Exhibit 99.1

 

Precision Drilling Corporation

Second Quarter Report for the three and six months ended June 30, 2019 and 2018

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s Discussion and Analysis for the three and six months ended June 30, 2019 of Precision Drilling Corporation (“Precision” or the “Corporation”) prepared as of July 24, 2019 focuses on the unaudited Interim Consolidated Financial Statements and related notes and pertains to known risks and uncertainties relating to the oilfield services sector. This discussion should not be considered all-inclusive as it does not include all changes regarding general economic, political, governmental and environmental events. This discussion should be read in conjunction with the Corporation’s 2018 Annual Report, Annual Information Form, unaudited June 30, 2019 Interim Consolidated Financial Statements and related notes.

This report contains “forward-looking information and statements” within the meaning of applicable securities laws. For a full disclosure of the forward-looking information and statements and the risks to which they are subject, see the “Cautionary Statement Regarding Forward-Looking Information and Statements” on page 16 of this report. This report contains references to Adjusted EBITDA, Covenant EBITDA, Operating Earnings (Loss), Funds Provided by (Used in) Operations and Working Capital. These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies, see “Non-GAAP Measures” on page 15 of this report.

Precision Drilling announces 2019 second quarter financial results:

· Revenue of $359 million was an increase of 9% compared with the second quarter of 2018.

· Net loss of $14 million or negative $0.05 per diluted share compares to a net loss of $47 million or negative $0.16 per diluted share in the second quarter of 2018.

· Earnings before income taxes, loss (gain) on repurchase of unsecured senior notes, finance charges, foreign exchange, impairment reversal, gain on asset disposals and depreciation and amortization (Adjusted EBITDA see “NON-GAAP MEASURES”) of $81 million was 30% higher than the second quarter of 2018.

· Funds provided by operations (see “NON-GAAP MEASURES”) was $41 million versus $50 million in the prior year quarter. Cash provided by operations was $106 million versus $130 million in the prior year quarter. The decrease in funds and cash provided by operations in the current quarter was primarily the result of a $28 million tax refund received in the prior year comparative quarter partially offset by improved operating results in 2019.

· Second quarter ending cash balance was $81 million.

· Second quarter capital expenditures were $43 million and as at June 30, 2019, we have spent $115 million or 68% of our 2019 capital budget.

· Second quarter proceeds from asset sales was $25 million.

· Second quarter debt reduction totaled $107 million, increasing our year to date reductions to $124 million. For the year we have repurchased and cancelled US$26 million of the 7.125% unsecured senior notes due 2026 and US$17 million of the 5.25% notes due 2024 and redeemed US$50 million principal amount of our 6.50% senior notes due 2021.

· Completed construction of our sixth rig in Kuwait. The rig commenced drilling on July 1, 2019.

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IMPACT OF IFRS 16 - LEASES ON FINANCIAL INFORMATION

On January 1, 2019, Precision applied IFRS 16 using the modified retrospective approach under which comparative information has not been restated and continues to be reported under IAS 17 and related interpretations. Please refer to “CHANGES IN ACCOUNTING POLICY” for additional information on the impact to our financial information.

SELECT FINANCIAL AND OPERATING INFORMATION

Financial Highlights

	Three months ended June 30,									Six months ended June 30,
(Stated in thousands of Canadian dollars, except per share amounts)	2019			2018			% Change			2019			2018			% Change
Revenue		359,424			330,716			8.7			793,467			731,722			8.4
Adjusted EBITDA(1)		81,037			62,182			30.3			189,004			159,651			18.4
Operating earnings (loss)(1)		5,569			(26,439	)		(121.1	)		67,643			(16,278	)		(515.5	)
Net earnings (loss)		(13,801	)		(47,217	)		(70.8	)		11,213			(65,294	)		(117.2	)
Cash provided by operations		106,035			129,695			(18.2	)		146,622			167,884			(12.7	)
Funds provided by operations(1)		40,950			50,225			(18.5	)		136,943			154,251			(11.2	)
Capital spending:
Expansion		29,543			15,786			87.1			91,986			16,471			458.5
Upgrade		4,052			5,447			(25.6	)		7,726			16,810			(54.0	)
Maintenance and infrastructure		9,874			13,091			(24.6	)		14,719			23,334			(36.9	)
Intangibles		26			2,429			(98.9	)		464			10,220			(95.5	)
Proceeds on sale		(24,575	)		(2,630	)		834.4			(82,452	)		(8,680	)		849.9
Net capital spending		18,920			34,123			(44.6	)		32,443			58,155			(44.2	)
Net earnings (loss) per share:
Basic		(0.05	)		(0.16	)		(68.8	)		0.04			(0.22	)		(118.2	)
Diluted		(0.05	)		(0.16	)		(68.8	)		0.04			(0.22	)		(118.2	)

(1) See “NON-GAAP MEASURES”.

Operating Highlights

	Three months ended June 30,							Six months ended June 30,
	2019		2018		% Change			2019		2018		% Change
Contract drilling rig fleet		232		257		(9.7	)		232		257		(9.7	)
Drilling rig utilization days:
U.S.		6,994		6,588		6.2			14,117		12,383		14.0
Canada		2,413		2,834		(14.9	)		6,757		9,302		(27.4	)
International		728		728		-			1,448		1,448		-
Revenue per utilization day:
U.S.(1) (US$)		23,425		21,795		7.5			23,312		21,237		9.8
Canada(2) (Cdn$)		21,613		22,072		(2.1	)		22,490		22,167		1.5
International (US$)		51,542		49,832		3.4			50,746		49,935		1.6
Operating cost per utilization day:
U.S. (US$)		14,803		14,026		5.5			14,584		14,026		4.0
Canada (Cdn$)		17,414		16,712		4.2			15,840		14,361		10.3
Service rig fleet(3)		123		210		(41.4	)		123		210		(41.4	)
Service rig operating hours		29,540		31,824		(7.2	)		72,438		84,525		(14.3	)
Revenue per operating hour (Cdn$)		733		676		8.4			748		691		8.2

(1) 2019 period includes revenue from idle but contracted rig days.

