activity in the oilfield services industry. During the spring
months, wet weather and the spring thaw make the ground unstable so municipalities and counties and provincial and
state transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment. This
reduces activity and highlights the importance of the location of our equipment prior to the imposition of the road bans. The
timing and length of road bans depend on weather conditions leading to the spring thaw and during the thawing period.
Additionally, certain oil and natural gas producing areas are located in parts of western Canada that are only accessible
during the winter months because the ground surrounding or containing the drilling sites in these areas consists of terrain
known as muskeg. Rigs and other necessary equipment cannot cross this terrain to reach the drilling site until the muskeg
freezes. Moreover, once the rigs and other equipment have been moved to a drilling site, they may become stranded or
be unable to move to another site if the muskeg thaws unexpectedly. Our business results depend partly on how long the
winter drilling season lasts.
Competition
Our business results and the strength of our financial position are affected by our ability to strategically manage our capital
expenditure program in a manner consistent with industry cycles and fluctuations in the demand for contract drilling
services. If we do not effectively manage our capital expenditures or respond to market signals relating to the supply or
demand for contract drilling and oilfield services, it could have a material adverse effect on our revenues, operations and
financial condition.
Periods of high demand often lead to higher capital expenditures on drilling rigs and other oilfield services equipment.
The number of drilling rigs competing for work in markets where we operate has increased as the industry adds new and
upgraded rigs. We expect new or newer rigs to continue to enter markets where we operate. The industry supply of drilling
rigs may exceed actual demand because of the relatively long life span of oilfield services equipment as well as the typically
long lead time required from when a decision is made to upgrade or build new equipment to when the equipment is placed
into service. Excess supply resulting from industry-wide capital expenditures could lead to lower demand for term drilling
contracts and for our equipment and services. The additional supply of drilling rigs has intensified price competition in
the past and could continue to do so, possibly leading to lower rates in the oilfield services industry generally and lower
utilization of existing rigs. If any of these factors materialize, it would have an adverse effect on our revenues, cash flows,
earnings and asset valuation.
22 Management’s Discussion and Analysis
Technology
Complex drilling programs for the exploration and development of conventional and unconventional oil and natural gas
reserves demand high performance drilling rigs. The ability of drilling rig service providers to meet this demand depends
on continuous improvement of existing rig technology, such as drive systems, control systems, automation, mud systems
and top drives, to improve drilling efficiency. Our ability to deliver equipment and services that meet customer demand
is critical to our continued success. We have an experienced internal engineering department that works closely with
operations and marketing on equipment design and improvements. We cannot assure, however, that our rig technology
will continue to meet the needs of our customers, especially as rigs age and technology advances, or that competitors
won’t develop technological improvements that are more advantageous, timely or cost effective.
Employees and Suppliers
Finding and Keeping Employees
Our success depends on our ability to continue to employ and retain skilled technical personnel and qualified rig personnel;
if we are unable to, it could have a material adverse effect on our operations. We may not be able to find enough skilled
labour to meet our needs, and this could limit growth. We may also have difficulty finding enough skilled and unskilled
labour in the future if demand for our services increases. Shortages of qualified personnel have occurred in the past during
periods of high demand. The demand for qualified rig personnel generally increases with stronger demand for land drilling
services and as new and refurbished rigs are brought into service. Increased demand typically leads to higher wages that
may or may not be reflected in any increases in service rates.
We continually monitor crew availability. To retain and attract quality staff, we focus on providing a safe and productive work
environment, opportunity for advancement, and added wage security.
Relying on Suppliers
We source certain key rig components, raw materials, equipment and component parts from a variety of suppliers in
Canada, the U.S. and overseas. We also outsource some or all construction services for drilling and service rigs, including
new-build rigs, as part of our capital expenditure program.
To manage this risk, we maintain relationships with several key suppliers and contractors and place advance orders for
components that have long lead times. We also have an inventory of key components, materials, equipment and parts.
We may, however, experience cost increases, delays in delivery due to the strong activity or financial hardship of suppliers
or contractors, or other unforeseen circumstances relating to third parties. If our current or alternate suppliers are unable
to deliver the necessary components, materials, equipment, parts and services we require for our businesses, including
for the construction of new-build drilling rigs, it can delay service to our customers and have a material adverse effect on
our revenues, cash flows and earnings.
Health, Safety and the Environment
We are subject to various environmental, health and safety laws, rules, legislation and guidelines, which can impose
material liability, increase our costs, or lead to lower demand for our services.
Standards for accident prevention in the oil and natural gas industry are governed by service company safety policies and
procedures, accepted industry safety practices, customer-specific safety requirements, and health and safety legislation.
Safety is a key factor that customers consider when selecting an oilfield service company. A decline in our safety
performance could result in lower demand for services, and this could have a material adverse effect on our revenues,
cash flows and earnings.
Our operations are affected by numerous laws, regulations and guidelines relating to spills, releases, emissions, and
discharges of hazardous substances or other waste materials into the environment. These may require removal or
remediation of pollutants or contaminants, and can impose civil and criminal penalties for violations. Some of these
apply to our operations and authorize the recovery of natural resource damages by the government, injunctive relief, and
the imposition of stop, control, remediation and abandonment orders. In addition, our land drilling operations may be
conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures, and
this may expose us to additional operating costs and liabilities for noncompliance with certain laws. Some environmental
Precision Drilling Corporation 2013 Annual Report 23
laws and regulations may impose strict and, in certain cases joint and several, liability. This means that in some situations
we could be exposed to liability as a result of conduct that was lawful at the time it occurred, or conditions caused by prior
operators or other third parties, including any liability related to offsite treatment or disposal facilities. The costs arising from
compliance with these laws, regulations and guidelines may be material.
We maintain liability insurance, including insurance for certain environmental claims, but coverage is limited, and some of
our policies exclude coverage for damages resulting from environmental contamination. We cannot assure that insurance
will continue to be available to us on commercially reasonable terms, that the possible types of liabilities that we may incur
will be covered by the insurance, or that the dollar amount of the liabilities will not exceed our policy limits. Even a partially
uninsured claim, if successful and of sufficient magnitude, could have a material adverse effect on our business, results
of operations and prospects.
The issue of energy and the environment has created intense public debate in Canada, the U.S. and around the world
in recent years, and it is likely to continue to be a focus area for the foreseeable future, which could potentially have
a significant impact on all aspects of the economy. The trend in environmental regulation has been to impose more
restrictions and limitations on activities that may impact the environment. Any regulatory changes that impose additional
environmental restrictions or requirements on us, or our customers, could increase our operating costs and potentially
lead to lower demand for our services and have an adverse effect on us. For example, there is growing concern about
the apparent connection between the burning of fossil fuels and climate change. Laws, regulations or treaties concerning
climate change or greenhouse gas emissions can have an adverse impact on the demand for oil and natural gas, which
could have a material adverse effect on us.
Governments in Canada and the U.S. are also considering more stringent regulation or restriction of hydraulic fracturing,
a technology used by some of our customers that involves the injection of water, sand and chemicals under pressure
into rock formations to stimulate oil and natural gas production. This could have a negative impact on the exploration of
unconventional energy resources, which are only commercially viable with the use of hydraulic fracturing. Laws relating
to hydraulic fracturing are in various stages of development at levels of governments in markets where we operate. The
outcome of these developments and their effect on the regulatory landscape and the contract drilling industry is uncertain.
Financial
Credit Market Conditions
The ability to make scheduled debt repayments, refinance debt obligations, or access financing depends on our financial
condition and operating performance, which may be affected by prevailing economic and competitive conditions and
certain financial, business and other factors beyond our control. Volatility in the credit markets can increase costs associated
with debt instruments due to increased spreads over relevant interest rate benchmarks, or affect our ability to access those
markets or the ability of third parties we wish to do business with. We may be unable to maintain sufficient cash flow from
operating activities to allow us to pay the principal, premium, if any, and interest on our debt.
In addition, if there is continued or future volatility or uncertainty in the capital markets, access to financing may be
uncertain, and this can have an adverse effect on the industry and our business, including future operating results. Our
customers may curtail their drilling programs, which could result in reduced dayrates, lower demand for drilling rigs, well
service rigs, directional drilling, turnkey jobs, and other wellsite services, or lower equipment utilization. In addition, certain
customers may be unable to pay suppliers, including us, if they are unable to access the capital markets to fund their
business operations.
Access to Additional Financing
We will need sufficient cash flows in the future to service and repay our debt. Our ability to generate cash in the future is
affected to some extent by general economic, financial, competitive and other factors that may be beyond our control. If
we need to borrow funds in the future to service our debt, our ability will depend on covenants in the secured facility, the
2019 Notes, the 2020 Notes, the 2021 Notes, and other debt agreements we have in the future, and on our credit ratings.
We may not be able to access sufficient amounts under the secured facility or from the capital markets in the future to pay
our obligations as they mature or to fund other liquidity requirements. If we are not able to borrow a sufficient amount, or
generate enough cash flow from operations to service and repay our debt, we will need to refinance our debt or we will be
in default, and we could be forced to reduce or delay investments and capital expenditures or dispose of material assets.
24 Management’s Discussion and Analysis
We may not be able to refinance or arrange alternative measures on favourable terms or at all. If we are unable to service,
repay or refinance our debt, it could have a negative impact on our financial condition and results of operations.
We regularly assess our credit policies and capital structure, and have enough liquidity to meet our needs. See page 36
for information about our liquidity.
Foreign Exchange
Our U.S. and international operations have revenues, expenses, assets and liabilities denominated in currencies other than
the Canadian dollar (mostly in U.S. dollars and currencies that are pegged to the U.S. dollar). This means that changes in
currency exchange rates affect our income statement, balance sheet and statement of cash flow.
Translation into Canadian dollars – When preparing our consolidated financial statements, we translate the financial
statements for foreign operations that don’t have a Canadian dollar functional currency into Canadian dollars. We
translate assets and liabilities at exchange rates in effect at the balance sheet date. We translate revenues and
expenses using average exchange rates for the month of the transaction. We initially recognize gains or losses from
these translation adjustments in other comprehensive income, and reclassify them from equity to net earnings on
disposal or partial disposal of the foreign operation. Changes in currency exchange rates could materially increase
or decrease our foreign currency-denominated net assets, which would increase or decrease shareholders’ equity.
Changes in currency exchange rates will affect the amount of revenues and expenses we record for our U.S. and
international operations, which will increase or decrease our net earnings. If the Canadian dollar strengthens against
the U.S. dollar, the net earnings we record in Canadian dollars for our international operations will be lower.
Transaction Exposure – Some of our long-term debt is denominated in U.S. dollars. We have designated our U.S.
dollar denominated unsecured senior notes (the 2020 Notes and the 2021 Notes) as a hedge against the net asset
position of our U.S. operations. We convert the debt at the exchange rate in effect at the balance sheet dates and
include the resulting gains or losses in the statement of comprehensive income. If the Canadian dollar strengthens
against the U.S. dollar, we will incur a foreign exchange gain from the translation of this debt. Most of our international
operations are transacted in U.S. dollars or U.S. dollar-pegged currencies. Transactions for our Canadian operations
are mainly in Canadian dollars, but we occasionally buy goods and supplies for our Canadian operations using U.S.
dollars. However, U.S. dollar denominated transactions and foreign exchange exposure in our Canadian operations
would not typically have a material impact on our financial results.
Liabilities from Prior Reorganizations
We have retained all liabilities of our predecessor companies, including liabilities relating to corporate and income tax matters.
International Operations
We conduct some of our business in Mexico and the Middle East. Our growth plans contemplate establishing operations in other
foreign countries, including countries where the political and economic systems may be less stable than in Canada or the U.S.
Our international operations are subject to risks normally associated with conducting business in foreign countries,
including among others:
an uncertain political and economic environment
the loss of revenue, property and equipment as a result of expropriation, confiscation, nationalization, contract
deprivation and force majeure
war, terrorist acts or threats, civil insurrection, and geopolitical and other political risks
fluctuations in foreign currency and exchange controls
restrictions on the repatriation of income or capital
increases in duties, taxes and governmental royalties
renegotiation of contracts with governmental entities
changes in laws and policies governing operations of foreign-based companies
restrictions under anti-corruption and anti-bribery legislation in Canada, the U.S. and other countries
trade restrictions or embargoes imposed by the U.S. or other countries.
If there is a dispute relating to our international operations, we may be subject to the exclusive jurisdiction of foreign courts
or may not be able to subject foreign persons to the jurisdiction of a court in Canada or the U.S.
Precision Drilling Corporation 2013 Annual Report 25
2013 Results
Management’s
Discussion and
Analysis
4
Adjusted EBITDA and operating earnings are additional GAAP measures. See page 5 for more information.
Consolidated Statements of Earnings Summary
Year ended December 31 (thousands of dollars)
2013
2012
2011
1,719,910
323,353
(13,286)
2,029,977
653,664
61,032
(75,863)
638,833
333,159
–
305,674
–
(9,112)
93,248
221,538
30,388
191,150
1,725,240
326,079
(10,578)
2,040,741
649,281
93,554
(72,043)
670,792
307,525
192,469
170,798
52,539
3,753
86,829
27,677
(24,683)
52,360
1,632,037
330,225
(11,235)
1,951,027
665,389
104,252
(74,577)
695,064
251,483
114,893
328,688
–
(23,674)
111,578
240,784
47,307
193,477
2013
2012
2011
1,002,199
1,053,966
1,071,526
901,246
137,681
(11,149)
936,113
64,017
(13,355)
866,776
22,994
(10,269)
2,029,977
2,040,741
1,951,027
2,082,958
2,006,519
489,646
4,579,123
2,119,891
1,913,810
266,562
4,300,263
2,252,084
2,027,676
148,114
4,427,874
Revenue
Contract Drilling Services
Completion and Production Services
Inter-segment elimination
Adjusted EBITDA
Contract Drilling Services
Completion and Production Services
Corporate and other
Depreciation and amortization
Loss on asset decommissioning
Operating earnings
Impairment of goodwill
Foreign exchange
Finance charges
Earning before income taxes
Income taxes
Net earnings
Results by Geographic Segment
Year ended December 31 (thousands of dollars)
Revenue
Canada
U.S.
International
Inter-segment elimination
Total assets
Canada
U.S.
International
26 Management’s Discussion and Analysis
2013 Compared to 2012
Net earnings in 2013 were $191 million or $0.66 per diluted share, compared to $52 million or $0.18 per diluted share
in 2012. For 2012, net earnings and net earnings per diluted share include the impact of charges associated with asset
decommissioning and an impairment charge to the goodwill attributable to our Canadian directional drilling operations.
Revenue was $2,030 million, 1% lower than 2012. Improved pricing in Canada and increased activity internationally were
offset by lower activity levels in both the Contract Drilling Services and Completion and Production Services segments.
Adjusted EBITDA in 2013 was $639 million, 5% lower than 2012. Lower activity levels were partially offset by higher average
pricing in both operating segments due to changes in product mix. Activity, as measured by drilling utilization days,
dropped 6% in Canada and 13% in the U.S. compared to 2012 but increased 70% internationally.
The volatile global environment and low natural gas prices in much of 2013 reduced utilization for us and for the industry
in general.
Average Oil and Natural Gas Prices
Oil
2013
2012
2011
West Texas Intermediate (per barrel)
US$98.02
US$94.13
US$95.02
Natural gas
Canada
AECO (per MMBtu)
U.S.
Henry Hub (per MMBtu)
$3.18
$2.39
$3.62
US$3.73
US$2.75
US$3.98
Key Statistics
There were 10,903 wells drilled in western Canada in 2013, 1% more than the 10,753 drilled in 2012. Despite the increases,
total industry drilling operating days was 3% lower than 2012, at 120,043. Average industry drilling operating days per well
was 11.0 compared to 11.6 in 2012. Average depth of a well increased 7%. The decrease in days per well while average
depth increased reflects the use of top tier rigs and greater industry experience with unconventional drilling.
Approximately 35,700 wells were started onshore in the U.S., 3% less than the approximately 36,800 wells started there
in 2012.
Fleet
We and many of our competitors have been in the process of upgrading the drilling rig fleet by building new rigs and
upgrading existing ones. In 2013, we added 7 new-build drilling rigs and upgraded another 19. In the fourth quarter of
2012, we decommissioned 42 Tier 3 drilling rigs and 10 Tier 2 rigs from our fleet and recorded an impairment charge of
$192 million. In the fourth quarter of 2011, we recorded an impairment charge of $115 million related to the decommissioning
of 36 drilling rigs and 13 well servicing rigs. We have exited the Tier 3 contract drilling business but retained 24 drilling rigs
for seasonal, stratification and turnkey drilling work (the PSST rigs). Our focus on the Tier 1 and Tier 2 market is aligned
with our corporate strategy, customer relationships and competitive position.
Goodwill
Under IFRS, we are required to assess the carrying value of cash-generating units that contain goodwill every year. Goodwill
in 2013 remains unchanged except for foreign currency translation. We recognized a $53 million goodwill impairment
charge in 2012 (the goodwill attributable to our Canadian directional drilling operations), because of the outlook for natural
gas pricing and the reduction in natural gas drilling in Canada.
Foreign Exchange
We recognized a foreign exchange gain of $9 million because the Canadian dollar weakened in value against the U.S.
dollar and this affected the net U.S. dollar denominated monetary position in our Canadian dollar-based companies.
Precision Drilling Corporation 2013 Annual Report 27
Finance Charges
Finance charges were $93 million, an increase of $6 million compared with 2012 primarily due to the increase in average
outstanding debt in Canadian dollars.
Income Taxes
Income taxes were $30 million, $55 million higher than in 2012 mainly because operating earnings were higher.
In June 2013, a wholly owned subsidiary of Precision lost a tax appeal in the Ontario Superior Court of Justice related
to a reassessment of Ontario income tax for the subsidiary’s 2001 thru 2004 taxation years. Precision has appealed the
decision to the Ontario Court of Appeal and we expect this appeal to be heard in 2014. Despite the decision in the Superior
Court, management believes it is more likely than not that Precision will prevail on appeal. Should Precision lose on appeal,
approximately $55 million of the long-term income tax recoverable related to this issue would be expensed.
2012 Compared to 2011
Net earnings in 2012 were $52 million or $0.18 per diluted share, compared to $193 million or $0.67 per diluted share
in 2011. Revenue was $2,041 million, 5% higher than 2011. Net earnings and net earnings per diluted share include the
impact of charges associated with asset decommissioning and an impairment charge to the goodwill attributable to our
Canadian directional drilling operations.
Adjusted EBITDA in 2012 was $671 million, 3% lower than 2011. Lower activity levels were partially offset by improved
pricing in both operating segments. Activity, as measured by drilling utilization days, dropped 15% in Canada and 9% in
the U.S. compared to 2011.
The volatile global environment and lower natural gas prices in much of 2012 reduced utilization for us and for the industry
in general.
Key Statistics
There were 10,753 wells drilled in western Canada in 2012, 9% fewer than the 11,832 drilled in 2011. Approximately 38,600
wells were started onshore in the U.S., 2% more than the approximately 37,800 wells started there in 2011.
In Canada, total industry drilling operating days were 14% lower than 2011, at 124,319. Average industry drilling operating
days per well was 11.6 compared to 12.2 in 2011. Average depth of a well increased 2%. The decrease in days per well
while average depth increased reflects the use of top tier rigs and greater industry experience with unconventional drilling.
Foreign Exchange
We recognized a foreign exchange loss of $4 million because the Canadian dollar strengthened in value against the U.S.
dollar and this affected the net U.S. dollar denominated monetary position in our Canadian dollar-based companies.
