EX-99.1 4 exh_991.htm EXHIBIT 99.1

Exhibit 99.1

PRECISION DRILLING CORPORATION

Third Quarter Report for the three and nine months ended September 30, 2022 and 2021

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 third quarter financial results and highlights:

Realized $429 million of revenue during the quarter, an increase of 69% over the same period last year and 32% compared to the previous quarter.

Increased North American drilling activity by 27% compared to the third quarter of 2021 and achieved average day rates of US$27,847 in the U.S. and $26,927 in Canada.

Achieved Adjusted EBITDA (see “FINANCIAL MEASURES AND RATIOS”) of $120 million, a 163% increase from $45 million in the prior year quarter as we continue to maximize our operating leverage in a growing activity environment. Adjusted EBITDA included $6 million of share-based compensation charges and $4 million of non-recurring costs associated with the High Arctic Energy Services Inc. (High Arctic) transaction, severance costs and mobilization of a drilling rig from the U.S. to Canada.

Generated net earnings of $31 million or $2.26 per share compared with a net loss of $38 million or $2.86 per share in third quarter of 2021.

Continued to scale our Alpha™ technologies across our Super Triple rig fleet, increasing our Alpha™ revenue over 50% compared to the same period last year.

Strengthened our contract book with 23 additions, bringing our year-to-date total to 61 term contracts.

Successfully integrated the acquired well servicing business and associated rental assets of High Arctic. During the quarter, the Completion and Production Services segment generated revenue of $57 million and Adjusted EBITDA of $15 million, representing increases of 101% and 170%, respectively, from the prior year’s third quarter.

Generated cash and funds from operations (see “FINANCIAL MEASURES AND RATIOS”) of $8 million and $81 million, respectively, as compared with $22 million and $34 million in the third quarter of 2021.

Repurchased and cancelled 69,599 common shares for $5 million under our Normal Course Issuer Bid (NCIB).

Ended the quarter with $40 million of cash, US$141 million drawn on our Senior Credit Facility and more than $540 million of available liquidity. We remain on track to reduce our debt by $75 million in 2022.

Increased our capital spending plan from $149 million to $165 million in response to higher drilling and service activity and expected customer contracted upgrades on over 30 drilling rigs in 2022.

Subsequent to September 30, 2022, we were awarded four five-year drilling contracts in the Middle East that will increase our active rig count in the region to eight rigs by the middle of 2023.

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)		2022		2021		% Change				2022		2021		% Change
Revenue		429,335		253,813			69.2			1,106,690		691,645			60.0
Adjusted EBITDA⁽¹⁾		119,561		45,408			163.3			220,515		128,891			71.1
Net earnings (loss)		30,679		(38,032	)		(180.7	)		(37,776	)	(150,050	)		(74.8	)
Cash provided by (used in) operations		8,142		21,871			(62.8	)		78,022		79,512			(1.9	)
Funds provided by operations⁽¹⁾		81,327		33,525			142.6			171,655		89,562			91.7

Cash used in investing activities		31,711		17,524			81.0			98,836		37,588			162.9
Capital spending by spend category⁽¹⁾
Expansion and upgrade		25,461		5,998			324.5			50,606		15,881			218.7
Maintenance and infrastructure		25,642		13,502			89.9			76,335		32,310			136.3
Proceeds on sale		(22,337	)	(4,476	)		399.0			(32,033	)	(10,390	)		208.3
Net capital spending⁽¹⁾		28,766		15,024			91.5			94,908		37,801			151.1

Net earnings (loss) per share:
Basic		2.26		(2.86	)		(179.0	)		(2.79	)	(11.27	)		(75.2	)
Diluted		2.03		(2.86	)		(171.0	)		(2.79	)	(11.27	)		(75.2	)

(1)

See “FINANCIAL MEASURES AND RATIOS.”