(2) Includes lump sum revenue from contract shortfall payments.

(3) In 2019, 75 rigs were not registered with the industry association and 12 snubbing units were sold.

Financial Position

(Stated in thousands of Canadian dollars, except ratios)	June 30, 2019		December 31, 2018
Working capital(1)		200,964		240,539
Cash		80,580		96,626
Long-term debt		1,514,964		1,706,253
Total long-term financial liabilities		1,592,822		1,723,350
Total assets		3,440,348		3,636,043
Long-term debt to long-term debt plus equity ratio		0.49		0.52

(1) See “NON-GAAP MEASURES”.

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Summary for the three months ended June 30, 2019:

· Revenue this quarter was $359 million, 9% higher than the second quarter of 2018. The increase in revenue is primarily the result of higher activity and average day rates in our U.S. contract drilling business, offset by lower Canadian drilling activity and day rates. Compared with the second quarter of 2018, our activity for the quarter, as measured by drilling rig utilization days increased 6% in the U.S., decreased 15% in Canada and remained consistent internationally. Revenue from our Contract Drilling Services increased by 10% and Completion and Production Services revenue decreased 6%.

· Adjusted EBITDA (see “NON-GAAP MEASURES”) was $81 million, an increase of $19 million from the second quarter of 2018. Our Adjusted EBITDA as a percentage of revenue was 23% this quarter, compared with 19% in the comparative quarter of 2018. Adjusted EBITDA this quarter was positively impacted by higher activity and day rates in the U.S., changes to the recognition of lease-related expenses under IFRS 16 and lower share-based incentive compensation expense offset by lower Canadian drilling activity. With the adoption of IFRS 16, lease-related charges of $3 million in the quarter of were recognized through finance charges and depreciation and amortization expense. Historically, these charges were reflected in operating and general and administrative expense. Total share-based incentive compensation expense for the quarter was $4 million compared with $10 million in the second quarter of 2018. See discussion on share-based incentive compensation under “Other Items” later in this report for additional details.

· Operating earnings (see “NON-GAAP MEASURES”) were $6 million compared with an operating loss of $26 million in the second quarter of 2018. Operating earnings this quarter were positively impacted by the gain on asset disposals primarily relating to the sale of our snubbing equipment, lower depreciation expense from assets becoming fully depreciated and disposed and lower share-based incentive compensation. See discussion on asset disposals under “Other Items” later in this report for additional details.

· General and administrative expenses were $26 million, $5 million lower than the second quarter in 2018. The lower general and administrative costs in 2019 were due to lower share-based incentive compensation expense partially offset by the weakening of the Canadian dollar on our U.S. dollar denominated costs.

· Net finance charges were $30 million, a decrease of $2 million compared with the second quarter of 2018, primarily due to a reduction in interest expense related to debt retired in 2018 and 2019, offset by the impact of a weakening of the Canadian dollar on our U.S. dollar denominated interest and $1 million of lease accretion charges resulting from the adoption of IFRS 16 on January 1, 2019.

· Revenue per utilization day in the U.S. increased in the second quarter of 2019 to US$23,425 from US$21,795 in the prior year quarter. The increase was the result of higher day rates, third-party cost recoveries and idle but contracted rig revenue, partially offset by lower turnkey revenue. During the quarter, we had revenue from idle but contracted rigs and turnkey projects of $1 million and nil, respectively, as compared to second quarter 2018 idle but contracted rig and turnkey revenue of nil and $10 million, respectively. Operating costs on a per day basis increased to US$14,803 in the second quarter of 2019 compared with US$14,026 in 2018. The increase was mainly due to higher third-party charges incurred but recovered from the customer, higher repair and maintenance costs due to the timing of equipment certifications and scheduled maintenance and higher crew labour and burden costs offset by lower turnkey costs from decreased activity. On a sequential basis, revenue per utilization day, excluding revenue from turnkey and idle but contracted rigs, increased by US$218 due to higher fleet average day rates and higher third-party cost recoveries, while operating costs per day increased by $435 due to higher third-party charges incurred but recovered from the customer and higher repair and maintenance costs.

· In Canada, average revenue per utilization day for contract drilling rigs was $21,613 compared with $22,072 in the second quarter of 2018. The lower average revenue per utilization day in the second quarter of 2019 was primarily because of lower day rates, boiler revenue and rig mix, as we had proportionately more shallow rigs working, partially offset by higher shortfall payments. During the quarter, we recognized $1 million of shortfall payments in revenue compared with nil in the prior year comparative period. Excluding the impact of shortfall payment revenue, average day rates in Canada were down $895. Average operating costs per utilization day for drilling rigs in Canada increased to $17,414 compared with the prior year quarter of $16,712. The increase was mainly caused by the impact of lower activity on fixed costs and higher repairs and maintenance costs due to the timing of certification costs.

· We realized revenue from international contract drilling of US$38 million in the second quarter of 2019, an increase of US$1 million over the prior year period. Average revenue per utilization day in our international contract drilling business was US$51,542 compared with US$49,832 in the respective prior year quarter. The higher average rate in 2019 was primarily due to day rate increases from the renewal and extension of drilling contracts in the first quarter of 2019.

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· Revenue from Completion and Production Services decreased $2 million compared with the second quarter of 2018 due to lower activity in our Canadian well servicing and camp businesses, partially offset by improved service rig revenue rates and higher rental activity. Our service rig operating hours in the quarter were down 7% from the second quarter of 2018 while rates increased an average of 8%. Average service rig revenue per operating hour in the quarter was $733 or $57 higher than the second quarter of 2018. The increase was primarily the result of rig mix in Canada and increased activity in the U.S. Adjusted EBITDA (see “NON-GAAP MEASURES”) was $3 million, $4 million higher than the second quarter of 2018, and was primarily the result of higher service rig rates, higher rental activity, reduced restructuring charges and improved cost structure, partially offset by lower Canadian well servicing and camp activity. During the second quarter of 2019, we disposed of certain snubbing units and related equipment for proceeds of $8 million resulting in a gain on asset disposal of $3 million.

