EX-99.2

This Management’s Discussion and Analysis (MD&A) contains information to help you understand our business and financial performance. Information is as of March 4, 2022. 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 43. In this MD&A, we reference certain Non-Generally Accepted Accounting Principles (Non-GAAP) measures and ratios that are not defined terms under IFRS to assess our performance because we believe they provide useful supplemental information to investors. Our financial measures and ratios are defined on page 44.

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

In 2021, we launched our EverGreen^TM suite of environmental solutions, bolstering our commitment to reduce the environmental impact of oilfield operations. Our EverGreen^TM suite of environment solutions is comprised of EverGreenMonitoring^TM, EverGreenEnergy^TM and EverGreen^TM Fuel Cell.

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:

As we work to be financially, environmentally, and socially responsible, Precision is guided by our core values and corporate governance principles. With the support and oversight of our Board of Directors (Board), we are committed to maintaining ethics and integrity and recognize that governance practices such as board independence, proactive shareholder engagement and risk management help us sustain the trust we’ve built with our stakeholders.

To deliver results, we focus on operational excellence, top-tier environmental, social and governance (ESG) performance and productive stakeholder engagement. We integrate our health, safety and environmental (HSE) commitment into our operations and incorporate ESG performance goals into our compensation program.

In July 2021, we published our second annual Corporate Responsibility Report that documents our progress in ESG efforts and provides an outline of our ESG strategies, focus areas and performance. We invite you to review our Corporate Responsibility Report available at www.precisiondrilling.com/sustainability. For additional information regarding ESG matters, we invite you to review our Corporate Responsibility initiatives in our Annual Information Form, dated March 7, 2022.

We foster a culture that is inclusive and encourage our people to contribute their differing perspectives, ideas and experiences to advance the way we live and work. We know that this is not achievable unless we have a diverse and inclusive culture. With this in mind, we have commenced a process to recruit a new female director and increase diversity on our Board in 2022. Our directors have a history of achievement and an effective mix of skills, knowledge and business experience. The directors continue to provide oversight in support of future operations and monitor regulatory developments and governance best practices in Canada, the United States (U.S.) and internationally.

As part of their oversight, 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.

We have two business segments, Contract Drilling Services and Completion and Production Services, which share business support systems and corporate and administrative services.

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 9% of the active U.S. market. We also have an international presence with operations in the Middle East.

Our Super Series rigs are state-of-the-art, technologically advanced land drilling rigs ideally suited for development drilling. We have engineered our Super Series rigs to exceed performance standards required by top operators by offering highly automated features designed to improve operational efficiencies, provide a safer working environment and deliver consistent results. 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. Our Super Series Alpha^TM rigs deliver exceptional value to our customers by further reducing risks, time and overall well cost. Our Alpha^TM technologies drive performance through its core strength of integrating data insights, human ingenuity, automation consistency and smart algorithms, increasing drilling performance and cost efficiencies for our customers.

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 2021, we serviced approximately 11% of the well completion and workover service rig market demand in Canada.

At December 31, 2021, our Completion and Production Services segment consisted of:

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 Hou0,000 0 2016 2017 2018 2019 2020

In 2021, the Novel Coronavirus (COVID-19) pandemic persisted as the emergence of virus variants caused further disruptions to global markets. The challenging economic climate continued to have an adverse impact on Precision including, but not limited to, reductions in revenue and cash flows, labour constraints and supply chain inflation. The situation remains dynamic and the ultimate duration and magnitude of the impact on the economy and financial effect on Precision remains unknown at this time. Estimates and judgements made by management in the preparation of our Consolidated Financial Statements and Notes are increasingly difficult and subject to a higher degree of measurement uncertainty during this volatile period.

Precision operates in the energy services business. Our primary customers are oil and natural gas exploration and production companies, who 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 (NGLs).

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 open rock micro fissures, 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.

Our customers’ funding mechanisms used to fund exploration and development is largely 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 NGLs 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. NGLs are used as a diluent for crude oil transportation, accordingly market prices are driven by heavy oil pricing and volumes. More recently, higher crude oil prices have contributed to increased NGL prices and, in turn, provided incentives to drill in liquid-rich formations, such as the Montney and Duvernay formations in Canada. The continued development of Liquefied Natural Gas (LNG) export capacity 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.

	2021		2020		2019
Oil
West Texas Intermediate (per barrel) (US$)		67.91		39.40		57.07
Western Canadian Select (per barrel) (US$)		54.84		26.56		44.28

Natural gas
U.S.
Henry Hub (per MMBtu) (US$)		3.72		2.13		2.56
Canada
AECO (per MMBtu) (Cdn$)		3.64		2.24		1.77
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 pad 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 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 cost. Our early investment in field-hardening our digital offering and training key personnel has allowed us to rapidly scale our Super Series rig fleet following the commercialization of our Alpha^TM technologies 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 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, as at December 31, 2021 had 47 commercialized AlphaAutomation^TM systems deployed in the field that have drilled over 2,100 wells to date. We intend to deploy additional AlphaAutomation^TM systems in North America in 2022, 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, 16 commercialized, which execute multiple on-bottom, cost control, equipment optimization and emissions reduction functions. AlphaApps^TM 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 the commercialization of performance data to drive optimization and performance KPI’s. To date, AlphaAnalytics^TM has generated successful results, setting new efficiency benchmarks 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, AlphaApps^TM and AlphaAnalytics^TM help our customers achieve their efficiency goals and generate strong returns for our shareholders through service differentiation.

North American drilling activity continues to recover after the steep decline 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 2021, approximately 10,500 wells were started onshore in the U.S., compared with approximately 8,400 in 2020 and 18,000 in 2019. The industry drilled 4,557 wells in western Canada in 2021, compared with 2,960 in 2020 and 4,679 in 2019. Total industry drilling operating days were 43,795 in 2021 compared with 29,741 in 2020 and 45,334 in 2019. 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. In 2021 and into early 2022, more drilling activity has occurred in the traditional heavy oil regions of Canada as well as the Clearwater play. 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, prior experience, condition of rigs, mobilization costs, location 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 operating efficiency and minimizing environmental impact 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 pad walking systems, higher pressure and capacity mud pumps, increased setback capacity and AlphaAutomation^TM, AlphaApps^TM and AlphaAnalytics^TM. In 2021, we launched our EverGreen™ suite of environmental solutions, focused on reducing and quantifying wellsite greenhouse gas (GHG) emissions. Our Battery Energy Storage System provides significant reductions in hydrocarbon fuel use, and in turn a similar reduction in GHG emissions and fuel cost. While our Integrated Power & Emissions Fuel Monitoring System measures wellsite GHG emissions, providing our customers with real-time insight into the correlation between power demand, fuel consumption, and resulting GHG emissions throughout the well construction process. Capturing and analyzing this data across different rigs, well profiles, engine types and geographic areas, will meaningfully improve both Precision’s and our customers’ understanding of the variability of land drilling GHG emissions and help operate power generating equipment with optimal fuel consumption and carbon footprint efficiency. 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, 2021, 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 and non-productive time is a key operating metric for us and our customers. Reliable and well-maintained equipment and highly skilled crews 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 the non-productive time (to move, rig-up and rig-out) by utilizing pad walking systems, reducing the number of move loads per rig, and using mechanized equipment for safer and quicker rig component connections.

Customer’s desire experienced, proven and stable crews as they believe this leads to safer and more economic operations. Customers will usually pay a premium for a hot crew or one they have prior experience with. We focus on training, developing and retaining key leaders of our field crews, including positions referred to as driller, rig manager, and field superintendent.

Retaining these key personnel, even through periods of low activity, allows us to respond quickly with highly experienced, customer preferred, field crews during periods of increasing activity.

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 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, recordable injuries or reportable spills. We had 312 Triple Target Zero Days in 2021.

We introduced HIPO and SIF tracking in 2021 and have included a SIF metric in our 2022 short-term incentive plan. A HIPO event is defined as a near miss or other incident that has a severity potential to cause a fatality, life threatening or life altering injury, major equipment or asset damage, major environmental harm, or major operational loss. A SIF event is a near miss or incident that has a severity potential to cause a fatal or life-altering injury or illness. SIF enhances our focus on identifying and preventing the incidents that pose the greatest risk.