Operating Highlights

	For the three months ended September 30,							For the nine months ended September 30,
	2022		2021		% Change			2022		2021		% Change
Contract drilling rig fleet		225		227		(0.9	)		225		227		(0.9	)
Drilling rig utilization days:
U.S.		5,287		3,785		39.7			14,914		10,315		44.6
Canada		5,432		4,648		16.9			14,461		10,963		31.9
International		552		552		-			1,638		1,638		-
Revenue per utilization day:
U.S. (US$)		27,847		20,331		37.0			25,864		20,904		23.7
Canada (Cdn$)		26,927		19,427		38.6			25,843		20,295		27.3
International (US$)		50,216		52,277		(3.9	)		51,687		53,095		(2.7	)
Operating cost per utilization day:
U.S. (US$)		18,220		15,120		20.5			18,484		14,639		26.3
Canada (Cdn$)		16,893		13,189		28.1			16,803		13,204		27.3

Service rig fleet		135		123		9.8			135		123		9.8
Service rig operating hours		52,340		32,244		62.3			120,994		93,777		29.0

Financial Position

(Stated in thousands of Canadian dollars, except ratios)	September 30, 2022		December 31, 2021
Working capital⁽¹⁾		152,289		81,637
Cash		40,048		40,588
Long-term debt		1,241,099		1,106,794
Total long-term financial liabilities		1,335,754		1,185,858
Total assets		2,927,384		2,661,752
Long-term debt to long-term debt plus equity ratio ⁽¹⁾		0.50		0.47

(1)

See “FINANCIAL MEASURES AND RATIOS.”

Summary for the three months ended September 30, 2022:

Revenue for the quarter was $429 million, 69% higher than in 2021, due to increased North American drilling and service activity and day rates.

Adjusted EBITDA for the quarter was $120 million, $74 million higher than 2021. Our Adjusted EBITDA for the quarter included $6 million of share-based compensation charges and approximately $4 million of non-recurring costs associated with the High Arctic transaction, severance costs, and mobilization of a drilling rig from the U.S. to Canada. Please refer to “Other Items” later in this report for additional information on our share-based compensation charges.

Adjusted EBITDA as a percentage of revenue (see “FINANCIAL MEASURES AND RATIOS”) was 28% as compared with 18% in 2021, demonstrating our ability to maximize our operating leverage in a growing activity environment.

General and administrative expenses this quarter were $25 million, $1 million higher than in 2021 due to increased labor and personnel costs, non-recurring well servicing acquisition costs and lower CEWS program assistance, offset by lower share-based compensation charges.

Net finance charges for the quarter were $23 million, an increase of $2 million from 2021 due to higher variable interest rates on our Senior Credit Facility and the impact of higher foreign exchange rates on our U.S. denominated long-term debt.

In the U.S., revenue per utilization day was US$27,847 compared with US$20,331 in 2021, an increase of 37% and was primarily the result of higher contracted day rates, impact of Alpha^TM and EverGreen^TM revenue and improved operating cost recoveries. During the third quarter, we recognized revenue from idle but contracted rigs and turnkey projects of US$1 million and nil, respectively, as compared with nil in 2021. Revenue per utilization day in the quarter excluding the impact of idle but contracted rig revenue was US$27,682, compared to US$20,331 in the prior year, an increase of US$7,351. On a sequential basis, revenue per utilization day, excluding idle but contract rigs and turnkey revenue, increased approximately US$4,092.

Our U.S. operating costs on a per day basis increased to US$18,220, compared with US$15,120 in 2021, due to increased rig operating expenses, repairs and maintenance and higher costs that pass through to our customers. Our U.S. operating costs included rig reactivations charges totaling US$2 million. Sequentially, excluding the impact of turnkey activity, our operating costs per day increased approximately US$1,522.

In Canada, average revenue per utilization day for contract drilling for the quarter was $26,927 compared with $19,427 in 2021, an increase of 39% and was the result of higher day rates and increased labor and cost recoveries.

