Precision
Drilling
Corporation
2018
Annual
Report
Precision
Management’s Discussion and Analysis
Consolidated Financial Statements and Notes
Precision Drilling Corporation 2018
What’s Inside
5 About Precision
9
2018 Highlights and Outlook
14 5 Understanding Our Business Drivers
14 The Energy Industry
19 A Competitive Operating Model
23 An Effective Strategy
25
2018 Results
26 2018 Compared with 2017
27 2017 Compared with 2016
28 Segmented Results
31 Quarterly Financial Results
34 Financial Condition
34 Liquidity
35 Capital Management
36 Sources and Uses of Cash
37 Capital Structure
401 Accounting Policies and Estimates
44 Risks in Our Business
55 Evaluation of Controls and Procedures
56 Management’s Report to the Shareholders
57
Independent Auditors’ Reports
59 Consolidated Financial Statements and Notes
92 Supplemental Information
94 Shareholder Information
95 Corporate Information
2018 SHARE TRADING SUMMARY
The Toronto Stock Exchange (TSX)
Volume (millions)
Daily Closing Sha re Price ( Cdn $)
)
$
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P
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$6
$4
$2
$-
Jan
Feb
Mar
Apr il
May
June
July
Aug
Sep t
Oct
Nov
Dec
Toronto (TSX:PD)
High: $5.33
Low: $2.25
Close December 31, 2018: $2.37
Volume Traded: 514,932,362
The New York Stock Exchange (NYSE)
Volume (millions)
Daily Closing Sha re Price ( US $)
$6
$4
$2
)
$
S
U
(
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c
i
r
P
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r
a
h
S
$-
Jan
Feb
Mar
Apr il
May
June
July
Aug
Sep t
Oct
Nov
Dec
New York (NYSE: PDS)
High: $4.14
Low: $1.62
Close December 31, 2018: $1.74
Volume Traded: 475,910,527
)
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MD&A
Management’s
Discussion and
Analysis
information
business
This management’s discussion and analysis
to help you
(MD&A) contains
financial
and
our
understand
performance. Information is as of March 1, 2019.
This MD&A focuses on our Consolidated Financial
Statements and Notes and includes a discussion of
known risks and uncertainties relating to our
business and the oilfield services sector.
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 2.
The terms we, us, our, Precision Drilling and
Precision mean Precision Drilling Corporation and
our subsidiaries and include any partnerships that
we are part.
All amounts are
otherwise stated.
in Canadian dollars unless
Precision Drilling
Corporation
2018
1
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.
Certain statements contained in this MD&A, including statements that contain words such as could, should, can, anticipate,
estimate, intend, plan, expect, believe, will, may, continue, project, potential and similar expressions and statements relating to
matters that are not historical facts constitute forward-looking information within the meaning of applicable Canadian securities
legislation and forward-looking statements within the meaning of the safe harbor provisions of the United States Private
Securities Litigation Reform Act of 1995 (collectively, forward-looking information and statements).
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 about drilling activity in North America and the demand for drilling rigs
our capital expenditure plans for 2019
our 2019 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 we currently operate in
our ability to remain compliant with our senior secured credit facility financial debt covenants.
The 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 customer spending plans as a result of changes in oil and natural gas prices
the status of current negotiations with our customers and vendors
customer focus on safety performance
existing term contracts are neither renewed or terminated prematurely
continued market demand for drilling rigs
our ability to deliver rigs to customers on a timely basis
the general stability of the economic and political environment in the jurisdictions we operate in
the impact of an increase/decrease in capital spending.
Undue reliance should not be placed on forward-looking information and statements. Whether actual results, performance or
achievements will conform to our expectations and predictions is subject to a number of known and unknown risks and
uncertainties which could cause actual results to differ materially from our expectations. Such risks and uncertainties include,
but are not limited to:
volatility 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
our customers’ inability to obtain adequate credit or financing to support their drilling and production activity
changes in drilling and well servicing technology, which could reduce demand for certain rigs or put us at a competitive
advantage
shortages, delays and interruptions in the delivery of equipment supplies and other key inputs
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
the availability of qualified personnel and management
a decline in our safety performance which could result in lower demand for our services
changes in laws or regulations, including changes in environmental laws and regulations such as increased regulation
of hydraulic fracturing or restrictions on the burning of fossil fuels and greenhouse gas emissions, which could have an
adverse impact on the demand for oil and natural gas
terrorism, social, civil and political unrest in the foreign jurisdictions where we operate
Precision Drilling Corporation 2018 Annual Report
2
fluctuations in foreign exchange, interest rates and tax rates, and
other unforeseen conditions which could impact the use of services supplied by Precision and our ability to respond to
such conditions.
Readers are cautioned that the foregoing list of risk factors is not exhaustive. You can find more information about these and
other factors that could affect our business, operations or financial results in reports on file with securities regulatory authorities
from time to time, including but not limited to our annual information form (AIF) for the year ended December 31, 2018, which
you can find in our profile on SEDAR (www.sedar.com) or in our 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 securities law.
NON-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, loss or gain on redemption and repurchase of unsecured
senior notes, finance charges, foreign exchange, impairment of property, plant and equipment, impairment of goodwill and
depreciation and amortization), as reported in our Consolidated Statement of Loss, is a useful measure, because it gives an
indication of the results from our principal business activities prior to consideration of how our activities are financed and the
impact of foreign exchange, taxation and depreciation and amortization charges.
Covenant EBITDA
Covenant EBITDA, as defined in our Senior Credit Facility agreement, is used in determining the Corporation’s compliance with
its covenants. Covenant EBITDA differs from Adjusted EBITDA by the exclusion of bad debt expense, restructuring costs and
certain foreign exchange amounts.
Operating Loss
We believe that operating loss is a useful measure because it provides an indication of the results of our principal business
activities before consideration of how those activities are financed and the impact of foreign exchange and taxation. Operating
loss is calculated as follows:
Year ended December 31 (thousands of dollars)
Revenue
Expenses:
Operating
General and administrative
Restructuring
Other recoveries
Depreciation and amortization
Impairment of goodwill
Impairment of property, plant and equipment
Gain on re-measurement of property, plant and equipment
Operating loss
Foreign exchange
Finance charges
Loss (gain) on redemption and repurchase of unsecured senior notes
Income taxes
Net loss
2018
1,541,189
1,067,871
112,387
-
(14,200 )
365,660
207,544
-
-
(198,073 )
4,017
127,178
(5,672 )
(29,326 )
(294,270 )
2017
1,321,224
926,171
90,072
-
-
377,746
-
15,313
-
(88,078 )
(2,970 )
137,928
9,021
(100,021 )
(132,036 )
2016
951,411
607,295
110,287
5,754
-
391,659
-
-
(7,605 )
(155,979 )
6,008
146,360
239
(153,031 )
(155,555 )
3
Management’s Discussion and Analysis
Funds Provided by (Used In) Operations
We believe that funds provided by (used in) operations, as reported in our Consolidated Statements of Cash Flow, is a useful
measure because it provides an indication of the funds our principal business activities generate prior to consideration of working
capital, which is primarily made up of highly liquid balances.
Working Capital
We define working capital as current assets less current liabilities as reported in our Consolidated Statement of Financial
Position.
Precision Drilling Corporation 2018 Annual Report
4
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 a large oilfield
services company with broad geographic scope in North America. We
also have operations in the Middle East.
Our common 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 globally recognized as the High
Performance, High Value provider of land drilling
services.
You can read about our strategic priorities for 2019
on page 24.
COMPETITIVE ADVANTAGE
From our founding as a private oilfield drilling contractor in the 1950s, Precision has grown to become one of the most active
drillers in North America. Our competitive advantage is underpinned by five distinguishing features:
a competitive operating model that drives efficiency, quality and cost discipline
a culture focused on safety and performance
size and scale of operations that provide higher margins and better service capabilities
high quality standardized equipment and control system with process automation control and advanced digital
backbone systems to deliver efficient, consistent and safe drilling services, and
a capital structure that provides long-term stability, flexibility and liquidity that allows us to take advantage of business
cycle opportunities.
CORPORATE GOVERNANCE
At Precision, we believe that a transparent culture of corporate governance and ethical behaviour in decision-making is
fundamental to the way we do business.
We have a diverse and experienced Board of Directors (Board). Our directors have a history of achievement and an effective
mix of skills, knowledge, and business experience. The directors oversee the conduct of our business, provide oversight in
support of future operations and monitor regulatory developments and governance best practices in Canada and the U.S. Our
Board also reviews our governance charters, guidelines, policies and procedures to make sure they are appropriate and that
we maintain high governance standards.
Our Board has established three standing committees, comprised of independent directors, to help it carry out its responsibilities
effectively:
Audit Committee
Corporate Governance, Nominating and Risk Committee, and
Human Resources and Compensation Committee.
The Board may also create special ad hoc committees from time to time to deal with important matters that arise.
You can find more information about our approach to governance in our management information circular, available on our
website (www.precisiondrilling.com).
5
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
● Drilling rig operations
– Canada
– U.S.
– International
● Directional drilling operations
– Canada
– U.S.
Completion and Production Services
● Canada and U.S.
– Service rigs
● Canada
– Snubbing
– Camps and catering
– Equipment Rentals
Business support systems
● Sales and
marketing
● Procurement and
distribution
● Manufacturing
● Equipment maintenance
● Engineering
and certification
Corporate support
● Information
systems
● Health, safety and
environment
● Human
resources
● Finance
● Legal and enterprise
risk management
2018 Revenue by Segment
Completion and Production
Services 10%
2018 Revenue by Location
International 12%
Ca nada 37%
Contract Drilling
Services 90%
U.S. 51%
Precision Drilling Corporation 2018 Annual Report
6
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 a large, multi-basin oilfield operator servicing approximately 26% of the active land drilling market in Canada and 7% of
the active U.S. market. We also have an international presence with operations in the Middle East and Mexico.
At December 31, 2018, our Contract Drilling Services segment consisted of:
236 land drilling rigs, including:
– 117 in Canada
– 102 in the U.S.
– 5 in Kuwait
– 5 in Mexico
– 4 in Saudi Arabia
– 2 in the Kurdistan region of Iraq
– 1 in the country of Georgia
directional drilling services 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
18 Canadian and four U.S. land drilling rigs designated as held for sale .
At December 31, 2018, we had 236 Super Series drilling rigs. Our Super Series rigs are highly mobile and mechanized, which
make them safer and more efficient in drilling directional and horizontal wells than older generation drilling rigs. Our Super Series
rigs have a broad range of features to meet a diverse range of customer needs with a focus on high efficiency development
drilling applications, from drilling shallow- to medium-depth wells to deeper, extended reach horizontal well bores and all depths
of conventional wells. Available features include alternating current (AC) power, digital control systems, integrated top drive,
omni-directional pad walking systems for multi-pad well drilling, highly mechanized pipe handling, and high capacity mud pumps.
Contract Drilling
Revenue
$ Millions
$2,500
$2,000
$1,500
$1,000
$500
$0
2014
2015
2016
2017
2018
Contract Drilling
Adjusted EBITDA
$ Millions
$1,000
$800
$600
$400
$200
$0
Contract Drilling
Utilization Days
80,000
60,000
40,000
20,000
0
2014
2015
2016
2017
2018
2014
2015
2016
2017
2018
7
Management’s Discussion and Analysis
Completion and Production Services
We provide well completion, workover, abandonment, and re-entry preparation services, as well as snubbing units for pressure
control 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 2018, we serviced approximately 12% of the well completion and workover service rig market
demand in Canada and less than 1% in the U.S.
At December 31, 2018, our Completion and Production Services segment consisted of:
∎ 198 well completion and workover service rigs, including:
– 190 in Canada
– 8 in the U.S.
∎ 12 snubbing units in Canada
∎ approximately 1,700 oilfield rental items, including surface storage, small-flow wastewater treatment, power generation,
and solids control equipment, primarily in Canada
∎ 132 wellsite accommodation units in Canada
∎ 43 drill camps and four base camps in Canada
∎ 10 large-flow wastewater treatment units, 22 pumphouses and eight potable water production units in Canada.
Completion and Production
Revenue
$ Millions
$400
Completion and Production
Adjusted EBITDA
$ Millions
$100
Completion and Production
Service Rig Hours
Hours
400,000
$300
$200
$100
$0
$50
$0
-$50
300,000
200,000
100,000
0
2014
2015
2016
2017
2018
2014
2015
2016
2017
2018
2014
2015
2016
2017
2018
Precision Drilling Corporation 2018 Annual Report
8
2018 Highlights and Outlook
Management’s
Discussion
and
Analysis
Adjusted EBITDA, funds provided by operations and working capital are Non-GAAP measures. See page 3 for more information.
Financial Highlights
Year ended December 31
(thousands of dollars, except where noted)
Revenue
Adjusted EBITDA
Adjusted EBITDA % of revenue
Net loss
Cash provided by operations
Funds provided by operations
Investing activities
Capital spending
Expansion
Upgrade
Maintenance and infrastructure
Intangibles
Proceeds on sale
Net capital spending
Business acquisition
Loss per share ($)
Basic and diluted
n/m – calculation not meaningful.
Operating Highlights
Year ended December 31
Contract drilling rig fleet
Drilling rig utilization days
Canada
U.S.
International
Revenue per utilization day
Canada (Cdn$)
U.S. (US$)
International (US$)
Operating cost per utilization day
Canada (Cdn$)
U.S. (US$)
Service rig fleet
Service rig operating hours
Revenue per operating hour (Cdn$)
2018
1,541,189
375,131
24.3%
(294,270)
293,334
311,214
35,444
30,757
48,375
11,567
(24,457)
101,686
—
% increase/
(decrease)
16.6
23.0
122.9
151.7
69.2
196.7
(17.1 )
87.6
(50.1 )
64.8
22.3
—
2017
1,321,224
304,981
23.1%
(132,036)
116,555
183,935
11,946
37,086
25,791
23,179
(14,841)
83,161
—
% increase/
(decrease)
31.7
33.7
2016
1,003,233
228,075
% increase/
(decrease)
(38.6)
(51.9)
(15.1 )
(4.9 )
74.6
(92.0 )
86.7
(25.7 )
n/m
89.3
(57.5 )
(100.0 )
22.7%
(155,555)
122,508
105,375
148,887
19,862
34,723
—
(7,840)
195,632
12,200
(57.2)
(76.3)
(70.5)
(58.8)
(59.0)
(28.8)
—
(19.9)
(56.4)
n/m
(57.3)
(1.00)
122.2
(0.45)
(15.1 )
(0.53)
2018
236
18,617
26,714
2,920
21,644
21,864
50,469
14,493
14,337
210
157,467
709
% increase/
(decrease)
(7.8)
(1.4)
30.4
-
2.4
10.1
0.5
10.3
3.5
-
(8.9)
11.3
2017
256
18,883
20,479
2,920
21,143
19,861
50,240
13,140
13,846
210
172,848
637
% increase/
(decrease)
0.4
48.4
80.5
4.8
(13.7 )
(24.0 )
9.8
(7.8 )
(10.9 )
1.4
73.8
(1.4 )
2016
255
12,722
11,343
2,786
24,509
26,145
45,753
14,258
15,547
207
99,451
646
% increase/
(decrease)
1.6
(26.2 )
(46.4 )
(31.8 )
(9.1 )
(2.2 )
5.2
(4.2 )
(0.5 )
27.0
(33.5 )
(17.6 )
9
Management’s Discussion and Analysis
Financial Position and Ratios
December 31,
(thousands of dollars, except ratios)
Working capital(1)
Working capital ratio
Long-term debt
Total long-term financial liabilities
Total assets
Enterprise value(2)
Long-term debt to long-term debt plus equity(3)
Long-term debt to cash provided by operations
Long-term debt to enterprise value
(1) See NON-GAAP MEASURES on page 3 of this report.
(2) Share price multiplied by the number of shares outstanding plus long-term debt minus cash. See page 39 for more information.
(3) Net of unamortized debt issue costs.
232,121
2.1
1,730,437
1,754,059
3,892,931
2,782,596
0.5
14.8
0.6
December 31,
2018
240,539
1.9
1,706,253
1,723,350
3,636,043
2,305,890
0.5
5.8
0.7
December 31,
2016
230,874
2.0
1,906,934
1,946,742
4,324,214
3,937,737
0.5
15.6
0.5
2017
2018 OVERVIEW
While global commodity prices strengthened in 2018, the year was beleaguered with extreme volatility, particularly in the
Canadian market. In the U.S., West Texas Intermediate (WTI) oil prices averaged US$65 per barrel and Henry Hub natural gas
prices averaged US$3.07 per MMBtu, levels supportive of unconventional resource development. However, a volatile and
uncertain oil price outlook and renewed focus on free cash flow has encouraged conservatism in customer spending. In Canada,
acute pipeline takeaway shortfalls and growing uncertainty in regulatory policy caused immense pressure on regional commodity
prices and subsequent activity levels, particularly towards the end of the year. In early December the Alberta government
instituted mandatory oil production curtailments as a vehicle to address regional oil price differentials relative to WTI oil prices.
For the year ended December 31, 2018, our net loss was $294 million, or $1.00 per diluted share, compared with a net loss of
$132 million, or $0.45 per diluted share in 2017. During 2018 we incurred a goodwill impairment charge of $208 million related
to our Canada contract drilling and U.S. directional drilling businesses, that after tax, increased our net loss by $199 million and
net loss per diluted share by $0.68.
Revenue in 2018 was $1,541 million, or 17% higher than in 2017, mainly due to higher activity and day rates in our U.S. contract
drilling operations. Contract Drilling Services revenue was up 19%, while Completion and Production Services revenue was
down 2%. Our U.S. drilling activity increased 30% in 2018 while Canadian and international drilling activity remained consistent
with 2017.
Adjusted EBITDA in 2018 was $375 million, or 23% higher than in 2017. Our Adjusted EBITDA margin was 24%, slightly higher
than 2017. Adjusted EBITDA improved in 2018 primarily due to increased U.S. drilling activity and day rates. Adjusted EBITDA
as a percentage of segment revenue for the year in our Contract Drilling Services segment was 30%, compared with 29% in the
prior year, while Adjusted EBITDA as a percentage of segment revenue from our Completion and Production Services segment
was 10%, compared to 8% in 2017. The improved percentages achieved in our Completion and Production Services segment
were the result of improved day rates. Our portfolio of term customer contracts, a scalable operating cost structure, and
economies achieved through vertical integration of the supply chain help us manage our Adjusted EBITDA percentages.
Capital expenditures for the purchase of property, plant and equipment were $126 million in 2018, an increase of $28 million
over 2017. Capital spending for 2018 included $66 million for upgrade and expansion capital, $48 million for the maintenance
of existing assets and infrastructure and $12 million for intangibles related to a new enterprise-wide resource planning (ERP)
system.
In 2018 we continued to invest in our fleet adding two new-build drilling rigs in the U.S., completing 31 rig upgrades, and
commencing the build of our sixth Kuwait rig, all of which were backed by long-term contracts and within a constrained expansion
and upgrade capital spend of approximately $66 million.
Under IFRS, we are required to assess the carrying value of assets in our cash-generating units (CGUs) containing goodwill
annually and when indicators of impairment exist. Due to the decrease in oil and natural gas well drilling in Canada and the
outlook for activity in Canada and in our directional drilling division in the U.S., we recognized a $208 million goodwill impairment
charge. The impairment charge represents the full amount of goodwill attributable to our Canadian contract drilling operation
and our U.S. directional drilling operations.
During the year we redeemed US$80 million and repurchased and cancelled US$3 million of our 6.5% unsecured senior notes
due 2021 and repurchased and cancelled US$49 million principal amount of our 5.25% unsecured senior notes due 2024.
Precision Drilling Corporation 2018 Annual Report
10
OUTLOOK
Contracts
Term customer contracts provide a base level of activity and revenue.
As of March 1, 2019, we had term contracts in place for an average of
54 rigs: six in Canada, 40 in the U.S. and eight internationally for 2019.
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 2018, we had an average of 63 drilling rigs working under term contracts and revenue from
these contracts was approximately 49% of our total contract drilling revenue for the year.
In 2018, approximately 49% of our total contract
drilling revenue was generated from rigs under
term contracts.
Pricing, Demand and Utilization
Volatility in global crude prices remained a key theme throughout 2018, particularly towards the end of the year with concerns
over the health of the global economy, ongoing trade wars, varying degrees of OPEC and non-OPEC production cuts and
continued growth in U.S. production driving uncertainty in supply and demand fundamentals. The WTI oil price closed the year
at US$45.41 per barrel. Since then, WTI has hovered in the mid-US$50’s per barrel range and closed at US$55.80 per barrel
on March 1, 2019. A similar phenomenon played out in other grades of crude such as Western Canada Select (WCS) and
Permian regional pricing whereby mid-to late 2018 differentials widened to extreme levels largely as a result of takeaway capacity
constraints in each respective market. Year-to-date in 2019 differentials have narrowed and are expected to revert to more
normalized levels in the Permian with incremental takeaway capacity added mid-year, while in Canada WCS differentials are
expected to remain volatile but show greater stability with the province of Alberta having instituted production constraints at the
end of 2018 in addition to incremental rail capacity and potential increased pipeline takeaway capacity.
Natural gas prices have remained relatively rangebound by historical standards as growth in associated gas from unconventional
oil development, higher than average storage levels, infrastructure constraints and the lack of a fully developed export market
from North America continue to cap pricing. Natural gas prices in the U.S., referenced by the Henry Hub price on the New York
Mercantile Exchange (NYMEX), averaged US$3.07 per MMBtu in 2018, and closed the year at US$2.94 per MMBtu. In Canada,
the AECO natural gas benchmark experienced price weakness and volatility in 2018 particularly in the summer months driven
by plant maintenance, pipeline shut-ins, and challenges exporting natural gas as a Canadian LNG export industry has not been
developed leaving a well-supplied U.S. market as the only export option for Canadian natural gas. Differences between NYMEX
(U.S.) prices and AECO (Canada) prices are expected to continue if Canadian export markets remained challenged.
The rig count at March 1, 2019 was 30% lower in Canada than it was a year ago while the year-to-date rig count has averaged
48% less than 2018. Activity for the remainder of the year is expected to be determined by the strength in commodity prices and
the resulting oil and natural gas customer budgets.
In the U.S., strengthening crude prices have resulted in increased drilling activity and demand for our rigs. As a result, spot
market pricing and activity each increased throughout 2018 and have improved further year-to-date in 2019. As of March 1,
2019, the rig count was 5% higher than the same time last year and has averaged 10% higher year-to-date compared to
2018. Activity levels for the remainder of 2019 are expected to be dependent on commodity prices and resulting customer
budgets.
The Canadian to U.S. dollar exchange rate averaged US$0.7712 (Cdn$/US$1.2966) for 2018 and closed the year at US$0.7325
(Cdn$/US$1.36521). The lower 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. Year to date, the
Canadian dollar has strengthened against the U.S. dollar and as of March 1, 2019, the Canadian dollar closed at US$0.7518.
International
We currently have eight rigs working on term contracts with five in Kuwait and three in the Kingdom of Saudi Arabia. During
2018, we announced the award of one new-build ST-3000 drilling rig in Kuwait under a five year take-or-pay contract with an
optional one-year extension. We expect the sixth rig to commence drilling operations in the third quarter of 2019.
11
Management’s Discussion and Analysis
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.
With the completion of our new-build rig program and upgrades of existing rigs, our fleet consisted of 236 Super Series rigs and
22 rigs identified and held for sale as at December 31, 2018.
Capital Spending
Capital spending in 2019 is expected to be $169 million and includes $53 million for sustaining and infrastructure and $116
million for upgrade and expansion, approximately $68 million of which relates to the completion of our sixth new-build rig in
Kuwait. We expect that the $169 million will be split $161 million in the Contract Drilling Services segment, $6 million in the
Completion and Production Services segment and $2 million to the Corporate segment.
Precision Drilling Corporation 2018 Annual Report
12
Revenue and
Adjusted EBITDA
Revenue
Adjusted EBITDA
EBITDA Margin
s
n
o
i
l
l
i
M
$
$2,500
$2,000
$1,500
$1,000
$500
$0
2014
2015
2016
2017
2018
50%
40%
30%
20%
10%
0%
%
n
i
g
r
a
M
Funds and Cash Provided By
Operations
s
n
o
i
l
l
i
M
$
Funds provided by operations
Cash provided by operations
$800
$700
$600
$500
$400
$300
$200
$100
$0
Drilling Utilization Days
80,000
s
y
a
D
60,000
40,000
20,000
0
International
U.S.