Finance Charges
Finance charges were $87 million, $25 million lower than 2011. In 2011, we incurred a $27 million charge for the make-whole
premium from the refinancing of a previously outstanding debt, and the interest expense associated with Canadian
income tax settlements. These were offset by higher interest costs from a higher average long-term debt balance and a
non-recurring gain we recognized in 2011.
Income Taxes
Income taxes were $72 million lower than in 2011 mainly because operating results were lower.
28 Management’s Discussion and Analysis
CONTRACT DRILLING SERVICES
Financial Results
Adjusted EBITDA and operating earnings are additional GAAP measures. See page 5 for more information.
Year ended December 31
(thousands of dollars, except where noted)
Revenue
Expenses
Operating
General and administrative
Adjusted EBITDA
Depreciation and amortization
Loss on asset decommissioning
Operating earnings
2013
1,719,910
1,019,156
47,090
653,664
292,217
–
361,447
% of
revenue
59.3
2.7
38.0
17.0
–
21.0
2012
1,725,240
1,036,553
39,406
649,281
271,993
192,469
184,819
% of
revenue
60.1
2.3
37.6
15.8
11.1
10.7
2011
1,632,037
931,062
35,586
665,389
219,194
113,366
332,829
% of
revenue
57.0
2.2
40.8
13.4
7.0
20.4
2013 Compared to 2012
Revenue from Contract Drilling Services was $1,720 million, slightly lower than 2012, mainly due to lower utilization days
in North America, partially offset by higher drilling rig revenue per day in both Canada and the U.S. and growth in our
international drilling operations.
Operating expenses were 59% of revenue, compared to 60% in 2012, mainly because of improved results from our
international drilling business. Operating expenses per day were 3% higher in Canada and 1% lower in the U.S. mainly
because of higher crew labour-related costs offset in the U.S. by lower turnkey activity. General and administrative expense
was higher because of the growth in our international business.
Operating earnings were $361 million, 96% higher than 2012, and equated to 21% of revenue compared to 11% in 2012.
Included in 2012 was a loss on asset decommissioning charge of $192 million on the decommissioning of 52 drilling rigs
in the fourth quarter.
Capital expenditures in 2013 were $447 million:
$208 million – to expand the underlying asset base
$141 million – to upgrade existing equipment
$98 million – on maintenance and infrastructure.
Most of the expansion capital was for our rig build program; seven of these were completed and placed into service by
December 31, 2013.
Precision Drilling Corporation 2013 Annual Report 29
Operating Statistics
Year ended December 31
Number of drilling rigs (year-end)
Drilling utilization days (operating and moving)
Canada
U.S.
International
Drilling revenue per utilization day
Canada (Cdn$)
U.S.(US$)
Drilling statistics (Canadian operations only)
Wells drilled
Average days per well
Metres drilled (hundreds)
Average metres per well
2013
327
30,530
30,268
3,555
22,108
23,575
3,211
8.4
5,576
1,736
% increase/
(decrease)
1.9
(5.6)
(12.5)
70.4
5.1
(0.5)
4.1
(10.6)
6.6
2.4
2012
321
32,352
34,597
2,086
21,030
23,696
3,085
9.4
5,233
1,696
% increase/
(decrease)
(4.7)
(14.8)
(8.7)
197.2
14.0
9.0
(13.5)
(1.1)
(8.5)
5.8
2011
337
37,970
37,887
702
18,442
21,744
3,566
9.5
5,717
1,603
% increase/
(decrease)
(5.1)
21.8
16.8
16.6
14.3
14.7
11.6
8.0
11.7
0.0
Canadian Drilling
Revenue from Canadian drilling was down $5 million or 1% from 2012. Drilling rig activity, as measured by utilization days,
was down 6%.
In 2013, the industry drilled 10,903 wells in western Canada, 1% more than in 2012. Industry operating days decreased 3%
to 120,043. These were the result of lower activity as customer demand for oil and liquids-rich natural gas related drilling
activity declined.
Adjusted EBITDA was $334 million, in line with $332 million in 2012, as higher pricing offset the decline in drilling activity.
Depreciation expense for the year was $5 million lower than 2012 because of lower utilization of our rigs and a recognized
loss on sale of assets in 2012.
Drilling Statistics – Canada
In 2013, we completed two new-build rigs and decommissioned one, bringing our Canadian 2013 year-end net rig count
to 187 (up by one).
The industry drilling rig fleet decreased slightly – there were approximately 819 rigs at the end of 2013 compared to 822 at
the end of 2012. Our operating day utilization was 39% (2012 – 40%), compared to industry utilization of 40% (2012 – 42%).
Our average dayrates in Canada increased 5% in 2013 because we had a favourable rig mix and demand for our Tier 1
rigs was strong.
U.S. Drilling
Revenue from U.S. drilling was lower than 2012 by US$106 million or 13%. Drilling rig activity, as measured by utilization
days, was down 13%.
Adjusted EBITDA was US$270 million, 12% lower than US$308 million in 2012, mainly because of lower industry activity
due to weak natural gas economics.
Depreciation expense for the year was $21 million lower than 2012 because of lower utilization of our drilling rigs and higher
losses on sale of assets in 2012.
Drilling Statistics – U.S.
In 2013, we completed five new-build rigs, and transferred five rigs to our international fleet, leaving our U.S. year-end net
rig count unchanged at 127. In 2013, we averaged 83 rigs working, a 13% decrease from 2012.
Our average dayrates in the U.S. decreased 1% in 2013 because we had fewer average rigs working turnkey jobs offset by
a better rig mix as demand for our Tier 1 rigs was strong. We also added new-build Tier 1 rigs and upgraded rigs to the fleet.
30 Management’s Discussion and Analysis
Drilling Statistics – U.S.
Average number of active land rigs for quarters ended:
March 31
June 30
September 30
December 31
Annual average
1 Source: Baker Hughes
2013
2012
Precision
Industry1
Precision
Industry1
81
80
81
90
83
1,706
1,710
1,709
1,697
1,705
104
97
90
87
95
1,947
1,924
1,855
1,759
1,871
COMPLETION AND PRODUCTION SERVICES
Financial Results
Adjusted EBITDA and operating earnings are additional GAAP measures. See page 5 for more information.
Year ended December 31
(thousands of dollars, except where noted)
Revenue
Expenses
Operating
General and administrative
Adjusted EBITDA
Depreciation and amortization
Loss on asset decommissioning
Operating earnings
2013
323,353
242,768
19,553
61,032
32,630
–
28,402
% of
revenue
75.1
6.0
18.9
10.1
8.8
2012
326,079
217,326
15,199
93,554
30,758
–
62,796
% of
revenue
66.6
4.7
28.7
9.4
–
19.3
2011
330,225
211,195
14,778
104,252
25,598
1,527
77,127
% of
revenue
64.0
4.5
31.6
7.8
0.5
23.4
Revenue from Completion and Production Services was $323 million in 2013, 1% lower than 2012, mainly because industry
activity was lower; customers reduced their spending on production activity as natural gas prices remained weak. Reduced
activity was partially offset by higher average day rates due to product mix and expansion of our services into the U.S.
Operating earnings were $28 million in 2013, 55% lower than 2012, and equated to 9% of revenue compared to 19% in
2012 as service rig activity was down in 2013 and rental equipment saw less activity.
Operating expenses were 75% of revenue, 8 percentage points higher than 2012, mainly because of lower equipment
utilization, which increased daily or hourly operating costs associated with fixed operating costs, and higher crew wages
starting in the fourth quarter.
Depreciation expense for the year was $2 million higher than 2012 mainly because of depreciation on equipment purchases
in 2012 and 2013.
Capital expenditures were $83 million:
$74 million – to expand the underlying asset base
$9 million – on maintenance and infrastructure.
Revenue from Precision Well Servicing was $189 million, 14% lower than 2012, because operating activity was down 14%.
Revenue from Precision Rentals was $39 million, 26% lower than 2012. Activity was lower because drilling, well servicing,
and frac-related activity was down. Precision Rentals expanded from three major product lines (surface equipment, wellsite
accommodations, and tubular equipment) to also provide power generation equipment, solids control equipment, and
WaterDams (containment rings).
Revenue from Precision Camp Services was $33 million, 5% higher than 2012, because there were more base camp days.
Precision operated three base camps and 50 drill camps during 2013.
Precision Drilling Corporation 2013 Annual Report 31
Operating Results
Year ended December 31
Number of service rigs (end of year)1
Service rig operating hours2
Revenue per operating hour2
2013
222
283,576
854
% increase/
(decrease)
3.7
(3.8)
14.8
2012
214
294,681
744
% increase/
(decrease)
3.4
(7.2)
8.1
2011
207
317,418
688
% increase/
(decrease)
(5.9)
7.9
8.0
1 Now includes snubbing services. Comparative numbers have been restated to reflect this change.
2 Prior year comparatives have been changed to include U.S. based service rig activity.
In 2013, we added one coil tubing unit in Canada and six in the U.S. In addition, we moved two service rigs from Canada
to the U.S., added one service rig to Canada and moved one snubbing unit from the U.S. to Canada. We also added rental
equipment as we continue to expand our North American footprint.
Service rig rates increased 15% as we provided higher-end services and crew wage increases were passed through to
customers. Our service rig hours decreased 4% although higher rig rates and our U.S. expansion partially offset market
activity declines.
CORPORATE AND OTHER
Financial Results
Adjusted EBITDA is an additional GAAP measure. See page 5 for more information.
Year ended December 31 (thousands of dollars)
2013
2012
2011
Revenue
Expenses
Operating
General and administrative
Adjusted EBITDA
Depreciation and amortization
Operating earnings (loss)
–
–
75,863
(75,863)
8,312
(84,175)
–
–
72,043
(72,043)
4,774
(76,817)
–
–
74,577
(74,577)
6,691
(81,268)
Our corporate segment has support functions that provide assistance to our other business segments. It includes costs
incurred in corporate groups in both Canada and the U.S.
Corporate and other expenses were $76 million in 2013, $4 million more than 2012, mainly related to costs resulting from
international growth. In 2013, corporate general and administrative costs were 3.7% of consolidated revenue compared to
3.5% in 2012 and 3.8% in 2011.
32 Management’s Discussion and Analysis
QUARTERLY FINANCIAL RESULTS
Adjusted EBITDA and funds provided by operations are additional GAAP measures. See page 5 for more information.
2013 – Quarters Ended
(thousands of dollars, except per share amounts)
March 31
June 30
September 30
December 31
Revenue
Adjusted EBITDA
Net earnings (loss)
Per basic share
Per diluted share
Funds provided by operations
Cash provided by operations
Dividends per share
595,720
215,181
93,313
0.34
0.33
144,682
62,948
0.05
378,898
88,248
473
0.00
0.00
33,791
182,345
0.05
488,450
137,660
29,443
0.11
0.10
127,684
88,341
0.05
566,909
197,744
67,921
0.24
0.24
155,816
94,452
0.06
2012 – Quarters Ended
(thousands of dollars, except per share amounts)
March 31
June 30
September 30
December 31
Revenue
Adjusted EBITDA
Net earnings (loss)
Per basic share
Per diluted share
Funds provided by operations
Cash provided by operations
Dividends per share
640,066
245,574
111,081
0.40
0.39
247,739
162,440
–
381,966
97,192
18,261
0.07
0.06
62,373
275,346
–
484,761
151,000
39,357
0.14
0.14
146,124
61,183
–
533,948
177,026
(116,339)
(0.42)
(0.42)
142,576
136,317
0.05
Seasonality
The Canadian drilling industry is affected by weather patterns. Activity peaks in the winter, in the fourth and first quarters.
In the spring, wet weather and the spring thaw make the ground unstable. Government road bans restrict the movement
of rigs and other heavy equipment, reducing activity in the second quarter. This leads to quarterly fluctuations in operating
results and working capital requirements.
Fourth Quarter 2013 Compared to Fourth Quarter 2012
We had net earnings in the fourth quarter of $68 million or $0.24 per diluted share, compared to a net loss of $116 million or
$0.42 per diluted share in the fourth quarter of 2012. In the fourth quarter of 2012, we recognized charges associated with
asset decommissioning and a goodwill impairment that, combined, reduced net earnings by $179 million and net earnings
per diluted share by $0.63 compared to the fourth quarter of 2013.
Revenue was $33 million higher in the fourth quarter of 2013 than the fourth quarter of 2012, mainly because of higher
international and U.S. drilling activity and higher pricing in Canadian contract drilling partially offset by lower turnkey activity
in the U.S.
Adjusted EBITDA was $21 million higher in the fourth quarter of 2013 than the fourth quarter of 2012 mainly because of
increases in international activity and U.S. contract drilling activity, and lower costs in U.S. contract drilling.
Our adjusted EBITDA margin was 35% in the fourth quarter of 2013, compared to 33% in the fourth quarter of 2012. The
increase in EBITDA margin was mainly due to improved profitability in international and U.S. contract drilling operations
and new-build and upgraded rigs that we have deployed over the past few years partially offset by weaker demand for our
completion and production services.
Operating costs were higher because of increased activity internationally and in contract drilling in the U.S. As a percentage
of revenue, operating costs were 59% in the fourth quarter of 2013 and 61% in the same quarter of 2012. Our portfolio of
term customer contracts, a highly variable operating cost structure, and economies achieved through vertical integration
of the supply chain all help us manage our adjusted EBITDA margin.
Precision Drilling Corporation 2013 Annual Report 33
Fourth quarter drilling rig utilization days (drilling days plus move days) in Canada were 8,201 in 2013, in line with 2012.
Drilling rig utilization days in the U.S. were 8,258 this quarter, 3% higher than the fourth quarter of 2012 as a result of
an improvement in market share as we were able to put more rigs to work in a period when industry land drilling rigs
declined 4%.
The majority of activity was in oil and liquids-rich natural gas related plays. We averaged a total of 190 rigs working in the
quarter (89 in Canada, 90 in the U.S., and 11 internationally), compared to an average of 175 rigs in the third quarter of
2013 and 185 rigs in the fourth quarter of 2012.
Our North America service rig activity in the fourth quarter was 7% lower than the fourth quarter of 2012 (71,981 operating
hours compared to 77,234 hours in the fourth quarter of 2012).
Contract Drilling Services
Revenue and adjusted EBITDA from Contract Drilling Services were both up in the fourth quarter compared to the fourth
quarter of 2012: revenue was $484 million, 7% higher than the fourth quarter of 2012 and adjusted EBITDA was $200 million,
16% higher than the fourth quarter of 2012. These results were mainly because of higher drilling rig activity in international
and the U.S. and higher average rates per day in Canada partially offset by lower turnkey activity in the U.S.
Operating results for our international operations improved as we averaged 11 rigs working compared to eight in the prior
year comparative quarter. Drilling utilization days in our international operations for the quarter were 1,052 days, 43% higher
than the fourth quarter of 2012.
Drilling rig utilization days in Canada (drilling days plus move days) during the fourth quarter of 2013 were 8,201, a
decrease of 1% compared to 2012 while drilling rig utilization days in the U.S. were 8,258, or 3% higher than the same
quarter of 2012. The increase in U.S. activity was primarily due to strong demand for Tier 1 assets and resulted in market
share gains by Precision during the second half of the year. The majority of our North America activity came from oil and
liquids-rich natural gas related plays.
In Canada, we generated 44% of utilization days in the fourth quarter from rigs under term contract, compared to 41% in
the fourth quarter of 2012. In the U.S., we generated 62% of utilization days from rigs under term contract as compared to
64% in the fourth quarter of 2012. At the end of the quarter, we had 57 drilling rigs working under term contracts in Canada,
58 in the U.S. and 10 internationally.
Operating costs were 56% of revenue for the fourth quarter of 2013 (2012 – 60%). On a per utilization day basis, operating
costs for the drilling rig division in Canada were above the prior year primarily because of an increase in crew wage
expense. In the U.S., operating costs for the quarter on a per day basis were down from the fourth quarter of 2012 as a
result of proportionately lower turnkey activity and cost savings from operational efficiencies. Labour rate increases are
typically recovered through higher dayrates.
Depreciation expense in the quarter was 2% higher than the prior year due to an increase in drilling activity and a greater
proportion of operating days from our Tier 1 drilling rigs. In 2012, we decommissioned 52 rigs in the fourth quarter (22 in
Canada and 30 in the U.S.) and recorded an impairment charge of $192 million.
We use the unit-of-production method of calculating depreciation for our contract drilling operations except for certain
PSST and directional drilling equipment, where we use the straight-line method.
Completion and Production Services
Revenue for the fourth quarter of 2013, from Completion and Production Services was $85 million in-line with the prior year
while adjusted EBITDA was $16 million, down 27% from the prior year, as weaker demand in the Canadian market offset
the expansion of services in the U.S. Activity in Canadian well servicing was down 16% but was offset by a 158% increase
in U.S. well servicing activity and higher average hourly rates in both Canada and the U.S.
34 Management’s Discussion and Analysis
Well servicing activity in the fourth quarter was 7% lower than the fourth quarter of 2012, as lower customer demand in
Canada more than offset our growing U.S. presence. Approximately 83% of the fourth quarter service rig activity was oil
related. Our rental division activity in the fourth quarter was lower than the fourth quarter of 2012 mainly due to the excess
amount of surface storage capacity in Western Canada.
Average service rig revenue per operating hour in the fourth quarter was $878, or $83 higher than the fourth quarter of 2012.
The increase was primarily the result of increased coil tubing operations in 2013, which operate at higher rates.
Operating costs as a percentage of revenue increased to 76% in the fourth quarter of 2013, from 70% in the fourth quarter
of 2012. Operating costs per service rig operating hour were higher than in the fourth quarter of 2012 mainly because of
the increase in costs associated with the new coil tubing operations and fixed costs spread over a lower activity base.
Depreciation in the fourth quarter of 2013 was 7% lower than the fourth quarter of 2012 because of lower equipment
utilization and losses on disposal realized in the fourth quarter of 2012. We use the straight-line method of calculating
depreciation for our completion and production business lines, except for the well servicing division, where we use the
unit-of-production method.
Consolidated
General and administrative expenses were $34 million in the fourth quarter, $4 million higher than the fourth quarter of
2012 because of the year to date recording of incentive compensation liabilities, which are tied to the price of our common
shares and our annual operating results.
Net finance charges were $23 million in the fourth quarter, $1 million higher than the fourth quarter of 2012, mainly because
of the increase in average outstanding debt stated in Canadian dollars.
Capital expenditures were $123 million in the fourth quarter compared to $187 million in the fourth quarter of 2012. Spending
in the fourth quarter of 2013 included:
$54 million – to expand the underlying asset base
$30 million – to upgrade existing equipment
$39 million – on maintenance and infrastructure.
Precision Drilling Corporation 2013 Annual Report 35
Financial Condition
Management’s
Discussion and
Analysis
5
The oilfield services business is inherently cyclical. To manage this, we focus on maintaining a strong balance sheet so
we have the financial flexibility we need to continue to manage our growth and cash flows, no matter where we are in the
business cycle.
We apply a disciplined approach to managing and tracking the results of our operations to keep costs down. We maintain
a scalable cost structure so we can be responsive to changing competition and market demand. And we invest in our fleet
to make sure we remain competitive. Our maintenance capital expenditures are rightly governed by and highly responsive
to activity levels with additional cost savings leverage provided through our internal manufacturing and supply divisions.
Term contracts on expansion capital for new-build rig programs help provide more certainty of future revenues and return
on our capital investments.
Liquidity
As at December 31, 2013, our liquidity was supported by a cash balance of $81 million, a senior secured credit facility
of US$850 million, operating facilities totalling approximately $55 million, and a US$25 million secured facility for letters
of credit.