Our Canadian operating costs on a per day basis increased to $16,893, compared with $13,189 in 2021 due to industry-wide wage increases, higher repairs and maintenance expense and lower CEWS program assistance. During the third quarter of 2021, we recognized $5 million of CEWS program assistance.

Completion and Production Services third quarter revenue and Adjusted EBITDA was $57 million and $15 million, respectively, compared with $28 million and $5 million in 2021. Our improved results were supported by higher service rates and operating hours, the impact of the High Arctic asset acquisition, partially offset by lower CEWS program assistance as we recognized $1 million of assistance in 2021.

We realized third quarter revenue from international contract drilling of US$28 million, largely consistent with 2021, as activity and day rates remained constant.

Third quarter cash provided by operations was $8 million as compared with $22 million in 2021. Our lower cash generation during the quarter was primarily due to the timing of long-term debt interest payments resulting from our unsecured senior notes issuance in 2021. We generated $81 million of funds from operations as compared with $34 million in 2021. Our increased activity and day rates, operational leverage and lower share-based compensation charges, partially offset by the timing of long-term debt interest payments, contributed to our higher funds from operations for the quarter.

Capital expenditures were $51 million as compared with $20 million in 2021. Capital spending by spend category (see “FINANCIAL MEASURES AND RATIOS”) included $25 million for expansion and upgrades and $26 million for the maintenance of existing assets and infrastructure.

Generated $22 million of proceeds from the sale of non-core assets; including certain real estate and facilities located in Alberta and Texas and the receipt of insurance proceeds from our second quarter well control event.

We ended the quarter with $40 million of cash and more than $540 million of available liquidity.

We repurchased and cancelled 69,599 common shares for $5 million under our NCIB.

We successfully integrated the well servicing business and associated rental assets acquired from High Arctic, adding 80 service rigs to our fleet along with related rental assets, ancillary support equipment, inventories, spares and six additional operating facilities in key operating basins.

Summary for the nine months ended September 30, 2022:

Revenue for the first nine months of 2022 was $1,107 million, an increase of 60% from 2021.

Adjusted EBITDA for the period was $221 million as compared with $129 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 second quarter well control event and lower CEWS program assistance. Our 2021 Adjusted EBITDA was positively impacted by $24 million of CEWS program assistance.

General and administrative costs were $102 million, an increase of $25 million from 2021 primarily due to increased personnel costs, higher share-based compensation charges and lower CEWS program assistance.

Net finance charges were $64 million, a decrease of $6 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 $78 million as compared with $80 million in 2021. Funds provided by operations in 2022 were $172 million, an increase of $82 million from the comparative period.

Capital expenditures were $127 million in 2022, an increase of $79 million from 2021. Capital spending by spend category included $51 million for expansion and upgrades and $76 million for the maintenance of existing assets and infrastructure.

Year-to-date, we have borrowed US$23 million on our Senior Credit Facility and repurchased and cancelled 130,395 common shares for $10 million under our NCIB.

STRATEGY

Precision’s strategic priorities for 2022 are as follows:

Grow revenue through scaling Alpha^TM technologies and EverGreen^TM suite of environmental solutions across Precision's Super Series rig fleet and further competitive differentiation through ESG initiatives – Utilization of our Alpha^TM technologies continues to grow and generate incremental revenue. During the quarter, revenue from our Alpha^TM technologies grew 56% compared with the third quarter of 2021 as our total paid days for AlphaAutomation^TM increased by 56%, consistent with our year-to-date increase of 55%. We currently have 60 AC Super Triple rigs equipped with Alpha^TM and over 90% are generating incremental revenue as customers see the value in our technology. Our plan is to have a total of 70 rigs converted by year end, and the entire fleet of Super Triple rigs converted by early 2024. We continue to scale our EverGreen^TM suite of environmental solutions, which will further differentiate us from our competitors and drive additional revenue growth. As of October 26, 2022, we had five commercial, field-deployed, EverGreen^TM Battery Energy Storage Systems with two additional systems scheduled for installation by year end. In addition, we had 13 EverGreen^TM Integrated Power & Emissions Monitoring Systems deployed and anticipate ending the year with 15 systems installed.