Canada
2014
2015
2016
2017
2018
2014
2015
2016
2017
2018
13
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 sector of the energy industry. We
depend on oil and natural gas exploration and production companies to contract our services as part of their exploration and
development activities. The economics of their businesses 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.
Conventional / Unconventional wells
Oil and natural gas reservoirs can be conventional, where a vertical well is drilled into a highly pressurized reservoir allowing the
oil and natural gas to flow freely shortly after completing the drilling process. Unconventional reservoirs are exploited by drilling
a vertical section of a well followed by a horizontal section to access a large portion of the oil or natural gas formation. These
“unconventional” or “shale” reservoirs are typically lower pressure and require extra stimulation to generate production. The
practice of “hydraulic fracturing” follows the unconventional drilling process with high horsepower equipment pumping water and
proppant down a wellbore at high pressure to frack the rock, releasing hydrocarbons. The vast majority of the wells we drill in
North America are unconventional. We are not involved in the hydraulic fracturing of a well.
Commodity Prices
Cash flow to fund exploration and development is dependent on commodity prices: higher prices increase cash flow and
encourage investment and 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. Higher oil prices typically result in stronger demand for drilling services with funding for drilling programs directed
toward the most economically attractive drilling opportunities. As the volume of unconventional oil development has dramatically
increased over the past decade, generating efficiencies through industrialized processes, more capital has been directed toward
unconventional oil development in North America, reflecting the region’s competitiveness globally.
Natural gas and natural gas liquids continue to be priced more 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, and lower prices. The planned
liquefied natural gas (LNG) export from Canada and continued development in the U.S. could serve as a catalyst for natural gas
directed drilling activity over the medium to long term.
The key natural gas price driver continues to be increased production from unconventional shale gas drilling. Since the winter
of 2014, pricing for natural gas in North America has generally 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.
Precision Drilling Corporation 2018 Annual Report
14
Average Oil and Natural Gas Prices
Oil
WTI (US$ per barrel)
Natural gas
Canada
AECO ($ per MMBtu)
U.S.
Henry Hub (US$ per MMBtu)
Source: WTI and Henry; Hub Energy Information Administration, AECO; Gas Alberta Inc.
12
WTI Oil Prices and
Henry Hub Natural Gas
Prices
u
t
B
M
M
/
$
S
U
8
4
Henry Hub Natural Gas
WTI Oil
0
Jan-14
Source: Energy Information Administration
2018
64.88
1.49
3.12
2016
43.30
2.14
2.48
2017
50.95
2.16
2.98
120
l
e
r
r
a
b
/
$
S
U
80
40
0
Jan-15
Jan-16
Jan-17
Jan-18
Jan-19
New Technology
North American exploration and production companies, which comprise the majority of our customer base, have been adapting
to a lower commodity price environment and are increasingly focused on drilling and completion efficiency. Most of these
companies have adopted large-scale industrialization techniques, utilizing multi-well pads and high-efficiency downhole and
surface drilling systems to improve efficiency. Over the past several years, drilling rig enhancements have focused on equipment
upgrades, such as walking systems, AC controls and increased fluid pumping capacity. More recently, customer focus has been
shifting to rig automation technologies to deliver increased efficiency, consistency and predictability of results, which customers
desire in their development-style drilling programs. Exploration and production companies have an increasing appetite for these
technologies as they provide an opportunity to push the limits of efficiency and consistency, common in industrialized processes.
Our technology strategy is well-aligned with customer efficiency objectives. We leverage our existing base of AC control systems
installed on over 100 of our Super Series drilling rigs. These standardized control systems enable us to reliably mass deploy
advanced software systems capable of delivering leading-edge digital automation, significantly boosting efficiency of the well
construction process. Our technology strategy is centered around partnering with industry experts which allows us to deliver an
15
Management’s Discussion and Analysis
extensive suite of offerings to our customers with minimal research and development capital. Our digital technology strategy is
currently focused on four fundamentals:
1. Standardized Control System Platform
We leverage our standardized rig equipment and control system to deploy a fully integrated Process Automation Control
system (PAC), which allows us to consistently implement best practices to eliminate human variance and human error,
resulting in significantly improved drilling efficiency. In addition to built-in process automation routines, PAC also hosts
Precision Drilling Apps (PD Apps), which leverage advanced algorithms and exploitation of various machine learning
techniques to improve complex drilling processes. The standard platform is encouraging innovation in the drilling app space
by attracting innovative solutions from customers and third parties inside and outside the oil and gas industry. We installed
our first PAC system in late 2016 and currently have 31 PAC systems deployed in the field and more than 15 PD Apps in
the trial phase or in development, making Precision an industry leader in automation technology.
2. Data Collection and Analytics
Our digital rig control systems with PAC are now generating well above 1 GB/min of data, versus a limited number of data
channels from traditional Electronic Data Recorders, knowns as EDR systems. We have a robust data analytics strategy
with a dedicated analytics team (PD Analytics) focused on improving rig performance and financial returns through
commercialization of performance data.
3. Digitally Enabled Services
Our advanced digital infrastructure helps automate repetitive tasks for the driller, freeing up time for the driller to address
more value-added responsibilities. For example, we have introduced our Directional Guidance System (DGS) aiming to
either replace directional drillers on the wellsite through an advanced algorithm delivered through a PD App and remote
support. To date, we have successfully drilled more than 200 wells using this technology and believe these types of solutions
will eventually become industry standard.
4. Leading-Edge Corporate-Wide Data Systems and Technology Culture
In 2018, we successfully implemented the latest version of SAP S/4HANA to fully realize the benefits of the system’s
integration with our digital service delivery platform. This robust SAP enterprise system is built to support the increased data
flows from the field, provided by our PAC systems. Precision committed to a digital technology strategy nearly three years
ago, enabling us to build a strong digital mindset within the company at all levels.
Our combination of High Performance standardized rig fleet, integrated PAC system, PD Apps and PD Analytics position us to
help our customers achieve their efficiency goals and generate strong returns for our shareholders through service differentiation.
Precision Drilling Corporation 2018 Annual Report
16
U.S. Lower 48 Production
120
100
80
60
40
20
/
)
d
F
C
B
(
s
a
G
l
a
r
u
t
a
N
Natural Gas Production
Crude Oil Production
Source: Energy Information Administration
0
Jan-14
Jan-15
Jan-16
Jan-17
Jan-18
Jan-19
12
10
8
6
4
2
0
)
d
/
s
l
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.
)
d
/
s
l
b
b
M
M
(
l
i
O
e
d
u
r
C
5
4
3
2
1
0
Canadian Production
20
16
12
8
4
/
)
d
F
C
B
(
s
a
G
l
a
r
u
t
a
N
Natural Gas Production
Crude Oil Production
Source: Energy Information Administration, FEC
0
Jan-14
Jan-15
Jan-16
Jan-17
Jan-18
Jan-19
17
Management’s Discussion and Analysis
Drilling Activity
Following a decline in activity in 2015 and 2016, the North American land drilling market showed increased activity levels in
2017 and 2018, particularly in the U.S., as customer demand improved with higher oil prices.
In 2018, the industry drilled 6,781 wells in western Canada, compared with 6,959 in 2017 and 3,963 in 2016. Total industry
drilling operating days were 64,491 in 2018 compared with 66,138 in 2017 and 42,391 in 2016. Average industry drilling
operating days per well was 9.5, the same as in 2017 and slightly lower than 10.7 in 2016. From 2017 to 2018 the average depth
of a well increased 4% compared with an increase of 5% from 2016 to 2017.
In 2018 approximately 19,300 wells were started onshore in the U.S., compared with approximately 15,800 in 2017 and 11,200
in 2016.
In Canada, there has been relative strength in natural gas liquids and light tight oil drilling activity in the deeper basins of
northwestern Alberta and northeastern British Columbia, while in the U.S. the bias towards oil-directed drilling continues. In
2018, approximately 63% of the Canadian industry’s active rigs and 81% of the U.S. industry’s active rigs were drilling for oil
targets, compared with 53% for Canada and 80% for the U.S. in 2017.
The graphs below show the shift in drilling activity to oil targets since 2014, in both the U.S. and Canada. 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. Active Rig Count
1,600
1,200
800
400
g
n
i
k
r
o
w
s
g
i
R
Oil Land
Gas Land
Source: Baker Hughes
0
Jan-14
Jan-15
Jan-16
Jan-17
Jan-18
Jan-19
Precision Drilling Corporation 2018 Annual Report
18
Canadian Active Rig Count
400
200
g
n
i
k
r
o
w
s
g
i
R
Oil
Gas
Source: Baker Hughes
0
Jan-14
A COMPETITIVE OPERATING MODEL
Jan-15
Jan-16
Jan-17
Jan-18
Jan-19
The contract drilling business is highly competitive, with many industry participants. We compete for drilling contracts that are
often awarded in 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, condition of rigs, quality of rig crews,
breadth of service, technology offering, 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 through passionate people supported by quality business systems, drilling technology, equipment and
infrastructure designed to optimize results and reduce risks. We create High Value by operating safely and sustainably, lowering
our customers’ risks and costs while improving efficiency, developing our people, and generating superior financial returns for
our investors.
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
∎ staffing our rigs with well-trained crews with performance measured against defined competencies, and
∎ compensating our executives and eligible employees based on performance against safety, operational, employee
retention, and financial measures.
Efficient, Cost-Reducing Technologies
We focus on providing efficient, cost-reducing drilling technologies. Design innovations and technology improvements, such as
multi-well pad capability and rapid mobility between wells, capture incremental time savings during the drilling process.
Precision has invested over $3 billion in its drilling rig fleet since 2010, adding over 120 Super Series drilling rigs during the
period. With one of the newest and most technically capable fleets in North America and the Middle East, Precision’s Super
Series rigs have been designed for industrial-style drilling: highly efficient; mobile; safe; controllable; upgradable; and able to act
as a platform for technology delivery to the well location. Precision has completed several relatively low dollar cost upgrades
over the past several years including additions of walking systems, higher pressure and capacity mud pumps, increased setback
capacity and PAC technology. Precision’s Super Series drilling rig fleet has the features needed to meet essentially all the
industrial-style drilling requirements of our customers in North America and deep, high-pressure drilling projects internationally.
19
Management’s Discussion and Analysis
Broad Geographic Footprint
Geographic proximity and fleet versatility support the High Performance, High Value services we provide to our customers. Our
large 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
Minimizing downtime is a key operating metric for us and our customers. 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 systems, reducing the number of move
loads per rig, and using mechanized equipment for safer and quicker rig component connections.
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 statistics to evaluate our performance against competitors.
We reward executives and eligible employees through incentive compensation plans for performance against the following
measures:
∎ safety performance – total recordable incident rate per 200,000 man-hours, recordable free facilities and “Triple Target
Zero” days (defined on page 22 under ‘Safe Operations’). 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
∎ strategic initiatives – achieving strategic operational goals. Measured against predetermined target metrics
∎ financial performance – Adjusted EBITDA, adjusted cash flow, return on capital employed and debt reduction. Measured
against predetermined targets
∎ investment returns – total shareholder return performance (including dividends) against a group of industry peers, over
a three-year period. The peer group consists of a predetermined group of companies with similar business operations
that we compete with for investors.
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 and conventional 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 in the northern U.S. Service rigs
are supported by four field locations in Alberta, two in Saskatchewan, and one each in 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.
Precision Drilling Corporation 2018 Annual Report
20
Upgrade Opportunities
We leverage our internal manufacturing and repair capabilities and inventory of quality rigs to address market demand through
upgraded drilling rigs. For drilling rigs, the upgrade is typically performed at the request of a customer and includes a term
contract. Historically, certain upgrades have resulted in a change in tier classification.
Ancillary Equipment and Services
An inventory of equipment (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 from our manufacturing division in
Canada and for standardization and distribution of consumable oilfield products through our procurement divisions in Canada
and the U.S.
Precision Rentals provides specialized equipment and wellsite accommodations to customers on a rental basis. Precision Camp
Services provides food and accommodation to personnel working at the wellsite, typically in remote locations in Western Canada.
Technical Centres
We operate two contract drilling technical centres, one in Nisku, Alberta and one 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. Both of our contract drilling
technical centres include fully functioning training rigs with the latest drilling technologies. 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, comprehensive
employee training, competency 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 and the U.S. Our people strategies have enabled us to deliver quality field crews at all points in the industry cycle.
Toughnecks (www.toughnecks.com) has been a
highly successful field recruiting program for us
since we introduced it in 2008.
Systems
In 2017 we commenced an upgrade to our ERP system that was completed in the second quarter of 2018. The upgraded
system fully integrates our drilling rigs with our field facilities and corporate offices increasing operating efficiencies and
positioning the organization to better handle the increased data flows associated with our business. All our divisions operate
using standardized business processes across marketing, equipment maintenance, procurement, manufacturing, HSE,
inventory control, engineering, finance, payroll and human resources.
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, which identify and help leverage economies of scale
as construction demands increase.
21
Management’s Discussion and Analysis
Safe Operations
Safety, environmental stewardship and employee health are critical for us and for our customers and are the foundation of our
culture.
to operating
Safety performance
performance and the financial results we generate for our shareholders.
We track safety using three separate metrics:
fundamental contributor
is a
∎ Total Recordable Incident Rate
∎ Facilities Recordable Free
∎ Triple Target Zero Days.
Target Zero
The health and safety of our employees is a core
value at Precision, and daily we work to set the
standard for safety in our industry.
Total Recordable Incident Rate (TRIR) is an industry standard and benchmarks our success 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 more serious events. In 2018, 96% of our drilling rigs and 99% of our service rigs achieved
Recordable Free Facilities. Facilities recordable free includes all of our rigs, operating centres and offices and measures how
many of our facilities do not have a recordable incident during the year. In addition, we have a goal of achieving “Triple Target
Zero” every day. A Triple Target Zero day is a day when we have no high potential work-related vehicle incidents, no recordable
injuries and no reportable spills. For 2018 we achieved 288 Triple Target Zero days.
We foster our safety culture through strong leadership, technical and compliance training, and proven support systems. Every
day, we invest in our employees to prepare them for any and every situation on the rig. Our Technical Support Centre training
facilities are located in Houston, Texas, and Nisku, Alberta, where more than 6,100 employees were trained in 2018 on our
culture, rig personnel and responsibilities, tools and equipment, safety and environmental protocol and procedures, leadership
and team-building.
We continuously review our rig designs and components and use advanced technology to operate safely, improve the life cycle,
maintain operational efficiency, reduce energy use, and maintain our energy and resources. In 2018, 20% of our fleet was
configured to be powered by natural gas, which is cleaner-burning than diesel and therefore reduces our, and our customer’s,
carbon footprint. Our pad-capable rig fleet has also helped our customers reduce their overall operating footprint by enabling
them to drill multiple wells on a single well pad location.
Precision Drilling Corporation 2018 Annual Report
22
AN EFFECTIVE STRATEGY
Precision’s vision is to be globally recognized as the High Performance, High Value provider of land drilling services. We work
toward this vision by defining and measuring our results against strategic priorities we establish at the beginning of every year.
2018 Strategic Priorities
2018 Results
Commercial deployment of Process Automation Controls
and Directional Guidance Systems on a wide scale.
Enhance financial performance through higher utilization
and improved margins.
Reduce debt by generating free cash flow while continuing
to fund only the most attractive investment opportunities.
• Target $75 million to $125 million debt repayment in
• Target $300 million to $500 million debt repayment
2018.
by year-end 2021.
Added ten Process Automation Control (PAC) systems with a
total of 31 systems deployed in the field at year-end, a 50%
increase in installed base during 2018. Equipped both training
rigs in Nisku and Houston with PAC technology.
Drilled 365 wells in 2018 utilizing PAC technology and drilled
119 wells utilizing its directional guidance system, over half of
which were drilled without any directional drillers on location.
By year-end, Precision, its partners, customers and several
third parties had 15 drilling performance applications under
development with several Apps in field trials.
Completed ERP system upgrade to position the organization
to better handle increased data flows.
Consolidated utilization days increased 14% year-over-year.
U.S. Drilling margins up 25%, Canadian Drilling margins up 4%
and International Drilling margins remained stable.
Achieved highest market share on record for Precision in the
U.S. of over 7.5%.
Generated $311 million in funds provided by operations (Non-
GAAP measure – see page 3
information)
representing a 69% increase year-over-year.
for more
Precision’s 2018 debt repayments totaled $174 million, $49
million higher than the top end of Precision’s target 2018 debt
repayment range.
In conjunction with debt repayments, Precision grew its cash
balance by $32 million throughout the year.
Completed two new-build rigs in the U.S. market while
continuing rig upgrade program (not exceeding $3 million in
upgrade cost per rig). Precision also began construction of its
sixth new-build rig in Kuwait.
Capital expenditures totaled $126 million, $9 million less than
planned spending. Net capital expenditures totaled $102
million with $24 million of proceeds on sale of property, plant
and equipment.
23
Management’s Discussion and Analysis
Our Corporate and Competitive Strategies are designed to optimize resource allocation and differentiate us from the
competition, generating value for investors. Unconventional drilling is the primary opportunity in the North American
marketplace. Unconventional resource development requires the most efficient and technically capable drilling rigs and other
highly developed services that facilitate the drilling of reliable, predictable and repeatable horizontal wells. Customer adoption
of large-scale industrialization techniques and high efficiency rig systems continues to increase and Precision’s Super Series
rig fleet and High Performance, High Value strategy positions the Company to benefit from that trend. The completion and
production work associated with unconventional wells provides the most profitable growth opportunities for our Completion and
Production Services segment.
Strategic Priorities for 2019
• Generate strong free cash flow and utilize $100 million to $150 million to reduce debt in 2019; increased long-term debt
reduction targets to $400 million to $600 million by year-end 2021 (inclusive of 2018 debt repayments).
• Maximize financial results by leveraging our High Performance, High Value Super Series rig fleet and scale with disciplined
cost management.
Full scale commercialization and implementation of our Process Automation Control platform, PD Apps and PD Analytics.
•
Precision Drilling Corporation 2018 Annual Report
24
2018 Results
Management’s
Discussion
and
Analysis
Adjusted EBITDA and operating loss are Non-GAAP measures. See page 3 for more information.
Consolidated Statements of Loss Summary
Year ended December 31 (thousands of dollars)
Revenue
Contract Drilling Services
Completion and Production Services
Inter-segment elimination
Adjusted EBITDA(1)
Contract Drilling Services
Completion and Production Services
Corporate and Other
Depreciation and amortization
Impairment of goodwill
Impairment of property, plant and equipment
Gain on re-measurement of property, plant and equipment
Foreign exchange
Finance charges
Loss (gain) on redemption and repurchase of unsecured senior notes
Loss before income taxes
Income taxes
Net loss
(1) See Non-GAAP Measures on page 3 of this report.
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
2018
2017
2016
1,396,492
150,760
(6,063 )
1,541,189
412,134
14,881
(51,884 )
375,131
365,660
207,544
—
—
4,017
127,178
(5,672 )
(323,596 )
(29,326 )
(294,270 )
1,173,930
154,146
(6,852 )
1,321,224
342,970
11,888
(49,877 )
304,981
377,746
—
15,313
—
(2,970 )
137,928
9,021
(232,057 )
(100,021 )
(132,036 )
907,821
100,049
(4,637 )
1,003,233
296,651
(3,649 )
(64,927 )
228,075
391,659
—
—
(7,605 )
6,008
146,360
239
(308,586 )
(153,031 )
(155,555 )
2018
2017
2016
571,640
797,217
191,131
(18,799 )
1,541,189
1,269,542
1,772,850
593,651
3,636,043
578,817
568,573
190,401
(16,567 )
1,321,224
1,631,838
1,666,368
594,725
3,892,931
418,030
426,546
169,286
(10,629 )
1,003,233
1,738,853
1,861,908
723,453
4,324,214
25
Management’s Discussion and Analysis
2018 COMPARED WITH 2017
Net loss in 2018 was $294 million, or $1.00 per diluted share, compared with net loss of $132 million, or $0.45 per diluted share,
in 2017. The higher net loss in 2018 was primarily the result of a $208 million goodwill impairment charge offset by higher U.S.
activity and average day rates.
Revenue was $1,541 million (17% higher than 2017) because of higher U.S. activity and improved day rates.
Adjusted EBITDA in 2018 was $375 million (23% higher than 2017), mainly because of the increase in U.S. activity. Activity, as
measured by drilling utilization days, increased 30% in the U.S. while remaining relatively constant in Canada and internationally
compared with 2017.
Impairment
Under IFRS, we are required to assess the carrying value of assets in our CGUs containing goodwill annually and when
indicators of impairment exist. Due to the decrease in oil and natural gas well drilling in Canada and the outlook for activity in
Canada and in our directional drilling division in the U.S., we recognized a $208 million goodwill impairment charge. The
impairment charge represents the full amount of goodwill attributable to our Canadian contract drilling and U.S. directional drilling
operations.
Because of no activity in Mexico in 2017, we completed an impairment test for our Mexico contract drilling CGU as of December
31, 2017. As a result of this test it was determined that property, plant and equipment in our Mexico contract drilling business
was impaired by US$12 million.
Foreign Exchange
We recognized a foreign exchange loss of $4 million in 2018 (2017 – $3 million gain) due to the devaluation of the Canadian
dollar 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 $127 million, a decrease of $11 million compared with 2017 primarily due to a reduction in interest
expense related to debt retired in 2017 and mid-2018 partially offset by higher interest income earned in the comparative period.
Gain on Redemption and Repurchase of Unsecured Senior Notes
During the year we redeemed US$80 million and repurchased and cancelled US$3 million of our 6.5% unsecured senior notes
due 2021 and repurchased and cancelled US$49 million principal amount of our 5.25% unsecured senior notes due 2024
resulting in a net gain of $6 million. In comparison, during 2017, we redeemed and/or repurchased and cancelled US$442 million
of our previously outstanding senior notes incurring a loss of $9 million.
Income Taxes
Income taxes were a recovery of $29 million, $71 million lower than the $100 million recovery booked in 2017. The reduced
recovery in 2018 compared with 2017 was mainly due to a smaller loss prior to the non-taxable portion of the goodwill
impairment.
Precision Drilling Corporation 2018 Annual Report
26
2017 COMPARED WITH 2016
Net loss in 2017 was $132 million, or $0.45 per diluted share, compared with net loss of $156 million, or $0.53 per diluted share,
in 2016. The reduction of net loss in 2017 was primarily the result of improved activity levels compared to 2016.
Revenue was $1,321 million (32% higher than 2016) because of higher activity in all our operations.
Adjusted EBITDA in 2017 was $305 million (34% higher than 2016), mainly because activity levels were higher in all our
operations. Activity, as measured by drilling utilization days, increased 48% in Canada, 81% in the U.S., and 5% internationally
compared with 2016.
Impairment
Under IFRS, we are required to assess the carrying value of assets in our CGUs containing goodwill annually and when
indicators of impairment exist. Because of no activity in Mexico in 2017, we completed an impairment test for our Mexico contract
drilling CGU as of December 31, 2017. The test involves determining a value in use based on a multi-year discounted cash flow
using assumptions on expected future results. The resulting value in use is then compared to the carrying value of the CGU. As
a result of this test it was determined that property, plant and equipment in our Mexico contract drilling business was impaired
by US$12 million.
Foreign Exchange
We recognized a foreign exchange gain of $3 million in 2017 (2016 – $6 million loss) because the Canadian dollar strengthened
in value against the U.S. dollar and this affected the net U.S. dollar denominated monetary position in our Canadian dollar-based
companies.
Finance Charges
Finance charges were $138 million, a decrease of $8 million compared with 2016. The decrease is the result of a stronger
Canadian dollar on our U.S. dollar denominated interest expense and a reduction in interest expense related to debt retired
during the past two years.
Loss on Redemption and Repurchase of Unsecured Senior Notes
During 2017, we redeemed and/or repurchased and cancelled US$442 million of our previously outstanding senior notes
incurring a loss of $9 million. In 2016, we redeemed and/or repurchased and cancelled $200 million and US$360 million of our
previously outstanding Canadian and U.S. senior notes, respectively, incurring a slight loss.
