Precision Drilling : MANAGEMENT’S DISCUSSION AND ANALYSIS - Form 6-K

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's Discussion and Analysis for the three and nine months ended September 30, 2021 of Precision Drilling Corporation ("Precision" or the "Corporation") prepared as of October 20, 2021 focuses on the unaudited Condensed Interim Consolidated Financial Statements and related notes and pertains to known risks and uncertainties relating to the oilfield services sector. This discussion should not be considered all-inclusive as it does not include all changes regarding general economic, political, governmental and environmental events. This discussion should be read in conjunction with the Corporation's 2020 Annual Report, Annual Information Form, unaudited September 30, 2021 Condensed Interim Consolidated Financial Statements and related notes.

This report contains "forward-looking information and statements" within the meaning of applicable securities laws. For a full disclosure of the forward-looking information and statements and the risks to which they are subject, see the "Cautionary Statement Regarding Forward-Looking Information and Statements" later in this report. This report contains references to Adjusted EBITDA (earnings before income taxes, loss (gain) on repurchase of unsecured senior notes, gain on investments and other assets, finance charges, foreign exchange, gain on asset disposals and depreciation and amortization), Covenant EBITDA, Operating Earnings (Loss), Funds Provided by (Used in) Operations and Working Capital. These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies, see "Non-GAAP Measures" later in this report.

Precision Drilling announces 2021 third quarter financial results:

·	Adjusted EBITDA (See "NON-GAAP MEASURES") of $45 million. Excluding the impact of share-based compensation charges our Adjusted EBITDA was $59 million.

·	Revenue of $254 million was an increase of 54% compared with the third quarter of 2020.

·	Net loss of $38 million or $2.86 per share compared with a net loss of $28 million or $2.08 per share in the third quarter of 2020.

·	Generated cash and funds provided by operations (see "NON-GAAP MEASURES") of $22 million and $34 million, respectively.

·	Third quarter ending cash balance was $57 million, with available liquidity of $500 million.

·	Third quarter and year to date debt reduction of $8 million and $60 million, respectively.

·	Third quarter capital expenditures were $20 million.

·	Recognized the Canadian government's Canada Emergency Wage Subsidy (CEWS) program assistance of $6 million.

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SELECT FINANCIAL AND OPERATING INFORMATION

Financial Highlights

		For the three months ended September 30,			For the nine months ended September 30,
(Stated in thousands of Canadian dollars, except per share amounts)		2021			2020			% Change			2021			2020			% Change
Revenue			253,813				164,822				54.0				691,645				734,065				(5.8	)
Adjusted EBITDA(1)			45,408				47,771				(4.9	)			128,891				208,140				(38.1	)
Operating earnings (loss)(1)			(20,762	)			(26,785	)			(22.5	)			(76,033	)			(23,375	)			225.3
Net loss			(38,032	)			(28,476	)			33.6				(150,050	)			(82,620	)			81.6
Cash provided by operations			21,871				41,950				(47.9	)			79,512				221,381				(64.1	)
Funds provided by operations(1)			33,525				27,489				22.0				89,562				135,445				(33.9	)
Capital spending:
Expansion and upgrade			5,998				-				n.m.				15,881				13,764				15.4
Maintenance and infrastructure			13,502				3,211				320.5				32,310				24,859				30.0
Intangibles			-				-				n.m.				-				57				(100.0	)
Proceeds on sale			(4,476	)			(5,705	)			(21.5	)			(10,390	)			(16,416	)			(36.7	)
Net capital spending			15,024				(2,494	)			(702.4	)			37,801				22,264				69.8
Net loss per share:
Basic			(2.86	)			(2.08	)			37.4				(11.27	)			(6.02	)			87.2
Diluted			(2.86	)			(2.08	)			37.4				(11.27	)			(6.02	)			87.2

(1)	See "NON-GAAP MEASURES."

n.m. Not meaningful

Operating Highlights

		For the three months ended September 30,			For the nine months ended September 30,
		2021			2020			% Change			2021			2020			% Change
Contract drilling rig fleet			227				227				-				227				227				-
Drilling rig utilization days:
U.S.			3,785				1,957				93.4				10,315				9,684				6.5
Canada			4,648				1,613				188.2				10,963				8,216				33.4
International			552				559				(1.3	)			1,638				1,974				(17.0	)
Revenue per utilization day:
U.S.(1)(US$)			20,331				28,334				(28.2	)			20,904				26,335				(20.6	)
Canada (Cdn$)			19,427				21,430				(9.3	)			20,295				21,593				(6.0	)
International (US$)			52,277				54,887				(4.8	)			53,095				54,631				(2.8	)
Operating cost per utilization day:
U.S. (US$)			15,120				16,037				(5.7	)			14,639				14,727				(0.6	)
Canada (Cdn$)			13,189				12,924				2.1				13,204				13,940				(5.3	)
Service rig fleet			123				123				-				123				123				-
Service rig operating hours			32,244				15,599				106.7				93,777				54,666				71.5

(1)	Includes revenue from idle but contracted rig days.

