pds-ex992_10.htm

This Management’s Discussion and Analysis (MD&A) contains information to help you understand our business and financial performance. Information is as of March 12, 2021. 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 47. In this MD&A, we reference additional non-generally accepted accounting principles (Non-GAAP) measures that are not defined terms under IFRS to assess performance because we believe they provide useful supplemental information to investors. Our Non-GAAP measures are defined on page 48.

The terms we, us, our, Corporation, Company, Precision and Precision Drilling mean Precision Drilling Corporation and our subsidiaries and include any partnerships that we are part.

Precision has partnered with several industry leaders to develop its digital portfolio consisting of AlphaAutomation^TM, AlphaApps^TM and AlphaAnalytics^TM, which delivers efficient, predictable and repeatable results through enhanced drilling performance.

Precision Drilling Corporation provides onshore drilling and completion and production services to exploration and production companies in the oil and natural gas industries. Headquartered in Calgary, Alberta, Canada, we are a leading North American drilling company. We also have operations in the Middle East. Our shares trade on the Toronto Stock Exchange under the symbol PD and on the New York Stock Exchange under the symbol PDS.

From our founding as a private drilling contractor in 1951, Precision has grown to become one of the most active drillers in North America. Our High Performance, High Value competitive advantage is underpinned by four distinguishing features:

In 2020, we continued to reinforce our steady focus on corporate responsibility by leveraging our long history of strong corporate governance and maintaining an unwavering commitment to responsibly operating our business. With the support and oversight of our Board of Directors (Board), we are committed to conduct our business in ways that are ethical, transparent and accountable to stakeholders. We believe a transparent culture of corporate governance and ethical behaviour in decision-making is fundamental to the way we do business. For specific information regarding Environmental, Social and Governance (ESG) matters, we invite you to review our Corporate Responsibility initiatives in our Annual Information Form, dated March 15, 2021.

We have a diverse and experienced 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, the United States (U.S.) and internationally. Our Board also annually 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 carry out its responsibilities effectively:

The Board may also create special ad hoc committees from time to time to deal with important matters that arise.

Management has also established internal committees, including an Enterprise Risk Management Committee, a Compliance Committee, a Disclosure Committee and a Health, Safety, Environment and Corporate Responsibility Council (HSE and Corporate Responsibility Council). Two of our directors, Dr. Meyers and Ms. MacKenzie, are active members of the HSE and Corporate Responsibility Council and attend quarterly meetings.

You can find more information about our approach to governance in our Management Information Circular, available on our website (www.precisiondrilling.com).

We operate our business in two segments, supported by vertically integrated business and corporate support systems.

Precision Drilling Corporation Contract Drilling Services Drilling Rig Operations Canada U.S. International Directional Drilling Operations Canada Completion and Production Services Canada and U.S. Service Rigs Canada Camps and Catering Equipment Rentals Business Support Systems Sales and Marketing Procurement and Distribution Manufacturing Equipment Maintenance and Certification Engineering Corporate Support Information Systems Health, Safety and Environment Human Resources Finance Legal and Enterprise Risk Management

2020 Revenue by Segment Contract Drilling Services Completion and Production Services 8% 92% 2020 Revenue by Location U.S. Canada International 47% 20% 33%

We provide onshore drilling services to exploration and production companies in the oil and natural gas and geothermal industries, operating in Canada, the U.S. and internationally.

We are a large, multi-basin oilfield operator servicing approximately 33% of the active land drilling market in Canada and 8% of the active U.S. market. We also have an international presence with operations in the Middle East.

At December 31, 2020, we had 227 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 AC power, digital control systems, integrated top drives, omni-directional pad walking systems for multi-pad well drilling, highly mechanized pipe handling, and high-capacity mud pumps.

Contract Drilling Revenue $ Millions $1,500 $1,200 $900 $600 $300 0 2016 2017 2018 2019 2020 Contract Drilling Adjusted EBITDA $ Millions $500 $400 $300 $200 $100 0 2016 2017 2018 2019 2020 Contract Drilling Utilization Days Hours 50,000 40,000 30,000 20,000 10,000 0 2016 2017 2018 2019 2020

We provide well completion, workover, abandonment and re-entry preparation services to oil and natural gas exploration and production companies in Canada and the U.S. In addition, we provide equipment rentals and camp and catering services in Canada.

On an operating hour basis in 2020, we serviced approximately 10% of the well completion and workover service rig market demand in Canada and 1% in the U.S.

At December 31, 2020, our Completion and Production Services segment consisted of:

At December 31, 2020, we had 75 additional well completion and workover service rigs in Canada that were not registered with the industry association.

Completion and Production Revenue $ Millions $200 $150 $100 $50 0 2016 2017 2018 2019 2020 Completion and Production Adjusted EBITDA $ Millions $25 $20 $15 $10 $5 0 -$5 2016 2017 2018 2019 2020 Completion and Production Service Rig Hours Hours 200,000 150,000 100,000 50,000 0 2016 2017 2018 2019 2020

In March 2020, the Novel Coronavirus (COVID-19) outbreak was declared a pandemic by the World Health Organization. Governments worldwide, including those countries in which Precision operates, have enacted emergency measures to combat the spread of the virus. These measures, which include the implementation of lockdowns, travel bans, quarantine periods and social distancing, have caused a material disruption to businesses globally resulting in an economic slowdown and decreased demand for oil. Governments and central banks have reacted with significant monetary and fiscal interventions designed to stabilize economic conditions; however, the long-term success of these interventions is not yet determinable.

As a result of the decrease in demand, worldwide inventories of oil increased significantly. However, voluntary production restraint from national oil companies and governments of oil-producing nations along with curtailments in the U.S. and Canada have shifted global oil markets from a position of over supply to inventory draws. The situation remains dynamic and the ultimate duration and magnitude of the impact on the economy and the financial effect on Precision remains unknown at this time.

The current challenging economic climate has or may have significant adverse impacts on Precision including, but not exclusively:

Our estimates and judgements made in the preparation of our financial statements are increasingly difficult and subject to a higher degree of measurement uncertainty during this volatile period. Precision took the following measures to align our cost structure and maximize cash preservation during the current market conditions, including:

We review the carrying value of our long-lived assets for indications of impairment at the end of each reporting period. At March 31, 2020, we tested all cash-generating units (CGU) for impairment and no impairment charges were identified. At December 31, 2020, we reviewed each CGU and did not identify any indications of impairment. Accordingly, we did not test our CGUs for impairment.

During the pandemic, in regions where the local authorities have ordered non-essential business closures and implemented “stay at home” orders, the oil and natural gas extractive services industry has been classified as an “essential service.” As a result, Precision’s operations remain open. This includes all of Precision’s field operations, technical support centres and administration groups. The vertical integration of our operations has resulted in minimal supply chain constraints and disruptions during the pandemic.

To manage the additional safety risks presented by COVID-19, Precision implemented a comprehensive infectious disease plan to keep our field crews, support staff and customers safe and well-informed. Precision has implemented additional safety, sanitization and physical distancing procedures, including remote work sites where possible and ceased all non-essential business travel. Precision’s procedures are in accordance with recommendations from the World Health Organization, Center for Disease Control and various federal, state and provincial government health authorities.

Despite the enormous challenges posed by COVID-19, we maintained our strong liquidity position. We exited the year with a cash balance of $109 million and $552 million of available borrowing capacity under our secured credit facilities, providing us with $661 million of total liquidity as compared with $725 million at December 31, 2019. To provide additional liquidity, we established a Real Estate Credit Facility in the amount of US$11 million in the fourth quarter of 2020.

At December 31, 2020, our available borrowing capacity of $552 million was comprised of our Senior Credit Facility of US$500 million less drawn amounts of US$75 million and US$32 million of outstanding letters of credit, our undrawn Canadian operating facility of $40 million less $7 million of outstanding letters of credit and our undrawn U.S. operating facility of US$15 million. Our available borrowing capacity calculation excludes our US$30 demand letter of credit facility.

We expect that cash provided by operations, cash on hand and our sources of financing, including our Senior Credit Facility, will be sufficient to meet our debt obligations and fund committed and future capital expenditures.

In response to COVID-19, on April 9, 2020, we agreed with the lenders of our Senior Credit Facility to amend our interest expense coverage ratio financial covenant in future periods. The amending agreement also restricts Precision’s distributions in the form of dividends, distributions and share repurchases. Despite obtaining financial covenant relief on our Senior Credit Facility through March 31, 2022, if the global economic slowdown continues for a prolonged period, there may be an increased risk to Precision’s ability to comply with these financial covenants.

Additional discussion of amendments to our Senior Credit Facility can be found on page 30.

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.

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.

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 are 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 continued development of liquefied natural gas (LNG) in the U.S. and planned export from Canada could serve as a catalyst for natural gas directed drilling activity over the medium to long term.

	2020		2019		2018
Oil
West Texas Intermediate (per barrel) (US$)		39.40		57.07		64.88
Western Canadian Select (per barrel) (US$)		35.59		44.28		38.46

Natural gas
U.S.
Henry Hub (per MMBtu) (US$)		2.13		2.56		3.12
Canada
AECO (per MMBtu) (Cdn$)		2.24		1.77		1.49
Source: WTI and Henry; Hub Energy Information Administration, AECO; Gas Alberta Inc.

North American exploration and production companies, which comprise the majority of our customer base, have been increasingly focused on enhancing operational efficiency within their drilling and completion programs. 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, digital AC controls and increased fluid pumping capacity. More recently, customers have shifted focus to digital offerings that deliver increased efficiency, consistency and predictability of results in their development-style drilling programs. Exploration and production companies have displayed an appetite for these technologies as they provide an opportunity to significantly reduce drilling times and improve overall wellbore quality.

Our technology strategy is well-aligned with customer efficiency objectives. We currently leverage our existing base of digital AC control systems installed on all of our Super Triple drilling rigs. Our standardized rig fleet enables us to reliably mass deploy our advanced digital platform capable of delivering leading-edge digital automation and significantly boosting efficiency of the well construction process. Our technology strategy is centered around partnering with industry experts which allows us to deliver an extensive suite of offerings to our customers with minimal research and development capital. Over the last five years, Precision has heavily invested in field-hardening its digital offering and training key personnel, which has allowed the company to commercialize its Alpha portfolio throughout North America. Our digital technology strategy is currently focused on four fundamentals:

We leverage our standardized fleet to deploy our fully integrated AlphaAutomation^TM system (AlphaAutomation^TM), which allows us to consistently implement best practices to eliminate human variance, resulting in significantly improved drilling efficiency. In addition to built-in process automation routines, AlphaAutomation^TM also hosts Precision Drilling Apps (AlphaApps^TM), which leverage advanced algorithms and exploitation of various machine learning techniques to improve complex down-hole 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 natural gas industry. We installed our first AlphaAutomation^TM system in late 2016 and currently have 39 commercialized AlphaAutomation^TM systems deployed in the field which have drilled over 1,800 wells to date. We intend to deploy additional AlphaAutomation^TM systems in North America in 2021, further strengthening our digital leadership position.

