Precision
Drilling
Corporation
2015
Annual
Report
Precision
Management’s
Discussion and Analysis
Consolidated Financial
Statements and Notes
Precision
Precision Drilling
Corporation
2015
What’s Inside
6 About Precision
10 2015 Highlights and Outlook
15 Understanding our Business Drivers
15 The Energy Industry
19 A Competitive Operating Model
23 An Effective Strategy
25 2015 Results
26 2015 Compared with 2014
27 2014 Compared with 2013
28 Segmented Results
31 Quarterly Financial Results
35 Financial Condition
35 Liquidity
36 Capital Management
37 Sources and Uses of Cash
40 Capital Structure
41 Accounting Policies and Estimates
44 Risks in Our Business
51
Evaluation of Controls and Procedures
52
Management’s Report
to the Shareholders
53
Independent Auditors’ Reports
55
Consolidated Financial
Statements and Notes
92 Supplemental Information
94 Shareholder Information
95 Corporate Information
2015 SHARE TRADING SUMMARY
The Toronto Stock Exchange (TSX)
P D
Volume (millions)
Share Price (Cdn$)
$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
Toronto (TSX: PD)
High: $9.43 Low: $4.47 Close December 31, 2015: $5.47 Volume Traded: 440,676,263
The New York Stock Exchange (NYSE)
P DS
Volume (millions)
Share Price (US$)
$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$7.80 Low: US$3.28 Close December 31, 2015: US$3.94 Volume Traded: 848,119,400
)
s
n
o
i
l
l
i
m
(
e
m
u
o
V
l
)
s
n
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i
l
l
i
m
(
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m
u
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10
7.5
5.0
2.5
0
10
7.5
5.0
2.5
0
Precision Drilling Corporation 2015 Annual Report
1
MD&A
Management’s
Discussion and
Analysis
Precision
Precision Drilling
Corporation
2015
This management’s discussion and analysis
(MD&A) contains information to help you
understand our business and financial
performance. Information is as of March 4,
2016. This MD&A focuses on our Consolidated
Financial Statements and Notes 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 Cautionary Statement About
Forward-Looking Information and Statements on
page 3. We adopted IFRS effective January 1,
2011, and restated our 2010 results at that time.
The terms we, us, our, Precision Drilling 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
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING INFORMATION AND STATEMENTS
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 in this MD&A:
typically include words and phrases about the future, such as anticipate, could, should, can, expect, seek, may,
intend, likely, will, plan, estimate and believe
are based on certain assumptions and analyses based on our experience, understanding of historical trends,
current conditions and expected future developments, and other factors we believe are appropriate given the
circumstances
can be affected by known and unknown risks, uncertainties and other factors that could cause actual results to
differ materially from our expectations.
In particular, our forward-looking information and statements in this MD&A include, but are not limited to, the following:
our outlook on oil and natural gas prices
our expectations regarding drilling activity in North America and the demand for Tier 1 rigs
our capital expenditure plans for 2016
the expected timing on the delivery of two new-build drilling rigs to Kuwait
our 2016 strategic priorities
the potential impact liquefied natural gas export development could have on North American drilling activity
our expectations that new or newer rigs will enter the markets in which we currently operate
our ability to remain compliant with our financial debt covenants.
These forward-looking information and statements are based on certain assumptions and analysis made by Precision 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 ability to react to customers’ spending plans as a result of the decline in oil prices
the status of current negotiations with our customers and vendors
continued market demand for Tier 1 rigs
our ability to deliver rigs to customers on a timely basis
the general stability of the economic and political environment in the jurisdictions where we operate.
Precision Drilling Corporation 2015 Annual Report
3
Readers are cautioned not to place undue reliance on forward-looking information and statements. Actual results,
performance or achievements could differ materially from those currently anticipated due to a number of risks and
uncertainties. Such risks and uncertainties include, but are not limited to, the following:
fluctuations in the price and demand for oil and natural gas
fluctuations in the level of oil and natural gas exploration and development activities
fluctuations in the demand for contract drilling, directional drilling, well servicing and ancillary oilfield services
liquidity of the capital markets to fund customer drilling programs
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 operations and facilities
competitive operating risks inherent in contract drilling, directional drilling, well servicing and ancillary oilfield
services
ability to improve our rig technology to improve drilling efficiency
general economic, market or business conditions
changes in laws or regulations
availability of qualified personnel, management or other key inputs
currency exchange fluctuations
operating in foreign countries
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 in our Business.
Readers are cautioned that the foregoing list of risk factors is not exhaustive. Additional information on these and other
factors that could affect our business, operations or financial results are included in reports on file with applicable
securities regulatory authorities, including but not limited to our annual information form (AIF) for the year ended
December 31, 2015, which may be accessed on Precision’s SEDAR profile on SEDAR (www.sedar.com) or under
Precision’s EDGAR profile on EDGAR (www.sec.gov).
All of the forward-looking information and statements made in this MD&A are expressly qualified by these cautionary
statements. There can be no assurance that actual results or developments that we anticipate will be realized. We
caution you not to place undue reliance on forward-looking information and statements. The forward-looking information
and statements made in this MD&A are made as of the date hereof. We will not necessarily update or revise this forward-
looking information as a result of new information, future events or otherwise, unless we are required to by applicable
securities law.
4
Management’s Discussion and Analysis
ADDITIONAL GAAP MEASURES
In this MD&A, we reference additional generally accepted accounting principles (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, impairment of property, plant and equipment, loss on asset decommissioning, and depreciation and
amortization), as reported in the Consolidated Statements of Earnings (Loss), 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, and non-cash impairment,
decommissioning, depreciation, and amortization charges.
Operating Earnings
We believe that operating earnings, as reported in the Consolidated Statements of Earnings (Loss), 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 Statements 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 2015 Annual Report
5
About Precision
Management’s
Discussion and
Analysis
Precision Drilling Corporation provides onshore drilling and 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.
Vision
Our vision is to be recognized as the
High Performance, High Value provider of
onshore drilling and related services globally.
You can read about our strategic priorities
for 2016 on page 24.
STRENGTH AND FLEXIBILITY
From our founding as a private drilling contractor in the 1950s,
Precision has grown to become one of the most active drillers in
North America. Our strength and flexibility are underpinned by five
distinguishing features:
a competitive operating model that drives efficiency, quality and cost control
a culture focused on safety and field performance
size and scale of operations that provide higher margins and better service capabilities
liquidity that allows us to take advantage of business cycle opportunities
a capital structure that provides long-term stability and flexibility.
CORPORATE GOVERNANCE
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.
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
Contract Drilling Services
(cid:127) Drilling rig operations
– Canada
– U.S.
– International
(cid:127) Directional drilling operations
– Canada
– U.S.
Completion and Production Services
(cid:127) Canada and U.S.
– Service rigs
– Equipment rentals
(cid:127) Canada
– Snubbing and coil tubing
– Camps and catering
– Water systems
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) Information
systems
(cid:127) Health, safety and
environment
(cid:127) Human
resources
(cid:127) Finance
(cid:127) Legal and enterprise
risk management
2015 Adjusted EBITDA by Operating Segment
2015 Revenue by Location
Contract
Drilling
Services
98%
Completion
and Production
Services
2%
14%
International
USA
48%
Canada
38%
Precision Drilling Corporation 2015 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 Canada, the U.S. and internationally.
We are the third largest land drilling contractor in North America, servicing approximately 26% of the active land drilling
market in Canada and 6% of the active U.S. market. We also have an international presence with operations in Mexico
and the Middle East.
At December 31, 2015, our Contract Drilling Services segment consisted of:
251 land drilling rigs, including:
– 134 in Canada
– 102 in the U.S.
– 5 in Mexico
– 4 in Saudi Arabia
– 3 in Kuwait
– 2 in the Kurdistan region of Iraq
– 1 in the country of Georgia
capacity for approximately 80 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 for our global operations.
One new-build, contracted drilling rig for Canada was delivered in February 2016. As at March 4, 2016, we had 236
Tier 1 rigs, with 16 additional rigs that are good candidates to be upgraded to Tier 1 status. Our drilling fleet is comprised
almost entirely of Tier 1 rigs. Tier 1 rigs are highly mobile and automated, which make them safer and more efficient
in drilling directional and horizontal wells than older generation drilling rigs. Our Tier 1 rigs, or Super Series rigs, have
a broad range of features to meet a diverse range of customer needs, from drilling shallow- to medium-depth wells
to exploiting the deep, unconventional shale plays that have driven the North American energy production boom over
the past decade. Available features include alternating current (AC) power, digitized control systems, integrated top
drive, bi-directional pad walking or skidding systems for multi-pad well drilling, highly mechanized pipe handling, and
high capacity mud pumps. Our Super Series fleet includes a number of smaller, fast-moving, hydraulically-powered
mechanized rigs that are optimized for shallow- to medium-depth resource plays found across North America.
Contract Drilling
Revenue
$ Millions
2,500
2,000
1,500
1,000
500
0
Contract Drilling
Adjusted EBITDA
$ Millions
1,000
Contract Drilling
Utilization Days
Utilization Days
80,000
800
600
400
200
0
60,000
40,000
20,000
0
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
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 in Canada and the U.S.
On an operating hour basis in 2015, we serviced approximately 11% of the well completion and workover service rig
market demand in Canada and less than 1% of the market in the U.S.
At December 31, 2015, our Completion and Production Services segment consisted of:
148 well completion and workover service rigs, including:
– 140 in Canada
– 8 in the U.S.
11 snubbing units in Canada
4 coil tubing units in Canada
approximately 2,400 oilfield rental items, including surface storage, small-flow wastewater treatment, power
generation, and solids control equipment, primarily in Canada
180 wellsite accommodation units in Canada
46 drilling camps and four base camps in Canada
10 large-flow wastewater treatment units, 24 pump houses and eight potable water production units in Canada.
Completion and Production
Revenue
Completion and Production
Adjusted EBITDA
Completion and Production
Service Rig Hours
$ Millions
400
300
200
100
0
$ Millions
150
100
50
0
Hours
400,000
300,000
200,000
100,000
0
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
Precision Drilling Corporation 2015 Annual Report
9
2015 Highlights and Outlook
Management’s
Discussion and
Analysis
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/
2015
(decrease)
2014
% increase/
(decrease)
Revenue
Adjusted EBITDA
Adjusted EBITDA % of revenue
Net earnings (loss)
Cash provided by operations
Funds provided by operations
Investing activities
Capital spending
Expansion
Upgrade
Maintenance and infrastructure
Proceeds on sale
Net capital spending
Earnings (loss) per share ($)
Basic
Diluted
Dividends per share ($)
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
1,555,624
473,865
30.5%
(33.8)
(40.8)
(363,436)
(1,196.3)
517,016
357,090
361,425
48,487
48,798
(9,786)
448,924
(24.0)
(48.8)
(36.7)
(64.5)
(67.2)
(90.4)
(40.5)
(1.24)
(1.24)
0.28
(1,227.3)
(1,227.3)
12.0
2,350,538
800,370
34.1%
33,152
680,159
697,474
571,383
136,475
148,832
(101,826)
754,864
0.11
0.11
0.25
15.8
25.3
(82.7)
58.9
51.0
102.5
(3.3)
32.3
661.5
44.5
(84.1)
(83.3)
19.0
% increase/
2015
(decrease)
251
(19.8)
17,238
21,172
4,084
163
149,574
(47.5)
(39.6)
1.2
(7.9)
(45.2)
2014
313
32,810
35,075
4,036
177
273,194
% increase/
(decrease)
(4.3)
7.5
15.9
13.5
(20.3)
(3.7)
2013
2,029,977
638,833
31.5%
191,150
428,086
461,973
282,145
141,132
112,527
(13,372)
522,432
0.69
0.66
0.21
2013
327
30,530
30,268
3,555
222
283,576
% increase/
(decrease)
(0.5)
(4.8)
265.1
(32.6)
(22.9)
(52.7)
8.5
(20.6)
(57.4)
(37.6)
263.2
266.7
320.0
% increase/
(decrease)
1.9
(5.6)
(12.5)
70.4
3.7
(3.8)
10 Management’s Discussion and Analysis
Financial Position and Ratios
(thousands of dollars, except ratios)
Working capital
Working capital ratio
Long-term debt
Total long-term financial liabilities
Total assets
Enterprise value (1)
Long-term debt to long-term debt plus equity (2)
Long-term debt to cash provided by operations
Long-term debt to enterprise value
December 31,
2015
December 31,
2014
December 31,
2013
536,815
3.2
2,180,510
2,210,231
4,878,690
3,245,924
0.51
4.22
0.67
653,630
2.3
1,852,186
1,881,275
5,308,996
3,265,865
0.43
2.72
0.57
305,783
1.9
1,323,268
1,355,535
4,579,123
3,919,763
0.36
3.09
0.34
(1) Share price multiplied by the number of shares outstanding plus long-term debt minus working capital. See page 40 for more information.
(2) Net of unamortized debt issue costs.
2015 OVERVIEW
Crude oil prices have decreased significantly since mid-2014, resulting in a severe, industry-wide downturn. Persistently
low oil and natural gas prices have reduced our customers’ cash flows, causing them to scale back their capital
budgets. As a result, drilling activity declined rapidly throughout most of 2015, negatively impacting our activity and
resulting cash flow.
For the year ended December 31, 2015, our net loss was $363 million, or $1.24 per diluted share, compared with net
earnings of $33 million, or $0.11 per diluted share in 2014. During the year, we recorded asset decommissioning and
asset impairment charges totalling $466 million that, after-tax, reduced net earnings by $329 million and net earnings per
diluted share by $1.12.
Revenue in 2015 was $1,556 million, 34% lower than in 2014, mainly due to lower drilling activity in Canada and the
United States. Contract Drilling Services revenue was down 32%, while Completion and Production Services revenue
was down 46%. Our international drilling activity increased 1% with an average of 11 rigs working in 2015.
Adjusted EBITDA in 2015 was $474 million, 41% lower than in 2014. Our Adjusted EBITDA margin was 30%, compared
with 34% in 2014. The decrease in Adjusted EBITDA margin was mainly the result of lower utilization in North America.
Adjusted EBITDA margin for the year in our Contract Drilling Services segment was 40%, compared with 41% in the prior
year, while Adjusted EBITDA margin from our Completion and Production Services segment was 5%, compared with a
prior year margin of 17%. Extreme price competition from excess industry capacity and fixed costs allocated to fewer
active rigs contributed to the lower margin in our Completion and Production Services segment. Our portfolio of term
customer contracts, a scalable operating cost structure, and economies achieved through vertical integration of the
supply chain all helped us manage our Adjusted EBITDA margin.
We undertook a number of measures to manage our variable costs during the industry downturn, including reducing our
capital and operating expenditures. In addition, we reduced our fixed cost structure by consolidating several of our North
American operating facilities, streamlining management reporting structures, and reducing staff levels, which resulted in
one-time costs of $21 million.
Capital expenditures for the purchase of property, plant and equipment were $459 million in 2015, a decrease of
$398 million over 2014. Capital spending for 2015 included $361 million for expansion capital, $49 million for upgrade
capital and $49 million for the maintenance of existing assets and infrastructure. Expansion capital was primarily for the
17 new-build drilling rigs from the 2014 new-build program.
In 2015, we high-graded our drilling rig fleet, as follows:
added 17 Tier 1 new-build drilling rigs
upgraded 10 drilling rigs
decommissioned 79 legacy drilling rigs (48 in Canada, 30 in the U.S. and one in Mexico).
Three additional Tier 1 new-build drilling rigs are in various stages of completion; one rig was delivered in February 2016,
and the other two are expected to be delivered in 2017.
Precision Drilling Corporation 2015 Annual Report
11
Under IFRS, we are required to assess the carrying value of our assets in cash generating units when indicators of
impairment exist. Due to the decrease in oil and natural gas well drilling in North America and the outlook for future
activity, in 2015 we recognized $282 million impairment of property, plant and equipment and a goodwill impairment
charge of $17 million associated with our rentals division. In addition, we incurred asset decommissioning charges
of $166 million associated with 79 legacy drilling rigs due to their high maintenance costs, low demand, and highly
competitive market.
Subsequent to year end, on February 11, 2016, we suspended our dividend as a result of a debt covenant restriction.
See Financial Condition – Liquidity on page 35 for more information.
OUTLOOK
Contracts
Term customer contracts provide a base level of activity and revenue
and, as of March 4, 2016, we had term contracts in place for an average
of 58 rigs: 31 in Canada, 20 in the U.S. and seven internationally for
2016, and an average of 30 rigs for 2017. 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 U.S. and
internationally, term contracts normally generate 365 utilization days per rig year. In 2015, we had an average of 105
drilling rigs working under term contracts and revenue from these contracts was approximately 73% of our total contract
drilling revenue for the year.
contract drilling revenue was generated
In 2015, approximately 73% of our total
from rigs under term contracts.
73%
Pricing, Demand and Utilization
Global crude oil prices continued their decline throughout 2015. Persistent oversupply in the market was compounded
by OPEC’s decision to not reduce production quotas, anticipation of Iran’s return to the global oil market, and fears
of economic slowdown in China and other emerging economies. West Texas Intermediate (WTI) crude oil averaged
US$48.77 per barrel in 2015, and closed the year at US$37.04 per barrel.
To date in 2016, global crude oil prices have continued to deteriorate. Oversupply continues to be a concern as
inventories remain high, delaying the effect of any supply/demand rebalancing.
Natural gas prices remained depressed in 2015, due to increased production from unconventional resource
development, higher than average storage levels, mild weather, and the lack of a developed export market from North
America. Natural gas prices, referenced by the average Henry Hub on the New York Mercantile Exchange (NYMEX)
price, averaged US$2.60 per MMBtu in 2015, and closed the year at US$2.31 per MMBtu.
Despite the industry-wide decline in natural gas drilling activity, U.S. production has continued to grow, keeping prices
low. Looking ahead to 2016, natural gas pricing is expected to experience continued weakness as a result of a relatively
mild winter to-date, and continued oversupply.
In 2015, the Canadian dollar weakened relative to the U.S. dollar, as crude oil prices moved lower and the U.S.
Federal Reserve raised its interest rates for the first time in almost 10 years. The Canadian dollar averaged US$0.7820
(Cdn$/US$1.2788) for 2015, and closed the year at US$0.7225 (Cdn$/US$1.3840). The weakening of the Canadian
dollar relative to the U.S. dollar serves to partially offset the impact of lower U.S. dollar-denominated crude oil and natural
gas prices for Canadian exploration and production companies.