Income Taxes
Income taxes were a recovery of $100 million, $53 million lower than the $153 million recovery booked in 2016 mainly due to a
smaller loss in 2017 compared with 2016 and from the fourth quarter tax reform implemented in the U.S. reducing tax rates
which reduced the benefit of our U.S. losses carried forward.
27
Management’s Discussion and Analysis
Segmented Results
CONTRACT DRILLING SERVICES
Financial Results
Adjusted EBITDA and operating loss are Non-GAAP measures. See page 3 for more information.
Year ended December 31
(thousands of dollars, except where noted)
Revenue
Expenses
Operating
General and administrative
Restructuring
Adjusted EBITDA (1)
Depreciation and amortization
Impairment of goodwill
Impairment of property, plant and equipment
Operating loss (1)
(1) See Non-GAAP measures on page 3 of this report.
2018
1,396,492
945,203
39,155
—
412,134
334,555
207,544
—
(129,965 )
2018 Compared with 2017
% of
revenue
2017
1,173,930
% of
revenue
2016
907,821
% of
revenue
67.7
2.8
—
29.5
24.0
14.9
—
(9.3 )
798,655
32,305
—
342,970
334,587
—
15,313
(6,930 )
68.0
2.8
—
29.2
28.5
—
1.3
(0.6 )
574,104
34,026
3,040
296,651
348,005
—
—
(51,354)
63.2
3.7
0.3
32.7
38.3
—
—
(5.7 )
Revenue from Contract Drilling Services was $1,396 million, 19% higher than 2017, mainly because of higher activity in our U.S.
contract drilling operations and higher average day rates in each of our contract drilling operations.
In 2018, total shortfall payments in Canada and idle but contracted revenue in the U.S. were $12 million and US$0.6 million,
compared with $31 million and US$6 million, respectively in 2017.
Operating expenses in 2018 were 68% of revenue and is consistent with the prior year. On a per utilization day basis, operating
costs for the drilling rig division in Canada were higher than the prior year period due to timing of equipment certifications and
equipment maintenance costs. In the U.S., operating costs on a per day basis were higher than the prior year period primarily
due to expenses recovered through the day rate and higher turnkey activity. General and administrative expenses for 2018 were
higher due to the devaluation of the Canadian dollar on our U.S. dollar denominated costs.
Our 2018 operating loss was $130 million as compared to an operating loss of $7 million in the comparable prior year period.
Operating loss in 2018 increased as a result of goodwill impairment charges of $208 million offset by an increase in drilling
activity in our U.S. drilling operations and improved day rates in each of our drilling operations. Our 2017 operating results
include an impairment of property, plant and equipment charge of $15 million related to certain drilling rigs and spare equipment.
Excluding the impairment of goodwill and property, plant and equipment impairment, operating earnings would have been
$78 million in 2018 and $8 million in 2017.
Our total depreciation expense was consistent year over year.
Capital expenditures in 2018 for our Contract Drilling segment were $108 million:
∎ $35 million – to expand our asset base
∎ $31 million – to upgrade existing equipment
∎ $42 million – on maintenance and infrastructure.
Precision Drilling Corporation 2018 Annual Report
28
Operating Statistics
Year ended December 31
Number of drilling rigs (year-end)
Drilling utilization days (operating and moving)
Canada
U.S.
International
Drilling revenue per utilization day
Canada (Cdn$)
U.S. (US$)
International (US$)
Drilling statistics (Canadian operations only)
Wells drilled
Average days per well
Metres drilled (hundreds)
Average metres per well
Canadian Drilling
%
increase/
(decrease)
(7.8)
(1.4)
30.4
-
2.4
10.1
0.5
(3.8)
2.1
2.1
6.2
2018
236
18,617
26,714
2,920
21,644
21,864
50,469
1,663
9.9
4,694
2,823
2017
256
18,883
20,479
2,920
21,143
19,861
50,240
1,729
9.7
4,597
2,659
% increase/
(decrease)
0.4
48.4
80.5
4.8
(13.7 )
(24.0 )
9.8
79.7
(17.1 )
80.4
0.4
2016
255
12,722
11,343
2,786
24,509
26,145
45,753
962
11.7
2,548
2,649
% increase/
(decrease)
1.6
(26.2)
(46.4)
(31.8)
(9.1)
(2.2)
5.2
(28.8)
2.6
(21.0)
11.0
Revenue from Canadian drilling was $403 million, 1% lower than 2017. Drilling rig activity, as measured by utilization days, was
down slightly by 1% while average day rates were up 2%.
Adjusted EBITDA was $124 million, 13% lower than 2017, because of lower drilling activity offset by higher average day rates.
Depreciation expense for the year was $112 million, in-line with 2017.
Drilling Statistics – Canada
In 2018, we transferred one drilling rig from Canada to the U.S. and identified 18 drilling rigs to be held for sale, bringing our
Canadian 2018 year-end net rig count to 117 (2017 –136).
The industry drilling rig fleet has decreased as there were approximately 592 rigs at the end of 2018 compared with 627 at the
end of 2017. Our operating day utilization was 34% (2017 – 34%), compared with industry utilization of 29% (2017 – 29%).
U.S. Drilling
Revenue from U.S. drilling was US$584 million, 43% higher than 2017. Drilling rig activity, as measured by utilization days, was
up 30% while average revenue per day was up 10%.
Adjusted EBITDA was US$180 million, 70% higher than 2017, mainly because of higher activity and average day rates offset
by lower idle but contracted revenue.
Depreciation expense for the year was US$120 million, US$1 million lower than 2017 because of a lower capital asset base.
Drilling Statistics – U.S.
In 2018, we completed two new-build rigs, transferred one rig from Canada and identified four drilling rigs to be held for sale,
leaving our U.S. year-end net rig count at 102. In 2018, we averaged 73 rigs working, an 30% increase from 56 rigs in 2017.
The industry drilling fleet increased as well, averaging 1,014 active land rigs in 2018, up 18% from 856 rigs in 2017.
Our average day rates in the U.S. increased 10% in 2018 as legacy contracts expired and newly contracted rigs were at higher
day rates. Revenue from idle but contracted rigs was US$0.6 million in 2018, a reduction of $6 million from the prior year period.
29
Management’s Discussion and Analysis
Turnkey utilization days increased 161% over 2017 and accounted for approximately 2% of our revenue compared with 2% in
2017.
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.
2018
2017
2016
Precision
Industry (1)
Precision
Industry (1) Precision
Industry (1)
64
72
76
80
73
951
1,021
1,032
1,050
1,014
47
59
61
58
56
722
874
927
902
856
32
24
29
39
31
516
397
465
567
486
COMPLETION AND PRODUCTION SERVICES
Financial Results
Adjusted EBITDA and operating loss are Non-GAAP measures. See page 3 for more information.
Year ended December 31
(thousands of dollars, except where noted)
Revenue
Expenses
Operating
General and administrative
Restructuring
Adjusted EBITDA (1)
Depreciation and amortization
Gain on re-measurement of property, plant and
equipment
Operating loss (1)
(1) See Non-GAAP Measures on page 3 of this report.
n/m – calculation not meaningful.
2018
150,760
128,731
7,148
—
14,881
23,879
% of
revenue
85.4
4.7
—
9.9
15.8
2017
154,146
134,368
7,890
—
11,888
29,638
% of
revenue
2016
100,049
% of
revenue
87.2
5.1
—
7.7
19.2
92,248
9,429
2,021
(3,649)
29,272
93.0
8.6
2.0
(3.6)
29.3
n/m
(25.3)
—
(8,998)
—
(6.0)
—
(17,750)
—
(11.5 )
(7,605)
(25,316)
Revenue from Completion and Production Services was $151 million in 2018, 2% lower than 2017, mainly because of lower
activity across all our product lines.
Operating loss was $9 million in 2018, compared with an operating loss of $18 million in 2017. The decrease in our operating
loss in 2018 was primarily due to higher average day rates and improved cost recoveries offset by lower service rig operating
hours.
Operating expenses were 85% of revenue, 2% points lower than 2017, mainly because of improved cost recoveries.
Depreciation in 2018 decreased by 19% as a higher proportion of the segment’s capital asset base became fully depreciated.
Capital expenditures in 2018 for our Completions and Production segment were $5 million, comprised mainly of maintenance
capital.
Revenue from Precision Well Servicing in Canada was $99 million, up $1 million from 2017 as average revenue rates increased
by 12% offset by a reduction in activity of 10% versus the prior year.
Revenue from our U.S. based completion and production businesses was US$10 million, 15% lower than 2017. The decrease
was the result of lower activity partially offset by higher average rates.
Revenue from Precision Rentals was $19 million, 17% lower than 2017. The decrease was due to lower activity and average
revenue rates.
Precision Drilling Corporation 2018 Annual Report
30
Revenue from Precision Camp Services was $15 million, 15% higher than 2017, because of an increase in camp activity, partially
offset by lower average revenue rates. Precision operated four base camps and 43 drill camps during 2018.
Operating Results
Year ended December 31
Number of service rigs (end of year)
Service rig operating hours
Revenue per operating hour
2018
210
157,467
709
% increase/
(decrease)
-
(8.9 )
11.3
2017
210
172,848
637
% increase/
(decrease)
1.4
73.8
(1.4 )
2016
207
99,451
646
% increase/
(decrease)
(27.0)
(33.5)
(17.6)
Our service operating hours fell by 9% in the current year while our revenue per operating hour increased by 11% over the
comparable prior year period. In December 2016, we acquired 48 well service rigs for consideration of $12 million and our coil
tubing assets and associated equipment.
CORPORATE AND OTHER
Financial Results
Adjusted EBITDA and operating loss are Non-GAAP measures. See page 3 for more information.
Year ended December 31
(thousands of dollars, except where noted)
Revenue
Expenses
Operating
General and administrative
Other recoveries
Restructuring
Adjusted EBITDA(1)
Depreciation and amortization
Operating loss(1)
(1) See Non-GAAP Measures on page 3 of this report.
2018
—
—
66,084
(14,200 )
—
(51,884 )
7,226
(59,110 )
2017
—
—
49,877
—
—
(49,877 )
13,521
(63,398 )
2016
—
—
64,234
—
693
(64,927 )
14,382
(79,309 )
Our Corporate and Other segment contains support functions that provide assistance to our business segments. It includes
costs incurred in corporate groups in both Canada and the U.S.
Corporate general and administrative expenses were $66 million in 2018, $16 million more than 2017. The increase is mainly
related to higher foreign exchange translation on our U.S. dollar based costs and higher share-based incentive compensation
expenses. In 2018, corporate general and administrative costs were 4.3% of consolidated revenue compared with 3.8% in 2017
and 6.4% in 2016.
During 2018 we terminated an arrangement agreement to acquire an oil and natural gas drilling contractor. Subsequent to the
termination a transaction fee was paid to us which, net of transaction costs, amounted to $14 million.
Capital expenditures in 2018 for our Corporate and Other segment were $13 million, primarily related to a new ERP system.
QUARTERLY FINANCIAL RESULTS
Adjusted EBITDA and funds provided by (used in) operations are Non-GAAP measures. See page 3 for more information.
2018 – Quarters Ended
(thousands of dollars, except per share amounts)
Revenue
Adjusted EBITDA(1)
Net loss
per basic and diluted share
Funds provided by operations(1)
Cash provided by operations
March 31
401,006
97,469
(18,077 )
(0.06 )
104,026
38,189
June 30
330,716
62,182
(47,217 )
(0.16 )
50,225
129,695
September 30 December 31
427,010
134,492
(198,328 )
(0.68 )
92,595
93,489
382,457
80,988
(30,648 )
(0.10 )
64,368
31,961
31
Management’s Discussion and Analysis
(1) See Non-GAAP measures on page 3 of this report.
2017 – Quarters Ended
(thousands of dollars, except per share amounts)
Revenue
Adjusted EBITDA(1)
Net loss
per basic and diluted share
Funds provided by (used in) operations(1)
Cash provided by operations
(1) See Non-GAAP measures on page 3 of this report.
Seasonality
March 31
368,673
84,308
(22,614 )
(0.08 )
85,659
33,770
June 30
290,860
56,520
(36,130 )
(0.12 )
(15,187 )
2,739
September 30
314,504
73,239
(26,287 )
(0.09 )
85,140
56,757
December 31
347,187
90,914
(47,005 )
(0.16 )
28,323
23,289
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. As a result
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 2018 Compared with Fourth Quarter 2017
In the fourth quarter of 2018, we recorded a net loss of $198 million, or net loss per diluted share of $0.68, compared with a net
loss of $47 million, or a net loss of $0.16 per diluted share, in the fourth quarter of 2017. During the quarter we incurred goodwill
impairment charges totaling $208 million that, after-tax, reduced net earnings by $199 million and net earnings per diluted share
by $0.68. Excluding the impact of the goodwill impairment net earnings would have been $1 million ($0.00 per share).
Revenue in the fourth quarter was $427 million or 23% higher than the fourth quarter of 2017, mainly due to increased activity
and day rates in our U.S. contract drilling business. Compared with the fourth quarter of 2017 our activity, as measured by drilling
rig utilization days, increased by 36% in the U.S., decreased 9% in Canada and remained consistent internationally. Revenue
from our Contract Drilling Services segment increased by 27% and Completion and Production Services segment decreased
10% over the comparative prior year period.
Adjusted EBITDA this quarter was $134 million, an increase of $44 million from the fourth quarter of 2017. Our Adjusted EBITDA
as a percentage of revenue was 31% this quarter, compared with 26% in the fourth quarter of 2017. Adjusted EBITDA as a
percent of revenue in the fourth quarter of 2018 was positively impacted by higher activity and day rates in the U.S., the receipt
of a transaction fee and lower share-based incentive compensation partially offset by lower activity in our Canada contract drilling
operations versus 2017.
As a percentage of revenue, operating costs were 67% in the fourth quarter of 2018 and was consistent with the same quarter
of 2017. 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 $392 million this quarter, or 27% higher than the fourth quarter of 2017, while
adjusted EBITDA increased by 22% to $122 million. The increase in revenue was primarily due to higher utilization days as well
as higher spot market rates in the U.S. During the quarter we recognized $1 million in shortfall payments in our Canadian contract
drilling business compared with $13 million in the prior year comparative period. In the U.S. we recognized turnkey revenue of
US$11 million compared with US$3 million in the comparative period and we recognized US$0.3 million in idle but contracted
rig revenue compared with US$1 million in the comparative quarter of 2017.
Drilling rig utilization days in Canada (drilling days plus move days) were 4,517 during the fourth quarter of 2018, a decrease of
9% compared to 2017 primarily due to decreased industry activity brought on by lower commodity prices and takeaway capacity
challenges in Canada. Drilling rig utilization days in the U.S. were 7,318, or 36% higher than the same quarter of 2017 as our
U.S. activity was up with higher industry activity. Drilling rig utilization days in our international business were 736, in-line with
the same quarter of 2017.
Compared with the same quarter in 2017, drilling rig revenue per utilization day in Canada decreased 3% as lower shortfall
revenue in the current quarter was partially offset by increases in spot market rates and higher expenses recovered through the
Precision Drilling Corporation 2018 Annual Report
32
day rate compared with the prior period. Drilling rig revenue per utilization day for the quarter in the U.S. was up 16% compared
to the prior year as we realized higher average day rates and turnkey revenue. International revenue per utilization day for the
quarter was up by 3% compared with the prior year comparative period due to fewer rig moves.
In Canada, 15% of our utilization days in the quarter were generated from rigs under term contract, compared with 13% in the
fourth quarter of 2017. In the U.S., 62% of utilization days were generated from rigs under term contract as compared with 55%
in the fourth quarter of 2017.
Operating costs were 66% of revenue for the quarter, one percentage point higher than the prior year period. On a per utilization
day basis, operating costs for the drilling rig division in Canada were higher than the prior year period due to timing of equipment
certifications and equipment maintenance costs and higher expenses recovered through the day rate. In the U.S., operating
costs for the quarter on a per day basis were higher than the prior year period primarily due to expenses recovered through the
day rate and higher turnkey activity.
Depreciation expense in the quarter was $13 million higher than the prior year comparative period due to the recognition of
accelerated depreciation on excess spare equipment.
Completion and Production Services
Revenue from Completion and Production Services was down $4 million or 10% compared with the fourth quarter of 2017 due
to lower activity in our Canadian businesses. Our service rig operating hours in the quarter were down 19% from the fourth
quarter of 2017 while rates increased an average of 17%. Approximately 81% of our fourth quarter Canadian service rig activity
was oil related.
During the quarter, Completion and Production Services generated 90% of its revenue from Canadian operations and 10% from
U.S. operations compared with the fourth quarter of 2017 where 92% of revenue was generated in Canada and 8% in the U.S.
Average service rig revenue per operating hour in the quarter was $753 or $109 higher than the fourth quarter of 2017. The
increase was primarily the result of increased costs passed through to the customer and rig mix.
Adjusted EBITDA was higher than the fourth quarter of 2017 primarily because of higher average rates and improved cost
structure, partially offset by lower activity.
Operating costs as a percentage of revenue was 78% compared with the prior year comparative quarter of 88%.
Depreciation expense in the quarter was $3 million lower than the prior year comparative period due to the recognition of gains
on disposal of capital assets in the current year compared with losses on disposal in the prior year.
Corporate and Other
Our Corporate and Other segment provides support functions to our operating segments. The Corporate and Other segment
had an adjusted EBITDA (see “NON-GAAP MEASURES”) of $5 million, a $17 million increase compared with the fourth quarter
of 2017 primarily due to lower share-based incentive compensation and the receipt of the transaction termination fee partially
offset by costs associated with our unsuccessful arrangement agreement.
Net financial charges for the quarter were $32 million, a decrease of $6 million compared with the fourth quarter of 2017 primarily
because of debt retired in 2017 and mid-2018 partially offset by a weaker Canadian dollar on our U.S. dollar denominated
interest expense.
During the quarter we redeemed US$30 million of our 6.5% unsecured senior notes due 2021 and repurchased and cancelled
US$44 million principal amount of our 5.25% unsecured senior notes due 2024 resulting in a net gain of $7 million.
Income tax expense for the quarter was a recovery of $2 million compared with a recovery of $17 million in the same quarter in
2017. The tax recovery in 2018 decreased primarily due to a smaller loss prior to the non-taxable portion of the goodwill
impairment compared with the prior year quarter.
Capital expenditures were $30 million in the fourth quarter compared with $25 million in the fourth quarter of 2017. Spending in
the fourth quarter of 2018 included:
∎ $11 million – to expand and upgrade our asset base
∎ $18 million – on maintenance and infrastructure
∎ $1 million – on intangibles.
33
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. We also 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
During the year we redeemed US$80 million and repurchased and cancelled US$3 million of our 6.5% unsecured senior notes
due 2021 and repurchased and cancelled US$49 million principal amount of our 5.25% unsecured senior notes due 2024. On
November 30, 2018 we agreed with our lenders to a one-year maturity extension of our Senior Credit Facility to November 2022.
In 2017, we issued US$400 million of 7.125% senior notes due in 2026 in a private offering, repurchased pursuant to an early
tender offer US$310 million of our 6.625% unsecured senior notes due 2020 and US$70 million of our 6.5% unsecured senior
notes due 2021 and redeemed our remaining outstanding 6.625% unsecured senior notes due 2020.
On November 21, 2017 we agreed with our lenders to the following amendments to our Senior Credit Facility:
∎ reduce the Covenant EBITDA (as defined in the debt agreement) (See Non-GAAP Measures on page 3 of this report) to
interest expense coverage ratio to greater than or equal to 2.0:1 for the periods ending June 30, September 30,
December 31, 2018 and March 31, 2019 reverting to 2.5:1 thereafter
∎ reduced the size of the facility to US$500 million
∎ amend certain negative covenants, to among other things, permit the redemption and repurchase of junior debt on a
permanent basis subject to a pro forma senior net leverage covenant test of less than or equal to 1.75:1
∎ add a new covenant that permits distributions post the covenant relief period subject to a pro forma senior net leverage
covenant of less than or equal to 1.75:1.
On January 20, 2017 we agreed with our lenders to the following amendments to our Senior Credit Facility:
∎ reduce the Covenant EBITDA (as defined in the debt agreement) to interest expense coverage ratio to greater than or
equal to 1.25:1 for the periods ending March 31, June 30 and September 30, 2017. For the periods ending December 31,
2017 and March 31, 2018 the ratio is 1.5:1 reverting to 2.5:1 thereafter
∎ reduce the size of the facility to US$525 million.
As of December 31, 2018, our liquidity was supported by a cash balance of $97 million, our Senior Credit Facility of
US$500 million, operating facilities totaling approximately $60 million, and a US$30 million secured facility for letters of credit.
Our ability to draw on our Senior Credit Facility is governed by financial covenants. See Capital Structure – Covenants on page
37.
We expect that cash provided by operations and our sources of financing, including our Senior Credit Facility, will be sufficient
to meet our debt obligations and to fund future capital expenditures.
Precision Drilling Corporation 2018 Annual Report
34
At December 31, 2018, excluding letters of credit, we had approximately
$1,729 million (2017 – $1,822 million) outstanding under our secured
and unsecured credit facilities and $23 million in unamortized debt issue
costs. Our Senior Credit Facility includes financial ratio covenants that
are tested quarterly.
Key Ratios
We ended 2018 with a long-term debt to long-term
debt plus equity ratio of 0.5, and a ratio of long-term
debt to cash provided by operations of 5.8.
We ended 2018 with a long-term debt to long-term debt plus equity ratio of 0.5 (2017 – 0.5) and a ratio of long-term debt to cash
provided by operations of 5.8 (2017 – 14.8).
The current blended cash interest cost of our debt is approximately 6.7%.
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.
Financial Position and Ratios
(in thousands of dollars, except ratios)
Working capital(1)
Working capital ratio
Long-term debt
Total long-term financial liabilities
Total assets
Enterprise value (see table on page 39)
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
(1) See Non-GAAP measures on page 3 of this report.
Credit Rating
December 31,
2018
240,539
1.9
1,706,253
1,723,350
3,636,043
2,305,890
0.5
5.8
4.5
0.7
December 31,
2017
232,121
2.1
1,730,437
1,754,059
3,892,931
2,782,596
0.5
14.8
5.7
0.6
December 31,
2016
230,874
2.0
1,906,934
1,946,742
4,324,214
3,937,737
0.5
15.6
8.4
0.5
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.
At March 1, 2019
Corporate credit rating
Senior Credit Facility rating
Senior unsecured credit rating
CAPITAL MANAGEMENT
Moody’s
B2
Not rated
B3
S&P
BB-
Not rated
BB-
Fitch
B+
BB+
BB-
To maintain and grow our business, we invest in growth, upgrade and sustaining capital. We base expansion and upgrade
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.
35
Management’s Discussion and Analysis
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 Foreign 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.
During 2018, we designated all of our U.S. dollar senior notes as a net investment hedge in our U.S. dollar denominated foreign
operations.
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 used in financing
Effect of exchange rate changes on cash
Net cash provided (used)
Cash from Operations
2018
293,334
(100,794 )
192,540
(169,085 )
8,090
31,545
2017
116,555
(91,150 )
25,405
(73,784 )
(2,245 )
(50,624 )
2016
122,508
(213,925 )
(91,417 )
(218,324 )
(19,313 )
(329,054 )
In 2018, we generated cash from operations of $293 million compared with $117 million in 2017. The increase is primarily the
result of lower interest payments on our long-term debt and higher cash tax recoveries.
Investing Activity
We made growth and sustaining capital investments of $126 million in 2018:
∎ $66 million on upgrade and expansion capital
∎ $48 million on maintenance and infrastructure capital
∎ $12 million on intangibles.
The $126 million in capital expenditures in 2018 was split between segments as follows:
∎ $108 million in Contract Drilling Services
∎ $5 million in Completion and Production Services
∎ $13 million in Corporate and Other.
Expansion and upgrade capital includes the cost of long-lead items purchased for our capital inventory, such as integrated 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 $24 million in 2018 compared with $15 million in 2017.
Financing Activity
As discussed on page 34, during the year, we redeemed US$80 million and repurchased and cancelled US$3 million of our
6.5% unsecured senior notes due 2021, repurchased and cancelled US$49 million principal amount of our 5.25% unsecured
senior notes due 2024 and extended the maturity date of our Senior Credit Facility to November 21, 2022.