Our open platform is capable of supporting internal, customer or third party developed applications, designed to further enhance the overall drilling function. To date, Precision has 18 available AlphaApps^TM, six commercialized, which execute multiple on-bottom, cost control and equipment optimization functions. These specialized apps maximize the performance of the entire drilling process, resulting in increased drilling performance and cost efficiencies for our customers.

Our digital platform captures more than 1 GB/min of data, versus a limited number of data channels from traditional Electronic Data Recorders, known as EDR systems. We have a robust data analytics offering (AlphaAnalytics^TM) focused on improving rig performance and financial returns through commercialization of performance data to drive optimization and performance KPI’s. To date, AlphaAnalytics^TM has generated successful results in trials, setting new efficiency benchmarks for several large customers across multiple basins.

In 2018, we implemented SAP S/4HANA to fully realize the benefits of the system’s integration with our digital service delivery platform. This robust SAP enterprise resource planning (ERP) system is built to support the increased data flows from the field. Precision remains committed to its digital technology strategy which has enabled us to build a strong digital mindset throughout the company.

The combination of our High Performance standardized rig fleet, integrated AlphaAutomation^TM systems, AlphaApps^TM and AlphaAnalytics^TM position us to help our customers achieve their efficiency goals and generate strong returns for our shareholders through service differentiation.

North American drilling activity steeply declined early in the second quarter of 2020 as reduced global oil demand caused by COVID-19 and prolonged periods of commodity price volatility spurred significant reductions in customer spending. In 2020 approximately 8,400 wells were started onshore in the U.S., compared with approximately 18,000 in 2019 and 19,300 in 2018. The industry drilled 2,960 wells in western Canada in 2020, compared with 4,679 in 2019 and 6,781 in 2018. Total industry drilling operating days were 29,741 in 2020 compared with 45,334 in 2019 and 64,491 in 2018. In Canada, there has been relative strength in natural gas liquids and tight light 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.

The graphs below show the shift in drilling activity to oil targets since 2017, 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 Source: Baker Hughes Oil Land Natural Gas Land Rigs Working 900 600 300 0 Jan - 16 Jan - 17 Jan - 18 Jan - 19 Jan - 20 Jan - 21 Canadian Active Rig Count Source: Baker Hughes Oil Land Natural Gas Land Rigs Working 300 200 100 0 Jan - 16 Jan - 17 Jan - 18 Jan - 19 Jan - 20 Jan - 21

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 represents 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 striving to generate superior financial returns for our investors.

We keep customer well costs down by maximizing the efficiency of operations in several ways:

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 125 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 digital technology delivery to the well location. Precision has completed 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 AlphaAutomation^TM and AlphaApps^TM technology. Precision’s Super Series drilling rig fleet meets the industrial-style drilling requirements of our customers in North America and deep, high-pressure/high-temperature drilling projects internationally. As of December 31, 2020, we had 227 Super Series rigs in our fleet.

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.

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.

We unitize key financial information per day 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:

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.

Safety and employee health are critical for us and for our customers and are the foundation of our culture.

Total Recordable Incident Rate 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.

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. We had 325 Triple Target Zero Days in 2020.

We foster our safety culture through strong leadership, technical and compliance training, and proven support systems. Every day, we invest in our field 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. These facilities are used to train employees on our culture, responsibilities, tools and equipment, safety and environmental protocol and procedures, leadership and team building.

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, critical sour gas well work and well re-entry preparation across the Western Canada Sedimentary Basin and in the northern U.S. Our service rigs are supported by four field locations in Alberta, two in Saskatchewan, and one each in Northwest Territories, British Columbia and North Dakota.

We continuously review our rig designs and components and use advanced technology to operate safely, improve our equipment life cycle, maintain operational efficiency and reduce energy use. In 2020, approximately 25% of our fleet was configured to be powered by natural gas, which is cleaner-burning than diesel and therefore reduces our customer’s emissions 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.

We leverage our internal manufacturing and repair capabilities and inventory of quality rigs to address market demand through upgraded drilling rigs. Upgrades are typically performed at the request of a customer and are secured by a term contract. Historically, certain upgrades have resulted in a change in classification to Super Series.

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.

We operate two contract drilling technical centres, one in Nisku, Alberta and one in Houston, Texas, and one completion and production services technical centre in Red Deer, Alberta. These centres accommodate our technical service and field training groups and consolidate field support and training for our operations. The Houston and Nisku facilities have fully-functioning training rigs with the latest drilling technologies. Also, our Houston facility accommodates our rig manufacturing group.

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.

Our ERP system is fully integrated with our drilling rigs, field facilities and corporate offices, increasing operating efficiencies and better positions the organization to capture and analyze increased data flow within 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 more timely processing and accuracy of data. 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.

Corporate Responsibility is integral to Precision’s vision, mission, and competitive strategy as we believe that operating a sustainable and responsible company is critical to our long-term success. We believe our Corporate Responsibility approach and initiatives drive business execution and create a competitive advantage. Precision’s High Performance, High Value competitive strategy is supported by and reliant upon safety performance, environmental stewardship, employee well-being and training and community involvement. Our employees, investors and customers reward our commitment to Corporate Responsibility and recognize that it provides us the ability to attract talent, capital and a premium for our services. For specific information regarding ESG matters, we invite you to review our Corporate Responsibility initiatives in our Annual Information Form, dated March 15, 2021.

Our Corporate and Competitive Strategies are designed to optimize resource allocation and differentiate us from the competition, generating value for investors. Unconventional drilling remains 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 our Super Series rig fleet, High Performance, High Value strategy and Alpha Technologies offering, positions us to benefit from that trend. In addition, the completion and production work associated with unconventional wells provides the most profitable growth opportunities for our Completion and Production Services segment.

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. We summarized the results of our 2020 strategic priorities.

Adjusted EBITDA, operating earnings (loss), funds provided by (used in) operations and working capital are Non-GAAP measures. See page 48 for more information.

Year ended December 31 (in thousands of dollars, except where noted)	2020			% increase/ (decrease)			2019			% increase/ (decrease)			2018			% increase/ (decrease)
Revenue		935,753			(39.3	)		1,541,320			0.0			1,541,189			16.6
Adjusted EBITDA		263,403			(32.7	)		391,305			4.3			375,131			23.0
Adjusted EBITDA % of revenue		28.1	%					25.4	%					24.3	%
Net earnings (loss)		(120,138	)		(1,915.3	)		6,618			(102.2	)		(294,270	)		122.9
Cash provided by operations		226,118			(21.5	)		288,159			(1.8	)		293,334			151.7
Funds provided by operations		170,727			(41.7	)		292,652			(6.0	)		311,214			69.2
Investing activities
Capital spending
Expansion and upgrade		26,858			(77.8	)		120,910			82.6			66,201			35.0
Maintenance and infrastructure		34,677			(11.0	)		38,976			(19.4	)		48,375			87.6
Intangibles		57			(92.9	)		808			(93.0	)		11,567			(50.1	)
Proceeds on sale		(21,094	)		(76.8	)		(90,768	)		271.1			(24,457	)		64.8
Net capital spending		40,498			(42.1	)		69,926			(31.2	)		101,686			22.3
Earnings (loss) per share ($)
Basic		(8.76	)		(2,004.3	)		0.46			(102.3	)		(20.05	)		122.2
Diluted		(8.76	)		(2,046.7	)		0.45			(102.2	)		(20.05	)		122.2

Year ended December 31	2020		% increase/ (decrease)			2019		% increase/ (decrease)			2018		% increase/ (decrease)
Contract drilling rig fleet		227		0.4			226		(4.2	)		236		(7.8	)
Drilling rig utilization days
U.S.		12,080		(54.5	)		26,544		(0.6	)		26,714		30.4
Canada		10,794		(25.5	)		14,498		(22.1	)		18,617		(1.4	)
International		2,526		(18.3	)		3,093		5.9			2,920		—
Revenue per utilization day
U.S. (US$)		26,184		11.9			23,397		7.0			21,864		10.1
Canada (Cdn$)		21,611		0.2			21,569		(0.3	)		21,644		2.4
International (US$)		54,811		6.7			51,360		1.8			50,469		0.5
Operating cost per utilization day
U.S. (US$)		14,666		1.5			14,447		0.8			14,337		3.5
Canada (Cdn$)		13,546		(11.1	)		15,240		5.2			14,493		10.3

Service rig fleet		123		—			123		(41.4	)		210		—
Service rig operating hours		81,952		(44.3	)		147,154		(6.5	)		157,467		(8.9	)

(in thousands of dollars, except ratios)	December 31, 2020		December 31, 2019		December 31, 2018
Working capital⁽¹⁾		175,423		201,696		240,539
Working capital ratio		2.1		1.9		1.9
Long-term debt⁽²⁾		1,236,210		1,427,181		1,706,253
Total long-term financial liabilities		1,304,162		1,500,950		1,723,350
Total assets		2,898,878		3,269,840		3,636,043
Enterprise value⁽³⁾		1,409,147		1,854,393		2,305,890
Long-term debt to long-term debt plus equity		0.5		0.5		0.5
Long-term debt to cash provided by operations		5.5		5.0		5.8

⁽³⁾^{Share price multiplied by the number of shares outstanding plus long-term debt minus cash. See page}³²^{for more information.}

2020 was overshadowed by significant decreases in industry activity and extreme commodity price volatility. In the U.S., West Texas Intermediate (WTI) oil prices averaged US$39.40 per barrel and Henry Hub natural gas prices averaged US$2.13 per MMBtu, representing a decrease of 31% and 17% from 2019, respectively. In Canada, Western Canadian Select (WCS) and AECO natural gas price averaged US$35.59 and $2.24 in 2020, respectively. Average WCS pricing was 20% lower than 2019 while AECO increased by 27%. Volatile commodity prices and uncertain outlook on global oil demand caused by the COVID-19 pandemic resulted in conservative customer spending and significant decreases to the active industry rig count in 2020.

For the year ended December 31, 2020, our net loss was $120 million, or a net loss of $8.76 per diluted share, compared with 2019 net earnings of $7 million, or $0.45 per diluted share.