12 Management’s Discussion and Analysis
During 2015, seasonally adjusted drilling activity consistently decreased in both Canada and the U.S. and this trend
has continued into 2016. The oil rig count at March 4, 2016 was 58% lower in the U.S. than it was a year ago, and 67%
lower in Canada. From peak levels achieved in November 2014, the overall North American land oil directed rig count on
March 4, 2016 was down 77%.
There is limited visibility with no market signals suggesting a rebound is imminent. In general, we expect lower drilling
activity levels and pricing pressure on spot market rigs in North America as lower oil prices have caused producers to
significantly reduce drilling budgets. We expect Tier 1 rigs to remain the preferred rigs of customers globally and that we
will benefit from our fleet of Tier 1 rigs.
International
We currently have 15 rigs in Mexico and the Middle East, and we plan to deliver another two new-build rigs to Kuwait
in 2017.
Upgrading the Fleet
The industry trend toward more complex drilling programs has accelerated the retirement of older generation, less
capable rigs. Over the past several years, we and some of our competitors have been upgrading the drilling rig fleet by
building new rigs, upgrading existing rigs, and decommissioning lower capacity rigs. We believe this retooling of the
industry-wide fleet has been making legacy rigs virtually obsolete in North America.
After a six-year new-build program, the upgrading of a number of existing rigs, and the cumulative decommissioning of
236 legacy rigs, our fleet now consists of 236 Tier 1 rigs with 16 additional rigs that are good candidates to be upgraded
to Tier 1 status.
Capital Spending
We expect capital spending in 2016 to be $202 million, including $156 million for expansion capital; $44 million for
sustaining and infrastructure expenditures; and $2 million to upgrade existing rigs. We expect that the $202 million will
be split $197 million in the Contract Drilling segment and $5 million in the Completion and Production Services segment.
The expansion capital plan for 2016 includes the construction of two new-build drilling rigs to be delivered in 2017 for
our customer in Kuwait. Precision’s sustaining and infrastructure capital plan is based upon currently anticipated activity
levels for 2016.
Precision Drilling Corporation 2015 Annual Report
13
i
%
n
g
r
a
M
50
40
30
20
10
0
2011
2012
2013
2014
2015
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
800
700
600
500
400
300
200
100
0
s
n
o
i
l
l
i
M
$
Source: Precision Drilling
2011
2012
2013
2014
2015
Drilling Utilization Days
80,000
60,000
s
y
a
D
40,000
20,000
0
International
USA
Canada
Source: Precision Drilling
2011
2012
2013
2014
2015
14 Management’s Discussion and Analysis
Understanding our Business Drivers
Management’s
Discussion and
Analysis
THE ENERGY INDUSTRY
Precision operates in the energy services business, which is an inherently challenging cyclical industry. 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: crude oil, natural gas, and natural
gas liquids.
Commodity Prices
Our customers’ cash flow to fund exploration and development is dependent on commodity prices: higher prices
increase cash flow and encourage investment; when prices decline, the opposite is true.
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 were relatively strong between 2009 and 2014, as supply and demand
fundamentals remained tight. Strong prices contributed to significant drilling activity in North America, resulting in supply
growth, particularly from shale plays in the U.S. This activity, combined with slower than expected global demand growth
and sustained production levels from OPEC, led to a supply-demand imbalance, which resulted in price deterioration
beginning in late 2014 and continuing into 2016.
Natural gas and natural gas liquids continue to be priced regionally. In North America, natural gas demand largely
depends on the weather. Colder winter temperatures, and to a lesser extent, warmer summer temperatures, result in
greater natural gas demand. Other demand drivers, such as natural gas fired power generation, industrial applications,
and transportation, 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 potential for 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.
The key driver of price continues to be increased production from unconventional shale gas drilling. Since the cold winter
of 2014, prices for natural gas in North America have been depressed, as supplies of unconventional natural gas have
increased and current inventory levels are viewed as adequate to keep North American markets well supplied.
Average Oil and Natural Gas Prices
Oil
WTI (US$ per barrel)
Natural gas
Canada
AECO ($ per MMBtu)
U.S.
Henry Hub (US$ per MMBtu)
2015
48.77
2.70
2.60
2014
93.06
4.45
4.33
2013
98.02
3.18
3.73
Precision Drilling Corporation 2015 Annual Report
15
WTI Oil Prices and
Henry Hub Natural
Gas Prices
12
t
u
B
M
M
/
$
S
U
8
4
Henry Hub Natural Gas Prices
WTI Oil Prices
Source: Precision Drilling
0
Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
Jan-16
120
80
40
0
l
e
r
r
a
b
/
$
S
U
New Technology
Technological advancements in horizontal drilling, fracturing and stimulation 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 reservoirs in North America, in existing and new basins that have not 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 Tier 1 drilling rigs, which garner premium contract rates.
Canadian Directional/
Horizontal Wells Drilled
as a Percentage of Total
Wells Drilled
100
80
60
40
20
t
e
g
a
n
e
c
r
e
P
Precision
Canada Industry Excluding Precision
Source: Whelby Data
0
Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
Jan-16
16 Management’s Discussion and Analysis
These technical innovations have been a major factor in the increase in oil and natural gas production in the U.S.
U.S. Lower 48 Production
100
)
d
/
f
c
B
(
s
a
G
l
a
r
u
a
N
t
80
60
40
20
Natural Gas
Crude Oil
Source: Energy Information Administration
0
Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
Jan-16
10
8
6
4
2
0
l
)
d
/
s
b
b
M
M
(
l
i
O
e
d
u
r
C
Natural gas production in Canada has been flat because of lower natural gas directed drilling due to pricing pressure
and Canada’s lack of an export market other than the U.S.
Canadian Production
20
16
12
8
4
)
d
/
f
c
B
(
s
a
G
l
a
r
u
a
N
t
Natural Gas
Crude Oil
Source: Energy Information Administration, FEC
0
Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
Jan-16
5
4
3
2
1
0
l
)
d
/
s
b
b
M
M
(
l
i
O
e
d
u
r
C
Precision Drilling Corporation 2015 Annual Report
17
Drilling Activity
The North American land drilling industry is almost a year and a half into a deep downturn, a result of lower commodity
prices pushing customer spending down and decreasing drilling demand.
In 2015, the industry drilled 5,241 wells in western Canada, compared with 10,942 in 2014 and 10,903 in 2013. Total
industry drilling operating days were 50% lower than 2014, at 64,880. Average industry drilling operating days per well
was 12.4 compared with 12.0 in 2014. Average depth of a well increased 14%.
Approximately 18,400 wells were started onshore in the U.S., compared with approximately 37,900 in 2014 and 35,700
in 2013.
In Canada, there has been strength in natural gas and natural gas liquids drilling activity related to deep basin drilling in
northwestern Alberta and northeastern British Columbia, while in the U.S. the bias towards oil-directed drilling continues.
In 2015, approximately 45% of the Canadian industry’s active rigs and 77% of the U.S. industry’s active rigs were drilling
for oil targets, compared with 57% for Canada and 82% for the U.S. in 2014.
The graphs below show the shift in drilling activity to oil targets, in both the U.S. and Canada, since 2011. The difference
in activity has narrowed with the rapid decline in the price of crude oil in late 2014. The Canadian drilling rig activity graph
also shows how Canadian drilling activity fluctuates with the seasons, a market dynamic that generally is not present in
the U.S.
U.S. Drilling Rig Activity
1,600
i
g
n
k
r
o
W
s
g
R
i
1,200
800
400
0
Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
Jan-16
Natural Gas Rigs
Crude Oil Rigs
Source: Baker Hughes, Inc.
Canadian Drilling Rig Activity
600
i
g
n
k
r
o
W
s
g
R
i
400
200
0
Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
Jan-16
Natural Gas Rigs
Crude Oil Rigs
Source: Baker Hughes, Inc.
18 Management’s Discussion and Analysis
A COMPETITIVE OPERATING MODEL
The contract drilling business is highly competitive, with numerous industry participants. We compete for 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, and safety
record, 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 our 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 is efficient and reduces costs
having equipment that is geographically dispersed, reliable and well maintained
monitoring our equipment to minimize mechanical downtime
managing operations effectively to keep non-productive time to a minimum
compensating our executives 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.
Our Tier 1 rigs, or our Super Series rigs, have a broad range of features to meet a diverse range of customer needs, from
drilling shallow- to medium-depth wells to exploiting the deep, unconventional shale plays that have driven the North
American energy production boom over the past decade. Available features include alternating current (AC) power,
digitized control systems, integrated top drive, bi-directional pad walking or skidding systems for multi-pad well drilling,
highly mechanized pipe handling and high capacity mud pumps. Our Super Series fleet includes a number of smaller,
fast-moving, hydraulically-powered mechanized rigs that are optimized for shallow- to medium-depth resource plays
found across North America.
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 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 (to move,
rig-up and rig-out) by utilizing walking and skidding systems, reducing the number of move loads per rig, and using
mechanized equipment for safer and quicker rig component connections.
Precision Drilling Corporation 2015 Annual Report
19
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. And 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 a predetermined target of available billable time.
Key field employee retention – senior field employee retention rates. Measured against predetermined target rates
of retention.
Financial performance – adjusted EBITDA and return on capital employed. Measured against predetermined
targets.
Investment returns – total shareholder return performance, including dividends, against an industry peer group,
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 opportunity in North America.
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, 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 and North Dakota.
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. Included in our self-contained units are three patented L-frame units, which are more efficient in the
rig up and rig out process than standard self-contained units.
Four coil tubing units serve the Canadian market. 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.
20 Management’s Discussion and Analysis
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 long-term contract. Historically an upgrade may have resulted in a change in tier classification.
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 Drilling 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.
Technical Centres
We operate two contract drilling technical centres, one in Nisku, Alberta and the other in Houston, Texas. We also
operate one completion and production services technical centre in Red Deer, Alberta. These centres accommodate
our technical service and field training groups and enable us to consolidate support and training for our operations. The
Houston facility includes a fully functioning training rig with the latest drilling technologies; a training rig will be added at
the Nisku facility in 2016. In addition, our Houston facility accommodates our rig manufacturing group.
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.
(www.toughnecks.com), our highly
In 2008, we launched Toughnecks
successful field recruiting program.
Precision Drilling Corporation 2015 Annual Report
21
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.
We track safety using Total Recordable Incident Frequency (TRIF), an
industry standard. This statistic benchmarks our 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 for the potential for a more serious
events. In 2015, 92% of our drilling rigs and 93% of our service rigs achieved Target Zero.
Our safety vision for eliminating workplace
incidents is a core belief that all injuries can
be prevented.
Target Zero
We continuously review our rig designs and components and use advanced technologies to improve the life cycle,
maintain safety and operational efficiency, reduce energy use, and manage our energy and resources.
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.
22 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.
2015 Strategic Priorities
2015 Results
Work with our customers to lower well costs
Work with our customers to create maximum efficiency and lower
risks for development drilling programs.
Utilize our platform of Tier 1 assets, geographically diverse
operations, and highly efficient service offering to deliver cost-
reducing solutions.
Grow our integrated directional service.
Utilized Tier 1 drilling rigs to further optimize pad drilling and alleviate
inefficiencies in the process.
Worked with customers to offer creative bundling packages where
Precision’s vertical integration can play a substantial role.
Completed 412 integrated directional drilling jobs representing 74% of
our total directional drilling jobs compared with 463 or 49% in 2014.
Maximize cost efficiency throughout the organization
Continue to leverage our scale to reduce costs while delivering
High Performance.
Leveraged the Nisku Drilling Support Centre and Houston Technical
Centre to lower costs in repair, maintenance, and new manufacturing
operations.
Maximize the benefits of the variable nature of operating and
capital expenses.
Consolidated six facilities and distribution centres in North America in
response to the industry downturn.
Maintain an efficient corporate cost structure by optimizing systems
for assets, people, and business management.
Achieved Target Zero for 92% of our drilling rigs and 93% of our
service rigs.
Maintain our focus on worker safety, premium service quality, and
employee development.
Reinforce our competitive advantage
Gain market share.
High grade our active fleet by delivering new-build rigs and
maximizing customer opportunities.
Deliver consistent, reliable, High Performance service.
Retain and continue to develop our people.
Manage liquidity and focus activities on cash flow generation
Monitor working capital, debt and liquidity.
Maintain a scalable cost structure that is responsive to changing
competition and market demand.
Adjust capital plans according to utilization and customer demand.
Gained market share in both Canada and the U.S. as measured by
the percent of drilling days in Canada and the average active rigs in
the U.S.
Delivered 17 new-build Super Series rigs to customers on long-term
contracts and upgraded 10 existing drilling rigs to higher specification
assets to deliver High Performance services to our customers.
Retired 79 legacy drilling rigs, completing the transformation of our
fleet to essentially all Tier 1 rigs.
Achieved better than predetermined targets for mechanical downtime.
Exceeded employee retention goals across all targeted skill positions,
and trained approximately 1,700 people in our training facilities.
Secured long-term contracts for two new-build drilling rigs to be
deployed to Kuwait in 2017.
Reduced days sales outstanding by 14% compared with 2014.
Incurred $21 million in restructuring charges through the year, which
will yield annualized savings of approximately $100 million.
Reduced maintenance and infrastructure capital by 67%, compared
with prior year, as equipment utilization was lower and facility
upgrades completed.
Amended financial ratio covenants under Senior Credit Facility to
improve access to capital through the industry downturn.
Our corporate and competitive growth strategies are designed to optimize resource allocation and differentiate us
from the competition, generating value for investors. Despite the downturn in industry activity, we see opportunities
for long-term 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 our Completion and Production
Services segment.
Precision Drilling Corporation 2015 Annual Report
23
Strategic Priorities for 2016
1. Maintain strong liquidity to manage through an extended downturn – sustain adequate liquidity by generating
positive operating cash flow, ensuring full access to the Senior Credit Facility, and begin a multi-year plan for net
debt reduction.
2. Sustain High Performance, High Value service offering – continue to deliver maximum efficiency and lower risks
to support development drilling programs by operating the highest quality assets in the industry with well-trained,
professional crews supported by robust systems that eliminate manual processes and improve automation throughout
the Precision organization.
3. Position for an eventual rebound – concurrent with right-sizing the organization for the extended downturn, we will
take steps to prepare for a rebound:
a. Asset integrity – maintain high quality and integrity of our Tier 1 drilling fleet by utilizing spare equipment, avoiding
fleet cannibalization and maintaining rigorous equipment standards.
b. People – retain field leadership within the organization, maintain relationships with former crew members and
continue to develop leadership and skills of workers within our organization.
c. Ample liquidity – maintain strong liquidity to fund working capital requirements and other short term commitments
that arise when activity levels increase.
24 Management’s Discussion and Analysis
2015 Results
Management’s
Discussion and
Analysis
Adjusted EBITDA and operating earnings (loss) are additional GAAP measures. See page 5 for more information.
Consolidated Statements of Earnings (Loss) Summary
Year ended December 31 (thousands of dollars)
2015
2014
2013
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
Impairment of property, plant and equipment
Operating earnings (loss)
Impairment of goodwill
Foreign exchange
Finance charges
Earnings (loss) before income taxes
Income taxes
Net earnings (loss)
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
1,378,336
186,317
(9,029)
1,555,624
546,719
10,240
(83,094)
473,865
486,655
166,486
281,987
(461,263)
17,117
(33,251)
121,043
(566,172)
(202,736)
(363,436)
2,017,110
343,556
(10,128)
2,350,538
821,490
57,954
(79,074)
800,370
448,669
126,699
–
225,002
95,170
(946)
109,701
21,077
(12,075)
33,152
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
2015
2014
2013
589,759
759,472
226,129
(19,736)
1,555,624
2,077,077
2,096,214
705,399
4,878,690
1,077,814
1,096,918
195,487
(19,681)
2,350,538
2,434,774
2,244,867
629,355
5,308,996
1,002,199
901,246
137,681
(11,149)
2,029,977
2,082,958
2,006,519
489,646
4,579,123
Precision Drilling Corporation 2015 Annual Report
25
2015 COMPARED WITH 2014
Net loss in 2015 was $363 million, or $1.24 per diluted share, compared with net earnings of $33 million, or $0.11 per
diluted share, in 2014. During the year, we recorded a pre-tax asset decommissioning charge, impairment of property,
plant and equipment and goodwill write down totalling $466 million that reduced after-tax net earnings by $329 million
and net earnings per diluted share by $1.12 compared with a pre-tax asset decommissioning charge and goodwill
write down totalling $222 million that reduced net earnings by $182 million and net earnings per diluted share by
$0.62 in 2014.
Revenue was $1,556 million, 34% lower than 2014. The decrease was the result of lower activity from our North
American operations.
Adjusted EBITDA in 2015 was $474 million, 41% lower than 2014, primarily because of lower activity levels in all of our
North American based operations. Activity, as measured by drilling utilization days, decreased 48% in Canada and 40%
in the U.S., and increased 1% internationally compared with 2014.
Impairment
Under IFRS, we are required to assess the carrying value of our assets in cash generating units (CGUs) containing
goodwill annually and CGUs when indicators of impairment exist. As a result of continued low commodity prices
and their impact on current and future industry activity, we completed an impairment test for all of our CGUs as at
December 31, 2015. The test involves determining a value in use based on a multi-year discounted cash flow approach
with cash flow assumptions based on historical and expected future results. The resulting value in use is then compared
to the carrying value of the CGU. As a result of these tests, it was determined that property, plant and equipment was
impaired by US$73 million in our U.S. contract drilling business, by US$49 million in our international contract drilling
business, and by US$26 million in our Mexico contract drilling business.
As a result of similar tests during the third quarter of 2015, it was determined that property, plant and equipment in our
Canadian well service business were impaired by $73 million and property, plant and equipment in our U.S. completion
and production business were impaired by $7 million. In addition, goodwill associated with our rentals cash generating
unit was impaired for its full value of $17 million. These impairment adjustments were reflected in our third quarter 2015
financial statements.
Foreign Exchange
We recognized a foreign exchange gain of $33 million in 2015 (2014 – $1 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.
Finance Charges
Finance charges were $121 million, an increase of $11 million compared with 2014. The increase is the result of the
impact of the weaker Canadian dollar on our U.S. dollar denominated interest and the issuance, in June 2014, of
US$400 million 5.25% senior notes due in 2024, partially offset by an increase of $14 million in interest income from the
settlement of an income tax dispute.
Income Taxes
Income taxes were a recovery of $203 million, $191 million higher than the $12 million recovery booked in 2014 mainly
due to lower operating results from the loss on asset decommissioning and impairment charges in the year.