At December 31, 2013, including letters of credit, we had approximately $1,394 million (2012 – $1,290 million) outstanding
under our secured and unsecured credit facilities and $23 million in unamortized debt issue costs. Our secured facility
includes financial ratio covenants that are tested quarterly. We are compliant with these covenants and expect to
remain compliant.
We ended 2013 with a long-term debt to long-term debt plus equity ratio of 0.36 (compared to 0.36 in 2012) and a ratio of
long-term debt to cash provided by operations of 3.09 (compared to 1.92 in 2012).
The current blended cash interest cost of our debt is about 6.5%.
Ratios and Key Financial Indicators
We evaluate the relative strength of our financial position by monitoring our working capital, debt ratios and liquidity.
We also monitor returns on capital, and we link our executives’ incentive compensation to the returns we generate
compared to our peers.
36 Management’s Discussion and Analysis
Financial Position and Ratios
At December 31 (thousands of dollars, except ratios)
Working capital
Working capital ratio
Long-term debt
Total long-term financial liabilities
Total assets
Enterprise value (see table on page 40)
Long-term debt to long-term debt plus equity
Long-term debt to cash provided by operations
Long-term debt to adjusted EBITDA
Long-term debt to enterprise value
2013
305,783
1.9
1,323,268
1,355,535
4,579,123
3,919,763
0.36
3.09
2.07
0.34
2012
278,021
1.7
1,218,796
1,245,290
4,300,263
3,213,406
0.36
1.92
1.82
0.38
2011
610,429
2.4
1,239,616
1,267,040
4,427,874
3,528,046
0.37
2.33
1.78
0.35
Credit Rating
Credit ratings affect our ability to obtain short and long-term financing, the cost of this financing, and our ability to engage
in certain business activities cost-effectively.
Corporate credit rating
Senior secured bank credit facility rating
Senior unsecured credit rating
Moody’s
Ba1
S&P
BB+
Not rated
Not rated
Ba1
BB
CAPITAL MANAGEMENT
To maintain and grow our business, we invest in both growth and sustaining capital. We base expansion capital decisions
on return on capital employed and payback, and we mitigate the risk that we may not be able to fully recover our capital
by requiring two to five year term contracts for new-build rigs.
We base our maintenance capital decisions on actual activity levels, using key financial indicators that we express as per
operating day or per operating hour. Sourcing internally (through our manufacturing and supply divisions) helps keep our
maintenance capital costs as low as possible.
Foreign Exchange Risk
Our U.S. and international operations have revenue, expenses, assets and liabilities denominated in currencies other than
the Canadian dollar (mostly in U.S. dollars and currencies that are pegged to the U.S. dollar). This means that changes
in currency exchange rates affect our income statement, balance sheet and statement of cash flow. We manage this risk
by matching the currency of our debt obligations with the currency of cash flows generated by the operations that the
debt supports.
Interest Rate Risk
We minimize interest rate risk by staggering long-term debt maturities.
Hedge of Investments in U.S. Operations
We have designated our U.S. dollar denominated long-term debt as a hedge of our investment in our operations in the
U.S. We recognize the effective amount of this hedge (net of tax) in other comprehensive income. We recognize ineffective
amounts (if any) in earnings.
Precision Drilling Corporation 2013 Annual Report 37
SOURCES AND USES OF CASH
At December 31 (thousands of dollars)
Cash from operations
Cash used in investing
Deficit
Cash (used in) from financing
Effect of exchange rate changes on cash
Net cash generated (used)
2013
428,086
(526,535)
(98,449)
21,517
4,770
(72,162)
2012
635,286
(930,121)
(294,835)
(14,899)
(4,974)
(314,708)
2011
532,772
(715,462)
(182,690)
366,887
26,448
210,645
Cash from Operations
In 2013, we generated cash from operations of $428 million compared to $635 million in 2012. The reduction is primarily
the result of higher income taxes paid in 2013 and lower operating results than 2012.
Investing Activity
We made growth and sustaining capital investments of $536 million in 2013:
$282 million in expansion capital
$141 million in upgrade capital
$113 million in maintenance and infrastructure capital.
The $536 million in capital expenditures in 2013 was split between segments:
$447 million in Contract Drilling Services
$83 million in Completion and Production Services
$6 million in Corporate and Other.
Expansion and upgrade capital includes the cost of long-lead items purchased for our capital inventory, such as top drives,
drill pipe, control systems, engines and other items we can use to complete new-build projects or upgrade our rigs in North
America and internationally.
Financing Activity
As at December 31, 2013, we had drawn US$28 million on our senior secured revolving facility, which in prior years had
only been used for letters of credit. No other changes, with the exception of foreign exchange translation, were made to
our net borrowings in 2013.
Effective August 30, 2012, our senior secured facility was increased from US$550 million to US$850 million and the
US$100 million accordion feature was increased to US$250 million, allowing the facility to be increased to US$1,100 million
with additional lender commitments. The term was extended to five years and several negative covenants were relaxed.
Also on August 30, 2012, our operating facility with Royal Bank of Canada was increased from $25 million to $40 million
and it remained undrawn as at March 7, 2014, except for $17 million in outstanding letters of credit. Our operating facility
of US$15 million with Wells Fargo remained undrawn as at March 7, 2014. Effective September 27, 2012, we entered into
a new US$25 million demand facility for letters of credit with HSBC Canada and as at March 7, 2014, US$24.8 million
was available.
38 Management’s Discussion and Analysis
Debt
At December 31, 2013, we had approximately $987 million in secured facilities, and $1,347 million in senior unsecured
notes (maturing in 2019, 2020 and 2021).
Amount
Availability
Used for
Maturity
Senior facility (secured)
US$850 million
(extendible, revolving term credit facility
with US$250 million accordion feature)
Drawn US$28 million and
US$29 million in outstanding
letters of credit
General corporate purposes
November 17, 2018
Operating facilities (secured)
$40 million
Undrawn, except $17 million in
outstanding letters of credit
Letters of credit and general
corporate purposes
US$15 million
Undrawn
Short term working capital
requirements
Demand letter of credit facility (secured)
US$25 million
Undrawn, except $0.2 million in
outstanding letters of credit
Letters of credit
Senior notes (unsecured)
$200 million
US$650 million
US$400 million
Fully drawn
Fully drawn
Fully drawn
Debt repayment
Debt repayment and general
corporate purposes
March 15, 2019
November 15, 2020
Capital expenditures and general
corporate purposes
December 15, 2021
Contractual Obligations
Our contractual obligations include both financial obligations (long-term debt and interest) and non-financial obligations
(new-build rig commitments, operating leases, and equity-based compensation for key executives and officers).
The table below shows the amounts of these obligations and when payments are due for each.
At December 31, 2013
(thousands of dollars)
Long-term
Interest on long-term debt
Rig construction
Operating leases
Contractual incentive plans1
Contingent purchase consideration
Total
Less than
1 year
–
87,176
150,624
16,833
14,952
28,133
297,718
Payments due (by period)
1-3 years
4-5 years
–
174,352
–
25,434
29,788
–
229,574
29,781
174,263
–
15,824
–
–
More than
5 years
1,316,780
170,394
–
15,714
–
–
Total
1,346,561
606,185
150,624
73,805
44,740
28,133
219,868
1,501,888
2,250,048
1 Includes amounts we have not yet accrued but are likely to pay at the end of the contract term. Our long-term incentive plans compensate officers and key employees through cash
payments when their awards vest. Equity-based compensation amounts are shown based on a share price of $9.83 at December 31, 2013.
Precision Drilling Corporation 2013 Annual Report 39
CAPITAL STRUCTURE
Shares outstanding
Deferred shares outstanding
Warrants outstanding
Share options outstanding
March 7,
2014
December 31,
2013
December 31,
2012
December 31,
2011
291,979,671
291,979,671
276,475,770
276,081,797
221,112
–
221,112
–
9,515,278
8,074,694
335,946
15,000,000
6,413,777
417,495
15,000,000
5,154,123
You can find more information about our capital structure in our annual information form, available online on our website
as well as on SEDAR and EDGAR.
Common Shares
Our articles of amalgamation allow us to issue an unlimited number of common shares.
In the fourth quarter of 2012, our Board of Directors approved the introduction of an annualized dividend of $0.20 per
common share, payable quarterly. In the fourth quarter of 2013, our Board of Directors approved an increase in the
quarterly dividend payment to $0.06 per common share.
Warrants
During December 2013, all of our 15,000,000 outstanding warrants were exercised providing proceeds of $48 million. The
warrants were issued on April 22, 2009, under a private placement. Each warrant was exercisable for one common share
at a price of $3.22 per common share for five years from the date of issue.
Preferred Shares
We can issue preferred shares in one or more series. The number of preferred shares that may be authorized for issue at
any time cannot exceed more than half of the number of issued and outstanding common shares. We currently have no
preferred shares issued.
Enterprise Value
(thousands of dollars, except shares outstanding and per share amounts)
Shares outstanding
Year-end share price on the TSX
Shares at market
Long-term debt
Less working capital
Enterprise value
December 31,
2013
December 31,
2012
December 31,
2011
291,979,671
276,475,770
276,081,797
9.94
2,902,278
1,323,268
(305,783)
3,919,763
8.22
2,272,631
1,218,796
(278,021)
3,213,406
10.50
2,898,859
1,239,616
(610,429)
3,528,046
40 Management’s Discussion and Analysis
Accounting Policies and Estimates
Management’s
Discussion and
Analysis
6
Critical Accounting Estimates and Judgements
Because of the nature of our business, we are required to make estimates about the future that affect the reported amounts
of assets, liabilities, revenues and expenses, and the disclosure of contingent liabilities. Estimates are based on our past
experience, our best judgment and assumptions we think are reasonable.
You’ll find all of our significant accounting policies in Note 3 to the consolidated financial statements. We believe the
following are the most difficult, subjective or complex judgments, and are the most critical to how we report our financial
position and results of operations:
impairment of long-lived assets
depreciation and amortization
income taxes.
Impairment of Long-Lived Assets
Long-lived assets, which include property, plant and equipment, intangibles and goodwill, comprise the majority of our
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. For property, plant and equipment, this
requires us to forecast future cash flows to be derived from the utilization of these assets based on assumptions about
future business conditions and technological developments. Significant, unanticipated changes to these assumptions
could require a provision for impairment in the future.
For goodwill, we conduct impairment tests annually in the fourth quarter or whenever there is a change in circumstance
that indicates that the carrying value may not be recoverable. The recoverability of goodwill requires a calculation of the
recoverable amount of the cash generating unit (CGU) or groups of CGUs to which goodwill has been allocated. A CGU
is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows
from other assets or groups of assets. Judgment is required in the aggregation of assets into CGUs. The recoverability
calculation requires an estimation of the future cash flows from the CGU or group of CGUs and judgment is required
in determining the appropriate discount rate. We use observable market data inputs to develop a discount rate that we
believe approximates the discount rate from market participants.
In deriving the underlying projected cash flows, assumptions must also be made about future drilling activity, margins and
market conditions over the long-term life of the assets or CGUs. We cannot predict if an event that triggers impairment will
occur, when it will occur or how it will occur or how it will affect reported asset amounts. Although estimates are reasonable
and consistent with current conditions, internal planning and expected future operations, such estimations are subject to
significant uncertainty and judgment.
We performed an impairment test on the well servicing CGU at December 31, 2013 as described in note 6 to the Consolidated
Financial Statements. This CGU has $89 million of goodwill allocated to it. An increase in the discount rate used by 1%
would require an impairment charge being recognized on the goodwill assigned to the well servicing CGU.
Precision Drilling Corporation 2013 Annual Report 41
Depreciation and Amortization
Our property, plant and equipment and intangible assets are depreciated and amortized based on estimates of useful
lives and salvage values. These estimates consider data and information from various sources including vendors, industry
practice and our own historical experience and may change as more experience is gained, market conditions shift or new
technological advancements are made.
Determination of which part of the drilling rig equipment represent significant cost relative to the entire rig and identifying
the consumption patterns along with the useful lives of these significant parts, are matters of judgment. This determination
can be complex and subject to differing interpretations and views, particularly when rig equipment comprises individual
components for which different depreciation methods or rates are appropriate.
Income Taxes
Uncertainties exist with respect to the interpretation of complex tax regulations, changes in tax laws, and the amount
and timing of future taxable income. Differences arising between the actual results and the assumptions made, or future
changes to such assumptions, could necessitate future adjustments to taxable income and expense already recorded.
We establish provisions, based on reasonable estimates, for possible consequences of audits by the tax authorities of the
respective countries in which we operate. The amount of such provisions is based on various factors, such as experience
of previous tax audits and differing interpretations of tax regulations by the taxable entity and the responsible tax authority.
In June 2013 a wholly owned subsidiary of the Corporation lost a tax appeal in the Ontario Superior Court of Justice related
to a reassessment of Ontario income tax for the subsidiary’s 2001 through 2004 taxation years. The Corporation has
appealed the decision to the Ontario Court of Appeal and expects this appeal to be heard in 2014. Despite the decision
in the Superior Court, management believes it is more likely than not that the Corporation would prevail on appeal. Should
the Corporation lose on appeal, approximately $55 million of the long-tern income tax recoverable related to this issue
would be expensed.
Accounting Policies Adopted January 1, 2013
Following are accounting policies Precision adopted with an initial application date of January 1, 2013:
IFRS 10 Consolidated Financial Statements
IFRS 10 introduces a new control model that is applicable to all investees; among other things, it requires the consolidation
of an investee if the Corporation controls the investee on the basis of de facto circumstances.
Subsidiaries are entities controlled by the Corporation. The Corporation controls an entity when it is exposed to, or has
rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power
over the entity. The financial statements of subsidiaries are included in the consolidated financial statements from the date
that control commences until the date that control ceases.
IFRS 11 Joint Arrangements
Joint arrangements are arrangements of which the Corporation has joint control, established by contracts requiring
unanimous consent for decisions about the activities that significantly affect the arrangements’ returns. Under IFRS 11,
joint arrangements are classified as either joint operations or joint ventures depending on the Corporation’s rights to the
assets and obligations for the liabilities of the arrangements. When making this assessment, the Corporation considers the
structure of the arrangements, the legal form of any separate vehicles, the contractual terms of the arrangement and other
facts and circumstances. Previously, the structure of the arrangement was the sole focus of classification.
The Corporation has no joint arrangements under IFRS 11.
42 Management’s Discussion and Analysis
IFRS 12 Disclosures of Interests in Other Entities
IFRS 12 sets out certain disclosures that are required relating to interests in subsidiaries, associates, joint arrangements
and unconsolidated structured entities. The Corporation does not have any investments that are not consolidated nor has
it entered into any joint arrangements or structured entities.
The Corporation’s subsidiaries, as detailed in Note 25 to the consolidated financial statements, are all wholly owned. The
determination of whether to consolidate these entities did not involve any significant judgments or assumptions. There
are no significant restrictions on the ability of the Corporation to access or use the assets and settle the liabilities of the
Corporation and its subsidiaries, except for customary limitations in the Corporation’s credit facility.
IFRS 13 Fair Value Measurement
IFRS 13 defines fair value and sets out a single standard a framework for measuring fair value and the required disclosures
about fair value measurements. Fair value is defined as the price that would be received to sell an asset or paid to transfer
a liability in an orderly transaction between market participants at the measurement date.
IFRS 13 is applied prospectively to fair value measurements occurring on or after January 1, 2013. The additional disclosure
requirements of IFRS 13 are also applied prospectively and have been presented, as relevant, in the 2013 interim and
annual financial statements.
Accounting Policies Not Yet Adopted
IFRS 9 Financial Instruments (2010), IFRS 9 Financial Instruments (2009)
IFRS 9 (2009) introduces new requirements for the classification and measurement of financial assets. Under IFRS 9 (2009),
financial assets are classified and measured based on the business model in which they are held and the characteristics
of their contractual cash flows. IFRS 9 (2010) introduces additions relating to financial liabilities. The IASB currently has an
active project to make limited amendments to the classification and measurement requirements of IFRS 9 and add new
requirements to address the impairment of financial assets and hedge accounting.
IFRS 9 (2010 and 2009) is effective for annual periods beginning on or after January 1, 2015, with early adoption permitted.
The Corporation is currently evaluating the impact of adopting this standard on its financial statements.
Precision Drilling Corporation 2013 Annual Report 43
Evaluation of Disclosure Controls and Procedures
Management’s
Discussion and
Analysis
7
Internal Control over Financial Reporting
Precision maintains internal control over financial reporting which is designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS.
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined
in Rules 13a – 15(f) and 15d – 15(f) under the United States Securities Exchange Act of 1934, as amended (the Exchange
Act) and under National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (NI 52-109).
Management, including the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO), has conducted an
evaluation of Precision’s internal control over financial reporting based on criteria established in Internal Control – Integrated
Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Based on management’s assessment as at December 31, 2013, management has concluded that Precision’s internal
control over financial reporting is effective.
The effectiveness of internal control over financial reporting as of December 31, 2013 was audited by KPMG LLP, an
independent registered public accounting firm, as stated in their Report of Independent Registered Public Accounting
Firm, which is included in this 2013 Annual Report to Shareholders.
Due to its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance
that a misstatement of Precision’s financial statements would be prevented or detected. Further, the evaluation of the
effectiveness of internal control over financial reporting was made as of a specific date, and continued effectiveness in
future periods is subject to the risks that controls may become inadequate.
Disclosure Controls and Procedures
Precision maintains disclosure controls and procedures designed to provide reasonable assurance that information
required to be disclosed in Precision’s interim and annual filings is reviewed, recognized and disclosed accurately and in
the appropriate time period.
An evaluation, as of December 31, 2013, of the effectiveness of the design and operation of Precision’s disclosure controls
and procedures, as defined in Rule 13a – 15(e) and 15d – 15(e) under the Exchange Act and NI 52-109, was carried out
by management, including the CEO and the CFO. Based on that evaluation, the CEO and CFO have concluded that the
design and operation of Precision’s disclosure controls and procedures were effective to ensure that information required
to be disclosed in the reports that Precision files or submits under the Exchange Act or Canadian securities legislation is
recorded, processed, summarized and reported within the time periods specified in the rules and forms therein.
It should be noted that while the CEO and CFO believe that Precision’s disclosure controls and procedures provide a
reasonable level of assurance that they are effective, they do not expect that Precision’s disclosure controls and procedures
will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable,
not absolute, assurance that the objectives of the control system are met.
44 Management’s Discussion and Analysis
Corporate Governance
Management’s
Discussion and
Analysis
8
At Precision, we believe that a strong culture of corporate governance and ethical behaviour in decision-making is
fundamental to the way we do business.
We have a strong board made up of directors with a history of achievement and an effective mix of skills, knowledge, and
business experience. The directors oversee the conduct of our business, provide oversight, and support our future growth.
They also monitor regulatory developments in Canada and the U.S. to keep abreast of developments in governance and
enhance transparency of our corporate disclosure.
You can find more information about our approach to governance in our Management Information Circular, available on
our website as well as on SEDAR and EDGAR.
Precision Drilling Corporation 2013 Annual Report 45
Management’s Report to the Shareholders
The accompanying consolidated financial statements and all information in this 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 that 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 International Financial
Reporting Standards (IFRS) appropriate in the circumstances. The financial information elsewhere in the Annual Report has been
reviewed to ensure consistency with that in the consolidated financial statements.
Management has prepared Management’s Discussion and Analysis (MD&A). The MD&A is based on the financial results of
Precision Drilling Corporation (the Corporation) prepared in accordance with IFRS. The MD&A compares the audited financial results
for the years ended December 31, 2013 to December 31, 2012 and the years ended December 31, 2012 to December 31, 2011.