Financial Position

(Stated in thousands of Canadian dollars, except ratios)		September 30, 2021			December 31, 2020
Working capital(1)			120,259				175,423
Cash			57,096				108,772
Long-term debt			1,162,841				1,236,210
Total long-term financial liabilities			1,241,708				1,304,162
Total assets			2,720,415				2,898,878
Long-term debt to long-term debt plus equity ratio			0.48				0.47

(1)	See "NON-GAAP MEASURES."

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Summary for the three months ended September 30, 2021:

·

Revenue for the third quarter was $254 million, 54% higher than in 2020 and was the result of increased drilling and service rig activity, partially offset by lower drilling day rates. Drilling rig utilization days increased by 93% in the U.S. and 188% in Canada and well service activity increased 107% as compared with the third quarter of 2020. Our international drilling activity decreased slightly from 2020 due to the expiration of a drilling contract.

·

Adjusted EBITDA (see "NON-GAAP MEASURES") for the quarter was $45 million, $2 million lower than 2020. Our Adjusted EBITDA as a percentage of revenue was 18% this quarter, compared with 29% in the comparative quarter. Our current quarter Adjusted EBITDA was negatively impacted by higher share-based compensation charges due to our increased share price and lower average day rates, partially offset by improved activity. Excluding the impact of $13 million of share-based compensation charges, our third quarter Adjusted EBITDA was $59 million as compared with the prior year Adjusted EBITDA excluding the impact of $4 million of share-based compensation of $51 million.

·	Operating loss (see "NON-GAAP MEASURES") for the quarter was $21 million compared with $27 million in 2020.

·	General and administrative expenses this quarter were $24 million, $12 million higher than in 2020 due to our increased share-based compensation charges and lower CEWS program assistance.

·	Net finance charges for the quarter were $21 million, $7 million lower than in 2020 and was primarily due to reduced interest expense due to lower debt levels and lower average cost of borrowing.

·

In the U.S., revenue per utilization day in the third quarter of 2021 decreased to US$20,331 compared with US$28,334 in 2020. The decrease was primarily the result of lower revenue from idle but contracted rigs, turnkey activity and lower fleet average day rates, partially offset by higher Alpha revenue. During the third quarter of 2021, we recognized revenue from idle but contracted rigs and turnkey projects of nil, as compared with US$10 million and US$2 million, respectively, in 2020. Our third quarter operating costs on a per day basis decreased to US$15,120, compared with US$16,037 in 2020, and was mainly due to lower turnkey activity. On a sequential basis, revenue per utilization day, excluding revenue from turnkey drilling and idle but contracted rigs, increased by US$692 primarily due to higher fleet average day rates, while operating costs per day increased by US$1,375 due to higher repairs and maintenance.

·

In Canada, average revenue per utilization day for contract drilling rigs for the quarter was $19,427 compared with $21,430 in 2020. The lower average revenue per utilization day in 2021 was primarily due to our rig mix. Average operating costs per utilization day in Canada for the quarter increased to $13,189 compared with $12,924 in 2020. The increase was mainly due to industry wage increases, partially offset by fixed costs being spread over higher activity.

·

During the quarter, we recognized CEWS program assistance of $6 million as compared with $8 million in 2020. CEWS program assistance was presented as offsets to operating and general and administrative costs of $5 million and $1 million, respectively, as compared with $6 million and $2 million in 2020.

·

We realized third quarter revenue from international contract drilling of US$29 million in 2021, as compared with US$31 million in 2020. The lower revenue in 2021 was primarily due to lower day rates. The average revenue per utilization day for the quarter was US$52,277, 5% lower than in the third quarter of 2020.

·	Cash and funds provided by operations (see "NON-GAAP MEASURES") in the third quarter of 2021 were $22 million and $34 million, respectively, compared with $42 million and $27 million in 2020.

·	Capital expenditures were $20 million as compared with $3 million in the third quarter of 2020. Capital spending included $6 million for expansion and upgrade capital and $14 million for the maintenance of existing assets, infrastructure spending and intangibles.

·	During the third quarter of 2021, we reduced long-term debt by $8 million.

Summary for the nine months ended September 30, 2021:

·	Revenue for the first nine months of 2021 was $692 million, a decrease of 6% from 2020.

·

Adjusted EBITDA (see "NON-GAAP MEASURES") for the period was $129 million, $79 million lower than 2020. Our Adjusted EBITDA was negatively impacted by lower idle but contracted rig revenue, higher share-based compensation charges due to our increased share price and lower average day rates, partially offset by improved North American activity.

·	General and administrative costs were $77 million, an increase of $27 million from 2020. The increase was the result of higher share-based compensation charges.