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 protocols and procedures, leadership, and team building.

Our fleet of drilling rigs is well positioned to address the industrialized unconventional drilling programs of our customers. The vast majority of our drilling rigs have been designed or significantly upgraded to efficiently 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.

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, typically working 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.

There are often shortages of industry manpower in peak operating periods. Having an experienced, High Performance crew is a competitive strength and is highly valued by our customers. We rely heavily on our safety record, investment in employee development, comprehensive employee training, competency development and reputation to attract and retain employees.

Our people strategies focus on initiatives that provide a safe and productive work environment, opportunity for advancement, and added wage security. We have centralized personnel, orientation and training programs in Canada and the U.S. Our people strategies have enabled us to deliver quality field crews at all points in the industry cycle.

Our ERP system is fully integrated with our drilling rigs, field facilities and corporate offices, increasing operating efficiencies and better positioning 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 7, 2022.

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 and 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, Alpha^TM technologies and EverGreen^TM suite of environmental solutions position 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 2021 strategic priorities.

2021 Strategic Priorities		2021 Results
Grow revenue and market share through our digital leadership position		Revenue increased by 6% as compared with 2020 as we achieved an average market share of 33% in Canada and 9% in the U.S. We realized U.S. drilling margins (revenue less operating costs) of US$6,165 per utilization day, supported by contracted revenues and rigid cost control. Our Canadian drilling margins were $7,371 per utilization day, driven by a favorable rig mix of larger AC Super Triples. Internationally, our day rates decreased to $52,069 per utilization day due to the expiration of drilling contracts. Our Completion and Production Services segment reported Adjusted EBITDA growth of 20% to $6 million, with year-over-year service rig activity growth of 55%. We ended the year with of 47 Alpha^TMrigs deployed in the North American market. In 2021, we increased our paid AlphaAutomation^TM days by 123% versus the prior year. We have drilled over 2,100 wells since the roll-out of AlphaAutomation^TM, including 765 wells in 2021. We had 18 AlphaApps^TM available, 16 of which were commercialized. Our paid AlphaApps^TM days in 2021 increased by more than 600% year-over-year. During 2021, we drilled 765 wells with AlphaApps^TM, resulting in over 3,900 AlphaApps^TM days during the year. In the fourth quarter of 2020, we commercialized our AlphaAnalytics^TM offering. Over the year, we steadily increased our paid AlphaAnalytics^TMdays. In 2021, our fourth quarter paid AlphaAnalytics^TM days increased 108% as compared with 2020.
Demonstrate operational leverage to generate free cash flow and reduce debt		Total debt reduction for the year was $115 million, exceeding the midpoint of our targeted range of $100 million to $125 million. This is our fourth consecutive year of achieving our stated debt reduction target and, as at December 31, 2021, we have reduced our debt levels by approximately $665 million since 2018. We issued US$400 million of unsecured senior notes due in 2029, using the proceeds along with drawings on our Senior Credit Facility to redeem in full our 2023 and 2024 unsecured senior notes. In addition, we extended the maturity of our Senior Credit Facility to June 18, 2025. Accordingly, we successfully extended our debt maturities with our earliest maturity date in 2025. We reported cash provided by operations of $139 million and an ending cash balance of $41 million. As at December 31, 2021, we had more than $530 million in available liquidity, providing financial flexibility to capture anticipated industry activity growth in 2022, reduce debt and repurchase common shares pursuant to our Normal Course Issuer Bid (NCIB). We disposed of non-core and underutilized assets for proceeds of $13 million. During the year, we repurchased and cancelled 155,168 common shares for $4 million.
Deliver leading ESG (environmental, social and governance) performance to strengthen customer and stakeholder positioning		We released our second annual Corporate Responsibility report during the second quarter and formed our ‘E-Team’ and ‘S-Team’, which are cross-functional teams tasked to develop and implement certain ESG strategies and tactics. Precision’s EverGreen™ suite of environmental solutions was launched in 2021, with development and implementation of multiple technologies aimed at reducing and quantifying greenhouse gas emissions at the wellsite. As part of our EverGreenEnergy™ sub-product line, our BESS was tested and validated to provide significant reductions in hydrocarbon fuel use, and in turn a similar reduction in emissions and fuel cost. This successful testing resulted in customer agreements for three BESS units scheduled for deployment in the first quarter of 2022, and several additional pending commitments expected by mid-year. We also completed testing and field-hardening of our Integrated Power & Emissions Fuel Monitoring System, part of our EverGreenMonitoring™ sub-product line, which is capable of measuring and communicating real-time wellsite GHG emissions. By the end of the first quarter of 2022, we expect to have eight Integrated Power & Emissions Monitoring Systems deployed, providing our customers with real-time insight into the correlation between power demand, fuel consumption, and resulting GHG emissions throughout the well construction process. Capturing and analyzing this data across different rigs, well profiles, engine types and geographic areas, will meaningfully improve both Precision’s and our customers’ understanding of the variability of land drilling GHG emissions and help operate power generating equipment with optimal fuel consumption and carbon footprint efficiency.

Year ended December 31 (in thousands of dollars, except where noted)	2021			% increase/ (decrease)			2020			% increase/ (decrease)			2019			% increase/ (decrease)
Revenue		986,847			5.5			935,753			(39.3	)		1,541,320			0.0
Adjusted EBITDA⁽¹⁾		192,772			(26.8	)		263,403			(32.7	)		391,305			4.3
Adjusted EBITDA % of revenue⁽¹⁾		19.5	%					28.1	%					25.4	%
Net earnings (loss)		(177,386	)		47.7			(120,138	)		(1,915.3	)		6,618			(102.2	)
Cash provided by operations		139,225			(38.4	)		226,118			(21.5	)		288,159			(1.8	)
Funds provided by operations⁽¹⁾		152,243			(10.8	)		170,727			(41.7	)		292,652			(6.0	)

Cash used in investing activities		56,613			39.7			40,517			(45.6	)		74,500			(26.1	)
Capital spending by spend category⁽¹⁾
Expansion and upgrade		19,006			(29.2	)		26,858			(77.8	)		120,910			82.6
Maintenance and infrastructure		56,935			64.2			34,677			(11.0	)		38,976			(19.4	)
Intangibles		—			(100.0	)		57			(92.9	)		808			(93.0	)
Proceeds on sale of property, plant and equipment		(13,086	)		(38.0	)		(21,094	)		(76.8	)		(90,768	)		271.1
Net capital spending⁽¹⁾		62,855			55.2			40,498			(42.1	)		69,926			(31.2	)

Earnings (loss) per share ($)
Basic		(13.32	)		52.1			(8.76	)		(2,004.3	)		0.46			(102.3	)
Diluted		(13.32	)		52.1			(8.76	)		(2,046.7	)		0.45			(102.2	)

Year ended December 31	2021		% increase/ (decrease)			2020		% increase/ (decrease)			2019		% increase/ (decrease)
Contract drilling rig fleet		227		—			227		0.4			226		(4.2	)
Drilling rig utilization days
U.S.		14,494		20.0			12,080		(54.5	)		26,544		(0.6	)
Canada		15,782		46.2			10,794		(25.5	)		14,498		(22.1	)
International		2,190		(13.3	)		2,526		(18.3	)		3,093		5.9
Revenue per utilization day
U.S. (US$)		21,213		(19.0	)		26,184		11.9			23,397		7.0
Canada (Cdn$)		21,105		(2.3	)		21,611		0.2			21,569		(0.3	)
International (US$)		52,837		(3.6	)		54,811		6.7			51,360		1.8
Operating cost per utilization day
U.S. (US$)		15,048		2.6			14,666		1.5			14,447		0.8
Canada (Cdn$)		13,734		1.4			13,546		(11.1	)		15,240		5.2

Service rig fleet		123		—			123		—			123		(41.4	)
Service rig operating hours		126,840		54.8			81,952		(44.3	)		147,154		(6.5	)