Management is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting
and is supported by an internal audit function that conducts periodic testing of these controls. Internal control over financial
reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation
of consolidated financial statements for external reporting purposes in accordance with IFRS. Because of its inherent limitations,
internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined
to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with direction from our principal executive officer and principal financial and accounting officer,
management conducted an evaluation of the effectiveness of the Corporation’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) (1992). Based on this evaluation,
management concluded that the Corporation’s internal control over financial reporting was effective as of December 31, 2013.
Also management determined that there were no material weaknesses in the Corporation’s internal control over financial reporting
as of December 31, 2013.
KPMG LLP (KPMG), an independent firm of Chartered Accountants, was engaged, as approved by a vote of shareholders
at the Corporation’s most recent annual meeting, to audit the consolidated financial statements and provide an independent
professional opinion.
KPMG completed an audit of the design and effectiveness of the Corporation’s internal control over financial reporting as of
December 31, 2013, as stated in its report included herein, and expressed an unqualified opinion on the design and effectiveness
of internal control over financial reporting as of December 31, 2013.
The Audit Committee of the Board of Directors, which is comprised of five independent directors who are not employees of the
Corporation, provides oversight to the financial reporting process. Integral to this process is the Audit Committee’s review and
discussion with management and KPMG 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 KPMG major issues as to
the adequacy of the Corporation’s internal controls. KPMG has unrestricted access to the Audit Committee to discuss its audit
and related matters. The consolidated financial statements have been approved by the Board of Directors of Precision Drilling
Corporation and its Audit Committee.
Kevin A. Neveu
President and
Chief Executive Officer
Precision Drilling Corporation
Robert J. McNally
Executive Vice President and
Chief Financial Officer
Precision Drilling Corporation
March 7, 2014
March 7, 2014
46 Consolidated Financial Statements
Independent Auditors’ Report of Registered Public Accounting Firm
To the Shareholders and Board of Directors of Precision Drilling Corporation
We have audited the accompanying consolidated financial statements of Precision Drilling Corporation (the Corporation), which
comprise the consolidated statements of financial position as at December 31, 2013 and December 31, 2012, the consolidated
statements of earnings, comprehensive income, changes in equity and cash flow for the years then ended, and notes, comprising
a summary of significant accounting policies and other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance
with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal
control as management determines is necessary to enable the preparation of consolidated financial statements that are free from
material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our
audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial
statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement
of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal
control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit
procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies
used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the
consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our
audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the
Corporation as at December 31, 2013 and December 31, 2012, and its consolidated financial performance and its consolidated
cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International
Accounting Standards Board.
Other Matter
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the Corporation’s internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal
Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)
(1992), and our report dated March 7, 2014 expressed an unqualified opinion on the effectiveness of the Corporation’s internal
control over financial reporting.
Chartered Accountants
Calgary, Canada
March 7, 2014
Precision Drilling Corporation 2013 Annual Report 47
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of Precision Drilling Corporation
We have audited Precision Drilling Corporation’s (the Corporation) internal control over financial reporting as of December 31,
2013, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) (1992). The Corporation’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 Shareholders. Our responsibility is to express an opinion
on the Corporation’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 Corporation maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2013, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO) (1992).
We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance sheets of the Corporation as of December 31,
2013 and December 31, 2012, and the related consolidated statements of income, shareholders’ equity and cash flow for the years
then ended, and our report dated March 7, 2014 expressed an unqualified opinion on those consolidated financial statements.
Chartered Accountants
Calgary, Canada
March 7, 2014
48 Consolidated Financial Statements
Consolidated Statements of Financial Position
(Stated in thousands of Canadian dollars)
ASSETS
Current assets:
Cash
Accounts receivable
Inventory
Total current assets
Non-current assets:
Income tax recoverable
Property, plant and equipment
Intangibles
Goodwill
Total non-current assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
December 31,
2013
December 31,
2012
$
80,606
$
549,697
12,378
642,681
58,435
3,561,734
3,917
312,356
152,768
509,547
13,787
676,102
64,579
3,242,929
6,101
310,552
3,936,442
3,624,161
$
4,579,123
$
4,300,263
(Note 23)
(Note 4)
(Note 5)
(Note 6)
Accounts payable and accrued liabilities
(Note 23)
$
332,838
$
333,893
Income tax payable
Total current liabilities
Non-current liabilities:
Share based compensation
Provisions and other
Long-term debt
Deferred tax liabilities
Total non-current liabilities
Shareholders’ equity:
Shareholders’ capital
Contributed surplus
Retained earnings (deficit)
(Note 8)
(Note 9)
(Note 10)
(Note 11)
4,060
336,898
14,431
17,836
1,323,268
487,347
1,842,882
64,188
398,081
8,676
17,818
1,218,796
485,592
1,730,882
(Note 12)
2,305,227
2,251,982
29,175
88,416
(23,475)
24,474
(44,621)
(60,535)
2,399,343
2,171,300
$
4,579,123
$
4,300,263
Accumulated other comprehensive loss
(Note 13)
Total shareholders’ equity
Total liabilities and shareholders’ equity
See accompanying notes to consolidated financial statements.
Approved by the Board of Directors:
Allen R. Hagerman
Director
Patrick M. Murray
Director
Precision Drilling Corporation 2013 Annual Report 49
Consolidated Statements of Earnings
Years ended December 31,
(Stated in thousands of Canadian dollars, except per share amounts)
Revenue
Expenses:
Operating
General and administrative
Earnings before income taxes, finance charges, foreign
exchange, impairment of goodwill, loss on asset
decommissioning and depreciation and amortization
Depreciation and amortization
Loss on asset decommissioning
Operating earnings
Impairment of goodwill
Foreign exchange
Finances charges
Earnings before tax
Income taxes:
Current
Deferred
Net earnings
Earnings per share:
Basic
Diluted
(Note 23)
(Note 23)
(Note 4)
(Note 14)
(Note 11)
(Note 18)
2013
2012
$
2,029,977
$
2,040,741
1,248,637
142,507
1,243,301
126,648
638,833
333,159
–
305,674
–
(9,112)
93,248
221,538
45,017
(14,629)
30,388
191,150
0.69
0.66
$
$
$
$
$
$
670,792
307,525
192,469
170,798
52,539
3,753
86,829
27,677
70,576
(95,259)
(24,683)
52,360
0.19
0.18
See accompanying notes to consolidated financial statements.
Consolidated Statements of Comprehensive Income
Years ended December 31,
(Stated in thousands of Canadian dollars)
Net earnings
Unrealized gain (loss) on translation of assets and liabilities
of operations denominated in foreign currency
Foreign exchange gain (loss) on net investment hedge
with U.S. denominated debt, net of tax
Comprehensive income
See accompanying notes to consolidated financial statements.
2013
2012
$
191,150
$
52,360
109,195
(32,878)
(72,135)
$
228,210
$
23,205
42,687
50 Consolidated Financial Statements
Consolidated Statements of Cash Flow
Years ended December 31,
(Stated in thousands of Canadian dollars)
Cash provided by (used in):
Operations:
Net earnings
Adjustments for:
Long-term compensation plans
Depreciation and amortization
Loss on asset decommissioning
Impairment of goodwill
Foreign exchange
Finance charges
Income taxes
Other
Income taxes paid
Income taxes recovered
Interest paid
Interest received
Funds provided by operations
Changes in non-cash working capital balances
(Note 23)
Investments:
Business acquisitions, net of cash acquired
Purchase of property, plant and equipment
Proceeds on sale of property, plant and equipment
Changes in income tax recoverable
(Note 19)
(Note 4)
Changes in non-cash working capital balances
(Note 23)
Financing:
Debt issue costs
Debt facility amendment costs
Dividends paid
Increase in long-term debt
Issuance of common shares on the exercise of options
Issuance of common shares on the exercise of warrants
(Note 12)
(Note 12)
(Note 12)
Effect of exchange rate changes on cash and cash equivalents
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.
2013
2012
$
191,150
$
52,360
20,708
333,159
–
–
(9,216)
93,248
30,388
(3,754)
(109,326)
3,761
(89,156)
1,011
461,973
(33,887)
428,086
–
(535,804)
13,372
6,144
(10,247)
(526,535)
(883)
–
(58,113)
29,781
2,432
48,300
21,517
4,770
(72,162)
152,768
$
80,606
$
19,350
307,525
192,469
52,539
4,403
86,829
(24,683)
1,018
(10,403)
721
(85,251)
1,935
598,812
36,474
635,286
(25)
(868,057)
31,423
–
(93,462)
(930,121)
(2,855)
(149)
(13,821)
–
1,926
–
(14,899)
(4,974)
(314,708)
467,476
152,768
Precision Drilling Corporation 2013 Annual Report 51
Consolidated Statements of Changes in Equity
(Stated in thousands of Canadian dollars)
Balance at January 1, 2013
Net earnings for the period
Other comprehensive income for
the period
Dividends
Shareholders’
capital
Contributed
surplus
Accumulated
other
comprehensive
loss (Note 13)
Retained
earnings
(deficit)
Total equity
$ 2,251,982
$
24,474
$
(60,535)
$
(44,621)
$ 2,171,300
–
–
–
–
–
–
–
191,150
191,150
37,060
–
–
–
–
–
–
(58,113)
–
–
–
–
37,060
(58,113)
2,432
207
48,300
7,007
Share options exercised
(Note 12)
3,707
(1,275)
Shares issued on redemption of
non-management directors’ DSUs
Warrants exercised
Share based compensation expense
(Note 8)
1,238
48,300
–
(1,031)
–
7,007
Balance at December 31, 2013
$ 2,305,227
$
29,175
$
(23,475)
$
88,416
$ 2,399,343
Shareholders’
capital
Contributed
surplus
Accumulated
other
comprehensive
loss (Note 13)
Deficit
Total equity
$ 2,248,217
$
18,396
$
(50,862)
$
(83,160)
$ 2,132,591
(Stated in thousands of Canadian dollars)
Balance at January 1, 2012
Net earnings for the period
Other comprehensive loss for
the period
Dividends
–
–
–
–
–
–
Share options exercised
(Note 12)
3,050
(1,124)
Shares issued on redemption of
non-management directors’ DSUs
Shares issued on waiver of right to
dissent by dissenting unitholder
Share based compensation expense
(Note 8)
706
(706)
9
–
(3)
7,911
–
52,360
52,360
(9,673)
–
–
–
–
–
–
(13,821)
–
–
–
–
(9,673)
(13,821)
1,926
–
6
7,911
Balance at December 31, 2012
$ 2,251,982
$
24,474
$
(60,535)
$
(44,621)
$ 2,171,300
See accompanying notes to consolidated financial statements.
52 Consolidated Financial Statements
Notes to Consolidated Financial Statements
(Tabular amounts are stated in thousands of Canadian dollars except share numbers and per share amounts)
NOTE 1. DESCRIPTION OF BUSINESS
Precision Drilling Corporation (Precision or the Corporation) is incorporated under the laws of the Province of Alberta, Canada
and is a provider of contract drilling and completion and production services primarily to oil and natural gas exploration and
production companies in Canada, the United States and certain international locations. The address of the registered office is
800, 525 – 8th Avenue S.W., Calgary, Alberta, Canada, T2P 1G1.
NOTE 2. BASIS OF PREPARATION
(a) Statement of Compliance
These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards
(IFRS) as issued by the International Accounting Standards Board (IASB).
These consolidated financial statements were authorized for issue by the Board of Directors on March 7, 2014.
(b) Basis of Measurement
The consolidated financial statements have been prepared using the historical cost basis except as detailed in the Corporation’s
accounting policies in Note 3 and are presented in thousands of Canadian dollars.
(c) Use of Estimates and Judgments
The preparation of the consolidated financial statements requires management to make estimates and judgments that affect
the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingencies. These estimates and
judgments are based on historical experience and on various other assumptions that are believed to be reasonable under
the circumstances. The estimation of anticipated future events involves uncertainty and, consequently, the estimates used in
preparation of the consolidated financial statements may change as future events unfold, more experience is acquired or the
Corporation’s operating environment changes. Significant estimates and judgments used in the preparation of the financial
statements are described in Note 3.
NOTE 3. SIGNIFICANT ACCOUNTING POLICIES
(a) Basis of Consolidation
These consolidated financial statements include the accounts of the Corporation and all of its subsidiaries and partnerships
substantially all of which are wholly-owned. The financial statements of the subsidiaries are prepared for the same period as the
parent entity, using consistent accounting policies. All significant intercompany balances, transactions and any unrealized gains
and losses arising from intercompany transactions, have been eliminated.
Subsidiaries are entities controlled by the Corporation. Control exists when Precision has the power to govern the financial
and operating policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that
currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial
statements from the date that control commences until the date that control ceases.
Precision does not hold investments in any companies where it exerts significant influence and does not hold interests in any
special-purpose entities.
The acquisition method is used to account for acquisitions of subsidiaries and assets that meet the definition of a business under
IFRS. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred
or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business
combination are measured initially at their fair values at the acquisition date. The excess of the cost of acquisition over the fair
value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of acquisition is
less than the fair value of the net assets of the subsidiary acquired, the difference is recognized immediately in the statement of
earnings. Transaction costs, other than those associated with the issuance of debt or equity securities, that the Corporation incurs
in connection with a business combination are expensed as incurred.
Precision Drilling Corporation 2013 Annual Report 53
(b) Cash and Cash Equivalents
Cash and cash equivalents consist of cash and short-term investments with original maturities of three months or less.
(c) Inventory
Inventory is primarily comprised of operating supplies and is carried at the lower of average cost, being the cost to acquire the
inventory, and net realizable value. Inventory is charged to operating expenses as items are sold or consumed at the amount of
the average cost of the item.
(d) Property, Plant and Equipment
Property, plant and equipment are carried at cost, less accumulated depreciation and any accumulated impairment losses.
Cost includes an expenditure that is directly attributable to the acquisition of the asset. The cost of self-constructed assets
includes the cost of materials and direct labour, any other costs directly attributable to bringing the assets to a working condition
for their intended use and borrowing costs on qualifying assets.
The cost of replacing a part of an item of property, plant and equipment is recognized in the carrying amount of the item if it is
probable that the future economic benefits embodied within the part will flow to the Corporation, and its cost can be measured
reliably. The carrying amount of the replaced part is derecognized. The costs of the day-to-day servicing of property, plant and
equipment (repair and maintenance) are recognized in profit or loss as incurred.
Property, plant, and equipment are depreciated as follows:
Expected Life
Salvage Value
Basis of Depreciation
Drilling rig equipment:
– Power & Tubulars
– Dynamic
– Structural
1,700 utilization days
3,400 utilization days
5,000 utilization days
Seasonal, stratification and turnkey
drilling equipment
4 years
Service rig equipment
24,000 service hours
Drilling rig spare equipment
Service rig spare equipment
Rental equipment
Other equipment
Light duty vehicles
Heavy duty vehicles
Buildings
up to 15 years
up to 15 years
10 to 15 years
3 to 10 years
4 years
7 to 10 years
10 to 20 years
–
–
20%
0 to 20%
20%
–
–
0 to 25%
–
–
–
–
unit-of-production
unit-of-production
unit-of-production
straight-line
unit-of-production
straight-line
straight-line
straight-line
straight-line
straight-line
straight-line
straight-line
Assets that are depreciated on a unit-of-production method that have less than 60 utilization days (drilling rig equipment) or 600
service hours (service rig equipment) in a rolling 12 month period are deemed to be idle and are depreciated at a rate of five
utilization days or 50 service hours per month until the asset exceeds the utilization threshold.
Gains and losses on disposal of an item of property, plant and equipment are determined by comparing the proceeds from
disposal with the carrying amount of property, plant and equipment, and are recognized in the statements of earnings.
The estimated useful lives, residual values and methods or depreciation are reviewed annually, and adjusted prospectively if
appropriate.
(e) Intangibles
Intangible assets that are acquired by the Corporation with finite lives are initially recorded at estimated fair value and subsequently
measured at cost less accumulated amortization and any accumulated impairment losses.
Subsequent expenditures are capitalized only when it increases the future economic benefits of the specific asset to which
it relates.
54 Notes to Consolidated Financial Statements
Amortization is recognized in profit and loss using the straight-line method based over the estimated useful lives of the respective
assets as follows:
Customer relationships
Patents
Brand
1 to 5 years
10 years
1 to 5 years
The estimated useful lives and methods of amortization are reviewed annually, and adjusted prospectively if appropriate.
(f) Goodwill
Goodwill is the amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated
to the assets acquired, less liabilities assumed, based on their fair values.
If the fair value of the identifiable net assets acquired exceeds the fair value of the consideration, Precision reassesses whether
it has correctly identified and measured the assets acquired and liabilities assumed. If that excess remains after reassessment,
Precision recognizes the resulting gain in profit or loss on the acquisition date.
After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment
testing, goodwill acquired in a business combination is, from the acquisition date, attributed to the cash generating unit or groups
of cash generating units that are expected to benefit and as identified in the business combination.
(g) Impairment
(i) Financial Assets
A financial asset not carried at fair value through profit or loss is assessed at each reporting date to determine whether there
is any objective evidence that it is impaired. A financial asset is tested for impairment if objective evidence indicates that one
or more events have had a negative effect on the estimated future cash flows of that asset.
Objective evidence that financial assets are impaired can include default or delinquency by a debtor, restructuring of an
amount due to the Corporation on terms that the Corporation would not consider otherwise, and indications that a debtor will
enter bankruptcy. Precision considers evidence of impairment for receivables at both a specific asset and collective level. All
individually significant receivables are assessed for specific impairment. All significant receivables found not to be specifically
impaired are then collectively assessed for impairment by grouping together receivables with similar risk characteristics.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its
carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.
Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are
assessed collectively in groups that share similar credit risk characteristics.
All impairment losses are recognized in profit or loss.
An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was
recognized. For financial assets measured at amortized cost the reversal is recognized in profit or loss.
(ii) Non-Financial Assets
The carrying amounts of the Corporation’s non-financial assets, other than inventories and deferred tax assets, are reviewed
at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the
asset’s recoverable amount is estimated. For goodwill and other intangible assets that have indefinite lives or that are not yet
available for use an impairment test is completed at the same time each year.
For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates
cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the
cash-generating unit or CGU). The recoverable amount of an asset or a CGU is the greater of its value in use and its fair
value less costs to sell.
In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount
rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use
is generally computed by reference to the present value of the future cash flows expected to be derived from the cash
generating unit.
Precision Drilling Corporation 2013 Annual Report 55
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount.
Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to
reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets
in the CGU on a pro rata basis.
An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior
years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment
loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have
been determined, net of depreciation or amortization, if no impairment loss had been recognized.
(h) Borrowing Costs
Interest and borrowing costs that are directly attributable to the acquisition, construction or production of assets that take a
substantial period of time to prepare for their intended use are capitalized as part of the cost of those assets. Capitalization ceases
during any extended period of suspension of construction or when substantially all activities necessary to prepare the asset for
its intended use are complete.
All other interest and borrowing costs are recognized in earnings in the period in which they are incurred.
(i) Income Taxes
Income tax expense is recognized in net earnings except to the extent that it relates to items recognized directly in equity, in which
case it is recognized in equity.
Current tax is the expected tax payable or receivable on the taxable earnings or loss for the year, using tax rates enacted or
substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.