·	Net finance charges were $71 million, a decrease of $12 million from 2020 primarily due to reduced interest expense due to lower debt levels and lower average cost of borrowing, partially offset by higher amortized debt issue costs.

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·	Cash provided by operations was $80 million in 2021 as compared with $221 million in 2020. Funds provided by operations (see "NON-GAAP MEASURES") in 2021 were $90 million, a decrease of $46 million from the prior year comparative period of $135 million.

·	Capital expenditures were $48 million in 2021, an increase of $10 million for the same period in 2020. Capital spending in 2021 included $16 million for expansion and upgrade capital and $32 million for the maintenance of existing assets, infrastructure spending and intangibles.

·	As of September 30, 2021, we have reduced long-term debt by $60 million and repurchased and cancelled 155,168 common shares for $4 million pursuant to our Normal Course Issuer Bid.

STRATEGY

Precision's strategic priorities for 2021 are as follows:

1.

Grow revenue and market share through our digital leadership position - Precision exited the third quarter with 46 AC Super Triple Alpha-rigs equipped with our AlphaAutomation platform and 16 commercialized AlphaApps. Our third quarter paid AlphaApp days increased 36% compared with the second quarter of 2021, with the increase largely driven by operational performance, additional revenue generating days and further uptake of customers fully utilizing our suite of Alpha technologies. During the quarter, Precision added four new AlphaAutomation customers and increased paid AlphaAutomation days, AlphaApp days and AlphaAnalytics days quarter-over-quarter by 8%, 36% and 4%, respectively.

2.

Demonstrate operational leverage to generate free cash flow and reduce debt - In the third quarter of 2021, Precision generated $22 million of cash provided by operations (see "NON-GAAP MEASURES") and $4 million of cash proceeds from the divestiture of non-core assets. As of September 30, 2021, we have reduced debt levels by $60 million, leaving $40 million of further debt reduction to achieve the low end of our 2021 debt reduction target of $100-$125 million. Precision exited the quarter with a cash balance of $57 million, US$161 million drawn on our US$500 million Senior Credit Facility and available liquidity of $500 million.

3.

Deliver leading ESG (environmental, social and governance) performance to strengthen customer and stakeholder positioning - During the third quarter, we introduced our Evergreen suite of environmental solutions focused on emissions reduction products and services to complement our Super Series drilling rigs and our Alpha digital products. We successfully deployed our first Evergreen hybrid battery storage, natural gas and low emission power generating system to a Super Triple drilling rig in the Canadian market. The system reduces GHG emissions and fuel costs, helping our customer achieve their GHG emission-reduction targets and improving their well construction economics. We have seen strong customer appetite in both Canada and the U.S. for hybrid battery power systems and have multiple commitments to deploy several additional systems by mid-2022. In the fourth quarter, we expect to deploy three real-time combustion fuel monitoring packages, using AlphaAnalytics to determine precise baseline emission data. These accurate baselines will enable us to make customer-specific recommendations to further reduce rig-generated GHG emissions.

OUTLOOK

The continued rise in global energy demand, sustained periods of strong commodity prices and the multi-year period of upstream underinvestment provide a promising backdrop for the oilfield services industry. At current commodity prices, we anticipate higher demand for our services and improved fleet utilization as customers look to maintain and replenish production levels as drilled but uncompleted well inventories have depleted.

In Canada, industry activity has surpassed pre-pandemic levels as takeaway capacity continues to improve, price differentials shrink and the startup of LNG exports is expected in the medium term.

Interest in our Evergreen solutions has gained momentum as customers look for meaningful solutions to achieve their emission reduction targets, and in many cases, also improve their well economics. Our suite of Alpha digital technologies will continue to be a key competitive differentiator as our predictable and repeatable drilling results deliver exceptional value to our customers by reducing risks, time and well construction costs.

The Government of Canada's $1.7 billion well site abandonment and rehabilitation program has supported industry activity levels and provided thousands of jobs throughout Western Canada. The program runs through to the end of 2022 with government funds provided in stages. Our well servicing business continues to capture opportunities because of our scale, operational performance and strong safety record. During the third quarter of 2021, our abandonment activity remained strong and we expect this momentum to continue through to the end of the program in 2022.

4

During 2020, the Government of Canada introduced the CEWS program to subsidize a portion of employee wages for Canadian employers whose businesses have been adversely affected by COVID-19. For the three months ended September 30, 2021, we recognized $6 million (2020 - $8 million) in CEWS program assistance, which is presented as offsets to operating and general and administrative expenses of $5 million (2020 - $6 million) and $1 million (2020 - $2 million), respectively. Unless extended, the CEWS program is expected to end in the fourth quarter of 2021.

Commodity Prices

During the third quarter of 2021, average West Texas Intermediate and Western Canadian Select oil prices were higher by 72% and 79%, respectively, from the comparative quarter. While average Henry Hub and AECO natural gas prices improved by 102% and 60%, respectively from 2020.