In April 2015, we received payment from the Ontario Minister of Revenue of $69 million representing $55 million owed
to us on a reassessment of income tax, recorded as an income tax recoverable on the Consolidated Statements of
Financial Position, plus interest of $14 million.
26 Management’s Discussion and Analysis
2014 COMPARED WITH 2013
Net earnings in 2014 were $33 million, or $0.11 per diluted share, compared with $191 million, or $0.66 per diluted
share, in 2013. During the year, we recorded a pre-tax asset decommissioning charge and goodwill write down totalling
$222 million that reduced net earnings by $182 million and net earnings per diluted share by $0.62. Effective January 1,
2014, we began calculating depreciation on our drilling rigs and service rigs on a straight-line basis, which reduced net
earnings by approximately $29 million, or $0.10 per diluted share, compared with what net earnings would have been
using the previous depreciation method.
Revenue was $2,351 million, 16% higher than 2013. The increase was the result of improved utilization and average
pricing in our Contract Drilling Services segment.
Adjusted EBITDA in 2014 was $800 million, 25% higher than 2013, primarily because of higher activity levels and higher
average pricing in our Contract Drilling Services segment. Activity, as measured by drilling utilization days, increased 8%
in Canada, 16% in the U.S., and 14% internationally compared with 2013.
Foreign Exchange
We recognized a foreign exchange gain of $1 million in 2014 (2013 – $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.
Finance Charges
Finance charges were $110 million, an increase of $16 million compared with 2013. The increase was the result of the
issuance, in June 2014, of US$400 million 5.25% senior notes due in 2024 and the impact of the weaker Canadian dollar
on our U.S. dollar denominated interest.
Income Taxes
Income taxes were a recovery of $12 million, $42 million lower than 2013 mainly due to lower operating results from asset
decommissioning charges in the year.
Precision Drilling Corporation 2015 Annual Report
27
Segmented Results
CONTRACT DRILLING SERVICES
Financial Results
Adjusted EBITDA and operating earnings (loss) 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
Restructuring
Adjusted EBITDA
Depreciation and amortization
Loss on asset decommissioning
Impairment of property, plant and equipment
2015
1,378,336
777,280
43,427
10,909
546,720
439,621
165,109
202,414
% of
revenue
56.4
3.1
0.8
39.7
31.9
12.0
14.7
2014
2,017,110
1,147,826
47,794
–
821,490
381,465
97,947
–
Operating earnings (loss)
(260,064)
(18.9)
342,078
% of
revenue
56.9
2.4
–
40.7
18.9
4.8
–
17.0
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
2015 Compared with 2014
Revenue from Contract Drilling Services was $1,378 million, 32% lower than 2014, mainly due to lower activity in North
America, partially offset by higher average day rates in North America as a greater proportion of our drilling rigs were
working under term contract.
Operating expenses were 56% of revenue, compared with 57% in 2014. On a per utilization day basis, operating costs
for the drilling rig divisions in Canada and the United States were higher than the prior year by 5% primarily because
of fixed costs spread across lower activity partially offset by cost saving initiatives. Internationally, operating costs on
a per utilization basis were lower than the prior year by 6% primarily due to certain rigs being on standby. General and
administrative expenses for 2015 were lower than 2014 as result of cost saving initiatives undertaken during 2015,
partially offset by the impact of the weakening Canadian dollar on our U.S. dollar denominated costs. Restructuring costs
incurred in 2015 were primarily severance related to right size the business for current activity levels.
Operating loss was $260 million, compared with operating earnings of $342 million in 2014. Operating results were
negatively impacted by the impairment of property, plant and equipment; the decommissioning of certain drilling rigs
and spare equipment; the decrease in activity in our North American operating segments; and depreciation from capital
asset additions in 2015 and 2014. Excluding asset impairment and decommissioning charges, operating earnings would
have been $108 million in 2015 compared with $440 million in 2014.
Capital expenditures in 2015 were $459 million:
$361 million – to expand our asset base
$49 million – to upgrade existing equipment
$49 million – on maintenance and infrastructure.
Most of the expansion capital was on 18 new-build rigs, as part of our rig build program; 17 of these were completed
and placed into service by December 31, 2015; the remaining rig was placed into service in February 2016.
Two new-build rigs to be delivered in early 2017 for our customer in Kuwait were started in 2015; most of the expansion
capital related to these rigs to be incurred in 2016.
28 Management’s Discussion and Analysis
Operating Statistics
Year ended December 31
Number of drilling rigs (year-end)
Drilling utilization days (operating and moving)
Canada
U.S.
International
Drilling revenue per utilization day
Canada (Cdn$)
U.S. (US$)
International (US$)
Drilling statistics (Canadian operations only)
Wells drilled
Average days per well
Metres drilled (hundreds)
Average metres per well
2015
251
17,238
21,172
4,084
23,670
25,901
43,491
1,351
11.4
3,224
2,386
% increase/
(decrease)
(19.8)
(47.5)
(39.6)
1.2
6.4
6.5
(0.9)
(56.3)
21.3
(45.0)
25.8
2014
313
32,810
35,075
4,036
22,250
24,330
43,885
3,091
9.4
5,864
1,897
% increase/
(decrease)
(4.3)
7.5
15.9
13.5
0.6
3.2
17.2
(3.7)
11.9
5.2
9.3
2013
327
30,530
30,268
3,555
22,108
23,575
37,445
3,211
8.4
5,576
1,736
% increase/
(decrease)
1.9
(5.6)
(12.5)
70.4
5.1
(0.5)
21.4
4.1
(10.6)
6.6
2.4
Canadian Drilling
Revenue from Canadian drilling was down $322 million, or 44%, from 2014. Drilling rig activity, as measured by utilization
days, was down 51%.
Adjusted EBITDA was $181 million, 48% lower than 2014, because of lower drilling activity partially offset by cost
reduction initiatives.
Depreciation expense for the year was $12 million higher than 2014 because of depreciation expense associated with
new equipment.
Drilling Statistics – Canada
In 2015, we completed three new-build rigs, transferred five rigs to Canada from the U.S., and decommissioned 48
legacy rigs, bringing our Canadian 2015 year-end net rig count to 134 (2014 – 174).
The industry drilling rig fleet decreased as well – there were approximately 721 rigs at the end of 2015 compared with
797 at the end of 2014. Our operating day utilization was 24% (2014 – 42%), compared with industry utilization of 23%
(2014 – 44%).
Our average dayrates in Canada increased 6% in 2015 with the addition of new-build and upgraded rigs to our fleet
resulting in a better rig mix.
U.S. Drilling
Revenue from U.S. drilling was lower than 2014 by US$304 million, or 36%. Drilling rig activity, as measured by utilization
days, was down 40% while average revenue per day was up 7%.
Adjusted EBITDA was US$235 million, 35% lower than US$359 million in 2014, mainly because of lower industry activity.
Depreciation expense for the year was $3 million higher than 2014 because of depreciation expense associated with
new equipment.
Drilling Statistics – U.S.
In 2015, we completed 13 new-build rigs, transferred five rigs to our Canadian fleet, and decommissioned 30 rigs,
leaving our U.S. year-end net rig count at 102 (2014 – 124). In 2015, we averaged 58 rigs working, a 40% decrease from
96 rigs in 2014. The industry drilling fleet declined as well, averaging 944 active land rigs in 2015, down 48% from 1,806
rigs in 2014.
Precision Drilling Corporation 2015 Annual Report
29
Our average dayrates in the U.S. increased 7% in 2015 with the addition of new-build and upgraded rigs to our fleet
resulting in a better rig mix. Turnkey utilization days decreased 52% over 2014 and accounted for approximately 2% of
our U.S. rig utilization compared with 3% in 2014.
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
2015
2014
Precision
Industry (1)
Precision
Industry (1)
80
57
51
45
58
1,353
873
829
720
944
94
93
97
100
96
1,724
1,802
1,842
1,856
1,806
COMPLETION AND PRODUCTION SERVICES
Financial Results
Adjusted EBITDA and operating earnings (loss) 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
Restructuring
Adjusted EBITDA
Depreciation and amortization
Loss on asset decommissioning
Impairment of property, plant and equipment
2015
186,317
156,089
16,355
3,634
10,239
32,396
1,377
79,573
% of
revenue
83.8
8.7
2.0
5.5
17.4
0.7
42.7
2014
343,556
268,129
17,473
–
57,954
58,621
28,752
–
% of
revenue
78.0
5.1
–
16.9
17.1
8.4
–
2013
323,353
242,768
19,553
–
61,032
32,630
–
–
Operating earnings (loss)
(103,107)
(55.3)
(29,419)
(8.6)
28,402
% of
revenue
75.1
6.0
–
18.9
10.1
–
–
8.8
Revenue from Completion and Production Services was $186 million in 2015, 46% lower than 2014, mainly because of
lower activity and pricing across all of our product lines.
Operating loss was $103 million in 2015, compared with a loss of $29 million in 2014, because of lower activity and the
charge for impairment of property, plant and equipment. In 2014, we incurred an asset decommissioning charge of
$29 million and a loss on disposal of our U.S. coil tubing assets of $14 million.
Operating expenses were 84% of revenue, 6% higher than 2014, mainly because of lower activity and lower revenue rates.
Depreciation, excluding the loss on disposal of our coil tubing assets in the prior year, was 28% less than 2014 because
of a lower asset base from asset decommissioning, impairments and disposals.
Capital expenditures were $3 million, entirely on maintenance of existing assets and infrastructure.
Revenue from Precision Well Servicing in Canada was $100 million, down $89 million from 2014 as activity was down
43% and average revenue rates were down 7%.
Revenue from our U.S. based completion and production businesses was US$33 million, 57% lower than 2014. The
decrease was the result of lower activity and the sale of our U.S. based coil tubing assets in the fourth quarter of 2014.
Revenue from Precision Rentals was $24 million, 42% lower than 2014. The decrease was due to lower activity and lower
revenue rates from the competitive market.
Revenue from Precision Camp Services was $20 million, 46% lower than 2014, because of a decrease in base camp
activity. Precision operated four base camps and 46 drill camps during 2015.
30 Management’s Discussion and Analysis
Operating Results
Year ended December 31
Number of service rigs (end of year)
Service rig operating hours
Revenue per operating hour
2015
163
149,754
784
% increase/
(decrease)
(7.9)
(45.2)
(13.6)
2014
177
273,194
907
% increase/
(decrease)
(20.3)
(3.7)
6.2
2013
222
283,576
854
% increase/
(decrease)
3.7
(3.8)
14.8
In 2015, we decommissioned nine service rigs and three snubbing units.
Service rig hours declined 45% as industry activity declined. Service rig rates decreased 14% as bidding for work
became more competitive.
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, except where noted)
2015
2014
2013
Revenue
Expenses
Operating
General and administrative
Restructuring
Adjusted EBITDA
Depreciation and amortization
Operating earnings (loss)
–
–
76,994
6,100
(83,094)
14,998
(98,092)
–
–
79,074
–
(79,074)
8,583
(87,657)
–
–
75,863
–
(75,863)
8,312
(84,175)
Our Corporate and Other 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 $77 million in 2015, $2 million less than 2014. The decrease is mainly related to
cost cutting initiatives taken in 2015, partially offset foreign exchange translation on U.S. dollar based costs. In 2015,
corporate general and administrative costs were 5.0% of consolidated revenue compared with 3.4% in 2014 and 3.7%
in 2013.
Quarterly Financial Results
Adjusted EBITDA and funds provided by operations are additional GAAP measures. See page 5 for more information.
2015 – 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
512,120
163,384
24,033
0.08
0.08
155,186
215,138
0.07
334,462
88,355
(29,817)
(0.10)
(0.10)
53,173
169,877
0.07
364,089
111,031
(86,700)
(0.30)
(0.30)
99,228
61,049
0.07
344,953
111,095
(270,952)
(0.93)
(0.93)
49,503
70,952
0.07
Precision Drilling Corporation 2015 Annual Report
31
2014 – 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
672,249
237,274
101,557
0.35
0.35
231,393
170,127
0.06
475,174
129,695
(7,174)
(0.02)
(0.02)
97,805
228,412
0.06
584,590
199,390
52,813
0.18
0.18
196,217
146,733
0.06
618,525
234,011
(114,044)
(0.39)
(0.39)
172,059
134,887
0.07
Seasonality
Drilling and well servicing activity is affected by seasonal weather patterns and ground conditions. In northern Canada,
some drilling sites can only be accessed in the winter once the terrain is frozen, which is usually late in the fourth quarter.
Thus, activity peaks in the winter, in the fourth and first quarters. In the spring, wet weather and the spring thaw in
Canada and the northern U.S. 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 2015 Compared with Fourth Quarter 2014
In the fourth quarter, we recorded a net loss of $271 million, or net loss per diluted share of $0.93, compared with a
net loss of $114 million, or $0.39 per diluted share, in the fourth quarter of 2014. We incurred asset decommissioning
and impairment charges totalling $369 million that, after-tax, reduced net earnings by $254 million and net earnings per
diluted share by $0.87.
Revenue in the fourth quarter was $345 million or 44% lower than the fourth quarter of 2014, mainly due to lower drilling
activity in the U.S., Canada and internationally. Revenue from our Contract Drilling Services and Completion and
Production Services segments both decreased over the comparative prior year period by 42% and 53%, respectively.
Adjusted EBITDA in the fourth quarter this quarter of $111 million or 53% lower than the fourth quarter of 2014. Our
activity for the quarter, as measured by drilling rig utilization days, decreased 51% in Canada, 55% in the U.S. and 23%
internationally, compared with the fourth quarter of 2014.
Our Adjusted EBITDA as a percentage of revenue was 32% this quarter, compared with 38% in the fourth quarter
of 2014. The decrease in adjusted EBITDA as a percentage of revenue was mainly due to decreases in activity and
profitability in our Contract Drilling Services segment and restructuring costs incurred in the current quarter.
As a percentage of revenue, operating costs were 56% in the fourth quarter of 2015 and 58% in the same quarter of
2014. Our portfolio of term customer contracts and a highly variable operating cost structure, helped us manage our
Adjusted EBITDA margin.
Contract Drilling Services
Revenue from Contract Drilling Services was $306 million this quarter, or 42% lower than the fourth quarter of 2014,
while adjusted EBITDA decreased by 43% to $134 million. The decreases were mainly due to lower drilling rig utilization
days in our Canadian, U.S. and international contract drilling businesses partially offset by higher average day rates in
all markets.
Drilling rig utilization days in Canada (drilling days plus move days) were 4,176 during the fourth quarter of 2015, a
decrease of 51% compared with 2014, primarily due to the decrease in industry activity resulting from lower commodity
prices. Drilling rig utilization days in the U.S. were 4,109, or 55% lower than the same quarter of 2014 as U.S. activity was
down due to lower industry activity. Drilling rig utilization days in our international business were 822, or 23% lower than
the same quarter of 2014, as activity declines in the Kurdistan region of Iraq were partially offset by adding a contracted
rig in Kuwait in 2015.
32 Management’s Discussion and Analysis
Compared with the same quarter in 2014, drilling rig revenue per utilization day was up 13% in Canada, up 2% in the U.S.
and up 10% internationally. In Canada, the day rate increase was the result of rig mix, as we operated proportionately
more Tier 1 rigs compared with the prior year, and one-time payments from customers due to contractual shortfalls. The
increase in average day rates for the U.S. was primarily due to a higher percentage of revenue being generated from
Tier 1 rigs and higher idle-but-contracted payments in the quarter relative to the prior year comparative quarter. The
average international day rate is up due to the recognition of an early termination payment of US$6 million in the quarter
and the addition of a new-build contracted rig in Kuwait.
In Canada, 53% of utilization days in the quarter were generated from rigs under term contract, compared with 42% in
the fourth quarter of 2014. In the U.S., 64% of utilization days were generated from rigs under term contract in the fourth
quarter of 2015, compared with 69% in the fourth quarter of 2014. At the end of the quarter, we had 37 drilling rigs under
contract in Canada, 27 in the U.S. and nine internationally.
Operating costs were 52% of revenue for the quarter, which was three percentage points lower than the prior year
period. On a per utilization day basis, operating costs for the drilling rig division in Canada were lower than the prior year
primarily because of crew wage reduction and cost saving initiatives. In the U.S., operating costs for the quarter on a per
day basis were slightly higher from the fourth quarter of 2014 primarily as a result of having fixed costs spread across
lower activity, partially offset by no turnkey activity in the current quarter.
General and administrative costs were higher than the prior year by $2 million due to the impact of the weakening
Canadian dollar on our U.S. dollar denominated costs in 2015 offset by a recovery of share based compensation in the
fourth quarter of 2014.
Restructuring costs of $2 million in the quarter related to cost cutting measures taken in response to the persistent
downturn in industry activity levels.
Depreciation expense in the quarter was 11% higher than in the fourth quarter of 2014 due to the addition of new-build
rigs deployed in 2014 and 2015 and the impact of the weakening Canadian dollar compared with the U.S. dollar and the
associated impact on our U.S. denominated depreciation expense.
Due to the significant decrease in industry activity resulting from the decline in oil and natural gas prices, we completed
an impairment test of our businesses in our Contract Drilling Services segment in the fourth quarter of 2015. The
recoverable amount of property, plant and equipment and goodwill was determined using a multi-year discounted
cash flow approach with cash flow assumptions based on historical and expected future results. As a result of this
test, it was determined that property, plant and equipment were impaired by US$73 million in our U.S. contract drilling
business, by US$49 million in our international contract drilling business, and by US$26 million in our Mexico contract
drilling business.
During the fourth quarter, the Contract Drilling Services segment recognized a loss of $165 million related to the
decommissioning of 79 drilling rigs, comprised of 48 in Canada, 30 in the United States, and one in Mexico, along with
certain spare equipment. Low commodity prices combined with the entry of new-build drilling rigs in the market have
effectively rendered legacy assets obsolete.
Completion and Production Services
Revenue from Completion and Production Services was down $48 million, or 53%, compared with the fourth quarter of
2014 due to lower activity levels in all service lines and lower average rates. In response to lower oil prices, customers
curtailed spending including well completion and production programs. Our well servicing activity in the quarter was
down 45% from the fourth quarter of 2014. Revenue was also negatively impacted by the sale of our U.S. coil tubing
operations in the fourth quarter of last year. Approximately 87% of our fourth quarter Canadian service rig activity was
oil related.
During the quarter, Completion and Production Services generated 87% of its revenue from Canadian and 13% from
U.S. operations.