Deferred tax is recognized using the liability method, providing for temporary differences between the carrying amounts of assets
and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on
the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not
recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax
rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or
substantively enacted at the reporting date. The effect of a change in tax rates on deferred tax assets and liabilities is recognized
in net earnings in the period that includes the date of enactment or substantive enactment. Deferred tax assets and liabilities are
offset if there is a legally enforceable right to offset and they relate to taxes levied by the same tax authority on the same taxable
entity, or on different tax entities that are expected to settle current tax liabilities and assets on a net basis or their tax assets and
liabilities will be realized simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the
temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that
it is no longer probable that the related tax benefit will be realized.
(j) Revenue Recognition
The Corporation’s services are generally sold based on service orders or contracts with a customer that include fixed or determinable
prices based on daily, hourly or job rates. Customer contract terms do not include provisions for significant post-service delivery
obligations. Revenue is recognized when services and equipment rentals are rendered and only when collectability is reasonably
assured. The Corporation also provides services under turnkey contracts whereby it drills a well to an agreed upon depth under
specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. Revenue
from turnkey drilling contracts is recognized using the percentage-of-completion method based on costs incurred to date and
estimated total contract costs. Anticipated losses, if any, on uncompleted contracts are recorded at the time the estimated costs
exceed the contract revenue.
(k) Employee Benefit Plans
Precision sponsors various defined contribution retirement plans for its employees. The Corporation’s contributions to defined
contribution plans are expensed as employees earn the entitlement.
56 Notes to Consolidated Financial Statements
(l) Provisions
Provisions are recognized when the Corporation has a present obligation (legal or constructive) as a result of a past event, when it
is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and when a reliable
estimate can be made of the amount of the obligation.
The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the end
of the reporting period, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured
using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows.
(m) Share Based Incentive Compensation Plans
The Corporation has established several cash settled share based incentive compensation plans for officers, non-management
directors and other eligible employees. The fair values as estimated by management of the amounts payable to eligible
participants under these plans are recognized as an expense with a corresponding increase in liabilities over the period that the
participants become unconditionally entitled to payment. The recorded liability is re-measured at the end of each reporting period
until settlement with the resultant change to the fair value of the liability recognized in net earnings for the period. When the plans
are settled, the cash paid reduces the outstanding liability.
Prior to January 1, 2012 the Corporation had an equity settled deferred share unit plan whereby non-management directors of
Precision could elect to receive all or a portion of their compensation in fully-vested deferred share units. Compensation expense
was recognized based on the fair value price of the Corporation’s shares at the date of grant with a corresponding increase to
contributed surplus. Upon redemption of the deferred share units into common shares, the amount previously recognized in
contributed surplus is recorded as an increase to shareholders’ capital. The Corporation continues to have obligations under
this plan.
A share option plan has been established for certain eligible employees. Under this plan the fair value of share purchase options is
calculated at the date of grant using the Black-Scholes option pricing model and that value is recorded as compensation expense
over the grant’s vesting period with an offsetting credit to contributed surplus. A forfeiture rate is estimated on the grant date and
is adjusted to reflect the actual number of options that vest. Upon exercise of the equity purchase option, the associated amount
is reclassified from contributed surplus to shareholders’ capital. Consideration paid by employees upon exercise of the equity
purchase options is credited to shareholders’ capital.
(n) Foreign Currency Translation
Transactions of the Corporation’s individual entities are recorded in the currency of the primary economic environment in which
it operates (its functional currency). Transactions in currencies other than the entities’ functional currency are translated at rates
in effect at the time of the transaction. At each period end, monetary assets and liabilities are translated at the prevailing period
end rates. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated. Gains and
losses are included in net earnings except for gains and losses on translation of long-term debt designated as a hedge of foreign
operations, which are deferred and included in accumulated other comprehensive income.
For the purpose of preparing the Corporation’s consolidated financial statements, the financial statements of each foreign
operation that does not have a Canadian dollar functional currency are translated into Canadian dollars. Assets and liabilities
are translated at exchange rates in effect at the balance sheet date. Revenues and expenses are translated using average
exchange rates for the month of the respective transaction. Gains or losses resulting from these translation adjustments are
recognized initially in other comprehensive income and reclassified from equity to net earnings on disposal or partial disposal of
the foreign operation.
(o) Per Share Amounts
Basic per share amounts are calculated using the weighted average number of shares outstanding during the period. Diluted per
share amounts are calculated by using the treasury stock method for equity based compensation arrangements. The treasury
stock method assumes that any proceeds obtained on exercise of equity based compensation arrangements would be used to
purchase common shares at the average market price during the period. The weighted average number of shares outstanding
is then adjusted by the difference between the number of shares issued from the exercise of equity based compensation
arrangements and shares repurchased from the related proceeds.
Precision Drilling Corporation 2013 Annual Report 57
(p) Financial Instruments
(i) Non-Derivative Financial Assets
Financial assets are classified as either fair value through profit and loss, loans and receivables, held to maturity or available
for sale. Financial liabilities are classified as either fair value through profit and loss or other financial liabilities. Non-derivative
financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit or loss, any
directly attributable transaction costs. Transaction costs attributable to fair value through profit or loss items are expensed
as incurred. Subsequent to initial recognition non-derivative financial instruments are measured based on their classification.
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 Corporation, the measured amount generally corresponds
to historical cost.
Accounts payable and accrued liabilities 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 Corporation, the
measured amount generally corresponds to historical cost.
(ii) Derivative Financial Instruments
The Corporation may enter into certain financial derivative contracts in order to manage the exposure to market risks from
fluctuations in interest rates or exchange rates. These instruments are not used for trading or speculative purposes. Precision
has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge
accounting, even though it considers certain financial contracts to be economic hedges. As a result, financial derivative
contracts are classified as fair value through profit or loss and are recorded on the balance sheet at estimated fair value.
Transaction costs are recognized in profit or loss when incurred.
Derivatives embedded in other instruments or host contracts are separated from the host contract and accounted for
separately when their economic characteristics and risks are not closely related to the host contract. Embedded derivatives
are recorded on the balance sheet at estimated fair value and changes in the fair value are recognized in earnings.
(q) Hedge Accounting
The Corporation utilizes foreign currency long-term debt to hedge its exposure to changes in the carrying values of the Corporation’s
net investment in certain 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 defines the relationship between the foreign currency
long-term debt and the net investment in the foreign operations, as well as the Corporation’s risk management objective and
strategy for undertaking the hedging transaction. The Corporation formally assesses, both at inception and on an ongoing basis
whether the changes in fair value of the foreign currency long-term debt is highly effective in offsetting changes in fair value of the
net investment in the foreign operations. The portion of gains or losses on the hedging item that is determined to be an effective
hedge is recognized in other comprehensive income, net of tax, and is limited to the translation gain or loss on the net investment,
while the ineffective portion is recorded in earnings. If the hedging relationship is terminated or ceases to be effective, hedge
accounting is not applied to subsequent gains or losses. The amounts recognized in other comprehensive income are reclassified
to net earnings when corresponding exchange gains or losses arising from the translation of the foreign operation are recorded
in net earnings.
58 Notes to Consolidated Financial Statements
(r) Critical Accounting Judgments
(i) Depreciation and Amortization
Precision’s property, plant and equipment and its intangible assets are depreciated and amortized based on estimates of
useful lives and salvage values. These estimates consider data and information from various sources including vendors,
industry practice and Precision’s own historical experience and may change as more experience is gained, market conditions
shift or new technological advancements are made.
Determination of which part of the drilling rig equipment represent significant cost relative to the entire rig and identifying
the consumption patterns along with the useful lives of these significant parts, are matters of judgment. This determination
can be complex and subject to differing interpretations and views, particularly when rig equipment comprises individual
components for which different depreciation methods or rates are appropriate.
(ii) Income Taxes
Uncertainties exist with respect to the interpretation of complex tax regulations, changes in tax laws, and the amount and
timing of future taxable income. Differences arising between the actual results and the assumptions made, or future changes
to such assumptions, could necessitate future adjustments to taxable income and expense already recorded. The Corporation
establishes provisions, based on reasonable estimates, for possible consequences of audits by the tax authorities of the
respective countries in which it operates. The amount of such provisions is based on various factors, such as experience
of previous tax audits and differing interpretations of tax regulations by the taxable entity and the responsible tax authority.
In June 2013 a wholly owned subsidiary of the Corporation lost a tax appeal in the Ontario Superior Court of Justice related
to a reassessment of Ontario income tax for the subsidiary’s 2001 thru 2004 taxation years. The Corporation has appealed
the decision to the Ontario Court of Appeal and expects this appeal to be heard in 2014. Despite the decision in the Superior
Court, management believes it is more likely than not that the Corporation would prevail on appeal. Should the Corporation
lose on appeal, approximately $55 million of the long-tern income tax recoverable related to this issue would be expensed.
(s) Critical Accounting Assumptions and Estimates
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. For property, plant and equipment, this
requires Precision to forecast future cash flows to be derived from the utilization of these assets based on assumptions
about future business conditions and technological developments. Significant, unanticipated changes to these assumptions
could require a provision for impairment in the future.
For goodwill, we conduct impairment tests annually in the fourth quarter or whenever there is change in circumstance
that indicates that the carrying value may not be recoverable. The recoverability of goodwill requires a calculation of the
recoverable amount of the CGU or groups of CGUs to which goodwill has been allocated. A CGU is the smallest identifiable
group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of
assets. Judgment is required in the aggregation of assets into CGUs. The recoverability calculation requires an estimation
of the future cash flows from the CGU or group of CGUs and judgment is required in determining the appropriate discount
rate. We use observable market data inputs to develop a discount rate that we believe approximates the discount rate from
market participants.
In deriving the underlying projected cash flows, assumptions must also be made about future drilling activity, margins and
market conditions over the long-term life of the assets or CGUs. Precision cannot predict if an event that triggers impairment
will occur, when it will occur or how it will occur or how it will affect reported asset amounts. Although estimates are reasonable
and consistent with current conditions, internal planning and expected future operations, such estimations are subject to
significant uncertainty and judgment.
We performed an impairment test on the well servicing CGU at December 31, 2013 as described in note 6. This CGU has
$89 million of goodwill allocated to it. An increase in the discount rate used by 1% would require an impairment charge being
recognized on the goodwill assigned to the well servicing CGU.
Precision Drilling Corporation 2013 Annual Report 59
(t) Accounting Policies Adopted January 1, 2013
The Corporation adopted IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of
Interests in Other Entities, as well as the consequential amendments to IAS 28 Investments in Associates and Joint Ventures
(2011) and IFRS 13 Fair Value Measurement, with a date of initial application of January 1, 2013.
The adoption of these standards on January 1, 2013 had no impact on the amounts recorded in the Corporation’s financial
statements.
(i) IFRS 10 Consolidated Financial Statements
IFRS 10 introduces a new control model that is applicable to all investees; among other things, it requires the consolidation
of an investee if the Corporation controls the investee on the basis of de facto circumstances.
Subsidiaries are entities controlled by the Corporation. The Corporation controls an entity when it is exposed to, or has rights
to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the
entity. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control
commences until the date that control ceases.
(ii) IFRS 11 Joint Arrangements
Joint arrangements are arrangements of which the Corporation has joint control, established by contracts requiring
unanimous consent for decisions about the activities that significantly affect the arrangements’ returns. Under IFRS 11, joint
arrangements are classified as either joint operations or joint ventures depending on the Corporation’s rights to the assets
and obligations for the liabilities of the arrangements. When making this assessment, the Corporation considers the structure
of the arrangements, the legal form of any separate vehicles, the contractual terms of the arrangement and other facts and
circumstances. Previously, the structure of the arrangement was the sole focus of classification.
The Corporation has no joint arrangements under IFRS 11.
(iii) IFRS 12 Disclosures of Interests in Other Entities
IFRS 12 sets out certain disclosures that are required relating to interests in subsidiaries, associates, joint arrangements
and unconsolidated structured entities. The Corporation does not have any investments that are not consolidated nor has it
entered into any joint arrangements or structured entities.
The Corporation’s subsidiaries, as detailed in Note 25, are all wholly owned. The determination of whether to consolidate
these entities did not involve any significant judgments or assumptions. There are no significant restrictions on the ability
of the Corporation to access or use the assets, and settle the liabilities of the Corporation and its subsidiaries except for
customary limitations in the Corporation’s credit facility.
(iv) IFRS 13 Fair Value Measurement
IFRS 13 defines fair value and sets out a single standard a framework for measuring fair value and the required disclosures
about fair value measurements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the measurement date.
IFRS 13 is applied prospectively to fair value measurements occurring on or after January 1, 2013. The additional disclosure
requirements of IFRS 13 are also applied prospectively and have been presented, as relevant, in the 2013 interim and annual
financial statements.
(u) Accounting Policies not yet Adopted
IFRS 9 Financial Instruments (2010), IFRS 9 Financial Instruments (2009)
IFRS 9 (2009) introduces new requirements for the classification and measurement of financial assets. Under IFRS 9 (2009),
financial assets are classified and measured based on the business model in which they are held and the characteristics
of their contractual cash flows. IFRS 9 (2010) introduces additions relating to financial liabilities. The IASB currently has an
active project to make limited amendments to the classification and measurement requirements of IFRS 9 and add new
requirements to address the impairment of financial assets and hedge accounting.
IFRS 9 (2010 and 2009) is effective for annual periods beginning on or after January 1, 2015, with early adoption permitted.
The Corporation is currently evaluating the impact of adopting this standard on its financial statements.
60 Notes to Consolidated Financial Statements
NOTE 4. PROPERTY, PLANT AND EQUIPMENT
Cost
Accumulated depreciation
Rig equipment
Rental equipment
Other equipment
Vehicles
Buildings
Assets under construction
Land
Cost
2013
2012
$
$
$
5,260,263
(1,698,529)
3,561,734
3,033,159
108,453
78,670
42,993
49,506
219,433
29,520
$
$
$
4,608,381
(1,365,452)
3,242,929
2,819,491
91,351
78,358
40,759
50,585
133,791
28,594
$
3,561,734
$
3,242,929
Rig
Equipment
Rental
Equipment
Other
Equipment
Vehicles
Buildings
Assets
Under
Construction
Land
Total
December 31, 2011
$ 3,441,052 $ 112,707 $ 142,563 $
28,051 $
48,082 $ 336,605 $
20,658 $ 4,129,718
Additions
Disposals
256,661
17,068
18,330
32,994
21,998
512,139
8,867
868,057
(26,796)
(920)
(8,311)
(2,267)
(971)
(38,405)
(857)
(78,527)
Asset decommissioning
(262,192)
–
–
–
–
–
–
(262,192)
Reclassifications
619,351
24,530
19,144
4,959
2,295
(670,279)
–
–
(71)
–
–
–
–
–
–
(71)
Removal of fully
depreciated assets
Effect of foreign
currency exchange
differences
(41,333)
(1,034)
(18)
(541)
665
(6,269)
(74)
(48,604)
December 31, 2012
3,986,743
152,351
171,637
63,196
72,069
133,791
28,594 4,608,381
Additions
Disposals
143,252
6,346
1,651
3,588
(52,659)
(1,126)
(2,971)
(5,324)
–
–
–
380,788
179
535,804
Reclassifications
270,615
10,508
14,141
4,900
825
(300,989)
–
–
(62,080)
–
Effect of foreign
currency exchange
differences
163,445
1,866
936
3,251
2,070
5,843
747
178,158
December 31, 2013
$ 4,511,396 $ 169,945 $ 185,394 $
69,611 $
74,964 $ 219,433 $
29,520 $ 5,260,263
Precision Drilling Corporation 2013 Annual Report 61
Accumulated Depreciation
Rig
Equipment
Rental
Equipment
Other
Equipment
Vehicles
Buildings
Assets
Under
Construction
Land
Total
December 31, 2011
$ 1,008,185 $
54,118 $
87,358 $
17,812 $
19,949 $
– $
– $ 1,187,422
Depreciation expense
274,129
7,901
14,280
6,917
2,341
Disposals
(35,697)
(785)
(8,213)
(2,132)
(884)
Asset decommissioning
(69,723)
–
Reclassifications
60
(156)
–
646
–
16
–
(566)
Removal of fully
depreciated assets
Effect of foreign
currency exchange
differences
–
–
(71)
–
–
(9,702)
(78)
(721)
(176)
644
December 31, 2012
1,167,252
61,000
93,279
22,437
21,484
Depreciation expense
295,807
9,695
15,518
8,299
3,774
Disposals
(43,423)
(1,007)
(2,937)
(5,069)
8,314
(8,557)
273
(20)
–
(10)
Reclassifications
Effect of foreign
currency exchange
differences
December 31, 2013
$ 1,478,237 $
61,492 $ 106,724 $
26,618 $
25,458 $
50,287
361
591
971
210
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
305,568
(47,711)
(69,723)
–
(71)
–
(10,033)
– 1,365,452
–
–
–
333,093
(52,436)
–
–
– $
–
52,420
– $ 1,698,529
In 2012, the Corporation incurred a $192.5 million loss on the decommissioning of certain drilling rigs. The assets were
decommissioned due to the inefficient nature of the assets and the high cost to maintain. The charge was allocated fully to the
Contract Drilling Services segment.
During 2012, the Corporation reviewed the remaining economic lives of certain drilling rigs and determined that, due to current
market conditions, the lives of these rigs should be reduced to four years and depreciation be charged on a straight-line basis to
their estimated salvage value. The effect of this change was to increase depreciation expense by $21.3 million in 2012.
62 Notes to Consolidated Financial Statements
NOTE 5. INTANGIBLES
Cost
Accumulated amortization
Customer relationships
Patents and brands
Loan commitment fees related to revolving credit facility
Cost
December 31, 2011
Business acquisitions
Additions
Effect of foreign currency exchange differences
Removal of fully amortized assets
December 31, 2012
Business acquisitions
Additions
Effect of foreign currency exchange differences
Removal of fully amortized assets
2013
12,221
(8,304)
3,917
616
16
3,285
3,917
$
$
$
$
$
$
$
$
Customer
Relationships
Patents and
Brands
Loan
Commitment
Fees
$
4,600
$
420
$
4,905
$
–
–
(25)
4,575
–
–
78
(1,128)
–
–
(8)
(359)
53
–
–
–
–
–
2,855
–
–
7,760
12,388
–
883
–
–
–
883
78
(1,128)
2012
12,388
(6,287)
6,101
1,890
21
4,190
6,101
Total
9,925
–
2,855
(33)
(359)
December 31, 2013
$
3,525
$
53
$
8,643
$
12,221
Accumulated Amortization
Customer
Relationships
Patents and
Brands
December 31, 2011
Amortization expense
Effect of foreign currency exchange differences
Removal of fully amortized assets
December 31, 2012
Amortization expense
Effect of foreign currency exchange differences
Removal of fully amortized assets
$
1,317
1,376
(8)
–
2,685
1,294
58
(1,128)
$
302
$
96
(7)
(359)
32
5
–
–
Loan
Commitment
Fees
$
1,835
1,735
–
–
3,570
1,788
–
–
December 31, 2013
$
2,909
$
37
$
5,358
$
Total
3,454
3,207
(15)
(359)
6,287
3,087
58
(1,128)
8,304
Precision Drilling Corporation 2013 Annual Report 63
NOTE 6. GOODWILL
Balance, December 31, 2011
Business acquisitions
Impairment charge
Exchange adjustment
Balance, December 31, 2012
Exchange adjustment
Balance, December 31, 2013
$
363,646
25
(52,539)
(580)
310,552
1,804
$
312,356
The Corporation performed an impairment test on the well servicing CGU at December 31, 2013. This CGU has $89 million
of goodwill allocated to it. The cash flow projections used in performing the impairment test were based on future expected
outcomes taking into account past experience and management expectation of future market conditions. No terminal value
growth rate was used due to the finite lives of the underlying assets of the CGU. An increase in the discount rate used by 1% would
require an impairment charge being recognized on the goodwill assigned to the well servicing CGU.