(in thousands of dollars, except ratios)	December 31, 2021		December 31, 2020		December 31, 2019
Working capital⁽¹⁾		81,637		175,423		201,696
Working capital ratio⁽¹⁾		1.3		2.1		1.9
Long-term debt⁽²⁾		1,106,794		1,236,210		1,427,181
Total long-term financial liabilities		1,185,858		1,304,162		1,500,950
Total assets		2,661,752		2,898,878		3,269,840
Enterprise value⁽¹⁾⁽³⁾		1,660,781		1,409,147		1,854,393
Long-term debt to long-term debt plus equity		0.5		0.5		0.5
Long-term debt to cash provided by operations⁽¹⁾		7.9		5.5		5.0

Year ended December 31 (in thousands of dollars)	2021			2020			2019
Revenue
Contract Drilling Services		877,943			861,202			1,399,068
Completion and Production Services		113,488			77,251			147,829
Inter-segment elimination		(4,584	)		(2,700	)		(5,577	)
		986,847			935,753			1,541,320
Adjusted EBITDA⁽¹⁾
Contract Drilling Services		231,532			300,425			429,483
Completion and Production Services		23,807			11,257			24,155
Corporate and Other		(62,567	)		(48,279	)		(61,733	)
		192,772			263,403			391,905
Depreciation and amortization		282,326			316,322			333,616
Gain on asset disposals		(8,516	)		(11,931	)		(50,741	)
Loss on asset decommissioning		—			—			20,263
Reversal of impairment of property, plant and equipment		—			—			(5,810	)
Foreign exchange		393			4,542			(8,722	)
Finance charges		91,431			107,468			118,453
Loss on investments and other assets		400			—			—
Loss (gain) on redemption and repurchase of unsecured senior notes		9,520			(43,814	)		(6,815	)
Loss before income tax		(182,782	)		(109,184	)		(8,339	)
Income taxes		(5,396	)		10,954			(14,957	)
Net earnings (loss)		(177,386	)		(120,138	)		6,618

Year ended December 31 (in thousands of dollars)	2021		2020		2019
Revenue
U.S.		398,024		444,052		871,651
Canada		443,772		305,613		459,377
International		145,051		186,088		210,292
		986,847		935,753		1,541,320
Total assets
U.S.		1,247,173		1,339,945		1,560,523
Canada		959,163		1,053,921		1,133,591
International		455,416		505,012		575,726
		2,661,752		2,898,878		3,269,840

2021 was highlighted by increasing industry activity, supported by strengthening commodity prices, as global oil and natural gas demand approached pre-pandemic levels and customers sought to replenish depleted well inventories. In the U.S., West Texas Intermediate (WTI) oil prices averaged US$67.91 per barrel and Henry Hub natural gas prices averaged US$3.72 per MMBtu, representing an increase of 72% and 75% from 2020, respectively. In Canada, Western Canadian Select (WCS) and AECO natural gas price averaged US$54.84 and $3.64 in 2020, respectively. Average WCS pricing was 106% higher than 2020 while AECO increased by 63%.

As compared with 2020, our revenue in 2021 increased by 5% to $987 million. Our higher revenue in the year was primarily the result of higher North American drilling and service activity, partially offset by lower average drilling day rates across all regions. We recognized Adjusted EBITDA in 2021 of $193 million, 27% lower than in 2020. Our lower Adjusted EBITDA in the current year was primarily due to higher share-based compensation charges, lower average drilling day rates and the impact of lower idle but contracted rig revenue, partially offset by higher drilling and service activity and lower restructuring costs. As compared with 2020, our U.S. drilling activity increased 20%, Canadian activity increased 46% and international activity decreased 13%. In addition, our service rig operating hours increase 55% compared with the prior year. Our net loss in 2021 was $177 million, or $13.32 per diluted share, compared with a net loss of $120 million, or $8.76 per diluted share, in 2020.

During the year, we issued US$400 million of 6.875% unsecured senior notes due in 2029 in a private offering. These unsecured senior notes were issued at a price equal to 99.253% of face value. The net proceeds from the issuance, along with amounts drawn on our Senior Credit Facility, were used to redeem in full US$286 million aggregate principal amount of our 7.750%

unsecured senior notes due 2023 and redeem in full US$263 million aggregate principal amount of our 5.250% unsecured senior notes due 2024 for a total of US$557 million, plus accrued and unpaid interest, resulting in a loss on redemption of US$8 million.

Finance charges were $91 million, a decrease of $16 million compared with 2020 and were primarily due to a reduction in interest expense related to retired debt and the impact of the strengthening of the Canadian dollar on our U.S. dollar denominated interest, partially offset by higher amortization of debt issue costs.

Capital expenditures for the purchase of property, plant and equipment and intangible assets were $76 million in 2021, an increase of $14 million from 2020. By spend category, our capital spending included $19 million for expansion and upgrades and $57 million for the maintenance of existing assets, infrastructure and intangibles.

Under IFRS, we review the carrying value of our long-lived assets for indications of impairment at the end of each reporting period. At December 31, 2021, we reviewed each of our cash-generating units (CGUs) and did not identify indications of impairment, or reversal of impairment and therefore, did not test our CGUs for impairment.

During the year, we disposed of our directional drilling business for a gain of $1 million.

We recognized a foreign exchange expense of $0.4 million in 2021 (2020 – $5 million). The lower foreign exchange expense in the current year was due to the translation impact of lower outstanding U.S. denominated intercompany payables.

In 2021, we recognized an income tax recovery of $5 million as compared with an income tax expense of $11 million in 2020. The income tax recovery in the current year was primarily the result of the reversal of temporary differences. In 2021, we continued to not recognize the benefit of Canadian and certain international deferred tax assets.

As compared with 2019, our revenue, Adjusted EBITDA and net earnings declined in 2020 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 the year. 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.

In 2020, 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.

Capital expenditures for the purchase of property, plant and equipment and intangible assets were $62 million in 2020, a decrease of $99 million from 2019. By spend category, our capital spending included $27 million for expansion and upgrades and $35 million for the maintenance of existing assets, infrastructure and intangibles.

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.

In 2020, 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.

During 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.

Year ended December 31 (in thousands of dollars, except where noted)	2021			% of revenue			2020			% of revenue			2019			% of revenue
Revenue		877,943						861,202						1,399,068
Expenses
Operating		618,327			70.4			526,716			61.2			927,612			66.3
General and administrative		28,084			3.2			26,441			3.1			38,927			2.8
Restructuring		—			—			7,620			0.9			3,046			0.2
Adjusted EBITDA⁽¹⁾		231,532			26.4			300,425			34.9			429,483			30.7
Depreciation and amortization		256,072			29.2			288,389			33.5			300,882			21.5
Gain on asset disposals		(7,673	)		(0.9	)		(10,171	)		(1.2	)		(46,849	)		(3.3	)
Loss on asset decommissioning		—			—			—			—			20,263			1.4
Reversal of impairment of property, plant and equipment		—			—			—			—			(5,810	)		(0.4	)
Operating earnings (loss)⁽¹⁾		(16,867	)		(1.9	)		22,207			2.6			160,997			11.5

Revenue from Contract Drilling Services was $878 million, 2% higher than 2020 due to higher drilling activity in North America, offset by lower average revenue day rates and lower international activity. In 2021, we did not recognize any U.S. idle but contracted rig revenue as compared with US$37 million in the prior year. In Canada, we recognized $1 million of shortfall payments, consistent with 2020.

Operating expenses in 2021 were 70% of revenue, 9% higher than the prior year and was primarily due to the impact of lower U.S. idle but contracted rig revenue. On a per utilization day basis, in the U.S., operating costs were 3% higher than the prior year primarily due to higher rig operating expenses and repairs and maintenance, offset by fixed operating overheads spread over more utilization days. Operating costs on a per day basis in our Canadian drilling rig division were 1% higher than in 2020, primarily due to increased industry-wide wage increases.

General and administrative expenses for 2021 increased by 6% higher due to higher share-based compensation charges resulting from our increased share price. In 2020, we incurred $8 million of restructuring charges, as we aligned our cost structure and personnel to reflect lower drilling activity.