· Directional drilling services realized revenue of $11 million in the second quarter of 2019 compared with $7 million in the prior year period.

· Funds provided by operations (see “NON-GAAP MEASURES”) in the second quarter of 2019 were $41 million, a decrease of $9 million from the prior year comparative quarter. Cash provided by operations was $106 million versus $130 million in the prior year quarter. The decrease in funds and cash provided by operations in 2019 was primarily the result of a $28 million tax refund received in the prior year comparative quarter partially offset by improved current year operating results.

· Capital expenditures were $43 million in the second quarter, an increase of $7 million over the same period in 2018. Capital spending for the quarter included $34 million for upgrade and expansion capital, primarily related to our sixth new-build rig for Kuwait, an SCR to AC Triple upgrade for the U.S. market under long-term contract and $10 million for the maintenance of existing assets, infrastructure spending and intangibles.

Summary for the six months ended June 30, 2019:

· Revenue for the first half of 2019 was $793 million, an increase of 8% from the 2018 period.

· Operating earnings (see “NON-GAAP MEASURES”) were $68 million, an increase of $84 million over the $16 million operating loss for the same period in 2018. As a percentage of revenue, operating earnings were 9% compared negative 2% in 2018. Operating results this year were positively impacted by increased drilling activity in the U.S., gains on asset disposals and higher average revenue rates in each operating region, partially offset by lower Canadian drilling activity.

· General and administrative costs were $57 million, a decrease of $3 million from 2018. The decrease was due to lower share-based incentive compensation that is tied to the price of our common shares, partially offset by the weakening of the Canadian dollar on our U.S. dollar denominated costs (see “Other Items” later in this report).

· Net finance charges were $62 million, a decrease of $2 million from 2018 primarily due to a reduction in interest expense related to debt retired in 2018 and 2019, partially offset by the weakening of the Canadian dollar on our U.S. dollar denominated interest expense.

· Funds provided by operations (see “NON-GAAP MEASURES”) in the first half of 2019 were $137 million, a decrease of $18 million from the prior year comparative period of $154 million. Cash provided by operations was $147 million in 2019 as compared to $168 million in 2018. The reduction in funds and cash provided by operations in 2019 was primarily caused by the receipt of a tax refund in the prior year comparative period and the timing of 2019 interest payments partially offset by improved current year operating results.

· Capital expenditures were $115 million for the first half of 2019, an increase of $48 million over the same period in 2018. Capital spending for 2019 to date includes $100 million for upgrade and expansion capital, primarily related to our sixth new-build rig for Kuwait, completion of a new build ST-1500 and SCR to AC Super Triple upgrade for the U.S. market and $15 million for the maintenance of existing assets, infrastructure spending and intangibles.

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STRATEGY

Precision’s strategic priorities for 2019 are as follows:

1. Generate strong free cash flow and utilize $200 million to reduce debt in 2019 (previously targeted $100 million to $150 million) – In the second quarter of 2019, we generated $106 million in cash provided by operations and further reduced our debt balance by $107 million through a combination of open market repurchases and redemptions of our unsecured senior notes. As of June 30, 2019, our total year-to-date 2019 debt reduction was $124 million, reaching the mid-point of our original 2019 targeted debt reduction range and we have announced further debt reductions for 2019.

2. Maximize financial results by leveraging our High Performance, High Value Super Series rig fleet and scale with disciplined cost management – In the second quarter of 2019, Precision continued to generate strong financial results, largely led by our U.S. contract drilling business. We continued operating at record market share levels in this region, with utilization days up 6% and operating margins (revenue less operating costs) up 14% compared to the prior year quarter. Despite a challenged market, our Canadian drilling operations generated strong cash flow and our Completion and Production Services business contributed an additional $4 million of Adjusted EBITDA as a result of our continued business improvement initiatives. In the second quarter of 2019, we continued to invest in our High-Performance, High-Value Super Series rig fleet with the completion of our sixth Kuwait rig which commenced drilling on July 1, 2019, increasing our economies of scale and operating margins in the region. Additionally, we completed our announced U.S. SCR triple to a full AC Super Triple upgrade.

3. Full scale commercialization and implementation of our Process Automation Control platform, PD-Apps and PD-Analytics – we currently have 33 rigs equipped with our Process Automation Control platform (PAC). Using PAC technology, we drilled approximately 195 wells in the second quarter of 2019, an increase of 65% over the 2018 second quarter. With more than 15 revenue generating PD-Apps commercialized or in development, Precision’s portfolio of technological offerings continues to expand. We continue to demonstrate to our customers our system’s ability to deliver consistent, high-quality results, as we progress towards our 2019 commercialization targets.

OUTLOOK

For the second quarter of 2019, the average West Texas Intermediate price of oil was 12% lower than the prior year comparative period, while Western Canadian Select was 32% higher. The average Henry Hub and AECO gas prices were 10% and 12% lower, respectively.

	Three months ended June 30,				Year ended December 31,
	2019		2018		2018
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)		59.99		67.91		64.88
Western Canadian Select (per barrel) (US$)		49.13		37.16		38.46
Natural gas
United States
Henry Hub (per MMBtu) (US$)		2.56		2.86		3.12
Canada
AECO (per MMBtu) (CDN$)		1.06		1.20		1.49

5

Contracts

Year to date in 2019 we have entered into 35 term contracts. The following chart outlines the average number of drilling rigs by quarter that we had under contract for 2018 and 2019 as of July 24, 2019. For those quarters ended after June 30, 2019, this chart represents the minimum number of long-term contracts where we will be earning revenue. We expect the actual number of contracted rigs to be higher in future periods as we continue to sign contracts.