During 2012 the Corporation determined that the carrying value of the goodwill allocated to the Canadian directional drilling CGU
exceeded its recoverable amount and recognized an impairment loss of $52.5 million. The recoverable amount was based on its
value in use determined by discounting expected future cash flows to be generated from the continuing use of the assets within
the CGU.
Key assumptions used in the calculation of value in use included a discount rate of 15%, terminal value growth rate of nil % and
average projected annual cash flow growth over the next four years of 40%. No terminal value growth rate was used due to the
finite lives of the underlying assets of the CGU. Projected cash flow was based on future expected outcomes taking into account
past experience and management expectation of future market conditions. A 10% change in the key assumptions would not
change the amount of the impairment loss recognized.
NOTE 7. BANK INDEBTEDNESS
At December 31, 2013 and 2012, Precision had available $40.0 million and US$15.0 million under secured operating facilities,
and a secured US$25.0 million facility for the issuance of letters of credit and performance and bid bonds to support international
operations. As at December 31, 2013 and 2012, no amounts had been drawn on any of the facilities. Availability of the $40.0 million
and US$25.0 million facility were reduced by outstanding letters of credit in the amount of $17.3 million (2012 – $18.9 million)
and US$0.2 million (2012 – US $nil), respectively. The facilities are primarily secured by charges on substantially all present and
future property of Precision and its material subsidiaries. Advances under the $40.0 million facility 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, and under the US$15.0 million and US$25.0 million facilities at the bank’s prime lending rate.
64 Notes to Consolidated Financial Statements
NOTE 8. SHARE BASED COMPENSATION PLANS
Liability Classified Plans
Deferred
Share Units
Restricted
Share Units
Performance
Share Units
Share
Appreciation
Rights
Non-
Management
Directors’ DSUs
Total
December 31, 2011
$
762
$
12,529
$
25,250
$
1,693
$
–
$
40,234
Expensed (recovered) during the period
Payments
December 31, 2012
Expensed (recovered) during the period
Payments and redemptions
December 31, 2013
Current
Long-term
(44)
(718)
–
–
–
–
–
–
–
$
$
$
5,094
(7,938)
9,685
11,622
(7,769)
6,022
(17,494)
13,778
8,137
(8,953)
(1,195)
(1)
497
(251)
–
816
–
816
1,245
(207)
10,693
(26,151)
24,776
20,753
(16,929)
$
13,538
$
12,962
$
246
$
1,854
$
28,600
$
9,027
$
4,896
$
246
$
–
$
14,169
4,511
8,066
–
1,854
14,431
$
13,538
$
12,962
$
246
$
1,854
$
28,600
(a) Restricted Share Units and Performance Share Units
Precision has two cash settled share based incentive plans for officers and other eligible employees. Under the Restricted Share
Unit (RSU) incentive plan shares granted to eligible employees vest annually over a three year term. Vested shares are automatically
paid out in cash at a value determined by the fair market value of the shares at the vesting date. Under the Performance Share Unit
(PSU) incentive plan shares granted to eligible employees vest at the end of a three-year term. Vested shares are automatically
paid out in cash in the first quarter following the vested term at a value determined by the fair market value of the shares at the
vesting date and based on the number of performance shares held multiplied by a performance factor that ranges from zero to
two times. The performance factor is based on Precision’s share price performance compared to a peer group over the three-year
period. A summary of the RSUs and PSUs outstanding under these share based incentive plans is presented below:
December 31, 2011
Granted
Issued as a result of cash dividends
Redeemed
Forfeitures
December 31, 2012
Granted
Issued as a result of cash dividends
Redeemed
Forfeitures
December 31, 2013
RSUs
Outstanding
1,836,830
1,117,850
11,566
(864,857)
(221,139)
1,880,250
1,295,739
51,113
(869,744)
(243,863)
PSUs
Outstanding
2,129,508
802,000
11,972
(851,499)
(143,029)
1,948,952
1,258,650
54,623
(696,171)
(128,126)
2,113,495
2,437,928
Precision Drilling Corporation 2013 Annual Report 65
(b) Share Appreciation Rights
The Corporation has a U.S. dollar denominated Share Appreciation Rights (SAR) plan under which eligible participants were
granted SARs that entitle the rights holder to receive cash payments calculated as the excess of the market price over the
exercise price per share on the exercise date. The SARs vest over a period of 5 years and expire 10 years from the date of grant.
At December 31, 2013, the intrinsic value of these awards was $7,000 (2012 – $nil).
Share Appreciation Rights
December 31, 2011
Exercised
Forfeited
December 31, 2012
Forfeited
December 31, 2013
Range of Exercise Prices (US$):
$ 9.26 – 11.99
12.00 – 14.99
15.00 – 17.38
$ 9.26 – 17.38
Outstanding
Range of
Exercise Price
(US$)
Weighted
Average Exercise
Price (US$)
705,688
$ 9.26 – 17.92
$ 14.83
(721)
9.26 – 9.59
(26,725)
678,242
(90,080)
15.22 – 17.92
9.26 – 17.38
13.26 – 17.38
9.45
15.55
14.81
15.42
Exercisable
705,688
678,242
588,162
$ 9.26 – 17.38
$ 14.71
588,162
Total SARs Outstanding and Exercisable
Weighted
Average Exercise
Price (US$)
$ 9.26
13.26
15.82
$ 14.71
Weighted Average
Remaining
Contractual Life
(Years)
1.23
1.10
3.43
2.71
Number
59,903
100,844
427,415
588,162
(c) Non-Management Directors
Effective January 1, 2012, Precision instituted a new deferred share unit plan for non-management directors whereby fully vested
deferred share units are granted quarterly based on an election by the non-management director to receive all or a portion of their
compensation in deferred share units. These deferred share units are redeemable in cash or for an equal number of common
shares upon the director’s retirement. The redemption of deferred share units in cash or common shares is solely at Precision’s
discretion. Non-management directors can receive a lump sum payment or two separate payments any time up until December 15
of the year following retirement. If the non-management director does not specify a redemption date, the deferred share units will
be redeemed on a single date six months after retirement. The cash settlement amount is based on the weighted average trading
price for Precision’s shares on the Toronto Stock Exchange for the five days immediately prior to payout. A summary of the DSUs
outstanding under this share based incentive plan is presented below:
Deferred Share Units
January 1, 2011
Granted
Issued as a result of cash dividends
December 31, 2012
Granted
Issued as a result of cash dividends
Redeemed
December 31, 2013
66 Notes to Consolidated Financial Statements
Outstanding
–
101,535
429
101,964
105,338
2,836
(21,563)
188,575
Equity Settled Plans
(d) Non-Management Directors
Prior to January 1, 2012, Precision had a deferred share unit plan for non-management directors. Under the plan fully vested
deferred share units were granted quarterly based on an election by the non-management director to receive all or a portion of
their compensation in deferred share units. These deferred share units are redeemable into an equal number of common shares
any time after the director’s retirement. A summary of this share based incentive plan is presented below:
Deferred Share Units
December 31, 2011
Issued as a result of cash dividends
Redeemed
December 31, 2012
Issued as a result of cash dividends
Redeemed
December 31, 2013
Outstanding
417,495
1,630
(83,179)
335,946
5,459
(120,293)
221,112
(e) Option Plan
The Corporation has a share option plan under which a combined total of 16,569,134 options to purchase common shares are
reserved to be granted to employees. Of the amount reserved, 9,357,588 options have been granted. Under this plan, the exercise
price of each option equals the fair market of the option at the date of grant determined by the weighted average trading price
for the five days preceding the grant. The options are denominated in either Canadian or U.S. dollars, and vest over a period of
three years from the date of grant as employees render continuous service to the Corporation and have a term of seven years.
A summary of the status of the equity incentive plan is presented below:
Canadian share options
December 31, 2011
Granted
Exercised
Forfeitures
December 31, 2012
Granted
Exercised
Forfeitures
Options
Outstanding
Range of
Exercise Prices
3,267,571
$
5.22 – 14.50
$
1,117,050
(237,545)
(133,279)
4,013,797
1,237,500
(172,158)
(178,253)
7.15 – 10.67
5.85 – 10.44
5.85 – 14.50
5.22 – 14.50
7.82 – 9.02
5.85 – 10.67
5.85 – 14.50
December 31, 2013
4,900,886
$
5.22 – 14.50
$
U.S. share options
December 31, 2011
Granted
Exercised
Forfeitures
December 31, 2012
Granted
Exercised
Forfeitures
Options
Outstanding
Range of
Exercise Prices
(US$)
1,886,552
$
4.95 – 15.21
$
867,000
(72,409)
(281,163)
2,399,980
1,025,100
(189,887)
(61,385)
7.14 – 10.74
4.95 – 10.55
4.95 – 15.21
4.95 – 15.21
8.99 – 9.28
4.95 – 10.55
7.14 – 15.21
December 31, 2013
3,173,808
$
4.95 – 15.21
$
Weighted
Average
Exercise Price
8.45
10.60
6.01
10.27
9.13
8.99
7.43
9.77
9.14
Weighted
Average
Exercise Price
(US$)
8.61
10.58
6.94
9.84
9.23
9.00
5.89
10.82
9.32
Options
Exercisable
1,008,305
1,846,603
2,676,865
Options
Exercisable
396,188
935,035
1,438,335
Precision Drilling Corporation 2013 Annual Report 67
The weighted average share price at the date of exercise for share options exercised in 2013 was $10.11 (2012 – $9.42) for the
Canadian share options and US$9.90 (2012 – US$10.10) for the U.S. share options.
The range of exercise prices for options outstanding at December 31, 2013 is as follows:
Canadian share options
Total Options Outstanding
Exercisable Options
Range of Exercise Prices:
$ 5.22 – 6.99
7.00 – 8.99
9.00 – 14.50
$ 5.22 – 14.50
Number
706,438
981,297
3,213,151
Weighted
Average
Exercise Price
$ 5.85
8.53
10.04
4,900,886
$ 9.14
Weighted Average
Remaining
Contractual Life
(Years)
2.35
3.25
5.16
4.37
Number
706,438
942,662
1,027,765
Weighted
Average
Exercise Price
$ 5.85
8.56
10.62
2,676,865
$ 8.64
U.S. share options
Total Options Outstanding
Exercisable Options
Weighted
Average
Exercise Price
(US$)
Weighted Average
Remaining
Contractual Life
(Years)
Range of Exercise Prices (US$):
$ 4.95 – 5.99
6.00 – 8.99
9.00 – 15.21
$ 4.95 – 15.21
Number
188,872
1,606,533
1,378,403
$ 4.95
8.55
10.82
3,173,808
$ 9.32
2.35
5.08
4.67
4.74
Weighted
Average
Exercise Price
(US$)
$ 4.95
7.82
10.89
Number
188,872
581,195
668,268
1,438,335
$ 8.87
The per option weighted average fair value of the share options granted during 2013 was $3.26 (2012 – $4.79) estimated on
the grant date using the Black-Scholes option pricing model with the following assumption: average risk-free interest rate 1%
(2012 – 1%), average expected life of four years (2012 – four years), expected forfeiture rate of 5% (2012 – 5%) and expected
volatility of 53% (2012 – 59%). Included in net earnings for the year ended December 31, 2013 is an expense of $7.0 million
(2012 – $7.9 million).
68 Notes to Consolidated Financial Statements
NOTE 9. PROVISIONS AND OTHER
Balance December 31, 2011
Expensed during the year
Payment of deductibles and uninsured claims
Effects of foreign currency exchange differences
Balance December 31, 2012
Expensed during the year
Payment of deductibles and uninsured claims
Effects of foreign currency exchange differences
Balance December 31, 2013
Current
Long-term
Workers’
Compensation
$
$
$
$
23,984
11,604
(8,436)
(551)
26,601
4,350
(8,546)
1,781
24,186
2012
8,783
17,818
26,601
2013
6,350
17,836
24,186
$
$
Precision maintains a provision for the deductible and uninsured portions of workers’ compensation and general liability claims.
The amount accrued for the provision for losses incurred varies depending on the number and nature of the claims outstanding at
the balance sheet dates. In addition, the accrual includes management’s estimate of the future cost to settle each claim such as
future changes in the severity of the claim and increases in medical costs. Precision uses third parties to assist in developing the
estimate of the ultimate costs to settle each claim, which is based on historical experience associated with the type of each claim
and specific information related to each claim. The specific circumstances of each claim may change over time prior to settlement
and, as a result, the estimates made as of the balance sheet dates may change.
NOTE 10. LONG-TERM DEBT
Secured revolving credit facility
Unsecured senior notes:
6.625% senior notes due 2020 (US$650.0 million)
6.5% senior notes due 2021 (US$400.0 million)
6.5% senior notes due 2019
Less net unamortized debt issue costs
2013
$
29,781
$
691,340
425,440
200,000
2012
–
646,685
397,960
200,000
1,346,561
1,244,645
(23,293)
(25,849)
$
1,323,268
$
1,218,796
Precision Drilling Corporation 2013 Annual Report 69
(a) Secured Revolving Credit Facility
The secured revolving credit facility provides Precision with senior secured financing for general corporate purposes, including
for acquisitions, of up to US$850 million with a provision for an increase in the facility of up to an additional US$250 million.
The secured revolving credit facility is secured by charges on substantially all of Precision’s present and future assets and the
present and future assets of its material U.S. and Canadian subsidiaries and, if necessary, in order to adhere to covenants under
the revolving credit facility, on certain assets of certain subsidiaries organized in a jurisdiction outside of Canada or the U.S.
The secured revolving credit facility requires that Precision comply with certain financial covenants including leverage ratios of
consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (EBITDA)
of less than 3:1 and consolidated total debt to EBITDA of less than 4:1 for the most recent four consecutive fiscal quarters; and
a interest coverage ratio of greater than 2.75:1 for the most recent four consecutive fiscal quarters. As well the revolving credit
facility contains certain covenants that place restrictions on Precision’s ability to dispose of assets; make or pay dividends,
share redemptions or other distributions; change its primary business; incur liens on assets; enter into mergers, consolidations
or amalgamations; and enter into speculative swap agreements. At December 31, 2013, Precision was in compliance with the
covenants of the revolving credit facility.
The revolving credit facility has a term of five years, with an annual option on Precision’s part to request that the lenders extend,
at their discretion, the facility to a new maturity date not to exceed five years from the date of the extension request. The current
maturity date of the revolving credit facility is November 17, 2018.
Under the revolving credit facility amounts can be drawn in U.S. dollars and/or Canadian dollars and as at December 31,
2013, US$28.0 was outstanding (2012 – $nil). Up to US$200 million of the revolving credit facility is available for letters of
credit denominated in U.S and/or Canadian dollars and as at December 31, 2013 outstanding letters of credit amounted to
US$28.6 million (2012 – US$26.8 million).
The interest rate on loans that are denominated in U.S. dollars is, at the option of Precision, either a margin over a U.S. base rate
or a margin over LIBOR. The interest rate on loans denominated in Canadian dollars is, at the option of Precision, either a margin
over the Canadian prime rate or a margin over the bankers’ acceptance rate; such margins will be based on the then applicable
ratio of consolidated total debt to EBITDA.
(b) Unsecured Senior Notes
Precision has outstanding the following unsecured senior notes:
US$650.0 million of 6.625% Senior Notes due 2020. These notes bear interest at a fixed rate of 6.625% per annum, and
mature on November 15, 2020. Interest is payable semi-annually on May 15 and November 15 of each year
$200.0 million of 6.5% Senior Notes due 2019. These notes bear interest at a fixed rate of 6.5% per annum, and mature on
March 15, 2019. Interest is payable semi-annually on March 15 and September 15 of each year.
US$400.0 million of 6.5% Senior Notes due 2021. These notes bear interest at a fixed rate of 6.5% per annum, and mature
on December 15, 2021. Interest is payable semi-annually on June 15 and December 15 of each year.
The 6.625% Senior Notes due 2020 and the 6.5% Senior Notes due 2019 are unsecured, ranking equally with existing and
future senior unsecured indebtedness, and have been guaranteed by current and future U.S. and Canadian subsidiaries that
guaranteed the revolving credit facility. These notes contain certain covenants that limit Precision’s ability and the ability of certain
subsidiaries to incur additional indebtedness and issue preferred stock; create liens; make restricted payments; create or permit
to exist restrictions on the ability of Precision or certain subsidiaries to make certain payments and distributions; engage in
amalgamations, mergers or consolidations; make certain dispositions and transfers of assets; and engage in transactions with
affiliates. If the notes receive an investment grade rating by Standard & Poor’s and Moody’s Investors Service and Precision
and its subsidiaries are not in default under the indenture governing the notes, then Precision will not be required to comply with
particular covenants contained in the indenture.
70 Notes to Consolidated Financial Statements
The 6.5% Senior Notes due 2021 are unsecured, ranking equally with existing and future senior unsecured indebtedness, and
have been guaranteed by current and future U.S. and Canadian subsidiaries that guaranteed the revolving credit facility. These
notes contain certain covenants that limit Precision’s ability and the ability of certain subsidiaries to incur additional indebtedness
and issue preferred stock; create liens; make restricted payments; create or permit to exist restrictions on the ability of Precision
or certain subsidiaries to make certain payments and distributions; engage in amalgamations, mergers or consolidations; make
certain dispositions and transfers of assets; and engage in transactions with affiliates. If the notes receive an investment grade
rating by Standard & Poor’s or Moody’s Investors Service and Precision and its subsidiaries are not in default under the indenture
governing the notes, then Precision will not be required to comply with particular covenants contained in the indenture.
Prior to November 15, 2015, Precision may redeem the 6.625% Senior Notes due 2020 in whole or in part at 100.0% of their
principal amount, plus accrued interest and the greater of 1.0% of the principal amount of the note to be redeemed and the excess,
if any, of the present value of the November 15, 2015 redemption price plus required interest payments through November 15,
2015 (calculated using the United States Treasury rate plus 50 basis points) over the principal amount of the note. As well,
Precision may redeem these notes in whole or in part at any time on or after November 15, 2015 and before November 15, 2018,
at redemption prices ranging between 103.313% and 101.104% of their principal amount plus accrued interest. Any time on or
after November 15, 2018 these notes can be redeemed for their principal amount plus accrued interest. Upon specified change
of control events, each holder of a note will have the right to sell to Precision all or a portion of its notes at a purchase price in cash
equal to 101% of the principal amount, plus accrued interest to the date of purchase.
Prior to March 15, 2014, Precision may redeem up to 35% of the 6.5% Senior Notes due 2019 with the net proceeds of certain
equity offerings at a redemption price equal to 106.5% of the principal amount plus accrued interest. Prior to March 15, 2015,
Precision may redeem these notes in whole or in part at 100.0% of their principal amount, plus accrued interest and the greater
of 1.0% of the principal amount of the note to be redeemed and the excess, if any, of the present value of the March 15, 2015
redemption price plus required interest payments through March 15, 2015 (calculated using the Government of Canada rate plus
100 basis points) over the principal amount of the note. As well, Precision may redeem these notes in whole or in part at any
time on or after March 15, 2015 and before March 15, 2017, at redemption prices ranging between 103.250% and 101.6254% of
their principal amount plus accrued interest. Any time on or after March 15, 2017 these notes can be redeemed for their principal
amount plus accrued interest. Upon specified change of control events, each holder of a note will have the right to sell to Precision
all or a portion of its notes at a purchase price in cash equal to 101% of the principal amount, plus accrued interest to the date
of purchase.