During the year, we recognized Canada Emergency Wage Subsidy (CEWS) program assistance of $16 million, as compared with $15 million in 2020.

Our 2021 operating loss was $17 million as compared with operating earnings of $22 million in the prior year. Our lower operating earnings in 2021 was primarily due to the impact of lower idle but contracted rig revenue and higher share-based compensation charges, partially offset by lower depreciation and amortization.

Our depreciation expense for 2021 was lower by 11% compared with the prior year due to asset sales and assets becoming fully depreciated.

During the year, we disposed of our directional drilling business for a gain of $1 million.

Capital expenditures in 2021 for our Contract Drilling segment were $71 million. Our capital spending by spend category was:

Year ended December 31	2021		% increase/ (decrease)			2020		% increase/ (decrease)			2019		% increase/ (decrease)
Number of drilling rigs (year-end)		227		—			227		0.4			226		(4.2	)
Drilling utilization days (operating and moving)
U.S.		14,494		20.0			12,080		(54.5	)		26,544		(0.6	)
Canada		15,782		46.2			10,794		(25.5	)		14,498		(22.1	)
International		2,190		(13.3	)		2,526		(18.3	)		3,093		5.9
Drilling revenue per utilization day
U.S.		21,213		(19.0	)		26,184		11.9			23,397		7.0
Canada		21,105		(2.3	)		21,611		0.2			21,569		(0.3	)
International		52,837		(3.6	)		54,811		6.7			51,360		1.8

Revenue from U.S. drilling was US$307 million, 3% lower than 2020. Drilling rig activity, as measured by utilization days, was up 20% from 2020 while average revenue per day was down 19%.

Adjusted EBITDA was US$78 million, 37% lower than 2020, mainly because of lower average day rates and idle but contracted revenue, partially offset by higher activity and lower restructuring costs.

Our average day rates in the U.S. decreased 19% compared with 2020 due to lower average day rates and revenue from idle but contracted rigs, partially offset by higher Alpha^TM revenue. During the year, we did not recognize revenue from idle but contracted rigs, as compared with US$37 million in 2020. In 2021, we recognized turnkey revenue of US$14 million which accounted for 4% of our U.S. drilling revenue as compared with US$11 million and 3% in 2020, respectively.

Depreciation expense for the year was US$100 million, US$6 million lower than 2020 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 40 rigs working in 2021, 21% higher than 2020, as industry activity increased by 10%. The average number of active land rigs for the industry was 461 in 2021 as compared with 420 rigs in the prior year.

	2021				2020				2019
	Precision		Industry⁽¹⁾		Precision		Industry⁽¹⁾		Precision		Industry⁽¹⁾
Average number of active land rigs for quarters ended:
March 31		33		378		55		764		79		1,023
June 30		39		437		30		378		77		967
September 30		41		485		21		241		72		896
December 31		45		545		26		297		63		798
Annual average		40		461		33		420		73		921

Revenue from Canadian drilling was $333 million, 43% higher than 2020. Drilling rig activity, as measured by utilization days, was up by 46% while average day rates were down 2% compared with the prior year.

Adjusted EBITDA was $108 million, 40% higher than 2020, as a result of higher drilling activity and lower restructuring costs.

During the year, we recognized CEWS program assistance of $16 million, as compared with $15 million in 2020. In 2021, CEWS program assistance was presented as offsets to operating and general and administrative expenses of $15 million and $1 million, respectively, as compared with $14 million and $1 million in 2020.

Depreciation expense for the year was $90 million, 5% lower than 2020 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 2020. We averaged 43 rigs working in 2021, 48% higher than 2020 which was consistent with industry as the average number of active land rigs for the year rose to 132 from 89.

	2021				2020				2019
	Precision		Industry⁽¹⁾		Precision		Industry⁽¹⁾		Precision		Industry⁽¹⁾
Average number of active land rigs for quarters ended:
March 31		42		145		63		196		48		183
June 30		27		72		9		25		27		82
September 30		51		151		18		47		42		132
December 31		52		160		28		88		43		138
Annual average		43		132		29		89		40		134

Year ended December 31 (in thousands of dollars, except where noted)	2021			% of revenue			2020			% of revenue			2019			% of revenue
Revenue		113,488						77,251						147,829
Expenses
Operating		84,401			74.4			59,404			76.9			116,932			79.1
General and administrative		5,280			4.7			3,995			5.2			6,285			4.3
Restructuring		—			—			2,595			3.4			457			0.3
Adjusted EBITDA⁽¹⁾		23,807			21.0			11,257			14.6			24,155			16.3
Depreciation and amortization		15,405			13.6			16,375			21.2			17,881			12.1
Gain on asset disposals		(525	)		(0.5	)		(1,447	)		(1.9	)		(3,767	)		(2.5	)
Operating earnings (loss)⁽¹⁾		8,927			7.9			(3,671	)		(4.8	)		10,041			6.8

Revenue from Completion and Production Services was $113 million, 47% higher than 2020, resulting from increased activity across all divisions and improved hourly service rates.

Operating expenses were 74% of segment revenue, 3% lower than 2020, which was primarily the result of our improved cost structure that was implemented in 2020 incurring restructuring charges of $3 million.

During the year, we recognized CEWS program assistance of $6 million, as compared with $7 million in 2020. In 2021, CEWS program assistance was presented as offsets to operating and general and administrative expenses of $5 million and $1 million, respectively, as compared with $6 million and $1 million in 2020.

Our increased activity in 2021 resulted in operating earnings of $9 million, compared with an operating loss of $4 million in 2020.

Depreciation in 2021 decreased by 6% due to our lower capital asset base as assets become fully depreciated, decommissioned, or were disposed.

Capital expenditures in 2021 were $4 million, comprised mainly of maintenance capital.

Our current year service rig operating hours rose by 55% versus the comparable period.

Year ended December 31 (in thousands of dollars, except where noted)	2021			2020			2019
Expenses
General and administrative		62,567			40,433			58,798
Restructuring		—			7,846			2,935
Adjusted EBITDA⁽¹⁾		(62,567	)		(48,279	)		(61,733	)
Depreciation and amortization		10,849			11,558			14,853
Gain on asset disposals		(318	)		(313	)		(125	)
Operating loss⁽¹⁾		(73,098	)		(59,524	)		(76,461	)

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 $63 million in 2021, $22 million higher than 2020. The increase was mainly related to increased share-based compensation charges, resulting from our higher share price in the current year, and lower CEWS program assistance. During the year, we recognized CEWS program assistance of $2 million, as compared with $4 million in 2020. In 2021, corporate general and administrative costs were 6.3% of consolidated revenue compared with 4.3% in the prior year.

In 2020, we recognized $8 million in restructuring costs, comprised of severance costs, as we aligned our cost structure in response to our reduced activity levels. We did not incur any restructuring costs in 2021.

Capital expenditures in 2021 for our Corporate and Other segment were $1 million, primarily related to infrastructure.

2021 – Quarters Ended (in thousands of dollars, except per share amounts)	March 31			June 30			September 30			December 31
Revenue		236,473			201,359			253,813			295,202
Adjusted EBITDA⁽¹⁾		54,539			28,944			45,408			63,881
Net loss		(36,106	)		(75,912	)		(38,032	)		(27,336	)
per basic share		(2.70	)		(5.71	)		(2.86	)		(2.05	)
per diluted share		(2.70	)		(5.71	)		(2.86	)		(2.05	)
Funds provided by (used in) operations⁽¹⁾		43,430			12,607			33,525			62,681
Cash provided by operations		15,422			42,219			21,871			59,713

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⁽¹⁾		101,904			58,465			47,771			55,263
Net 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⁽¹⁾		81,317			26,639			27,489			35,282
Cash provided by operations		74,953			104,478			41,950			4,737

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 2021, we recorded a net loss of $27 million or a net loss of $2.05 per diluted share compared to a net loss of $38 million or a net loss of $2.74 per diluted share in 2020.

Revenue for the fourth quarter was $295 million, 46% higher than in 2020 and was the result of increased drilling and service rig activity, partially offset by lower average revenue rates in the U.S. and internationally. Compared with the fourth quarter of 2020, our drilling activity increased 74% in the U.S. and 87% in Canada, while international activity remained consistent. Our 2021 fourth quarter revenue from our Contract Drilling Services and Completion and Production Services segments increased 48% and 36%, respectively, from the comparable 2020 quarter.