Revenue in 2020 was $936 million, 39% lower than 2019. As compared with 2019, revenue from our Contract Drilling Services and Completion and Production Services segments was down 38% and 48%, respectively. Our lower revenue in the year was primarily the result of lower activity across all regions. Our U.S. drilling activity decreased 55%, Canadian activity decreased 26% and international activity decreased 18%. In addition, our service rig operating hours were down 44% compared with the prior year.

Adjusted EBITDA in 2020 was $263 million, 33% lower than in 2019. Our lower Adjusted EBITDA in 2020 was primarily due to decreased drilling and service activity and higher restructuring charges, partially offset by higher Contract Drilling Services day rates and the impact of Canadian Emergency Wage Subsidy (CEWS) program assistance of $26 million. As a percentage of revenue, our Adjusted EBITDA margin was 28% as compared with 25% in 2019.

Contract Drilling Services’ Adjusted EBITDA as a percentage of segment revenue for the year was 35%, compared with 31% in 2019, while the Completion and Production Services segment was 15%, compared with 16% in 2019. Our portfolio of term customer contracts, scalable operating cost structure and economies achieved through vertical integration of the supply chain helped manage our Adjusted EBITDA percentages during 2020.

Capital expenditures for the purchase of property, plant and equipment and intangible assets were $62 million in 2020, a decrease of $99 million over 2019. Our capital spending included $27 million for upgrade and expansion capital, $35 million for the maintenance of existing assets, infrastructure and intangibles.

During the year, we retired our 6.50% unsecured senior notes due 2021 through redemptions of US$88 million principal amount and repurchases and cancellations of US$3 million. In addition, we repurchased and cancelled US$44 million of our 5.25% unsecured senior notes due 2024, US$22 million of our 7.125% unsecured senior notes due 2026 and US$59 million of our 7.75% unsecured senior notes due 2023. We recognized a gain of $44 million on the repurchase of unsecured senior notes.

Pursuant to our NCIB, we repurchased and cancelled a total of 420,588 common shares for $11 million. Subsequent to December 31, 2020, we repurchased and cancelled an additional 155,168 shares for $4 million.

On November 12, 2020, we completed a 20:1 consolidation of our common shares. No fractional shares were issued pursuant to the share consolidation. Comparative period basic and diluted weighted average shares outstanding have been retrospectively adjusted to reflect our share consolidation.

Revenue and Adjusted EBITDA $ Millions $1,750 $1,500 $1,250 $1,000 $750 $500 $250 0 2016 2017 2018 2019 2020 Margin % 50% 40% 30% 20% 10% 0% Revenue Adjusted EBITDA EBITDA Margin Cash and Funds Provided by Operations $ Millions $350 $300 $250 $200 $150 $100 $50 0 2016 2017 2018 2019 2020 Funds provided by operations Cash provided by operations Drilling Utilization Days Days 60,000 40,000 20,000 0 2016 2017 2018 2019 2020 International U.S. Canada

Year ended December 31 (in thousands of dollars)	2020			2019			2018
Revenue
Contract Drilling Services		861,202			1,399,068			1,396,492
Completion and Production Services		77,251			147,829			150,760
Inter-segment elimination		(2,700	)		(5,577	)		(6,063	)
		935,753			1,541,320			1,541,189
Adjusted EBITDA
Contract Drilling Services		300,425			429,483			412,134
Completion and Production Services		11,257			24,155			14,881
Corporate and Other		(48,279	)		(61,733	)		(51,884	)
		263,403			391,905			375,131
Depreciation and amortization		316,322			333,616			377,044
Gain on asset disposals		(11,931	)		(50,741	)		(11,384	)
Loss on asset decommissioning		—			20,263			—
Reversal of impairment of property, plant and equipment		—			(5,810	)		—
Impairment of goodwill		—			—			207,544
Foreign exchange		4,542			(8,722	)		4,017
Finance charges		107,468			118,453			127,178
Gain on redemption and repurchase of unsecured senior notes		(43,814	)		(6,815	)		(5,672	)
Loss before income tax		(109,184	)		(8,339	)		(323,596	)
Income taxes		10,954			(14,957	)		(29,326	)
Net earnings (loss)		(120,138	)		6,618			(294,270	)

Year ended December 31 (in thousands of dollars)	2020		2019		2018
Revenue
U.S.		444,052		871,651		791,312
Canada		305,613		459,377		558,746
International		186,088		210,292		191,131
		935,753		1,541,320		1,541,189
Total assets
U.S.		1,339,945		1,560,523		1,772,850
Canada		1,053,921		1,133,591		1,269,542
International		505,012		575,726		593,651
		2,898,878		3,269,840		3,636,043

As compared with 2019, our revenue, Adjusted EBITDA and net earnings declined in the year primarily due to lower activity levels across all segments as volatile commodity prices and uncertain outlook on global oil demand caused by the COVID-19 pandemic resulted in conservative customer spending throughout 2020. Our 2020 revenue declined 39% from the prior year while Adjusted EBITDA was $263 million, a decrease of $128 million from 2019. Net loss in 2020 was $120 million, or a net loss of $8.76 per diluted share, compared with net earnings of $7 million, or $0.45 per diluted share, in 2019.

We incurred $18 million of restructuring charges, as compared with $6 million in 2019. Our restructuring charges were comprised of severance and costs associated with the shutdown of our U.S. directional drilling operations as we continued to align our structure and personnel with a lower activity environment.

Under IFRS, we review the carrying value of our long-lived assets for indications of impairment at the end of each reporting period. At March 31, 2020, we tested all CGUs for impairment and no impairment charges were identified. At December 31, 2020, we reviewed each CGU and did not identify any indications of impairment. Accordingly, we did not test our CGUs for impairment.

Through normal course disposal, we recognized a gain on asset disposals of $12 million as compared with $51 million in 2019. In the prior year, we sold our Mexico-based drilling rigs and ancillary equipment for total proceeds of US$48 million, recognizing a gain on asset disposal of US$24 million and reversed US$4 million of previous impairment charges. In 2019, we

decommissioned certain assets that no longer met our High Performance technology standard for a loss on asset decommissioning of $20 million. We did not decommission any assets in 2020.

We recognized a foreign exchange loss of $5 million in 2020 (2019 – $9 million gain) due to the weakening of the Canadian dollar against the U.S. dollar. This affected the net U.S. dollar denominated monetary position in our Canadian dollar-based companies and the translation of our U.S. denominated intercompany payables.

Finance charges were $107 million, a decrease of $11 million compared with 2019 and was primarily due to a reduction in interest expense related to debt retired, partially offset by the impact of the weakening of the Canadian dollar on our U.S. dollar denominated interest.

In 2020, we were able to repurchase our unsecured senior notes at a discount. We retired our 6.50% unsecured senior notes due 2021 through redemptions of US$88 million principal amount and repurchases and cancellations of US$3 million. We repurchased and cancelled US$44 million of our 5.25% unsecured senior notes due 2024, US$22 million of our 7.125% unsecured senior notes due 2026 and US$59 million of our 7.75% unsecured senior notes due 2023. We recognized a gain of $44 million on the repurchase of our unsecured senior notes. In comparison, during 2019, we redeemed and/or repurchased and cancelled US$153 million of our previously outstanding unsecured senior notes for a gain of $7 million.

In 2020, we recognized an income tax expense of $11 million as compared with a recovery of $15 million in 2019. The higher income tax expense in the current year was primarily the result of not recognizing the benefit of Canadian and certain international deferred tax assets.

Net earnings in 2019 was $7 million, or $0.45 per diluted share, compared with a net loss of $294 million, or a net loss of $20.05 per diluted share, in 2018. The higher net earnings were primarily the result of higher operating margins in our U.S. contract drilling business, lower general and administrative costs, lower finance charges because of our reduced debt, a current year foreign exchange gain and a 2018 goodwill impairment charge that after-tax reduced net earnings by $199 million, partially offset by lower activity in Canada and the receipt of a transaction termination fee in 2018.

Revenue was $1,541 million (consistent with 2018) because of higher international activity and improved U.S. and international day rates, offset by lower U.S. and Canadian activity and lower day rates in Canada.

Adjusted EBITDA in 2019 was $392 million (5% higher than in 2018). Our higher Adjusted EBITDA in 2019 was primarily due to increased U.S. and international day rates, higher international activity, improved operating margins and lower general and administrative costs, partially offset by lower activity in the U.S. and Canada.

Under IFRS, we are required to assess the carrying value of assets in our CGUs containing goodwill annually and when indicators of impairment exist. As a result of the goodwill impairments recognized in 2018, at December 31, 2019, we no longer have any CGUs that contain goodwill. We did not identify an indication of impairment within the Corporation’s CGUs as at December 31, 2019. Accordingly, no impairment tests were performed.

In the second quarter of 2019, Precision sold its Mexico-based drilling rigs and ancillary equipment, contained within its Contract Drilling Services segment, for total proceeds of US$48 million. Precision recognized a gain on asset disposal of US$24 million and reversed US$4 million of previous impairment charges.

In 2018, 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.

We recognized a foreign exchange gain of $9 million in 2019 (2018 – $4 million loss) due to the strengthening 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 and the translation of our U.S. denominated intercompany payables.

Finance charges were $118 million, a decrease of $9 million compared with 2018 primarily due to a reduction in interest expense related to debt retired in 2018 and 2019, partially offset by the impact of the weakening of the Canadian dollar on our U.S. dollar denominated interest and lease accretion charges resulting from the adoption of IFRS 16 on January 1, 2019.

During 2019, Precision repurchased and cancelled US$30 million of the 7.125% unsecured senior notes due 2026, US$5 million of the 7.75% unsecured senior notes due 2023 and US$43 million of the 5.25% unsecured senior notes due 2024. In addition, Precision redeemed US$75 million principal amount of its 6.50% unsecured senior notes due 2021. We recognized a gain on the repurchase and redemption of unsecured senior notes of $7 million. In comparison, during 2018, we redeemed and/or repurchased and cancelled US$132 million of our previously outstanding unsecured senior notes resulting in a gain of $6 million.

In 2019, we recognized an income tax recovery of $15 million as compared to $30 million in 2018. The reduced recovery in 2019 compared with 2018 was mainly due to a smaller loss in 2019, prior to the non-taxable portion of the goodwill impairment recorded in 2018.

Adjusted EBITDA, operating earnings (loss), funds provided by (used in) operations and working capital are Non-GAAP measures. See page 48 for more information.