Prior to December 15, 2014, Precision may redeem up to 35% of the 6.5% Senior Notes due 2021 with the net proceeds of certain
equity offerings at a redemption price equal to 106.5% of the principal amount plus accrued interest. Prior to December 15, 2016,
Precision may redeem these notes in whole or in part at 100.0% of their principal amount, plus accrued interest and the greater
of 1.0% of the principal amount of the note to be redeemed and the excess, if any, of the present value of the December 15,
2016 redemption price plus required interest payments through December 15, 2016 (calculated using the United States Treasury
rate plus 50 basis points) over the principal amount of the note. As well, Precision may redeem these notes in whole or in part at
any time on or after December 15, 2016 and before December 15, 2019, at redemption prices ranging between 103.250% and
101.083% of their principal amount plus accrued interest. Any time on or after December 15, 2019 these notes can be redeemed
for their principal amount plus accrued interest. Upon specified change of control events, each holder of a note will have the right
to sell to Precision all or a portion of its notes at a purchase price in cash equal to 101% of the principal amount, plus accrued
interest to the date of purchase.
Long-term debt obligations at December 31, 2013 will mature as follows:
2018
Thereafter
$
29,781
1,316,780
$
1,346,561
Precision Drilling Corporation 2013 Annual Report 71
(c) Guarantor Disclosures
The following presents supplemental condensed consolidating financial information for the parent company, guarantor subsidiaries
and the non-guarantor subsidiaries, respectively.
Condensed Consolidating Statement of Financial Position as at December 31, 2013
Parent
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
Assets
Cash
Other current assets
Intercompany receivables
Investments in subsidiaries
Income tax recoverable
Property, plant and equipment
Intangibles
Goodwill
Total assets
Liabilities and Shareholders’ Equity
Current liabilities
Intercompany payables and debt
Long-term debt
Other long-term liabilities
Total liabilities
Shareholders’ equity
$
27,160
$
23,039
$
30,407
$
3,592
424,178
5,904,795
–
56,501
3,286
–
6,419,512
40,624
2,442,373
1,323,268
263,410
4,069,675
2,349,837
$
$
456,574
2,342,467
69
–
3,261,610
631
312,356
6,396,746
240,052
202,986
–
262,308
705,346
5,691,400
$
$
–
3
$
80,606
562,075
101,906
74,795
(2,841,440)
–
(5,904,864)
58,435
243,858
–
–
–
(235)
–
–
$
$
$
$
509,401
$
(8,746,536)
56,222
$
–
196,081
(2,841,440)
–
(6,104)
246,199
263,202
–
–
(2,841,440)
(5,905,096)
–
–
58,435
3,561,734
3,917
312,356
4,579,123
336,898
–
1,323,268
519,614
2,179,780
2,399,343
Total liabilities and shareholders’ equity
$
6,419,512
$
6,396,746
$
509,401
$
(8,746,536)
$
4,579,123
Condensed Consolidating Statement of Financial Position as at December 31, 2012
Parent
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
Assets
Cash
Other current assets
Intercompany receivables
Investments in subsidiaries
Income tax recoverable
Property, plant and equipment
Intangibles
Goodwill
Total assets
Liabilities and Shareholders’ Equity
Current liabilities
Intercompany payables and debt
Long-term debt
Other long-term liabilities
Total liabilities
Shareholders’ equity
$
114,709
$
15,709
$
22,350
$
9,238
394,112
5,412,168
9,441
57,939
4,190
–
6,001,797
103,383
2,200,650
1,218,796
245,377
3,768,206
2,233,591
$
$
465,695
2,082,616
3,099
–
3,043,239
1,911
310,552
5,922,821
264,788
185,855
–
273,547
724,190
5,198,631
$
$
–
3
$
152,768
523,334
48,398
65,279
(2,542,007)
–
(5,415,267)
55,138
142,104
–
–
–
(353)
–
–
$
$
$
$
333,269
$
(7,957,624)
29,910
$
–
155,502
(2,542,007)
–
(6,838)
178,574
154,695
–
–
(2,542,007)
(5,415,617)
–
–
64,579
3,242,929
6,101
310,552
4,300,263
398,081
–
1,218,796
512,086
2,128,963
2,171,300
Total liabilities and shareholders’ equity
$
6,001,797
$
5,922,821
$
333,269
$
(7,957,624)
$
4,300,263
72 Notes to Consolidated Financial Statements
Condensed Consolidating Statement of Earnings (Loss) for the Year ended December 31, 2013
Revenue
Operating expense
$
General and administrative expense
Earnings (loss) before income taxes,
finance charges, foreign exchange,
and depreciation and amortization
Depreciation and amortization
Operating earnings (loss)
Foreign exchange
Finance charges
Equity in earnings of subsidiaries
Earnings (loss) before tax
Income taxes
Net earnings (loss)
Parent
143
273
29,174
(29,304)
7,393
(36,697)
(3,356)
92,112
(360,468)
235,015
43,615
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$
1,912,750
$
137,681
$
(20,597)
$
2,029,977
1,148,786
101,407
120,175
11,926
662,557
309,939
352,618
(5,198)
1,141
–
356,675
(15,431)
5,580
15,576
(9,996)
(558)
(5)
–
(9,433)
2,204
(20,597)
1,248,637
–
–
251
(251)
–
–
360,468
(360,719)
–
142,507
638,833
333,159
305,674
(9,112)
93,248
–
221,538
30,388
$
191,400
$
372,106
$
(11,637)
$
(360,719)
$
191,150
Condensed Consolidating Statement of Earnings (Loss) for the Year ended December 31, 2012
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$
1,986,590
$
64,779
$
(10,779)
$
2,040,741
$
Parent
151
82
27,246
1,173,157
94,014
80,841
5,388
Revenue
Operating expense
General and administrative expense
Earnings (loss) before income taxes,
finance charges, foreign exchange,
impairment of goodwill, loss on
asset decommissioning and
depreciation and amortization
Depreciation and amortization
Loss on asset decommissioning
Operating earnings (loss)
Impairment of goodwill
Foreign exchange
Finance charges
Equity in earnings of subsidiaries
Earnings (loss) before tax
Income taxes
Net earnings (loss)
(27,177)
3,405
–
(30,582)
–
4,252
86,780
(196,489)
74,875
30,011
719,419
303,693
192,469
223,257
52,539
(189)
48
–
170,859
(49,342)
(21,450)
7,922
–
(29,372)
–
(310)
1
–
(29,063)
(5,352)
(10,779)
1,243,301
–
–
(7,495)
–
7,495
–
–
–
196,489
(188,994)
–
126,648
670,792
307,525
192,469
170,798
52,539
3,753
86,829
–
27,677
(24,683)
$
44,864
$
220,201
$
(23,711)
$
(188,994)
$
52,360
Precision Drilling Corporation 2013 Annual Report 73
Condensed Consolidating Statement of Comprehensive Income (Loss) for the Year ended December 31, 2013
Net earnings
Other comprehensive income (loss)
Comprehensive income (loss)
Parent
191,400
(72,135)
119,265
$
$
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
$
$
372,106
98,105
470,211
$
$
(11,637)
10,720
(917)
$
$
(360,719)
370
(360,349)
$
$
Condensed Consolidating Statement of Comprehensive Income (Loss) for the Year ended December 31, 2012
Net earnings
Other comprehensive income (loss)
Comprehensive income (loss)
Parent
44,864
23,205
68,069
$
$
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
$
$
220,201
(30,899)
189,302
$
$
(23,711)
(1,934)
(25,645)
$
$
(188,994)
(45)
(189,039)
$
$
Total
191,150
37,060
228,210
Total
52,360
(9,673)
42,687
Condensed Consolidating Statement of Cash Flow for the Year ended December 31, 2013
Cash provided by (used in):
Operations
Investments
Financing
Effects of exchange rate changes on
cash and cash equivalents
Increase (decrease) in cash and
cash equivalents
Cash and cash equivalents,
beginning of year
Parent
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$
(207,558)
$
693,757
$
(58,113)
$
–
$
428,086
96,685
21,517
1,807
(87,549)
(458,810)
(229,688)
2,071
7,330
(68,951)
134,229
892
8,057
114,709
15,709
22,350
(95,459)
95,459
–
–
–
–
(526,535)
21,517
4,770
(72,162)
152,768
$
80,606
Cash and cash equivalents, end of year
$
27,160
$
23,039
$
30,407
$
Condensed Consolidating Statement of Cash Flow for the Year ended December 31, 2012
Parent
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$
(135,797)
$
775,145
$
(65,654)
$
61,592
$
635,286
(171,158)
(14,899)
(806,436)
41,996
(43,971)
111,040
91,444
(153,036)
Cash provided by (used in):
Operations
Investments
Financing
Effects of exchange rate changes on
cash and cash equivalents
Increase (decrease) in cash and
cash equivalents
Cash and cash equivalents,
beginning of year
(4,197)
(811)
(326,051)
440,760
9,894
5,815
34
1,449
20,901
Cash and cash equivalents, end of year
$
114,709
$
15,709
$
22,350
$
74 Notes to Consolidated Financial Statements
(930,121)
(14,899)
(4,974)
(314,708)
467,476
$
152,768
–
–
–
–
NOTE 11. INCOME TAXES
The provision for income taxes differs from that which would be expected by applying statutory Canadian income tax rates.
A reconciliation of the difference at December 31 is as follows:
Earnings before income taxes
Federal and provincial statutory rates
Tax at statutory rates
Adjusted for the effect of:
Non-deductible expenses
Non-taxable capital gains
Income taxed at lower rates
Impact of foreign tax rates
Withholding taxes
Taxes related to prior years
Other
Income tax expense (recovery)
$
$
$
$
2013
221,538
25%
55,385
4,097
(626)
(31,118)
(5,957)
3,343
4,738
526
2012
27,677
25%
6,919
15,975
(546)
(30,191)
(26,559)
4,009
1,053
4,657
$
30,388
$
(24,683)
The net deferred tax liability is comprised of the tax effect of the following temporary differences:
Deferred income tax liability:
Property, plant and equipment and intangibles
$
749,760
$
686,833
2013
2012
Partnership deferrals
Debt issue costs
Other
Deferred income tax assets:
Losses (expire from time to time up to 2033)
Long-term incentive plan
Other
Net deferred income tax liability
34,938
2,966
6,569
60,906
1,561
4,260
794,233
753,560
285,438
14,800
6,648
244,888
13,917
9,163
$
487,347
$
485,592
Included in the net deferred tax liability is $257.8 million (2012 – $242.6 million) of tax effected temporary differences related to
the Corporation’s United States operations. As at December 31, 2013, the Corporation had unrecognized net deferred tax assets
related to its foreign operations of $7.2 million (2012 – $5.9 million).
Precision Drilling Corporation 2013 Annual Report 75
The movement in temporary differences is as follows:
Property,
Plant and
Equipment
and
Intangibles
Other
Deferred
Income Tax
Liabilities
Partnership
Deferrals
Losses
Debt Issue
Costs
Long-Term
Incentive
Plan
Other
Deferred
Income Tax
Assets
Net
Deferred
Income Tax
Liability
December 31, 2011
$ 735,815
$ 91,319
$
5,704
$ (221,982)
$
(2,568)
$ (13,026)
$
(7,472)
$ 587,790
Recognized in net earnings
(37,034)
(30,413)
(1,413)
(27,784)
4,129
(1,058)
(1,686)
(95,259)
Effect of foreign currency
exchange differences
(11,948)
–
(31)
4,878
December 31, 2012
686,833
60,906
4,260
(244,888)
Recognized in net earnings
28,176
(25,968)
2,312
(22,968)
–
1,561
1,405
167
(5)
(6,939)
(13,917)
(9,163)
485,592
(173)
2,587
(14,629)
Effect of foreign currency
exchange differences
34,751
–
(3)
(17,582)
–
(710)
(72)
16,384
December 31, 2013
$ 749,760
$ 34,938
$
6,569
$ (285,438)
$
2,966
$ (14,800)
$
(6,648)
$ 487,347
On December 31, 2013, Precision had $30.9 million (2012 – $34.4 million) of unrecognized tax benefits that, if recognized,
would have a favourable impact on Precision’s effective income tax rate in future periods. Precision classifies interest accrued
on unrecognized tax benefits and income tax penalties as income tax expense. Included in the unrecognized tax benefit, as at
December 31, 2013 was interest and penalties of $10.1 million (2012 – $9.2 million).
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
2013
2012
$
34,357
$
34,300
2,031
2,033
(5,458)
(1,976)
$
30,930
$
34,357
It is anticipated that approximately $0.5 million (2012 – $0.6 million) of an unrecognized tax position that relates to prior year
activities will be realized during the next 12 months. Subject to the results of audit examinations by taxing authorities and/or
legislative changes by taxing jurisdictions, Precision does not anticipate further adjustments of unrecognized tax positions during
the next 12 months that would have a material impact on the financial statements of Precision.
76 Notes to Consolidated Financial Statements
NOTE 12. SHAREHOLDERS’ CAPITAL
(a) Authorized – unlimited number of voting common shares
– unlimited number of preferred shares, issuable in series, limited to an amount
equal to one half of the issued and outstanding common shares
(b) Issued
Common shares
December 31, 2011
Options exercised – cash consideration
– reclassification from contributed surplus
Issued on redemption of non-management directors’ DSUs
Issued on waiver of right to dissent by dissenting unitholder
December 31, 2012
Options exercised – cash consideration
– reclassification from contributed surplus
Issued on redemption of non-management directors’ DSUs
Issued on exercise of warrants
December 31, 2013
Number
Amount
276,081,797
$
2,248,217
309,954
–
83,179
840
1,926
1,124
706
9
276,475,770
$
2,251,982
362,045
–
141,856
15,000,000
2,432
1,275
1,238
48,300
291,979,671
$
2,305,227
(c) Dividends
During 2013, the Corporation approved and paid dividends of $0.21 per common share (2012 – $0.05) for total payments of
$58 million (2012 – $14 million). On February 12, 2014, the Board of Directors declared a dividend of $0.06 per common share
payable on March 14, 2014 to shareholders of record on February 27, 2014.
NOTE 13. ACCUMULATED OTHER COMPREHENSIVE LOSS
December 31, 2011
Other comprehensive loss
December 31, 2012
Other comprehensive income
December 31, 2013
Unrealized
Foreign Currency
Translation Gains
(Losses)
Foreign Exchange
Gain (Loss) on Net
Investment Hedge
Accumulated
Other
Comprehensive
Loss
$
(27,987)
$
(22,875)
$
(50,862)
(32,878)
(60,865)
109,195
23,205
330
(72,135)
(9,673)
(60,535)
37,060
$
48,330
$
(71,805)
$
(23,475)
Precision Drilling Corporation 2013 Annual Report 77
NOTE 14. FINANCE CHARGES
Interest:
Long-term debt
Other
Income
Amortization of debt issue costs
Debt amendment fees
Other
Finance charges
2013
2012
$
88,516
$
85,113
1,356
(967)
4,343
–
–
138
(1,933)
4,120
149
(758)
$
93,248
$
86,829
NOTE 15. EMPLOYEE BENEFIT PLANS
The Corporation has a defined contribution pension plan covering a significant number of its employees. Under this plan, the
Corporation matches individual contributions up to 5% of the employee’s eligible compensation. Total expense under the defined
contribution plan in 2013 was $13.0 million (2012 – $11.1 million).
NOTE 16. RELATED PARTY TRANSACTIONS
Compensation of Key Management Personnel
The remuneration of key management personnel is as follows:
Salaries and other benefits
Equity settled share based compensation
Cash settled share based compensation
$
2013
6,752
3,433
8,051
2012
6,988
3,257
4,872
18,236
$
15,117
$
$
Key management personnel are comprised of the directors and executive officers of the Corporation. Certain executive officers
have entered into employment agreements with Precision that provide termination benefits of up to 24 months base salary plus
up to two times targeted incentive compensation upon dismissal without cause.
78 Notes to Consolidated Financial Statements
NOTE 17. COMMITMENTS
(a) Operating Lease Commitments
The Corporation has commitments under various operating lease agreements, primarily for vehicles and office space. Terms of
the office leases run for a period of one to 10 years while the vehicle leases are typically for terms of between three and four years.
Expected non-cancellable operating lease payments are as follows:
Less than one year
Between one and five years
Later than five years
2013
2012
16,833
$
15,561
41,258
15,714
41,898
23,161
73,805
$
80,620
$
$
Three of the leased properties was sublet by the Corporation.
The following amounts were recognized as expenses in respect of operating leases in the consolidated statement of earnings:
Operating leases
Sub-lease recoveries
2013
19,578
(1,024)
18,554
$
$
2012
19,075
(583)
18,492
$
$
(b) Capital Commitments
At December 31, 2013 the Corporation had commitments to purchase property, plant and equipment totaling $178.8 million
(2012 – $157.5 million). Payments of $178.8 million for these commitments are expected to be made in 2014.
NOTE 18. PER SHARE AMOUNTS
The following tables reconcile the net earnings and weighted average shares outstanding used in computing basic and diluted
earnings per share:
Net earnings – basic and diluted
(Stated in thousands)
Weighted average shares outstanding – basic
Effect of share warrants
Effect of stock options and other equity compensation plans
Weighted average shares outstanding – diluted
2013
2012
$
191,150
$
52,360
2013
277,583
9,327
971
2012
276,276
9,418
933
287,881
286,627
Precision Drilling Corporation 2013 Annual Report 79
NOTE 19. BUSINESS ACQUISITIONS
In 2012 a contingent liability from a previous acquisition was settled, resulting in a $758 thousand recovery in the statement of
earnings and a $25 thousand increase to goodwill.
NOTE 20. SEGMENTED INFORMATION
The Corporation operates primarily in Canada and the United States, in two industry segments; Contract Drilling Services and
Completion and Production Services. Contract Drilling Services includes drilling rigs, directional drilling, procurement and
distribution of oilfield supplies, and manufacture, sale and repair of drilling equipment. Completion and Production Services
includes service rigs, snubbing units, coil tubing units, oilfield equipment rental, camp and catering services, and wastewater
treatment units.
2013
Revenue
Operating earnings
Depreciation and amortization
Total assets
Goodwill
Capital expenditures
2012
Revenue
Operating earnings
Depreciation and amortization
Loss on asset decommissioning
Total assets
Goodwill
Capital expenditures*
* Excludes business acquisitions
Contract
Drilling
Services
Completion
and
Production
Services
Corporate
and Other
Inter-
Segment
Eliminations
Total
$
1,719,910
$
323,353
$
–
$
(13,286)
$
2,029,977
361,447
292,217
3,837,919
200,217
446,566
Contract
Drilling
Services
28,402
32,630
590,992
112,139
83,470
Completion
and
Production
Services
(84,175)
8,312
150,212
–
5,768
–
–
–
–
–
305,674
333,159
4,579,123
312,356
535,804
Corporate
and Other
Inter-
Segment
Eliminations
Total
$
1,725,240
$
326,079
$
–
$
(10,578)
$
2,040,741
184,819
271,993
192,469
3,495,604
198,413
750,763
62,796
30,758
–
551,893
112,139
109,202
(76,817)
4,774
–
252,766
–
8,092
–
–
–
–
–
–
170,798
307,525
192,469
4,300,263
310,552
868,057
The Corporation’s operations are carried on in the following geographic locations:
2013
Revenue
Total assets
2012
Revenue
Total assets
Canada
United States
International
Inter-
Segment
Eliminations
Total
$
1,002,199
$
901,246
$
137,681
$
(11,149)
$
2,029,977
2,082,958
2,006,519
489,646
–
4,579,123
Canada
United States
International
Inter-
Segment
Eliminations
Total
$
1,053,966
$
936,113
$
64,017
$
(13,355)
$
2,040,741
2,119,891
1,913,810
266,562
–
4,300,263
During the year ended December 31, 2013, no one individual customer accounted for more than 10% of the Corporation’s total
revenue. For the year ended December 31, 2012 revenues from one customer of the Corporation’s Contract Drilling Services and
Completion and Production Services segments accounted for $222.7 million of the Corporation’s total revenue.