Precision Drilling Corporation 2018 Annual Report
36
During 2017, we issued US$400 million of senior notes, redeemed US$62 million of senior notes and repurchased and cancelled
US$380 million of senior notes.
As of December 31, 2018, our operating facility of $40 million with Royal Bank of Canada was undrawn except for $28 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$30 million with HSBC Canada had US$28 million available.
CAPITAL STRUCTURE
Debt
As of December 31, 2018, we had a cash balance of $97 million, available capacity under our secured facilities of $715 million
and $1,729 million outstanding under our senior unsecured notes.
Amount
Senior facility (secured)
US$500 million (extendible, revolving term
credit facility with US$250 million(1) accordion
feature)
Operating facilities (secured)
$40 million
US$15 million
Demand letter of credit facility (secured)
US$30 million
Senior notes (unsecured)
US$166 million – 6.5%
US$350 million – 7.75%
US$351 million – 5.25%
Availability
Used for
Maturity
Undrawn, except US$28 million in
outstanding letters of credit
General corporate purposes
November 21, 2022
Undrawn, except $28 million in
outstanding letters of credit
Undrawn
Letters of credit and general
corporate purposes
Short term working capital
requirements
Undrawn, except US$2 million in
outstanding letters of credit
Letters of credit
Fully drawn
Fully drawn
Fully drawn
Fully drawn
Capital expenditures and general
corporate purposes
Debt redemption and repurchases
Capital expenditures and general
corporate purposes
Debt redemption and repurchases
December 15, 2021
December 15, 2023
November 15, 2024
January 15, 2026
US$400 million – 7.125%
(1)
Increases to US$300 million at the end of the covenant relief period of March 31, 2019.
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 (Covenant EBITDA)
of less than or equal to 2.5:1. For purposes of calculating the leverage ratio, consolidated senior debt only includes secured
indebtedness. Covenant EBITDA as defined in our Senior Credit Facility agreement differs from Adjusted EBITDA as defined
under Non-GAAP Measures by the exclusion of bad debt expense and certain foreign exchange amounts. As of December 31,
2018, our consolidated senior debt to Covenant EBITDA ratio was negative 0.16:1.
Under the Senior Credit Facility, we are required to maintain a Covenant EBITDA coverage ratio, calculated as Covenant
EBITDA to interest expense for the most recent four consecutive fiscal quarters, of greater than or equal to 1.5:1, which, after
the November 2017 amendment increased to 2.0:1 for the periods June 30, September 30, December 31, 2018 and March 31,
2019 and reverts to 2.5:1 for periods ending after March 31, 2019 until the maturity date of the facility. As of December 31, 2018,
our Covenant EBITDA coverage ratio was 3.31:1.
The Senior Credit Facility prevents us from making distributions prior to April 1, 2019, after which, distributions are subject to a
pro forma senior net leverage covenant of less than or equal to 1.75:1. The Senior Credit Facility also limits the redemption and
repurchase of junior debt subject to a pro forma senior net leverage covenant test of less than or equal to 1.75:1.
37
Management’s Discussion and Analysis
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, 2018, we were in compliance with the covenants of the Senior Credit Facility.
Senior Notes
The senior notes require that we comply with certain covenants including an incurrence based consolidated interest coverage
ratio test, as defined in the senior note agreements, of greater than or equal to 2.0:1 for the most recent four consecutive fiscal
quarters. In the event that our consolidated interest coverage ratio is less than 2.0:1 for the most recent four consecutive fiscal
quarters the senior notes restrict our ability to incur additional indebtedness, except as permitted under the agreements, until
such time as we are in compliance with the ratio test but would not restrict our access to available funds under the Senior Credit
Facility or refinance our existing debt. Furthermore, it does not give rise to any cross-covenant violations, give the lenders the
right to demand repayment of any outstanding portion of the senior notes prior to the stated maturity dates, or provide any other
forms of recourse to the lenders. As of December 31, 2018, our senior notes consolidated interest coverage ratio was 2.8:1.
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. The restricted payments basket grows from a starting point of October 1, 2010
for the 2021 and 2024 Senior Notes, from October 1, 2016 for the 2023 Senior Note and October 1, 2017 for the 2026 Senior
Note by, among other things, 50% of cumulative consolidated net earnings, and decreases by 100% of cumulative consolidated
net losses as defined in the note agreements, and cumulative payments made to shareholders. Based on our consolidated
financial results for the period ended December 31, 2015, the governing net restricted payments basket under the senior notes
was negative $152 million prohibiting us from making any further dividend payments for dividends declared on or after
December 31, 2015 until the restricted payments baskets become positive. As a result, Precision suspended our dividend on
February 11, 2016.
Based on our consolidated financial results for the period ended December 31, 2018, the governing net restricted payments
basket was negative $496 million.
For further information, please see the senior note indentures which are available on SEDAR and EDGAR.
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 shares; 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.
Shelf Registration
In August 2016, we completed the filing of a short form base shelf prospectus with the securities regulatory authorities in each
of the provinces of Canada and a corresponding registration statement in the U.S., for the offering of up to $1 billion of common
shares, preferred shares, debt securities, warrants, subscription receipts or units (the Securities). The Securities may be offered
from time to time during the 25-month period for which the short form base shelf prospectus remains valid. During 2018, the
shelf registration period lapsed and was not renewed.
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).
Precision Drilling Corporation 2018 Annual Report
38
The table below shows the amounts of these obligations and when payments are due for each.
At December 31, 2018
(thousands of dollars)
Long-term debt(1)
Interest on long-term debt(1)
Purchase of property, plant and equipment(1)(2)
Operating leases(1)
Contractual incentive plans(1)(3)
Total
Payments due (by period)
Less than
1 year
—
115,802
88,046
13,496
6,221
223,565
1-3 years
226,113
230,992
91,797
20,418
10,439
579,760
4-5 years
477,823
200,667
—
16,221
—
694,711
More than
5 years
1,025,415
101,457
—
17,797
—
1,144,669
Total
1,729,351
648,918
179,843
67,932
16,660
2,642,705
(1) U.S. dollar denominated balances are translated at the period end exchange rate of Cdn$1.00 equals US$0.7325.
(2) The balance relates primarily to the costs of rig equipment with a flexible delivery schedule wherein we can take delivery of the equipment
between 2019 and 2021 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 $2.36 at December 31, 2018.
Shareholders Capital
Shares outstanding
Deferred shares outstanding
Share options outstanding
March 1,
2019
293,781,836
93,173
10,441,601
December 31,
2018
293,781,836
93,173
10,799,006
December 31,
2017
293,238,858
195,743
10,458,981
December 31,
2016
293,238,858
195,743
11,525,742
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, we introduced a quarterly dividend program. The dividend program was suspended in the first
quarter of 2016. See Covenants – Senior Notes on page 38 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 cash
Enterprise value
December 31,
2018
293,781,836
2.37
696,263
1,706,253
(96,626 )
2,305,890
December 31,
2017
293,238,858
3.81
1,117,240
1,730,437
(65,081 )
2,782,596
December 31,
2016
293,238,858
7.32
2,146,508
1,906,934
(115,705 )
3,937,737
39
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.
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.
Precision Drilling Corporation 2018 Annual Report
40
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.
AMENDMENTS TO ACCOUNTING STANDARDS ADOPTED JANUARY 1, 2018
We applied the following mandatorily effective amendments to IFRSs in the current year. Outside of additional disclosure
requirements, these amendments had no impact on the amounts recorded in our financial statements.
IFRS 9, Financial Instruments
IFRS 9 replaced IAS 39 Financial Instruments, Recognition and Measurement. IFRS 9 contains three principal classification
categories for financial assets: measured at amortized cost, fair value through other comprehensive income and fair value
through profit or loss. The classification of financial assets under IFRS 9 is generally based on the business model in which a
financial asset is managed and the characteristics of its contractual cash flows. IFRS 9 eliminates the previous IAS 39 categories
of held to maturity, loans and receivables and available for sale. Under IFRS 9, derivatives embedded in contracts where the
host is a financial asset under the standard are never separated. Instead the hybrid financial instrument as a whole is assessed
for classification.
Under the new standard, Precision’s accounts receivable, accounts payable and accrued liabilities and long-term debt have
been classified and measured at amortized cost.
IFRS 9 replaced the incurred loss model of IAS 39 with an expected credit loss model. The loss allowance to be recorded against
trade receivables is measured as the lifetime expected credit losses. Due to low historical default rates, there was no material
adjustment to the credit loss allowance.
IFRS 15, Revenue from Contracts with Customers
IFRS 15 established a single comprehensive model 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. It replaced existing revenue recognition
guidance including IAS 18 Revenue and IAS 11 Construction Contracts.
The standard provides a principle 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 performance obligations.
During its initial application of IFRS 15, the Corporation did not apply any of the available practical expedients. The application
of IFRS 15 did not result in a material impact to the Corporation’s consolidated financial statements. For additional information
about the Corporation’s accounting policies with respect to revenue recognition, see Note 3(j) in our Consolidated Financial
Statements.
ACCOUNTING STANDARDS, INTERPRETATIONS AND AMENDMENTS TO EXISTING STANDARDS NOT YET
EFFECTIVE
IFRS 16, Leases
On January 1, 2019, Precision will adopt IFRS 16 - Leases. This standard introduces a single, on-balance sheet lease accounting
model for lessees and requires a lessee to recognize a right-of-use asset representing its right to direct the use of the underlying
asset as well as a lease liability representing its obligation to make future lease payments. IFRS 16 will also cause expenses to
be higher at the beginning and lower towards the end of a lease, even when payments are consistent throughout the term. The
standard includes recognition exemptions for short-term leases and leases of low-value items. Lessor accounting remains similar
to the current standard in which lessors continue to classify leases as either finance or operating leases.
41
Management’s Discussion and Analysis
IFRS 16 will replace existing lease guidance, including IAS 17 Leases, IFRIC 4 Determining whether an Arrangement contains
a Lease, SIC-15 Operating Leases – Incentives and SIC-27 Evaluating the Substance of Transactions Involving the Legal Form
of a Lease.
Precision has completed its review of the existing contracts that are currently classified as leases under the existing standard,
or that could be classified as leases under IFRS 16, in order to identify the contracts that will be impacted by the new standard
from the perspective of both a lessor and a lessee. Management has also estimated the impact that the initial application of
IFRS 16 will have on its consolidated financial statements, as described below. The actual impact of adopting the standard on
January 1, 2019 may differ from what is described below as Precision’s accounting policies, including the election to apply
certain practical expedients, are subject to change until presented in its first published financial statements after the date of initial
application.
Leases in which Precision is a lessee
Precision will recognize right-of-use assets and lease liabilities for its real estate, vehicle, office equipment and other contracts
that are currently classified as operating leases. The nature of expenses related to those leases will change as Precision will
depreciate the right-of-use assets and recognize interest expense on its lease liabilities. Under the existing standard, Precision
recognizes operating lease expenses on a straight-line basis over the term of the lease in either operating or general and
administrative expense and recognizes assets and liabilities only to the extent there was a timing difference between the
payment date and the recognition of the expense.
Based on the information currently available, Precision estimates that it will recognize lease liabilities and corresponding right-
of-use assets of approximately $60 million - $70 million on January 1, 2019 related to contracts where it is the lessee. Precision
does not expect a material adjustment to the opening balance of retained earnings on January 1, 2019 upon the initial application
of IFRS 16. The actual impact of adopting the standard on January 1, 2019 may differ from these estimates as the Corporation
continues to review its calculations and may refine certain inputs therein, such as the discount rate and lease term.
Leases in which Precision is a lessor
Precision evaluated its drilling rigs under term contracts longer than one year and determined that these meet the definition of a
lease under IFRS 16. Precision expects to classify these as operating leases, and accordingly, will recognize lease income over
the term of the respective drilling contract. This is not expected to give rise to differences in the recognition or measurement of
revenues from these contracts as compared to Precision’s existing accounting policies.
Precision reassessed the classification of its real estate sub-leases in which it is a lessor. These are classified as an operating
lease under the existing lease standard and management does not expect to reclassify these as finance leases.
Transition
There are two methods by which the new standard may be adopted: (1) a full retrospective approach with a restatement of all
prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment recognized in opening
retained earnings as of the date of adoption, with no restatement of comparative information. Precision will apply IFRS 16 initially
on January 1, 2019, using the modified retrospective approach.
When applying a modified retrospective approach to leases previously classified as operating leases under IAS 17, the lessee
can elect, on a lease-by-lease basis, whether to apply a number of practical expedients on transition. On initial adoption of the
new standard, the Corporation intends to use the following practical expedients, where applicable:
∎ not applying the requirements of the standard to short-term leases
∎ treat existing operating leases with a remaining term of less than 12 months at January 1, 2019 as short-term leases
∎ not applying the requirements of the standard to low-value leases, and
∎ applying a single discount rate to a portfolio of leases with reasonably similar characteristics.
As a result of the adoption of the new standard, Precision will be required to include significant disclosures in the consolidated
financial statements based on the prescribed requirements. These new disclosures will include information regarding the
judgments used in determining discount rates and terms of leases including optional renewal periods. The Corporation will
include the required disclosures in its 2019 first quarter condensed consolidated interim financial statements.
IFRIC 23, Uncertainty over Income Tax Treatments
IFRIC 23 clarifies the accounting for uncertainties in income taxes. The interpretation requires the entity to use the most likely
amount or the expected value of the tax treatment if it concludes that it is not probable that a particular tax treatment will be
accepted. It requires an entity to assume that a taxation authority with the right to examine any amounts reported to it will
examine those amounts and will have full knowledge of all relevant information when doing so.
Precision Drilling Corporation 2018 Annual Report
42
IFRIC 23 is effective for annual reporting periods beginning on or after January 1, 2019. The requirements are applied by
recognizing the cumulative effect of initially applying them in retained earnings, or in other appropriate components of equity, at
the start of the reporting period in which an entity first applies them, without adjusting comparative information. Full retrospective
application is permitted, if an entity can do so without using hindsight.
Precision has reviewed its initial application of IFRIC 23 and determined it will not have a material impact on the consolidated
financial statements. The actual impact of adopting the standard on January 1, 2019 may differ as Precision’s accounting policies
are subject to change until presented in its first published financial statements after the date of initial application.
43
Management’s Discussion and Analysis
Risks in Our Business
Management’s
Discussion
and
Analysis
Our key business risks are summarized below. Additional information and other risks in our business are discussed in our AIF,
available on our website (www.precisiondrilling.com).
Our enterprise risk management framework operates at the business and functional levels and is designed to identify, evaluate,
and mitigate risks within each of the risk categories below. It leverages the risk framework in each of our businesses, which
includes our risk policies, guidelines and review mechanisms.
Our businesses routinely encounter and manage risks, some of which may cause our future results to be different, sometimes
materially different, than what we presently anticipate. We describe certain important strategic, operational, financial, and legal
and compliance risks. Our response to development in those risk areas and our reactions to material future developments will
affect our future results.
Our operations depend on the price of oil and natural gas, which have been subject to increased volatility in recent
years, and the exploration and development activities of oil and natural gas exploration companies
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 relatively low, as is currently the case. The volatility of crude oil and natural gas
prices accounts for much of the cyclical nature of the oilfield services business and in recent years, increased volatility has led
to greater uncertainty in the demand for our services.
The markets for oil and natural gas are separate and distinct. Oil is a global commodity with a vast distribution network, although
the differential between benchmarks such as West Texas Intermediate, Western Canadian Select, and European Brent crude
oil can fluctuate. As in all markets, when supply, demand, inability to access domestic or export markets and other factors
change, so can the spreads between benchmarks. The most economical way to transport natural gas is in its gaseous state by
pipeline, and the natural gas market depends on pipeline infrastructure and regional supply and demand. However,
developments in the transportation of liquefied natural gas in ocean going tanker ships have introduced an element of
globalization to the natural gas market.
Worldwide military, political and economic events, such as conflict in the Middle East, expectations for global economic growth,
trade disputes, or initiatives by OPEC and other major petroleum exporting countries, can affect supply and demand for oil and
natural gas. Weather conditions, governmental regulation (in Canada and elsewhere), levels of consumer demand, the
availability and pricing of alternate sources of energy (including renewal energy initiatives), the availability of pipeline capacity
and other transportation for oil and natural gas, U.S. and Canadian oil and 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.
The North American land drilling industry has been in a downturn relative to activity levels experienced prior to 2015, a result of
lower commodity prices restricting customer spending and decreasing drilling demand. In 2018, approximately 19,300 wells
were started onshore in the U.S., compared to approximately 43,700 in 2014. In 2018, the industry drilled 6,781 wells in western
Canada, compared to 10,942 in 2014. According to industry sources, the U.S. average active land drilling rig count was up
approximately 18% in 2018, compared to 2017, and the Canadian average active land drilling rig count was down approximately
7% during the same period. However, oil and natural gas prices remained volatile throughout 2018 and could continue at these
relatively low levels or lower levels for the foreseeable future. Prices have been negatively affected since late 2014 by a
combination of factors, including increased production, the decisions of OPEC and Russia and a strengthening in the U.S. dollar
relative to most other currencies. These factors have adversely affected, and could continue to adversely affect, the price of oil
and natural gas, which would adversely affect the level of capital spending by our customers and in turn could have a material
and adverse effect on our results of operations.
As a result of the continued pressure on commodity prices, many of our customers have reduced spending budgets compared
to periods prior to the downturn, and further reductions in commodity prices or prices remaining at current levels for a prolonged
period may result in further reductions in capital budgets in the future, which could result in cancelled, delayed or reduced drilling
programs by our customers and a corresponding decline in demand for our services. Moreover, the prolonged reduction in oil
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and natural gas prices has depressed, and may continue to depress, and the availability and pricing of alternative sources of
energy and technological advances may depress, the overall level of exploration and production activity, resulting in
corresponding decline in the demand for our services. In late 2018 and into 2019, as a result of oil and natural gas price volatility
and regulatory uncertainty, some of our Canadian customers have delayed announcing their 2019 capital budgets, which has
created some uncertainty in the level of demand for our services in Canada.
If a reduction in exploration and development activities, whether resulting from changes in oil and natural gas prices and
reductions in capital budgets described above or otherwise, continues or worsens, it could materially and adversely affect us
further by:
negatively impacting our revenue, cash flow, profitability and financial condition
restricting our ability to make capital expenditures compared to periods prior to the downturn and our ability to meet
future contracted deliveries of new-build rigs
affecting the existing fair market value of our rig fleet, which in turn could trigger a write-down for accounting purposes
our customers negotiating, terminating, or failing to honour their drilling contracts with us
making our Senior Credit Facility financial covenants more difficult to attain, and
negatively impacting our ability to maintain or increase our borrowing capacity, our ability to obtain additional capital to
finance our business and our ability to achieve our debt reduction targets.
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.
Additionally, 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.
Pipeline constraints in western Canada have an adverse effect on the demand for our services in Canada
In western Canada, delays and/or the inability to obtain necessary regulatory approvals for pipeline projects that would provide
additional transportation capacity and access to refinery capacity for our customers has led to downward price pressure on oil
and natural gas produced in western Canada, which has depressed, and may continue to depress, the overall exploration and
production activity of our customers. Additionally, this regulatory uncertainty in Canada has impacted some of our customers’
ability to obtain financing, which has also depressed overall exploration and production activity. These factors result in a
corresponding decline in the demand for our services that could have a material adverse effect on our revenue, cash flow, and
profitability.
In December 2018, the Province of Alberta introduced mandatory curtailment on heavy oil production within the Province of
Alberta, which has resulted in reduced differentials between WTI pricing and Western Canada Select Pricing; however, with a
limited line of sight to new pipeline additions, customer spending in Canada is expected to be down significantly in the first half
of the year with the potential for increased activity later in the year.
Intense price competition and the cyclical nature of the contract drilling industry could have an adverse effect on
revenue and profitability
The contract drilling business is highly competitive with many 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 day rates, followed by
periods of high demand, short rig supply and increasing day rates. Periods of excess drilling rig supply intensify the competition
and often result in rigs being idle. There are numerous contract drilling companies in 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 suitable drilling rigs in 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.
45
Management’s Discussion and Analysis
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 in the contract drilling industry expose us to the risk of oversupply of equipment
Periods of high demand often lead to higher capital expenditures on drilling rigs and other oilfield services equipment. The
number of newer drilling rigs competing for work in markets where we operate has increased as the industry has added 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
intensified price competition in the past and could continue to do so. This could lead to lower day rates in the oilfield services
industry generally and lower utilization of existing rigs. If any of these factors materialize, it would have an adverse effect on our
revenue, cash flow, earnings and asset valuation.
We require sufficient cash flows to service and repay our debt
We will need sufficient cash flows in the future to service and repay our debt. Our ability to generate cash in the future is affected
to some extent by general economic, financial, competitive and other factors that may be beyond our control. If we need to
borrow funds in the future to service our debt, our ability will depend on covenants in the Senior Credit Facility, the 2021 Note
Indenture, the 2023 Note Indenture, the 2024 Note Indenture, the 2026 Note indenture 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 or issue equity. 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.
Repaying our debt depends on our guarantor subsidiaries generating cash flow and making it available to us by dividend, debt
repayment or otherwise. Our guarantor subsidiaries may not be able to, or may not be permitted to, make distributions to allow
us to make payments on our debt. Each guarantor subsidiary is a distinct legal entity, and, under certain circumstances, legal
and contractual restrictions may limit our ability to obtain cash from the subsidiaries. While the agreements governing certain
existing debt limits the ability of our subsidiaries to incur consensual restrictions on their ability to pay dividends or make other
intercompany payments to us, these limitations are subject to qualifications and exceptions.
A substantial portion of our operations is carried out through subsidiaries, and some of them are not guarantors of our debt. The
assets of the non-guarantor subsidiaries represent approximately 15% of Precision’s consolidated assets. These subsidiaries
do not have any obligation to pay amounts due on the debt or to make funds available for that purpose.
If we do not receive dividends from our guarantor subsidiaries, we may be unable to make the required principal and interest
payments, which could have a material adverse effect on our financial position and results of operations.
Customers’ inability to obtain credit/financing could lead to lower demand for our services
Many of our customers require reasonable access to credit facilities and debt capital markets to finance their oil and natural gas
drilling activity. If the availability of credit to our customers is reduced, they may reduce their drilling and production expenditures,
thereby decreasing demand for our products and services. In Canada, the Supreme Court of Canada’s 2019 Redwater decision
(Orphan Well Association v. Grant Thornton Ltd., which held that abandonment and reclamation obligations of a bankrupt debtor
were binding on the debtor’s trustee) may increase the cost of capital for our Canadian customers and could impact the
availability for credit for those customers while secured lenders assess the impact of the decision. A reduction in spending by
our customers could adversely affect our operating results and financial condition as described further under – “Our operations
depend on the price of oil and natural gas, which have been subject to increase volatility in recent years, and the exploration
and development activities of oil and natural gas exploration companies” on page 44.
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Our debt facilities contain restrictive covenants
The Senior Credit Facility, the 2021 Note Indenture, the 2023 Note Indenture, the 2024 Note Indenture and the 2026 Note
indenture contain a number of covenants which, among other things, restrict us and some of our subsidiaries from conducting
certain activities (see Capital Structure – Covenants – Senior Notes on page 38). In the event Consolidated Interest Coverage
Ratio (as defined in our four senior note indentures) is less than 2.0:1 for the most recent four consecutive fiscal quarters, the
senior note indentures restrict our ability to incur additional indebtedness. As at December 31, 2018, our Consolidated Interest
Coverage Ratio, as calculated per our senior note indentures, was 2.8:1.
In addition, we must satisfy and maintain certain financial ratio tests under the Senior Credit Facility (see Capital
Structure – Senior Credit Facility on page 37). Events beyond our control could affect our ability to meet these tests in the future.
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 under our Senior Credit Facility, the applicable lenders 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. If there is an acceleration by the lenders and the accelerated amounts exceed a specific threshold, the
applicable noteholders could decide to declare all amounts outstanding under any of the note indentures to be due and payable
immediately.
At December 31, 2018, we were in compliance with the covenants of the Senior Credit Facility.
Uncertainty in Trade Relations
Ratification of the United States-Mexico-Canada Agreement (USMCA) deal to replace the North American Free Trade
Agreement (NAFTA) may be delayed or prevented in the U.S. House of Representatives following the U.S. mid-term elections.