		For the three months ended September 30,			Year ended December 31,
		2021			2020			2020
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)			70.49				40.90				39.40
Western Canadian Select (per barrel) (US$)			56.96				31.81				35.59
Natural gas
United States
Henry Hub (per MMBtu) (US$)			4.31				2.13				2.13
Canada
AECO (per MMBtu) (CDN$)			3.61				2.26				2.24

Contracts

Year to date in 2021 we have entered into 28 term contracts. The following chart outlines the average number of drilling rigs under contract by quarter as of October 20, 2021. For those quarters ending after September 30, 2021, this chart represents the minimum number of long-term contracts from which we will earn revenue. We expect the actual number of contracted rigs to vary in future periods as we sign additional contracts.

			Average for the quarter ended 2020			Average for the quarter ended 2021
			Mar. 31			June 30			Sept. 30			Dec. 31			Mar. 31			June 30			Sept. 30			Dec. 31
Average rigs under term contract as of October 20, 2021:
	U.S.				41				32				26				24				21				24				22				22
	Canada				5				4				3				4				6				6				7				7
	International				8				8				6				6				6				6				6				6
	Total				54				44				35				34				33				36				35				35

The following chart outlines the average number of drilling rigs that we had under contract for 2020 and the average number of rigs we have under contract as of October 20, 2021.

		Average for the year ended
		2020			2021
Average rigs under term contract as of October 20, 2021:
U.S.			31				22
Canada			4				7
International			7				6
Total			42				35

In Canada, term contracted rigs normally generate 250 utilization days per year because of the seasonal nature of well site access. In most regions in the U.S. and internationally, term contracts normally generate 365 utilization days per year.

Drilling Activity

The following chart outlines the average number of drilling rigs that we had working or moving by quarter for the periods noted.

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		Average for the quarter ended 2020			Average for the quarter ended 2021
		Mar. 31			June 30			Sept. 30			Dec. 31			Mar. 31			June 30			Sept. 30
Average Precision active rig count:
U.S.			55				30				21				26				33				39				41
Canada			63				9				18				28				42				27				51
International			8				8				6				6				6				6				6
Total			126				47				45				60				81				72				98

According to industry sources, as of October 20, 2021, the U.S. active land drilling rig count has increased 98% from the same point last year while the Canadian active land drilling rig count increased by 110%. To date in 2021, approximately 78% of the U.S. industry's active rigs and 56% of the Canadian industry's active rigs were drilling for oil targets, compared with 80% for the U.S. and 54% for Canada at the same time last year.

Capital Spending

Capital spending in 2021 is expected to be $74 million and includes $51 million for sustaining, infrastructure and intangibles and $23 million for expansion and upgrades. We expect that the $74 million will be split $68 million in the Contract Drilling Services segment, $5 million in the Completion and Production Services segment and $1 million to the Corporate segment. At September 30, 2021, Precision had capital commitments of $137 million with payments expected through 2023.

SEGMENTED FINANCIAL RESULTS

Precision's operations are reported in two segments: Contract Drilling Services, which includes our drilling rig, directional drilling (divested in the third quarter of 2021), oilfield supply and manufacturing divisions; and Completion and Production Services, which includes our service rig, rental and camp and catering divisions.

		For the three months ended September 30,			For the nine months ended September 30,
(Stated in thousands of Canadian dollars)		2021			2020			% Change			2021			2020			% Change
Revenue:
Contract Drilling Services			226,957				150,773				50.5				613,032				682,060				(10.1	)
Completion and Production Services			28,143				14,443				94.9				81,354				53,631				51.7
Inter-segment eliminations			(1,287	)			(394	)			226.6				(2,741	)			(1,626	)			68.6
			253,813				164,822				54.0				691,645				734,065				(5.8	)
Adjusted EBITDA:(1)
Contract Drilling Services			55,384				51,594				7.3				163,118				236,940				(31.2	)
Completion and Production Services			5,479				3,945				38.9				17,533				5,960				194.2
Corporate and Other			(15,455	)			(7,768	)			99.0				(51,760	)			(34,760	)			48.9
			45,408				47,771				(4.9	)			128,891				208,140				(38.1	)

(1)	See "NON-GAAP MEASURES."

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

		For the three months ended September 30,			For the nine months ended September 30,
(Stated in thousands of Canadian dollars, except where noted)		2021			2020			% Change			2021			2020			% Change
Revenue			226,957				150,773				50.5				613,032				682,060				(10.1	)
Expenses:
Operating			164,521				93,669				75.6				429,036				417,496				2.8
General and administrative			7,052				5,151				36.9				20,878				20,004				4.4
Restructuring			-				359				(100.0	)			-				7,620				(100.0	)
Adjusted EBITDA(1)			55,384				51,594				7.3				163,118				236,940				(31.2	)
Depreciation			62,751				70,675				(11.2	)			191,084				220,461				(13.3	)
Gain on asset disposals			(3,035	)			(2,684	)			13.1				(5,355	)			(8,617	)			(37.9	)
Operating earnings (loss)(1)			(4,332	)			(16,397	)			(73.6	)			(22,611	)			25,096				(190.1	)
Operating earnings (loss)(1) as a percentage of revenue			(1.9	)%			(10.9	)%							(3.7	)%			3.7	%

(1)	See "NON-GAAP MEASURES."