	Average for the quarter ended 2018								Average for the quarter ended 2019
	Mar. 31		June 30		Sept. 30		Dec. 31		Mar. 31		June 30		Sept. 30		Dec. 31
Average rigs under term contract   as of July 24, 2019:
U.S.		36		48		50		51		56		52		47		36
Canada		8		9		9		11		8		7		7		6
International		8		8		8		8		8		8		9		9
Total		52		65		67		70		72		67		63		51

The following chart outlines the average number of drilling rigs that we had under contract for 2018 and the average number of rigs we have under contract as of July 24, 2019.

	Average for the year ended
	2018		2019		2020
Average rigs under term contract   as of July 24, 2019:
U.S.		46		48		13
Canada		9		7		3
International		8		9		8
Total		63		64		24

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 2018								2019
	Mar. 31		June 30		Sept. 30		Dec. 31		Mar. 31		June 30
Average Precision active rig count:
U.S.		64		72		76		80		79		77
Canada		72		31		52		49		48		27
International		8		8		8		8		8		8
Total		144		111		136		137		135		112

For the first half of 2019, drilling activity has decreased relative to this time last year in the U.S. and Canada. According to industry sources, as of July 19, 2019, the U.S. active land drilling rig count was down 10% compared with the same point last year and the Canadian active land drilling rig count was down approximately 31%. To date in 2019, approximately 81% of the U.S. industry’s active rigs and 58% of the Canadian industry’s active rigs were drilling for oil targets, compared with 81% for the U.S. and 63% for Canada at the same time last year.

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Industry Conditions

We expect Tier 1 rigs to remain the preferred rigs of customers globally. The economic value created by the significant drilling and mobility efficiencies delivered by the most advanced XY pad walking rigs has been highlighted and widely accepted by our customers. The trend to longer-reach horizontal completions and importance of the rig delivering these complex wells consistently and efficiently has been well established by the industry. We expect demand for leading edge high efficiency Tier 1 rigs will continue to strengthen, as drilling rig capability has been a key economic facilitator of horizontal/unconventional resource exploitation. Development and field application of drilling equipment process automation coupled with closed loop drilling controls and de-manning of rigs will continue this technical evolution while creating further cost efficiencies and performance value for customers.

Capital Spending

Capital spending in 2019 is expected to be $169 million and includes $52 million for sustaining, infrastructure and intangibles and $117 million for upgrade and expansion. We expect that the $169 million will be split $162 million in the Contract Drilling Services segment, $5 million in the Completion and Production Services segment and $2 million to the Corporate segment.

SEGMENTED FINANCIAL RESULTS

Precision’s operations are reported in two segments: Contract Drilling Services, which includes the drilling rig, directional drilling, oilfield supply and manufacturing divisions; and Completion and Production Services, which includes the service rig, rental and camp and catering divisions.

	Three months ended June 30,									Six months ended June 30,
(Stated in thousands of Canadian dollars)	2019			2018			% Change			2019			2018			% Change
Revenue:
Contract Drilling Services		334,475			304,353			9.9			713,739			657,155			8.6
Completion and Production Services		26,145			27,706			(5.6	)		81,964			77,748			5.4
Inter-segment eliminations		(1,196	)		(1,343	)		(10.9	)		(2,236	)		(3,181	)		(29.7	)
		359,424			330,716			8.7			793,467			731,722			8.4
Adjusted EBITDA:(1)
Contract Drilling Services		93,295			83,441			11.8			211,750			194,407			8.9
Completion and Production Services		2,781			(1,402	)		(298.4	)		13,299			3,242			310.2
Corporate and Other		(15,039	)		(19,857	)		(24.3	)		(36,045	)		(37,998	)		(5.1	)
		81,037			62,182			30.3			189,004			159,651			18.4

(1) See “NON-GAAP MEASURES”.

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

	Three months ended June 30,									Six months ended June 30,
(Stated in thousands of Canadian dollars, except where noted)	2019			2018			% Change			2019			2018			% Change
Revenue		334,475			304,353			9.9			713,739			657,155			8.6
Expenses:
Operating		231,422			211,008			9.7			477,937			444,156			7.6
General and administrative		9,758			9,904			(1.5	)		21,006			18,592			13.0
Restructuring		-			-			n/m			3,046			-			n/m
Adjusted EBITDA(1)		93,295			83,441			11.8			211,750			194,407			8.9
Depreciation		75,155			81,100			(7.3	)		153,154			160,838			(4.8	)
Gain on asset disposals		(4,271	)		(921	)		363.7			(39,272	)		(2,959	)		1,227.2
Impairment reversal		-			-			n/m			(5,810	)		-			n/m
Operating earnings(1)		22,411			3,262			587.0			103,678			36,528			183.8
Operating earnings(1) as a percentage of revenue		6.7	%		1.1	%					14.5	%		5.6	%

(1)	See “NON-GAAP MEASURES”.
n/m	Calculation not meaningful.

United States onshore drilling statistics:(1)	2019				2018
	Precision		Industry(2)		Precision		Industry(2)
Average number of active land rigs for quarters ended:
March 31		79		1,023		64		951
June 30		77		967		72		1,021
Year to date average		78		995		68		986

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

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	Three months ended June 30,
Canadian onshore drilling statistics:(1)	2019						2018
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		116			548			135			618
Drilling rig operating days (spud to release)		2,192			7,266			2,526			9,536
Drilling rig operating day utilization		21	%		15	%		21	%		17	%
Number of wells drilled		230			752			227			903
Average days per well		9.5			9.7			11.1			10.6
Number of metres drilled (000s)		721			2,301			731			2,756
Average metres per well		3,135			3,059			3,218			3,052
Average metres per day		329			317			289			289

	Six months ended June 30,
Canadian onshore drilling statistics:(1)	2019						2018
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		116			548			135			618
Drilling rig operating days (spud to release)		5,972			22,580			8,180			32,381
Drilling rig operating day utilization		29	%		22	%		34	%		29	%
Number of wells drilled		594			2,228			742			3,133
Average days per well		10.1			10.1			11.0			10.3
Number of metres drilled (000s)		1,772			6,692			2,228			9,201
Average metres per well		2,983			3,004			3,003			2,937
Average metres per day		297			296			272			284

(1) Canadian operations only.