Grow free cash flow by maximizing operating leverage as demand for our High Performance, High Value services continues to rebound – During the third quarter of 2022, we generated cash and funds from operations of $8 million and $81 million, respectively. Our third quarter active rig count was up 39% in the U.S. and 16% in Canada compared to the same period last year, while our daily operating margins (average revenue less operating costs per utilization day) also improved despite continued industry-wide inflationary pressure. With the tightening of available Super Series rigs, we expect to realize further pricing increases in the U.S. and Canada as expiring contracts are renewed or extended. On July 27, 2022, we acquired High Arctic’s well servicing business and associated rental assets, increasing our well servicing hours 62% from the prior year’s third quarter and driving the highest quarterly Adjusted EBITDA from our Completion and Production Services segment since the fourth quarter of 2018.

Utilize free cash flow to continue strengthening our balance sheet while investing in our people, equipment and returning capital to shareholders – We continue to target $75 million of long-term debt reduction for 2022 and our longer-term debt reduction goals of $400 million between 2022 and 2025 and Net Debt to Adjusted EBITDA (see “FINANCIAL MEASURES AND RATIOS”) of less than 1.5 times by 2025. During the quarter, our reinvestment into our drilling fleet included $51 million of capital expenditures and we generated $22 million of cash proceeds from the divestiture of non-core assets. In 2022, we have drawn approximately US$23 million on our Senior Credit Facility to fund our increased cash demands as our respective drilling and service activity increased 26% and 72% from the second quarter of 2022. Through share repurchases under our NCIB, we have returned $10 million of capital to shareholders this year.

OUTLOOK

The rebound of global energy demand and the impact of a multi-year period of underinvestment in upstream oil and natural gas has resulted in reduced inventories of oil and natural gas and higher commodity prices, providing a supportive 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 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 strengthening 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 recession risk, rising interest rates and geopolitical instability. These concerns may negatively impact customer spending plans.

With North American industry activity expected to further increase into 2023, we anticipate near full utilization 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. We successfully acquired and integrated the High Arctic well servicing assets and associated rental business early in the third quarter. By leveraging our existing platform and continuing our strict focus on cost control, we have realized annual run-rate cost synergies of over $3 million and expect to achieve the vast majority of our $5 million target by early next year. Additionally, support from both federal and provincial governments has increased well abandonment and rehabilitation projects.

In October, we announced the addition of Lori A. Lancaster to our Board of Directors. With over 25 years of experience as a strategic and financial advisor to the global natural resources sector and having served as a board member of publicly traded companies within the energy sector, we believe Ms. Lancaster's extensive knowledge and experience will enhance our existing Board of Directors.

Commodity Prices

During the third quarter of 2022, average West Texas Intermediate and Western Canadian Select oil prices were higher by 30% and 26%, respectively, from the comparative quarter. While average Henry Hub and AECO natural gas prices improved by 83% and 24%, respectively from 2021.

	For the three months ended September 30,			Year ended December 31,
		2022	2021		2021
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)		91.66	70.49		67.91
Western Canadian Select (per barrel) (US$)		71.56	56.96		54.84
Natural gas
United States
Henry Hub (per MMBtu) (US$)		7.89	4.31		3.72
Canada
AECO (per MMBtu) (CDN$)		4.47	3.61		3.64

Contracts

Year-to-date in 2022, we have entered into 61 term contracts and 23 new contracts since the end of the second quarter of 2022. The following chart outlines the average number of drilling rigs under contract by quarter as of October 26, 2022. For those quarters ending after September 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 October 26, 2022:
U.S.		21		24		22		24		27		29		31		36
Canada		6		6		7		7		6		8		10		15
International		6		6		6		6		6		6		6		4
Total		33		36		35		37		39		43		47		55

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 October 26, 2022.