Precision Drilling Corporation 2015 Annual Report
33
Average service rig revenue per operating hour in the fourth quarter was $760 or $136 lower than the fourth quarter of
2014. The decrease was primarily the result of industry pricing pressure and the sale of our U.S. coil tubing assets, which
generally received a higher rate per hour.
Adjusted EBITDA was $16 million lower than the fourth quarter of 2014 due to declines in activity and pricing and
$2 million in restructuring costs in the current quarter.
Operating costs as a percentage of revenue increased to 86% in the fourth quarter of 2015, from 78% in the fourth
quarter of 2014.
General and administrative costs were $1 million higher than the prior year due to a recovery of share based
compensation in the fourth quarter of 2014, partially offset by cost saving initiatives.
Restructuring costs of $2 million in the quarter related to cost cutting measures taken during the quarter in response to
the persistent decline in industry activity levels.
Depreciation in the quarter was 75% lower than the fourth quarter of 2014 because of a lower asset base after
decommissioning equipment in the fourth quarter of 2014, the recording of an impairment charge in the third quarter of
2015, and the disposal of our U.S. coil tubing assets part way through the fourth quarter of 2014.
Corporate and Other
The Corporate and Other segment had an adjusted EBITDA loss of $22 million for the fourth quarter of 2015, $8 million
more than the 2014 comparative period due primarily to restructuring charges of $3 million incurred in the current year
quarter and higher share based incentive compensation.
Net financial charges for the quarter were $34 million, an increase of $4 million from the fourth quarter of 2014, driven
by the impact of the weaker Canadian dollar on our U.S. dollar denominated interest partially offset by customer related
interest income of $2 million in the current quarter. We had a foreign exchange gain of $1 million during the fourth
quarter of 2015 due to the weakening of the Canadian dollar versus the U.S. dollar, which affected the net U.S. dollar
denominated monetary position in the Canadian dollar-based companies.
Capital expenditures were $66 million in the fourth quarter compared with $338 million in the fourth quarter of 2014.
Spending in the fourth quarter of 2015 included:
$39 million to expand our asset base
$6 million to upgrade existing equipment
$21 million on maintenance and infrastructure.
34 Management’s Discussion and Analysis
Financial Condition
Management’s
Discussion and
Analysis
The oilfield services business is inherently cyclical. To manage this variability, we focus on maintaining a strong balance
sheet so we have the financial flexibility we need to continue to manage our capital expenditures 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 tightly 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 growth capital investments.
LIQUIDITY
In 2015, due to the continued decline in global oil prices and uncertain industry outlook, we amended certain financial
covenants under our syndicated senior secured revolving credit facility (as amended, the Senior Credit Facility)
to provide for temporary covenant relief, and reduced the size of the Senior Credit Facility to US$550 million from
US$650 million. See Sources and Uses of Cash – Financing Activity on page 37 for more information.
In June 2014, we issued US$400 million of 5.25% senior notes due in 2024 in a private offering. The Notes are
guaranteed on a senior unsecured basis by current and future U.S. and Canadian subsidiaries that also guarantee our
Senior Credit Facility and certain other indebtedness.
As at December 31, 2015, our liquidity was supported by a cash balance of $445 million, our Senior Credit Facility of
US$550 million, operating facilities totalling approximately $60 million, and a US$40 million secured facility for letters of
credit. Our ability to draw on our Senior Credit Facility is governed by financial covenants. See Sources and Uses of Cash
– Covenants on page 39.
At December 31, 2015, including letters of credit, we had approximately
$2,330 million (2014 – $1,942 million) outstanding under our secured and
unsecured credit facilities and $26 million in unamortized debt issue
costs. Our Senior Credit Facility includes financial ratio covenants that
are tested quarterly.
Key Ratios
We ended 2015 with a long-term debt to
long-term debt plus equity ratio of 0.51, and
a ratio of long-term debt to cash provided by
operations of 4.22.
We ended 2015 with a long-term debt to long-term debt plus equity ratio of 0.51 (2014 – 0.43) and a ratio of long-term
debt to cash provided by operations of 4.22 (2014 – 2.72).
The current blended cash interest cost of our debt is about 6.2%.
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 to our shareholders
relative to the shareholder returns of our peers.
Precision Drilling Corporation 2015 Annual Report
35
Financial Position and Ratios
(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
December 31,
2015
December 31,
2014
December 31,
2013
536,815
3.2
2,180,510
2,210,231
4,878,690
3,245,924
0.51
4.22
4.60
0.67
653,630
2.3
1,852,186
1,881,275
5,308,996
3,265,865
0.43
2.72
2.31
0.57
305,783
1.9
1,323,268
1,355,535
4,579,123
3,919,763
0.36
3.09
2.07
0.34
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. On March 3, 2016, Moody’s downgraded our corporate credit rating
from Ba2 to B2 and senior unsecured credit rating from Ba2 to B3.
Corporate credit rating
Senior Credit Facility rating
Senior unsecured credit rating
Moody’s
B2
S&P
BB+
Not rated
Not rated
B3
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 can materially 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.
Hedge of Investments in U.S. Operations
We utilize foreign currency long-term debt to hedge our exposure to changes in the carrying values of our net investment
in certain foreign operations as a result of changes in foreign exchange rates.
Effective January 1, 2015, we have included the US$400 million of 5.25% senior notes due in 2024 as a designated
hedge of our investment in our U.S. dollar denominated foreign operations, and now all of our U.S. dollar senior notes
are designated as a net investment hedge.
Effective April 30, 2015, a portion of our U.S. dollar denominated debt that was previously treated as a hedge of our net
investment in our U.S. operations was designated as a hedge of the investment in our international operations that have
a U.S. dollar functional currency.
36 Management’s Discussion and Analysis
To be accounted for as a hedge, the foreign currency denominated long-term debt must be designated and documented
as such and must be effective at inception and on an ongoing basis. We recognize the effective amount of this hedge
(net of tax) in other comprehensive income. We recognize ineffective amounts in earnings.
SOURCES AND USES OF CASH
At December 31 (thousands of dollars)
Cash from operations
Cash used in investing
Surplus (deficit)
Cash from (used in) financing
Effect of exchange rate changes on cash
Net cash generated (used)
2015
517,016
(541,102)
(24,086)
(84,044)
61,408
(46,722)
2014
680,159
(629,987)
50,172
329,704
30,999
410,875
2013
428,086
(526,535)
(98,449)
21,517
4,770
(72,162)
Cash from Operations
In 2015, we generated cash from operations of $517 million compared with $680 million in 2014. The decrease is
primarily the result of lower operating results due to the industry downturn, partially offset by lower income taxes paid
in 2015.
Investing Activity
We made growth and sustaining capital investments of $459 million in 2015:
$361 million in expansion capital
$49 million in upgrade capital
$49 million in maintenance and infrastructure capital.
The $459 million in capital expenditures in 2015 was split between segments as follows:
$452 million in Contract Drilling Services
$2 million in Completion and Production Services
$5 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.
We sold underutilized capital assets for proceeds of $10 million in 2015.
Financing Activity
On March 27, 2015, we amended certain financial covenants under the credit agreement governing our Senior Credit
Facility to, among other things, temporarily increase the maximum consolidated total debt to Adjusted EBITDA ratio (as
defined in the debt agreement) to 6:1 from 4:1 and temporarily reduce the minimum interest coverage ratio to 2.5:1 from
2.75:1, in each case until December 31, 2016.
On October 27, 2015, we further amended the credit agreement, whereby we reduced the size of the Senior Credit
Facility to US$550 million from US$650 million and eliminated the consolidated total debt to adjusted EBITDA financial
covenant ratio in its entirety. We further decreased the minimum interest coverage ratio to 2:1 from 2.5:1 for a temporary
period up to and including December 31, 2017, which will revert to 2.5:1 thereafter until the maturity date of the facility.
We also reduced the maximum consolidated senior debt to adjusted EBITDA financial covenant ratio to 2.5:1 from 3:1
and added a new debt covenant whereby we agreed to not incur or assume more than US$250 million in new unsecured
debt other than where the new unsecured debt is used to refinance existing unsecured debt or the new debt is assumed
through an acquisition.
Precision Drilling Corporation 2015 Annual Report
37
As at March 4, 2016, we were in compliance with all covenants and expect to remain compliant throughout 2016 in our
Senior Credit Facility, which remains undrawn except for US$46 million in outstanding letters of credit.
In May 2015, we increased the size of our demand letter of credit facility to US$40 million from US$25 million to provide
additional availability to issue letters of credit for international opportunities.
In June 2014, we issued US$400 million of 5.25% senior notes due in 2024 in a private offering. The notes are
guaranteed on a senior unsecured basis by current and future U.S. and Canadian subsidiaries that also guarantee our
Senior Credit Facility and certain other indebtedness.
As at March 4, 2016, our operating facility of $40 million with Royal Bank of Canada was undrawn except for $24 million
in outstanding letters of credit; our operating facility of US$15 million with Wells Fargo remained undrawn; and our
demand facility for letters of credit of US$40 million with HSBC Canada had US$5 million available.
Debt
As at December 31, 2015, we had a cash balance of $445 million and available capacity under our secured facilities of
$754 million.
As at December 31, 2015, we had $2,207 million outstanding under our senior unsecured notes.
Amount
Availability
Used for
Maturity
Senior Credit Facility (secured)
US$550 million
(extendible, revolving term credit facility
with US$250 million accordion feature)
Operating facilities (secured)
$40 million
Undrawn, except US$46 million in
outstanding letters of credit
General corporate purposes
June 3, 2019
Undrawn, except $25 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$40 million
Senior notes (unsecured)
Undrawn, except US$25 million in
outstanding letters of credit
Letters of credit
$200 million
US$650 million
US$400 million
US$400 million
Fully drawn
Fully drawn
Fully drawn
Fully drawn
Debt repayment
Debt repayment and general
corporate purposes
Capital expenditures and
general corporate purposes
Capital expenditures and
general corporate purposes
March 15, 2019
November 15, 2020
December 15, 2021
November 15, 2024
38 Management’s Discussion and Analysis
Covenants
Senior Credit Facility
The Senior Credit Facility requires that we comply with certain financial covenants including a leverage ratio of
consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement
(Adjusted EBITDA) of less than 2.5:1. For purposes of calculating the leverage ratio, consolidated senior debt only
includes secured indebtedness. Adjusted EBITDA as defined in our Senior Credit Facility agreement differs from
Adjusted EBITDA as defined under Additional GAAP Measures by the exclusion of bad debt expense and certain
foreign exchange amounts. As at December 31, 2015, our consolidated senior debt to Adjusted EBITDA ratio was
negative 0.55:1.
Under the Senior Credit Facility, we are required to maintain an Adjusted EBITDA coverage ratio, calculated as Adjusted
EBITDA to interest expense for the most recent four consecutive fiscal quarters, of greater than 2:1, which reverts to 2.5:1
for periods ending after December 31, 2017 until the maturity date of the facility. As at December 31, 2015, our Adjusted
EBITDA coverage ratio was 4.26:1.
In addition, the Senior Credit Facility contains certain covenants that place restrictions on our ability to incur or assume
additional indebtedness; dispose of assets; pay dividends, share redemptions or other distributions; change our
primary business; incur liens on assets; engage in transactions with affiliates; enter into mergers, consolidations or
amalgamations; and enter into speculative swap agreements. At December 31, 2015, we were in compliance with the
covenants of the Senior Credit Facility.
Senior Notes
The senior notes require that we comply with certain financial covenants including an Adjusted EBITDA (as defined in
the note agreements) to interest coverage ratio of greater than 2:1 for the four most recent consecutive fiscal quarters.
In the event that our Adjusted EBITDA to interest coverage ratio is less than 2:1 for the four most recent consecutive
fiscal quarters, the senior notes restricts our ability to incur additional indebtedness. The senior notes contain a
restricted payments covenant that limits our ability to make payments in the nature of dividends, distributions and
repurchases from shareholders. This restricted payment basket grows by, among other things, 50% of consolidated net
earnings, and decreases by 100% of consolidated net losses as defined in the note agreements, and payments made
to shareholders. Based on our consolidated financial results for the period ended December 31, 2015, the restricted
payments basket was negative $152 million, therefore prohibiting us from making any further dividend payments until the
restricted payments basket once again becomes positive. As a result, we announced the suspension of our dividend on
February 11, 2016.
In addition, the senior notes contain certain covenants that limit our ability and the ability of certain subsidiaries to incur
additional indebtedness and issue preferred stock; create liens; create or permit to exist restrictions on our ability or
certain subsidiaries to make certain payments and distributions; engage in amalgamations, mergers or consolidations;
make certain dispositions and engage in transactions with affiliates.
At December 31, 2015, we were in compliance with the covenants of the senior notes.
Precision Drilling Corporation 2015 Annual Report
39
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, 2015
(thousands of dollars)
Long-term debt (1)
Interest on long-term debt (1)
Purchase of property, plant and equipment (1)
Operating leases (1)(2)
Contractual incentive plans (3)(1)
Total
Less than
1 year
–
137,647
118,095
19,003
18,189
292,934
Payments due (by period)
1-3 years
–
275,294
59,679
27,541
49,264
411,778
4-5 years
1,099,600
244,551
80,991
17,013
–
More than
5 years
1,107,200
147,107
–
7,369
–
Total
2,206,800
804,599
258,765
70,926
67,453
1,442,155
1,261,676
3,408,543
(1) U.S. dollar denominated balances are translated at the period end exchange rate of Cdn$1.00 equals US$0.7225.
(2) The balance due within one year relates to the costs committed to complete the two rigs scheduled for delivery in Kuwait in early 2017. The remaining balance relates to the costs
of rig equipment with a flexible delivery schedule wherein we can take delivery of the equipment between 2016 and 2019 at our discretion.
(3) 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 the five-day weighted average share price on the TSX of $5.57 at
December 31, 2015.
CAPITAL STRUCTURE
Shares outstanding
Deferred shares outstanding
Share options outstanding
March 4,
2016
December 31,
2015
December 31,
2014
December 31,
2013
292,912,090
292,912,090
292,819,921
291,979,671
195,743
195,743
13,260,470
10,750,833
226,010
8,560,088
221,112
8,074,694
You can find more information about our capital structure in our AIF, available on our website and on SEDAR.
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 and in the fourth quarter of 2014, our Board of Directors
approved an increase in the quarterly dividend to $0.07 per common share.
Effective for the first quarter of 2016, we suspended the quarterly dividend. See Covenants – Senior Notes on page 39
for more information.
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,
2015
December 31,
2014
December 31,
2013
292,912,090
292,819,921
291,979,671
5.47
1,602,229
2,180,510
(536,815)
3,245,924
7.06
2,067,309
1,852,186
(653,630)
3,265,865
9.94
2,902,278
1,323,268
(305,783)
3,919,763
40 Management’s Discussion and Analysis
Accounting Policies and Estimates
Management’s
Discussion and
Analysis
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.
Our significant accounting policies are described 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 reviewed for impairment periodically 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 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 projecting
cash flows and selecting 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 we
believe the estimates are reasonable and consistent with current conditions, internal planning, and expected future
operations, such estimations are subject to significant uncertainty and judgment.
Precision Drilling Corporation 2015 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 parts of the drilling rig equipment represent a 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 expenses 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.
ACCOUNTING POLICIES ADOPTED JANUARY 1, 2015
There were no new accounting policies adopted by Precision with an initial application date of January 1, 2015.
ACCOUNTING POLICIES NOT YET ADOPTED
IFRS 9, Financial Instruments
In November 2009, the International Accounting Standards Board (IASB) issued IFRS 9, replacing IAS 39, Financial
Instruments, Recognition and Measurement. IFRS 9 will be issued in three phases. The first phase, which has already
been issued, addresses the accounting for financial assets and financial liabilities. The second phase will address
impairment of financial instruments, while the third phase will address hedge accounting. IFRS 9 uses a single approach
to determine whether a financial asset is measured at amortized cost or fair value, and replaces the multiple category
and measurement models in IAS 39. The approach in IFRS 9 focuses on how an entity manages its financial instruments
in the context of its business model, as well as the contractual cash flow characteristics of the financial assets. The new
standard also requires a single impairment method to be used, replacing the multiple impairment methods currently
provided in IAS 39.
Requirements for financial liabilities were added to IFRS 9 in October 2010. Although the classification criteria for
financial liabilities will not change under IFRS 9, the fair value option may require different accounting for changes to the
fair value of a financial liability resulting from changes to an entity’s own credit risk.
In December 2013, new hedge accounting requirements were incorporated into IFRS 9 that increase the scope of items
that can qualify as a hedged item and change the requirements of hedge effectiveness testing that must be met to use
hedge accounting.
In July 2014, the IASB issued final amendments to IFRS 9, replacing earlier versions of IFRS 9. These amendments to
IFRS 9 introduce a single, forward-looking ‘expected loss’ impairment model for financial assets, which will require more
timely recognition of expected credit losses, and a fair value through other comprehensive income category for financial
assets that are debt instruments.
The amendments to IFRS 9 are effective for annual periods beginning on or after January 1, 2018 and are
available for earlier adoption. We do not expect that the implementation of IFRS 9 will have a material effect on the
financial statements.
42 Management’s Discussion and Analysis
IFRS 15, Revenue from Contracts with Customers
In May 2014, the IASB issued IFRS 15 to address how and when to recognize revenue as well as requiring entities to
provide users of financial statements with more informative, relevant disclosures in order to understand the nature,
amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard provides
a principles based, five-step model to be applied to all contracts with customers. This five-step model involves identifying
the contract(s) with a customer; identifying the performance obligations in the contract; determining the transaction
price; allocating the transaction price to the performance obligations in the contract; and recognizing revenue when (or
as) the entity satisfies a performance obligation.
Application of this new standard is mandatory for annual reporting periods beginning on or after January 1, 2017, with
earlier application permitted. We do not expect that the implementation of IFRS 15 will have a material effect on the
financial statements.
IFRS 16, Leases
In January 2016, the IASB issued IFRS 16 to replace the guidance currently found in IAS 17. The new standard requires
lessees to recognize a lease liability reflecting future lease payments and a right of use asset for virtually all lease
contracts. In addition, IFRS 16 has updated the definition of a lease and introduced new disclosure requirements. IFRS
16 is effective for annual periods beginning on or after January 1, 2019, with earlier application permitted in certain
circumstances. We have yet to determine the impact this new standard will have on the financial statements.