Changes that could have had an impact on the oil and natural gas industry were not included in the USMCA; however, as the
final terms and ratification of the USMCA remain uncertain, it is currently unclear how this agreement may affect the U.S., Mexico
and Canada and what effects the final terms will have on our operations. In addition, implementation by the U.S. of new legislative
or regulatory regimes or tariffs could impose additional costs on us, decrease U.S., Mexico or Canadian demand for our services
or otherwise negatively impact us or our customers, which may have a material adverse effect on our business, financial
condition and operations.
Risks and uncertainties associated with our international operations can negatively affect our business
We conduct some of our business in 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,
but not limited to, the following:
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 companies
compliance with anti-corruption and anti-bribery legislation in Canada, the U.S. and other countries, and
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.
47
Management’s Discussion and Analysis
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.
Our and our customer’s operations are subject to numerous environmental laws, regulations and guidelines
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 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.
Major projects which would benefit our customers, such as new pipelines and other facilities, may be inhibited, delayed or
stopped by a variety of factors, including inability to obtain regulatory or governmental approvals or public opposition.
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, financial condition, results of
operations and future prospects.
Environment regulations could have a significant impact on the energy industry
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,
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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. 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.
Poor safety performance could 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 services 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.
We are subject to various health and safety laws, rules, legislation and guidelines which can impose material liability, increase
our costs or lead to lower demand for our services.
Relying on third-party suppliers has risks
We source certain key rig components, raw materials, equipment and component parts from a variety of suppliers in Canada,
the U.S. and internationally. We also outsource some or all construction services for drilling and service rigs, including new-build
rigs, as part of our capital expenditure programs. 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.
Acquisitions entail numerous risks and may disrupt our business or distract management
We consider and evaluate acquisitions of, or significant investments in, complementary businesses and assets as part of our
business strategy. Acquisitions involve numerous risks, including unanticipated costs and liabilities, difficulty in integrating the
operations and assets of the acquired business, the ability to properly access and maintain an effective internal control
environment over an acquired company to comply with public reporting requirements, potential loss of key employees and
customers of the acquired companies, and an increase in our expenses and working capital requirements. Any acquisition could
have a material adverse effect on our operating results, financial condition or the price of our securities.
We may incur substantial debt to finance future acquisitions and also may issue equity securities or convertible securities for
acquisitions. Debt service requirements could be a burden on our results of operations and financial condition. We would also
be required to meet certain conditions to borrow money to fund future acquisitions. Acquisitions could also divert the attention
of management and other employees from our day-to-day operations and the development of new business opportunities. Even
if we are successful in integrating future acquisitions into our operations, we may not derive the benefits such as operational or
administrative synergies we expect from acquisitions, which may result in us committing capital resources and not receiving the
expected returns. In addition, we may not be able to continue to identify attractive acquisition opportunities or successfully
acquire identified targets.
New technology could reduce demand for certain rigs or put us at a competitive disadvantage
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
49
Management’s Discussion and Analysis
and technology advances, or that our competitors will not develop technological improvements that are more advantageous,
timely, or cost effective.
Our operations face risks of interruption and casualty losses
Our operations face many hazards inherent in the drilling and well servicing industries, including blowouts, cratering, explosions,
fires, loss of well control, loss of hole, reservoir damage, loss of directional control, damaged or lost equipment, and damage or
loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or
destruction of equipment and facilities, suspension of operations, environmental damage, damage to the property of others, and
damage to producing or potentially productive oil and natural gas formations that we drill through.
Generally, drilling and service rig contracts separate the responsibilities of a drilling or service rig company and the customer,
and we try to obtain indemnification from our customers by contract for some of these risks even though we also have insurance
coverage to protect us. We cannot assure, however, that any insurance or indemnification agreements will adequately protect
us against liability from all the consequences described above. If there is an event that is not fully insured or indemnified against,
or a customer or insurer does not meet its indemnification or insurance obligations, it could result in substantial losses. In
addition, we may not be able to get insurance to cover any or all these risks, or the coverage may not be adequate. Insurance
premiums or other costs may rise significantly in the future, making the insurance prohibitively expensive or uneconomic.
Significant events, including terrorist attacks in the U.S., severe hurricane damage and well blowout damage in the U.S. Gulf
Coast region, have resulted in significantly higher insurance costs, deductibles and coverage restrictions. When we renew our
insurance, we may decide to self-insure at higher levels and assume increased risk in order to reduce costs associated with
higher insurance premiums.
Business in our industry is seasonal and highly variable
Seasonal weather patterns in Canada and the northern U.S. affect activity in the oilfield services industry. During the spring
months, wet weather and the spring thaw make the ground unstable, so municipalities and counties and provincial and state
transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment. This reduces activity
and highlights the importance of the location of our equipment prior to the imposition of the road bans. The timing and length of
road bans depend on weather conditions leading to the spring thaw and during the thawing period.
Additionally, certain oil and natural gas producing areas are located in parts of western Canada that are only accessible during
the winter months because the ground surrounding or containing the drilling sites in these areas consists of terrain known as
muskeg. Rigs and other necessary equipment cannot cross this terrain to reach the drilling site until the muskeg freezes.
Moreover, once the rigs and other equipment have been moved to a drilling site, they may become stranded or be unable to
move to another site if the muskeg thaws unexpectedly. Our business activity depends, at least in part, on the severity and
duration of the winter season.
Global climate change could impact the timing and length of the spring thaw and the period in which the muskeg freezes and
thaws and it could impact the severity of winter, which could adversely affect our business and operating results. Furthermore,
extreme climate conditions that could result in natural disasters such as flooding or forest fires, may result in delays or
cancellation of some of our customer’s operations, which could adversely affect our operating results. We cannot; however,
estimate the degree to which climate change and extreme climate conditions could impact our business and operating results.
Our operations are subject to foreign exchange risk
Our U.S. and international operations have revenue, expenses, assets and liabilities denominated in currencies other than the
Canadian dollar and are mostly in U.S. dollars and currencies that are pegged to the U.S. dollar. This means that 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 period end 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
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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 U.S. dollar denominated unsecured 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 period end 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. 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.
We may be unable to access 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 (including the Senior Credit Facility, the 2021 Notes, the 2023 Notes, the 2024 Notes
and the 2026 Notes), 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.
Increasing Interest Rates may increase our cost of borrowing
Both the Bank of Canada and the United States Federal Reserve increased their benchmark interest rates in 2018, and
commentary suggests that there may be additional increases in 2019. These rate increases may have an impact on our cost of
borrowing under our Senior Credit Facility and any debt financing we may negotiate. On July 27, 2017, the U.K. Financial
Conduct Authority announced that it intends to stop compelling banks to submit LIBOR rates after 2021. The elimination of
LIBOR or any other changes or reforms to the determination or supervision of LIBOR could have an adverse impact on the
market for or value of any LIBOR-linked securities, loans, and other financial obligations or extensions of credit held by or due
to us.
Risks associated with turnkey drilling operations could adversely affect our business
We earn some of our revenue from turnkey drilling contracts. We expect that turnkey drilling will continue to be part of our service
offering; however, turnkey contracts pose substantially more risk than wells drilled on a daywork basis. Under a typical turnkey
drilling contract, we agree to drill a well for a customer to a specified depth and under specified conditions for a fixed price. We
typically provide technical expertise and engineering services, as well as most of the equipment required for the drilling of turnkey
wells and use subcontractors for related services. We typically do not receive progress payments and are entitled to payment
by the customer only after we have met the full terms of the drilling contract. We sometimes encounter difficulties on wells and
incur unanticipated costs, and not all the costs are covered by insurance. As a result, under turnkey contracts we assume most
of the risks associated with drilling operations that are generally assumed by customers under a daywork contract. Operating
cost overruns or operational difficulties on turnkey jobs could have a material adverse effect on our financial position and results
of operations.
There are risks associated with increased capital expenditures
The timing and amount of capital expenditures we incur will directly affect the amount of cash available to us. The cost of
equipment generally escalates as a result of high input costs during periods of high demand for our drilling rigs and oilfield
services equipment and other factors. There is no assurance that we will be able to recover higher capital costs through rate
increases to our customers.
A successful challenge by the tax authorities of expense deductions could negatively affect the value of our common
shares
Taxation authorities may not agree with the classification of expenses we or our subsidiaries have claimed, or they may challenge
the amount of interest expense deducted. If the taxation authorities successfully challenge our classifications or deductions, it
could have a material adverse effect on our return to shareholders.
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Management’s Discussion and Analysis
Losing key management could reduce our competitiveness and prospects for future success
Our future success and growth depend 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 assessment of goodwill or capital assets for impairment may result in a non-cash charge against our
consolidated net income
We are required to assess our goodwill balance for impairment at least annually, and our capital assets balance for impairment
when certain internal and external factors indicate the need for further analysis. We calculate impairment based on
management’s estimates and assumptions. We may consider several factors, including any declines in our share price and
market capitalization, lower future cash flow and earnings estimates, significantly reduced or depressed markets in our industry,
and general economic conditions, among other things. Any impairment write-down to goodwill or capital assets would result in
a non-cash charge against net earnings, and it could be material.
After recording a goodwill impairment charge for $208 million in the fourth quarter of 2018, we no longer have a goodwill balance.
Our credit ratings may change
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.
The price of our common shares can fluctuate
Several factors can cause volatility in our share price, including increases or decreases in revenue or earnings, changes in
revenue or earnings estimates by the investment community, failure to meet analysts’ expectations, changes in credit ratings,
and speculation in the media or investment community about our financial condition or results of operations. General market
conditions and Canadian, U.S. or international economic factors and political events unrelated to our performance may also
affect the price of our common shares. Investors should therefore not rely on past performance of our common shares to predict
the future performance of our common shares or financial results.
Selling additional common shares could affect share value
We may issue additional common shares in the future to fund our needs or those of other entities owned directly or indirectly by
us, as authorized by the Board. We do not need shareholder approval to issue additional common shares, except as may be
required by applicable stock exchange rules, and shareholders do not have any pre-emptive rights related to share issues (see
Capital Structure on page 37).
Any difficulty in retaining, replacing, or adding personnel could adversely affect our business
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 services 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.
Precision Drilling Corporation 2018 Annual Report
52
Our business is subject to cybersecurity risks
We rely heavily on information technology systems and other digital systems for operating our business. Threats to information
technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow and are increased by
the growing complexity of our information technology systems. Cybersecurity attacks could include, but are not limited to,
malicious software, attempts to gain unauthorized access to data and the unauthorized release, corruption or loss of data and
personal information, account takeovers, and other electronic security breaches that could lead to disruptions in our critical
systems. Other cyber incidents may occur as a result of natural disasters, telecommunication failure, utility outages, human
error, design defects, and unexpected complications with technology upgrades. Risks associated with these attacks and other
incidents include, among other things, loss of intellectual property, reputational harm, leaked information, improper use of our
assets, disruption of our and our customers’ business operations and safety procedures, loss or damage to our data delivery
systems, unauthorized disclosure of personal information which could result in administrative penalties and increased costs to
prevent, respond to or mitigate cybersecurity events. Although we use various procedures and controls to mitigate our exposure
to such risk, including cybersecurity risk assessments that are reviewed by our Corporate Governance, Nominating and Risk
Committee, cyber security awareness programs for our employees, continuous monitoring of our information technology systems
for threats, and insurance that may cover losses incurred as a result of certain cyber security attacks or incidents, cybersecurity
attacks and other incidents are evolving and unpredictable. The occurrence of such an attack or incident could go unnoticed for
a period of time. Any such attack or incident could have a material adverse effect on our business, financial condition and results
of operations.
Our business could be negatively affected as a result of actions of activist shareholders and some institutional
investors may be discouraged from investing in the industry we operate in
Activist shareholders could advocate for changes to our corporate governance, operational practices and strategic direction,
which could have an adverse effect on our reputation, business and future operations. In recent years, publicly-traded companies
have been increasingly subject to demands from activist shareholders advocating for changes to corporate governance
practices, such as executive compensation practices, social issues, or for certain corporate actions or reorganizations. There
can be no assurances that activist shareholders won’t publicly advocate for us to make certain corporate governance changes
or engage in certain corporate actions. Responding to challenges from activist shareholders, such as proxy contests, media
campaigns or other activities, could be costly and time consuming and could have an adverse effect on our reputation and divert
the attention and resources of management and our Board, which could have an adverse effect on our business and operational
results. Additionally, shareholder activism could create uncertainty about future strategic direction, resulting in loss of future
business opportunities, which could adversely affect our business, future operations, profitability and our ability to attract and
retain qualified personnel.
In addition to risks associated with activist shareholders, some institutional investors are placing an increased emphasis on ESG
factors when allocating their capital. These investors may be seeking enhanced ESG disclosures or may implement policies that
discourage investment in the hydrocarbon industry. To the extent that certain institutions implement policies that discourage
investments in our industry, it could have an adverse effect on our financing costs and access to liquidity and capital.
As a foreign private issuer in the U.S., we may file less information with the SEC than a company incorporated in the
U.S.
As a foreign private issuer, we are exempt from certain rules under the United States Exchange Act of 1934 (the Exchange Act)
that impose disclosure requirements, as well as procedural requirements, for proxy solicitations under Section 14 of the
Exchange Act. Our directors, officers and principal shareholders are also exempt from the reporting and short-swing profit
recovery provisions of Section 16 of the Exchange Act. We are not required to file periodic reports and financial statements with
the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act, nor are we
generally required to comply with Regulation FD, which restricts the selective disclosure of material non-public information. As
a result, there may be less publicly available information about us than U.S. public companies and this information may not be
provided as promptly. In addition, we are permitted, under a multi-jurisdictional disclosure system adopted by the U.S. and
Canada, to prepare our disclosure documents in accordance with Canadian disclosure requirements, including preparing our
financial statements in accordance with International Financial Reporting Standards (IFRS), which differs in some respects from
U.S. GAAP. We are required to assess our foreign private issuer status under U.S. securities laws annually at the end of the
second quarter. If we were to lose our status as a foreign private issuer under U.S. securities laws, we would be required to fully
comply with U.S. securities and accounting requirements.
We have retained liabilities from prior reorganizations
We have retained all liabilities of our predecessor companies, including liabilities relating to corporate and income tax matters.
53
Management’s Discussion and Analysis
We may become a passive foreign investment company, which could result in adverse U.S. tax consequences to U.S.
investors
Management does not believe that we are or will be treated as a passive foreign investment company (PFIC) for U.S. tax
purposes. However, because PFIC status is determined annually and will depend on the composition of our income and assets
from time to time, it is possible that we could be considered a PFIC in the future. This could result in adverse U.S. tax
consequences to a U.S. investor. In particular, a U.S. investor would be subject to U.S. federal income tax at ordinary income
rates, plus a possible interest charge, for any gain derived from a disposition of common shares, as well as certain distributions
by us. In addition, a step-up in the tax basis of our common shares would not be available if an individual holder dies.
An investor who acquires 10% or more of our common shares may be subject to taxation under the controlled foreign corporation
(CFC) rules.
Under certain circumstances, a U.S. person who directly or indirectly owns 10% or more of the voting power of a foreign
corporation that is a CFC (generally, a foreign corporation where 10% of the U.S. shareholders own more than 50% of the voting
power or value of the stock of the foreign corporation) for 30 straight days or more during a taxable year and who holds any
shares of the foreign corporation on the last day of the corporation’s tax year must include in gross income for U.S. federal
income tax purposes its pro rata share of certain income of the CFC even if the share is not distributed to the person. We are
not currently a CFC, but this could change in the future.
Precision Drilling Corporation 2018 Annual Report
54
Evaluation of
Controls and Procedures
Management’s
Discussion
and
Analysis
Internal Control over Financial Reporting
We maintain 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 our 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).
There were no changes in our internal control over financial reporting in 2018 that have materially affected or are reasonably
likely to materially affect our internal control over financial reporting. Based on management’s assessment as of December 31,
2018, management has concluded that our internal control over financial reporting is effective.
The effectiveness of internal control over financial reporting as of December 31, 2018 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 our 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
We maintain disclosure controls and procedures designed to provide reasonable assurance that information required to be
disclosed in our interim and annual filings is reviewed, recognized and disclosed accurately and in the appropriate time period.
Management, including the CEO and CFO, carried out an evaluation, as of December 31, 2018, 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. 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
we file or submit 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 our disclosure controls and procedures provide a reasonable level
of assurance that they are effective, they do not expect that these 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.
55
Management’s Discussion and Analysis
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, 2018 and December 31, 2017.
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, 2018.
Also, management determined that there were no material weaknesses in the Corporation’s internal control over financial
reporting as of December 31, 2018.
KPMG LLP (KPMG), an independent firm of Chartered Professional 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 also completed an audit of the design and effectiveness of the Corporation’s internal control over financial reporting as
of December 31, 2018, 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, 2018.
The Audit Committee of the Board of Directors, which is comprised of six 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
Carey T. Ford
Senior Vice President and Chief Financial Officer
Precision Drilling Corporation
March 1, 2019
March 1, 2019
Precision Drilling Corporation 2018 Annual Report
56
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of Precision Drilling Corporation
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated statements of financial position of Precision Drilling Corporation (the
Corporation) as of December 31, 2018 and 2017, the related consolidated statements of loss, comprehensive loss, changes in
equity, and cash flow for the years then ended, and the related notes (collectively, the consolidated financial statements). In
our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the
Corporation as of December 31, 2018 and 2017, and the results of its financial performance and its cash flows for the years
then ended, in conformity with International Financial Reporting Standards as issued by the International Accounting
Standards Board.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Corporation’s internal control over financial reporting as of December 31, 2018, based on criteria established in
Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated March 1, 2019 expressed an unqualified opinion on the effectiveness of the Corporation’s
internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Corporation’s management. Our responsibility is to
express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond
to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the
consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates
made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that
our audits provide a reasonable basis for our opinion.
We have served as the Corporation’s auditor since 1987.
Chartered Professional Accountants
Calgary, Canada
March 1, 2019
57
Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of Precision Drilling Corporation
Opinion on Internal Control over Financial Reporting
We have audited Precision Drilling Corporation’s (the “Corporation”) internal control over financial reporting as of December
31, 2018, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission. In our opinion, the Corporation maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2018, based on the criteria established in Internal Control
– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(“PCAOB”), the consolidated statements of financial position of the Corporation as of December 31, 2018 and December 31,
2017, the related consolidated statements of loss, comprehensive loss, changes in equity and cash flows for the years then
ended, and the related notes (collectively the “consolidated financial statements”) and our report dated March 1, 2019
expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
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 are a public accounting firm registered with the PCAOB and are required to be independent
with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of
the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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 of internal control over financial reporting 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.
Definition and Limitations of Internal Control over Financial Reporting
A company’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. A company’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 company; (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 company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’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.
Chartered Professional Accountants
Calgary, Canada
March 1, 2019
Precision Drilling Corporation 2018 Annual Report
58
Consolidated Statements of Financial Position
(Stated in thousands of Canadian dollars)
ASSETS
Current assets:
Cash
Accounts receivable
Income tax recoverable
Inventory
Assets held for sale
Total current assets
Non-current assets:
Income taxes recoverable
Deferred tax assets
Property, plant and equipment
Intangibles
Goodwill
Total non-current assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities
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
Deficit
Accumulated other comprehensive income
Total shareholders’ equity
Total liabilities and shareholders’ equity
December 31,
2018
December 31,
2017
$
(Note 25)
(Note 6)
(Note 14)
(Note 7)
(Note 8)
(Note 9)
$
(Note 25)
$
(Note 13)
(Note 16)
(Note 10)
(Note 14)
(Note 17)
(Note 19)
$
96,626
372,336
—
34,081
503,043
19,658
522,701
2,449
36,880
3,038,612
35,401
—
3,113,342
3,636,043
274,489
7,673
282,162
6,520
10,577
1,706,253
72,779
1,796,129
2,322,280
52,332
(978,874)
162,014
1,557,752
3,636,043
$
$
$
$
65,081
322,585
29,449
24,631
441,746
—
441,746
2,256
41,822
3,173,824
28,116
205,167
3,451,185
3,892,931
209,625
—
209,625
13,536
10,086
1,730,437
118,911
1,872,970
2,319,293
44,037
(684,604)
131,610
1,810,336
3,892,931
See accompanying notes to consolidated financial statements.
Approved by the Board of Directors:
Allen R. Hagerman
Director
Steven W. Krablin
Director
59
Consolidated Financial Statements
Consolidated Statements of Loss
Years ended December 31,
(Stated in thousands of Canadian dollars, except per share amounts)
Revenue
Expenses:
Operating
General and administrative
Other recoveries
Earnings before income taxes, loss (gain) on redemption and repurchase of
unsecured senior notes, finance charges, foreign exchange,
impairment of property, plant, and equipment, impairment of goodwill
and depreciation and amortization
Depreciation and amortization
Impairment of goodwill
Impairment of property, plant and equipment
Foreign exchange
Finance charges
Loss (gain) on redemption and repurchase of unsecured senior notes
Loss before income taxes
Income taxes:
Current
Deferred
Net loss
Loss per share:
Basic
Diluted
See accompanying notes to consolidated financial statements.
Consolidated Statements of Comprehensive Loss
Years ended December 31,
(Stated in thousands of Canadian dollars)
Net loss
Unrealized gain (loss) on translation of assets and liabilities of operations
denominated in foreign currency
Foreign exchange gain (loss) on net investment hedge with U.S. denominated debt,
net of tax
Comprehensive loss
See accompanying notes to consolidated financial statements.
(Note 9)
(Note 7)
(Note 12)
(Note 14)
(Note 18)
(Note 4)
$
2018
1,541,189
$
2017
1,321,224
(Note 25)
(Note 25)
(Note 11)
1,067,871
112,387
(14,200)
926,171
90,072
—
304,981
377,746
—
15,313
(2,970)
137,928
9,021
(232,057)
(1,331)
(98,690)
(100,021)
(132,036)
(0.45)
(0.45)
375,131
365,660
207,544
—
4,017
127,178
(5,672)
(323,596)
8,573
(37,899)
(29,326)
(294,270)
(1.00)
(1.00)
$
$
$
2018
(294,270)
175,630
(145,226)
(263,866)
$
$
2017
(132,036)
(146,545)
121,699
(156,882)
$
$
$
$
$
Precision Drilling Corporation 2018 Annual Report
60
Consolidated Statements of Cash Flow
Years ended December 31,
(Stated in thousands of Canadian dollars)
Cash provided by (used in):
Operations:
Net loss
Adjustments for:
Long-term compensation plans
Depreciation and amortization
Impairment of property, plant and equipment
Impairment of goodwill
Foreign exchange
Finance charges
Loss (gain) on redemption and repurchase of unsecured senior notes
Income taxes
Other
Income taxes paid
Income taxes recovered
Interest paid
Interest received
Funds provided by operations
Changes in non-cash working capital balances
Cash provided by operations
Investments:
Purchase of property, plant and equipment
Purchase of intangibles
Proceeds on sale of property, plant and equipment
Changes in non-cash working capital balances
Cash used in investing activities
Financing:
Redemption and repurchase of unsecured senior notes
Debt issuance costs
Debt amendment fees
Proceeds from issuance of long-term debt
Issuance of common shares on the exercise of options
Cash used in financing activities
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.
