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

MANAGEMENT'S DISCUSSION AND ANALYSIS

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 certain Financial Measures and Ratios, including Adjusted EBITDA (earnings before income taxes, gain (loss) on investments and other assets, loss on repurchase of unsecured senior notes, finance charges, foreign exchange, gain on asset disposals and depreciation and amortization), Funds Provided by (Used in) Operations, Net Capital Spending 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 "Financial Measures and Ratios" later in this report.

Precision Drilling announces 2022 second quarter financial results:

·	Revenue for the quarter was $326 million, an increase of 62% as compared with 2021 as our North American drilling activity increased by 38% and drilling day rates increased in the U.S. and Canada by 25% and 30%, respectively.

·	Strengthened our contract book with year-to-date additions of 39 term contracts.

·

Adjusted EBITDA (see "FINANCIAL MEASURES AND RATIOS") of $64 million increased 122% from $29 million the prior year quarter, reflective of our success in maximizing operating leverage in a growing activity environment. Current quarter Adjusted EBITDA was negatively impacted by a $6.5 million (US$5 million) well control event, share-based compensation charges of $5 million and $9 million less of CEWS program assistance.

·	Net loss of $25 million or $1.81 per share compared with a net loss of $76 million or $5.71 per share in 2021.

·

Generated cash from operations and funds from operations (see "FINANCIAL MEASURES AND RATIOS") of $135 million and $60 million, respectively, as compared with $42 million and $13 million in 2021. Our increased activity, operational leverage and day rates and lower share-based compensation charges contributed to higher cash generation in the current quarter.

·	Reduced our Senior Credit Facility balance by approximately $70 million during the quarter, ending with $52 million of cash and more than $540 million of available liquidity.

·	Increased our capital spending plan to $149 million in response to higher demand and expected customer contracted upgrades on over 20 drilling rigs for 2022.

·	Repurchased and cancelled 60,796 common shares for $5 million under our Normal Course Issuer Bid (NCIB).

·	Completion and Production Services segment generated revenue of $33 million and Adjusted EBITDA of $5 million, increases of 60% and 14%, respectively, from the prior year second quarter.

·	Agreed to acquire the well servicing business and associated rental assets of High Arctic Energy Services Inc. (High Arctic) for $38 million subsequent to the end of the quarter.

1

SELECT FINANCIAL AND OPERATING INFORMATION

Financial Highlights

		For the three months ended June 30,		For the six months ended June 30,
(Stated in thousands of Canadian dollars, except per share amounts)			2022				2021				% Change				2022				2021				% Change
Revenue			326,016				201,359				61.9				677,355				437,832				54.7
Adjusted EBITDA(1)			64,099				28,944				121.5				100,954				83,483				20.9
Net loss			(24,611	)			(75,912	)			(67.6	)			(68,455	)			(112,018	)			(38.9	)
Cash provided by (used in) operations			135,174				42,219				220.2				69,880				57,641				21.2
Funds provided by operations(1)			60,373				12,607				378.9				90,328				56,037				61.2
Cash used in investing activities			36,782				10,150				262.4				67,125				20,064				234.6
Capital spending by spend category(1)
Expansion and upgrade			15,530				6,446				140.9				25,145				9,883				154.4
Maintenance and infrastructure			23,906				13,809				73.1				50,693				18,808				169.5
Proceeds on sale			(6,849	)			(2,590	)			164.4				(9,696	)			(5,914	)			63.9
Net capital spending(1)			32,587				17,665				84.5				66,142				22,777				190.4
Net loss per share:
Basic			(1.81	)			(5.71	)			(68.3	)			(5.06	)			(8.41	)			(39.8	)
Diluted			(1.81	)			(5.71	)			(68.3	)			(5.06	)			(8.41	)			(39.8	)

(1)	See "FINANCIAL MEASURES AND RATIOS."