Precision Drilling Corporation 2015 Annual Report
43
Risks in our Business
Management’s
Discussion and
Analysis
Our key business risks are summarized below. Additional information and other risks in business are discussed in our
AIF, available on our website (www.precisiondrilling.com).
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 oilfield services business.
Weather conditions, governmental regulation (in Canada and elsewhere), levels of consumer demand, the availability
of pipeline capacity, U.S. and Canadian natural gas storage levels, and other factors beyond our control can also
affect the supply of and demand for oil and natural gas and lead to future price volatility. A prolonged reduction in oil
and natural gas prices would likely depress the level of exploration and production activity. This would likely result in a
corresponding decline in the demand for our services and could have a material adverse effect on our revenue, cash
flow and profitability.
Lower oil and natural gas prices could also cause our customers to terminate, renegotiate, or fail to honour their
drilling contracts with us, which could affect the anticipated revenues that support our capital expenditure program and
deliveries of new-build rigs. In addition, lower oil and natural gas prices, lower demand for oilfield services, or lower
rig utilization could affect the fair market value of our rig fleet, which in turn could trigger a write down for accounting
purposes. There is no assurance that demands for our services or conditions in the oil and natural gas and oilfield
services sector will not decline in the future, and a significant decline in demand could have a material adverse effect on
our financial condition.
We have accounts receivable with customers in the oil and natural gas industry and their revenues may be affected
by fluctuations in commodity prices. Our ability to collect receivables may be adversely affected by any prolonged
weakness in oil and natural gas prices.
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.
44 Management’s Discussion and Analysis
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 activity depends at least
in part, on the severity and duration of the winter season.
Competition
The contract drilling business is highly competitive with numerous industry participants. We compete for drilling contracts
that are usually awarded based on competitive bids. We believe pricing and rig availability are the primary factors
potential customers consider when selecting a drilling contractor. We believe other factors are also important, such as
the drilling capabilities and condition of drilling rigs, the quality of service and experience of rig crews, the safety record
of the contractor and the particular drilling rig, the offering of ancillary services, the ability to provide drilling equipment
that is adaptable to and having personnel familiar with new technologies and drilling techniques, and rig mobility
and efficiency.
Historically, contract drilling has been cyclical with periods of low demand, excess rig supply and low dayrates, followed
by periods of high demand, short rig supply and increasing dayrates. Periods of excess drilling rig supply intensify the
competition and often result in rigs being idle. There are numerous contract drilling companies in each of the markets
where we operate, and an oversupply of drilling rigs can cause greater price competition. Contract drilling companies
compete primarily on a regional basis, and the intensity of competition can vary significantly from region to region at any
particular time. If demand for drilling services is better in a region where we operate, our competitors might respond by
moving in suitable drilling rigs from other regions, reactivating previously stacked rigs or purchasing new drilling rigs.
An influx of drilling rigs into a market from any source could rapidly intensify competition and make any improvement in
the demand for our drilling rigs short-lived, which could in turn have a material adverse effect on our revenue, cash flow
and earnings.
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 revenue,
operations and financial condition.
New Capital Expenditures
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. 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 time from when a decision is made to upgrade or build new
equipment to when the equipment is built and 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 served to intensify price competition in the past and could continue to do so. This could lead
to lower rates in the oilfield services industry generally and lower utilization of existing rigs, which would have an adverse
effect on our revenue, cash flow, earnings and asset valuation.
Precision Drilling Corporation 2015 Annual Report
45
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 essential to our continued success. We cannot guarantee that our rig technology will continue to meet the
needs of our customers, especially as rigs age and technology advances, or that our competitors will not develop
technological improvements that are more advantageous, timely, or cost effective.
Employees and Suppliers
Finding and Keeping Employees
Our future success and growth depends partly on the expertise and experience of our key management. There is no
assurance that we will be able to retain key management. Losing these individuals could have a material adverse effect
on our operations and financial condition.
Our ability to provide reliable services depends on the availability of well-trained, experienced crews to operate our
field equipment. We must also balance our need to maintain a skilled workforce with cost structures that fluctuate with
activity levels. We retain the most experienced employees during periods of low utilization by having them fill lower level
positions on field crews. Many of our businesses experience manpower shortages in peak operating periods, and we
may experience more severe shortages if the industry adds more rigs, oilfield service companies expand, and new
companies enter the business.
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.
Other factors can also affect our ability to find enough workers to meet our needs. Our business requires skilled workers
who can perform physically demanding work. Volatility in oil and natural gas activity and the demanding nature of the
work, however, may prompt workers to pursue other kinds of jobs that offer a more desirable work environment and
wages competitive to ours. 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 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 programs.
To manage this risk, we maintain relationships with several key suppliers and contractors and an inventory of key
components, materials, equipment and parts. We also place advance orders for components that have long lead times.
We may, however, experience cost increases, delays in delivery due to 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
the construction of new-build drilling rigs, it can delay service to our customers and have a material adverse effect on our
revenue, cash flow and earnings.
46 Management’s Discussion and Analysis
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
revenue, cash flow and earnings.
Our operations are affected by numerous laws, regulations and guidelines relating to the protection of the environment,
including those governing the management, transportation and disposal of hazardous substances and other waste
materials. These include those relating to spills, releases, and discharges of hazardous substances or other waste
materials into the environment, requiring removal or remediation of pollutants or contaminants and imposing civil and
criminal penalties for violations. Some of 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
that are subject to special protective measures, which may expose us to additional operating costs and liabilities for
noncompliance with certain laws. Some environmental 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 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 subject of energy and the environment has created intense public debate around the world in recent years. Debate
is likely to continue for the foreseeable future, and 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 most of our customers that involves the injection of water, sand and chemicals under pressure into
rock formations to stimulate oil and natural gas production.
Increasing regulatory restrictions 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 and the outcome of these developments
and their effect on the regulatory landscape and the contract drilling industry is uncertain; however, hydraulic fracturing
laws or regulations that cause a decrease in the completion of new oil and natural gas wells and an associated decrease
in demand for our services could have a material adverse effect on our operations and financial results.
Precision Drilling Corporation 2015 Annual Report
47
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.
Many of our customers require reasonable access to credit facilities and debt capital markets to finance their oil and
gas drilling activity. If the availability of credit to our customers is reduced, they may reduce their drilling and production
expenditures, 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. Any such reduction in spending by our
customers could adversely affect our operating results and financial condition. 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.
Our Debt Facilities Contain Restrictive Covenants
Our Senior Credit Facility and each note indenture contain a number of covenants which, among other things, restrict
us and some of our subsidiaries from conducting certain activities. In addition, we must satisfy and maintain certain
financial ratio tests under the Senior Credit Facility. Events beyond our control could affect our ability to meet these
tests. If we breach any of the covenants, it could result in a default under the Senior Credit Facility or any of the note
indentures. If there is a default, the applicable lenders or note holders could decide to declare all amounts outstanding
under the Senior Credit Facility or any of the note indentures to be due and payable immediately, and terminate any
commitments to extend further credit.
Access to Additional Financing
We may need to obtain additional debt or equity financing in the future to support ongoing operations, undertake capital
expenditures, repay existing or future debt, or pursue acquisitions or other business combination transactions. Volatility
or uncertainty in the credit markets may increase costs associated with issuing debt or equity, and there is no assurance
that we will be able to access additional financing when we need it, or on terms we find acceptable or favourable. If
we are unable to obtain financing to support ongoing operations or to fund capital expenditures, acquisitions, debt
repayments, or other business combination transactions, it could limit growth and may have a material adverse effect on
our revenue, cash flow and profitability.
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 our Senior Credit
Facility, our note indentures and other debt agreements we may have in the future, and on our credit ratings. We may
not be able to access sufficient amounts under the Senior Credit 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. 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.
48 Management’s Discussion and Analysis
Credit ratings affect our financing costs, liquidity and operations over the long term and are intended as an independent
measure of the credit quality of long-term debt. Credit ratings affect our ability to obtain short and long-term financing
and the cost of this financing, and our ability to engage in certain business activities cost-effectively. If a rating agency
reduces its current rating on our debt, or downgrades us, or we experience a negative change in our ratings outlook,
it could have an adverse effect on our financing costs and access to liquidity and capital.
We regularly assess our credit policies and capital structure, and have enough liquidity to meet our needs. See Financial
Condition – Liquidity on page 35 for information.
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 can 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 do not 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 from our
U.S. and international operations will be lower.
Transaction Exposure – We have long-term debt denominated in U.S. dollars. We have designated our senior
notes as a hedge against the net asset position of our U.S. and foreign operations. This debt is converted at the
exchange rate in effect at the balance sheet dates with the resulting gains or losses included 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. Similarly, if the Canadian dollar weakens against the U.S. dollar, we will incur
a foreign exchange loss from the translation of this debt. The vast majority of our international operations are
transacted in U.S. dollars or U.S. dollar-pegged currencies. Transactions for our Canadian operations are primarily
transacted in Canadian dollars. However, we occasionally purchase goods and supplies in U.S. dollars for our
Canadian operations, and we maintain U.S. dollar cash in our Canadian operations.
Liabilities from Prior Reorganizations
We have retained all liabilities of our predecessor companies, including liabilities relating to corporate and income
tax matters.
Precision Drilling Corporation 2015 Annual Report
49
International Operations
We conduct some of our business in Mexico and the Middle East. Our growth plans contemplate establishing operations
in other international regions, 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
compliance with 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.
Government-owned petroleum companies located in some of the countries where we operate now or in the future may
have policies, or may be subject to governmental policies, that give preference to the purchase of goods and services
from companies that are majority-owned by local nationals. As such, we may rely on joint ventures, license arrangements
and other business combinations with local nationals in these countries, which may expose us to certain counterparty
risks, including the failure of local nationals to meet contractual obligations or comply with local or international laws that
apply to us.
In the international markets where we operate, we are subject to various laws and regulations that govern the operation
and taxation of our businesses and the import and export of our equipment from country to country. There may be
uncertainty about how these laws and regulations are imposed, applied or interpreted, and they could be subject to
change. Since we derive a portion of our revenues from subsidiaries outside of Canada and the U.S., the subsidiaries
paying dividends or making other cash payments or advances may be restricted from transferring funds in or out of the
respective countries, or face exchange controls or taxes on any payments or advances. We have organized our foreign
operations partly based on certain assumptions about various tax laws (including capital gains and withholding taxes),
foreign currency exchange, and capital repatriation laws and other relevant laws of a variety of foreign jurisdictions. We
believe these assumptions are reasonable; however, there is no assurance that foreign taxing or other authorities will
reach the same conclusion. If these foreign jurisdictions change or modify the laws, we could suffer adverse tax and
financial consequences.
While we have developed policies and procedures designed to achieve compliance with applicable international laws,
we could be exposed to potential claims, economic sanctions, or other restrictions for alleged or actual violations of
international laws related to our international operations, including anti-corruption and anti-bribery legislation, trade
laws and trade sanctions. The Canadian government, the U.S. Department of Justice, the Securities and Exchange
Commission (SEC), the U.S. Office of Foreign Assets Control, and similar agencies and authorities in other jurisdictions
have a broad range of civil and criminal penalties they may seek to impose against corporations and individuals for
such violations, including injunctive relief, disgorgement, fines, penalties and modifications to business practices and
compliance programs, among other things. While we cannot accurately predict the impact of any of these factors, if any
of those risks materialize, it could have a material adverse effect on our reputation, business, financial condition, results
of operations and cash flow.
50 Management’s Discussion and Analysis
Evaluation of
Controls and Procedures
Management’s
Discussion and
Analysis
Internal Control over Financial Reporting
Precision maintains internal control over financial reporting that 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 Issuer’s 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 (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO 2013).
Based on management’s assessment as at December 31, 2015, 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, 2015 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 annual report.
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, 2015, 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.
Precision Drilling Corporation 2015 Annual Report
51
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 this
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, 2015 and December 31, 2014.
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 of, 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 2013). Based on this evaluation,
management concluded that the Corporation’s internal control over financial reporting was effective as of December 31, 2015.
Also management determined that there were no material weaknesses in the Corporation’s internal control over financial
reporting as of December 31, 2015.
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, 2015, as stated in its report included in this Annual Report, and expressed an unqualified opinion on the design
and effectiveness of internal control over financial reporting as of December 31, 2015.
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 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 4, 2016
March 4, 2016
52
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, 2015 and December 31, 2014, the
consolidated statements of earnings (loss), comprehensive income (loss), 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, 2015 and December 31, 2014, 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, 2015, based on the criteria established in Internal
Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013),
and our report dated March 4, 2016 expressed an unqualified opinion on the effectiveness of the Corporation’s internal control
over financial reporting.
Chartered Professional Accountants
March 4, 2016
Calgary, Canada
Precision Drilling Corporation 2015 Annual Report
53
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, 2015, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013). 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, 2015, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (2013).
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 statements of financial position of the Corporation as
of December 31, 2015 and December 31, 2014, and the related consolidated statements of earnings (loss), comprehensive
income (loss) , changes in equity and cash flow for the years then ended, and our report dated March 4, 2016 expressed an
unqualified opinion on those consolidated financial statements.
Chartered Professional Accountants
March 4, 2016
Calgary, Canada
54
Consolidated Financial Statements
Consolidated Statements of Financial Position
(Stated in thousands of Canadian dollars)
ASSETS
Current assets:
Cash
Accounts receivable
Income tax recoverable
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,
2015
December 31,
2014
$
444,759
$
311,595
–
24,245
780,599
491,481
598,063
55,138
9,170
1,153,852
2,917
3,297
3,883,332
3,928,826
3,363
208,479
3,302
219,719
4,098,091
4,155,144
$
4,878,690
$
5,308,996
(Note 22)
(Note 23)
(Note 4)
(Note 5)
(Note 6)
Accounts payable and accrued liabilities
(Note 22)
$
235,948
$
493,038
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)
Accumulated other comprehensive income
(Note 13)
Total shareholders’ equity
Total liabilities and shareholders’ equity
See accompanying notes to consolidated financial statements.
Approved by the Board of Directors:
(Note 8)
(Note 9)
(Note 10)
(Note 11)
7,836
243,784
15,201
14,520
2,180,510
303,466
2,513,697
7,184
500,222
14,252
14,837
1,852,186
486,133
2,367,408
(Note 12)
2,316,321
2,315,539
35,800
(397,013)
166,101
31,109
48,426
46,292
2,121,209
2,441,366
$
4,878,690
$
5,308,996
Allen R. Hagerman
Director
Robert L. Phillips
Director
Precision Drilling Corporation 2015 Annual Report
55
Consolidated Statements of Earnings (Loss)
Years ended December 31,
(Stated in thousands of Canadian dollars, except per share amounts)
Revenue
Expenses:
Operating
General and administrative
Restructuring
Earnings before income taxes, finance charges, foreign
exchange, impairment of goodwill, impairment of property,
plant and equipment, loss on asset decommissioning and
depreciation and amortization
Depreciation and amortization
Loss on asset decommissioning
Impairment of property, plant and equipment
Operating earnings (loss)
Impairment of goodwill
Foreign exchange
Finances charges
Earnings (loss) before tax
Income taxes:
Current
Deferred
Net earnings (loss)
Earnings per share:
Basic
Diluted
(Note 22)
(Note 22)
(Note 4)
(Note 4)
(Note 14)
(Note 11)
(Note 18)
2015
2014
$
1,555,624
$
2,350,538
924,340
136,776
20,643
1,405,827
144,341
–
473,865
486,655
166,486
281,987
(461,263)
17,117
(33,251)
121,043
(566,172)
11,276
(214,012)
(202,736)
(363,436)
(1.24)
(1.24)
$
$
$
$
$
$
800,370
448,669
126,699
–
225,002
95,170
(946)
109,701
21,077
10,172
(22,247)
(12,075)
33,152
0.11
0.11
See accompanying notes to consolidated financial statements.
Consolidated Statements of Comprehensive Income (Loss)
Years ended December 31,
(Stated in thousands of Canadian dollars)
Net earnings (loss)
Unrealized gain on translation of assets and liabilities
of operations denominated in foreign currency
Foreign exchange loss on net investment hedge
with U.S. denominated debt, net of tax
Comprehensive income (loss)
See accompanying notes to consolidated financial statements.
56
Consolidated Financial Statements
2015
2014
$
(363,436)
$
33,152
444,464
171,092
(324,655)
(101,325)
$
(243,627)
$
102,919
Consolidated Statements of Cash Flow
Years ended December 31,
(Stated in thousands of Canadian dollars)
Cash provided by (used in):
Operations:
Net earnings (loss)
Adjustments for:
Long-term compensation plans
Depreciation and amortization
Loss on asset decommissioning
Impairment of property, plant and equipment
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 22)
Investments:
Purchase of property, plant and equipment
(Note 4)
Proceeds on sale of property, plant and equipment
Income taxes recovered
Changes in non-cash working capital balances
(Note 22)
Financing:
Repayment of long-term debt
Debt issue costs
Dividends paid
Increase in long-term debt
Issuance of common shares on the exercise of options
Effect of exchange rate changes on cash and cash equivalents
Increase (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.
2015
2014
$
(363,436)
$
33,152
15,594
486,655
166,486
281,987
17,117
(36,994)
121,043
(202,736)
(4,408)
(13,560)
1,770
(130,325)
17,897
357,090
159,926
517,016
(458,710)
9,786
55,138
(147,316)
(541,102)
–
(2,134)
(82,003)
–
93
(84,044)
61,408
(46,722)
491,481
16,197
448,669
126,699
–
95,170
(3,971)
109,701
(12,075)
(6,033)
(15,601)
8,463
(103,816)
919
697,474
(17,315)
680,159
(856,690)
101,826
–
124,877
(629,987)
(30,670)
(10,166)
(73,142)
436,600
7,082
329,704
30,999
410,875
80,606
$
444,759
$
491,481
Precision Drilling Corporation 2015 Annual Report
57
Consolidated Statements of Changes in Equity
(Stated in thousands of Canadian dollars)
Shareholders’
capital
(Note 12)
Contributed
surplus
Accumulated
other
comprehensive
income
(Note 13)
Retained
earnings
(deficit)
Total equity
Balance at January 1, 2015
$ 2,315,539
$
31,109
$
46,292
$
48,426
$ 2,441,366
Net loss for the period
Other comprehensive income for
the period
Dividends
Share options exercised
(Note 12)
Shares issued on redemption of
non-management directors’ DSUs
Share based compensation expense
(Note 8)
–
–
–
142
640
–
–
–
–
(49)
(324)
5,064
–
(363,436)
(363,436)
119,809
–
–
–
–
–
(82,003)
–
–
–
119,809
(82,003)
93
316
5,064
Balance at December 31, 2015
$ 2,316,321
$
35,800
$
166,101
$ (397,013)
$ 2,121,209
(Stated in thousands of Canadian dollars)
Balance at January 1, 2014
Net earnings for the period
Other comprehensive income for
the period
Dividends
Shareholders’
capital
Contributed
surplus
Accumulated
other
comprehensive
income (loss)
(Note 13)
Retained
earnings
Total equity
$ 2,305,227
$
29,175
$
(23,475)
$
88,416
$ 2,399,343
–
–
–
–
–
–
(3,230)
5,164
–
33,152
33,152
69,767
–
–
–
–
(73,142)
–
–
69,767
(73,142)
7,082
5,164
Share options exercised
(Note 12)
10,312
Share based compensation expense
(Note 8)
–
Balance at December 31, 2014
$ 2,315,539
$
31,109
$
46,292
$
48,426
$ 2,441,366
See accompanying notes to consolidated financial statements.
