Exhibit 99.1

Precision Drilling Corporation

Third Quarter Report for the three and nine months ended September 30, 2019 and 2018

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s Discussion and Analysis for the three and nine months ended September 30, 2019 of Precision Drilling Corporation (“Precision” or the “Corporation”) prepared as of October 23, 2019 focuses on the unaudited Condensed Interim Consolidated Financial Statements and related notes and pertains to known risks and uncertainties relating to the oilfield services sector. This discussion should not be considered all-inclusive as it does not include all changes regarding general economic, political, governmental and environmental events. This discussion should be read in conjunction with the Corporation’s 2018 Annual Report, Annual Information Form, unaudited September 30, 2019 Condensed Interim Consolidated Financial Statements and related notes.

This report contains “forward-looking information and statements” within the meaning of applicable securities laws. For a full disclosure of the forward-looking information and statements and the risks to which they are subject, see the “Cautionary Statement Regarding Forward-Looking Information and Statements” 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 third quarter highlights:

· Revenue of $376 million was a decrease of 2% compared with the third quarter of 2018.

· Net loss of $4 million or negative $0.01 per share compares to a net loss of $31 million or negative $0.10 per share in the third 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 $98 million was 21% higher than the third quarter of 2018. During the quarter, we recognized $6 million of non-recurring items that positively impacted Adjusted EBITDA but did not relate to current period operations.

· Funds provided by operations (see “NON-GAAP MEASURES”) was $80 million versus $64 million in the prior year quarter. Cash provided by operations was $67 million versus $32 million in the prior year quarter. The increase in funds and cash provided by operations in the current quarter was primarily the result of improved operations and management’s focus on free cash flow.

· Strict cost control focus resulted in year-to-date general and administrative costs decreasing 13% from the same period in 2018.

· For the first nine months of 2019, debt reduction of $146 million and share repurchases of $8 million while our cash balance of $94 million remained largely unchanged from the start of the year.

· In the quarter the Toronto Stock Exchange approved our application to implement a Normal Course Issuer Bid. We purchased and cancelled 5 million common shares for $8 million in the third quarter and, as of October 23, 2019, purchased and cancelled an additional 3 million common shares for $4 million.

· Year-to-date market share gains in both the U.S. and Canada evident by Precision’s year-to-date average U.S. rig count increasing 7% despite a 4% industry decrease from the same period in 2018 and Precision’s Canadian average rig count decreasing 25% compared to a 32% decrease for the industry.

· Substantial increases in Process Automation Control (PAC) utilization and commercial agreements. With 584 wells drilled in 2019, Precision is on track to achieve our 2019 commercialization target.

· Our year-to-date Completion and Production Services Adjusted EBITDA of $18 million was more than double our total for the comparable 2018 period.

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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 September 30,							Nine months ended September 30,
(Stated in thousands of Canadian dollars, except per share amounts)		2019		2018		% Change			2019		2018		% Change
Revenue		375,552		382,457		(1.8	)		1,169,019		1,114,179		4.9
Adjusted EBITDA(1)		97,895		80,988		20.9			286,899		240,639		19.2
Operating earnings (loss)(1)		19,235		(9,702	)	(298.3	)		86,878		(25,980	)	(434.4	)
Net earnings (loss)		(3,534	)	(30,648	)	(88.5	)		7,679		(95,942	)	(108.0	)
Cash provided by operations		66,556		31,961		108.2			213,178		199,845		6.7
Funds provided by operations(1)		79,930		64,368		24.2			216,873		218,619		(0.8	)
Capital spending:
Expansion		8,162		9,909		(17.6	)		100,148		26,380		279.6
Upgrade		4,921		11,545		(57.4	)		12,647		28,355		(55.4	)
Maintenance and infrastructure		10,831		6,913		56.7			25,550		30,247		(15.5	)
Intangibles		12		660		(98.2	)		476		10,880		(95.6	)
Proceeds on sale		(3,385	)	(3,757	)	(9.9	)		(85,837	)	(12,437	)	590.2
Net capital spending		20,541		25,270		(18.7	)		52,984		83,425		(36.5	)
Net earnings (loss) per share:
Basic		(0.01	)	(0.10	)	(90.0	)		0.03		(0.33	)	(109.1	)
Diluted		(0.01	)	(0.10	)	(90.0	)		0.03		(0.33	)	(109.1	)

(1) See “NON-GAAP MEASURES”.