Adjusted EBITDA was $64 million, an increase of $9 million from the fourth quarter of 2020. Our higher Adjusted EBITDA in the current quarter was mainly due to higher drilling and service activity, lower share-based compensation charges, partially offset by lower CEWS program assistance, U.S. wage increases and labour settlement, and the impact of a $3 million inventory write-down.

Revenue from Contract Drilling Services was $265 million this quarter, 48% higher than 2020, while Adjusted EBITDA increased by 8% to $68 million. The increase in revenue and Adjusted EBITDA was primarily due to higher activity, partially offset by lower U.S. and international drilling day rates.

Our fourth quarter drilling rig utilization days in the U.S. were 4,179, 74% higher than in 2020. Drilling rig utilization days in Canada were 4,819 during the fourth quarter of 2021, 87% higher than 2020. The increase in utilization days in both the U.S. and Canada was consistent with higher industry activity. Drilling rig utilization days in our international business were 552, consistent with 2020.

Revenue per utilization day in the U.S. decreased in the fourth quarter of 2021 to US$21,976 from US$25,577 in the prior year quarter. The decrease was primarily the result of lower revenue from idle but contracted rigs and lower fleet average day rates. During the fourth quarter of 2021, we recognized revenue from idle but contracted rigs and turnkey projects of nil and US$6 million, respectively, as compared with US$7 million and US$5 million in 2020. Excluding the impact of idle but contracted rig revenue, our fourth quarter 2021 average revenue per utilization day was down 3% compared with 2020. In Canada, average revenue per utilization day for contract drilling rigs for the quarter was $22,948 compared with $21,670 in 2020. The higher average revenue per utilization day in 2021 was primarily due to our higher average day rates. Average revenue per utilization day in our international contract drilling business was US$52,069 compared with US$55,453 in the prior year quarter. The lower average rate in 2021 was primarily due to the expiration of a drilling contract.

In the U.S., 51% of utilization days were generated from rigs under term contract as compared with 62% in the fourth quarter of 2020. In Canada, 13% of our utilization days in the quarter were generated from rigs under term contract, compared with 11% in 2020.

Operating costs were 71% of revenue for the quarter, as compared to 61% in the prior year period. In the U.S., our fourth quarter operating costs on a per day basis increased to US$16,056, compared with US$14,419 in 2020 due to higher rig operating expenses, partially offset by the impact of fixed costs being spread over higher activity and lower turnkey costs. During the fourth quarter of 2021, we incurred a non-recurring wage dispute settlement charge of US$1.5 million that increased daily operating costs by US$378 per day. Additionally, in December of 2021, we implemented field wage increases and after quarter end, adjusted day rates for these increases. The higher wages increased our daily operating costs by US$242 per day and negatively impacted field margins for the quarter by the same amount. In the prior year quarter, we recognized US$3 million of certain operating cost recoveries, further reducing our comparative daily operating costs by approximately US$1,300 per day.

In Canada, our average operating costs per utilization day for the quarter increased to $14,935 compared with $12,291 in 2020. The increase was mainly due to industry-wide wage increases and lower CEWS program assistance, partially offset by fixed costs being spread over higher activity. During the quarter, we did not recognize any CEWS program assistance as compared with $6 million in 2020.

Depreciation expense in the quarter was 4% lower than in 2020 primarily because of a lower capital asset base as assets become fully depreciated, decommissioned or disposed.

In the fourth quarter of 2021, we sold used assets recognizing a gain on disposal of $2 million, consistent with 2020.

Completion and Production Services revenue for the fourth quarter of 2021 increased to $32 million as compared with $24 million in 2020. The higher revenue was primarily due to increased average hourly service rates and service activity. Our fourth quarter service rig operating hours were 33,063, an increase of 21% from 2020. Approximately 78% of our fourth quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 11% of its revenue from U.S. operations compared with 21% in the comparative period.

Operating costs as a percentage of revenue increased to 77% as compared with 73% in the comparative quarter. The higher percentage in 2021 was primarily the result of lower CEWS program assistance. In the fourth quarter of 2021, we received CEWS program assistance of $0.2 million as compared with $2 million in 2020.

As compared with 2020, our fourth quarter Adjusted EBITDA increased by $1 million to $6 million primarily from increased average hourly service rates and activity.

Depreciation expense in the quarter was 10% lower than in 2020 primarily because of a lower capital asset base as assets become fully depreciated, decommissioned or disposed.

The Corporate and Other segment had negative Adjusted EBITDA of $11 million as compared with $14 million in 2020. Our Adjusted EBITDA was positively impacted by lower share-based compensation costs, partially offset by lower CEWS program assistance. During the quarter, CEWS program assistance offset general and administrative costs by $0.1 million as compared with $1 million in 2020.

Net finance charges were $21 million as compared with $24 million in the fourth quarter of 2020. Our lower net finance charges were primarily due to reduced interest expense from lower debt levels and average cost of borrowings. Interest charges on our U.S. denominated long-term debt in the fourth quarter of 2021 were US$15 million ($19 million) as compared with US$16 million ($21 million) in 2020.

During the quarter, we reduced debt by $55 million, primarily through repayments of our Senior Credit Facility.

Income tax expense for the quarter was $1 million as compared with $8 million in 2020. During the fourth quarter of 2021 and 2020, we did not recognize deferred tax assets on certain Canadian and international operating losses.

In 2021, we had an average of 36 drilling rigs working under term contracts. Utilization days from these contracts was approximately 37% of our total contract drilling utilization days for the year.

During 2021, commodity prices strengthened as global demand for oil and natural gas gradually returned to pre-pandemic levels. Although customer spending remained conservative, the active rig count steadily increased in North America as customers sought to replenish production levels after depleting their drilled but uncompleted well inventories since the onset of pandemic. As of March 4, 2022, the U.S. rig count was approximately 66% higher than the same time last year and has averaged approximately 63% higher year-to-date compared to 2021. In Canada, the industry rig count at March 4, 2022 was approximately 37% higher in Canada than it was a year ago while the year-to-date rig count has averaged approximately 31% higher than 2021. Our U.S. and Canadian activity for the remainder of the year is expected to be determined by the strength in commodity prices and 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 as the region has been slow to reemerge from the pandemic. We remain optimistic in our ability to secure rig 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 2022 is expected to be $98 million and includes $56 million for maintenance, infrastructure, and intangibles and $42 million for expansion and upgrades. Capital spending by spend category is expected to be $91 million in the Contract Drilling Services segment, $6 million in the Completion and Production Services segment and $1 million to the Corporate segment. At December 31, 2021, Precision had capital commitments of $137 million with payments expected through 2024.

Our debt reduction plans will continue with the goal of repaying over $400 million in debt over the next four years and reaching a sustained Net Debt to Adjusted EBITDA ratio of below 1.5 times. At the end of 2025, we expect to have reduced debt by well over $1 billion since 2018. In addition to debt reduction targets through 2025, we plan to allocate 10% to 20% of free cash flow before debt principal repayments toward the return of capital to shareholders.

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 variable cost structure so we can respond 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.

During 2021, we maintained our strong liquidity position, exiting the year with a cash balance of $41 million and approximately $490 million of available borrowing capacity under our secured credit facilities, providing us with more than $530 million of total liquidity. To provide additional liquidity, we established a Canadian Real Estate Credit Facility in the amount of $20 million in the first quarter of 2021.

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

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 of our shareholders relative to the shareholder returns of our peers.

(in thousands of dollars, except ratios)	December 31, 2021		December 31, 2020		December 31, 2019
Working capital⁽¹⁾		81,637		175,423		201,696
Working capital ratio⁽¹⁾		1.3		2.1		1.9
Long-term debt⁽²⁾		1,106,794		1,236,210		1,427,181
Total long-term financial liabilities		1,185,858		1,304,162		1,500,950
Total assets		2,661,752		2,898,878		3,269,840
Enterprise value⁽¹⁾⁽³⁾		1,660,781		1,409,147		1,854,393
Long-term debt to long-term debt plus equity		0.5		0.5		0.5
Long-term debt to cash provided by operations⁽¹⁾		7.9		5.5		5.0
Net debt to Adjusted EBITDA⁽¹⁾		5.5		4.3		3.5

Credit ratings affect our ability to obtain short and long-term financing, the cost of this financing, and our ability to engage in certain business activities cost-effectively.