58
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
The 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 4, 2016.
(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(r) and (s).
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 and 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 2015 Annual Report
59
(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:
– Power & Tubulars
– Dynamic
– Structural
Seasonal, stratification and turnkey
drilling equipment
Service rig equipment
Drilling rig spare equipment
Service rig spare equipment
Rental equipment
Other equipment
Light duty vehicles
Heavy duty vehicles
Buildings
5 years
10 years
20 years
4 years
20 years
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
–
–
10%
0 to 20%
10%
–
–
0 to 25%
–
–
–
–
straight-line
straight-line
straight-line
straight-line
straight-line
straight-line
straight-line
straight-line
straight-line
straight-line
straight-line
straight-line
Gains and losses on disposal of an item of property, plant and equipment are determined by comparing the proceeds
from disposal to the carrying amount of property, plant and equipment, and are recognized in the consolidated statements
of earnings (loss).
The estimated useful lives, residual values and methods of 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 they increase the future economic benefits of the specific asset to which
they relate.
60
Notes to Consolidated Financial Statements
Amortization is recognized in profit and loss using the straight-line method 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 (CGU)
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). 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.
Precision Drilling Corporation 2015 Annual Report
61
In assessing value in use, the estimated future cash flows are discounted to their present value using an after-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.
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.
62
Notes to Consolidated Financial Statements
(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.
(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 non-management
directors, officers, and other eligible employees. As estimated by management, the fair values 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.
The Corporation has implemented an employee share purchase plan that allows eligible employees to purchase common
shares through payroll deductions. Under this plan, contributions made by employees are matched to a specific percentage by
the Corporation. The contributions made by the Corporation are expensed as incurred.
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.
Precision Drilling Corporation 2015 Annual Report
63
(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.
(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.
64
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 parts 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.
(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 reviewed for impairment 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.
Precision Drilling Corporation 2015 Annual Report
65
(t) Accounting Standards, Interpretations and Amendments to Existing Standards not yet Effective
(i) IFRS 9, Financial Instruments
In July 2014, the IASB issued final amendments to IFRS 9, replacing earlier versions of IFRS 9. These amendments to IFRS
9 introduce a single, forward-looking ‘expected loss’ impairment model for financial assets which will require more timely
recognition of expected credit losses, and a fair value through other comprehensive income category for financial assets
that are debt instruments.
The amendments to IFRS 9 are effective for annual periods beginning on or after January 1, 2018 and are available for
earlier adoption. The Corporation does not expect that the implementation of IFRS 9 will have a material effect on the
financial statements.
(ii) IFRS 15, Revenue from Contracts with Customers
In May 2014, the IASB issued IFRS 15 to address how and when to recognize revenue as well as requiring entities to
provide users of financial statements with more informative, relevant disclosures in order to understand the nature,
amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard provides
a principles based five-step model to be applied to all contracts with customers. This five-step model involves identifying
the contract(s) with a customer; identifying the performance obligations in the contract; determining the transaction price;
allocating the transaction price to the performance obligations in the contract; and recognizing revenue when (or as) the
entity satisfies a performance obligation.
Application of this new standard is mandatory for annual reporting periods beginning on or after January 1, 2017, with
earlier application permitted. The Corporation does not expect that the implementation of IFRS 15 will have a material effect
on the financial statements.
(iii) IFRS 16, Leases
In January 2016, the IASB issued IFRS 16 to replace the guidance currently found in IAS 17. The new standard requires
lessees to recognize a lease liability reflecting future lease payments and a right of use asset for virtually all lease contracts.
In addition IFRS 16 has updated the definition of a lease and introduced new disclosure requirements. IFRS 16 is effective
for annual periods beginning on or after January 1, 2019, with earlier application permitted in certain circumstances. The
Corporation has yet to determine the impact this new standard will have on the financial statements.
NOTE 4. PROPERTY, PLANT AND EQUIPMENT
2015
2014
$
$
$
6,949,846
(3,066,514)
3,883,332
3,279,188
$
$
$
97,000
97,346
24,840
90,419
258,952
35,587
5,898,980
(1,970,154)
3,928,826
3,182,090
104,492
97,887
24,682
89,539
397,556
32,580
$
3,883,332
$
3,928,826
Cost
Accumulated depreciation
Rig equipment
Rental equipment
Other equipment
Vehicles
Buildings
Assets under construction
Land
66
Notes to Consolidated Financial Statements
Cost
Balance,
December 31, 2013
Additions
Disposals
Effect of foreign
currency exchange
differences
Balance,
December 31, 2014
Additions
Disposals
Rig
Equipment
Rental
Equipment
Other
Equipment
Vehicles
Buildings
Assets
Under
Construction
Land
Total
$ 4,511,396 $ 169,945 $ 185,394 $
69,611 $
74,964 $ 219,433 $
29,520 $ 5,260,263
144,169
2,939
5,504
4,356
5,320
692,560
1,842
856,690
Asset decommissioning
(286,898)
–
–
–
(155,002)
(1,587)
(4,853)
(43,084)
(69)
–
–
–
–
(204,595)
–
(286,898)
Reclassifications
453,862
1,650
27,990
7,335
36,968
(527,805)
–
–
248,802
1,411
3,992
1,639
3,090
13,368
1,218
273,520
4,916,329
174,358
218,027
39,857
120,273
397,556
32,580 5,898,980
Asset decommissioning
(637,486)
–
–
–
309,670
104
1,451
204
3,363
143,918
(61,506)
(8,143)
(3,049)
(2,881)
(90)
–
–
–
–
–
458,710
(75,669)
–
(637,486)
Reclassifications
298,930
747
12,426
2,738
(1,154)
(313,687)
–
–
Effect of foreign
currency exchange
differences
Balance,
December 31, 2015
1,243,242
4,154
11,337
3,634
8,772
31,165
3,007 1,305,311
$ 6,069,179 $ 171,220 $ 240,192 $
43,552 $ 131,164 $ 258,952 $
35,587 $ 6,949,846
Accumulated Depreciation
Rig
Equipment
Rental
Equipment
Other
Equipment
Vehicles
Buildings
Assets
Under
Construction
Land
Total
Balance,
December 31, 2013
$ 1,478,237 $
61,492 $ 106,724 $
26,618 $
25,458 $
– $
– $ 1,698,529
Depreciation expense
392,565
10,789
16,815
6,468
4,818
Disposals
(63,305)
(1,364)
(4,845)
(18,270)
Asset decommissioning
(160,200)
–
1,549
(1,501)
–
2
–
(95)
(19)
–
45
85,393
450
1,444
454
432
1,734,239
69,866
120,140
15,175
30,734
Depreciation expense
440,548
10,272
21,755
4,984
8,497
Disposals
(53,271)
(7,533)
(2,988)
(2,635)
(61)
Asset decommissioning
(471,000)
281,720
(12)
–
197
27
–
70
(8)
–
–
31
–
–
(38)
Reclassifications
Effect of foreign
currency exchange
differences
Balance,
December 31, 2014
Impairment loss
Reclassifications
Effect of foreign
currency exchange
differences
Balance,
December 31, 2015
–
–
–
–
–
–
–
–
–
–
–
–
–
431,455
(87,803)
–
(160,200)
–
–
–
88,173
– 1,970,154
–
–
486,056
(66,488)
–
(471,000)
–
–
281,987
–
857,767
1,391
3,877
1,157
1,613
–
–
865,805
$ 2,789,991 $
74,220 $ 142,846 $
18,712 $
40,745 $
– $
– $ 3,066,514
In 2015, the Corporation incurred a $166.5 million (2014 – $126.7 million) loss on the decommissioning of certain drilling and
service rigs and ancillary equipment. The assets were decommissioned due to the inefficient nature of the assets and the high
cost to maintain. The charge was allocated $165.1 million (2014 – $97.9 million) to the Contract Drilling Services segment and
$1.4 million (2014 – $28.8 million) to the Completion and Production Services segment.
Precision Drilling Corporation 2015 Annual Report
67
Impairment Test
Precision reviews the carrying value of its long-lived assets at each reporting period for indicators of impairment. During the
period ended September 30, 2015 the Corporation determined that low commodity prices and the associated impact on current
and future business and industry activity levels was an indicator of impairment and performed a comprehensive assessment
of the carrying values of property, plant and equipment for the directional drilling, well servicing, camp and catering, oilfield
equipment rental, wastewater treatment and U.S. completion and production CGUs.
The recoverable amount of each CGU was determined using a value in use calculation based on five-year cash flow projections.
The cash flow projections were based on future expected outcomes taking into account existing term contracts, past experience
and management’s expectation of future market conditions with no terminal value growth rate. Cash flow information was
derived primarily from strategic plans approved by management, which were developed based on benchmark commodity
prices and industry supply-demand fundamentals.
Cash flows used in the calculation were discounted using a discount rate specific to each CGU. Discount rates are derived from
Precision’s weighted average cost of capital, adjusted for risk factors specific to each CGU. The after-tax discount rates used in
determining the recoverable amount for the CGUs ranged from 12.9% to 14.4%.
As a result of the impairment test completed as at September 30, 2015, Precision recorded a property, plant and equipment
impairment charge related to its well servicing and U.S. completion and production CGUs of $72.8 million, and $7.0 million
respectively. These CGUs are all part of the Completion and Production Services segment.
Due to continued weakness in commodity prices and the associated decline in industry activity levels during the period
ended December 31, 2015, the Corporation performed a comprehensive assessment of the carrying values all CGUs. The
recoverable amount of each CGU was determined using a methodology consistent with the September 30, 2015 calculation
with updated assumptions.
Cash flows used in the calculation were discounted using discount rates derived from Precision’s weighted average cost of
capital, adjusted for risk factors specific to each CGU. The after-tax discount rates used in determining the recoverable amount
for the CGUs ranged from 11.7% to 14.2%.
As a result of the impairment test completed as at December 31, 2015, Precision recorded a property, plant and equipment
impairment charge related to its U.S. drilling, international drilling, and Mexico drilling CGUs of $99.8 million, $66.9 million and
$35.8 million respectively. These CGUs are all part of the Contract Drilling Services segment. The calculation of the recoverable
amount is sensitive to the discount rate and cash flow projections. A 0.5% increase in the discount rate for U.S. drilling,
international drilling and Mexico drilling CGUs would result in an additional impairment charge of approximately $99 million. In
addition, a 10% decrease in the annual cash flow projections within U.S. drilling, international drilling, and Mexico drilling CGUs
would result in an additional impairment charge of approximately $83 million.
In prior years, property, plant and equipment related to the Mexico operations were aggregated into the international CGU.
During the period ended December 31, 2015, these assets began to be managed and operated independently of the other
international drilling operations and have been treated as a standalone CGU for purposes of the 2015 recoverability calculation.
68
Notes to Consolidated Financial Statements
NOTE 5. INTANGIBLES
Cost
Accumulated amortization
Loan commitment fees related to Senior Credit Facility
Cost
2015
11,131
(7,768)
3,363
3,363
$
$
$
$
$
$
Customer
Relationships
Patents and
Brands
Loan
Commitment
Fees
2014
8,997
(5,695)
3,302
3,302
Total
Balance, December 31, 2013
$
3,525
$
53
$
8,643
$
12,221
Additions
Effect of foreign currency exchange differences
Removal of fully amortized assets
Balance, December 31, 2014
Additions
Balance, December 31, 2015
$
Accumulated Amortization
–
47
(3,572)
–
–
–
$
–
–
(53)
–
–
–
354
–
–
8,997
2,134
354
47
(3,625)
8,997
2,134
$
11,131
$
11,131
Balance, December 31, 2013
Amortization expense
Effect of foreign currency exchange differences
Removal of fully amortized assets
Balance, December 31, 2014
Amortization expense
Balance, December 31, 2015
Customer
Relationships
Patents and
Brands
$
2,909
$
619
44
(3,572)
–
–
–
$
$
37
16
–
(53)
–
–
–
Loan
Commitment
Fees
$
5,358
$
337
–
–
5,695
2,073
$
7,768
$
Total
8,304
972
44
(3,625)
5,695
2,073
7,768
Precision Drilling Corporation 2015 Annual Report
69
NOTE 6. GOODWILL
Balance, December 31, 2013
Impairment charge
Exchange adjustment
Balance, December 31, 2014
Impairment charge
Exchange adjustment
Balance, December 31, 2015
$
312,356
(95,170)
2,533
219,719
(17,117)
5,877
$
208,479
During the period ended September 30, 2015 the Corporation determined the low commodity prices and the associated impact
on current and future business and industry levels was an indicator of impairment. Accordingly, Precision determined that the
carrying value of the goodwill allocated to the oilfield equipment rental CGU exceeded its recoverable amount and recognized
impairment loss of $17.0 million for the period ended September 30, 2015. The impairment charge resulted in the entire goodwill
balance of the CGU being written off. The oilfield equipment rental CGU is included in the Completion and Production Services
segment. 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 for the oilfield equipment rental CGU included a discount rate of
13.4%, terminal value growth rate of nil and no projected annual cash flow growth over the next five years. Projected cash flow
was based on future expected outcomes taking into account existing term contracts, past experience, and management’s
expectation of future market conditions. Cash flow information was derived primarily from strategic plans approved by
management, which were developed based on benchmark commodity prices and industry supply-demand fundamentals.
Of the remaining carrying value of goodwill, $172.3 million is associated with the Canada contract drilling CGU. The Corporation
performed its annual goodwill impairment test at December 31, 2015 for this CGU, and determined that no impairment was
required. The key assumptions used in the calculation of value in use included a discount rate of 11.7% (2014 – 10.5%), terminal
value growth rate of nil and no projected annual cash flow growth over the next five years. Projected cash flow was based
on future expected outcomes taking into account existing term contracts, past experience, and management’s expectation
of future market conditions. Cash flow information was derived primarily from strategic plans approved by management,
which were developed based on benchmark commodity prices and industry supply-demand fundamentals. A discount
rate higher than 13.5% would have resulted in an impairment of goodwill for this CGU, with each 0.5% increase resulting
in approximately $55 million of additional impairment charges. In addition, the U.S. directional drilling CGU had a goodwill
balance of $36.1 million at December 31, 2015. The Corporation performed its annual goodwill impairment test at December
31, 2015 for this CGU, and determined that no impairment was required. The key assumptions used in the calculation of value
in use included a discount rate of 13.24% (2014 – 14.0%) and nil terminal value growth rate. Projected cash flow was based
on future expected outcomes taking into account past experience and management’s expectation of future market conditions.
Cash flow information was derived primarily from strategic plans approved by management, which were developed based on
benchmark commodity prices and industry supply-demand fundamentals. A discount rate higher than 15.32% would have
resulted in an impairment of goodwill for this CGU, with each 0.5% increase resulting in approximately $1.8 million of additional
impairment charges.
NOTE 7. BANK INDEBTEDNESS
At December 31, 2015, Precision had available $40.0 million (2014 – $40.0 million) and US$15.0 million (2014 – US$15.0 million)
under secured operating facilities, and a secured US$40.0 million (2014 – 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, 2015 and 2014, no amounts
had been drawn on any of the facilities. Availability of the $40.0 million and US$40.0 million facility were reduced by outstanding
letters of credit in the amount of $24.8 million (2014 – $20.5 million) and US$24.6 million (2014 – US$8.1 million), 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$40.0 million facilities at the bank’s prime lending rate.
70
Notes to Consolidated Financial Statements
NOTE 8. SHARE BASED COMPENSATION PLANS
Liability Classified Plans
Restricted
Share Units
Performance
Share Units
Share
Appreciation
Rights
Non-
Management
Directors’ DSUs
Total
Balance, December 31, 2013
$
13,538
$
12,962
$
246
$
1,854
$
28,600
Expensed (recovered) during the period
Payments
Balance, December 31, 2014
Expensed (recovered) during the period
Payments and redemptions
Balance, December 31, 2015
Current
Long-term
7,618
(10,572)
10,584
6,825
(6,950)
10,459
6,638
3,821
$
$
5,220
(4,413)
13,769
11,648
(5,793)
19,624
10,627
8,997
$
$
$
10,459
$
19,624
(95)
(70)
81
(75)
–
6
6
–
6
135
–
1,989
709
(315)
2,383
–
2,383
$
$
12,878
(15,055)
26,423
19,107
(13,058)
32,472
17,271
15,201
$
$
$
2,383
$
32,472
$
$
$
(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, 2013
Granted
Issued as a result of cash dividends
Redeemed
Forfeitures
December 31, 2014
Granted
Issued as a result of cash dividends
Redeemed
Forfeitures
December 31, 2015
RSUs
Outstanding
PSUs
Outstanding
2,113,495
1,387,293
52,369
(1,016,242)
(290,219)
2,246,696
2,151,100
132,233
(1,128,011)
(505,200)
2,437,928
1,704,188
76,994
(439,256)
(329,821)
3,450,033
2,639,400
218,339
(905,355)
(503,962)
2,896,818
4,898,455
Precision Drilling Corporation 2015 Annual Report
71
(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 five years and expire 10 years from the date of
grant. At December 31, 2015 and 2014 the intrinsic value of these awards was $nil.