2018
2017
$
(294,270)
$
(132,036)
17,401
365,660
—
207,544
2,341
127,178
(5,672)
(29,326)
(1,269)
(4,446)
33,283
(108,622)
1,412
311,214
(17,880)
293,334
(114,576)
(11,567)
24,457
892
(100,794)
(168,722)
—
(638)
—
275
(169,085)
8,090
31,545
65,081
96,626
$
6,795
377,746
15,313
—
(2,873)
137,928
9,021
(100,021)
(2,025)
(3,645)
11,932
(136,065)
1,865
183,935
(67,380)
116,555
(74,823)
(23,179)
14,841
(7,989)
(91,150)
(571,975)
(9,196)
(1,793)
509,180
—
(73,784)
(2,245)
(50,624)
115,705
65,081
(Note 25)
(Note 7)
(Note 8)
(Note 7)
(Note 25)
(Note 10)
(Note 10)
(Note 8)
(Note 10)
$
61
Consolidated Financial Statements
Consolidated Statements of Changes in Equity
(Stated in thousands of Canadian dollars)
Balance at January 1, 2018
Net loss for the period
Other comprehensive income for the
period
Redemption of non-management directors
DSUs
Share options exercised
Share based compensation expense
Balance at December 31, 2018
(Note 13)
(Note 13)
(Note 13)
2,609
378
—
2,322,280
$
(Stated in thousands of Canadian dollars)
Balance at January 1, 2017
Net loss for the period
Other comprehensive loss for the period
Share based compensation expense
Balance at December 31, 2017
(Note 13)
$
Shareholders’
Capital
(Note 17)
2,319,293
—
—
—
2,319,293
$
Shareholders’
Capital
(Note 17)
2,319,293
—
$
Contributed
Surplus
44,037
—
$
Accumulated
other
Comprehensive
Income
(Note 19)
131,610
—
$
—
—
30,404
Deficit
(684,604) $
(294,270)
Total Equity
1,810,336
(294,270)
—
30,404
—
—
—
(978,874) $
1,800
275
9,207
1,557,752
Deficit
(552,568) $
(132,036)
—
—
(684,604) $
Total Equity
1,962,118
(132,036)
(24,846)
5,100
1,810,336
$
$
$
$
(809)
(103)
9,207
52,332
$
—
—
—
162,014
Accumulated
other
Comprehensive
Income
(Note 19)
156,456
—
(24,846)
—
131,610
$
$
Contributed
Surplus
38,937
—
—
5,100
44,037
$
$
$
See accompanying notes to consolidated financial statements.
Precision Drilling Corporation 2018 Annual Report
62
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 1, 2019.
(b) Basis of Measurement
The consolidated financial statements have been prepared using the historical cost basis 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. The Corporation reviews its estimates and assumptions on an ongoing basis.
Adjustments that result from a change in estimate are recorded in the period in which they become known. Significant
estimates and judgments used in the preparation of the financial statements are described in Note 3(d), (g), (i), (j) 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 considered. 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.
(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 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.
63
Notes to Consolidated Financial Statements
(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:
Drilling rig equipment:
– Power & Tubulars
– Dynamic
– Structural
Service rig equipment
Drilling rig spare equipment
Service rig spare equipment
Rental equipment
Other equipment
Light duty vehicles
Heavy duty vehicles
Buildings
Expected Life
Salvage Value
Basis of
Depreciation
5 years
10 years
20 years
20 years
up to 15 years
up to 15 years
up to 15 years
3 to 10 years
4 years
7 to 10 years
10 to 20 years
–
–
10%
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
Property, plant and equipment are depreciated 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 technological advancements are made.
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 loss.
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.
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.
Intangible assets are amortized based on estimates of useful lives. These estimates consider data and information from
various sources including vendors and Precision’s own historical experience and may change as more experience is gained or
technological advancements are made.
Amortization is recognized in profit and loss using the straight-line method over the estimated useful lives of the respective
assets. Precision’s loan commitment fees are amortized over the term of the respective facility. Software is amortized over its
expected useful life of up to 10 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.
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.
Precision Drilling Corporation 2018 Annual Report
64
(g) Impairment of 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. 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). Judgment is required in the
aggregation of assets into CGUs.
If any such indication exists, then the asset or CGU’s recoverable amount is estimated. Judgement is required when
evaluating whether a CGU has indications of impairment. For CGUs that contain goodwill and other intangible assets that have
indefinite lives or that are not yet available for use, an impairment test is, at a minimum, completed annually as of December
31.
The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell. In assessing
value in use, the estimated future cash flows are discounted to their present value using 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 a 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 profit or loss 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 profit or loss 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.
The Corporation is subject to taxation in numerous jurisdictions. Uncertainties exist with respect to the interpretation of
complex tax regulations and requires significant judgement. 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.
(j) Revenue from Contracts with Customers
The Corporation initially applied IFRS 15 on January 1, 2018, as described in Note 3(t). Precision recognizes revenue from a
variety of sources. In general, customer invoices are issued upon rendering all performance obligations for an individual well-
65
Notes to Consolidated Financial Statements
site job. Under the Corporation’s standard contract terms, customer payments are to be received within 30 days of the
customer’s receipt of an invoice.
Contract Drilling Services
The Corporation contracts individual drilling rig packages, including crews and support equipment, to its customers.
Depending on the customer’s drilling program, contracts may be for a single well, multiple wells or a fixed term. Revenue
from contract drilling services is recognized over time from spud to rig release on a daily basis. Operating days are
measured through industry standard tour sheets that document the daily activity of the rig. Revenue is recognized at the
applicable day rate for each well, based on rates specified in the drilling contract.
The Corporation provides services under turnkey contracts, whereby Precision is required to drill a well to an agreed
upon depth under specified conditions for a fixed price, regardless of the time required or problems encountered in
drilling the well. Revenue from turnkey drilling contracts is recognized over time using the input method based on costs
incurred to date in relation to estimated total contract costs, as that most accurately depicts the Corporation’s
performance.
The Corporation also provides directional drilling services, which include the provision of directional drilling equipment,
tools and personnel to the wellsite, and performance of daily directional drilling services. Directional drilling revenue is
recognized over time, upon the daily completion of operating activities. Operating days are measured through daily tour
sheets. Revenue is recognized at the applicable day rate, as stipulated in the directional drilling contract.
Completion and Production Services
The Corporation provides a variety of well completion and production services including well servicing and snubbing. In
general, service rigs do not involve long-term contracts or penalties for termination. Revenue is recognized daily upon
completion of services. Operating days are measured through daily tour sheets and field tickets. Revenue is recognized
at the applicable daily or hourly rate, as stipulated in the contract.
The Corporation offers a variety of oilfield equipment for rental to its customers. Rental revenue is recognized daily at
the applicable rate stated in the rental contract. Rental days are measured through field tickets.
The Corporation provides accommodation and catering services to customers in remote locations. Customers contract
these services either as a package or individually for a fixed term. For accommodation services, the Corporation
supplies camp equipment and revenue is recognized over time on a daily basis, once the equipment is on-site and
available for use, at the applicable rate stated in the contract. For catering services, the Corporation recognizes revenue
daily according to meals served. Accommodation and catering services provided are measured through field tickets.
(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 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 profit or loss 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.
Precision Drilling Corporation 2018 Annual Report
66
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 profit or loss except for gains and losses on translation of long-term debt
designated as a hedge of foreign operations, which are deferred and included in 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 period end 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 profit or loss on disposal or partial disposal
of the foreign operation.
(o) Per Share Amounts
Basic per share amounts are calculated using the weighted average number of shares outstanding during the period. Diluted
per share amounts are calculated by using the treasury stock method for equity based compensation arrangements. The
treasury stock method assumes that any proceeds obtained on exercise of equity based compensation arrangements would
be used to purchase common shares at the average market price during the period. The weighted average number of shares
outstanding is then adjusted by the difference between the number of shares issued from the exercise of equity based
compensation arrangements and shares repurchased from the related proceeds.
(p) Financial Instruments
i) Non-Derivative Financial Instruments:
The Corporation initially applied IFRS 9, Financial Instruments, on January 1, 2018 as described in Note 3(s). Financial
assets and liabilities are classified and measured at amortized cost, fair value through other comprehensive income or
fair value through profit and loss. The classification of financial assets and liabilities is generally based on the business
model in which the asset or liability is managed and its contractual cash flow characteristics. Financial assets held within
a business model whose objective is to collect contractual cash flows and whose contractual terms give rise to cash
flows on specified dates that are solely payments of principal and interest on the principal amount outstanding are
measured at amortized cost. After their initial fair value measurement, accounts receivable, accounts payable and
accrued liabilities and long-term debt are classified and measured at amortized cost using the effective interest rate
method.
Upon initial recognition of a non-derivative financial asset a loss allowance is recorded for expected credit losses (ECL).
Loss allowances for trade receivables are measured based on lifetime ECL that incorporates historical loss information
and is adjusted for current economic and credit conditions.
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 statement of financial
position at estimated fair value. Transaction costs are recognized in profit or loss when incurred.
Derivatives embedded in financial assets are never separated. Rather, the financial instrument as a whole is assessed
for classification. Derivatives embedded in financial liabilities 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 in financial liabilities are recorded on the statement of financial position at estimated fair value and changes
in the fair value are recognized in earnings.
67
Notes to Consolidated Financial Statements
(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 from fluctuations 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 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
ineffective portions are recorded through profit or loss.
A reduction in the fair value of the net investment in the foreign operations or increase in the foreign currency long-term debt
balance may result in a portion of the hedge becoming ineffective. If the hedging relationship ceases to be effective or is
terminated, hedge accounting is not applied to subsequent gains or losses. The amounts recognized in other comprehensive
income are reclassified to profit and loss and the corresponding exchange gains or losses arising from the translation of the
foreign operation are recorded through profit and loss upon dissolution or substantial dissolution of the foreign operation.
(r) Assets Held For Sale
Non-current assets, or disposal groups, are classified as held-for sale if it is highly probable that their carrying amount will be
recovered primarily through a sale transaction rather than through continued use. Such assets, or disposal groups, are
measured at the lower of their carrying amount and fair value less costs to sell. Impairment losses on initial classification as
held-for-sale and subsequent gains or losses on remeasurement are recognized in profit or loss.
(s) Critical Accounting Assumptions and Estimates
i) Impairment of Long-Lived Assets
When indications of impairment exist within a CGU, a recoverable amount is determined and requires assumptions to
estimate future discounted cash flows. These estimates and assumptions include future drilling activity, margins and
market conditions over the long-term life of the CGU. In selecting a discount rate, we use observable market data inputs
to develop a rate that we believe approximates the discount rate of market participants.
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.
ii) Income Taxes
Significant estimation and assumptions are required in determining the provision for income taxes. The recognition of
deferred tax assets in respect of deductible temporary differences and unused tax losses and credits is based on the
Corporation’s estimation of future taxable profit against which these differences, losses and credits may be used. The
assessment is based upon existing tax laws and estimates of the Corporation’s future taxable income. These estimates
may be materially different from the actual final tax return in future periods.
(t) Accounting Standards Adopted January 1, 2018
The following standards were adopted by the Corporation on January 1, 2018 using the cumulative-effect method of
adoption. The adoption of these standards had no material impact on the amounts recorded in these financial
statements.
i) IFRS 9, Financial Instruments
Effective January 1, 2018, IFRS 9 replaced IAS 39 Financial Instruments, Recognition and Measurement. IFRS 9
contains three principal classification categories for financial assets: measured at amortized cost, fair value through
other comprehensive income and fair value through profit or loss. The classification of financial assets under IFRS 9 is
generally based on the business model in which a financial asset is managed and the characteristics of its contractual
cash flows. IFRS 9 eliminates the previous IAS 39 categories of held to maturity, loans and receivables and available for
sale. Under IFRS 9, derivatives embedded in contracts where the host is a financial asset under the standard are never
separated. Instead the hybrid financial instrument as a whole is assessed for classification.
Under the new standard, Precision’s accounts receivable, accounts payable and accrued liabilities and long-term debt
have been classified and measured at amortized cost.
The following table shows the original measurement categories and carrying amounts for each financial asset and
liability under IAS 39 and the subsequent measurement and carrying amount upon adoption of IFRS 9 as at January 1,
2018.
Precision Drilling Corporation 2018 Annual Report
68
(Stated in thousands of Canadian dollars)
Financial Assets
Cash and cash equivalents
Accounts receivable
Loans and receivables
Loans and receivables
Amortized cost
Amortized cost
Measurement Category
Carrying Amount
IAS 39
IFRS 9
IAS 39
IFRS 9
Financial Liabilities
Accounts payable and accrued liabilities Other financial liabilities
Other financial liabilities
Long-term debt
Amortized cost
Amortized cost
$
$
$
$
65,081 $
322,585
387,666 $
65,081
322,585
387,666
209,625 $
1,730,437
1,940,062 $
209,625
1,730,437
1,940,062
IFRS 9 replaced the incurred loss model of IAS 39 with an expected credit loss model. The loss allowance to be
recorded against trade receivables is measured as the lifetime expected credit losses. Due to low historical default rates,
there was no material adjustment to the credit loss allowance.
ii) IFRS 15, Revenue from Contracts with Customers
IFRS 15 established a single comprehensive model 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. It replaced
existing revenue recognition guidance including IAS 18 Revenue and IAS 11 Construction Contracts.
The standard provides a principle 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 performance obligations.
During its initial application of IFRS 15, the Corporation did not apply any of the available practical expedients. The
application of IFRS 15 did not result in a material impact to the Corporation’s consolidated financial statements. For
additional information about the Corporation’s accounting policies with respect to revenue recognition, see Note 3(j).
(u) Accounting Standards, Interpretations and Amendments to Existing Standards not yet Effective
i) IFRS 16, Leases
On January 1, 2019, Precision will adopt IFRS 16 - Leases. This standard introduces a single, on-balance sheet lease
accounting model for lessees and requires a lessee to recognize a right-of-use asset representing its right to direct the
use of the underlying asset as well as a lease liability representing its obligation to make future lease payments. IFRS 16
will also cause expenses to be higher at the beginning and lower towards the end of a lease, even when payments are
consistent throughout the term. The standard includes recognition exemptions for short-term leases and leases of low-
value items. Lessor accounting remains similar to the current standard in which lessors continue to classify leases as
either finance or operating leases.
IFRS 16 will replace existing lease guidance, including IAS 17 Leases, IFRIC 4 Determining whether an Arrangement
contains a Lease, SIC-15 Operating Leases – Incentives and SIC-27 Evaluating the Substance of Transactions
Involving the Legal Form of a Lease.
Precision has completed its review of the existing contracts that are currently classified as leases under the existing
standard, or that could be classified as leases under IFRS 16, in order to identify the contracts that will be impacted by
the new standard from the perspective of both a lessor and a lessee. Management has also estimated the impact that
the initial application of IFRS 16 will have on its consolidated financial statements, as described below. The actual
impact of adopting the standard on January 1, 2019 may differ from what is described below as Precision’s accounting
policies, including the election to apply certain practical expedients, are subject to change until presented in its first
published financial statements after the date of initial application.
Leases in which Precision is a lessee
Precision will recognize right-of-use assets and lease liabilities for its real estate, vehicle, office equipment and other
contracts that are currently classified as operating leases. The nature of expenses related to those leases will change as
Precision will depreciate the right-of-use assets and recognize interest expense on its lease liabilities. Under the existing
standard, Precision recognizes operating lease expenses on a straight-line basis over the term of the lease in either
operating or general and administrative expense and recognizes assets and liabilities only to the extent there was a
timing difference between the payment date and the recognition of the expense.
Based on the information currently available, Precision estimates that it will recognize lease liabilities and corresponding
right-of-use assets of approximately $60 million - $70 million on January 1, 2019 related to contracts where it is the
lessee. Precision does not expect a material adjustment to the opening balance of retained earnings on January 1, 2019
upon the initial application of IFRS 16. The actual impact of adopting the standard on January 1, 2019 may differ from
69
Notes to Consolidated Financial Statements
these estimates as the Corporation continues to review its calculations and may refine certain inputs therein, such as the
discount rate and lease term.
Leases in which Precision is a lessor
Precision evaluated its drilling rigs under term contracts longer than one year and determined that these meet the
definition of a lease under IFRS 16. Precision expects to classify these as operating leases, and accordingly, will
recognize lease income over the term of the respective drilling contract. This is not expected to give rise to differences in
the recognition or measurement of revenues from these contracts as compared to Precision’s existing accounting
policies.
Precision reassessed the classification of its real estate sub-leases in which it is a lessor. These are classified as an
operating lease under the existing lease standard and management does not expect to reclassify these as finance
leases.
Transition
There are two methods by which the new standard may be adopted: (1) a full retrospective approach with a restatement
of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment recognized in
opening retained earnings as of the date of adoption, with no restatement of comparative information. Precision will
apply IFRS 16 initially on January 1, 2019, using the modified retrospective approach.
When applying a modified retrospective approach to leases previously classified as operating leases under IAS 17, the
lessee can elect, on a lease-by-lease basis, whether to apply a number of practical expedients on transition. On initial
adoption of the new standard, the Corporation intends to use the following practical expedients, where applicable:
• not applying the requirements of the standard to short-term leases;
•
treat existing operating leases with a remaining term of less than 12 months at January 1, 2019 as short-term leases;
• not applying the requirements of the standard to low-value leases; and
• applying a single discount rate to a portfolio of leases with reasonably similar characteristics.
As a result of the adoption of the new standard, Precision will be required to include significant disclosures in the
consolidated financial statements based on the prescribed requirements. These new disclosures will include information
regarding the judgments used in determining discount rates and terms of leases including optional renewal periods. The
Corporation will include the required disclosures in its 2019 first quarter condensed consolidated interim financial
statements.
ii) IFRIC 23, Uncertainty over Income Tax Treatments
IFRIC 23 clarifies the accounting for uncertainties in income taxes. The interpretation requires the entity to use the most
likely amount or the expected value of the tax treatment if it concludes that it is not probable that a particular tax
treatment will be accepted. It requires an entity to assume that a taxation authority with the right to examine any
amounts reported to it will examine those amounts and will have full knowledge of all relevant information when doing
so.
IFRIC 23 is effective for annual reporting periods beginning on or after January 1, 2019. The requirements are applied
by recognizing the cumulative effect of initially applying them in retained earnings, or in other appropriate components of
equity, at the start of the reporting period in which an entity first applies them, without adjusting comparative information.
Full retrospective application is permitted, if an entity can do so without using hindsight.
Precision has reviewed its initial application of IFRIC 23 and determined it will not have a material impact on the
consolidated financial statements. The actual impact of adopting the standard on January 1, 2019 may differ as
Precision’s accounting policies are subject to change until presented in its first published financial statements after the
date of initial application.
Precision Drilling Corporation 2018 Annual Report
70
NOTE 4. REVENUE
The following table includes a reconciliation of disaggregated revenue by reportable segment (Note 5). Revenue has been
disaggregated by primary geographical market and type of service provided.
Twelve months ended December 31, 2018
Canada
United States
International
Day rate/hourly services
Shortfall payments/idle but contracted
Turnkey drilling services
Directional services
Other
Twelve months ended December 31, 2017 (1)
Canada
United States
International
Contract
Drilling
Services
426,475 $
778,886
191,131
1,396,492 $
1,302,575 $
12,520
37,811
31,943
11,643
1,396,492 $
Completion
and
Production
Services
138,030 $
12,730
—
150,760 $
150,760 $
—
—
—
—
150,760 $
Contract
Drilling
Services
429,119 $
554,410
190,401
1,173,930 $
Completion
and
Production
Services
139,113 $
15,033
—
154,146 $
$
$
$
$
$
$
Corporate
and Other
Inter-
Segment
Eliminations
— $
—
—
— $
— $
—
—
—
—
— $
(5,759) $
(304)
—
(6,063) $
(1,009) $
—
—
—
(5,054)
(6,063) $
Corporate
and Other
Inter-
Segment
Eliminations
— $
—
—
— $
(5,982) $
(870)
—
(6,852) $
$
Day rate/hourly services
Shortfall payments/idle but contracted
Turnkey drilling services
Directional services
Other
(1,614) $
—
—
—
(5,238)
(6,852) $
(1) IFRS 15 initially applied at January 1, 2018; under the transition method chosen, comparative information is not restated.
1,076,018 $
39,468
12,306
34,481
11,657
1,173,930 $
154,146 $
—
—
—
—
154,146 $
— $
—
—
—
—
— $
$
Total
558,746
791,312
191,131
1,541,189
1,452,326
12,520
37,811
31,943
6,589
1,541,189
Total
562,250
568,573
190,401
1,321,224
1,228,550
39,468
12,306
34,481
6,419
1,321,224
NOTE 5. SEGMENTED INFORMATION
The Corporation operates primarily in Canada, the United States and certain international locations, 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, oilfield equipment rental, camp and catering
services, and wastewater treatment units.
2018
Revenue
Operating loss
Depreciation and amortization
Impairment of goodwill
Total assets
Goodwill
Capital expenditures
$
Contract
Drilling
Services
1,396,492 $
(129,965)
334,555
207,544
3,301,457
—
108,610
Completion
and
Production
Services
150,760 $
(8,998)
23,879
—
170,113
—
5,004
Corporate
and Other
Inter-
Segment
Eliminations
— $
(59,110)
7,226
—
164,473
—
12,529
(6,063) $
—
—
—
—
—
—
Total
1,541,189
(198,073)
365,660
207,544
3,636,043
—
126,143
71
Notes to Consolidated Financial Statements
2017
Revenue
Operating loss
Depreciation and amortization
Impairment of property, plant and equipment
Total assets
Goodwill
Capital expenditures
$
Contract
Drilling
Services
1,173,930 $
(6,930)
334,587
15,313
3,491,393
205,167
69,076
Completion
and
Production
Services
154,146 $
(17,750)
29,638
—
209,353
—
4,509
Corporate
and Other
Inter-
Segment
Eliminations
— $
(63,398)
13,521
—
192,185
—
24,417
(6,852) $
—
—
—
—
—
—
A reconciliation of operating loss to loss before income taxes is as follows:
Total
1,321,224
(88,078)
377,746
15,313
3,892,931
205,167
98,002
2017
(88,078)
(2,970)
137,928
2018
$
(198,073)
$
4,017
127,178
(5,672)
(323,596)
$
9,021
(232,057)
$
Total segment operating loss
Add (deduct):
Foreign exchange
Finance charges
Loss (gain) on redemption and repurchase of
unsecured senior notes
Loss before income taxes
The Corporation’s operations are carried on in the following geographic locations:
2018
Revenue
Total assets
2017
Revenue
Total assets
$
$
Canada
571,640 $
1,269,542
United States
International
Eliminations
797,217 $
1,772,850
191,131 $
593,651
(18,799) $
—
Canada
578,817 $
1,631,838
United States
International
Eliminations
568,573 $
1,666,368
190,401 $
594,725
(16,567) $
—
Total
1,541,189
3,636,043
Total
1,321,224
3,892,931
NOTE 6. ASSETS HELD FOR SALE
In December 2018, Precision committed to a plan to sell drilling rigs that no longer met the Corporation’s High-Performance
technology standards. The disposal group, contained within its Contract Drilling Services segment, has been classified as held
for sale and measured at the lower of its carrying value and fair value less costs to sell. At December 31, 2018, the disposal
group was stated at its carrying value of $19.7 million, which is less than its estimated fair value. Efforts to sell the disposal
group have started and are expected to be completed prior to December 31, 2019.
NOTE 7. PROPERTY, PLANT AND EQUIPMENT
Cost
Accumulated depreciation
Rig equipment
Rental equipment
Other equipment
Vehicles
Buildings
Assets under construction
Land
$
$
$
$
$
2018
6,937,062
(3,898,450)
3,038,612
2,745,172
43,992
52,195
12,702
65,561
84,561
34,429
3,038,612 $
2017
6,733,634
(3,559,810)
3,173,824
2,823,782
60,179
66,560
16,280
71,102
102,035
33,886
3,173,824
Precision Drilling Corporation 2018 Annual Report
72
Cost
Balance, December 31, 2016
Additions
Disposals
Reclassifications
Effect of foreign currency exchange
differences
Balance, December 31, 2017
Additions
Disposals
Reclassifications
Reclassification to assets held for sale
Effect of foreign currency exchange
differences
Balance, December 31, 2018
Accumulated Depreciation
Balance, December 31, 2016
Depreciation expense
Disposals
Impairment
Effect of foreign currency exchange
differences
Balance, December 31, 2017
Depreciation expense
Disposals
Reclassification to assets held for sale
Effect of foreign currency exchange
differences
Balance, December 31, 2018
a)
Impairment Test
Rig
Rental
Other
Assets
Under
Equipment
Equipment
Equipment Vehicles Buildings
$6,266,991 $ 159,144 $ 247,073 $ 45,147 $131,361 $
235
(930)
—
21,268
(71,014)
67,779
71
(9,758)
84
49
(785)
216
42
(339)
113
Construction
Total
Land
126,430 $35,032 $7,011,178
74,823
(82,826)
(374)
53,158
—
(68,566)
—
—
—
(1,530)
(1,762)
(1,603)
(250,858)
(3,281)
6,034,166 148,011 244,950 43,201 127,385
569
(3,663)
—
—
7,013
(32,153)
127,668
(135,398)
347
(59,865)
507
—
—
(18,227)
—
—
—
(228)
—
—
321,240
4,036
$6,322,536 $ 130,463 $ 191,290 $ 45,456 $128,327 $
5,351 2,483
679
(8,987) (1,146)
(269,167)
102,035 33,886 6,733,634
114,576
106,647
(115,029)
—
—
(128,175)
(135,398)
—
—
(893)
—
—
4,054 1,436
339,279
84,561 $34,429 $6,937,062
Rig
Rental
Other
Assets
Under
Equipment
$3,056,058 $
334,896
(67,304)
15,313
Equipment
Equipment Vehicles Buildings
79,746 $ 161,342 $ 23,117 $ 49,026 $
8,488
19,914 5,064
15,159
(208)
(320)
(6,331)
—
—
—
(592)
—
Construction
— $
—
—
—
Land
Total
— $3,369,289
383,521
—
(74,755)
—
15,313
—
(128,579)
3,210,384
335,215
(28,399)
(115,740)
(742)
(940)
(2,274)
(1,023)
87,832 178,390 26,921 56,283
8,126
15,993 4,820
(3,161)
(220)
(59,857)
—
—
—
9,418
(11,249)
—
175,904
$3,577,364 $
470
1,518
4,569 1,233
86,471 $ 139,095 $ 32,754 $ 62,766 $
—
—
—
—
—
—
— $
—
(133,558)
— 3,559,810
373,572
—
(102,886)
—
(115,740)
—
183,694
—
— $3,898,450
Precision reviews the carrying value of its long-lived assets at each reporting period for indications of impairment. Precision
completed its review as at December 31, 2018 and impairment charges of $207.5 million were recorded against goodwill.