Year ended December 31 (in thousands of dollars, except where noted)	2020			% of revenue			2019			% of revenue			2018			% of revenue
Revenue		861,202						1,399,068						1,396,492
Expenses
Operating		526,716			61.2			927,612			66.3			945,203			67.7
General and administrative		26,441			3.1			38,927			2.8			39,155			2.8
Restructuring		7,620			0.9			3,046			0.2			—			—
Adjusted EBITDA		300,425			34.9			429,483			30.7			412,134			29.5
Depreciation and amortization		288,389			33.5			300,882			21.5			341,712			24.5
Gain on asset disposals		(10,171	)		(1.2	)		(46,849	)		(3.3	)		(7,157	)		(0.5	)
Loss on asset decommissioning		—			—			20,263			1.4			—			—
Reversal of impairment of property, plant and equipment		—			—			(5,810	)		(0.4	)		—			—
Impairment of goodwill		—			—			—			—			207,544			14.9
Operating earnings (loss)		22,207			2.6			160,997			11.5			(129,965	)		(9.3	)

Revenue from Contract Drilling Services was $861 million, 38% lower than 2019 due to lower drilling activity in each geographic region. In 2020, we recognized idle but contracted rig revenue in the U.S. of US$37 million and shortfall payments in Canada of $1 million, compared to US$4 million and $4 million, respectively in 2019.

Operating expenses in 2020 were 61% of revenue, 5% lower than the prior year. On a per utilization day basis, in the U.S., operating costs were 2% higher than the prior year primarily due to fixed operating overheads spread over fewer utilization days and higher turnkey activity, offset by lower repairs and maintenance and our rig mix. Operating costs on a per day basis in our Canadian drilling rig division was 11% lower than 2019, primarily due to the impact of CEWS program assistance and lower repairs and maintenance.

General and administrative expenses for 2020 were 32% lower due to our cost savings initiatives, restructuring and CEWS program assistance. In 2020, we incurred $8 million of restructuring charges, as compared with $3 million in 2019, as we continued to align our cost structure and personnel to reflect lower drilling activity.

During the year, we recognized CEWS program assistance of $15 million of which $14 million and $1 million were presented as reductions to our operating and general and administrative costs, respectively.

Our 2020 operating earnings were $22 million as compared to $161 million in the prior year. In addition to lower activity, our operating earnings decreased in 2020 as a result of lower gains on asset disposals and reversals of impairment, partially offset by lower asset decommissioning and depreciation and amortization.

In 2019 we decommissioned drilling rigs resulting in a loss on decommissioning of $20 million and sold our Mexico-based drilling rigs and ancillary equipment, recognizing a gain on asset disposal of US$24 million and reversal of impairment of US$4 million.

Our depreciation expense for 2020 was lower by 4% compared with the prior year due to asset sales and assets becoming fully depreciated.

Capital expenditures in 2020 for our Contract Drilling segment were $58 million:

Year ended December 31	2020		% increase/ (decrease)			2019		% increase/ (decrease)			2018		% increase/ (decrease)
Number of drilling rigs (year-end)		227		0.4			226		(4.2	)		236		(7.8	)
Drilling utilization days (operating and moving)
U.S.		12,080		(54.5	)		26,544		(0.6	)		26,714		30.4
Canada		10,794		(25.5	)		14,498		(22.1	)		18,617		(1.4	)
International		2,526		(18.3	)		3,093		5.9			2,920		—
Drilling revenue per utilization day
U.S.		26,184		11.9			23,397		7.0			21,864		10.1
Canada		21,611		0.2			21,569		(0.3	)		21,644		2.4
International		54,811		6.7			51,360		1.8			50,469		0.5

Revenue from U.S. drilling was US$316 million, 49% lower than 2019. Drilling rig activity, as measured by utilization days, was down 55% from 2019 while average revenue per day was up 12%.

Adjusted EBITDA was US$124 million, 43% lower than 2019, mainly because of lower activity, partially offset by higher average day rates, idle but contracted revenue and turnkey activity.

Our average day rates in the U.S. increased 12% compared with 2019 due to higher revenue from idle but contracted rigs, turnkey projects and the commercialization of our Alpha technology. Revenue from idle but contracted rigs was US$37 million in 2020, an increase of US$33 million from the prior year. We recognized turnkey revenue of US$11 million which accounted for 3% of our U.S. drilling revenue as compared with US$3 million and less than 1% in 2019, respectively.

Depreciation expense for the year was US$106 million, US$6 million lower than 2019 because of a lower capital asset base as assets become fully depreciated, decommissioned, or were disposed.

We ended the year with a U.S. rig count of 105. We averaged 33 rigs working in 2020, 55% lower than 2019, consistent with lower industry activity. In 2020, the average number of active land rigs for the industry was 420, down 54% from 921 rigs in 2019.

	2020				2019				2018
	Precision		Industry⁽¹⁾		Precision		Industry⁽¹⁾		Precision		Industry⁽¹⁾
Average number of active land rigs for quarters ended:
March 31		55		764		79		1,023		64		951
June 30		30		378		77		967		72		1,021
September 30		21		241		72		896		76		1,032
December 31		26		297		63		798		80		1,050
Annual average		33		420		73		921		73		1,014

Revenue from Canadian drilling was $233 million, 25% lower than 2019. Drilling rig activity, as measured by utilization days, was down by 26% while average day rates were consistent with 2019.

Adjusted EBITDA was $78 million, 6% lower than 2019, as a result of lower drilling activity, partially offset by the impact of CEWS program assistance.

Depreciation expense for the year was $95 million, 13% lower than 2019 because of a lower capital asset base as assets become fully depreciated, decommissioned, or were disposed.

Our Canadian rig count remained at 109, consistent with 2019. We averaged 29 rigs working in 2020, 28% lower than 2019 while the average number of active land rigs for the industry declined 34% from 134 to 89.

	2020				2019				2018
	Precision		Industry⁽¹⁾		Precision		Industry⁽¹⁾		Precision		Industry⁽¹⁾
Average number of active land rigs for quarters ended:
March 31		63		196		48		183		64		269
June 30		9		25		27		82		72		108
September 30		18		47		42		132		76		209
December 31		28		88		43		138		80		179
Annual average		29		89		40		134		73		191

Adjusted EBITDA, operating earnings (loss), funds provided by (used in) operations and working capital are Non-GAAP measures. See page 48 for more information.

Year ended December 31 (in thousands of dollars, except where noted)	2020			% of revenue			2019			% of revenue			2018			% of revenue
Revenue		77,251						147,829						150,760
Expenses
Operating		59,404			76.9			116,932			79.1			128,124			85.0
General and administrative		3,995			5.2			6,285			4.3			6,591			4.4
Restructuring		2,595			3.4			457			0.3			1,164			0.8
Adjusted EBITDA		11,257			14.6			24,155			16.3			14,881			9.9
Depreciation and amortization		16,375			21.2			17,881			12.1			22,801			15.1
Loss (gain) on asset disposals		(1,447	)		(1.9	)		(3,767	)		(2.5	)		1,078			0.7
Operating earnings (loss)		(3,671	)		(4.8	)		10,041			6.8			(8,998	)		(6.0	)

Revenue from Completion and Production Services was $77 million, 48% lower than 2019, resulting from lower activity across all divisions.

Operating expenses were 77% of segment revenue, 2% lower than 2019, which was primarily the result of our improved cost structure and the impact of CEWS program assistance.

During the year, we recognized CEWS program assistance of $7 million of which $6 million and $1 million were presented as reductions to our operating and general and administrative costs, respectively.

We incurred $3 million of restructuring costs, compared with less than $1 million in 2019, as we continued to align our cost structure to reflect lower divisional activity.

Our reduced activity in 2020 resulted in an operating loss of $4 million in 2020, compared with operating earnings of $10 million in the prior year.

Depreciation in 2020 decreased by 8% due to our lower capital asset base as assets become fully depreciated, decommissioned, or were disposed.

Through normal course disposals, we recognized a gain on asset disposals of $1 million as compared with $4 million in 2019. In the prior year, we disposed of certain snubbing units and related equipment, recognizing a gain on disposal of $3 million.

Capital expenditures in 2020 were $3 million, comprised mainly of maintenance capital.

Our service rig operating hours fell by 44% in the current year as compared with the prior year period.

Adjusted EBITDA, operating earnings (loss), funds provided by (used in) operations and working capital are Non-GAAP measures. See page 48 for more information.

Year ended December 31 (in thousands of dollars, except where noted)	2020			2019			2018
Revenue		—			—			—
Expenses
Operating		—			—			—
General and administrative		40,433			58,798			66,084
Restructuring		7,846			2,935			—
Other recoveries		—			—			(14,200	)
Adjusted EBITDA		(48,279	)		(61,733	)		(51,884	)
Depreciation and amortization		11,558			14,853			12,531
Gain on asset disposals		(313	)		(125	)		(5,305	)
Operating loss		(59,524	)		(76,461	)		(59,110	)

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 $40 million in 2020, $18 million lower than 2019. The decrease was mainly related to our efforts to realign our cost structure, including the reduction of fixed overhead costs, and CEWS program assistance, partially offset by higher foreign exchange translation on our U.S. dollar-based costs.

We recognized $4 million of CEWS program assistance in the year. In 2020, corporate general and administrative costs were 4.3% of consolidated revenue compared with 3.8% in 2019.

During the year, we recognized $8 million in restructuring costs, as compared with $3 million in the prior year. Our restructuring costs were primarily comprised of severance costs as we continued to align our cost structure with our reduced activity levels.

Capital expenditures in 2020 for our Corporate and Other segment were $1 million, primarily related to infrastructure.

Adjusted EBITDA, operating earnings (loss), funds provided by (used in) operations and working capital are Non-GAAP measures. See page 48 for more information.

2020 – Quarters Ended (in thousands of dollars, except per share amounts)	March 31			June 30			September 30			December 31
Revenue		379,484			189,759			164,822			201,688
Adjusted EBITDA		101,904			58,465			47,771			55,263
Net earnings (loss)		(5,277	)		(48,867	)		(28,476	)		(37,518	)
per basic share		(0.38	)		(3.56	)		(2.08	)		(2.74	)
per diluted share		(0.38	)		(3.56	)		(2.08	)		(2.74	)
Funds provided by operations		81,317			26,639			27,489			35,282
Cash provided by operations		74,953			104,478			41,950			4,737

2019 – Quarters Ended (in thousands of dollars, except per share amounts)	March 31		June 30			September 30			December 31
Revenue		434,043		359,424			375,552			372,301
Adjusted EBITDA		107,967		81,037			97,895			105,006
Net loss		25,014		(13,801	)		(3,534	)		(1,061	)
per basic share		1.70		(0.93	)		(0.23	)		(0.08	)
per diluted share		1.67		(0.93	)		(0.23	)		(0.08	)
Funds provided by operations		95,993		40,950			79,930			75,779
Cash provided by operations		40,587		106,035			66,556			74,981

Drilling and well servicing activity is affected by seasonal weather patterns and ground conditions. In Canada and the northern U.S., wet weather and the spring thaw make the ground unstable resulting in road restrictions that may limit the movement of heavy oilfield equipment and reduce the level of drilling and well servicing activity primarily during the second quarter of the year. In northern Canada, some drilling sites can only be accessed in the winter once the terrain is frozen, which usually begins late in the fourth quarter. Our business activity depends, in part, on the severity and duration of the winter drilling season.