Share Appreciation Rights
December 31, 2013
Exercised
Forfeited
December 31, 2014
Forfeited
December 31, 2015
Range of Exercise Prices (US$):
$ 15.22 – 15.99
16.00 – 17.38
$ 15.22 – 17.38
Outstanding
Range of
Exercise Price
(US$)
Weighted
Average Exercise
Price (US$)
588,162
$ 9.26 – 17.38
(31,506)
(112,915)
9.26 – 9.26
9.26 – 17.38
443,741
13.26 – 17.38
(100,609)
13.26 – 13.26
343,132
$ 15.22 – 17.38
$ 14.71
9.26
13.85
$ 15.32
13.26
$ 15.93
Exercisable
588,162
443,741
343,132
Total SARs Outstanding and Exercisable
Weighted
Average Exercise
Price (US$)
$ 15.47
17.38
$ 15.93
Weighted Average
Remaining
Contractual Life
(Years)
1.71
0.13
1.33
Number
261,064
82,068
343,132
(c) Non-Management Directors
Effective January 1, 2012, Precision instituted a new deferred share unit (DSU) plan for non-management directors whereby fully
vested DSUs are granted quarterly based on an election by the non-management director to receive all or a portion of his or
her compensation in DSUs. These DSUs are redeemable in cash or for an equal number of common shares upon the director’s
retirement. The redemption of DSUs 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 DSUs 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
December 31, 2013
Granted
Issued as a result of cash dividends
December 31, 2014
Granted
Issued as a result of cash dividends
Redeemed
December 31, 2015
72
Notes to Consolidated Financial Statements
Outstanding
188,575
85,183
4,829
278,587
173,115
13,602
(37,276)
428,028
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
his or her 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, 2013
Issued as a result of cash dividends
December 31, 2014
Issued as a result of cash dividends
Redeemed
December 31, 2015
Outstanding
221,112
4,898
226,010
8,626
(38,393)
195,743
(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, 12,650,339 options have been granted. Under this plan, the
exercise price of each option equals the fair market value 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, 2013
Granted
Exercised
Forfeitures
December 31, 2014
Granted
Exercised
Forfeitures
Options
Outstanding
Range of
Exercise Prices
4,900,886
$
5.22 – 14.50
$
881,700
(530,738)
(97,534)
5,154,314
1,447,400
(16,000)
(417,118)
10.15 – 14.31
5.85 – 11.16
5.85 – 10.67
5.22 – 14.50
7.32 – 7.32
5.85 – 5.85
5.85 – 14.50
December 31, 2015
6,168,596
$
5.22 – 14.50
$
Weighted
Average
Exercise Price
9.14
10.24
8.07
9.62
9.43
7.32
5.85
9.56
8.93
U.S. share options
December 31, 2013
Granted
Exercised
Forfeitures
December 31, 2014
Granted
Forfeitures
December 31, 2015
Options
Outstanding
Range of
Exercise Prices
(US$)
3,173,808
$
4.95 – 15.21
$
827,300
(309,512)
(285,822)
3,405,774
1,344,900
(168,437)
9.18 – 9.18
4.95 – 10.96
4.95 – 14.58
4.95 – 15.21
5.79 – 5.79
4.95 – 15.21
4,582,237
$
4.95 – 15.21
$
Weighted
Average
Exercise Price
(US$)
9.32
9.18
8.26
9.77
9.35
5.79
9.37
8.30
Options
Exercisable
2,676,865
3,185,500
3,870,673
Options
Exercisable
1,438,335
1,795,639
2,468,185
Precision Drilling Corporation 2015 Annual Report
73
The weighted average share price at the date of exercise for share options exercised in 2015 was $8.49 (2014 – $12.98) for the
Canadian share options and US$nil (2014 – US$12.07) for the U.S. share options.
The range of exercise prices for options outstanding at December 31, 2015 is as follows:
Canadian share options
Total Options Outstanding
Options Exercisable
Range of Exercise Prices:
$ 5.22 – 6.99
7.00 – 8.99
9.00 – 9.99
10.00 – 14.50
$ 5.22 – 14.50
Number
468,102
2,188,675
1,038,684
2,473,135
Weighted
Average
Exercise Price
$ 5.85
7.76
9.02
10.52
6,168,596
$ 8.93
Weighted Average
Remaining
Contractual Life
(Years)
0.35
4.37
4.12
3.43
3.64
Number
468,102
772,007
689,770
1,940,794
Weighted
Average
Exercise Price
$ 5.85
8.56
9.02
10.59
3,870,673
$ 9.33
U.S. share options
Total Options Outstanding
Options Exercisable
Range of Exercise Prices (US$):
Number
Weighted
Average
Exercise Price
(US$)
Weighted Average
Remaining
Contractual Life
(Years)
$ 4.95 – 6.99
7.00 – 8.99
9.00 – 9.99
10.00 – 15.21
$ 4.95 – 15.21
1,433,268
$ 5.74
1,315,228
738,800
1,094,941
8.56
9.18
10.77
4,582,237
$ 8.30
5.76
3.14
5.10
2.66
4.16
Weighted
Average
Exercise Price
(US$)
Number
88,368
$ 4.95
1,033,614
251,262
1,094,941
8.44
9.18
10.77
2,468,185
$ 9.42
The per option weighted average fair value of the share options granted during 2015 was $1.60 (2014 – $3.17) estimated on
the grant date using the Black-Scholes option pricing model with the following assumptions: average risk-free interest rate
of 1% (2014 – 1%), average expected life of four years (2014 – four years), expected forfeiture rate of 5% (2014 – 5%) and
expected volatility of 44% (2014 – 46%). Included in net earnings (loss) for the year ended December 31, 2015 is an expense
of $5.1 million (2014 – $5.2 million).
Employee Share Purchase Plan
The Corporation has an employee share purchase plan to encourage employees to become Precision shareholders and to
attract and retain people. Under the plan, eligible employees can contribute up to 10% of their regular base salary through
payroll deduction with Precision matching 20% of the employee’s contribution. These contributions are used to purchase the
Corporation’s shares in the open market. No vesting conditions apply. During 2015, the Corporation recorded compensation
expense of $0.8 million (2014 – $0.5 million).
74
Notes to Consolidated Financial Statements
NOTE 9. PROVISIONS AND OTHER
Balance December 31, 2013
Expensed during the year
Payment of deductibles and uninsured claims
Effects of foreign currency exchange differences
Balance December 31, 2014
Expensed during the year
Payment of deductibles and uninsured claims
Effects of foreign currency exchange differences
Balance December 31, 2015
Current
Long-term
Workers’
Compensation
$
24,186
5,215
(11,272)
1,852
19,981
4,983
(10,014)
3,879
$
18,829
December 31,
2015
December 31,
2014
$
$
4,309
14,520
18,829
$
$
5,144
14,837
19,981
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
Senior 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)
5.25% senior notes due 2024 (US$400.0 million)
6.5% senior notes due 2019
Less net unamortized debt issue costs
2015
$
–
$
899,600
553,600
553,600
200,000
2014
–
754,065
464,040
464,040
200,000
2,206,800
1,882,145
(26,290)
(29,959)
$
2,180,510
$
1,852,186
(a) Senior Credit Facility
The senior secured revolving credit facility (as amended, the Senior Credit Facility) provides Precision with senior secured
financing for general corporate purposes, including for acquisitions, of up to US$550.0 million with a provision for an increase
in the facility of up to an additional US$250.0 million. The Senior 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 Senior Credit Facility, on certain assets of certain subsidiaries organized in
a jurisdiction outside of Canada or the U.S.
Precision Drilling Corporation 2015 Annual Report
75
On March 27, 2015, we amended certain financial covenants under the credit agreement governing our Senior Credit Facility to,
among other things, temporarily increase the maximum consolidated total debt to Adjusted EBITDA ratio (as defined in the debt
agreement) to 6:1 from 4:1 and temporarily reduce the minimum interest coverage ratio to 2.5:1 from 2.75:1, in each case until
December 31, 2016.
On October 27, 2015, we further amended the credit agreement, whereby we reduced the size of the Senior Credit Facility
to US$550.0 million from US$650.0 million and eliminated the consolidated total debt to adjusted EBITDA financial covenant
ratio in its entirety. We further decreased the minimum interest coverage ratio to 2:1 from 2.5:1 for a temporary period up to
and including December 31, 2017, which will revert to 2.5:1 thereafter until the maturity date of the facility. We also reduced
the maximum consolidated senior debt to adjusted EBITDA financial covenant ratio to 2.5:1 from 3:1 and added a new debt
covenant whereby we agreed not incur or assume more than US$250.0 million in new unsecured debt other than where the new
unsecured debt is used to refinance existing unsecured debt or the new debt is assumed through an acquisition.
In addition, the revolving credit facility contains certain covenants that place restrictions on Precision’s ability to incur or
assume additional indebtedness; dispose of assets; make or pay dividends, share redemptions or other distributions;
change its primary business; incur liens on assets; engage in transactions with affiliates; enter into mergers, consolidations or
amalgamations; and enter into speculative swap agreements. At December 31, 2015, Precision was in compliance with the
covenants of the Senior Credit Facility.
The Senior 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 Senior Credit Facility is June 3, 2019.
Under the Senior Credit Facility, amounts can be drawn in U.S. dollars and/or Canadian dollars and, as at December 31, 2015
and 2014 no amounts were drawn under this facility. Up to US$200.0 million of the Senior Credit Facility is available for letters
of credit denominated in U.S and/or Canadian dollars and as at December 31, 2015 outstanding letters of credit amounted to
US$46.4 million (2014 – US$25.6 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:
$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.
These notes 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 Senior 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.
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 101.625% 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.
76
Notes to Consolidated Financial Statements
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.
These notes 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 senior 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.
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.
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.
These notes 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 Senior 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 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.
Precision Drilling Corporation 2015 Annual Report
77
US$400.0 million of 5.25% senior notes due 2024
These notes bear interest at a fixed rate of 5.25% per annum and mature on November 15, 2024. Interest is payable
semi-annually on May 15 and November 15 of each year.
These notes 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 Senior 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 May 15, 2017, Precision may redeem up to 35% of the 5.25% senior notes due 2024 with the net proceeds of
certain equity offerings at a redemption price equal to 105.25% of the principal amount plus accrued interest. Prior to
May 15, 2019, 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 May 15, 2019 redemption price plus required interest payments through May 15, 2019 (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 May 15, 2019 and before May 15, 2022, at redemption prices ranging
between 102.625% and 100.875% of their principal amount plus accrued interest. Any time on or after May 15, 2022, 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.
All issues of our senior notes require that we comply with certain financial covenants including an Adjusted EBITDA (as defined
in the note agreements) to interest coverage ratio of greater than 2:1 for the most recent four consecutive fiscal quarters. In the
event that this ratio is less than 2:1 for the most recent consecutive fiscal quarters, the senior notes restrict our ability to incur
additional indebtedness. The senior notes also contain a restricted payments covenant that limits our ability to make payments
in the nature of dividends, distributions and repurchases from shareholders (restricted payments basket). The restricted
payment basket grows by, among other things, 50% of consolidated net earnings, and decreases by 100% of consolidated net
losses (as defined in the note) and payments made to shareholders. As at December 31, 2015, the restricted payments basket
was negative $152 million, therefore prohibiting us from making any further dividend payments until the restricted payments
basket once again becomes positive. No dividends have been paid subsequent to December 31, 2015.
At December 31, 2015, Precision was in compliance with the covenants of the senior notes.
Long-term debt obligations at December 31, 2015 will mature as follows:
2019
2020
Thereafter
$
200,000
899,600
1,107,200
$
2,206,800
78
Notes to Consolidated Financial Statements
(c) Guarantor Disclosures
The following presents supplemental condensed consolidating financial information for the parent corporation, guarantor
subsidiaries and the non-guarantor subsidiaries, respectively.
Condensed Consolidating Statement of Financial Position as at December 31, 2015
Parent
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$
330,758
$
43,039
$
70,962
$
–
3
$
444,759
335,840
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
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
3,993
1,537,538
4,888,294
2,917
88,238
3,363
–
6,855,101
43,149
2,957,753
2,180,510
217,188
5,398,600
1,456,500
$
$
3,923
364,958
6,026,160
3,297
59,485
3,302
–
6,798,973
49,622
2,628,522
1,852,186
47,713
4,578,043
2,220,930
$
$
–
–
–
–
228,333
2,943,153
61
–
103,511
71,689
–
–
3,343,623
451,294
(4,552,380)
(4,888,355)
–
177
–
–
$
$
–
208,479
6,766,688
135,613
1,460,838
–
116,925
1,713,376
5,053,312
$
$
$
$
697,456
$
(9,440,555)
65,022
$
–
133,789
(4,552,380)
–
(926)
197,885
499,572
–
–
(4,552,380)
(4,888,175)
513,465
2,555,200
61
–
144,980
73,404
–
–
3,459,563
409,923
(2,993,562)
(6,026,221)
–
(145)
–
–
$
$
–
219,719
6,845,988
384,452
169,855
–
473,415
1,027,722
5,818,266
$
$
$
$
683,960
$
(9,019,925)
66,148
$
–
195,185
(2,993,562)
–
(5,906)
255,427
428,533
–
–
(2,993,562)
(6,026,363)
–
–
2,917
3,883,332
3,363
208,479
4,878,690
243,784
–
2,180,510
333,187
2,757,481
2,121,209
–
–
3,297
3,928,826
3,302
219,719
5,308,996
500,222
–
1,852,186
515,222
2,867,630
2,441,366
Total liabilities and shareholders’ equity
$
6,855,100
$
6,766,688
$
697,457
$
(9,440,555)
$
4,878,690
Condensed Consolidating Statement of Financial Position as at December 31, 2014
Parent
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$
337,848
$
97,980
$
55,653
$
–
3
$
491,481
662,371
Total liabilities and shareholders’ equity
$
6,798,973
$
6,845,988
$
683,960
$
(9,019,925)
$
5,308,996
Precision Drilling Corporation 2015 Annual Report
79
Condensed Consolidating Statement of Earnings (Loss) for the Year ended December 31, 2015
Revenue
Operating expense
General and administrative expense
Restructuring
Earnings (loss) before income taxes,
finance charges, foreign exchange,
impairment of goodwill, impairment
of property, plant and equipment,
loss on asset decommissioning and
depreciation and amortization
Depreciation and amortization
Loss on asset decommissioning
Impairment of property, plant and
equipment
Operating loss
Impairment of goodwill
Foreign exchange
Finance charges
Equity in loss of subsidiaries
Loss before tax
Income taxes
Net loss
$
Parent
118
118
22,395
6,100
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$
1,358,162
$
226,128
$
(28,784)
$
1,555,624
792,590
104,051
14,543
160,416
10,330
–
(28,784)
–
–
924,340
136,776
20,643
(28,495)
14,360
–
–
(42,855)
–
(34,836)
137,093
264,257
(409,369)
(46,123)
446,978
425,518
166,264
215,048
(359,852)
17,117
1,549
(2,213)
–
(376,305)
(165,375)
55,382
46,586
222
66,939
(58,365)
–
36
(13,837)
–
(44,564)
8,762
–
191
–
–
(191)
–
–
–
(264,257)
264,066
–
473,865
486,655
166,486
281,987
(461,263)
17,117
(33,251)
121,043
–
(566,172)
(202,736)
$
(363,246)
$
(210,930)
$
(53,326)
$
264,066
$
(363,436)
Condensed Consolidating Statement of Earnings for the Year ended December 31, 2014
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 before tax
Income taxes
Net earnings
$
Parent
172
98
26,798
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$
2,179,259
$
195,487
$
(24,380)
$
2,350,538
1,281,955
107,028
148,154
10,515
(24,380)
1,405,827
–
144,341
(26,724)
8,106
–
(34,830)
–
5,274
109,628
(206,095)
56,363
23,050
790,276
415,973
126,699
247,604
95,170
(8,450)
87
–
160,797
(37,581)
$
33,313
$
98,378
$
36,818
24,430
–
12,388
–
2,230
(14)
–
10,172
2,456
7,716
–
160
–
(160)
–
–
–
206,095
(206,255)
–
800,370
448,669
126,699
225,002
95,170
(946)
109,701
–
21,077
(12,075)
$
(206,255)
$
33,152
80
Notes to Consolidated Financial Statements
Condensed Consolidating Statement of Comprehensive Income (Loss) for the Year ended December 31, 2015
Net loss
Other comprehensive income (loss)
Comprehensive income (loss)
Parent
(363,246)
(324,655)
(687,901)
$
$
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
$
$
(210,930)
361,512
150,584
$
$
(53,326)
82,439
29,110
$
$
264,066
513
264,580
$
$
Condensed Consolidating Statement of Comprehensive Income (Loss) for the Year ended December 31, 2014
Net earnings
Other comprehensive income (loss)
Comprehensive income (loss)
Parent
33,313
(101,325)
(68,012)
$
$
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
$
$
198,378
141,519
339,897
$
$
7,716
29,324
37,040
$
$
(206,255)
249
(206,006)
$
$
Total
(363,436)
119,809
(243,627)
Total
33,152
69,767
102,919
Condensed Consolidating Statement of Cash Flow for the Year ended December 31, 2015
Parent
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$
(217,212)
$
694,956
$
39,272
$
–
$
517,016
256,781
(84,044)
(520,175)
(244,775)
(15,297)
(17,636)
(262,411)
262,411
37,835
15,053
8,970
(7,090)
(54,941)
15,309
337,848
97,980
55,653
Cash and cash equivalents, end of year
$
330,758
$
43,039
$
70,962
$
Condensed Consolidating Statement of Cash Flow for the Year ended December 31, 2014
Parent
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$
(142,565)
$
815,939
$
6,785
$
–
$
680,159
101,403
329,704
(478,613)
(267,482)
(139,018)
153,723
(113,759)
113,759
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
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
22,146
5,097
3,756
310,688
74,941
25,246
27,160
23,039
30,407
Cash and cash equivalents, end of year
$
337,848
$
97,980
$
55,653
$
(541,102)
(84,044)
61,408
(46,722)
491,481
$
444,759
(629,987)
329,704
30,999
410,875
80,606
$
491,481
–
–
–
–
–
–
–
–
Precision Drilling Corporation 2015 Annual Report
81
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 (loss) 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
Increase in deferred tax balances due to enacted tax rate increases
2015
(566,172)
26%
(147,205)
$
$
$
$
7,193
(206)
(40,166)
(39,170)
3,303
560
399
12,556
2014
21,077
25%
5,269
26,829
(1,123)
(33,356)
(12,695)
3,932
(3,980)
3,049
–
Income tax recovery
$
(202,736)
$
(12,075)
Effective July 1, 2015 the Alberta corporate income tax rate increased from 10% to 12% resulting in an increase in the Federal
and provincial statutory rate to 26% in 2015 (2014 – 25%).