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 2021, 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.

In 2021, cash provided by operations was $139 million compared with $226 million in 2020. The decrease was primarily attributable to higher share-based compensation charges, lower U.S. idle but contracted rig revenue and the impact of increased working capital draws resulting from our increased activity in 2021.

The $76 million in capital expenditures in 2021 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 $13 million in 2021 compared with $21 million in 2020. During the year, we disposed of our directional drilling business for a gain of $1 million.

In 2021, cash used in financing activities was $150 million as compared with $146 million in 2020. Our 2021 financing activities were comprised of:

Amount	Availability	Used for	Maturity
Senior Credit Facility (secured)
US$500¹ million (extendible, revolving term credit facility with US$300 million accordion feature)	US$118 million drawn and US$33 million in outstanding letters of credit	General corporate purposes	June 18, 2025¹
Real estate credit facility (secured)
US$10 million	Fully drawn	General corporate purposes	November 19, 2025
$19 million	Fully drawn	General corporate purposes	March 16, 2026
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$3 million in outstanding letters of credit	Letters of credit
Unsecured senior notes (unsecured)
US$348 million – 7.125%	Fully drawn	Debt redemption and repurchases	January 15, 2026
US$400 million – 6.875%	Fully drawn	Debt redemption and repurchases	January 15, 2029

At December 31, 2021, we were in compliance with the covenants of our Senior Credit Facility, Real Estate Credit Facility and unsecured senior notes.

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

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 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 Senior Credit Facility requires we comply with certain covenants including a leverage ratio of consolidated senior debt to consolidated Covenant EBITDA of less than 2.5:1. For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness.

On June 18, 2021, we agreed with the lenders of our Senior Credit Facility to extend the facility’s maturity date and extend and amend certain financial covenants during the Covenant Relief Period (established on April 9, 2020). The maturity date of the Senior Credit Facility was extended to June 18, 2025; however, US$53 million of the US$500 million will expire on November 21, 2023.

The lenders agreed to extend the Covenant Relief Period to September 30, 2022 and amend the consolidated Covenant EBITDA to consolidated interest coverage ratio for the most recent four consecutive quarters to be greater than or equal to 1.75:1 for the period ended September 30, 2021, 2.0:1, for the periods ending December 31, 2021 and March 31, 2022, 2.25:1 for the periods ending June 30, 2022 and September 30, 2022 and 2.5:1 for periods ending thereafter.

During the Covenant Relief Period, our distributions in the form of dividends, distributions and share repurchases are restricted to a maximum of 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.

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. We also have the option to voluntarily terminate the Covenant Relief Period prior September 30, 2022.

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.

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.

Under the Senior Credit Facility, amounts can be drawn in U.S. dollars and/or Canadian dollars. At December 31, 2021, US$118 million amounts were drawn under this facility (2020 – US$75 million). 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, 2021 outstanding letters of credit amounted to US$33 million (2020 – US$32 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.

Our Canadian Real Estate Credit Facility is secured by real properties in Alberta, Canada. Principal plus interest payments are due quarterly, based on 15-year straight-line amortization with any unpaid principal and accrued interest due at maturity. Interest is calculated using a CDOR rate plus margin.

Our U.S. Real Estate Credit Facility 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.

Our Real Estate Credit Facilities contain certain affirmative and negative covenants and events of default, customary for these types of transactions. Under the terms of these facilities, we must maintain financial covenants in accordance with the Senior Credit Facility, described above, as of the last day of each period of four consecutive fiscal quarters. For the Canadian Real Estate Credit Facility, in the event the Senior Credit Facility expires, is cancelled, or is terminated, financial covenants in effect at that time shall remain in place for the remaining duration of the facility. For the U.S. Real Estate Credit Facility, 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, 2017 for the 2026 senior notes and July 1, 2021 for the 2029 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 2021, 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, 2021 (in thousands of dollars)	Less than 1 year		1-3 years		4-5 years		More than 5 years		Total
Long-term debt⁽¹⁾		2,223		4,446		613,660		505,784		1,126,113
Interest on long-term debt⁽¹⁾		72,147		144,067		105,629		70,995		392,838
Purchase of property, plant and equipment⁽¹⁾⁽²⁾		42,248		94,883		—		—		137,131
Operating leases⁽¹⁾		10,782		18,816		10,511		2,391		42,500
Contractual incentive plans⁽¹⁾⁽³⁾		18,414		49,073		—		—		67,487
Total		145,814		311,285		729,800		579,170		1,766,069

⁽¹⁾^{U.S. dollar denominated balances are translated at the period end exchange rate of Cdn$1.00 equals US$0.}⁷⁹⁰⁹^.

⁽²⁾^B^alance^primarily^{relates to cost of rig equipment with flexible delivery schedule wherein we can take delivery between 20}²²^{and 202}⁴^.

⁽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 $}^44.69^at^{December 31, 20}²¹^.

During the third quarter of 2021, 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 1,317,158 common shares, representing 10% of the public float of common shares as of August 13, 2021. The NCIB will terminate no later than August 26, 2022. For the year ended December 31, 2021, we repurchased and cancelled a total of 155,168 common shares for $4 million.

Subsequent to December 31, 2021, Precision settled 131,950 vesting Executive PSUs in 263,900 common shares.

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.

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 judgement 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 judgements, and are the most critical to how we report our financial position and results of operations:

Climate-related risks and opportunities may have a future impact on the Corporation and its estimates and judgements, including but not limited to the useful life and residual value of its property, plant and equipment and the measurement of projected cash flows when identifying impairment triggers, performing tests for impairment or impairment recoveries of non-financial assets.

The Corporation evaluated the remaining useful lives and residual values of its property, plant and equipment, concluding they remain reasonable given the current estimate of the demand period for oil and natural gas extractive services well exceeds their remaining useful lives. In addition, the Corporation’s property, plant and equipment, including drill rig equipment, adapts to numerous low-carbon projects, including but not limited to, geothermal drilling, carbon capture and storage and the extraction of helium and hydrogen gas.

In future periods, if indications of impairment of non-financial assets exist, the Corporation’s measurement of projected cash flows may be exposed to higher estimation uncertainty, including but not limited to the Corporation’s continued capital investment required to lower the carbon intensity of its property, plant and equipment, period and growth expectations used to calculate terminal values and the Corporation’s weighted average cost of capital.

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 Corporation’s analysis is based on relevant internal and external factors that indicate a CGU may be impaired such as the obsolescence or planned disposal of significant assets, financial performance of the CGU compared to forecasts and consideration of the Corporation’s market capitalization.

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. Judgement 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 judgement 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 judgement.

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 judgement. 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 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, the conflict in Ukraine and actions of Russia or a conflict in the Middle East, expectations for global economic growth, political sanctions, trade disputes, international government sanctions, or initiatives by OPEC+, can affect supply and demand for oil and natural gas and cause extreme commodity price volatility, complicating the business planning for us and our customers and exposing us to rapid changes in demand for our services. Weather conditions, governmental regulation (in Canada and U.S.), 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.

In 2021, approximately 10,500 wells were started onshore in the U.S., compared to approximately 43,700 in 2014. In 2021, the industry drilled 4,557 wells in western Canada, compared to 10,942 in 2014. According to industry sources, the U.S. average active land drilling rig count was up approximately 10% in 2021, compared to 2020, and the Canadian average active land drilling rig count was up approximately 48% during the same period as oil and natural gas prices stabilized throughout 2021.