Operating Highlights

		For the three months ended June 30,		For the six months ended June 30,
			2022				2021				% Change				2022				2021				% Change
Contract drilling rig fleet			226				227				(0.4	)			226				227				(0.4	)
Drilling rig utilization days:
U.S.			5,037				3,579				40.7				9,627				6,530				47.4
Canada			3,376				2,497				35.2				9,029				6,315				43.0
International			546				546				-				1,086				1,086				-
Revenue per utilization day:
U.S. (US$)			25,547				20,497				24.6				24,951				21,236				17.5
Canada (Cdn$)			26,746				20,634				29.6				25,192				20,935				20.3
International (US$)			54,612				54,269				0.6				52,436				53,512				(2.0	)
Operating cost per utilization day:
U.S. (US$)			18,864				13,745				37.2				18,628				14,360				29.7
Canada (Cdn$)			19,010				13,510				40.7				16,749				13,216				26.7
Service rig fleet			93				123				(24.4	)			93				123				(24.4	)
Service rig operating hours			30,389				26,630				14.1				68,654				61,533				11.6

Financial Position

(Stated in thousands of Canadian dollars, except ratios)			June 30, 2022				December 31, 2021
Working capital(1)			111,492				81,637
Cash			51,641				40,588
Long-term debt			1,139,720				1,106,794
Total long-term financial liabilities			1,226,744				1,185,858
Total assets			2,704,686				2,661,752
Long-term debt to long-term debt plus equity ratio (1)			0.49				0.47

(1)	See "FINANCIAL MEASURES AND RATIOS."

2

Summary for the three months ended June 30, 2022:

·

Revenue for the second quarter was $326 million, 62% higher than in 2021 and was the result of increased North American drilling and service activity and day rates. Drilling rig utilization days increased by 41% in the U.S. and 35% in Canada and well service activity increased 14% as compared with the second quarter of 2021.

·

Adjusted EBITDA for the quarter was $64 million, $35 million higher than 2021 mainly due to lower share-based compensation charges, partially offset by a $6.5 million (US$5 million) charge related to a well control event and $9 million less CEWS program assistance. Share-based compensation charges for the quarter were $5 million, $21 million lower than in 2021 with the decrease primarily due to our lower share price during the current year quarter. Please refer to "Other Items" later in this report for additional information on the well control event and share-based compensation charges.

·	Adjusted EBITDA as a percentage of revenue (see "FINANCIAL MEASURES AND RATIOS") was 20% as compared with 14% in 2021, demonstrating our ability to maximize the operating leverage within the business in a growing activity environment.

·	General and administrative expenses this quarter were $21 million, $10 million lower than in 2021 due to lower share-based compensation charges, partially offset by lower CEWS program assistance.

·	Net finance charges for the quarter were $21 million, a decrease of $7 million from 2021 due to lower debt issue costs. Our higher debt issue costs in 2021 related to accelerated amortization of issue costs associated with the unsecured senior notes that were fully redeemed in the quarter.

·

In the U.S., revenue per utilization day was US$25,547 compared with US$20,497 in 2021. The increase was primarily the result of improved pricing and turnkey activity. During the second quarter, we recognized revenue from turnkey projects of US$9 million compared with US$3 million in 2021. Revenue per utilization day in the quarter, excluding the impact of turnkey, was US$23,689, compared to US$19,666 in the prior year, an increase of $4,023. On a sequential basis, revenue per utilization day, excluding turnkey revenue, increased approximately US$1,925.

·

Our U.S. operating costs on a per day basis increased to US$18,864, compared with US$13,745 in 2021 due to higher rig operating expenses, repairs and maintenance and turnkey activity, partially offset by the impact of fixed costs being spread over higher activity. During the second quarter of 2022, we experienced a well control event resulting in a US$5 million charge, causing our daily operating costs to increase by approximately US$1,015. U.S. operating cost per day during the quarter, excluding turnkey, was US$16,517 compared with US$13,160 in the prior year. Sequentially, excluding the impact of turnkey activity, our operating costs per day increased approximately US$420.

·	In Canada, average revenue per utilization day for contract drilling for the quarter was $26,746 compared with $20,634 in 2021, an increase of 30% and the result of higher day rates and increased labor and cost recoveries.

·

Our Canadian operating costs on a per day basis increased to $19,010, compared with $13,510 in 2021 due to industry-wide wage increases, higher repairs and maintenance expense and lower CEWS program assistance. During the second quarter of 2021, we recognized $5 million of CEWS program assistance which decreased our comparative daily operating costs by $1,877. Canadian operating cost per day for the prior year quarter, excluding the impact of CEWS program assistance, were $15,387.

·

Completion and Production Services second quarter revenue and Adjusted EBITDA was $33 million and $5 million, respectively, compared with $21 million and $4 million in 2021. Our improved results were supported by higher service rates and operating hours, partially offset by lower CEWS program assistance as we recognized $3 million of assistance in 2021.

·	During the quarter, we did not recognize any CEWS program assistance as compared with $9 million in 2021. In 2021, CEWS program assistance was presented as offsets to operating and general and administrative costs of $8 million and $1 million, respectively.