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United States onshore drilling statistics:(1)		2021			2020
		Precision			Industry(2)			Precision			Industry(2)
Average number of active land rigs for quarters ended:
March 31			33				378				55				764
June 30			39				437				30				378
September 30			41				485				21				241
Year to date average			38				433				35				461

(1)	United States lower 48 operations only.

(2)	Baker Hughes rig counts.

Canadian onshore drilling statistics:(1)		2021			2020
		Precision			Industry(2)			Precision			Industry(2)
Average number of active land rigs for quarters ended:
March 31			42				145				63				196
June 30			27				72				9				25
September 30			51				151				18				47
Year to date average			40				123				30				89

(1)	Canadian operations only.

(2)	Baker Hughes rig counts.

Revenue from Contract Drilling Services was $227 million this quarter, 51% higher than 2020, while Adjusted EBITDA (see "NON-GAAP MEASURES") increased by 7% to $55 million. The increase in revenue and Adjusted EBITDA was primarily due to higher activity, partially offset by lower drilling day rates.

Drilling rig utilization days (drilling days plus move days) in the U.S. were 3,785, 93% higher than 2020. Drilling rig utilization days in Canada were 4,648 during the third quarter of 2021, 188% 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, a decrease of 1% from 2020 due to the expiration of a drilling contract.

Revenue per utilization day in the U.S. in the third quarter of 2021 decreased 28% from the comparable quarter. The decrease was primarily the result of lower revenue from idle but contracted rigs, turnkey activity and lower fleet average day rates, partially offset by higher Alpha revenue. In the U.S., during the third quarter of 2021, we recognized revenue from idle but contracted rigs and turnkey projects of nil, as compared with US$10 million and US$2 million, respectively, in 2020. Compared with the same quarter in 2020, drilling rig revenue per utilization day in Canada decreased 9% due to our rig mix. Our international average revenue per utilization day for the quarter was 5% lower than the third quarter of 2020, primarily due to the expiration of a drilling contract.

In the U.S., 49% of utilization days were generated from rigs under term contract as compared with 78% in the third quarter of 2020. In Canada, 12% of our utilization days in the quarter were generated from rigs under term contract, compared with 15% in 2020.

In the U.S., operating costs for the quarter on a per day basis were lower than the prior year period primarily due to lower turnkey activity. On a per utilization day basis, operating costs in Canada were higher than the 2020 quarter, mainly due to industry wage increases, partially offset by fixed costs being spread over higher activity. During the quarter, CEWS program assistance offset operating costs by $5 million as compared with $4 million in 2020.

Depreciation expense in the quarter was 11% lower than in 2020 primarily because of a lower capital asset base as assets become fully depreciated, decommissioned or disposed.

In the third quarter of 2021, we sold used assets recognizing a gain on disposal of $3 million, consistent with 2020. During the quarter, we disposed of our directional drilling business for a gain of $1 million.

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SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES

		For the three months ended September 30,			For the nine months ended September 30,
(Stated in thousands of Canadian dollars, except where noted)		2021			2020			% Change			2021			2020
Revenue			28,143				14,443				94.9				81,354				53,631				51.7
Expenses:
Operating			21,188				9,872				114.6				59,703				42,056				42.0
General and administrative			1,476				626				135.8				4,118				3,020				36.4
Restructuring			-				-				n.m.				-				2,595				(100.0	)
Adjusted EBITDA(1)			5,479				3,945				38.9				17,533				5,960				194.2
Depreciation			4,004				4,014				(0.2	)			11,859				12,416				(4.5	)
Gain on asset disposals			(95	)			(236	)			(59.7	)			(551	)			(1,237	)			(55.5	)
Operating earnings (loss)(1)			1,570				167				840.1				6,225				(5,219	)			(219.3	)
Operating earnings (loss)(1) as a percentage of revenue			5.6	%			1.2	%							7.7	%			(9.7	)%
Well servicing statistics:
Number of service rigs (end of period)			123				123				-				123				123				-
Service rig operating hours			32,244				15,599				106.7				93,777				54,666				71.5
Service rig operating hour utilization			28	%			14	%							28	%			16	%

(1)	See "NON-GAAP MEASURES."

n.m.	Not meaningful.

Completion and Production Services revenue for the third quarter of 2021 increased to $28 million as compared with $14 million in 2020. The higher revenue was primarily due to increased activity as our service rig operating hours increased by 107% from 2020. Approximately 87% of our third quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 12% of its revenue from U.S. operations compared with 19% in the comparative period.