Recently, commodity prices have been negatively affected by a combination of factors, including increased production, the decisions of OPEC+, the COVID-19 pandemic and a strengthening in the U.S. dollar relative to most other currencies. Although OPEC+ agreed in April 2020 to oil production cuts, OPEC+ has been gradually reducing such cuts and in July 2021, agreed to further reduce such cuts on a monthly basis with a goal of phasing out all production cuts towards the end of 2022. There is no assurance that the most recent OPEC+ agreement will be observed by its parties and OPEC+ may change its agreement depending upon market conditions. Although crude oil prices have recovered since March 2020, reductions related to the onset of the COVID-19 pandemic, oil and natural gas prices are expected to continue to be volatile as a result of near-term production instability, the ongoing COVID-19 pandemic, conflict in Ukraine and actions of Russia, changes in oil and natural gas inventories, industry demand, global and national economic performance, the actions of OPEC+, and any coordinated releases of oil from

strategic reserves by the U.S. (or any other country). Certain of these events and conditions may contribute to decreased exploration and drilling activities and a decrease in confidence in the oil and natural gas industry generally. These difficulties have been exacerbated in Canada and the U.S . by political and other actions resulting in uncertainty surrounding regulatory, tax, royalty and environmental regulation. Each of these factors have adversely affected, and could continue to adversely affect, the price of oil and natural gas and drilling activities by our customers, 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 volatility in oil and natural gas prices, regulatory uncertainty, and strategies of certain of our customers to focus on debt reductions or returning cash to shareholders rather than incurring expenditures on exploration and drilling activities, many of our customers have reduced spending budgets compared to periods prior to the downturn in commodity prices experienced in 2014. 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. 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.

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, rig availability and technology 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. In addition, development of new drilling technology by competitors has increased in recent years, which could negatively affect our ability to differentiate our services. 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.

Lower activity in the contract drilling industry exposes us to the risk of oversupply of equipment

Periods of low demand often lead to low utilization. The number of drilling rigs competing for work in markets where we operate has remained the same as the industry has seen a decrease in drilling activity. 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 decline 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 17% 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.

Pipeline constraints in western Canada could 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. On March 17, 2021, 21 states filed a lawsuit in the Southern District of Texas, alleging President Biden’s order violates the U.S. Constitution. As at the date hereof, the constitutional challenge was dismissed.

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.

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.

Risks and uncertainties associated with our international operations can negatively affect our business

We conduct some of our business in the Middle East. We may decide to establish 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 civil and criminal 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 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. We could also face fines, sanctions and other penalties from authorities in other the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of drilling rigs or other assets. 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.

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. Additionally, certain investors and lenders may discourage investments or lending into the hydrocarbon industry. To the extent that certain institutions implement policies that discourage investments or lending into the hydrocarbon industry, it could have an adverse effect on the cost of capital or availability of capital for our customers, which may result in reduced spending by our 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 on the exploration and development activities of oil and natural gas exploration and production companies” on page 30.

Our Senior Credit Facility, Real Estate Credit Facilities 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 27). In the event our Consolidated Interest Coverage Ratio (as defined in our two 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 of December 31, 2021, our Consolidated Interest Coverage Ratio, as calculated per our unsecured Senior Note Indentures, was 2.06.

In addition, we must satisfy and maintain certain financial ratio tests under the Senior Credit Facility and Real Estate Credit Facilities (see Capital Structure – Material Debt on page 26). 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 Facilities 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 Facilities 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, 2021, we were in compliance with the covenants of our Senior Credit Facility and Real Estate Credit Facilities.

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. Additionally, new technologies, services or standards could render some of our services, drilling rigs or equipment obsolete, which could reduce our competitiveness and have a material adverse impact on our business, financial condition and results of operations.

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. 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, or be required from time to time, in certain countries or jurisdictions which could continue to result in decreased demand for oil and gas or increased volatility in prices for oil and gas. 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, as there are no comparable recent events to provide guidance on the spread or continuance of the COVID-19 pandemic, including future variants.

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

Additionally, any potential spread of COVID-19 amongst our or our customers’ employees or contractors may result in temporary interruptions to our business or operations, which may have an adverse effect on our financial condition, results of operations and cash flow.

Future local, regional, national or international outbreaks of contagious diseases 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 and our customers’ operations are subject to numerous environmental laws, regulations and guidelines

In addition to expanded regulations and guidelines related specifically to climate change, we and our customers are subject to numerous environmental laws and regulations, including regulations 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 regulations apply directly to our operations and authorize the recovery of damages by the government, injunctive relief, and the imposition of stop, control, remediation and abandonment orders. For instance, 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. The total costs of complying with environmental protection requirements is unknown, but we may experience increased insurance and compliance costs as further environmental laws and regulations are introduced.

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.

Governments in Canada and the U.S. may also 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.

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. There can also be no guarantee that other laws and other government programs relating to the oil and gas industry and the transportation industry will not be changed in a manner which directly and adversely impact the demand for oil and natural gas which could affect our business, nor can there be any assurances that the laws, regulations or rules governing our customers will not be changed in a manner which adversely affects our customers and, therefore, 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.

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.

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

The views on climate change are evolving at a regional, national and international level. As a result, political and economic events may significantly affect the scope and timing of climate change measures and regulations that are ultimately put in place, which may challenge the oil and gas industry in a number of ways. Additionally, the risks of natural disasters that could impact our business may increase in the future as a result of climate change. Furthermore, as societal awareness and public debate continues to grow in relation to the potential impact of climate change, consumer-demand for alternative fuel sources may continue to rise and incentives to conserve energy may be developed. Our business, financial condition, results of operations, cash flows, reputation, access to capital, access to insurance, cost of borrowing, access to liquidity, and/or business plans may, in particular, without limitation, be adversely impacted as a result of climate change and its associated impacts.

As discussed under “Business in our industry is seasonal and highly variable” on page 40, 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 and evolving climate conditions could result in increased risks of, or more frequent, natural disasters such as flooding or forest fires and 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. Extreme weather conditions could also impact the production and drilling of new wells. We cannot estimate the degree to which climate change and extreme climate conditions could impact our business and operating results.

In response to climate change and increased focus on environmental protection, environmental laws, regulations and guidelines relating to the protection of the environment, including regulations and treaties concerning climate change or greenhouse gas emissions, continue to expand in scope. There has been 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. 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.

Canada and the U.S. are signatories to the Paris Agreement drafted at the United Nations Framework Convention on Climate Change (UNFCCC) 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 United States. 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. Certain Canadian provinces, including Alberta and Saskatchewan, had previously launched constitutional challenges related to the PCF; however, on March 25, 2021, the Supreme Court of Canada released its judgement confirming the constitutionality of Canada's national carbon pricing regime. In November 2021, to conclude the 26th Conference of the Parties to the UNFCCC, nearly 200 countries including Canada signed the Glasgow Climate Pact, which reaffirms the commitments to limiting global temperature rise set out in the Paris Agreement. The Glasgow Climate Pact calls for nations to submit new targets to the UNFCCC by the end of 2022 to align with the Paris Agreement’s goals, requests that nations take accelerated actions to reduce emissions by 2030 and asks nations to accelerate the development and adoption of policies to transition towards low-emission energy systems. It also includes the party nations’ agreement on rules under the Paris Agreement to create a global carbon credit market.

As at the date hereof, it is not possible to predict the effect of the Paris Agreement, the Glasgow Climate Pact and climate change-related legislation in Canada, the U.S. and globally on our business or whether additional climate-change legislation, regulations or other measures will be adopted at the federal, state, provincial or local levels in Canada, the U.S. or globally. While some of these regulations are in effect, others remain in various phases of review, discussion or implementation, leading

to uncertainties regarding timing and effects of these emerging regulations, making it difficult to accurately determine the cost impacts and effects on our operations. 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 and potentially lead to lower demand for our services.

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 oil and gas exploration and production activity, impacting the demand for our services from the oil and gas industry. 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. A public safety performance issue could also result in reputational damage to us or increased costs of operating and insuring Precision’s assets.

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.

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.

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. Increased inflation may also result in cost increases for the key components, materials, equipment and parts we use in our business. 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 COVID-19 pandemic has resulted in acute supply chain issues for many industries that may impact our ability to obtain key components, materials, equipment and parts for our operations.

Our business could be negatively affected as a result of actions of activist shareholders and some institutional investors may be discouraged from investing in the industry in which we operate

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.