·	We realized second quarter revenue from international contract drilling of US$30 million, consistent with 2021, as activity and day rates remained constant.

·

Second quarter cash provided by operations was $135 million as compared with $42 million in 2021. We generated $60 million of funds from operations as compared with $13 million in 2021. Our increased activity, operational leverage, day rates and lower share-based compensation charges contributed to higher cash generation in the current quarter.

·	Capital expenditures were $39 million as compared with $20 million in 2021. Capital spending by spend category (see "FINANCIAL MEASURES AND RATIOS") included $16 million for expansion and upgrades and $24 million for the maintenance of existing assets and infrastructure.

3

·	We reduced our Senior Credit Facility balance by approximately $70 million during the quarter, ending the quarter with $52 million of cash and more than $540 million of available liquidity. Year-to-date, we have borrowed $12 million on our Senior Credit Facility.

·	We repurchased and cancelled 60,796 common shares for $5 million under our NCIB.

·

Subsequent to the quarter, we agreed to acquire the well servicing business and associated rental assets of High Arctic for $38 million, adding 80 service rigs (51 marketed and 29 inactive) to our fleet along with related rental assets, ancillary support equipment, inventories and spares and six additional operating facilities in key operating basins.

Summary for the six months ended June 30, 2022:

·	Revenue for the first six months of 2022 was $677 million, an increase of 55% from 2021.

·

Adjusted EBITDA for the period was $101 million as compared with $83 million in 2021. Our higher Adjusted EBITDA was attributable to higher activity and day rates, partially offset by higher share-based compensation charges, the impact of the well control event and lower CEWS program assistance. Our 2021 Adjusted EBITDA was positively impact by $17 million of CEWS program assistance.

·	General and administrative costs were $77 million, an increase of $24 million from 2021 primarily due to higher share-based compensation charges of $17 million and lower CEWS program assistance of $2 million.

·	Net finance charges were $42 million, a decrease of $8 million from 2021 due to lower debt issue costs. In 2021, we accelerated the amortization of issue costs associated with fully redeemed unsecured senior notes.

·	Cash provided by operations was $70 million as compared with $58 million in 2021. Funds provided by operations in 2022 were $90 million, an increase of $34 million from the comparative period.

·	Capital expenditures were $76 million in 2022, an increase of $47 million from 2021. Capital spending by spend category included $25 million for expansion and upgrades and $51 million for the maintenance of existing assets and infrastructure.

·	Year-to-date, we have borrowed $12 million on our Senior Credit Facility and repurchased and cancelled 60,697 common shares for $5 million under our NCIB.

STRATEGY

Precision's strategic priorities for 2022 are as follows:

1.

Grow revenue through scaling AlphaTM technologies and EverGreenTM suite of environmental solutions across Precision's Super Series rig fleet and further competitive differentiation through ESG initiatives - We exited the quarter with 53 AC Super Triple AlphaTM rigs equipped with our AlphaAutomationTM platform and 20 commercialized AlphaAppsTM. As compared with the second quarter of 2021, our total paid days for AlphaAutomationTM, AlphaAppsTM and AlphaAnalyticsTM increased by 4%. As at July 26, 2022, we had three commercial, field-deployed, EverGreenTM Battery Energy Storage Systems with six additional systems scheduled for installation by year end. In addition, we had 10 EverGreenTM Integrated Power & Emissions Monitoring Systems deployed and anticipate ending the year with 15 systems installed. In July, we released our annual Corporate Responsibility Report which highlighted several key ESG accomplishments aligned with our High Performance, High Value strategy. We expanded our reporting to include additional elements from the Sustainability Accounting Standards Board and Task Force on Climate-Related Financial Disclosures guidelines.

2.

Grow free cash flow by maximizing operating leverage as demand for our High Performance, High Value services continues to rebound - During the second quarter of 2022, we generated cash from operations of $135 million. In the U.S., our second quarter average active rig count was 55, 41% higher than in 2021. In Canada, we averaged 37 active rigs for the quarter, a 37% increase from 2021. Despite industry-wide inflationary pressures, our second quarter daily operating margins (average revenue less operating costs per utilization day) in our North American contract drilling business remained strong. Our daily operating margins were secured by our strengthening day rates, growing contract book and disciplined spending. Year-to-date in 2022, we have entered into 39 term contracts and as at July 26, 2022 had 57 active rigs in the U.S. and 61 in Canada. With the tightening of available Super Series rigs, we expect to realize further pricing increases in the U.S. and Canada in the back half of 2022. Our acquisition of High Arctic's well servicing business and associated rental assets maximizes our existing operating leverage and supports future cash flow generation.