Operating Highlights

	Three months ended September 30,					Nine months ended September 30,
		2019	2018	% Change			2019	2018	% Change
Contract drilling rig fleet		233	257	(9.3	)		233	257	(9.3	)
Drilling rig utilization days:
U.S.		6,613	7,013	(5.7	)		20,730	19,396	6.9
Canada		3,822	4,798	(20.3	)		10,579	14,100	(25.0	)
International		827	736	12.4			2,275	2,184	4.2
Revenue per utilization day:
U.S.(1) (US$)		23,092	21,399	7.9			23,242	21,296	9.1
Canada (Cdn$)		19,311	19,538	(1.2	)		21,342	21,273	0.3
International (US$)		51,233	50,007	2.5			50,923	49,959	1.9
Operating cost per utilization day:
U.S. (US$)		14,487	14,151	2.4			14,552	14,071	3.4
Canada (Cdn$)		14,639	14,164	3.4			15,406	14,294	7.8
Service rig fleet(2)		123	210	(41.4	)		123	210	(41.4	)
Service rig operating hours		34,851	37,169	(6.2	)		107,289	121,694	(11.8	)
Revenue per operating hour (Cdn$)		712	708	0.6			736	696	5.7

(1) 2018 period includes revenue from idle but contracted rig days.

(2) 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)	September 30, 2019	December 31, 2018
Working capital(1)	227,282	240,539
Cash	93,761	96,626
Long-term debt	1,513,827	1,706,253
Total long-term financial liabilities	1,588,883	1,723,350
Total assets	3,445,734	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 September 30, 2019:

· Revenue was $376 million, 2% lower than the third quarter of 2018. The revenue decrease primarily resulted from lower activity in the U.S. and Canada, partially offset by higher average day rates in our U.S. and international operations and higher international activity. Compared with the third quarter of 2018, our drilling activity for the quarter decreased 6% in the U.S., decreased 20% in Canada and grew 12% internationally. Our 2019 third quarter revenue from our Contract Drilling Services segment was consistent with the 2018 quarter while Completion and Production Services segment revenue decreased 15%.

· General and administrative expenses were $21 million, $9 million lower than the third quarter of 2018. The decreased expenses were due to lower share-based incentive compensation expense, fixed cost control initiatives, non-recurring items of $2 million and the impact of lease-related charges due to the adoption of IFRS 16 partially offset by the weakening of the Canadian dollar on our U.S. dollar denominated costs.

· Adjusted EBITDA (see “NON-GAAP MEASURES”) was $98 million, an increase of $17 million from the third quarter of 2018. Our Adjusted EBITDA as a percentage of revenue was 26% this quarter, compared with 21% in the comparative quarter of 2018. Operating earnings (see “NON-GAAP MEASURES”) were $19 million compared with an operating loss of $10 million in the third quarter of 2018. Both Adjusted EBITDA and operating earnings this quarter were positively impacted by higher international activity, increased average U.S. and international day rates, lower general and administrative costs and the recognition of $4 million of non-recurring items in operating expenses partially offset by lower U.S. and Canadian drilling activity. With the adoption of IFRS 16, lease-related charges of $3 million in the quarter 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 $2 million compared with $8 million in the third quarter of 2018. See discussion on share-based incentive compensation under “Other Items” later in this report for additional details.

· Net finance charges were $28 million, a decrease of $3 million compared with the third 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 third quarter of 2019 to US$23,092 from US$21,399 in the prior year quarter. The increase was the result of higher day rates, third-party cost recoveries and rig technology revenue, partially offset by lower turnkey activity, rig mobilizations and idle but contracted rig revenue. During the quarter, we had revenue from idle but contracted rigs and turnkey projects of nil, as compared to third quarter 2018 idle but contracted rig and turnkey revenue of US$0.3 million and US$0.4 million, respectively. Operating costs on a per day basis increased to US$14,487 in the third quarter of 2019 compared with US$14,151 in 2018. The increase was mainly due to higher third-party charges incurred but recovered from the customer, partially offset by lower repair and maintenance costs due to the timing of equipment certifications and scheduled maintenance and lower turnkey costs from decreased activity. On a sequential basis, revenue per utilization day, excluding revenue from turnkey and idle but contracted rigs, decreased by US$218 due to lower fleet average day rates partially offset by higher technology revenue, while operating costs per day decreased by US$313 due to certain non-recurring items.

· In Canada, average revenue per utilization day for contract drilling rigs was $19,311 compared with $19,538 in the third quarter of 2018. The lower average revenue per utilization day in the third quarter of 2019 was primarily because of lower day rates and boiler revenue. We did not receive shortfall payments in the third quarter of 2019, consistent with the 2018 quarter. Average operating costs per utilization day for drilling rigs in Canada increased to $14,639 compared with the prior year quarter of $14,164. 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$42 million in the third quarter of 2019, an increase of US$5 million over the prior year period. Average revenue per utilization day in our international contract drilling business was US$51,233 compared with US$50,007 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 and the deployment of our sixth Kuwait rig.