In the fourth quarter of 2020, we recorded a net loss of $38 million or a net loss of $2.74 per diluted share compared to a net loss of $1 million or a net loss of $0.08 per diluted share in 2019.

Revenue in the fourth quarter was $202 million or 46% lower than the comparable 2019 quarter, mainly due to lower activity. Compared with the fourth quarter of 2019, our drilling activity decreased 59% in the U.S., 34% in Canada and 33% internationally. Our 2020 fourth quarter revenue from our Contract Drilling Services and Completion and Production Services segments decreased 47% and 33%, respectively, from the comparable 2019 quarter.

Adjusted EBITDA was $55 million, a decrease of $50 million from the fourth quarter of 2019. Our lower Adjusted EBITDA in 2020 was primarily due to reduced activity and higher share-based incentive compensation expense.

As a percentage of revenue, operating costs were 62% in the fourth quarter of 2020, 3% lower than the same quarter of 2019. Our portfolio of term customer contracts and a highly variable operating cost structure helped us manage our Adjusted EBITDA margin.

Revenue from Contract Drilling Services was $179 million in the fourth quarter of 2020, 47% lower than the fourth quarter of 2019, while Adjusted EBITDA decreased by 44% to $63 million. The decrease in revenue and Adjusted EBITDA was due to lower activity across all geographic operating locations.

In the U.S., we had fourth quarter revenue from idle but contracted rigs and turnkey projects of US$7 million and US$5 million, respectively. Whereas in 2019, we had revenue of US$3 million in each of idle but contracted rigs and turnkey projects. During the quarter, we recognized $1 million of contract shortfall revenue in Canada as compared with nil in 2019.

In the fourth quarter of 2020, industry drilling activity remained low. Accordingly, our U.S. drilling rig utilization days (drilling days plus move days) were 2,396, 59% lower than 2019 while our Canadian utilization days were 2,578, 34% lower than 2019. Drilling rig utilization days in our international business were 552 in the fourth quarter of 2020, 33% lower than 2019 due to the expiration of drilling contracts.

Revenue per utilization day in the U.S. increased in the fourth quarter of 2020 to US$25,577 from US$23,949 in the prior year quarter as we realized higher revenues from idle but contracted rig revenue and turnkey projects. In Canada, average revenue per utilization day for contract drilling rigs was $21,670 compared with $22,182 in the fourth quarter of 2019. The lower average revenue per utilization day in the fourth quarter of 2019 was primarily due to our rig mix for the quarter. Average revenue per utilization day in our international contract drilling business was US$55,453 compared with US$52,283 in the prior year quarter. The higher average rate in 2020 was primarily due to our rig mix.

In the U.S., 62% of utilization days were generated from rigs under term contract as compared with 66% in the fourth quarter of 2019. In Canada, 11% of our utilization days in the quarter were generated from rigs under term contract, compared with 9% in the fourth quarter of 2019.

Operating costs were 61% of revenue for the quarter, as compared to 64% in the prior year period. In the U.S., operating costs for the quarter on a per day basis of US$14,419 were higher than the prior year period of US$14,073 primarily due to higher turnkey activity and fixed operating overheads spread over fewer utilization days. On a per utilization day basis, operating costs in Canada of $12,291 were lower than the 2019 quarter of $14,791 due to the impact of the CEWS program assistance, offset by fixed operating overheads spread over fewer utilization days. During the quarter, we recognized CEWS program assistance of $7 million of which $6 million and $1 million were respectively presented as reductions to our operating and general and administrative costs.

Depreciation expense in the quarter was 7% lower than the fourth quarter of 2019 primarily because of a lower capital asset base as assets become fully depreciated, decommissioned, or were disposed.

In the fourth quarter of 2020, through the completion of normal course business operations, we sold used assets recognizing a gain on disposal of $2 million, compared with $4 million in 2019.

Completion and Production Services revenue decreased 33% compared with the fourth quarter of 2019 due to lower activity in each of our service lines. Our service rig operating hours in the quarter of 27,286 were down 32% from the fourth quarter of 2019, consistent with lower industry activity. Approximately 73% of our fourth quarter Canadian service rig activity was oil related.

Adjusted EBITDA of $5 million in the fourth quarter of 2020 was 15% lower than the 2019 quarter primarily due to lower activity.

During the quarter, Completion and Production Services generated 21% of its revenue from U.S. operations compared with 19% in the comparative period.

In the fourth quarter of 2020, operating and general and administrative costs as a percentage of revenue were lower as compared with 2019. The lower percentage in 2020 was primarily due to the impact of our reduced cost structure and CEWS program assistance partially offset by fixed overhead costs spread over a lower revenue base. During the quarter, we recognized CEWS program assistance of $3 million which were presented as reductions to our operating and general and administrative costs of $2 million and $1 million, respectively.

Depreciation expense in the quarter was 8% lower than the comparative period, primarily because of a lower capital asset base as assets become fully depreciated or were disposed.

The Corporate and Other segment had negative Adjusted EBITDA of $14 million, consistent with the comparative 2019 quarter. In the fourth quarter of 2020 our improved cost structure and CEWS program assistance were offset by higher share-based compensation expense. During the fourth quarter of 2020, we recognized $1 million of CEWS program assistance.

Net finance charges were $24 million, a decrease of $4 million compared with the fourth quarter of 2019, primarily due to reduced interest expense related to retired debt. Interest charges on our U.S. denominated long-term debt in the fourth quarter of 2020 were US$16 million ($21 million) as compared with US$20 million ($26 million) in 2019.

During the quarter, we repurchased and cancelled US$21 million of our 7.75% unsecured senior notes due 2023, US$10 million of our 7.125% unsecured senior notes due 2026, and US$8 million of our 5.25% unsecured senior notes due 2024. Our debt reduction resulted in a gain of $14 million.

Income tax expense for the quarter was $8 million compared with a recovery of $12 million in the same quarter in 2019. In the fourth quarter of 2020, we did not recognize deferred tax assets in Canada and certain international jurisdictions, resulting in a higher income tax expense as compared with 2019.

In 2020, we had an average of 42 drilling rigs working under term contracts. Utilization days from these contracts was approximately 48% of our total contract drilling utilization days for the year.

The volatile and uncertain outlook on oil prices and stringent focus on free cash flow encouraged conservatism in customer spending, leading to a significant industry decrease in rig count late in the year. In the U.S., customer focus on free cash flow continues to encourage conservatism in customer spending, leading to a significant industry decrease in rig counts late in 2020. As of March 12, 2021, the U.S. rig count was 49% lower than the same time last year and has averaged 51% lower year-to-date compared to 2020. In Canada, acute pipeline takeaway shortfalls and continued uncertainty in regulatory policy caused immense pressure on regional commodity prices and subsequent activity levels. The industry rig count at March 12, 2021 was 43% lower in Canada than it was a year ago while the year-to-date rig count has averaged 30% lower than 2020. Our U.S. and Canadian activity for the remainder of the year is expected to be determined by the strength in commodity prices and the resulting customer budgets.

We currently have six rigs working on term contracts with three in Kuwait and three in the Kingdom of Saudi Arabia. We continue to bid our idle rigs within the region. Securing reactivations has been difficult due to COVID-19 restrictions. However, we remain optimistic in our ability to secure reactivations as our customers return to more normal operations.

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 made legacy rigs virtually obsolete in North America.

Capital spending in 2021 is expected to be $54 million and includes $16 million for upgrade and expansion and $38 million for sustaining, infrastructure and intangibles. We expect that the $54 million will be split $50 million in the Contract Drilling Services segment, $3 million in the Completion and Production Services segment and $1 million to the Corporate segment. At December 31, 2020, Precision had capital commitments of $112 million with payments expected through to 2023.

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 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.

Despite the enormous challenges posed by COVID-19, we maintained our strong liquidity position. We exited the year with a cash balance of $109 million and $552 million of available borrowing capacity under our secured credit facilities, providing us with $661 million of total liquidity. To provide additional liquidity, we established a Real Estate Credit Facility in the amount of US$11 million in the fourth quarter of 2020.

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.

We ended 2020 with a long-term debt to long-term debt plus equity ratio of 0.5 (2019 – 0.5) and a ratio of long-term debt to cash provided by operations of 5.5 (2019 – 5.0).

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 link our executives’ incentive compensation to the returns to our shareholders relative to the shareholder returns of our peers.

(in thousands of dollars, except ratios)	December 31, 2020		December 31, 2019		December 31, 2018
Working capital⁽¹⁾		175,423		201,696		240,539
Working capital ratio		2.1		1.9		1.9
Long-term debt⁽²⁾		1,236,210		1,427,181		1,706,253
Total long-term financial liabilities		1,304,162		1,500,950		1,723,350
Total assets		2,898,878		3,269,840		3,636,043
Enterprise value⁽³⁾		1,409,147		1,854,393		2,305,890
Long-term debt to long-term debt plus equity		0.5		0.5		0.5
Long-term debt to cash provided by operations		5.5		5.0		5.8
Long-term debt to Adjusted EBITDA⁽¹⁾		4.7		3.6		4.5

⁽³⁾^{Share price multiplied by the number of shares outstanding plus long-term debt minus cash. See page}³²^{for more information.}

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.

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 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.

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.

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 2020, we designated our U.S. dollar Senior Credit Facility and unsecured 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.

At December 31 (in thousands of dollars)	2020			2019			2018
Cash from operations		226,118			288,159			293,334
Cash used in investing		(40,517	)		(74,500	)		(100,794	)
Surplus (deficit)		185,601			213,659			192,540
Cash used in financing		(145,624	)		(231,814	)		(169,085	)
Effect of exchange rate changes on cash		(5,906	)		(3,770	)		8,090
Net cash used		34,071			(21,925	)		31,545

In 2020, we generated cash from operations of $226 million compared with $288 million in 2019. The decrease is primarily the result of lower activity, partially offset by lower interest payments due to debt reduction.