Operating costs as a percentage of revenue increased to 75% as compared with 68% in the prior year comparative quarter. The higher percentage in 2021 was primarily the result of lower CEWS program assistance. In the third quarter of 2021, we received CEWS program assistance of $1 million as compared with $2 million in 2020.

Our third quarter Adjusted EBITDA (see "NON-GAAP MEASURES") increased by $2 million as compared with 2020 primarily from increased service rig activity and improved service rates.

Depreciation expense in the quarter was consistent with 2020.

SEGMENT REVIEW OF CORPORATE AND OTHER

Our Corporate and Other segment provides support functions to our operating segments. The Corporate and Other segment had negative Adjusted EBITDA (see "NON-GAAP MEASURES") of $15 million as compared with $8 million in the third quarter of 2020. Our Adjusted EBITDA was negatively impacted by higher share-based compensation costs as a result of our improved share price performance in 2021 and lower CEWS program assistance, partially offset by lower restructuring charges. During the quarter, CEWS program assistance offset general and administrative costs by $0.4 million as compared with $1 million in 2020. In the third quarter of 2020, we incurred $2 million of restructuring charges.

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OTHER ITEMS

Share-based Incentive Compensation Plans

We have several cash and equity-settled share-based incentive plans for non-management directors, officers, and other eligible employees. Our accounting policies for each share-based incentive plan can be found in our 2020 Annual Report.

A summary of amounts expensed under these plans during the reporting periods are as follows:

		For the three months ended September 30,			For the nine months ended September 30,
(Stated in thousands of Canadian dollars)		2021			2020			2021			2020
Cash settled share-based incentive plans			11,839				971				46,537				(50	)
Equity settled share-based incentive plans:
Executive PSU			1,468				2,434				3,639				8,128
Stock option plan			34				160				199				714
Total share-based incentive compensation plan expense (recovery)			13,341				3,565				50,375				8,792
Allocated:
Operating			3,272				740				11,437				1,754
General and Administrative			10,069				2,825				38,938				7,038
			13,341				3,565				50,375				8,792

Cash settled share-based compensation expense increased by $11 million in the current quarter primarily due to our increasing share price and the reclassification of Executive PSUs as a cash settled share-based incentive plan. Our equity settled share-based compensation expense for the third quarter of 2021 decreased by $1 million as fewer Executive PSUs were outstanding as compared with 2020.

Finance Charges

Net finance charges were $21 million as compared with $28 million in the third quarter of 2020. Interest charges on our U.S. denominated long-term debt in the third quarter of 2021 were US$15 million ($19 million) as compared with US$18 million ($24 million) in 2020.

Income Tax

Income tax recovery for the quarter was $4 million as compared with an income tax expense of $1 million in 2020. During the third quarter of 2021 and 2020, we did not recognize deferred tax assets on certain Canadian and international operating losses.

LIQUIDITY AND CAPITAL RESOURCES

The oilfield services business is inherently cyclical in nature. To manage this, we focus on maintaining a strong balance sheet so we have the financial flexibility we need to continue to manage our growth and cash flow, regardless of where we are in the business cycle. We maintain a variable operating cost structure so we can be responsive to changes in demand.

Our maintenance capital expenditures are tightly governed 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 and upgrade rig programs provide more certainty of future revenues and return on our capital investments.

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Liquidity

Amount		Availability		Used for		Maturity
Senior credit facility (secured)
US$500 million1 (extendible, revolving term credit facility with US$300 million accordion feature)		US$161 million drawn and US$31 million in outstanding letters of credit		General corporate purposes		June 18, 20251
Real estate credit facilities (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

(1)	US$53 million expires on November 21, 2023.

At September 30, 2021, we had $1,183 million outstanding under our Senior Credit Facility, Real Estate Credit Facilities and unsecured senior notes as compared with $1,250 million at December 31, 2020.

The current blended cash interest cost of our debt is approximately 6.3%.

Senior Credit Facility

The Senior Credit Facility requires we comply with certain covenants including a leverage ratio of consolidated senior debt to consolidated Covenant EBITDA (see "NON-GAAP MEASURES") 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. 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 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.

Unsecured Senior Notes

The unsecured senior notes require that we comply with restrictive and financial covenants including 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 unsecured 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 unsecured senior notes and from July 1, 2021 for the 2029 unsecured 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.

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

Real Estate Credit Facilities

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.

Covenants

At September 30, 2021, we were in compliance with the covenants of our Senior Credit Facility and Real Estate Credit Facilities.