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
$
637,106
$
730,742
2015
2014
Partnership deferrals
Debt issue costs
Other
Deferred income tax assets:
Losses (expire from time to time up to 2035)
Long-term incentive plan
Other
Net deferred income tax liability
12,604
5,802
4,668
55,848
4,905
1,921
660,180
793,416
335,966
12,477
8,271
284,776
13,939
8,568
$
303,466
$
486,133
Included in the net deferred tax liability is $101.6 million (2014 – $235.8 million) of tax-effected temporary differences related to
the Corporation’s U.S. operations.
Deferred tax assets are recognized only to the extent that it is probable that the assets can be recovered. At December 31, 2015,
the Corporation had $16.0 million (2014 – $9.8 million) of deferred tax assets, primarily related to international operations, that
were not recognized. These temporary differences that give rise to the deferred tax assets begin to expire in 2016.
82
Notes to Consolidated Financial Statements
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
Balance, December 31, 2013
$ 749,760
$ 34,938
$
6,569
$ (285,438)
$
2,966
$ (14,800)
$
(6,648)
$ 487,347
Recognized in net earnings
(65,223)
20,910
(4,626)
24,655
1,939
1,856
(1,758)
(22,247)
Effect of foreign currency
exchange differences
46,205
–
(22)
(23,993)
–
(995)
(162)
21,033
Balance, December 31, 2014
730,742
55,848
1,921
(284,776)
4,905
(13,939)
(8,568)
486,133
Recognized in net loss
(181,734)
(43,244)
2,788
2,973
897
3,310
998
(214,012)
Effect of foreign currency
exchange differences
88,098
–
(41)
(54,163)
–
(1,848)
(701)
31,345
Balance, December 31, 2015 $ 637,106
$ 12,604
$
4,668
$ (335,966)
$
5,802
$ (12,477)
$
(8,271)
$ 303,466
On December 31, 2015, Precision had $19.6 million (2014 – $32.7 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, 2015 was interest and penalties of $8.3 million (2014 – $11.4 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
2015
2014
$
32,700
$
30,930
850
2,492
(13,932)
(722)
$
19,618
$
32,700
It is anticipated that approximately $nil (2014 – $8.0 million) of unrecognized tax positions that relate 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.
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
Balance, December 31, 2013
Options exercised – cash consideration
– reclassification from contributed surplus
Balance, December 31, 2014
Options exercised – cash consideration
– reclassification from contributed surplus
Issued on redemption of non-management directors’ DSUs
Number
Amount
291,979,671
$
2,305,227
840,250
–
7,082
3,230
292,819,921
$
2,315,539
16,000
–
76,169
93
49
640
Balance, December 31, 2015
292,912,090
$
2,316,321
Precision Drilling Corporation 2015 Annual Report
83
(c) Dividends
During 2015, the Corporation approved and paid dividends of $0.28 per common share (2014 – $0.25) for total payments of
$82 million (2014 – $73 million). On February 11, 2016, Precision announced the suspension of its dividend.
NOTE 13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
December 31, 2013
Other comprehensive income
December 31, 2014
Other comprehensive income
December 31, 2015
NOTE 14. FINANCE CHARGES
Interest:
Long-term debt
Other
Income
Amortization of debt issue costs
Finance charges
Unrealized
Foreign Currency
Translation Gains
Foreign Exchange
Loss on Net
Investment Hedge
Accumulated
Other
Comprehensive
Income (Loss)
$
48,330
$
(71,805)
$
(23,475)
171,092
219,422
444,464
(101,325)
(173,130)
(324,655)
69,767
46,292
119,809
$
663,886
$
(497,785)
$
166,101
2015
2014
$
132,526
$
106,837
635
(17,861)
5,743
368
(987)
3,483
$
121,043
$
109,701
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 2015 was $12.8 million (2014 – $15.1 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
Termination benefits
$
$
2015
7,926
2,963
4,287
2,021
2014
9,193
3,241
3,235
–
$
17,197
$
15,669
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.
84
Notes to Consolidated Financial Statements
NOTE 17. COMMITMENTS
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
2015
2014
19,003
$
19,143
44,554
7,369
70,926
$
44,913
11,005
75,061
$
$
One of the leased properties was sublet by the Corporation.
The following amounts were recognized as expenses in respect of operating leases in the consolidated statements of
earnings (loss):
Operating leases
Sub-lease recoveries
2015
21,440
(687)
20,753
$
$
2014
21,516
(870)
20,646
$
$
Capital Commitments
At December 31, 2015, the Corporation had commitments to purchase property, plant and equipment totalling $261.8 million
(2014 – $418.3 million). Payments of $121.1 million for these commitments are expected to be made in 2016, $59.7 million in
2018, and $81.0 million in 2019.
NOTE 18. PER SHARE AMOUNTS
The following tables reconcile the net earnings (loss) and weighted average shares outstanding used in computing basic and
diluted earnings (loss) per share:
Net earnings (loss) – basic and diluted
(Stated in thousands)
Weighted average shares outstanding – basic
Effect of stock options and other equity compensation plans
Weighted average shares outstanding – diluted
2015
2014
$
(363,436)
$
33,152
2015
292,878
–
292,878
2014
292,533
1,271
293,804
Precision Drilling Corporation 2015 Annual Report
85
NOTE 19. 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 the 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.
(260,064)
(103,107)
Depreciation and amortization
Loss on asset decommissioning
439,261
165,109
Impairment of property, plant and equipment
202,414
32,396
1,377
79,573
(98,092)
14,998
–
–
2015
Revenue
Operating loss
Total assets
Goodwill
Capital expenditures
2014
Revenue
Operating earnings (loss)
Depreciation and amortization
Loss on asset decommissioning
Total assets
Goodwill
Capital expenditures
Contract
Drilling
Services
Completion
and
Production
Services
Corporate
and Other
Inter-
Segment
Eliminations
Total
$
1,378,336
$
186,317
$
–
$
(9,029)
$
1,555,624
–
–
–
–
–
–
–
(461,263)
486,655
166,486
281,987
4,878,690
208,479
458,710
4,204,872
228,918
444,900
–
2,651
–
5,241
208,479
450,818
Contract
Drilling
Services
Completion
and
Production
Services
Corporate
and Other
Inter-
Segment
Eliminations
Total
$
2,017,110
$
343,556
$
–
$
(10,128)
$
2,350,538
342,078
381,465
97,947
4,425,531
202,751
821,713
(29,419)
(87,657)
58,621
28,752
412,423
16,968
24,401
8,583
–
471,042
–
10,576
–
–
–
–
–
–
225,002
448,669
126,699
5,308,996
219,719
856,690
The Corporation’s operations are carried on in the following geographic locations:
2015
Revenue
Total assets
2014
Revenue
Total assets
Canada
United States
International
Inter-
Segment
Eliminations
Total
$
589,759
$
759,472
$
226,129
$
(19,736)
$
1,555,624
2,077,077
2,096,214
705,399
–
4,878,690
Canada
United States
International
Inter-
Segment
Eliminations
Total
$
1,077,814
$
1,096,918
$
195,487
$
(19,681)
$
2,350,538
2,434,774
2,244,867
629,355
–
5,308,996
During the years ended December 31, 2015 and 2014, no one individual customer accounted for more than 10% of the
Corporation’s total revenue.
86
Notes to Consolidated Financial Statements
NOTE 20. 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, and by 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. Precision’s most significant customer accounted for $18.2 million of the trade
receivables amount at December 31, 2015 (2014 – $22.7 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 aging of trade receivables at December 31 was as follows:
2015
2014
$
6,413
$
11,703
4,101
(1,576)
(305)
456
115
(5,645)
–
240
$
9,089
$
6,413
Not past due
Past due 0-30 days
Past due 31-120 days
Past due more than 120 days
2015
2014
Gross
Provision for
Impairment
Gross
Provision for
Impairment
$
112,219
$
50,446
25,540
9,417
$
197,622
$
–
–
–
9,089
9,089
$
219,000
$
108,946
47,365
11,141
$
386,452
$
–
–
–
6,413
6,413
(b) Interest Rate Risk
As at December 31, 2015 and 2014, all of Precision’s long-term debt, with the exception of the Senior 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 $nil (2014 – $nil).
(c) Foreign Currency Risk
The Corporation is primarily exposed to foreign currency fluctuations in relation to the working capital of its foreign 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 2015 Annual Report
87
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
$
$
$
2015
2014
Canadian
Operations (1)
Foreign
Operations
Canadian
Operations (1)
Foreign
Operations
$
150,512
$
78,014
$
272,981
$
115,716
–
(10,296)
–
140,216
1,402
–
$
$
$
155,386
(107,807)
(10,491)
115,102
–
1,151
–
(18,165)
–
254,816
2,548
–
$
$
$
270,984
(270,863)
(12,790)
103,047
–
1,030
$
$
$
(1) Excludes U.S. dollar 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, 2015:
2016
2017
2018
2019
2020
Thereafter
Total
Long-term debt
$
–
$
–
$
–
$ 200,000
$ 899,600
$ 1,107,200
$ 2,206,800
Interest on long-term debt (1)
137,647
137,647
137,647
127,355
117,196
147,107
804,599
Commitments
Total
140,101
15,123
72,097
90,346
7,658
7,369
332,694
$ 277,748
$ 152,770
$ 209,744
$ 417,701
$ 1,024,454
$ 1,261,676
$ 3,344,093
(1) Interest has been calculated based on debt balances, interest rates, and foreign exchange rates in effect as at December 31, 2015 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, 2015
was approximately $1,736 million (2014 – $1,668 million).
Financial assets and liabilities recorded or disclosed at fair value in the consolidated statements of financial position 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.
88
Notes to Consolidated Financial Statements
NOTE 21. 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, 2015 and 2014, these ratios were as follows:
Long-term debt
Shareholders’ equity
Total capitalization
Long-term debt to long-term debt plus equity ratio
$
$
2015
2,180,510
2,121,209
4,301,719
0.51
$
$
2014
1,852,186
2,441,366
4,293,552
0.43
As at December 31, 2015, liquidity remained sufficient as Precision had $444.8 million (2014 – $491.5 million) in cash and
access to the US$550.0 million Senior Credit Facility (2014 – US$650.0 million) and $116.1 million (2014 – $86.4 million)
secured operating facilities. As at December 31, 2015, no amounts (2014 – US$nil) were drawn on the Senior Credit Facility
with availability reduced by US$46.4 million (2014 – US$25.6 million) in outstanding letters of credit. Availability of the
$40.0 million and US$40.0 million secured operating facilities was reduced by outstanding letters of credit of $24.8 million
(2014 – $20.5 million) and US$24.6 million (2014 – US$8.1 million), respectively. There was no amount drawn on the
US$15.0 million secured operating facility.
NOTE 22. 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
The components of accounts payable and accrued liabilities are as follows:
Accounts payable
Accrued liabilities:
Payroll
Other
2015
2014
$
333,379
$
(20,986)
(12,575)
(308,194)
12,610
159,926
(147,316)
$
$
$
$
$
$
3,946
124,602
107,562
(17,315)
124,877
2015
2014
$
188,533
$
380,039
72,375
50,687
147,616
70,408
$
311,595
$
598,063
2015
2014
$
82,481
$
295,468
61,201
92,266
86,496
111,074
$
235,948
$
493,038
Precision Drilling Corporation 2015 Annual Report
89
Precision presents expenses in the consolidated statements of earnings (loss) by function with the exception of depreciation
and amortization and loss on asset decommissioning and impairment of property, plant and equipment, which are presented
by nature. Operating expense and general and administrative expense would include $920.1 million and $15.0 million
(2014 – $566.7 million and $8.6 million), respectively, of depreciation and amortization and loss on asset decommissioning and
impairment of property, plant and equipment 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
Restructuring
2015
2014
$
638,945
$
930,402
$
$
418,643
24,171
1,081,759
924,340
136,776
20,643
$
$
601,724
18,042
1,550,168
1,405,827
144,341
–
$
1,081,759
$
1,550,168
NOTE 23. 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 $2.9 million. This amount is included in the estimated
amount pertaining to the long-term income tax recoverable on the balance sheet.
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.
90
Notes to Consolidated Financial Statements
NOTE 24. 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
Grey Wolf Drilling (Barbados) Ltd.
Country of
Incorporation
Canada
Canada
Canada
Canada
United States
United States
United States
United States
Cyprus
Barbados
Ownership Interest %
2015
100
100
100
100
100
100
100
100
100
100
2014
100
100
100
100
100
100
100
100
100
100
Precision Drilling Corporation 2015 Annual Report
91
Precision
Drilling
Corporation
Supplemental Information
Consolidated Statements of Earnings (Loss)
2015
2014
2013
2012
2011
$ 1,555.6
$ 2,350.5
$ 2,029.9
$ 2,040.7
$ 1,951.0
1,405.8
1,248.6
1,243.3
1,131.0
924.3
136.8
20.6
473.9
486.7
166.5
282.0
144.3
–
800.4
448.7
126.7
–
142.5
–
638.8
333.1
–
–
(461.3)
225.0
305.7
17.1
(33.3)
121.0
(566.1)
(202.7)
(363.4)
95.1
(0.9)
109.7
21.1
(12.1)
33.2
–
(9.1)
93.3
221.5
30.3
191.2
126.6
–
124.9
–
670.8
307.5
192.5
–
170.8
52.5
3.8
86.8
27.7
(24.7)
52.4
695.1
251.5
114.9
–
328.7
–
(23.7)
111.6
240.8
47.3
193.5
$
$
(1.24)
(1.24)
$
$
0.11
0.11
$
$
0.69
0.66
$
$
0.19
0.18
$
$
0.70
0.67
Years ended December 31,
(millions of Canadian dollars, except per share amounts)
Revenue
Expenses:
Operating
General and administrative
Restructuring
Earnings before income taxes, finance charges, foreign exchange,
impairment of property, plant and equipment, impairment of
goodwill, loss on asset decommissioning, and depreciation and
amortization (Adjusted EBITDA)
Depreciation and amortization
Loss on decommissioning
Impairment of property, plant and equipment
Operating earnings (loss)
Impairment of goodwill
Foreign exchange
Finance charges
Earnings before income taxes
Income taxes
Net earnings (loss)
Earnings (loss) per share:
Basic
Diluted
92
Supplemental Information
Additional Selected Financial Information
Years ended December 31,
(millions of Canadian dollars, except per share amounts)
Return on sales – % (1)
Return on assets – % (2)
Return on equity – % (3)
Working capital
Current ratio
2015
(23.4)
(7.0)
(15.3)
2014
2013
2012
2011
1.4
0.7
1.3
9.4
4.3
8.4
2.6
1.2
2.4
9.9
4.9
9.5
$
536.8
$
653.6
$
305.8
$
278.0
$
610.4
3.2
2.3
1.9
1.7
2.4
Property, plant and equipment and intangibles
$ 3,886.7
$ 3,932.1
$ 3,565.7
$ 3,249.0
$ 2,948.8
Total assets
Long-term debt
Shareholders’ equity
Long-term debt to long-term debt plus equity
Interest coverage (4)
Net capital expenditures excluding business acquisitions
Adjusted EBITDA
Adjusted EBITDA – % of revenue
Operating earnings (loss)
$ 4,878.7
$ 5,309.0
$ 4,579.1
$ 4,300.3
$ 4,427.9
$ 2,180.5
$ 1,852.2
$ 1,323.3
$ 1,218.8
$ 1,239.6
$ 2,121.2
$ 2,441.4
$ 2,399.3
$ 2,171.3
$ 2,132.6
0.51
(3.8)
448.9
473.9
30.5
$
$
$
$
0.43
2.1
754.9
800.4
34.1
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
$
$
$
$
$
(461.3)
$
225.0
$
305.7
$
170.8
$
328.7
Operating earnings (loss) – % of revenue
(29.7)
9.6
15.1
8.4
16.8
Cash flow from continuing operations
$
517.0
$
680.2
$
428.1
$
635.3
$
532.8
Cash flow from continuing operations per share:
Basic
Diluted
Book value per share (5)
Price earnings (loss) ratio (6)
$
$
$
$
$
$
1.77
1.77
7.24
(4.4)
2.33
2.32
8.34
64.2
$
$
$
1.54
1.49
8.22
$
$
$
2.30
2.22
7.85
$
$
$
1.93
1.85
7.72
14.41
43.26
15.00
Basic weighted average shares outstanding (000s)
292,878
292,533
277,583
276,276
275,899
(1) Return on sales was calculated by dividing earnings (loss) from continuing operations by total revenue.
(2) Return on assets was calculated by dividing net earnings (loss) by quarter average total assets.
(3) Return on equity was calculated by dividing net earnings (loss) by quarter average total shareholders’ equity.
(4) Interest coverage was calculated by dividing operating earnings (loss) by net interest expense.
(5) Book value per share was calculated by dividing shareholders’ equity by shares outstanding.
(6) Price earnings ratio was calculated using year-end closing price divided by basic earnings (loss) per share.
Precision Drilling Corporation 2015 Annual Report
93
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
Canton, Massachusetts
2015 TRADING PROFILE
Toronto (TSX: PD)
High: $9.43
Low: $4.47
Close: $5.47
Volume Traded: 440,676,263
New York (NYSE: PDS)
High: US$7.80
Low: US$3.28
Close: US$3.94
Volume Traded: 848,119,400
ACCOUNT QUESTIONS
Our transfer agent can help you
with shareholder related services,
including:
change of address
lost share certificates
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 U.S.)
1.514.982.7555
(international direct dialing)
Email: service@computershare.com
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 Precision, including our annual
information form and management
information circular, 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 2015 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
94
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. Donovan (1)(2)
North Palm Beach, Florida, USA
Brian J. Gibson (1)(2)
Mississauga, Ontario, Canada
Allen R. Hagerman, FCA (1)(3)
Millarville, Alberta, Canada
Catherine J. Hughes (2)(3)
Calgary, Alberta, Canada
Steven W. Krablin (1)(3)
Spring, Texas, USA
Stephen J. J. Letwin (2)(3)
Toronto, Ontario, Canada
Kevin O. Meyers (2)(3)
Anchorage, Alaska, USA
Kevin A. Neveu
Houston, Texas, USA
Robert L. Phillips (1)(2)(3)
West 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
Niels Espeland
President, International
Doug B. Evasiuk
Senior Vice President,
Sales and Marketing
Veronica Foley
Vice President, Legal and
Corporate Secretary
Robert J. McNally
Executive Vice President and
Chief Financial Officer
Darren J. Ruhr
Senior Vice President,
Corporate Services
Gene C. Stahl
President, Drilling Operations
Precision Drilling Corporation 2015 Annual Report
95
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