3.

Utilize free cash flow to continue strengthening our balance sheet while investing in our people, equipment and returning capital to shareholders - During the quarter, our reinvestment into our drilling fleet included $39 million of capital expenditures and we generated $7 million of cash proceeds from the divestiture of non-core assets. We repaid approximately $70 million on our Senior Credit Facility and continue to target $75 million of debt reduction for 2022 and longer-term goals of $400 million of debt reduction between 2022 and 2025 and Net Debt to Adjusted EBITDA (see "FINANCIAL MEASURES AND RATIOS") less than 1.5 times by 2025. Through share repurchases under our NCIB, we returned $5 million of capital to shareholders. We ended the quarter with a cash balance of $52 million and more than $540 million of available liquidity.

4

OUTLOOK

The return of global energy demand and the reality of a multi-year period of upstream oil and natural gas underinvestment has resulted in a shortage of oil and natural gas and higher commodity prices, providing a promising outlook for the oilfield services industry. The war in Ukraine and sanctions on Russian hydrocarbons have exacerbated the challenged supply situation and many importing countries are looking toward North America and the Middle East to fill the supply gap, both from exports of crude oil and natural gas through the global Liquified Natural Gas (LNG) market. Constrained natural gas production levels and low natural gas storage volumes have resulted in North American natural gas prices more than doubling in the last year. With U.S. LNG exports growing as countries look to displace Russian natural gas and various Canadian LNG projects to come online in 2025, we anticipate a sustained period of elevated natural gas drilling activity.

At current commodity price levels, we anticipate higher demand for our services and improved fleet utilization as customers seek to maintain production levels and replenish inventories, as drilled but uncompleted wells have been depleted over the past several years. However, broad economic concerns exist with respect to inflation, rising interest rates and geopolitical instability. These concerns may negatively impact customer spending plans.

With North American industry activity expected to further increase in 2022, we anticipate tightness in the high specification rig market with customers seeking term contracts to secure rigs and ensure fulfilment of their development programs. Accordingly, the tightening of available high specification rigs is expected to drive higher day rates and necessitate customer funded rig upgrades.

Interest in our EverGreen^TM suite of environmental solutions continues to gain momentum as customers seek meaningful solutions to achieve their emission reduction targets and improve their well economics. We expect our growing suite of Alpha^TM technologies paired with our EverGreen^TM suite of environmental solutions to be key competitive differentiators as our predictable and repeatable drilling results deliver exceptional value to our customers by reducing risks, well construction costs and carbon footprint.

The outlook for our Precision Well Servicing business remains positive with strong commodity prices supporting maintenance and completion activity as well as both federal and provincial support for increased well abandonment and rehabilitation projects. In addition, we are focusing on the successful integration of the recent purchase of High Arctic's well service and associated rental operations. By leveraging our existing platform and continuing our strict focus on cost control, we expect to realize $5 million in annualized savings, realizable within one year of completing the acquisition.

Commodity Prices

During the second quarter of 2022, average West Texas Intermediate and Western Canadian Select oil prices were higher by 64% and 76%, respectively, from the comparative quarter. While average Henry Hub and AECO natural gas prices improved by 152% and 136%, respectively from 2021.

		For the three months ended June 30,		Year ended December 31,
			2022				2021				2021
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)			108.34				65.99				67.91
Western Canadian Select (per barrel) (US$)			95.62				54.39				54.84
Natural gas
United States
Henry Hub (per MMBtu) (US$)			7.47				2.97				3.72
Canada
AECO (per MMBtu) (CDN$)			7.25				3.07				3.64

5

Contracts

Year-to-date in 2022, we have entered into 39 term contracts and 18 new contracts since the end of the first quarter of 2022. The following chart outlines the average number of drilling rigs under contract by quarter as of July 26, 2022. For those quarters ending after June 30, 2022, 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 2021		Average for the quarter ended 2022
			Mar. 31				June 30				Sept. 30				Dec. 31				Mar. 31				June 30				Sept. 30				Dec. 31
Average rigs under term contract as of July 26, 2022:
U.S.			21				24				22				24				27				29				31				27
Canada			6				6				7				7				6				8				10				11
International			6				6				6				6				6				6				4				4
Total			33				36				35				37				39				43				45				42

The following chart outlines the average number of drilling rigs that we had under contract for 2021 and the average number of rigs we have under contract as of July 26, 2022.