The $62 million in capital expenditures in 2020 was split between our segments as follows:

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 $21 million in 2020 compared with $91 million in 2019.

Amount	Availability	Used for	Maturity
Senior Credit Facility (secured)
US$500 million (extendible, revolving term credit facility with US$300 million accordion feature)	US$500 million less US$75 million drawn and US$32 million in outstanding letters of credit	General corporate purposes	November 21, 2023
Real estate credit facility (secured)
US$11 million	Fully drawn	General corporate purposes	November 19, 2025
Operating facilities (secured)
$40 million	Undrawn, except $7 million in outstanding letters of credit	Letters of credit and general corporate purposes
US$15 million	Undrawn	Short-term working capital requirements
Demand letter of credit facility (secured)
US$30 million	Undrawn, except US$2 million in outstanding letters of credit	Letters of credit
Unsecured senior notes (unsecured)
US$286 million – 7.75%	Fully drawn	Debt redemption and repurchases	December 15, 2023
US$263 million – 5.25%	Fully drawn	Capital expenditures and general corporate purposes	November 15, 2024
US$348 million – 7.125%	Fully drawn	Debt redemption and repurchases	January 15, 2026

Following is a listing of our currently applicable covenants and the calculations as of December 31, 2020:

^{(1) For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness.}

At December 31, 2020, we were in compliance with the covenants of our Senior Credit Facility, Real Estate Credit Facility and unsecured senior notes.

The senior secured revolving credit facility (Senior Credit Facility) provides Precision with senior secured financing for general corporate purposes, including for acquisitions, of up to US$500 million with a provision for an increase in the facility of up to an additional US$300 million. 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 we comply with certain restrictive and 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 we maintain a ratio of consolidated Covenant EBITDA to consolidated interest expense for the most recent four consecutive quarters, of greater than 2.5:1.

Distributions under the Senior Credit Facility 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.

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, 2023.

On April 9, 2020 we agreed with the lenders of our Senior Credit Facility to reduce the consolidated Covenant EBITDA to consolidated interest expense coverage ratio for the most recent four consecutive quarters of greater than or equal to 2.5:1 to 2.0:1 for the period ending September 30, 2020, 1.75:1 for the period ending December 31, 2020, 1.25:1 for the periods ending March 31, June 30 and September 30, 2021, 1.75:1, for the period ending December 31, 2021, 2.0:1 for the period ending March 31, 2022 and 2.5:1 for periods ending thereafter.

During the covenant relief period, Precision’s distributions in the form of dividends, distributions and share repurchases are restricted to a maximum of US$15 million in 2020 and US$25 million in each of 2021 and 2022, subject to a pro forma senior net leverage ratio (as defined in the credit agreement) of less than or equal to 1.75:1.

In addition, during 2021, the North American and acceptable secured foreign assets must directly account for at least 65% of consolidated Covenant EBITDA calculated quarterly on a rolling twelve-month basis, increasing to 70% thereafter. Precision also has the option to voluntarily terminate the covenant relief period prior to its March 31, 2022 end date.

Under the Senior Credit Facility, amounts can be drawn in U.S. dollars and/or Canadian dollars. At December 31, 2020, US$75 million amounts were drawn under this facility (2019 – nil). Up to US$200 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, 2020 outstanding letters of credit amounted to US$32 million (2019 – US$25 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 Canadian Dollar Offered Rate (CDOR); such margins will be based on the then applicable ratio of consolidated total debt to EBITDA.

In November 2020, Precision established a Real Estate Credit Facility in the amount of US$11 million. The facility matures in November 2025 and is secured by real property located in Houston, Texas. Principal plus interest payments are due monthly, based on 15-year straight-line amortization with any unpaid principal and accrued interest due at maturity. Interest is calculated using a LIBOR rate plus margin.

The Real Estate Credit Facility contains certain affirmative and negative covenants and events of default, customary for this type of transactions. Under the terms of the Real Estate Credit Facility, Precision must maintain a consolidated interest coverage ratio in accordance with the Senior Credit Facility, described above, as of the last day of each period of four consecutive fiscal quarters commencing December 31, 2020. In the event the consolidated Covenant EBITDA to consolidated interest expense coverage ratio is waived or removed from the Senior Credit Facility, a minimum threshold of 1.15:1 is required.

The unsecured senior notes require we comply with an incurrence based consolidated interest coverage ratio test of consolidated cash flow, as defined in the senior note agreements, to consolidated interest expense of greater than 2.0:1 for the most recent four consecutive fiscal quarters. In the event 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.

The unsecured senior notes contain a restricted payment covenant that limits our ability to make payments in the nature of dividends, distributions and for share repurchases from shareholders. This restricted payment basket grows from a starting point of October 1, 2010 for the 2024 senior notes, from October 1, 2016 for the 2023 senior notes and October 1, 2017 for the 2026 senior notes by, among other things, 50% of consolidated cumulative net earnings and decreases by 100% of consolidated cumulative net losses, as defined in the senior note agreements, and payments made to shareholders. The governing net restricted payments basket is currently negative, limiting our ability to declare and make dividend payments until such time as the restricted payments baskets become positive . During 2020, pursuant to the indentures governing the unsecured senior notes, Precision used the available general restricted payments basket to facilitate the repurchase and cancellation of its common shares.

In addition, the unsecured 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.

For further information, please see the unsecured senior note indentures which are available on SEDAR and EDGAR.

Our contractual obligations include both financial obligations (long-term debt and interest) and non-financial obligations (new-build rig commitments, operating leases, and equity-based compensation for key executives and officers). The table below shows the amounts of these obligations and when payments are due for each.

	Payments due (by period)
At December 31, 2020 (in thousands of dollars)	Less than 1 year		1-3 years		4-5 years		More than 5 years		Total
Long-term debt⁽¹⁾		896		460,615		345,781		442,757		1,250,049
Interest on long-term debt⁽¹⁾		80,980		160,520		79,360		1,314		322,174
Purchase of property, plant and equipment⁽¹⁾⁽²⁾		23,917		89,552		—		—		113,469
Operating leases⁽¹⁾		10,960		18,438		11,192		6,590		47,180
Contractual incentive plans⁽¹⁾⁽³⁾		7,768		19,277		—		—		27,045
Total		124,521		748,402		436,333		450,661		1,759,917

⁽¹⁾^{U.S. dollar denominated balances are translated at the period end exchange rate of Cdn$1.00 equals US$0.}⁷⁸⁵⁵^.

⁽²⁾^B^alance^primarily^{relates to cost of rig equipment with flexible delivery schedule wherein we can take delivery between 20}²¹^{and 202}³^.

⁽³⁾^{Includes amounts not yet accrued but are likely to}^be^pa^id^{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}^closing^{share price on the TSX of $}^20.93^{at December 31, 20}²⁰^.

On November 12, 2020, we completed a 20:1 consolidation of our common shares. No fractional shares were issued pursuant to the share consolidation. In lieu of any such fractional shares, each registered shareholder otherwise entitled to a fractional share following the implementation of the share consolidation received the nearest whole number of post-consolidation shares.

During the third quarter of 2020, the Toronto Stock Exchange approved our application to renew our Normal Course Issuer Bid. Under the terms of the NCIB, we may purchase and cancel up to a maximum of 1,199,883 common shares, representing 10% of the public float of common shares as of August 14, 2020. The NCIB will terminate no later than August 26, 2021. For the year ended December 31, 2020, we repurchased and cancelled a total of 420,588 common shares for $11 million. Subsequent to December 31, 2020, we have repurchased and cancelled an additional 155,168 shares for $4 million.

More information about our capital structure can be found in our Annual Information Form, available on our website and on SEDAR.

Our articles of amalgamation allow us to issue an unlimited number of common shares.

We can issue preferred shares in one or more series. The Board must pass a resolution determining the number of shares in each series, and the designation, rights, privileges, restrictions and conditions for each series, before the shares can be issued. This includes the rate or amount of dividends, when and where dividends are paid, the dates dividends accrue from any rights or obligations for us to buy or redeem the shares, and the price, terms and conditions, and any conversion rights.

(in thousands of dollars, except shares outstanding and per share amounts)	December 31, 2020			December 31, 2019			December 31, 2018
Shares outstanding		13,459,593			13,864,990			14,689,092
Year-end share price on the TSX		20.93			36.20			47.40
Shares at market		281,709			501,913			696,263
Long-term debt		1,236,210			1,427,181			1,706,253
Less cash		(108,772	)		(74,701	)		(96,626	)
Enterprise value		1,409,147			1,854,393			2,305,890

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:

Due to the outbreak of COVID-19 and the resulting impact on the economy and in particular the prices of oil and natural gas, the estimates and judgements used to prepare our Consolidated Financial Statements were subject to a higher degree of measurement uncertainty.

Long-lived assets, which include property, plant and equipment and intangibles, 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.

The recoverability of long-lived assets requires a calculation of the recoverable amount of the cash generating unit or groups of CGUs to which assets have 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. For property, plant and equipment, this requires us to forecast future cash flows to be derived from the utilization of our 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.

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.

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.

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.

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 Precision’s policies, guidelines and review mechanisms.

Our businesses routinely encounter and manage risks, some of which may cause our future results to be different, and sometimes materially different than what we presently anticipate. We describe certain important strategic, operational, financial, legal and compliance risks. Our response to developments 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 on the exploration and development activities of oil and natural gas exploration and production companies

We primarily 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. 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 use of natural gas is growing quickly worldwide, with the three most developed demand centers residing in North America, Western Europe and North Asia. These regions have dense pipeline networks and a high demand for natural gas. The world’s largest producers of natural gas are currently the U.S., Russia, Iran, Qatar, Canada, China and Norway. 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 (LNG) in ocean-going tanker ships introduced an element of globalization to the natural gas market. The development of LNG means all the major production centers for natural gas are linked to the world’s major demand centers.

Worldwide military, political, economic and other events, such as the COVID-19 pandemic in 2020 or a 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 renewable energy initiatives), the availability of pipeline capacity and other transportation for oil and natural gas, global 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 which decreases drilling demand. In 2020, approximately 8,400 wells were started onshore in the U.S., compared to approximately 43,700 in 2014. In 2020, the industry drilled 2,960 wells in western Canada, compared to 10,942 in 2014. According to industry sources, the U.S. average active land drilling rig count was down approximately 54% in 2020, compared to 2019, and the Canadian average active land drilling rig count was down approximately 34% during the same period. Oil and natural gas prices remained volatile throughout 2020 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, the COVID-19 pandemic 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 adverse effect on our business, financial condition, results of operations and cash flow.