Refer to Note 9 for additional discussion of impairment testing performed in the current year.
As at December 31, 2017, the Corporation determined that the uncertainty around future activity levels within Mexico was an
indication of impairment and a comprehensive assessment of the carrying values of property, plant and equipment of the
Mexico drilling CGU within the Contract Drilling Services segment was performed.
The recoverable amount of the Mexico drilling CGU was determined using a value in use calculation. Projected cash flows
covered a five-year period and were based on future expected outcomes taking into account existing contracts, past
experience and management’s expectation of future market conditions. The primary source of cash flow information was the
strategic plan approved by executives of the Corporation. The strategic plan was 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 the Mexico drilling CGU. The after-tax
discount rate derived from Precision’s weighted average cost of capital, adjusted for risk factors specific to the CGU and used
in determining the recoverable amount for the Mexico drilling CGU was 17.1%. The test resulted in an impairment charge of
$15.3 million as the carrying value of the CGU’s assets exceeded its value in use of $26.3 million.
73
Notes to Consolidated Financial Statements
NOTE 8. INTANGIBLES
Cost
Accumulated amortization
Loan commitment fees related to Senior Credit Facility
Software
Cost
Balance, December 31, 2016
Additions
Reclassifications
Balance, December 31, 2017
Additions
Balance, December 31, 2018
Accumulated Amortization
Balance, December 31, 2016
Amortization expense
Balance, December 31, 2017
Amortization expense
Balance, December 31, 2018
NOTE 9. GOODWILL
Balance, December 31, 2016
Exchange adjustment
Balance, December 31, 2017
Exchange adjustment
Impairment charge
Balance, December 31, 2018
$
$
$
$
2018
51,912 $
(16,511)
35,401 $
2,307 $
33,094
35,401 $
Loan
Commitment
Fees
12,345 $
1,793
—
14,138
638
14,776 $
Loan
Commitment
Fees
9,029 $
1,989
11,018
1,451
12,469 $
$
$
$
$
Software
— $
23,179
2,390
25,569
11,567
37,136
$
Software
— $
573
573
3,469
4,042 $
2017
39,707
(11,591)
28,116
3,120
24,996
28,116
Total
12,345
24,972
2,390
39,707
12,205
51,912
Total
9,029
2,562
11,591
4,920
16,511
$
$
207,399
(2,232)
205,167
2,377
(207,544)
—
Management performed its annual impairment test for those CGUs containing goodwill and determined the goodwill
associated with the Canada contract drilling CGU of $172.2 million and U.S. directional drilling CGU of $35.3 million were not
recoverable at December 31, 2018. Accordingly, an impairment charge of $207.5 million was recorded in the statement of loss
for the period ended December 31, 2018. Both CGUs are contained within the Contract Drilling Services segment.
In performing its annual goodwill impairment tests, the Corporation used a value in use approach. Projected cash flows
covered a five-year period and were based on future expected outcomes taking into account existing term contracts, past
experience and management’s expectation of future market conditions. The primary source of cash flow information was the
strategic plans approved by the Corporation’s Board of Directors. These strategic plans were developed based on benchmark
commodity prices and industry supply-demand fundamentals.
Canada Contract Drilling
Cash flows used in the impairment calculation were discounted using a discount rate specific to the Canada contract drilling
CGU. The after-tax discount rate derived from Precision’s weighted average cost of capital, adjusted for risk factors specific to
the CGU and used in determining the recoverable amount for the Canada contract drilling CGU was 11.66% (2017 – 9.72%).
The test resulted in a goodwill impairment charge of $172.2 million as the carrying value of the CGU’s assets exceeded its
value in use of $941.6 million.
Precision Drilling Corporation 2018 Annual Report
74
The key assumptions used in the calculation of the CGU’s value in use included the discount rate and terminal value growth
rates of nil. An increase of 0.5% to the discount rate would result in approximately $37.3 million of additional impairment
charges to the remaining assets within the CGU.
US Directional Drilling
Cash flows used in the impairment calculation were discounted using a discount rate specific to the U.S. directional drilling
CGU. The after-tax discount rate derived from Precision’s weighted average cost of capital, adjusted for risk factors specific to
the CGU and used in determining the recoverable amount for the U.S. directional drilling CGU was 12.16% (2017 – 11.72%).
The test resulted in a goodwill impairment charge of $35.3 million as the carrying value of the CGU’s assets exceeded its
value in use of $38.8 million.
The key assumptions used in the calculation of the CGU’s value in use included the discount rate and terminal value growth
rates of nil. An increase of 0.5% to the discount rate would result in approximately $2.4 million of additional impairment
charges to the remaining assets within the CGU.
NOTE 10. LONG-TERM DEBT
Senior Credit Facility
Unsecured senior notes:
6.5% senior notes due 2021
7.75% senior notes due 2023
5.25% senior notes due 2024
7.125% senior notes due 2026
Less net unamortized debt issue costs
Balance December 31, 2016
Changes from financing cash flows:
Proceeds from issue of senior notes
Redemption of senior notes
Payment of debt issue costs
Non-cash changes:
Loss on redemption of unsecured senior notes
Amortization of debt issue costs
Foreign exchange adjustment
Balance December 31, 2017
Changes from financing cash flows:
Redemption of senior notes
Non-cash changes:
Gain on redemption of unsecured senior notes
Amortization of debt issue costs
Foreign exchange adjustment
US$
US$
2018
— US$
2017
— $
2018
— $
2017
—
165,625
350,000
351,104
400,000
1,266,729 US$
248,625
350,000
400,000
400,000
1,398,625
$
226,113
477,823
479,331
546,084
1,729,351
(23,098)
1,706,253 $
312,601
440,062
502,928
502,928
1,758,519
(28,082)
1,730,437
Senior Credit
Facility
Unsecured
senior notes
$
— $
1,933,993 $
Debt issue
costs
(27,059) $
Total
1,906,934
—
—
—
—
—
—
—
—
509,180
(571,975)
—
(62,795)
9,021
—
(121,700)
1,758,519
—
—
(9,196)
(9,196)
509,180
(571,975)
(9,196)
(71,991)
—
8,173
—
(28,082)
9,021
8,173
(121,700)
1,730,437
—
(168,722)
—
(168,722)
—
—
—
— $
(5,672)
—
145,226
1,729,351 $
—
4,984
—
$
(23,098)
(5,672)
4,984
145,226
1,706,253
Balance December 31, 2018
$
(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$500.0 million with a provision for an increase
in the facility of up to an additional US$250.0 million (US$300.0 million after March 31, 2019). The Senior Credit Facility is
secured by charges on substantially all of the present and future assets of Precision, its material U.S. and Canadian
subsidiaries and, if necessary, to adhere to covenants under the Senior Credit Facility, certain subsidiaries organized in
jurisdictions outside of Canada and the U.S.
The Senior Credit Facility requires that Precision comply with certain financial covenants including a leverage ratio of
consolidated senior debt to consolidated Covenant EBITDA (as defined in the debt agreement) of less than 2.5:1. For
purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness. It also requires the
Corporation to maintain a ratio of consolidated Covenant EBITDA to consolidated interest expense for the most recent four
consecutive quarters, of greater than 2.0:1 for the periods ending December 31, 2018 and March 31, 2019. For periods ending
after March 31, 2019 the ratio reverts to 2.5:1.
75
Notes to Consolidated Financial Statements
The Senior Credit Facility prevents us from making distributions prior to April 1, 2019, after which, distributions are subject to a
pro-forma senior net leverage covenant of less than or equal to 1.75:1. The Senior Credit Facility also limits the redemption
and repurchase of junior debt subject to a pro-forma senior net leverage covenant test of less than or equal to 1.75:1.
In addition, the Senior Credit Facility contains certain restrictive covenants that limit Precision’s ability to incur 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, 2018, Precision was in compliance with the covenants of the
Senior Credit Facility.
The Senior Credit Facility has a term of four 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 November 21, 2022.
Under the Senior Credit Facility, amounts can be drawn in U.S. dollars and/or Canadian dollars and, as at December 31, 2018
and 2017 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 other currencies acceptable to the fronting lender. As at
December 31, 2018 outstanding letters of credit amounted to US$28.2 million (2017 – US$20.9 million).
The interest rate on loans that are denominated in U.S. dollars is, at the option of Precision, either a margin over a U.S. base
rate or a margin over LIBOR. The interest rate on loans denominated in Canadian dollars is, at the option of Precision, either a
margin over the Canadian prime rate or a margin over the bankers’ acceptance rate; such margins will be based on the then
applicable ratio of consolidated total debt to EBITDA.
(b) Unsecured Senior Notes:
Precision has outstanding the following unsecured senior notes:
6.5% US$ 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.
Precision may redeem these notes in whole or in part before December 15, 2019, at a redemption price of 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.
During 2018, Precision redeemed US$80.0 million and repurchased and cancelled US$3.0 million of these notes for an
aggregate purchase price of US$84.5 million. The difference was recognized as a loss on redemption of unsecured
senior notes within the consolidated statement of loss.
7.75% US$ senior notes due 2023
These notes bear interest at a fixed rate of 7.75% per annum and mature on December 15, 2023. Interest is payable
semi-annually on June 15 and December 15 of each year.
Prior to December 15, 2019, Precision may redeem up to 35% of the 7.75% senior notes due 2023 with the net
proceeds of certain equity offerings at a redemption price equal to 107.75% of the principal amount plus accrued
interest. Prior to December 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 December 15, 2019 redemption price plus required interest payments through
December 15, 2019 (calculated using the U.S. 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, 2019 and before
December 15, 2021, at redemption prices ranging between 103.875% and 101.938% of their principal amount plus
accrued interest. Any time on or after December 15, 2021, 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.
5.25% US$ 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.
Precision Drilling Corporation 2018 Annual Report
76
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 U.S. 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.
During 2018, Precision repurchased and cancelled US$48.9 million of these notes for an aggregate purchase price of
US$43.2 million. The difference was recognized as a gain on repurchase of unsecured senior notes within the
consolidated statement of loss.
7.125% US$ senior notes due 2026
These notes, issued in 2017, bear interest at a fixed rate of 7.125% per annum and mature on January 15, 2026.
Interest is payable semi-annually on January 15 and July 15 of each year, commencing July 15, 2018.
Prior to November 15, 2020, Precision may redeem up to 35% of the 7.125% senior notes due 2026 with the net
proceeds of certain equity offerings at a redemption price equal to 107.125% of the principal amount plus accrued
interest. Prior to November 15, 2020, 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 November 15, 2020 redemption price plus required interest payments through
November 15, 2020 (calculated using the U.S. Treasury rate plus 50 basis points) over the principal amount of the note.
As well, Precision may redeem these notes in whole or in part at any time on or after November 15, 2020 and before
November 15, 2022, at redemption prices ranging between 105.344% and 101.781% of their principal amount plus
accrued interest. Any time on or after November 15, 2023, 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.
The senior notes require that we comply with certain financial covenants including an incurrence based test of Consolidated
Interest Coverage Ratio, as defined in the senior note agreements, of greater than or equal to 2.0:1 for the most recent four
consecutive fiscal quarters. In the event that our Consolidated Interest Coverage Ratio is less than 2.0:1 for the most recent
four consecutive fiscal quarters the senior notes restrict our ability to incur additional indebtedness. As at December 31, 2018,
our senior notes Consolidated Interest Coverage Ratio was 2.80:1.
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. This restricted payment basket grows by, among other things,
50% of cumulative consolidated net earnings, and decreases by 100% of cumulative consolidated net losses as defined in the
note agreements, and cumulative payments made to shareholders. As at December 31, 2018, the governing restricted
payments basket was negative $496 million (2017 – negative $213 million), therefore prohibiting us from making any further
dividend payments until the governing restricted payments basket once again becomes positive. No dividends have been
declared or paid subsequent to December 31, 2018.
Our unsecured senior notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by all
U.S. and Canadian subsidiaries that guaranteed the Senior Credit Facility (Guarantor Subsidiaries). These Guarantor
Subsidiaries are directly or indirectly 100% owned by the parent company. Separate financial statements for each of the
Guarantor Subsidiaries have not been provided; instead we have included in Note 27 condensed consolidating financial
statements based on Rule 3-10 of the U.S. Securities and Exchange Commission’s Regulation S-X.
Long-term debt obligations at December 31, 2018 will mature as follows:
2021
2023
Thereafter
$
$
226,113
477,823
1,025,415
1,729,351
77
Notes to Consolidated Financial Statements
NOTE 11. OTHER RECOVERIES
For the period ended December 31, 2018, the Corporation had other recoveries of $14.2 million (2017 – nil) relating to the
recovery of Corporate transactions costs resulting from the termination of an arrangement agreement to acquire an oil and gas
drilling contractor.
NOTE 12. FINANCE CHARGES
Interest:
Long-term debt
Other
Income
Amortization of debt issue costs
Other
Finance charges
2018
121,810
378
(1,444)
6,434
—
127,178
$
$
2017
128,381
1,083
(1,858)
10,162
160
137,928
$
$
NOTE 13. SHARE BASED COMPENSATION PLANS
In May 2017 shareholders approved an omnibus equity incentive plan (Omnibus Plan) that allows the Corporation to settle
short-term incentive awards (annual bonus) and long-term incentive awards (options, performance share units and restricted
share units) issued on or after February 8, 2017 in voting shares of Precision (either issued from treasury or purchased in the
open market), cash, or a combination of both. Precision intends to settle all short-term incentive, restricted share unit and non-
executive performance share unit awards issued under the Omnibus Plan in cash and to settle performance share awards
issued to senior executives and all options in voting shares. No further grants will be made under the legacy stock option plan,
performance share unit plan or restricted share unit plan. Vesting conditions for incentive awards issued under the Omnibus
Plan are unchanged from what existed under the legacy plans.
Liability Classified Plans
Restricted
Share Units
Performance
Share Units
Share
Appreciation
Rights
Balance, December 31, 2016
Expensed (recovered) during the period
Payments
Balance, December 31, 2017
Expensed during the period
Payments
Balance, December 31, 2018
Current
Long-term
$
$
$
$
15,592 $
2,115
(10,757)
6,950
5,223
(6,764)
5,409 $
3,112 $
2,297
5,409 $
29,045 $
(4,188)
(13,450)
11,407
398
(7,284)
4,521 $
2,779 $
1,742
4,521 $
Non-
Management
Directors’
DSUs
4,602 $
(1,090)
—
3,512
769
(1,800)
2,481 $
— $
2,481
2,481 $
3 $
(3)
—
—
—
—
— $
— $
—
— $
Total
49,242
(3,166)
(24,207)
21,869
6,390
(15,848)
12,411
5,891
6,520
12,411
(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:
Precision Drilling Corporation 2018 Annual Report
78
December 31, 2016
Granted
Redeemed
Forfeited
December 31, 2017
Granted
Redeemed
Forfeited
December 31, 2018
RSUs
Outstanding
3,129,039
1,343,669
(1,404,271)
(271,579)
2,796,858
2,918,912
(1,404,284)
(255,572)
4,055,914
PSUs
Outstanding
6,493,798
828,400
(1,325,692)
(270,247)
5,726,259
1,292,550
(2,137,163)
(338,656)
4,542,990
(b) Share Appreciation Rights
The Corporation had 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. There were no SARs outstanding at December 31, 2018. The SARs vested over
a period of five years and expired 10 years from the date of grant. At December 31, 2018 and 2017 the intrinsic value of these
awards was $nil.
Range of
Exercise Price
Weighted
Average
Exercise
Share Appreciation Rights
December 31, 2016
Forfeited
December 31, 2017
Forfeited
December 31, 2018
Outstanding
(US$)
Price (US$) Exercisable
253,376
253,376 $ 15.22 – 15.79 $
15.22 – 17.38
(117,207)
15.22 – 15.22
136,169
15.22 – 15.22
(136,169)
— $
— $
15.47
15.75
15.22
—
—
136,169
—
(c) Non-Management Directors
Effective January 1, 2012, Precision instituted a 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
Balance December 31, 2016
Granted
Balance December 31, 2017
Granted
Redeemed
Balance December 31, 2018
Equity Settled Plans
Outstanding
621,821
331,456
953,277
474,766
(374,408)
1,053,635
(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, 2016 and 2017
Redeemed
December 31, 2018
Outstanding
195,743
(102,570)
93,173
79
Notes to Consolidated Financial Statements
(e) Option Plan
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, 2016
Granted
Forfeited
December 31, 2017
Granted
Forfeited
December 31, 2018
U.S. Share Options
December 31, 2016
Granted
Forfeited
December 31, 2017
Granted
Exercised
Forfeited
December 31, 2018
Options
Outstanding
Range of
Exercise Prices
6,188,672 $ 4.46 – 14.50 $
7.30 – 7.30
377,100
7.32 – 14.50
(1,665,412)
4.46 – 14.50
4,900,360
4.35 – 4.35
490,200
10.44 – 14.50
(657,404)
4,733,156 $ 4.35 – 14.31 $
Options
Outstanding
Range of
Exercise Prices
(US$)
5,337,070 $ 3.21 – 15.21 $
3.99 – 5.57
1,165,900
5.79 – 10.96
(944,349)
3.21 – 15.21
5,558,621
3.44 – 3.62
1,569,250
3.21 – 3.21
(66,000)
3.21 – 15.21
(996,021)
6,065,850 $ 3.21 – 10.74 $
Weighted
Average
Exercise
Options
Price
Exercisable
8.70 4,369,155
7.30
8.98
8.50 3,734,019
4.35
10.58
7.78 3,786,473
Weighted
Average
Exercise
Price
(US$)
Options
Exercisable
6.69 2,626,326
5.56
8.42
6.16 2,891,808
3.45
3.21
8.08
5.17 3,224,078
The weighted average share price at the date of exercise for the U.S. share options exercised in 2018 was US$4.02.
Canadian Share Options
Total Options Outstanding
Options Exercisable
Range of Exercise
Prices:
$ 4.34 – 6.99
7.00 – 8.99
9.00 – 14.31
$ 4.34 – 14.31
U.S. Share Options
Range of Exercise
Prices
(US$):
$ 3.21 – 3.99
4.00 – 6.99
7.00 – 10.74
$ 3.21 – 10.74
Weighted
Average
Number
1,105,400 $
1,539,001
2,088,755
4,733,156 $
Exercise Price
4.41
7.32
9.90
7.78
Weighted
Average
Remaining
Contractual Life
(Years)
5.04
3.58
1.12
2.83
Number
410,122 $
1,287,596
2,088,755
3,786,473 $
Weighted
Average
Exercise Price
4.46
7.33
9.90
8.43
Total Options Outstanding
Options Exercisable
Weighted
Average
Exercise Price
(US$)
Weighted
Average
Remaining
Contractual Life
(Years)
3.33
5.61
9.52
5.17
5.18
4.37
1.19
4.20
Number
3,046,950 $
1,924,500
1,094,400
6,065,850 $
Weighted
Average
Exercise Price
(US$)
3.21
5.66
9.52
6.22
Number
995,888 $
1,133,790
1,094,400
3,224,078 $
The per option weighted average fair value of the share options granted during 2018 was $1.96 (2017 – $1.59) estimated on
the grant date using the Black-Scholes option pricing model with the following assumptions: average risk-free interest rate of
2% (2017 – 1%), average expected life of four years (2017 – four years), expected forfeiture rate of 5% (2017 – 5%) and
expected volatility of 56% (2017 – 54%). Included in net loss for the year ended December 31, 2018 is an expense of $3.3
million (2017 – $3.2 million).
(f) Executive Performance Share Units
During 2018 Precision granted PSUs to certain senior executives with the intention of settling them in voting shares of the
Corporation either issued from treasury or purchased in the open market. These PSUs vest over a three year period and
Precision Drilling Corporation 2018 Annual Report
80
incorporate performance criteria established at the date of grant that can adjust the number of performance share units
available for settlement from zero to two times the amount originally granted. A summary of the activity under this share based
incentive plan is presented below:
December 31, 2016
Granted
December 31, 2017
Granted
Forfeited
December 31, 2018
Outstanding
— $
1,159,000
1,159,000
2,082,800
(50,733)
3,191,067 $
Weighted
Fair Value
—
6.00
6.00
6.22
6.12
6.14
The per unit weighted average fair value of the performance share units granted during 2018 was $6.22 (2017 – $6.00)
estimated on the grant date using a Monte Carlo simulation with the following assumptions: share price of $4.29 (2017 –
$5.08), average risk-free interest rate of 2.3% (2017 – 1.2%), average expected life of three years (2017 – three years),
expected volatility of 59% (2017 – 60%), and an expected dividend yield of nil (2017 – nil). Included in net loss for year ended
December 31, 2018 is an expense of $5.9 million (2017 - $1.9 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 2018, the Corporation recorded compensation
expense of $0.7 million (2017 – $0.8 million) related to this plan.
NOTE 14. 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 for the years ended December 31, is as follows:
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
Income tax recovery
$
$
$
2018
(323,596) $
27%
(87,371) $
49,455
(845)
—
4,861
1,061
3,803
(290)
(29,326) $
2017
(232,057)
27%
(62,655)
2,672
(175)
(42,334)
(2,814)
1,165
(618)
4,738
(100,021)
81
Notes to Consolidated Financial Statements
On December 22, 2017, the United States government enacted new tax legislation which affects the taxation of Precision’s
U.S. subsidiaries. In additional to changing certain U.S. federal income tax laws, this new tax legislation reduced the U.S.
federal income tax rate from 35% to 21% effective January 1, 2018. For the period ending December 31, 2017 Precision
recorded a $15.8 million deferred income tax expense on the revaluation of its U.S. subsidiaries net deferred income tax
assets which incorporates the reduction in the U.S. federal income tax rate and the expected impact of other applicable
provisions within the new U.S tax legislation. The Corporation has also recognized a $2.4 million long-term receivable for the
recovery of its U.S. subsidiaries alternative minimum tax carryforward balance.
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
Debt issue costs
Partnership deferrals
Other
Offsetting of assets and liabilities
Deferred income tax assets:
Losses (expire from time to time up to 2037)
Partnership deferrals
Long-term incentive plan
Other
Offsetting of assets and liabilities
$
2018
2017
467,109 $
3,534
1,730
5,722
478,095
(405,316)
72,779
423,595
—
6,849
11,752
442,196
(405,316)
36,880
454,613
3,352
—
6,709
464,674
(345,763)
118,911
368,133
335
7,935
11,182
387,585
(345,763)
41,822
Net deferred income tax liability
$
35,899 $
77,089
Included in the deferred income tax assets is $33.2 million (2017 – $38.8 million) of tax-effected temporary differences related
to the Corporation’s U.S. operations.
The Corporation has certain loss carryforwards in U.S. and international locations for which it is unlikely that sufficient future
taxable income will be available. Accordingly, the Corporation has not recognized a deferred income tax asset on these losses
totaling $37.1 million.