		Average for the year ended
			2021				2022
Average rigs under term contract as of July 26, 2022:
U.S.			23				29
Canada			7				9
International			6				5
Total			36				43

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.

		Average for the quarter ended 2021		Average for the quarter ended 2022
			Mar. 31				June 30				Sept. 30				Dec. 31				Mar. 31				June 30
Average Precision active rig count:
U.S.			33				39				41				45				51				55
Canada			42				27				51				52				63				37
International			6				6				6				6				6				6
Total			81				72				98				103				120				98

According to industry sources, as of July 26, 2022, the U.S. active land drilling rig count has increased 57% from the same point last year while the Canadian active land drilling rig count has increased by 31%. To date in 2022, approximately 79% of the U.S. industry's active rigs and 60% of the Canadian industry's active rigs were drilling for oil targets, compared with 82% for the U.S. and 58% for Canada at the same time last year.

Capital Spending and Free Cash Flow Allocation

During the quarter, we increased our capital spending plan to reflect higher maintenance capital from our increasing activity, strategic purchase of drill pipe and customer funded rig upgrades. Capital spending in 2022 is expected to be $149 million and by spend category includes $73 million for sustaining, infrastructure and intangibles and $76 million for expansion and upgrades. We expect that the $149 million will be split $141 million in the Contract Drilling Services segment, $6 million in the Completion and Production Services segment and $2 million to the Corporate segment. At June 30, 2022, Precision had capital commitments of $159 million with payments expected through 2024.

Our debt reduction plans continue with the goal of repaying over $400 million of 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 our debt reduction target through 2025, we plan to allocate 10% to 20% of free cash flow before debt principal repayments toward the return of capital to shareholders.

6

SEGMENTED FINANCIAL RESULTS

Precision's operations are reported in two segments: Contract Drilling Services, which includes our drilling rig, 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 June 30,		For the six months ended June 30,
(Stated in thousands of Canadian dollars)			2022				2021				% Change				2022				2021				% Change
Revenue:
Contract Drilling Services			294,299				181,256				62.4				608,444				386,075				57.6
Completion and Production Services			33,041				20,667				59.9				71,279				53,211				34.0
Inter-segment eliminations			(1,324	)			(564	)			134.8				(2,368	)			(1,454	)			62.9
			326,016				201,359				61.9				677,355				437,832				54.7
Adjusted EBITDA:(1)
Contract Drilling Services			70,429				47,703				47.6				141,603				107,734				31.4
Completion and Production Services			4,839				4,252				13.8				11,378				12,054				(5.6	)
Corporate and Other			(11,169	)			(23,011	)			(51.5	)			(52,027	)			(36,305	)			43.3
			64,099				28,944				121.5				100,954				83,483				20.9

(1)	See "FINANCIAL MEASURES AND RATIOS."

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

		For the three months ended June 30,		For the six months ended June 30,
(Stated in thousands of Canadian dollars, except where noted)			2022				2021				% Change				2022				2021				% Change
Revenue			294,299				181,256				62.4				608,444				386,075				57.6
Expenses:
Operating			215,676				126,394				70.6				445,727				264,515				68.5
General and administrative			8,194				7,159				14.5				21,114				13,826				52.7
Adjusted EBITDA(1)			70,429				47,703				47.6				141,603				107,734				31.4
Adjusted EBITDA as a percentage of revenue(1)			23.9	%			26.3	%							23.3	%			27.9	%

(1)	See "FINANCIAL MEASURES AND RATIOS."

United States onshore drilling statistics:(1)		2022		2021
			Precision				Industry(2)				Precision				Industry(2)
Average number of active land rigs for quarters ended:
March 31			51				603				33				378
June 30			55				687				39				437
Year to date average			53				645				36				408

(1)	United States lower 48 operations only.

(2)	Baker Hughes rig counts.

Canadian onshore drilling statistics:(1)		2022		2021
			Precision				Industry(2)				Precision				Industry(2)
Average number of active land rigs for quarters ended:
March 31			63				205				42				145
June 30			37				113				27				72
Year to date average			50				159				35				109

(1)	Canadian operations only.

(2)	Baker Hughes rig counts.

Revenue from Contract Drilling Services was $294 million this quarter, 62% higher than 2021, while Adjusted EBITDA increased by 48% to $70 million. The increase in revenue and Adjusted EBITDA was primarily due to higher North American activity and day rates.