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. Reductions in commodity prices or factors that impact the supply and demand for oil and natural gas and lead to price volatility 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 and natural gas prices has depressed, and may continue to depress, the overall level of exploration and production activity, resulting in a corresponding decline in the demand for our services. Additionally, the availability and pricing of alternative sources of energy, a potential shift to lower carbon intensive energy sources or a shift to a lower carbon economy, and technological advances may also depress the overall level of oil and natural gas exploration and production activity, similarly impacting the demand for our services.

If a reduction in exploration and development activities, whether resulting from changes in oil and natural gas prices or reductions in capital budgets as described above or otherwise, continues or worsens, it could materially and adversely affect us further by:

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 business, financial condition, results of operations and cash flow.

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.

In March 2020, the COVID-19 outbreak was declared a pandemic by the World Health Organization. Governments worldwide, including those countries in which Precision operates, have enacted emergency measures from time to time to combat the spread of the virus. These measures, which include the implementation of travel bans, quarantine periods, stay-at-home orders and social distancing, have caused a material disruption to businesses globally resulting in an economic slowdown and decreased demand for oil. Governments and central banks have reacted with significant monetary and fiscal interventions designed to stabilize economic conditions; however, the long-term success of these interventions is not yet determinable. As a result of the decrease in demand, worldwide inventories of oil have increased significantly. However, voluntary production restraint from national oil companies and governments of oil-producing nations along with voluntary curtailments in the U.S. and Canada have shifted global oil markets from a position of over supply to inventory draws. Vaccines that are expected to provide for high levels of effectiveness against COVID-19 have been developed and vaccination programs are in progress globally. While vaccination programs have resulted in a more positive worldwide economic outlook, the overall timing, including the spread of any variants, and effectiveness of the vaccination programs remains uncertain and emergency measures to combat the spread of the virus may remain in effect for an indefinite period in certain countries or jurisdictions which could continue to result in decreased demand for oil. The situation remains dynamic and the ultimate duration and magnitude of the impact on the economy and the financial effect on Precision remains unknown at this time.

The current challenging economic climate resulting from the impact of the COVID-19 pandemic and corresponding emergency measures that have been implemented by various governments has or may have significant adverse impacts on Precision including, but not exclusively:

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. Construction has commenced on the Trans Mountain and Coastal Gaslink pipelines in Western Canada; however, both projects may face further regulatory delays or disruptions. On January 20, 2021, the Biden Administration issued an executive order revoking the Presidential permit allowing the construction and operation of the Keystone XL pipeline. The 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 could result in a corresponding decline in the demand for our services that could have a material adverse effect on our business, financial condition, results of operations and cash flow.

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, the offering of ancillary services, the ability to provide drilling equipment that is adaptable, 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 business, financial condition, results of operations and cash flow.

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 business, financial condition, results of operations and cash flow.

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 could have a material adverse effect on our business, financial condition, results of operations and cash flow.

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, geopolitical, financial, competitive and other factors that may be beyond our control. If we need to borrow funds in the future to service our debt, our ability will depend on covenants in our Senior Credit Facility and in our Senior Note Indentures and other debt agreements we may have in the future, and on our credit ratings. We may not be able to access sufficient amounts under the Senior Credit Facility or from the capital markets in the future to pay our obligations as they mature, or to fund other liquidity requirements. If we are not able to generate enough cash flow from operations or borrow a sufficient amount 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 business, financial condition, results of operations and cash flow.

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 are carried out through subsidiaries, and some of them are not guarantors of our debt. The assets of the non-guarantor subsidiaries represent approximately 21% 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 funds 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 business, financial condition, results of operations and cash flow.

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 of credit for those customers. A reduction in spending by our customers could have a material adverse effect on our business, financial condition, results of operations and cash flow as described further under – “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” on page 34.

Our Senior Credit Facility, Real Estate Credit Facility and the unsecured senior notes indentures contain a number of covenants which, among other things, restrict us and some of our subsidiaries from conducting certain activities (see Capital Structure – Material Debt – Unsecured Senior Notes on page 31). In the event our Consolidated Interest Coverage Ratio (as defined in our three 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, 2020, our Consolidated Interest Coverage Ratio, as calculated per our unsecured senior note indentures, was 2.57:1.

In addition, we must satisfy and maintain certain financial ratio tests under the Senior Credit Facility and Real Estate Credit Facility (see Capital Structure – Material Debt on page 30). 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 and Real Estate Credit Facility or any of the unsecured senior 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, Real Estate Credit Facility or any of the unsecured senior note indentures to be due and payable immediately and terminate any commitments to extend further credit under the Senior Credit Facility. 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 Senior Note Indentures to be due and payable immediately.

At December 31, 2020, we were in compliance with the covenants of our Senior Credit Facility and Real Estate Credit Facility.

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 United States.

Our international operations are subject to risks normally associated with conducting business in foreign countries, including, but not limited to, the following:

If there is a dispute relating to our international operations, we may be subject to the exclusive jurisdiction of foreign courts. In addition, we may not be able to file suits against foreign persons or subject them to the jurisdiction of a court in Canada or the U.S. or be able to enforce judgement or arbitrated awards against state-owned customers.

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.

We are subject to compliance with the United States Foreign Corrupt Practices Act (FCPA) and the Corruption of Foreign Public Official Act (Canada) (CFPOA), which generally prohibit companies from making improper payments to foreign government officials for the purpose of obtaining business. While we have developed policies and procedures designed to achieve compliance with the FCPA, CFPOA and other 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 that 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 cash flow.

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 result in changes that may 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. Laws, regulations or treaties concerning climate change or greenhouse gas emissions, including incentives to conserve energy or use alternate sources of energy, can have an adverse impact on the demand for oil and natural gas, which could have a material adverse effect on us. Such laws, regulations or treaties are evolving and it is difficult to estimate with certainty the impact they will have on our business.

In the U.S., the Biden Administration will likely implement additional regulations and oversight concerning environmental policies and federal land management compared to the Trump Administration. On January 20, 2021, President Biden took executive actions to temporarily block new leases for oil and natural gas drilling on federal lands and ordered a review of fossil-fuel subsidies. The potential for increased regulation and oversight may make it more difficult or costly for us to operate.

Governments in Canada and the U.S. may consider 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 business, financial condition, results of operations and cash flow.

Effects of climate change, including physical and regulatory impacts, could have a negative impact on our business

The effects of climate change, including physical and regulatory impacts, could have a negative impact on our operations and the demand for oil and natural gas. There is growing concern about the apparent connection between the burning of fossil fuels and climate change. Laws, regulations or treaties concerning climate change or greenhouse gas emissions, including incentives to conserve energy or use alternate sources of energy, can have an adverse impact on the demand for oil and natural gas, which could have a material adverse effect on us.

As discussed under “Business in our industry is seasonal and highly variable” on page 41, weather patterns in Canada and the northern U.S. affect activity in the oilfield services industry. Global climate change could impact the timing and length of the spring thaw and the period in which the muskeg freezes and thaws and could impact the severity of winter, which could have a material adverse affect on 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 or could increase our operating costs (such as insurance costs), which could have a material adverse affect on our business and operating results. We cannot, however, estimate the degree to which climate change and extreme climate conditions could impact our business and operating results.

Canada and the U.S. are signatories to the Paris Agreement drafted at the United Nations Framework Convention on Climate Change in December 2015. The goals of the Paris Agreement are to prevent global temperature rise from exceeding 2 degrees Celsius above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5 degrees Celsius above pre-industrial levels. On November 4, 2020, the U.S. formally withdrew from the Paris Agreement; however, on January 20, 2021, the Biden Administration re-entered the U.S. into the Paris Agreement, which may provide for climate targets that could result in reduced demand for oil and natural gas in the U.S. In Canada, in connection with its commitments under the Paris Agreement, the federal government developed the Pan-Canadian Framework on Clean Growth and Climate Change in 2016 (the “PCF”). The PCF requires all provinces and territories to have a carbon price of $30 per tonne in 2020 and rising by $10 per year to $50 per tonne in 2022. In December 2020, the Canadian Government announced proposed $15 per year increases to the carbon price commencing in 2023, to reach a total of $170 per tonne by 2050. Provinces and territories can implement either an explicit price-based system (such as the systems implemented in British Columbia and Alberta) or a cap and trade system. Saskatchewan remains the only Canadian jurisdiction that has not joined the national plan set out in the PCF. Saskatchewan released its own output-based performance standards approach, which is applied only to certain large industrial facilities. The proposed system in Saskatchewan only partially meets the PCF standards, therefore the federal carbon pollution pricing system will apply in Saskatchewan to sources not covered by Saskatchewan’s system. It is not possible at this time to predict the effect of the Paris Agreement and climate change-related legislation in Canada and the U.S. or whether additional climate-change legislation, regulations or other measures will be adopted at the federal, state, provincial or local levels in Canada and the U.S. However, further efforts by governments and non-governmental organizations to reduce greenhouse gas emissions appear likely, which, together with existing efforts, may reduce demand for oil and natural gas.

In addition to physical and regulatory effects of climate change on our business, an increasing focus on reduction of greenhouse gas emissions and a potential shift to lower carbon intensive energy sources or a shift to a lower carbon economy may depress the overall level of exploration and production activity, impacting the demand for our services. Certain investors may discourage investments into 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 our access to liquidity and capital. Additionally, if our reputation is diminished as a result of the industry we operate in or services we provide, it could result in increased operating or regulatory costs, lower shareholder confidence or loss of public support for our business. It may also encourage exploration and production companies to diversify and limit drilling to find other more energy efficient/green generating energy alternatives.

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 business, financial condition, results of operations and cash flow.

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 and shortages in supply of equipment could adversely impact our business

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. In times of increased demand for drilling services, there may be shortages of components, materials, equipment, parts and services required for our business. 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 business, financial condition, results of operations and cash flow.

The loss of one or more of our larger customers could have a material adverse effect on our business and our current backlog of contract drilling revenue may decline

In 2020, approximately 51% of our revenue was received from our 10 largest drilling customers and approximately 28% of our revenue was received from our three largest drilling customers. The loss of one or more of our larger customers could have a material adverse effect on our business, financial condition, results of operations and cash flow. In addition, financial difficulties experienced by customers could adversely impact their demand for our services and cause them to request amendments to our contracts with them. Further, consolidation among oil and natural gas exploration and production companies may reduce the number of available customers.