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 2021, approximately 48% of our revenue was received from our ten largest drilling customers and approximately 25% 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.

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 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. See also “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.”

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 Facilities and any debt financing we may negotiate. On July 27, 2017, the U.K. Financial Conduct Authority (FCA) 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. On July 29, 2021, the Alternative References Rates Committee formally recommended the Secured Overnight Finance Rate (SOFR) as its preferred alternative replacement rate for U.S. dollar LIBOR. Although SOFR appears to be the preferred replacement rate for U.S. dollar LIBOR at this time, it is not presently known whether SOFR or any other alternative reference rates that have been proposed will attain market acceptance as replacements of U.S. dollar LIBOR.

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.

Mergers and acquisitions entail numerous risks and may disrupt our business or distract management

We consider and evaluate mergers and acquisitions of, or significant investments in, complementary businesses and assets as part of our business strategy. Mergers and acquisitions involve numerous risks, including unanticipated costs and liabilities, difficulty in integrating the operations and assets of the merged or acquired business, the ability to properly access and maintain an effective internal control environment over a merged or acquired company to comply with public reporting requirements, potential loss of key employees and customers of the merged or acquired companies, and an increase in our expenses and working capital requirements. Any merger or 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 mergers and acquisitions and also may issue equity securities or convertible securities for mergers and 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 mergers and acquisitions. Mergers and 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 mergers and acquisitions into our operations, we may not derive the benefits such as operational or administrative synergies we expect from mergers and 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.

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, political sanctions, 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, flooding, 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.

The timing and amount of capital expenditures we incur, including those related to our Alpha^TM technologies and EverGreen^TM suite of environmental solutions, 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.

Our assessment of capital assets for impairment may result in a non-cash charge against our consolidated net income

We are required to assess our capital asset balance for impairment when certain internal and external factors indicate the need for further analysis. When assessing impairment triggers and calculating impairment it is 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 capital assets would result in a non-cash charge against net earnings, and it could be material.

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.

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 26).

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 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 2021 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, 2021, management has concluded that our internal control over financial reporting is effective.

The effectiveness of internal control over financial reporting as of December 31, 2021 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, 2021, 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 this MD&A under the section titled “Risks in our Business” and 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, 2021, 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.

Year ended December 31 (in thousands of dollars)	2021			2020			2019
Capital spending by spend category
Expansion and upgrade		19,006			26,858			120,910
Maintenance and infrastructure		56,935			34,677			38,976
Intangibles		—			57			808
		75,941			61,592			160,694
Proceeds on sale of property, plant and equipment		(13,086	)		(21,094	)		(90,768	)
Net capital spending		62,855			40,498			69,926
Purchase of investments and other assets		3,500			—			—
Changes in non-cash working capital balances		(9,742	)		19			(4,574	)
Cash used in investing activities		56,613			40,517			74,500

Year ended December 31 (in thousands of dollars)	2021			2020			2019
Revenue		986,847			935,753			1,541,320
Expenses:
Operating		698,144			583,420			1,038,967
General and administrative		95,931			70,869			104,010
Restructuring		—			18,061			6,438
Depreciation and amortization		282,326			316,322			333,616
Gain on asset disposals		(8,516	)		(11,931	)		(50,741	)
Loss on asset decommissioning		—			—			20,263
Reversal of impairment of property, plant and equipment		—			—			(5,810	)
Operating earnings (loss)		(81,038	)		(40,988	)		94,577
Foreign exchange		393			4,542			(8,722	)
Finance charges		91,431			107,468			118,453
Loss on investments and other assets		400			—			—
Loss (gain) on repurchase of unsecured senior notes		9,520			(43,814	)		(6,815	)
Income taxes		(5,396	)		10,954			(14,957	)
Net earnings (loss)		(177,386	)		(120,138	)		6,618

At March 4, 2022	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+

At December 31 (in thousands of dollars)	2021			2020			2019
Cash provided by operations		139,225			226,118			288,159
Cash used in investing activities		(56,613	)		(40,517	)		(74,500	)
Surplus (deficit)		82,612			185,601			213,659
Cash used in financing activities		(149,913	)		(145,624	)		(231,814	)
Effect of exchange rate changes on cash		(883	)		(5,906	)		(3,770	)
Net cash used		(68,184	)		34,071			(21,925	)

	Covenant	At December 31, 2021
Senior Credit Facility
Consolidated senior debt to consolidated covenant EBITDA⁽¹⁾	≤ 2.50		0.97
Consolidated covenant EBITDA to consolidated interest expense	≥ 2.00		2.83

Real Estate Credit Facility
Consolidated covenant EBITDA to consolidated interest expense	≥ 2.00		2.83

Unsecured Senior Notes
Consolidated interest coverage ratio	≥ 2.00		2.06

	March 4, 2022		December 31, 2021		December 31, 2020		December 31, 2019
Shares outstanding		13,568,325		13,304,425		13,459,593		13,864,990
Deferred shares outstanding		1,470		1,470		1,470		4,659
Share options outstanding		298,263		383,448		432,458		519,232

(in thousands of dollars, except shares outstanding and per share amounts)	December 31, 2021			December 31, 2020			December 31, 2019
Shares outstanding		13,304,425			13,459,593			13,864,990
Year-end share price on the TSX		44.69			20.93			36.20
Shares at market		594,575			281,709			501,913
Long-term debt		1,106,794			1,236,210			1,427,181
Less cash		(40,588	)		(108,772	)		(74,701	)
Enterprise value⁽¹⁾		1,660,781			1,409,147			1,854,393


NON-GAAP FINANCIAL MEASURES
We reference certain 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.
Adjusted EBITDA	We believe that adjusted EBITDA (earnings before income taxes, loss (gain) on redemption and repurchase of unsecured senior notes, loss on investments and other assets, finance charges, foreign exchange, gain on asset disposals, and depreciation and amortization), as reported in our Consolidated Statements 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. The most directly comparable financial measure is net earnings (loss).
Funds Provided by (Used In) Operations	We believe that funds provided by (used in) operations, as reported in our Consolidated Statements of Cash Flow, is a useful measure because it provides an indication of the funds our principal business activities generate prior to consideration of working capital changes, which is primarily made up of highly liquid balances. The most directly comparable financial measure is cash provided by (used in) operations.
Net Capital Spending	We believe net capital spending is a useful measure as it provides an indication of our primary investment activities. The most directly comparable financial measure is cash provided by (used in) investing activities. Net capital spending is calculated as follows:


NON-GAAP RATIOS
We reference certain additional non-GAAP ratios that are not defined terms under IFRS to assess performance because we believe they provide useful supplemental information to investors.
Adjusted EBITDA % of Revenue	We believe that adjusted EBITDA as a percentage of consolidated revenue, as reported in our Consolidated Statements of Net Earnings (Loss), provides an indication of our profitability 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.
Net Debt to Adjusted EBITDA	We believe that the net debt (long-term debt less cash, as reported in our Consolidated Statements of Financial Position) to Adjusted EBITDA ratio provides an indication to the number of years it would take for us to repay our debt obligations.
SUPPLEMENTARY FINANCIAL MEASURES
We reference certain supplementary financial measures that are not defined terms under IFRS to assess performance because we believe they provide useful supplemental information to investors.
Capital Spending by Spend Category	We provide additional disclosure to better depict the nature of our capital spending. Our capital spending is categorized as expansion and upgrade, maintenance and infrastructure, or intangibles.
Enterprise Value	We calculate our enterprise value as our market capitalization (outstanding common shares multiplied by our share price at the reporting date) plus our long-term debt less cash, as reported in our Consolidated Statements of Financial Position.
Long-term debt to cash provided by (used in) operations	We calculate our long-term debt, as reported in our Consolidated Statements of Financial Position, to cash provided by (used in) operations, as reported in our Consolidated Statements of Cash Flow.
Working Capital Ratio	We define our working capital ratio as current assets divided by current liabilities, as reported in our Consolidated Statements of Financial Position.


MANAGEMENT’S DISCUSSION & ANALYSIS


ABOUT PRECISION


IMPACT OF COVID-19