(2) Canadian Association of Oilwell Drilling Contractors (“CAODC”), and Precision – excludes non-CAODC rigs and non-reporting CAODC members.

Revenue from Contract Drilling Services was $334 million this quarter, or 10% higher than the second quarter of 2018, while Adjusted EBITDA (see “NON-GAAP MEASURES”) increased 12% to $93 million. The increase in revenue was primarily due to higher utilization days as well as higher U.S. and international day rates, partially offset by lower Canadian activity and pricing. In the U.S., we had revenue from idle but contracted rigs and turnkey projects of $1 million and nil, respectively, as compared to idle but contracted rig and turnkey revenue of nil and $10 million in the second quarter of 2018. During the quarter, we recognized $1 million of shortfall payment revenue in Canada compared with nil in the prior year comparative period.

Drilling rig utilization days (drilling days plus move days) in the U.S. were 6,994, or 6% higher than the same quarter of 2018 as our U.S. activity was up despite lower industry activity. Drilling rig utilization days in Canada were 2,413 during the second quarter of 2019, a decrease of 15% compared with 2018 primarily due to lower industry activity. Drilling rig utilization days in our international business were 728, in-line with the same quarter of 2018.

Drilling rig revenue per utilization day for the quarter in the U.S. was up 7% compared with the prior year as we realized higher day rates, third-party cost recoveries and idle but contracted rig revenue, partially offset by lower turnkey revenue. Compared with the same quarter in 2018, drilling rig revenue per utilization day in Canada decreased 2% primarily due to lower spot market day rates partially offset by more shortfall payments received. International revenue per utilization day was slightly higher than the prior year comparative period and was primarily due to day rate increases that resulted from the renewal and extension of drilling contracts in the first quarter of 2019.

In the U.S., 66% of utilization days were generated from rigs under term contract as compared with 67% in the second quarter of 2018. In Canada, 12% of our utilization days in the quarter were generated from rigs under term contract, compared with 8% in the second quarter of 2018.

Operating costs were 69% of revenue for the quarter, consistent the prior year period. In the U.S., operating costs for the quarter on a per day basis were higher than the prior year period primarily due higher third-party charges incurred but recovered from the customer, higher repair and maintenance costs due to the timing of equipment certifications and scheduled maintenance and higher crew labour and burden costs offset by lower turnkey costs from decreased activity. On a per utilization day basis, operating costs for the drilling rig division in Canada were greater than the 2018 period. The increase was mainly caused by the impact of lower activity on fixed costs and higher repairs and maintenance costs due to the timing of certification costs.

Depreciation expense in the quarter was 7% lower than the second quarter of 2018 because of asset sales and assets becoming fully depreciated.

8

In the second quarter of 2019, Precision concluded the sale its Mexico-based drilling rigs and ancillary equipment as we received final proceeds of US$8 million.

SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES

	Three months ended June 30,									Six months ended June 30,
(Stated in thousands of Canadian dollars, except where noted)	2019			2018			% Change			2019			2018			% Change
Revenue		26,145			27,706			(5.6	)		81,964			77,748			5.4
Expenses:
Operating		21,823			26,207			(16.7	)		64,956			69,471			(6.5	)
General and administrative		1,541			1,737			(11.3	)		3,252			3,871			(16.0	)
Restructuring		-			1,164			(100.0	)		457			1,164			(60.7	)
Adjusted EBITDA(1)		2,781			(1,402	)		(298.4	)		13,299			3,242			310.2
Depreciation		4,341			5,785			(25.0	)		9,290			11,749			(20.9	)
Loss (gain) on asset disposals		(3,546	)		(773	)		358.7			(3,602	)		138			(2,710.1	)
Operating earnings (loss)(1)		1,986			(6,414	)		(131.0	)		7,611			(8,645	)		(188.0	)
Operating earnings (loss)(1) as a percentage of revenue		7.6	%		(23.2	)%					9.3	%		(11.1	)%
Well servicing statistics:
Number of service rigs (end of period)(2)		123			210			(41.4	)		123			210			(41.4	)
Service rig operating hours		29,540			31,824			(7.2	)		72,438			84,525			(14.3	)
Service rig operating hour utilization		26	%		17	%					31	%		22	%
Service rig revenue per operating hour		733			676			8.4			748			691			8.2

(1) See “NON-GAAP MEASURES”.

(2) In 2019, 75 rigs were not registered with the industry association and 12 snubbing units were sold.

Revenue from Completion and Production Services decreased $2 million or 6% compared with the second quarter of 2018 due to lower activity in our Canadian well servicing and camps businesses, partially offset by improved service rig revenue rates and higher rental activity. Our service rig operating hours in the quarter were down 7% from the second quarter of 2018 while rates increased an average of 8%. Approximately 83% of our second quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 85% of its revenue from Canadian operations and 15% from U.S. operations compared with the second quarter of 2018 where 88% of revenue was generated in Canada and 12% in the U.S.

Average service rig revenue per operating hour in the quarter was $733 or $57 higher than the second quarter of 2018. The increase was primarily the result of rig mix in Canada and increased activity in the U.S.

Adjusted EBITDA (see “NON-GAAP MEASURES”) was $3 million, $4 million higher than the second quarter of 2018, and was primarily the result of higher service rig rates, higher rental activity, reduced restructuring charges and improved cost structure, partially offset by lower Canadian well servicing and camp activity. In the second quarter of 2018, the segment incurred $1 million of restructuring charges primarily related to severance as we continued to align our cost structure to reflect reduced Canadian activity levels.

Operating costs as a percentage of revenue was 83% compared with the prior year comparative quarter of 95%. The reduction of operating costs as a percentage of revenue was primarily the result of increased service rig rates, a higher proportion of 24-hour well service work and continued cost control.

Depreciation expense in the quarter was 25% lower than the prior year comparative period. The decrease in depreciation expense was primarily due to a lower capital asset base resulting from the disposition of snubbing units and Terra Water assets and assets becoming fully depreciated.