Our fixed-term drilling contracts generally provide our customers with an ability to terminate the contracts at their election, with an early termination payment to us if the contract is terminated prior to the expiration of the fixed term. During depressed market conditions or otherwise, customers may be unable to satisfy their contractual obligations or may seek to terminate or renegotiate or otherwise fail to honor their contractual obligations. In addition, we may not be able to perform under these contracts due to events beyond our control, and our customers may seek to terminate or renegotiate our contracts for various reasons, without paying an early termination payment. As a result, we may not realize all of our contract drilling backlog. In addition, the termination or renegotiation of fixed-term contracts without the receipt of early termination payments could have a material adverse effect on our business, financial condition, results of operations and cash flows. Our contract drilling backlog may decline, as fixed-term drilling contract coverage over time may not be offset by new or renegotiated contracts or may be reduced by price adjustments to existing contracts, including as a result of the decline in the price of oil and natural gas, capital spending reductions by our customers or other factors.

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 business, financial condition, results of operations and cash flow.

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 and technology advances, or that our competitors will not develop technological improvements that are more advantageous, timely, or cost effective.

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, which could have a material adverse effect on our business, financial condition, results of operations and cash flow. Additionally, unexpected events such as unplanned power outages, natural disasters, supply disruptions, pandemic illness or other unforeseeable circumstances could have a material adverse effect on our business, financial condition, results of operations and cash flow.

Our worldwide operations could be disrupted by terrorism, acts of war, earthquakes, telecommunications failures, power or water shortages, tsunamis, floods, hurricanes, typhoons, fires, extreme weather conditions (whether as a result of climate change or otherwise), medical epidemics or pandemics and other natural or manmade disasters or catastrophic events, for some of which we may be self-insured. The occurrence of any of these business disruptions could result in difficulties in transporting our crews, hiring or managing personnel as well as other significant losses, that may adversely affect our business, financial conditions, results of operations and cash flow, and require substantial expenditures and recovery time in order to fully resume operations.

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., wildfires, 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.

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.

We may be subject to legal proceedings and governmental investigations from time to time related to our business and operations. Lawsuits or claims against us could have a material adverse effect on our business, financial condition, results of operations and cash flow. While we maintain insurance that may cover the cost of certain litigation or have indemnity provisions in our favor, we cannot assure that any insurance or indemnification agreement will cover the cost of theses liabilities, thus litigation or claims could negatively impact our business, reputation, financial condition and cash flow.

Unionization efforts and labor regulations could materially increase our costs or limit our flexibility

Efforts may be made from time to time to unionize portions of our workforce. We may be subject to strikes or work stoppages and other labor disruptions in connection with unionization efforts or renegotiation of existing contracts with unions. Unionization efforts, if successful, new collective bargaining agreements or work stoppages could materially increase our labor costs, reduce our revenues and adversely impact our operations and cash flow.

Future local, regional, national or international outbreaks of contagious diseases, such as COVID-19, could have an adverse effect on local economies and potentially the global economy, which may adversely impact the price of and demand for oil and natural gas (and correspondingly, decrease the demand for our services, which could have a material adverse effect on our

business, financial condition, results of operations and cash flows). Additionally, such an outbreak, if uncontrolled, may result in temporary shortages of staff to the extent our work force is impacted, which may have a material adverse effect on our business.

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.

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 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.

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 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 and the unsecured senior note indentures, 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. Such volatility and uncertainty may be adversely impacted by potential negative perception of investing in the hydrocarbon industry. 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 business, financial condition, results of operations, and cash flow.

Increases to the Canadian or United States benchmark interest rates may have an impact on our cost of borrowing under our Senior Credit Facility, Real Estate 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 business, financial condition, results of operations and cash flow.

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 business financial condition, results of operations and cash flow.

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 business, financial condition, results of operations and cash flow.

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 business, financial condition, results of operations and cash flow.

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.

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 downgrades our current corporate credit rating or rating of debt, or changes our credit outlook to negative, it could have an adverse effect on our financing costs and access to liquidity and capital.

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, the perception of the industry we operate in and service and Canadian, U.S. or international economic and social factors and political events unrelated to our performance may also affect the price of our shares. Investors should therefore not

rely on past performance of our shares to predict the future performance of our shares or financial results. At times when our share price is relatively low, we may be subject to takeover attempts by certain companies or institutions acting opportunistically.

While there is currently an active trading market for our shares in both the United States and Canada, we cannot guarantee that an active trading market will be sustained in either country. There could cease to be an active trading market due to, among other factors, minimum listing requirements of stock exchanges. If an active trading market in our shares is not sustained, the trading liquidity of our shares will be limited and the market value of our shares may be reduced. The removal of our shares from stock exchanges due to the failure to maintain minimum listing requirements may have an adverse impact on the value of our shares.

While we have a normal course issuer bid in place under which we may acquire our own shares, in the future we may issue additional shares 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 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 30).

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 CGNRC, 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 results of operations and cash flow.

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 will not 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. Additionally, if our reputation is diminished as a result of the industry we operate in or service, it could result in increased operation or regulatory costs, lower shareholder confidence or loss of public support for our business.

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 all liabilities of our predecessor companies, including liabilities relating to corporate and income tax matters.

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% or more 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 income is not distributed to the person. We are not currently a CFC, but this could change in the future.

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 2020 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, 2020, management has concluded that our internal control over financial reporting is effective.

The effectiveness of internal control over financial reporting as of December 31, 2020 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.

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, 2020, 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.

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:

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:

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:

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, 2020, 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.

In this MD&A, we reference additional non-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.

We believe that adjusted EBITDA (earnings before income taxes, gain on repurchase of unsecured senior notes, finance charges, foreign exchange, impairment of goodwill, reversal of impairment of property, plant and equipment, loss on asset decommissioning, gain on asset disposals and depreciation and amortization), as reported in our Consolidated Statement of Net Earnings (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, 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, certain foreign exchange amounts and with the adoption of the new lease standard IFRS 16 - Leases, the deduction of cash lease payments incurred after December 31, 2018.

We believe that operating earnings (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 earnings (loss) is calculated as follows:

Year ended December 31 (in thousands of dollars)	2020			2019			2018
Revenue		935,753			1,541,320			1,541,189
Expenses:
Operating		583,420			1,038,967			1,067,264
General and administrative		70,869			104,010			111,830
Restructuring		18,061			6,438			1,164
Other recoveries		—			—			(14,200	)
Depreciation and amortization		316,322			333,616			377,044
Gain on asset disposals		(11,931	)		(50,741	)		(11,384	)
Loss on asset decommissioning		—			20,263			—
Reversal of impairment of property, plant and equipment		—			(5,810	)		—
Impairment of goodwill		—			—			207,544
Operating earnings (loss)		(40,988	)		94,577			(198,073	)
Foreign exchange		4,542			(8,722	)		4,017
Finance charges		107,468			118,453			127,178
Gain on redemption and repurchase of unsecured senior notes		(43,814	)		(6,815	)		(5,672	)
Income taxes		10,954			(14,957	)		(29,326	)
Net earnings (loss)		(120,138	)		6,618			(294,270	)

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.

We define working capital as current assets less current liabilities as reported in our Consolidated Statement of Financial Position.

2020 Strategic Priorities		2020 Results
Generate strong free cash flow and reduce debt by $100 million to $150 million in 2020 and by $700 million between 2018 and 2022.		Despite the drastic industry decrease in global rig count, we ended the year with total debt reduction of $171 million, exceeding the high end of our original targeted range by $21 million. This is our third consecutive year exceeding the high-end of our annual targeted range. At the conclusion of the year, we increased our long-term debt reduction target to $800 million, previously set at $700 million from 2018 through to 2022. At year-end, we reduced debt levels by approximately $550 million, just three years into our five-year debt reduction plan. Reported cash provided by operations of $226 million, compared with $288 million in 2019. At the onset of the pandemic, we prioritized maintaining a strong liquidity position. We ended the year with $661 million in liquidity, providing financial flexibility to both reduce debt and utilize our Normal Course Issuer Bid (NCIB) to repurchase and cancel 420,588 common shares for $11 million. Ended the year with a reported cash balance of $109 million and covenant relief on our Senior Credit Facility, lasting through the first quarter of 2022.
Demonstrate operational excellence in all aspects of our business including operational, financial and ESG (environmental, social and governance) metrics.		Achieved record market share levels in Canada throughout the year of over 30%. Sustained strong market share results in the U.S. at approximately 8%. U.S. Drilling margins (revenue less operating costs) of $11,518 per utilization day were driven by contracted revenues and rigid cost controls. Canada drilling margins of $8,065 per utilization day were driven by a favorable rig mix of larger AC Super Triples. International day rates remained stable at $54,811 per utilization day. Our Completion and Production Services segment generated positive cash flow, reporting Adjusted EBITDA of $11 million. Adjusted EBITDA in 2020 was $263 million, down 33% from prior year despite a 42% reduction in global drilling activity levels resulting from the COVID-19 pandemic. Released our inaugural Corporate Responsibility report, highlighting several ESG initiatives.
Leverage our Alpha Technology platform as a competitive differentiator and source of financial returns for Precision.		Precision ended the year with a total of 39 Alpha-Rigs deployed in the North American market, fully equipped with AlphaAutomation^TM. We also had 18 AlphaApps^TM available, six of which are commercialized, and demonstrated significant cost savings with recent case studies with its AlphaAnalytics^TM offering. Precision drilled over 1,800 wells since the roll-out of its AlphaAutomation^TM technology, which includes approximately 650 wells in 2020. During 2020, we drilled approximately 200 wells with AlphaApps^TM, resulting in over 2,300 App-Days during the year.

At March 12, 2021	Moody’s	S&P	Fitch
Corporate credit rating	B2	B	B+
Senior Credit Facility rating	Not rated	Not rated	BB+
Unsecured senior notes credit rating	B3	B	B+

	Covenant	At December 31, 2020
Senior Credit Facility
Consolidated senior debt to consolidated covenant EBITDA⁽¹⁾	≤ 2.50		0.23
Consolidated covenant EBITDA to consolidated interest expense	≥ 1.75		2.68

Real Estate Credit Facility
Consolidated covenant EBITDA to consolidated interest expense	≥ 1.75		2.68

Unsecured Senior Notes
Consolidated interest coverage ratio	≥ 2.00		2.57

	March 12, 2021		December 31, 2020		December 31, 2019		December 31, 2018
Shares outstanding		13,304,425		13,459,593		13,864,990		14,689,092
Deferred shares outstanding		1,470		1,470		4,659		4,659
Share options outstanding		389,258		432,458		519,232		539,951

MANAGEMENT’S DISCUSSION & ANALYSIS

ABOUT PRECISION

IMPACT OF COVID-19