80 Notes to Consolidated Financial Statements
NOTE 21. FINANCIAL INSTRUMENTS
Financial Risk Management
The Board of Directors is responsible for identifying the principal risks of Precision’s business and for ensuring the implementation
of systems to manage these risks. With the assistance of senior management, who report to the Board of Directors on the risks of
Precision’s business, the Board of Directors considers such risks and discusses the management of such risks on a regular basis.
Precision has exposure to the following risks from its use of financial instruments:
(a) Credit Risk
Accounts receivable includes balances from a large number of customers primarily operating in the oil and gas industry. The
Corporation manages credit risk by assessing the creditworthiness of its customers before providing services and on an ongoing
basis as well as monitoring the amount and age of balances outstanding. In some instances the Corporation will take additional
measures to reduce credit risk including obtaining letters of credit and prepayments from customers. When indicators of credit
problems appear the Corporation takes appropriate steps to reduce its exposure including negotiating with the customer, filing
liens and entering into litigation. The Corporation views the credit risks on these amounts as normal for the industry. Precision’s
most significant customer accounted for $19.6 million of the trade receivables amount at December 31, 2013 (2012 – $23.0 million).
The movement in the allowance for doubtful accounts during the year was as follows:
Balance at January 1
Impairment loss recognized
Amounts written off as uncollectible
Impairment loss reversed
Effect of movement in exchange rates
Balance at December 31
The ageing of trade receivables at December 31 was:
Not past due
Past due 0-30 days
Past due 31-120 days
Past due more than 120 days
2013
2012
$
12,187
$
12,179
325
(1,172)
(138)
501
348
(174)
–
(166)
$
11,703
$
12,187
2013
2012
Gross
Provision for
Impairment
Gross
Provision for
Impairment
$
177,141
$
98,529
28,897
21,584
–
–
–
11,703
$
197,194
$
100,217
27,861
15,016
$
326,151
$
11,703
$
340,288
$
–
–
–
12,187
12,187
(b) Interest Rate Risk
As at December 31, 2013 and 2012, all of Precision’s long-term debt, with the exception of the secured revolving credit facility,
bears fixed interest rates. As a result Precision is not exposed to significant fluctuations in interest expense as a result of changes
in interest rates. Based on the debt outstanding at the end of the year, a 100 basis point change in interest rates would change
the annual interest expense by $0.3 million (2012 – $nil).
(c) Foreign Currency Risk
The Corporation is exposed to foreign currency fluctuations in relation to the working capital and long-term debt of its United
States operations and certain long-term debt facilities of its Canadian operations. The Corporation has no significant exposures
to foreign currencies other than the U.S. dollar. The Corporation monitors its foreign currency exposure and attempts to minimize
the impact by aligning appropriate levels of U.S. denominated debt with cash flows from U.S. based operations.
Precision Drilling Corporation 2013 Annual Report 81
The following financial instruments were denominated in U.S. dollars:
Cash
Accounts receivable
Accounts payable and accrued liabilities
Long-term liabilities, excluding long-term incentive plans
Net foreign currency exposure
Impact of $0.01 change in the U.S. dollar to Canadian dollar
exchange rate on net earnings
Impact of $0.01 change in the U.S. dollar to Canadian dollar
exchange rate on comprehensive income
2013
2012
Canadian
Operations (1)
U.S.
Operations
Canadian
Operations (1)
U.S.
Operations
$
$
$
$
995
26
(13,385)
–
(12,364)
124
–
$
53,327
$
39,693
$
61,515
290,995
(180,626)
(16,770)
146,926
–
1,469
$
$
$
$
$
$
56
(13,028)
–
26,721
267
–
$
$
$
237,370
(184,593)
(17,909)
96,383
–
964
(1) Excludes US$1,050 million of long-term debt that has been designated as a hedge of the Corporation’s net investment in certain self-sustaining foreign operations.
(d) Liquidity Risk
Liquidity risk is the exposure of the Corporation to the risk of not being able to meet its financial obligations as they become due.
The Corporation manages liquidity risk by monitoring and reviewing actual and forecasted cash flows to ensure there are available
cash resources to meet these needs. The following are the contractual maturities of the Corporation’s financial liabilities as at
December 31, 2013:
2014
2015
2016
2017
2018
Thereafter
Total
Long-term debt
$
–
$
–
$
–
$
–
$
29,781
$ 1,316,780
$ 1,346,561
Interest on long-term debt (1)
Commitments
Total
87,176
195,589
87,176
14,061
87,176
11,373
87,176
8,467
87,087
170,394
606,185
7,357
15,714
252,561
$ 282,765
$ 101,237
$
98,549
$
95,643
$ 124,225
$ 1,502,888
$ 2,205,307
(1) Interest has been calculated based on debt balances, interest rates and foreign exchange rates in effect as at December 31, 2013 and excludes amortization of long-term debt
issue costs.
Fair Values
The carrying value of cash, accounts receivable, and accounts payable and accrued liabilities approximates their fair value due to
the relatively short period to maturity of the instruments. The fair value of the unsecured senior notes at December 31, 2013 was
approximately $1,403 million (2012 – $1,330 million).
Financial assets and liabilities recorded or disclosed at fair value in the consolidated balance sheet are categorized based on
the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels are based on the amount of
subjectivity associated with the inputs in the fair determination and are as follows:
Level I—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
Level II—Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability
through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level III—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability
at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the
inputs to the model.
The estimated fair value of unsecured senior notes is based on level II inputs. The fair value is estimated considering the risk free
interest rates on government debt instruments of similar maturities, adjusted for estimated credit risk, industry risk and market
risk premiums.
82 Notes to Consolidated Financial Statements
NOTE 22. CAPITAL MANAGEMENT
The Corporation’s strategy is to carry a capital base to maintain investor, creditor and market confidence and to sustain future
development of the business. The Corporation seeks to maintain a balance between the level of long-term debt and shareholders’
equity to ensure access to capital markets to fund growth and working capital given the cyclical nature of the oilfield services
sector. The Corporation strives to maintain a conservative ratio of long-term debt to long-term debt plus equity. As at December 31,
2013 and 2012 these ratios were as follows:
Long-term debt
Shareholders’ equity
Total capitalization
Long-term debt to long-term debt plus equity ratio
$
$
2013
1,323,268
2,399,343
3,722,611
0.36
$
$
2012
1,218,796
2,171,300
3,390,096
0.36
As at December 31, 2013 liquidity remained sufficient as Precision had $80.6 million (2012 – $152.8 million) in cash and access
to a US$850.0 million senior secured revolving credit facility (2012 – US$850.0 million) and $82.5 million (2012 – $79.8 million)
secured operating facilities. As at December 31, 2013, US$28 million (2012 – US $nil) was drawn on the US$850 million secured
revolving credit facility with availability further reduced by US$28.6 million (2012 – US$26.8 million) in outstanding letters of
credit. Availability of the $40 million and US$25 million secured operating facilities were reduced by outstanding letters of credit
of $17.3 million (2012 – $18.9 million) and US$0.2 million (2012 – US$ nil), respectively. There was no amount drawn on the
US$15 million secured operating facility.
NOTE 23. SUPPLEMENTAL INFORMATION
Components of changes in non-cash working capital balances are as follows:
Accounts receivable
Inventory
Accounts payable and accrued liabilities
Pertaining to:
Operations
Investments
The components of accounts receivable are as follows:
Trade
Accrued trade
Prepaids and other
2013
2012
(23,110)
$
61,052
1,658
(22,682)
(44,134)
(33,887)
(10,247)
$
$
$
(6,707)
(111,333)
(56,988)
36,474
(93,462)
$
$
$
$
2013
2012
$
314,448
$
328,101
152,768
82,481
125,035
56,411
$
549,697
$
509,547
Precision Drilling Corporation 2013 Annual Report 83
The components of accounts payable and accrued liabilities are as follows:
Accounts payable
Accrued liabilities:
Payroll
Other
2013
2012
$
148,081
$
146,234
81,586
103,171
79,978
107,681
$
332,838
$
333,893
Precision presents expenses in the consolidated statement of earnings by function with the exception of depreciation and
amortization and loss on asset decommissioning which are presented by nature. Operating expense and general and administrative
expense would include $324.8 million and $8.3 million (2012 – $495.2 million and $4.8 million) respectively of depreciation and
amortization and loss on asset decommissioning if the statements of earnings were presented purely by function. The following
table presents operating and general and administrative expenses by nature:
Wages, salaries and benefits
Purchased materials, supplies and services
Share-based compensation
Allocated to:
Operating expense
General and administrative
2013
2012
$
773,901
$
795,243
589,394
27,849
1,391,144
1,248,637
142,507
1,391,144
$
$
$
556,103
18,603
1,369,949
1,243,301
126,648
1,369,949
$
$
$
NOTE 24. CONTINGENCIES AND GUARANTEES
The business and operations of the Corporation are complex and the Corporation 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 Corporation’s interpretation of relevant tax legislation
and regulations. The Corporation’s management believes that the provision for income tax is adequate and in accordance with
IFRS and applicable legislation and regulations. However, there are tax filing positions that have been and can still be the subject
of review by taxation authorities who may successfully challenge the Corporation’s interpretation of the applicable tax legislation
and regulations, with the result that additional taxes could be payable by the Corporation and the amount owed, with estimated
interest but without penalties, could be up to $58 million and is included in long-term income tax recoverable on the balance sheet.
In June 2013 a wholly owned subsidiary of the Corporation lost a tax appeal in the Ontario Superior Court of Justice related to
a reassessment of Ontario income tax for the subsidiary’s 2001 thru 2004 taxation years. The Corporation has appealed the
decision to the Ontario Court of Appeal and expects this appeal to be heard in 2014. Despite the decision in the Superior Court,
management believes it is more likely than not that the Corporation would prevail on appeal. Should the Corporation lose on
appeal, approximately $55 million of the long-tern income tax recoverable related to this issue would be expensed.
The Corporation, 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 Corporation is not determinable at this time; however, their ultimate
resolution is not expected to have a material adverse effect on the Corporation.
The Corporation has entered into agreements indemnifying certain parties primarily with respect to tax and specific third party
claims associated with businesses sold by the Corporation. Due to the nature of the indemnifications, the maximum exposure
under these agreements cannot be estimated. No amounts have been recorded for the indemnities as the Corporation’s
obligations under them are not probable or estimable.
84 Notes to Consolidated Financial Statements
NOTE 25. SUBSIDIARIES
Significant Subsidiaries
Precision Limited Partnership
Precision Drilling Canada Limited Partnership
Precision Diversified Oilfield Services Corp.
Precision Directional Services Ltd.
Precision Drilling (US) Corporation
Precision Drilling Company LP
Precision Completion & Production Services Ltd.
Precision Directional Services, Inc.
Grey Wolf Drilling Limited
Country of
Incorporation
Canada
Canada
Canada
Canada
United States
United States
United States
United States
Cyprus
Ownership Interest
2013
100
100
100
100
100
100
100
100
100
2012
100
100
100
100
100
100
100
100
100
Precision Drilling Corporation 2013 Annual Report 85
Consolidated Statements of Earnings
2013
2012
2011
2010
2009 (1)
$ 2,029.9
$ 2,040.7
$ 1,951.0
$ 1,429.7
$ 1,197.4
1,248.6
1,243.3
1,131.0
142.5
126.6
124.9
886.8
108.0
434.9
210.1
–
224.8
–
692.2
98.2
407.0
138.0
82.1
186.9
–
695.1
251.5
114.9
328.7
–
(23.7)
(12.7)
(122.8)
111.6
240.8
47.3
193.5
211.3
26.2
(17.3)
43.5
147.4
162.3
0.6
161.7
638.8
333.1
–
305.7
–
(9.1)
93.3
221.5
30.3
191.2
670.8
307.5
192.5
170.8
52.5
3.8
86.8
27.7
(24.7)
52.4
$
$
0.69
0.66
$
$
0.19
0.18
$
$
0.70
0.67
$
$
0.16
0.15
$
$
0.65
0.63
Years ended December 31,
(Stated in millions of Canadian dollars, except per unit/share amounts)
Revenue
Expenses:
Operating
General and administrative
Earnings before income taxes, finance charges, foreign exchange,
impairment of goodwill, loss on asset decommissioning, and
depreciation and amortization (Adjusted EBITDA)
Depreciation and amortization
Loss on decommissioning
Operating earnings
Impairment of goodwill
Foreign exchange
Finance charges
Earnings before income taxes
Income taxes
Net earnings
Earnings per unit/share:
Basic
Diluted
(1) 2009 was prepared under previous Canadian GAAP.
86 Supplemental Information
Additional Selected Financial Information
Years ended December 31,
(Stated in millions of Canadian dollars, except per unit/share amounts)
Return on sales – % (2)
Return on assets – % (3)
Return on equity – % (4)
Working capital
Current ratio
PP&E and intangibles
Total assets
Long-term debt
Shareholders’ equity
Long-term debt to long-term debt plus equity
Interest coverage (5)
Net capital expenditures excluding business acquisitions
Adjusted EBITDA
Adjusted EBITDA – % of revenue
Operating earnings
Operating earnings – % of revenue
2013
2012
2011
2010
2009 (1)
9.4
4.3
8.4
2.6
1.2
2.4
9.9
4.9
9.5
3.0
1.3
2.2
13.5
3.6
6.2
$
305.8
$
278.0
$
610.4
$
458.0
$
320.9
1.9
1.7
2.4
3.1
3.5
$ 3,565.7
$ 3,249.0
$ 2,948.8
$ 2,538.8
$ 2,917.1
$ 4,579.1
$ 4,300.3
$ 4,427.9
$ 3,564.5
$ 4,191.7
$ 1,323.3
$ 1,218.8
$ 1,239.6
$
804.5
$
748.7
$ 2,399.3
$ 2,171.3
$ 2,132.6
$ 1,932.8
$ 2,584.5
0.36
3.3
522.4
638.8
31.5
$
$
0.36
2.0
836.6
670.8
32.9
0.37
2.9
710.4
695.1
35.6
$
$
$
$
0.29
1.1
163.6
434.9
30.4
0.22
1.3
177.5
407.0
34.0
$
$
$
$
$
305.7
$
170.8
$
328.7
$
224.8
$
186.9
15.1
8.4
16.8
15.7
15.6
Cash flow from continuing operations
$
428.1
$
635.3
$
532.8
$
306.3
$
504.7
Cash flow from continuing operations per unit/share:
Basic
Diluted
Book value per unit/share (6)
Price earnings ratio (7)
$
$
$
1.54
1.49
8.22
$
$
$
2.30
2.22
7.85
$
$
$
1.93
1.85
7.72
$
$
$
1.11
1.07
7.01
$
$
$
2.02
1.94
9.38
14.41
43.26
15.00
41.74
11.77
Basic weighted average units/shares outstanding (000s)
277,583
276,276
275,899
275,655
249,925
(1) 2009 was prepared under previous Canadian GAAP.
(2) Return on sales was calculated by dividing earnings from continuing operations by total revenues.
(3) Return on assets was calculated by dividing net earnings by quarter average total assets.
(4) Return on equity was calculated by dividing net earnings by quarter average total shareholders’ equity.
(5) Interest coverage was calculated by dividing operating earnings by net interest expense.
(6) Book value per unit/share was calculated by dividing shareholders’ equity by shares outstanding.
(7) Price earnings ratio was calculated using year-end closing price divided by basic earnings per unit/share.
Precision Drilling Corporation 2013 Annual Report 87
ACCOUNT QUESTIONS
Our transfer agent can help you
with shareholder related services,
including:
change of address
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transferring shares to another
person
estate settlement.
Computershare Trust Company
of Canada
100 University Avenue,
9th Floor, North Tower
Toronto, Ontario, Canada
M5J 2Y1
Telephone: 1.800.564.6253
(toll free in Canada and the United States)
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Email: service@computershare.com
Shareholder Information
STOCK EXCHANGE LISTINGS
Our shares are listed on the Toronto
Stock Exchange under the trading
symbol PD and on the New York
Stock Exchange under the trading
symbol PDS.
TRANSFER AGENT
AND REGISTRAR
Computershare Trust Company
of Canada
Calgary, Alberta
TRANSFER POINT
Computershare Trust Company NA
Denver, Colorado
2013 TRADING PROFILE
Toronto (TSX: PD)
High: $11.53
Low: $7.47
Close: $9.94
Volume Traded: 297,457,268
New York (NYSE: PDS)
High: US$11.21
Low: US$7.29
Close: US$9.37
Volume Traded: 288,801,100
ONLINE INFORMATION
To receive news releases by email, or
to view this report online, please visit
the Investor Relations section of our
website at www.precisiondrilling.com.
You can find additional information
about us, including our annual
information form, 2013 annual report
and management information circular,
on our website as well as under our
profile on the SEDAR website at
www.sedar.com and on the EDGAR
website at www.sec.gov.
PUBLISHED INFORMATION
Please contact us if you would like
additional copies of this annual
report, or copies of our 2013 annual
information form as filed with the
Canadian securities commissions
and under Form 40-F with the
U.S. Securities and Exchange
Commission:
Investor Relations
Suite 800, 525 – 8th Avenue SW
Calgary, Alberta, Canada
T2P 1G1
Telephone: 403.716.4500
88 Shareholder Information
LEAD BANK
Royal Bank of Canada
Calgary, Alberta
AUDITORS
KPMG LLP
Calgary, Alberta
HEAD OFFICE
Suite 800, 525 – 8th Avenue SW
Calgary, Alberta, Canada
T2P 1G1
Telephone: 403.716.4500
Email: info@precisiondrilling.com
www.precisiondrilling.com
Corporate Information
DIRECTORS
William T. Donovan1,2
North Palm Beach, Florida, USA
Brian J. Gibson1,2
Mississauga, Ontario, Canada
Allen R. Hagerman, FCA1,3
Calgary, Alberta, Canada
Catherine Hughes2,3
Calgary, Alberta, Canada
Stephen J. J. Letwin2,3
Toronto, Ontario, Canada
Kevin O. Meyers2,3
Houston, Texas, USA
Patrick M. Murray1,3
Dallas, Texas, USA
Kevin A. Neveu
Calgary, Alberta, Canada
Robert L. Phillips1,2,3
Vancouver, British Columbia, Canada
1. Member of Audit Committee
2. Member of Corporate Governance,
Nominating and Risk Committee
3. Member of Human Resources and
Compensation Committee
OFFICERS
Kevin A. Neveu
President and
Chief Executive Officer
Joanne L. Alexander
Senior Vice President, General
Counsel and Corporate Secretary
Niels Espeland
President, International Operations
Douglas B. Evasiuk
Senior Vice President,
Sales and Marketing
Kenneth J. Haddad
Senior Vice President,
Business Development
Robert J. McNally
Executive Vice President and
Chief Financial Officer
Darren J. Ruhr
Senior Vice President,
Corporate Services
Gene C. Stahl
President, Drilling Operations
Douglas J. Strong
President, Completion and
Production Services
Precision Drilling Corporation 2013 Annual Report 89
Precision Drilling Corporation
Suite 800, 525 – 8th Avenue SW
Calgary, Alberta, Canada T2P 1G1
Telephone: 403.716.4500
Email: info@precisiondrilling.com
www.precisiondrilling.com
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