	Average for the year ended
	2021		2022		2023
Average rigs under term contract as of October 26, 2022:
U.S.		23		31		18
Canada		7		10		14
International¹		6		5		3
Total		36		46		35

(1)

Does not include Kuwait contracts awarded subsequent to September 30, 2022.

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		Sept. 30
Average Precision active rig count:
U.S.		33		39		41		45			51		55		57
Canada		42		27		51		52			63		37		59
International		6		6		6		6			6		6		6
Total		81		72		98		103			120		98		122

According to industry sources, as at October 26, 2022, the U.S. active land drilling rig count has increased 43% from the same point last year while the Canadian active land drilling rig count has increased by 28%. To date in 2022, approximately 79% of the U.S. industry’s active rigs and 63% 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 and Free Cash Flow Allocation

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 $165 million and by spend category includes $96 million for sustaining, infrastructure and intangibles and $69 million for expansion and upgrades. We expect the $165 million will be split $157 million in the Contract Drilling Services segment, $5 million in the Completion and Production Services segment and $3 million to the Corporate segment. At September 30, 2022, Precision had capital commitments of $163 million with payments expected through 2024.

Our debt reduction plans continue with the goal of repaying $75 million in 2022 and 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.

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 September 30,									For the nine months ended September 30,
(Stated in thousands of Canadian dollars)		2022		2021			% Change				2022		2021			% Change
Revenue:
Contract Drilling Services		374,465			226,957			65.0			982,909			613,032			60.3
Completion and Production Services		56,642			28,143			101.3			127,921			81,354			57.2
Inter-segment eliminations		(1,772	)		(1,287	)		37.7			(4,140	)		(2,741	)		51.0
		429,335			253,813			69.2			1,106,690			691,645			60.0
Adjusted EBITDA:⁽¹⁾
Contract Drilling Services		118,599			55,384			114.1			260,202			163,118			59.5
Completion and Production Services		14,788			5,479			169.9			26,166			17,533			49.2
Corporate and Other		(13,826	)		(15,455	)		(10.5	)		(65,853	)		(51,760	)		27.2
		119,561			45,408			163.3			220,515			128,891			71.1

(1)

See “FINANCIAL MEASURES AND RATIOS.”

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)		2022		2021		% Change			2022		2021		% Change
Revenue		374,465		226,957			65.0		982,909		613,032			60.3
Expenses:
Operating		246,442		164,521			49.8		692,169		429,036			61.3
General and administrative		9,424		7,052			33.6		30,538		20,878			46.3
Adjusted EBITDA⁽¹⁾		118,599		55,384			114.1		260,202		163,118			59.5
Adjusted EBITDA as a percentage of revenue⁽¹⁾		31.7	%	24.4	%				26.5	%	26.6	%

(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
September 30		57		746		41		485
Year to date average		54		679		38		433

(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
September 30		59		199		51		151
Year to date average		53		172		40		123

(1)

Canadian operations only.

(2)

Baker Hughes rig counts.

Revenue from Contract Drilling Services was $374 million this quarter, 65% higher than 2021, while Adjusted EBITDA increased by 114% to $119 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 5,287, 40% higher than 2021. Drilling rig utilization days in Canada were 5,432, 17% 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 552, consistent with 2021.

Our third quarter revenue per utilization day in the U.S. increased 37% from the comparable quarter. The increase was primarily the result of higher contracted day rates, impact of Alpha^TM and EverGreen^TM revenue and improved operating cost recoveries. During the third quarter, we recognized revenue from idle but contracted rigs and turnkey projects of US$1 million and nil, respectively, as compared with nil in 2021. Compared with the same quarter in 2021, drilling rig revenue per utilization day in Canada increased 39%. 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 slightly lower than 2021 primarily due to the expiration of drilling contracts.