Drilling rig utilization days (drilling days plus move days) in the U.S. were 5,037, 41% higher than 2021. Drilling rig utilization days in Canada were 3,376, 35% higher than 2021. 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 546, consistent with 2021.

Our second quarter revenue per utilization day in the U.S. increased 25% from the comparable quarter. The increase was primarily the result of improved pricing and higher turnkey activity. During the second quarter, we recognized revenue from turnkey projects of US$9 million compared with US$3 million in 2021. Compared with the same quarter in 2021, drilling rig revenue per utilization day in Canada increased 30%. The increase was the result of higher day rates and increased labor and cost recoveries. Our international revenue per utilization day for the quarter was consistent with 2021.

7

In the U.S., 49% of utilization days were generated from rigs under term contract as compared with 52% in 2021. In Canada, 19% of our utilization days were generated from rigs under term contract, compared with 16% in 2021.

In the U.S., operating costs for the quarter on a per day basis were higher by 37% compared with 2021 primarily due to higher rig operating expenses, repairs and maintenance and turnkey activity, partially offset by the impact of fixed costs being spread over higher activity. Our higher rig operating expenses in 2022 related to higher field wages and larger crew sizes. During the second and fourth quarters of 2021, we implemented field wage increases. In anticipation of increased activity, we strategically staffed active rigs with larger crews to ensure we have a sufficient number of trained and available crew personnel to meet growing customer demand. During the second quarter of 2022, we experienced a well control event resulting in a US$5 million charge, causing our daily operating costs to increase by approximately US$1,015. U.S. operating cost per day during the quarter, excluding turnkey, was US$16,517 compared with US$13,160 the prior year.

Our Canadian operating costs on a per day basis increased to $19,010, compared with $13,510 in 2021 due to industry-wide wage increases, higher repairs and maintenance expense and lower CEWS program assistance. During the second quarter of 2021, we recognized $5 million of CEWS program assistance which decreased our comparative daily operating costs by $1,877. Canadian operating cost per day for the prior year quarter, excluding the impact of CEWS program assistance, were $15,387.

Our general and administrative expense increased by 15% as compared with the second quarter of 2021. The higher expense for the quarter pertains to higher fixed overhead charges and lower CEWS program assistance, partially offset by lower share-based compensation charges.

SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES

		For the three months ended June 30,		For the six months ended June 30,
(Stated in thousands of Canadian dollars, except where noted)			2022				2021				% Change				2022				2021				% Change
Revenue			33,041				20,667				59.9				71,279				53,211				34.0
Expenses:
Operating			26,200				15,125				73.2				56,167				38,515				45.8
General and administrative			2,002				1,290				55.2				3,734				2,642				41.3
Adjusted EBITDA(1)			4,839				4,252				13.8				11,378				12,054				(5.6	)
Adjusted EBITDA as a percentage of revenue(1)			14.6	%			20.6	%							16.0	%			22.7	%
Well servicing statistics:
Number of service rigs (end of period)			93				123				(24.4	)			93				123				(24.4	)
Service rig operating hours			30,389				26,630				14.1				68,654				61,533				11.6
Service rig operating hour utilization			36	%			24	%							41	%			27	%

(1)	See "FINANCIAL MEASURES AND RATIOS."

Completion and Production Services revenue for the second quarter of 2022 increased to $33 million as compared with $21 million in 2021. The higher revenue was primarily due to increased average service rates and activity. Our second quarter service rig operating hours increased by 14% from 2021.

During the quarter, Completion and Production Services generated 13% of its revenue from U.S. operations compared with 12% in the comparative period.

Operating costs as a percentage of revenue increased to 79%, as compared with 73% in 2021 and was primarily due to the impact of CEWS program assistance. In the second quarter of 2022, we received CEWS program assistance of nil as compared with $2 million in 2021.

As compared to 2021, our second quarter general and administrative expense increased by 55%. The higher expense for the quarter pertains to higher fixed overhead charges and lower CEWS program assistance, partially offset by lower share-based compensation charges.

Our second quarter Adjusted EBITDA increased by $1 million as compared with 2021 primarily due to increased average service rates and activity, partially offset by lower CEWS program assistance of $3 million.

Subsequent to June 30, 2022, we acquired the well servicing business and associated rental assets of High Arctic for an aggregate purchase price of $38 million.

During the quarter, we did not renew the registration of 30 Canadian service rigs with the industry association, reducing our marketed fleet to 93 as at June 30, 2022.