During the second quarter of 2019, Precision disposed of certain snubbing units and related equipment for proceeds of $8 million resulting in a gain on asset disposal of $3 million.

In the first quarter of 2019, as a cost control measure, Precision did not renew the registration of 75 Canada-based well service rigs with industry associations due to low anticipated activity levels for the year. Once activity levels improve, these rigs are expected to return to work with minimal start-up costs.

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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 (see “NON-GAAP MEASURES”) of $15 million, a $5 million decrease compared with the second quarter of 2018 primarily due to lower share-based incentive compensation.

OTHER ITEMS

Asset Disposals

In the second quarter of 2019, Precision concluded the sale of its five Mexico-based drilling rigs and ancillary equipment for total proceeds of US$48 million. In the first quarter, Precision received US$40 million for the sale of four drilling rigs and ancillary equipment and recognized a gain on asset disposal of US$24 million. Precision reversed US$4 million of previous impairment charges pertaining to the fifth rig. The impairment reversal brought the drilling rig’s carrying value up to its fair value of US$8 million and was reclassified as held for sale at March 31, 2019. In the second quarter of 2019, Precision delivered the fifth rig to its buyer and received final proceeds of US$8 million. As the rig was carried at fair value, no gain or loss was recognized on disposal.

During the second quarter of 2019, Precision disposed of certain snubbing units and related equipment for proceeds of $8 million resulting in a gain on asset disposal of $3 million.

In addition to the above disposals, through the completion of normal course business operations, we sell used assets incurring gains or losses on disposal.

Share-based Incentive Compensation Plans

We have several cash-settled share-based incentive plans for non-management directors, officers, and other eligible employees. The fair values of the amounts payable under these plans are recognized as an expense with a corresponding increase in liabilities over the period that the participant becomes entitled to payment. The recorded liability is re-established at the end of each reporting period until settlement with the resultant change to fair value of the liability recognized in net earnings (loss) for the period.

We also have two equity-settled share-based incentive plans. Under the Executive Performance Share (Executive PSU) plan, the fair value of PSUs granted is calculated at the date of grant using a Monte Carlo simulation and Black-Scholes option pricing model, and that value is recorded as compensation expense over the grant's vesting period with an offset to contributed surplus. Upon redemption of the Executive PSUs into common shares, the associated amount is reclassified from contributed surplus to shareholders' capital. The share option plan is treated similarly, whereby, the fair value of the share purchased options granted are valued using the Black-Scholes option pricing model and consideration paid by employees upon exercise of the equity purchase options are recognized in share capital.

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

	Three months ended June 30,				Six months ended June 30,
(Stated in thousands of Canadian dollars)	2019		2018		2019		2018
Cash settled share-based incentive plans		515		7,681		6,319		15,471
Equity settled share-based incentive plans:
Executive PSU		3,024		1,696		5,396		2,749
Stock option plan		506		901		1,237		1,718
Total share-based incentive compensation plan expense		4,045		10,278		12,952		19,938
Allocated:
Operating		798		3,305		3,227		6,801
General and Administrative		3,247		6,973		9,725		13,137
		4,045		10,278		12,952		19,938

Cash settled shared-based compensation expense decreased $7 million in the current quarter to $1 million compared with $8 million in the same quarter in 2018. The decrease is primarily due to the decreasing share price in the second quarter of 2019.

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Executive PSU share-based incentive compensation expense for the quarter was $3 million compared with $2 million in the same quarter in 2018. The increased compensation expense was the result of additional Executive PSUs granted in 2019 offset partially by lower fair values for the 2019 grants.

Finance Charges

Net finance charges were $30 million, a decrease of $2 million compared with the second quarter of 2018, primarily due to a reduction in interest expense related to the debt retired in 2018 and 2019, partially offset by the impact of the weakening of the Canadian dollar on our U.S. dollar denominated interest and $1 million of lease accretion charges resulting from the adoption of IFRS 16 on January 1, 2019.

Interest charges on our U.S. denominated long-term debt in the second quarter of 2019 were US$21 million ($28 million) as compared with US$24 million ($31 million) in 2018.

Income Tax

Income tax recovery for the quarter was $6 million compared with $13 million in the same quarter in 2018. In 2019, the Province of Alberta announced various reductions to corporate income tax rates, that when fully implemented over the next three years will decrease the provincial corporate income tax rate from 12% to 8% by 2022. The reduction in the Alberta provincial corporate income tax rate is considered substantially enacted and resulted in a deferred tax recovery of $4 million.

LIQUIDITY AND CAPITAL RESOURCES

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

Our maintenance capital expenditures are tightly governed by and highly responsive to activity levels with additional cost savings leverage provided through our internal manufacturing and supply capabilities. 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 facility (secured)
US$500 million (extendible, revolving term credit facility with US$300 million accordion feature)	Undrawn, except US$25 million in outstanding letters of credit	General corporate purposes	November 21, 2022
Operating facilities (secured)
$40 million	Undrawn, except $27 million in outstanding letters of credit	Letters of credit and general corporate purposes
US$15 million	Undrawn	Short term working capital requirements
Demand letter of credit facility (secured)
US$30 million	Undrawn, except US$2 million in outstanding letters of credit	Letters of credit
Senior notes  (unsecured)
US$116 million – 6.5%	Fully drawn	Capital expenditures and general corporate purposes	December 15, 2021
US$350 million – 7.75%	Fully drawn	Debt redemption and repurchases	December 15, 2023
US$334 million – 5.25%	Fully drawn	Capital expenditures and general corporate purposes	November 15, 2024
US$374 million – 7.125%	Fully drawn	Debt redemption and repurchases	January 15, 2026

As of June 30, 2019, we had US$1,174 million ($1,535 million) outstanding under our unsecured senior notes as compared with US$1,267 million ($1,729 million) at December 31, 2018. The current blended cash interest cost of our debt is approximately 6.7%.

During the first half of 2019, Precision repurchased and cancelled US$26 million of the 7.125% unsecured senior notes due 2026 and US$17 million of the 5.25% notes due 2024 and redeemed US$50 million principal amount of our 6.50% senior notes due 2021.