		Covenant			At September 30, 2021
Senior Credit Facility
Consolidated senior debt to consolidated covenant EBITDA(1)			<2.50				1.33
Consolidated covenant EBITDA to consolidated interest expense			>1.75				1.96
Real Estate Credit Facilities
Consolidated covenant EBITDA to consolidated interest expense			>1.75				1.96

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

Impact of foreign exchange rates

The strengthening of the Canadian dollar during in 2021 resulted in lower translated U.S. denominated revenue and costs. On average, for the three and nine months ended September 30, 2021, the Canadian dollar strengthened by 5% and 7%, respectively, from the comparable 2020 periods. The following table summarizes the average and closing Canada-U.S. foreign exchanges rates.

		For the three months ended September 30,			For the nine months ended September 30,			At December 31,
		2021			2020			2021			2020			2020
Canada-U.S. foreign exchange rates
Average			1.26				1.33				1.25				1.35				-
Closing			1.27				1.33				1.27				1.33				1.27

Hedge of investments in foreign operations

We utilize foreign currency long-term debt to hedge our exposure to changes in the carrying values of our net investment in certain foreign operations as a result of changes in foreign exchange rates.

We have designated our U.S. dollar denominated long-term debt as a net investment hedge in our U.S. operations and other foreign operations that have a U.S. dollar functional currency. 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 (if any) in net earnings (loss).

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QUARTERLY FINANCIAL SUMMARY

(Stated in thousands of Canadian dollars, except per share amounts)		2020			2021
Quarters ended		December 31			March 31			June 30			September 30
Revenue			201,688				236,473				201,359				253,813
Adjusted EBITDA(1)			55,263				54,539				28,944				45,408
Net loss			(37,518	)			(36,106	)			(75,912	)			(38,032	)
Net loss per basic and diluted share			(2.74	)			(2.70	)			(5.71	)			(2.86	)
Funds provided by operations(1)			35,282				43,430				12,607				33,525
Cash provided by operations			4,737				15,422				42,219				21,871

(Stated in thousands of Canadian dollars, except per share amounts)		2019			2020
Quarters ended		December 31			March 31			June 30			September 30
Revenue			372,301				379,484				189,759				164,822
Adjusted EBITDA(1)			105,006				101,904				58,465				47,771
Net loss			(1,061	)			(5,277	)			(48,867	)			(28,476	)
Net loss per basic and diluted share			(0.08	)			(0.38	)			(3.56	)			(2.08	)
Funds provided by operations(1)			75,779				81,317				26,639				27,489
Cash provided by operations			74,981				74,953				104,478				41,950

(1)	See "NON-GAAP MEASURES."

CRITICAL ACCOUNTING JUDGMENTS AND ESTIMATES

Because of the nature of our business, we are required to make judgments and estimates in preparing our Condensed Consolidated Interim Financial Statements that could materially affect the amounts recognized. Our judgments and estimates are based on our past experiences and assumptions we believe are reasonable in the circumstances. The critical judgments and estimates used in preparing the Condensed Consolidated Interim Financial Statements are described in our 2020 Annual Report.

The COVID-19 global pandemic and commodity price volatility has created a challenging economic climate that may have significant adverse impacts on Precision. As the situation remains dynamic and the ultimate duration and magnitude of the impact on the economy and the financial effect on Precision is not known at this time. Our estimates and judgments made in the preparation of our Condensed Consolidated Interim Financial Statements are increasingly difficult and subject to a higher degree of measurement uncertainty during this volatile period.

EVALUATION OF CONTROLS AND PROCEDURES

Based on their evaluation as at September 30, 2021, Precision's Chief Executive Officer and Chief Financial Officer concluded that the Corporation's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act)), are effective to ensure that information required to be disclosed by the Corporation in reports that are filed or submitted to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as at September 30, 2021, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the three months ended September 30, 2021 that have materially affected, or are reasonably likely to materially affect, the Corporation's internal control over financial reporting. Management will continue to periodically evaluate the Corporation's disclosure controls and procedures and internal control over financial reporting and will make any modifications from time to time as deemed necessary.

Based on their inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

NON-GAAP MEASURES

In this report we reference non-GAAP (Generally Accepted Accounting Principles) measures. Adjusted EBITDA, Covenant EBITDA, Operating Earnings (Loss), Funds Provided by (Used in) Operations and Working Capital are terms used by us to assess performance as we believe they provide useful supplemental information to investors. These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies.

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Adjusted EBITDA

We believe that Adjusted EBITDA (earnings before income taxes, loss (gain) on repurchase of unsecured senior notes, loss (gain) on investments and other assets, finance charges, foreign exchange, gain on assets disposals and depreciation and amortization), as reported in the Interim Consolidated Statement of Net Loss, is a useful measure, because it gives an indication of the results from our principal business activities prior to consideration of how our activities are financed and the impact of foreign exchange, taxation and depreciation and amortization charges.

Covenant EBITDA

Covenant EBITDA, as defined in our Senior Credit Facility agreement, is used in determining the Corporation's compliance with its covenants. Covenant EBITDA differs from Adjusted EBITDA by the exclusion of bad debt expense, restructuring costs, certain foreign exchange amounts and the deduction of cash lease payments incurred after December 31, 2018.