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· Revenue from Completion and Production Services decreased $5 million compared with the third quarter of 2018 due to lower activity in each of our Canadian business lines partially offset by higher U.S. well service activity. Our average service rig revenue per operating hour was up slightly from the third quarter of 2018 to $712 while our service rig operating hours in the quarter were down 6%. Adjusted EBITDA (see “NON-GAAP MEASURES”) of $5 million in the third quarter of 2019 was consistent with the 2018 quarter as lower Canadian activity was offset by higher U.S. service rig activity and lower costs due to the impact of cost control measures from prior periods.

· Directional drilling services realized revenue of $13 million in the third quarter of 2019 compared with $7 million in the prior year period.

· Funds provided by operations (see “NON-GAAP MEASURES”) in the third quarter of 2019 were $80 million, an increase of $16 million from the prior year comparative quarter. Cash provided by operations was $67 million versus $32 million in the prior year quarter. The increase in funds and cash provided by operations was primarily the result of improved operating results in 2019 and management’s focus on free cash flow.

· Capital expenditures were $24 million in the third quarter, $5 million lower than the same period in 2018. Capital spending for the quarter included $13 million for upgrade and expansion capital and $11 million for the maintenance of existing assets, infrastructure spending and intangibles.

Summary for the nine months ended September 30, 2019:

· Revenue for the first nine months of 2019 was $1,169 million, an increase of 5% from the 2018 period.

· Operating earnings (see “NON-GAAP MEASURES”) were $87 million, an increase of $113 million over the $26 million operating loss for the same period in 2018. As a percentage of revenue, operating earnings were 7% compared to negative 2% in 2018. Operating results this year were positively impacted by increased U.S. and international drilling activity, higher average revenue rates in each operating region and gains on asset disposals, partially offset by lower Canadian drilling activity.

· General and administrative costs were $78 million, a decrease of $12 million from 2018. The decrease was due to lower share-based incentive compensation that is tied to the price of our common shares and continued fixed cost control initiatives, 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 $90 million, a decrease of $5 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 nine months of 2019 were $217 million, a decrease of $2 million from the prior year comparative period of $219 million. Cash provided by operations was $213 million in 2019 as compared to $200 million in 2018.

· Capital expenditures were $139 million for the first nine months of 2019, an increase of $43 million over the same period in 2018. Capital spending for 2019 to date includes $113 million for upgrade and expansion capital and $26 million for the maintenance of existing assets, infrastructure spending and intangibles.

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 – In the third quarter of 2019, we generated $67 million in cash provided by operations and further reduced our debt balance by $21 million through open market repurchases of our unsecured senior notes. With a total year-to-date 2019 debt reduction of $146 million, continued strong operating cash flow and a cash balance of $94 million, we are on pace to meet or exceed our recently increased 2019 debt reduction target of $200 million. Additionally, we have set debt reduction targets at $100 million to $150 million for 2020, including retiring our 2021 unsecured senior notes.

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2. Maximize financial results by leveraging our High Performance, High Value Super Series rig fleet and scale with disciplined cost management – In the third quarter of 2019, Precision generated Adjusted EBITDA as a percentage of revenue of 26%, our highest third quarter percentage in the past four years. We continued operating at record market share levels in the U.S. and Canada and have leveraged our size and scale to maximize cash flow. In the U.S., operating margins (revenue less operating costs) were up 20% compared to the prior year quarter. Despite decreased Canadian industry activity levels, our Canadian drilling operations generated strong cash flow and our Completion and Production Services business contributed $5 million of Adjusted EBITDA. Our focus on fixed costs has resulted in year-to-date general and administrative cost reductions of 13% from the same period in 2018. In the third quarter of 2019, we continued to invest in our High-Performance, High-Value Super Series rig fleet with the deployment of our sixth Kuwait rig which commenced drilling on July 1, 2019, increasing our economies of scale and operating margins in the region.

3. Full scale commercialization and implementation of our Process Automation Control platform, PD-Apps and PD-Analytics – We currently have 34 rigs equipped with our Process Automation Control platform. Using PAC technology, we drilled approximately 584 wells year-to-date in 2019, an increase of 69% over the prior year comparative. With more than 15 revenue generating PD-Apps commercialized or in development, Precision’s portfolio of technology offerings continues to expand. We are demonstrating to our customers our system’s ability to deliver consistent, high-quality results, as we progress towards our 2019 commercialization targets. In the third quarter, we doubled the number of customers paying commercial rates for our PAC system.