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Covenants

Following is a listing of our currently applicable covenants and the calculations as of June 30, 2019:

	Covenant		As at June 30, 2019
Senior Facility
Consolidated senior debt to consolidated covenant EBITDA(1)		≤2.50		(0.60	)
Consolidated covenant EBITDA to consolidated interest expense(1)		≥2.50		3.10
Senior Notes
Consolidated interest coverage ratio		≥2.00		3.10

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

At June 30, 2019, we were in compliance with the covenants of our senior credit facility and unsecured senior notes.

Senior Facility

The senior credit facility requires that we comply with certain covenants including a leverage ratio of consolidated senior debt to consolidated Covenant EBITDA (see “NON-GAAP MEASURES”) of less than 2.5:1. For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness.

Under the senior credit facility, we are required to maintain a ratio of consolidated Covenant EBITDA (see “NON-GAAP MEASURES”) to consolidated interest expense, for the most recent four consecutive quarters, of greater than 2.5:1.

The senior credit facility contains certain covenants that place restrictions on our ability to incur or assume additional indebtedness; dispose of assets; pay dividends, undertake share redemptions or other distributions; change our primary business; incur liens on assets; engage in transactions with affiliates; enter into mergers, consolidations or amalgamations; and enter into speculative swap agreements.

Unsecured Senior Notes

The senior notes require that we comply with 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 senior notes restrict our ability to incur additional indebtedness.

The senior notes contain a restricted payment covenant that limits our ability to make payments in the nature of dividends, distributions and for repurchases from shareholders. This restricted payment basket grows from a starting point of October 1, 2010 for the 2021 and 2024 senior notes, from October 1, 2016 for the 2023 senior notes and October 1, 2017 for the 2026 senior notes by, among other things, 50% of consolidated cumulative net earnings and decreases by 100% of consolidated cumulative net losses, as defined in the note agreements, and payments made to shareholders. Beginning with the December 31, 2015 calculation the governing net restricted payments basket was negative which limits our ability to declare and make dividend payments until such time as the restricted payments baskets once again become positive.

In addition, the senior notes contain certain covenants that limit our ability, and the ability of certain subsidiaries, to incur additional indebtedness and issue preferred shares; create liens; create or permit to exist restrictions on our ability or certain subsidiaries to make certain payments and distributions; engage in amalgamations, mergers or consolidations; make certain dispositions and engage in transactions with affiliates.

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

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Impact of foreign exchange rates

The devaluation of the Canadian dollar during the first half of 2019 resulted in higher translated U.S. denominated revenue and costs. On average for the three and six months ended June 30, 2019, the Canadian dollar weakened by 4% from the comparable 2018 periods. The following table summarizes the average and closing Canada-U.S. foreign exchanges rates:

	Three months ended June 30,				Six months ended June 30,				December 31,
	2019		2018		2019		2018		2018
Canada-U.S. foreign exchange rates
Average		1.34		1.29		1.33		1.28		1.30
Closing		1.31		1.31		1.31		1.31		1.37

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)	2018						2019
Quarters ended	September 30			December 31			March 31		June 30
Revenue		382,457			427,010			434,043		359,424
Adjusted EBITDA(1)		80,988			134,492			107,697		81,037
Net earnings (loss)		(30,648	)		(198,328	)		25,014		(13,801	)
Net earnings (loss) per basic share		(0.10	)		(0.68	)		0.09		(0.05	)
Net earnings (loss) per diluted share		(0.10	)		(0.68	)		0.08		(0.05	)
Funds provided by operations(1)		64,368			92,595			95,993		40,950
Cash provided by operations		31,961			93,489			40,587		106,035

(Stated in thousands of Canadian dollars, except per share amounts)	2017						2018
Quarters ended	September 30			December 31			March 31			June 30
Revenue		314,504			347,187			401,006			330,716
Adjusted EBITDA(1)		73,239			90,914			97,469			62,182
Net loss		(26,287	)		(47,005	)		(18,077	)		(47,217	)
Net loss per basic		(0.09	)		(0.16	)		(0.06	)		(0.16	)
Net loss per diluted share		(0.09	)		(0.16	)		(0.06	)		(0.16	)
Funds provided by operations(1)		85,140			28,323			104,026			50,225
Cash provided by operations		56,757			23,289			38,189			129,695

(1) See “NON-GAAP MEASURES”.

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CRITICAL ACCOUNTING JUDGEMENTS AND ESTIMATES

Because of the nature of our business, we are required to make judgments and estimates in preparing our Consolidated Interim Financial Statements that could materially affect the amounts recognized. Our judgments and estimates are based on our past experiences and assumptions we believe are reasonable in the circumstances. The critical judgments and estimates used in preparing the Interim Financial Statements are described in our 2018 Annual Report and there have been no material changes to our critical accounting judgments and estimates during the three and six months ended June 30, 2019 except for those impacted by the adoption of new accounting standards.

CHANGES IN ACCOUNTING POLICY

New standards adopted

The following standards became effective on January 1, 2019:

· IFRS 16 Leases

· IFRIC 23 Uncertainty over Income Tax Treatments

Precision adopted these standards using the modified retrospective method on January 1, 2019. Please see the unaudited June 30, 2019 Interim Consolidated Financial Statements and related notes for further details on the adoption of these standards.

Impact of IFRS 16 Leases on Adjusted EBITDA

With the adoption of IFRS 16, the accounting treatment for operating leases when Precision is the lessee, changed effective January 1, 2019. Precision adopted IFRS 16 using the modified retrospective approach and our comparative information was not restated. As a result, the comparability of our 2019 Adjusted EBITDA to periods prior to January 1, 2019 is impacted.

Under IFRS 16, leases classified as operating leases were recognized on our statement of financial position with a right of use asset and corresponding lease obligation representing the present value of Precision’s future lease payments. Once recognized, right of use assets are depreciated over the shorter of their useful life and the term of the lease. The lease obligation is measured at amortized cost using the effective interest method. Under this approach, an interest charge is applied to accrete the lease obligation to the present value of future lease payments. As lease payments are made, the lease obligation is reduced.