Operating Earnings (Loss)

We believe that operating earnings (loss) is a useful measure because it provides an indication of the results of our principal business activities before consideration of how those activities are financed and the impact of foreign exchange and taxation. Operating earnings is calculated as follows:

		For the three months ended September 30,			For the nine months ended September 30,
(Stated in thousands of Canadian dollars)		2021			2020			2021			2020
Revenue			253,813				164,822				691,645				734,065
Expenses:
Operating			184,422				103,147				485,998				457,926
General and administrative			23,983				11,954				76,756				49,938
Restructuring			-				1,950				-				18,061
Depreciation and amortization			69,431				77,588				211,148				241,626
Gain on asset disposals			(3,261	)			(3,032	)			(6,224	)			(10,111	)
Operating earnings (loss)			(20,762	)			(26,785	)			(76,033	)			(23,375	)
Foreign exchange			464				1,161				104				2,924
Finance charges			20,639				27,613				70,783				83,276
Gain on investments and other assets			(327	)			-				(327	)			-
Loss (gain) on repurchase of unsecured notes			-				(27,971	)			9,520				(29,942	)
Loss before income taxes			(41,538	)			(27,588	)			(156,113	)			(79,633	)

Funds Provided By (Used In) Operations

We believe that funds provided by (used in) operations, as reported in the Interim Consolidated Statements of Cash Flow, is a useful measure because it provides an indication of the funds our principal business activities generate prior to consideration of working capital, which is primarily made up of highly liquid balances.

Working Capital

We define working capital as current assets less current liabilities as reported on the Interim Consolidated Statement of Financial Position.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

Certain statements contained in this report, 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").

In particular, forward looking information and statements include, but are not limited to, the following:

·	our strategic priorities for 2021;

·	our capital expenditure plans for 2021;

·	anticipated activity levels in 2021;

·	anticipated demand for our drilling rigs;

·	the average number of term contracts in place for 2021;

·	anticipated cash savings and liquidity;

·	customer adoption of Alpha technologies;

·	potential commercial opportunities and rig contract renewals; and

·	our future debt reduction plans.

These forward-looking information and statements are based on certain assumptions and analysis made by Precision in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. These include, among other things:

·	the fluctuation in oil prices may pressure customers into reducing or limiting their drilling budgets;

·	the success of our response to the COVID-19 global pandemic;

·	the status of current negotiations with our customers and vendors;

·	customer focus on safety performance;

·	existing term contracts are neither renewed nor terminated prematurely;

·	our ability to deliver rigs to customers on a timely basis; and

·	the general stability of the economic and political environments in the jurisdictions where we operate.

Undue reliance should not be placed on forward-looking information and statements. Whether actual results, performance or achievements will conform to our expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results to differ materially from our expectations. Such risks and uncertainties include, but are not limited to:

·	volatility in the price and demand for oil and natural gas;

·	fluctuations in the level of oil and natural gas exploration and development activities;

·	fluctuations in the demand for contract drilling, well servicing and ancillary oilfield services;

·	our customers' inability to obtain adequate credit or financing to support their drilling and production activity;

·	the success of vaccinations for COVID-19 worldwide;

·	changes in drilling and well servicing technology, which could reduce demand for certain rigs or put us at a competitive advantage;

·	shortages, delays and interruptions in the delivery of equipment supplies and other key inputs;

·	liquidity of the capital markets to fund customer drilling programs;

·	availability of cash flow, debt and equity sources to fund our capital and operating requirements, as needed;

·	the impact of weather and seasonal conditions on operations and facilities;

·	competitive operating risks inherent in contract drilling, well servicing and ancillary oilfield services;

·	ability to improve our rig technology to improve drilling efficiency;

·	general economic, market or business conditions;

·	the availability of qualified personnel and management;

·	a decline in our safety performance which could result in lower demand for our services;

·	changes in laws or regulations, including changes in environmental laws and regulations such as increased regulation of hydraulic fracturing or restrictions on the burning of fossil fuels and greenhouse gas emissions, which could have an adverse impact on the demand for oil and natural gas;

·	terrorism, social, civil and political unrest in the foreign jurisdictions where we operate;

·	fluctuations in foreign exchange, interest rates and tax rates; and

·	other unforeseen conditions which could impact the use of services supplied by Precision and Precision's ability to respond to such conditions.

Readers are cautioned that the forgoing list of risk factors is not exhaustive. Additional information on these and other factors that could affect our business, operations or financial results are included in reports on file with applicable securities regulatory authorities, including but not limited to Precision's Annual Information Form for the year ended December 31, 2020, which may be accessed on Precision's SEDAR profile at www.sedar.com or under Precision's EDGAR profile at www.sec.gov. The forward-looking information and statements contained in this report are made as of the date hereof and Precision undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, except as required by law.

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