In the U.S., 54% of utilization days were generated from rigs under term contract as compared with 49% in 2021. In Canada, 14% of our utilization days were generated from rigs under term contract, compared with 12% in 2021.

In the U.S., operating costs for the quarter on a per day basis were higher by 21% compared with 2021 primarily due to increased rig operating expenses, repairs and maintenance and higher costs that pass through to our customers. Our U.S. operating costs included rig reactivations charges totaling US$2 million.

Compared with the third quarter of 2021, our Canadian operating costs on a per day basis increased by 28% due to industry-wide wage increases, higher repairs and maintenance expense and lower CEWS program assistance. During the third quarter of 2021, we recognized $5 million of CEWS program assistance.

Our general and administrative expense increased by 34% as compared with 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.

During the quarter, we did not renew the industry association registration for one drilling rig, reducing our contract drilling rig fleet to 225 as at September 30, 2022.

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)		2022		2021		% Change			2022		2021
Revenue		56,642		28,143			101.3		127,921		81,354		57.2
Expenses:
Operating		40,198		21,188			89.7		96,365		59,703		61.4
General and administrative		1,656		1,476			12.2		5,390		4,118		30.9
Adjusted EBITDA⁽¹⁾		14,788		5,479			169.9		26,166		17,533		49.2
Adjusted EBITDA as a percentage of revenue⁽¹⁾		26.1	%	19.5	%				20.5	%	21.6	%
Well servicing statistics:
Number of service rigs (end of period)		135		123			9.8		135		123		9.8
Service rig operating hours		52,340		32,244			62.3		120,994		93,777		29.0
Service rig operating hour utilization		47	%	28	%				43	%	28	%

(1)

See “FINANCIAL MEASURES AND RATIOS.”

Completion and Production Services revenue for the third quarter of 2022 increased to $57 million as compared with $28 million in 2021. The higher revenue was primarily due to increased average service rates and activity. Our third quarter service rig operating hours increased by 62% from 2021.

During the quarter, Completion and Production Services generated 8% of its revenue from U.S. operations compared with 12% in the comparative period.

Operating costs as a percentage of revenue decreased to 71%, as compared with 75% in 2021, due to our operating leverage in an increasing activity environment, partially offset by lower CEWS program assistance. In the third quarter of 2022, we received CEWS program assistance of nil as compared with $1 million in 2021.

As compared to 2021, our third quarter general and administrative expense increased by 12% due to higher fixed overhead charges and lower CEWS program assistance, partially offset by lower share-based compensation charges.

Our third quarter Adjusted EBITDA increased by $9 million as compared with 2021 primarily due to increased average service rates and activity, partially offset by lower CEWS program assistance.

During the quarter, we acquired the well servicing business and associated rental assets of High Arctic for an aggregate purchase price of $38 million.

As at September 30, 2022, our Completion and Production Services segment had a fleet of 278 rigs of which 135 were registered with industry associations and actively marketed. We continue to maintain our non-registered service rigs and will reactivate as required.

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 $14 million as compared with $15 million in the third quarter of 2021. Our Adjusted EBITDA was positively impacted by decreased share-based compensation costs, partially offset by lower CEWS program assistance.

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 September 30,				For the nine months ended September 30,
(Stated in thousands of Canadian dollars)	2022		2021		2022		2021
Cash settled share-based incentive plans		5,543		11,839		57,802		46,537
Equity settled share-based incentive plans:
Executive PSU		—		1,468		407		3,639
Share option plan		—		34		20		199
Total share-based incentive compensation plan expense		5,543		13,341		58,229		50,375

Allocated:
Operating		1,922		3,272		14,694		11,437
General and Administrative		3,621		10,069		43,535		38,938
		5,543		13,341		58,229		50,375

Cash settled share-based compensation expense for the quarter was $6 million as compared with $12 million in 2021. The decreased expense in 2022 was primarily due to our lower sequential quarter share price. Our equity settled share-based compensation expense for the third quarter of 2022 was nil as our Executive PSUs and share options fully vested in the first quarter of 2022.