Historically, operating lease obligations were accounted for as ‘off-balance sheet’ and lease expenses were only recognized at the time of payment in either operating or general and administrative expense. However, under IFRS 16, lease costs are reflected on the statement of income (loss) through depreciation and interest expense, resulting in an increase to Adjusted EBITDA.

Upon transition, we recognized right of use assets and corresponding lease obligations of $73 million. For the three and six months ended June 30, 2019, Precision recorded lease interest charges of $1 million and $2 million and depreciated its right of use assets by $2 million and $4 million, respectively. As a result of the new lease standard, our Adjusted EBITDA was positively impacted for the three and six months ended June 30, 2019 by $3 million and $6 million, respectively.

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NON-GAAP MEASURES

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

Adjusted EBITDA

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

Covenant EBITDA

Covenant EBITDA, as defined in our senior credit facility agreement, is used in determining the Corporation’s compliance with its covenants. Covenant EBITDA differs from Adjusted EBITDA by the exclusion of bad debt expense, restructuring costs, certain foreign exchange amounts and with the adoption of the new lease standard IFRS 16 - Leases, the deduction of cash lease payments incurred after December 31, 2018.

Operating Earnings (Loss)

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

	Three months ended June 30,						Six months ended June 30,
(Stated in thousands of Canadian dollars)	2019			2018			2019			2018
Revenue		359,424			330,716			793,467			731,722
Expenses:
Operating		252,049			235,872			540,657			510,446
General and administrative		26,338			31,498			57,368			60,461
Restructuring		-			1,164			6,438			1,164
Depreciation and amortization		83,327			90,315			170,080			178,750
Gain on asset disposals		(7,859	)		(1,694	)		(42,909	)		(2,821	)
Impairment reversal		-			-			(5,810	)		-
Operating earnings (loss)		5,569			(26,439	)		67,643			(16,278	)
Foreign exchange		(3,763	)		556			(5,886	)		1,771
Finance charges		30,385			32,103			61,688			63,782
Loss (gain) on repurchase of unsecured notes		(1,085	)		1,176			(1,398	)		1,176
Earnings (loss) before income taxes		(19,968	)		(60,274	)		13,239			(83,007	)

Funds Provided By (Used In) Operations

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

Working Capital

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

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

Certain statements contained in this report, including statements that contain words such as "could", "should", "can", "anticipate", "estimate", "intend", "plan", "expect", "believe", "will", "may", "continue", "project", "potential" and similar expressions and statements relating to matters that are not historical facts constitute "forward-looking information" within the meaning of applicable Canadian securities legislation and "forward-looking statements" within the meaning of the "safe harbor" provisions of the United States Private Securities Litigation Reform Act of 1995 (collectively, "forward-looking information and statements").

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

· our strategic priorities for 2019;

· our capital expenditure plans for 2019;

· anticipated activity levels in 2019 and our scheduled infrastructure projects;

· anticipated demand for Tier 1 rigs;

· the average number of term contracts in place for 2019 and 2020; and

· our future debt reduction plans.

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

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

· the 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 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;

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

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

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

· the availability of qualified personnel and management;

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

· 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 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, 2018, which may be accessed on Precision’s SEDAR profile at www.sedar.com or under Precision’s EDGAR profile at www.sec.gov. The forward-looking information and statements contained in this report are made as of the date hereof and Precision undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, except as required by law.

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SHAREHOLDER INFORMATION

STOCK EXCHANGE LISTINGS

Shares of Precision Drilling Corporation are listed on the Toronto Stock Exchange under the trading symbol PD and on the New York Stock Exchange under the trading symbol PDS.

TRANSFER AGENT AND REGISTRAR

Computershare Trust Company of Canada

Calgary, Alberta

TRANSFER POINT

Computershare Trust Company NA

Canton, Massachusetts

Q2 2019 TRADING PROFILE

Toronto (TSX: PD)

High: $4.05

Low: $2.20

Close: $2.46

Volume Traded: 87,594,195

New York (NYSE: PDS)

High: US$3.01

Low: US$1.65

Close: US$1.89

Volume Traded: 65,223,300

ACCOUNT QUESTIONS

Precision’s Transfer Agent can help you with a variety of shareholder related services, including:

•  change of address

•  lost unit certificates

•  transfer of shares to another person

•  estate settlement

Computershare Trust Company of Canada

100 University Avenue

9th Floor, North Tower

Toronto, Ontario M5J 2Y1

Canada

1-800-564-6253 (toll free in Canada and the United States)

1-514-982-7555 (international direct dialing)

Email: service@computershare.com

ONLINE INFORMATION

To receive news releases by email, or to view this interim report online, please visit Precision’s website at www.precisiondrilling.com and refer to the Investor Relations section. Additional information relating to Precision, including the Annual Information Form, Annual Report and Management Information Circular has been filed with SEDAR and is available at www.sedar.com and on the EDGAR website www.sec.gov

CORPORATE INFORMATION

DIRECTORS

Michael R. Culbert

William T. Donovan

Brian J. Gibson

Allen R. Hagerman, FCA

Steven W. Krablin

Susan M. MacKenzie

Kevin O. Meyers

Kevin A. Neveu

David W. Williams

OFFICERS

Kevin A. Neveu

President and Chief Executive Officer

Veronica H. Foley

Senior Vice President, General Counsel and Corporate Secretary

Carey T. Ford

Senior Vice President and Chief Financial Officer

Shuja U. Goraya

Chief Technology Officer

Darren J. Ruhr

Chief Administrative Officer

Gene C. Stahl

Chief Marketing Officer

AUDITORS

KPMG LLP

Calgary, Alberta

HEAD OFFICE

Suite 800, 525 8th Avenue SW

Calgary, Alberta, Canada T2P 1G1

Telephone: 403-716-4500

Facsimile: 403-264-0251

Email: info@precisiondrilling.com

www.precisiondrilling.com

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