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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 of $11 million as compared with $23 million in the second quarter of 2021. Our Adjusted EBITDA was positively impacted by decreased share-based compensation costs from our lower share price, partially offset by lower CEWS program assistance. During the quarter, we did not recognize any CEWS program assistance as compared with $1 million in 2021.

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 2021 Annual Report.

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

		For the three months ended June 30,		For the six months ended June 30,
(Stated in thousands of Canadian dollars)			2022				2021				2022				2021
Cash settled share-based incentive plans			5,048				24,830				52,259				34,698
Equity settled share-based incentive plans:
Executive PSU			-				1,398				407				2,171
Share option plan			-				34				20				165
Total share-based incentive compensation plan expense			5,048				26,262				52,686				37,034
Allocated:
Operating			1,852				5,901				12,772				8,165
General and Administrative			3,196				20,361				39,914				28,869
			5,048				26,262				52,686				37,034

Cash settled share-based compensation expense for the quarter was $5 million as compared with $26 million in 2021. The decreased expense in 2022 was primarily due to our lower share price. Our equity settled share-based compensation expense for the second quarter of 2022 was nil as our Executive PSUs and share options fully vested in the first quarter of 2022.

As at June 30, 2022, the majority of our share-based compensation plans were classified as cash-settled and will be impacted by changes in our share price. Although accounted for as cash-settled, Precision retains the ability to settle certain vested units in common shares at its discretion.

Finance Charges

Second quarter net finance charges were $21 million as compared with $28 million in 2021. The decreased finance charges were primarily due to lower debt issue costs. In 2021, we accelerated the amortization of issue costs associated with the unsecured senior notes that were fully redeemed in the quarter. Interest charges on our U.S. denominated long-term debt in the second quarter were US$15 million ($19 million) as compared with US$16 million ($19 million) in 2021.

Income Tax

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

Well Control Event

Late in the second quarter of 2022, we experienced a well control event during a turnkey drilling project. We recognized revenue of nil and US$5 million of drilling-related operating costs. Additionally, the net book value of our damaged drilling rig was derecognized resulting in a US$1 million charge to depreciation and amortization expense. We accrued US$12 million of associated well site clean-up and remediation costs and accrued estimated insurance recoveries of US$16 million for the drilling rig and associated costs. The provisions for the associated costs and insurance recoveries are based on our best estimates at June 30, 2022. As the assessment of damage is ongoing, the provisions may be subject to change.

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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 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.

Liquidity

Amount		Availability		Used for		Maturity
Senior credit facility (secured)
US$500 million(1) (extendible, revolving term credit facility with US$300 million accordion feature)		US$128 million drawn and US$32 million in outstanding letters of credit		General corporate purposes		June 18, 2025(1)
Real estate credit facilities (secured)
US$9 million		Fully drawn		General corporate purposes		November 19, 2025
$18 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$12 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 June 30, 2022, we had $1,158 million outstanding under our Senior Credit Facility, Real Estate Credit Facilities and unsecured senior notes as compared with $1,126 million at December 31, 2021.

The current blended cash interest cost of our debt is approximately 6.6%.

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 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 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 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. 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 certain 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.

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

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Covenants

At June 30, 2022, we were in compliance with the covenants of our Senior Credit Facility and Real Estate Credit Facilities.

			Covenant				At June 30, 2022
Senior Credit Facility
Consolidated senior debt to consolidated covenant EBITDA(1)			<2.50				0.79
Consolidated covenant EBITDA to consolidated interest expense			>2.25				3.88
Real Estate Credit Facilities
Consolidated covenant EBITDA to consolidated interest expense			>2.25				3.88

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

Impact of foreign exchange rates

The following table summarizes the average and closing Canada-U.S. foreign exchanges rates.

			For the three months ended June 30,				For the six months ended June 30,				At December 31,
			2022				2021				2022				2021				2021
Canada-U.S. foreign exchange rates
Average			1.28				1.23				1.27				1.25				-
Closing			1.29				1.24				1.29				1.24				1.26

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).