As at September 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

Third quarter net finance charges were $23 million as compared with $21 million in 2021. The increased finance charges were primarily due to higher variable interest rates on our Senior and Real Estate Credit Facilities and the impact of higher foreign exchange rates on our U.S. denominated long-term debt. Interest charges on our U.S. denominated long-term debt in the third quarter were US$16 million ($20 million) as compared with US$15 million ($19 million) in 2021.

Income Tax

Income tax expense for the quarter was $6 million as compared with a $4 million recovery in 2021. The higher income tax expense for the quarter was the result of our positive earnings. During the third quarter, we did not recognize deferred tax assets on certain Canadian and international operating losses.

LIQUIDITY AND CAPITAL RESOURCE

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$141 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 $8 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$18 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, 2022, we had $1,259 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 weakening of the Canadian dollar resulted in $106 million of additional stated debt at September 30, 2022.

The current blended cash interest cost of our debt is approximately 6.9%.

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 period ended 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 were 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 exited the Covenant Relief Period on October 1, 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.

Covenants

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

	Covenant	At September 30, 2022
Senior Credit Facility
Consolidated senior debt to consolidated covenant EBITDA⁽¹⁾	<2.50	0.72
Consolidated covenant EBITDA to consolidated interest expense	>2.25	3.76
Real Estate Credit Facilities
Consolidated covenant EBITDA to consolidated interest expense	>2.25	3.76

(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 September 30,				For the nine months ended September 30,				At December 31,
	2022		2021		2022		2021		2021
Canada-U.S. foreign exchange rates
Average		1.31		1.26		1.28		1.25		—
Closing		1.38		1.27		1.38		1.27		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	December 31			March 31			June 30			September 30
Revenue		295,202			351,339			326,016			429,335
Adjusted EBITDA⁽¹⁾		63,881			36,855			64,099			119,561
Net earnings (loss)		(27,336	)		(43,844	)		(24,611	)		30,679
Net earnings (loss) per basic share		(2.05	)		(3.25	)		(1.81	)		2.26
Net earnings (loss) per diluted share		(2.05	)		(3.25	)		(1.81	)		2.03
Funds provided by operations⁽¹⁾		62,681			29,955			60,373			81,327
Cash provided by (used in) operations		59,713			(65,294	)		135,174			8,142

(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

(1)

See “FINANCIAL MEASURES AND RATIOS.”

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 September 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 September 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 September 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 Earnings (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.

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 September 30,					For the nine months ended September 30,
(Stated in thousands of Canadian dollars)		2022		2021			2022		2021
Capital spending by spend category
Expansion and upgrade		25,461		5,998			50,606		15,881
Maintenance and infrastructure		25,642		13,502			76,335		32,310
		51,103		19,500			126,941		48,191
Proceeds on sale of property, plant and equipment		(22,337	)	(4,476	)		(32,033	)	(10,390	)
Net capital spending		28,766		15,024			94,908		37,801
Business acquisitions		10,200		—			10,200		—
Purchase of investments and other assets		73		3,000			609		3,000
Changes in non-cash working capital balances		(7,328	)	(500	)		(6,881	)	(3,213	)
Cash used in investing activities		31,711		17,524			98,836		37,588

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 September 30,		At December 31,
(Stated in thousands of Canadian dollars)		2022		2021
Current assets		489,584		319,757
Current liabilities		337,295		238,120
Working capital		152,289		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 Earnings (Loss), provides an indication of our profitability from our principal business activities prior to consideration of how our activities are financed and the impact of foreign exchange, taxation and depreciation and amortization charges.
*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.

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 Alpha^TM technologies and EverGreen^TM 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 beyond 2022; 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.