The movement in temporary differences is as follows:
Property,
Plant and
Equipment
and
Partnership
Other
Deferred
Income Tax
Debt Issue
Long-Term
Incentive
Other
Deferred
Income Tax
Intangibles
Deferrals
Liabilities
Losses
Costs
Plan
Assets
Net
Deferred
Income Tax
Liability
Balance, December 31, 2016
Recognized in net loss
Effect of foreign currency exchange
differences
Balance, December 31, 2017
Recognized in net loss
Effect of foreign currency exchange
differences
Balance, December 31, 2018
$
$
$
629,967 $
(149,489 )
(16,447 ) $
16,112
6,159 $
545
(418,253 ) $
24,124
4,215 $
(863 )
(18,270 )
$
9,651
(12,753 ) $
1,230
174,618
(98,690 )
(25,865 )
454,613 $
(9,667 )
22,163
467,109 $
—
(335 ) $
2,065
—
1,730 $
5
6,709 $
(1,005 )
25,996
(368,133 ) $
(30,660 )
—
3,352 $
182
684
(7,935 ) $
1,325
341
(11,182 ) $
(139 )
1,161
77,089
(37,899 )
18
5,722 $
(24,802 )
(423,595 ) $
—
3,534 $
(239 )
(6,849 ) $
(431 )
(11,752 ) $
(3,291 )
35,899
On December 31, 2018, Precision had $2.0 million (2017 – $2.0 million) of unrecognized tax benefits that, if recognized, would
have a favourable impact on Precision’s effective income tax rate in future periods. Precision classifies interest accrued on
unrecognized tax benefits and income tax penalties as income tax expense. Included in the unrecognized tax benefit, as at
December 31, 2018 was interest and penalties of $0.5 million (2017 – $0.5 million).
Precision Drilling Corporation 2018 Annual Report
82
Reconciliation of Uncertain Tax Positions
Unrecognized tax benefits, beginning of year
Additions:
Prior year’s tax positions
Reductions:
Prior year’s tax positions
Unrecognized tax benefits, end of year
$
$
2018
1,980 $
60
—
2,040 $
2017
1,923
57
—
1,980
It is anticipated that approximately $2.0 million (2017 – $nil) 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 15. BANK INDEBTEDNESS
At December 31, 2018, Precision had available $40.0 million (2017 – $40.0 million) and US$15.0 million (2017 – US$15.0
million) under secured operating facilities, and a secured US$30.0 million (2017 – US$30.0 million) facility for the issuance of
letters of credit and performance and bid bonds to support international operations. As at December 31, 2018 and 2017, no
amounts had been drawn on any of the facilities. Availability of the $40.0 million and US$30.0 million facility were reduced by
outstanding letters of credit in the amount of $27.8 million (2017 – $20.8 million) and US$2.1 million (2017 – US$13.3 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 rate plus 80% of applicable margin, or Banker’s Acceptance plus 80% of applicable margin, or in combination, and
under the US$15.0 million facility at the bank’s prime lending rate.
NOTE 16. PROVISIONS AND OTHER
Balance December 31, 2016
Expensed during the year
Payment of deductibles and uninsured claims
Effects of foreign currency exchange differences
Balance December 31, 2017
Expensed during the year
Payment of deductibles and uninsured claims
Effects of foreign currency exchange differences
Balance December 31, 2018
Current
Long-term
$
$
2018
2,796 $
10,577
13,373 $
$
$
Workers’
Compensation
15,461
2,613
(3,929)
(913)
13,232
3,359
(4,271)
1,053
13,373
2017
3,146
10,086
13,232
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.
83
Notes to Consolidated Financial Statements
NOTE 17. 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, 2016 and 2017
Issued on redemption of non-management directors' DSUs
Options exercised – cash consideration
– reclassification from contributed surplus
Balance, December 31, 2018
Number
293,238,858 $
476,978 $
66,000
—
293,781,836 $
Amount
2,319,293
2,609
275
103
2,322,280
NOTE 18. PER SHARE AMOUNTS
The following tables reconcile the net loss and weighted average shares outstanding used in computing basic and diluted loss
per share:
Net 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
NOTE 19. ACCUMULATED OTHER COMPREHENSIVE INCOME
$
2018
(294,270) $
2018
293,560
—
293,560
2017
(132,036)
2017
293,239
—
293,239
Unrealized
Foreign Currency
Translation Gains
(Losses)
587,278 $
(146,545)
440,733
175,630
616,363 $
Foreign Exchange
Gain (Loss) on Net
Investment Hedge
(430,822)
121,699
(309,123)
(145,226)
(454,349)
$
$
$
$
Accumulated
Other
Comprehensive
Income
156,456
(24,846)
131,610
30,404
162,014
December 31, 2016
Other comprehensive loss
December 31, 2017
Other comprehensive income
December 31, 2018
NOTE 20. 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 2018 was $12.0 million (2017 – $10.4 million).
NOTE 21. 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
$
$
2018
6,732 $
5,562
722
13,016 $
2017
6,078
3,036
(3,945)
5,169
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.
Precision Drilling Corporation 2018 Annual Report
84
NOTE 22. 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
$
$
2018
13,496 $
36,639
17,797
67,932 $
2017
12,248
27,445
21,909
61,602
Certain leased properties were sublet by the Corporation.
The following amounts were recognized as expenses in respect of operating leases in the consolidated statements of loss:
Operating leases
Sub-lease recoveries
Capital Commitments
$
$
2018
17,187 $
(540)
16,647 $
2017
16,311
(441)
15,870
At December 31, 2018, the Corporation had commitments to purchase property, plant and equipment totaling $179.8 million
(2017 – $132.9 million). Payments of $88.0 million for these commitments are expected to be made in 2019, $73.6 million
in 2020 and $18.2 million in 2021.
NOTE 23. 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 $18.1 million of the
trade receivables amount at December 31, 2018 (2017 – $11.7 million).
The movement in the expected credit loss allowance 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
$
$
2018
2,596 $
483
(416)
(1,247)
54
1,470 $
2017
6,072
56
(3,296)
(30)
(206)
2,596
85
Notes to Consolidated Financial Statements
The ageing of trade receivables at December 31 was as follows:
Not past due
Past due 0 – 30 days
Past due 31 – 120 days
Past due more than 120 days
2018
Provision for
Gross
175,277 $
64,351
25,032
1,399
266,059 $
$
$
Impairment
— $
—
71
1,399
1,470 $
2017
Gross
92,880 $
66,723
19,410
2,016
181,029 $
Provision for
Impairment
—
—
580
2,016
2,596
(b) Interest Rate Risk
As at December 31, 2018 and 2017, all of Precision’s outstanding long-term debt 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. The Corporation
would have exposure to interest rates if it were to draw upon its Senior Credit Facility.
(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.
The following financial instruments were denominated in U.S. dollars:
2018
2017
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 loss
Impact of $0.01 change in the U.S. dollar to Canadian dollar
exchange rate on comprehensive loss
Canadian
Operations (1)
957
$
482
(20,655)
—
(19,216)
$
$
$
(192)
—
$
$
$
$
Foreign
Operations
49,302
181,609
(122,417)
(7,747)
100,747
—
1,007
$
$
$
Canadian
Operations (1)
$
1,720 $
—
(13,221)
—
(11,501) $
Foreign.
Operations
39,636
152,216
(98,008)
(8,023)
85,821
(115) $
— $
—
858
(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 and other contractual commitments as at December 31, 2018:
Accounts payable and accrued liabilities
Share based compensation
Long-term debt
Interest on long-term debt (1)
Commitments
Total
2019
$ 274,489
6,221
—
115,802
101,542
$ 498,054
$
2020
—
4,357
—
115,802
84,404
$ 204,563
$
2021
—
6,082
226,113
115,190
27,811
$ 375,196
$
2022
—
—
—
101,105
8,604
$ 109,709
2023 Thereafter
$
—
—
477,823
99,562
7,617
$ 585,002
$
—
—
1,025,415
101,457
17,797
$ 1,144,669
Total
$ 274,489
16,660
1,729,351
648,918
247,775
$ 2,917,193
(1) Interest has been calculated based on debt balances, interest rates, and foreign exchange rates in effect as at December 31, 2018 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,
2018 was approximately $1,548 million (2017 – $1,765 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.
Precision Drilling Corporation 2018 Annual Report
86
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.
NOTE 24. 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, 2018 and 2017, these ratios were as follows:
Long-term debt
Shareholders’ equity
Total capitalization
Long-term debt to long-term debt plus equity ratio
$
$
2018
1,706,253
1,557,752
3,264,005
0.52
$
$
2017
1,730,437
1,810,336
3,540,773
0.49
As at December 31, 2018, liquidity remained sufficient as Precision had $96.6 million (2017 – $65.1 million) in cash and
access to the US$500.0 million Senior Credit Facility (2017 – US$500.0 million) and $101.4 million (2017 – $96.6 million)
secured operating facilities. As at December 31, 2018, no amounts (2017 – US$ nil) were drawn on the Senior Credit Facility
with availability reduced by US$28.2 million (2017 – US$20.9 million) in outstanding letters of credit. Availability of the
$40.0 million secured operating facility and US$30.0 million secured facility for the issuance of letters of credit and
performance and bid bonds were reduced by outstanding letters of credit of $27.8 million (2017 – $20.8 million) and
US$2.1 million (2017 – US$ 13.3 million), respectively. There was no amount drawn on the US$15.0 million secured operating
facility.
NOTE 25. 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
87
Notes to Consolidated Financial Statements
$
$
$
$
$
$
$
$
2018
(32,709)
(7,504)
23,225
(16,988)
(17,880)
892
2018
264,589
47,426
60,321
372,336
2018
129,493
73,682
71,314
274,489
$
$
$
$
$
$
$
$
2017
(41,309)
(3,902)
(30,158)
(75,369)
(67,380)
(7,989)
2017
178,433
91,708
52,444
322,585
2017
87,436
58,550
63,639
209,625
Precision presents expenses in the consolidated statements of earnings by function with the exception of depreciation and
amortization and impairment of property, plant and equipment, which are presented by nature. Operating expense and general
and administrative expense would include $358.4 million and $7.2 million (2017 – $364.2 million and $13.5 million),
respectively, of depreciation and amortization 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
Other recoveries
$
$
$
$
2018
2017
728,101 $
422,359
15,598
1,166,058 $
1,067,871 $
112,387
(14,200)
1,166,058 $
580,482
433,827
1,934
1,016,243
926,171
90,072
—
1,016,243
NOTE 26. 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.
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.
NOTE 27. LONG-TERM DEBT GUARANTOR DISCLOSURE
Condensed Consolidating Statement of Financial Position as at December 31, 2018
Parent
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Consolidating
Adjustments
Total
Assets
Cash
Other current assets
Intercompany receivables
Investments in subsidiaries
Assets held for sale
Property, plant and equipment
Intangibles
Goodwill
Other long-term assets
Total assets
Liabilities and shareholders’ equity
Current liabilities
Intercompany payables and debt
Long-term debt
Other long-term liabilities
Total liabilities
Shareholders’ equity
Total liabilities and shareholders’ equity
$
4,522,964
—
28,626 $
4,798
37,138 $
308,450
51,616 1,887,405
68
19,658
55,430 2,541,060
1,853
33,548
—
—
46,620
—
$
$ 4,842,252
30,862 $
93,166
80,735
—
—
441,509
—
—
5,479
— $
3
(2,019,756)
(4,523,032)
—
96,626
406,417
—
—
19,658
613 3,038,612
35,401
—
39,329
$ 3,636,043
—
—
(12,770)
$ 4,696,982
651,751
$ (6,554,942)
$
42,211 $
1,918,306
1,706,253
88,983
3,755,753
190,239 $
60,101
—
13,160
263,500
941,229 4,578,752
$
$ 4,842,252
$ 4,696,982
49,712 $
41,349
—
503
91,564
560,187
651,751
— $
(2,019,756)
282,162
—
— 1,706,253
89,876
(2,032,526) 2,078,291
(4,522,416) 1,557,752
$ 3,636,043
(12,770)
$ (6,554,942)
Precision Drilling Corporation 2018 Annual Report
88
Condensed Consolidating Statement of Financial Position as at December 31, 2017
Parent
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Consolidating
Adjustments
Total
Assets
Cash
Other current assets
Intercompany receivables
Investments in subsidiaries
Property, plant and equipment
Intangibles
Goodwill
Other long-term assets
Total assets
Liabilities and shareholders’ equity
Current liabilities
Intercompany payables and debt
Long-term debt
Other long-term liabilities
Total liabilities
Shareholders’ equity
Total liabilities and shareholders’ equity
$
4,822,876
5,422 $
20,843 $
38,558
261,883
93,662 2,669,280
61
64,605 2,659,831
2,472
25,644
205,167
—
53,908
—
$
$ 5,858,024
38,816 $
76,221
84,861
—
449,917
—
—
3,051
— $
3
(2,847,803)
(4,822,937)
65,081
376,665
—
—
(529) 3,173,824
28,116
205,167
44,078
$ 3,892,931
—
—
(12,881)
$ 5,066,188
652,866
$ (7,684,147)
36,331 $
$
124,482 $
1,795,141 1,000,167
—
1,730,437
17,978
135,053
3,696,962 1,142,627
1,369,226 4,715,397
$
$ 5,858,024
$ 5,066,188
48,812 $
52,495
—
2,383
103,690
549,176
652,866
— $
(2,847,803)
209,625
—
— 1,730,437
142,533
(2,860,684) 2,082,595
(4,823,463) 1,810,336
$ 3,892,931
(12,881)
$ (7,684,147)
Condensed Consolidating Statement of Loss for the Year ended December 31, 2018
$
Revenue
Operating expense
General and administrative expense
Other recoveries
Earnings (loss) before income taxes, equity in loss
of subsidiaries, gain on redemption and repurchase of
unsecured senior notes, finance charges, foreign exchange,
impairment of goodwill and depreciation and amortization
Depreciation and amortization
Impairment of goodwill
Foreign exchange
Finance charges
Gain on redemption and repurchase of unsecured senior notes
Equity in loss of subsidiaries
Loss before income taxes
Income taxes
Net loss
Parent
Guarantor
Subsidiaries
104 $ 1,356,913 $
950,058
49,305
—
83
52,638
(14,200)
Non-
Guarantor
Subsidiaries
Consolidating
Adjustments
191,131 $
124,689
10,444
—
Total
(6,959) $ 1,541,189
(6,959) 1,067,871
112,387
(14,200)
—
—
(38,417)
6,882
—
4,819
126,758
(5,672)
168,975
(340,179)
(46,125)
357,550
298,019
207,544
(443)
(233)
—
—
(147,337)
13,863
$ (294,054) $ (161,200) $
55,998
60,542
—
(359)
653
—
—
(4,838)
2,936
(7,774) $
—
217
—
—
—
—
(168,975)
168,758
—
375,131
365,660
207,544
4,017
127,178
(5,672)
—
(323,596)
(29,326)
168,758 $ (294,270)
89
Notes to Consolidated Financial Statements
Condensed Consolidating Statement of Earnings (Loss) for the Year ended December 31, 2017
Parent
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
89 $ 1,138,049 $
809,233
44,932
138
35,605
190,401 $
124,115
9,535
Consolidating
Adjustments
Total
(7,315) $ 1,321,224
926,171
(7,315)
90,072
—
$
Revenue
Operating expense
General and administrative expense
Earnings (loss) before income taxes, equity in loss of
subsidiaries, loss on redemption and repurchase of
unsecured senior notes, finance charges, foreign
exchange, impairment of property, plant and equipment
and depreciation and amortization
Depreciation and amortization
Impairment of property, plant and equipment
Foreign exchange
Finance charges
Loss on redemption and repurchase of unsecured senior notes
Equity in loss of subsidiaries
Loss before income taxes
Income taxes
Net income (loss)
(35,654)
13,118
—
(2,375)
138,027
9,021
(12,383)
(181,062)
(47,567)
$ (133,495) $
283,884
302,958
15,313
(889)
(68)
—
—
(33,430)
(59,120)
25,690 $
56,751
61,450
—
294
(31)
—
—
(4,962)
6,666
(11,628) $
—
220
—
—
—
—
12,383
(12,603)
—
304,981
377,746
15,313
(2,970)
137,928
9,021
—
(232,057)
(100,021)
(12,603) $ (132,036)
Condensed Consolidating Statement of Comprehensive Income (Loss) for the Year ended December 31, 2018
Net loss
Other comprehensive income (loss)
Comprehensive Income (loss)
Parent
(294,054)
(145,226)
$ (439,280) $
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
(161,200)
129,804
(31,396) $
(7,774)
45,190
37,416 $
Consolidating
Adjustments
Total
168,758 $ (294,270)
30,404
169,394 $ (263,866)
636
Condensed Consolidating Statement of Comprehensive Loss for the Year ended December 31, 2017
Net income (loss)
Other comprehensive income (loss)
Comprehensive loss
$ (133,495) $
121,699
(11,796) $
$
25,690 $
(110,717)
(85,027) $
(11,628) $
(35,661)
(47,289) $
Condensed Consolidating Statement of Cash Flow for the Year ended December 31, 2018
Parent
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Consolidating
Adjustments
Total
(12,603) $ (132,036)
(24,846)
(12,770) $ (156,882)
(167)
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 and cash equivalents, end of year
Parent
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$ (102,901) $
277,501
(169,085)
351,782 $
(75,740)
(247,017)
44,453 $
(16,253)
(39,285)
— $
(286,302)
286,302
293,334
(100,794)
(169,085)
2,268
7,783
20,843
28,626 $
2,691
31,716
5,422
37,138 $
3,131
(7,954)
38,816
30,862 $
$
—
—
—
— $
8,090
31,545
65,081
96,626
Precision Drilling Corporation 2018 Annual Report
90
Condensed Consolidating Statement of Cash Flow for the Year ended December 31, 2017
Cash provided by (used in):
Operations
Investments
Financing
Effects of exchange rate changes on cash and cash
equivalents
Decrease in cash and cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
NOTE 28. 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.
Parent
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Consolidating
Adjustments
Total
$ (160,698) $
191,638
(73,784)
243,364 $
(58,942)
(190,360)
33,889 $
(11,152)
(22,334)
— $
(212,694)
212,694
116,555
(91,150)
(73,784)
1,893
(40,951)
61,794
20,843 $
(1,778)
(7,716)
13,138
5,422 $
(2,360)
(1,957)
40,773
38,816 $
$
—
—
—
— $
(2,245)
(50,624)
115,705
65,081
Ownership Interest
Country of
Incorporation
Canada
Canada
Canada
Canada
United States
United States
United States
United States
Barbados
Barbados
2018
100
100
100
100
100
100
100
100
100
100
2017
100
100
100
100
100
100
100
100
100
100
91
Notes to Consolidated Financial Statements
Supplemental Information
Precision
Drilling
Corporation
Consolidated Statements of Earnings (Loss)
Years ended December 31,
(Stated in millions of Canadian dollars, except per share amounts)
Revenue(1)
Expenses:
Operating(1)
General and administrative(1)
Other
Restructuring
Earnings (loss) before taxes, loss on redemption and
repurchase of unsecured senior notes, finance charges, foreign
exchange, loss on asset decommissioning, gain on re-measurement
of property, plant and equipment, impairment of property, plant and
equipment, impairment of goodwill and depreciation and
amortization
Depreciation and amortization
Impairment of goodwill
Impairment of property, plant and equipment
Gain on re-measurement of property, plant and equipment
Loss on asset decommissioning
Foreign exchange
Finance charges
Loss on redemption and repurchase of unsecured senior notes
Earnings (loss) before income taxes
Income taxes
Net earnings (loss)
Earnings (loss) per share:
$
2018
1,541
$
2017
1,321
$
2016
1,003
$
2015
1,635
$
2014
2,488
$
1,068
112
(14)
-
375
366
207
-
-
-
4
127
(6)
(323)
(29)
(294)
$
926
90
-
305
378
-
15
-
-
(3)
138
9
(232)
(100)
(132)
662
107
6
1,021
119
1,564
124
21
-
228
392
-
-
(8)
-
6
147
-
(309)
(153)
(156)
$
474
487
17
282
-
166
(33)
121
-
(566)
(203)
(363)
$
800
448
95
-
-
127
(1)
110
-
21
(12)
33
$
Basic
Diluted
(1.00)
(1.00)
(0.45)
(0.45)
(0.53)
(0.53)
(1.24)
(1.24)
0.11
0.11
(1) For years prior to 2017 comparatives have changed to conform to current year presentation.
Precision Drilling Corporation 2018 Annual Report
92
Additional Select Financial Information
Years ended December 31,
(Stated in millions of Canadian dollars, except per share amounts)
Return on sales - %(1)
Return on assets - %(2)
Return on equity - %(3)
Working Capital
Current ratio
Property, plant and equipment
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)
Operating earnings (loss) - % of revenue
Cash provided by operations
Cash provided by operations per share:
Basic
Diluted
Book value per share(5)
Price earnings (loss) ratio(6)
Basic weighted average shares outstanding (millions)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2018
(19.1)
(8.1)
(0.2)
248
1.9
3,039
3,636
1,706
1,558
0.5
(1.6)
$
102
375
$
24.3%
(198)
$
(0.1)
293
$
$
2017
(10.0)
(3.4)
(0.1)
232
2.1
3,174
3,893
1,730
1,810
0.5
(0.6)
$
83
305
$
23.1%
$
$
$
$
$
(88)
(0.1)
117
$
$
$
$
$
$
$
$
$
2016
(15.6)
(3.6)
(7.7)
231
2.0
3,642
4,324
1,907
1,962
0.5
(1.1)
$
196
228
$
22.7%
(156)
$
(0.2)
123
$
$
$
$
$
$
2015
(22.2)
(7.0)
(15.3)
654
2.3
3,887
4,879
2,181
2,121
0.5
(4.0)
$
449
474
$
29.0%
(478)
$
(0.3)
517
$
$
$
$
0.42
0.42
6.69
(13.8)
293
$
$
$
1.77
1.77
7.24
(4.4)
293
2014
1.3
0.7
1.3
306
1.9
3,932
5,309
1,852
2,441
0.4
1.2
755
800
32.2%
130
0.1
680
2.33
2.32
8.34
64.2
293
$
$
$
1.00
1.00
5.31
(3.8)
294
0.40
0.40
6.17
(8.5)
293
(1) Return on sales was calculated by dividing earnings (loss) 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.
93
Supplemental Information
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
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
2018 TRADING PROFILE
Toronto (TSX: PD)
High: $5.33
Low: $2.25
Close: $2.37
Volume Traded: 514,932,362
New York (NYSE: PDS)
High: US$4.14
Low: US$1.62
Close: US$1.74
Volume Traded: 475,910,527
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
at
www.sedar.com and on the EDGAR
website at www.sec.gov.
SEDAR
website
the
PUBLISHED INFORMATION
Please contact us if you would like
additional copies of this annual report,
or copies of our 2018 annual
the
information
Canadian securities commissions and
under Form 40-F with
the U.S.
Securities and Exchange Commission:
filed with
form as
Investor Relations
Suite 800, 525 – 8th Avenue SW
Calgary, Alberta, Canada
T2P 1G1
Telephone: 403.716.4500
Precision Drilling Corporation 2018 Annual Report
94
Corporate Information
DIRECTORS
Michael R. Culbert(1)(3)
Calgary, Alberta, Canada
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
Steven W. Krablin(1)(2)(3)
Spring, Texas, USA
Susan M. MacKenzie(2)(3)
Calgary, Alberta, Canada
Kevin O. Meyers(2)(3)
Anchorage, Alaska, USA
Kevin A. Neveu
Houston, Texas, USA
David W. Williams(1)(3)
Houston, Texas, USA
1. Member of Audit Committee
2. Member of Corporate Governance, Nominating
and Risk Committee
3. Member of Human Resources and
Compensation Committee
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
OFFICERS
Kevin A. Neveu
President and
Chief Executive Officer
Doug B. Evasiuk
Senior Vice President,
Sales and Marketing
Veronica H. Foley
Senior Vice President, General
Counsel and Corporate Secretary
Cary T. Ford
Senior Vice President and
Chief Financial Officer
Shuja U. Goraya
Chief Technology Officer
Darren J. Ruhr
Chief Administrative Officer
Gene C. Stahl
President, Drilling Operations
95
Corporate Information
Precision Drilling Corporation
Suite 800, 525 – 8th Avenue SW
Calgary, Alberta, Canada T2P 1G1
Phone: 403.716.4500
Email: info@precisiondrilling.com www.precisiondrilling.com