QUARTERLY FINANCIAL SUMMARY

(Stated in thousands of Canadian dollars, except per share amounts)		2021		2022
Quarters ended			September 30				December 31				March 31				June 30
Revenue			253,813				295,202				351,339				326,016
Adjusted EBITDA(1)			45,408				63,881				36,855				64,099
Net loss			(38,032	)			(27,336	)			(43,844	)			(24,611	)
Net loss per basic and diluted share			(2.86	)			(2.05	)			(3.25	)			(1.81	)
Funds provided by operations(1)			33,525				62,681				29,955				60,373
Cash provided by (used in) operations			21,871				59,713				(65,294	)			135,174

(Stated in thousands of Canadian dollars, except per share amounts)		2020		2021
Quarters ended			September 30				December 31				March 31				June 30
Revenue			164,822				201,688				236,473				201,359
Adjusted EBITDA(1)			47,771				55,263				54,539				28,944
Net loss			(28,476	)			(37,518	)			(36,106	)			(75,912	)
Net loss per basic and diluted share			(2.08	)			(2.74	)			(2.70	)			(5.71	)
Funds provided by operations(1)			27,489				35,282				43,430				12,607
Cash provided by operations			41,950				4,737				15,422				42,219

(1)	See "FINANCIAL MEASURES AND RATIOS."

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CRITICAL ACCOUNTING JUDGEMENTS AND ESTIMATES

Because of the nature of our business, we are required to make judgements and estimates in preparing our Condensed Consolidated Interim Financial Statements that could materially affect the amounts recognized. Our judgements and estimates are based on our past experiences and assumptions we believe are reasonable in the circumstances. The critical judgements and estimates used in preparing the Condensed Consolidated Interim Financial Statements are described in our 2021 Annual Report.

EVALUATION OF CONTROLS AND PROCEDURES

Based on their evaluation as at June 30, 2022, 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 June 30, 2022, 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 June 30, 2022 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.

FINANCIAL MEASURES AND RATIOS

Non-GAAP Financial Measures
We reference certain additional Non-Generally Accepted Accounting Principles (Non-GAAP) measures that are not defined terms under IFRS to assess performance because we believe they provide useful supplemental information to investors.
Adjusted EBITDA		We believe Adjusted EBITDA (earnings before income taxes, gain (loss) on investments and other assets, loss on repurchase of unsecured senior notes, finance charges, foreign exchange, gain on asset disposals and depreciation and amortization), as reported in our Condensed Interim Consolidated Statements of Net Loss and our reportable operating segment disclosures, 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 funds provided by (used in) operations, as reported in our Condensed Interim Consolidated Statements of Cash Flows, 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.

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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:

		For the three months ended June 30,		For the six months ended June 30,
(Stated in thousands of Canadian dollars)			2022				2021				2022				2021
Capital spending by spend category
Expansion and upgrade			15,530				6,446				25,145				9,883
Maintenance and infrastructure			23,906				13,809				50,693				18,808
			39,436				20,255				75,838				28,691
Proceeds on sale of property, plant and equipment			(6,849	)			(2,590	)			(9,696	)			(5,914	)
Net capital spending			32,587				17,665				66,142				22,777
Purchase of investments and other assets			536				-				536				-
Changes in non-cash working capital balances			3,659				(7,515	)			447				(2,713	)
Cash used in investing activities			36,782				10,150				67,125				20,064

Working Capital

We define working capital as current assets less current liabilities, as reported in our Condensed Interim Consolidated Statements of Financial Position. Working capital is calculated as follows:

			At June 30,				At December 31,
(Stated in thousands of Canadian dollars)			2022				2021
Current assets			394,717				319,757
Current liabilities			283,225				238,120
Working capital			111,492				81,637

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 Adjusted EBITDA as a percentage of consolidated revenue, as reported in our Condensed Interim Consolidated Statements of Net 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.
Long-term debt to long-term debt plus equity		We believe that long-term debt (as reported in our Condensed Interim Consolidated Statements of Financial Position) to long-term debt plus equity (total shareholders' equity as reported in our Condensed Interim Consolidated Statements of Financial Position) provides an indication to our debt leverage.
Net Debt to Adjusted EBITDA		We believe that the Net Debt (long-term debt less cash, as reported in our Condensed Interim 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.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

Certain statements contained in this release, 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 2022;

·	our capital expenditures, free cash flow allocation and debt reduction plan for 2022;

·	anticipated activity levels, demand for our drilling rigs, day rates and margins in 2022;

·	the average number of term contracts in place for 2022;

·	customer adoption of AlphaTM technologies and EverGreenTM suite of environmental solutions;

·	anticipated timing and amount of costs savings from acquired well servicing and rental assets;

·	potential commercial opportunities and rig contract renewals;

·	our future debt reduction plans; and

·	anticipated timing and amounts of insurance recoveries.

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, 2021, 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 release 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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