OUTLOOK

For the third quarter of 2019, the average price of West Texas Intermediate and Western Canadian Select were down 19% and 6%, respectively. The average Henry Hub and AECO gas prices were 19% and 22% lower, respectively.

	Three months ended September 30,		Year ended December 31,
	2019	2018	2018
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)	56.40	69.77	64.88
Western Canadian Select (per barrel) (US$)	44.21	47.25	38.46
Natural gas
United States
Henry Hub (per MMBtu) (US$)	2.37	2.93	3.12
Canada
AECO (per MMBtu) (CDN$)	0.97	1.24	1.49

Contracts

Year-to-date in 2019 we have entered into 43 term contracts. The following chart outlines the average number of drilling rigs by quarter that we had under contract for 2019 and 2020 as of October 23, 2019. For those quarters ended after September 30, 2019, this chart represents the minimum number of 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 2019					Average for the quarter ended 2020
		Mar. 31	June 30	Sept. 30	Dec. 31		Mar. 31	June 30	Sept. 30	Dec. 31
Average rigs under term contract as of October 23, 2019:
U.S.		56	52	49	41		30	21	15	11
Canada		8	5	5	5		4	3	2	2
International		8	8	9	9		8	8	6	6
Total		72	65	63	55		42	32	23	19

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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 October 23, 2019.

	Average for the year ended
		2018	2019	2020
Average rigs under term contract as of October 23, 2019:
U.S.		46	50	19
Canada		9	5	3
International		8	9	7
Total		63	64	29

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					Average for the quarter ended 2019
		Mar. 31	June 30	Sept. 30	Dec. 31		Mar. 31	June 30	Sept. 30
Average Precision active rig count:
U.S.		64	72	76	80		79	77	72
Canada		72	31	52	49		48	27	42
International		8	8	8	8		8	8	9
Total		144	111	136	137		135	112	123

For the nine months ended September 30, 2019, drilling activity has decreased relative to this time last year in the U.S. and Canada. According to industry sources, as of October 23, 2019, the U.S. active land drilling rig count was down 21% compared with the same point last year and the Canadian active land drilling rig count was down approximately 32%. To date in 2019, approximately 82% of the U.S. industry’s active rigs and 62% of the Canadian industry’s active rigs were drilling for oil targets, compared with 81% for the U.S. and 64% for Canada at the same time last year.

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 relative to less capable rigs, 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 $144 million and includes $31 million for sustaining, infrastructure and intangibles and $113 million for upgrade and expansion. We expect that the $144 million will be split $139 million in the Contract Drilling Services segment, $4 million in the Completion and Production Services segment and $1 million to the Corporate segment.

For 2020, we expect capital spending to be $60 million to $80 million, comprised primarily of maintenance and upgrade capital.

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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 September 30,							Nine months ended September 30,
(Stated in thousands of Canadian dollars)		2019		2018		% Change			2019		2018		% Change
Revenue:
Contract Drilling Services		346,443		347,494		(0.3	)		1,060,182		1,004,649		5.5
Completion and Production Services		30,880		36,297		(14.9	)		112,844		114,045		(1.1	)
Inter-segment eliminations		(1,771	)	(1,334	)	32.8			(4,007	)	(4,515	)	(11.3	)
		375,552		382,457		(1.8	)		1,169,019		1,114,179		4.9
Adjusted EBITDA:(1)
Contract Drilling Services		105,167		95,596		10.0			316,917		290,003		9.3
Completion and Production Services		4,597		4,628		(0.7	)		17,896		7,870		127.4
Corporate and Other		(11,869	)	(19,236	)	(38.3	)		(47,914	)	(57,234	)	(16.3	)
		97,895		80,988		20.9			286,899		240,639		19.2

(1) See “NON-GAAP MEASURES”.

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

	Three months ended September 30,							Nine months ended September 30,
(Stated in thousands of Canadian dollars, except where noted)		2019		2018		% Change			2019		2018		% Change
Revenue		346,443		347,494		(0.3	)		1,060,182		1,004,649		5.5
Expenses:
Operating		233,370		242,792		(3.9	)		711,307		686,948		3.5
General and administrative		7,906		9,106		(13.2	)		28,912		27,698		4.4
Restructuring		-		-		n/m			3,046		-		n/m
Adjusted EBITDA(1)		105,167		95,596		10.0			316,917		290,003		9.3
Depreciation		74,532		82,414		(9.6	)		227,686		243,252		(6.4	)
Gain on asset disposals		(3,956	)	(1,672	)	136.6			(43,228	)	(4,631	)	833.4
Impairment reversal		-		-		n/m			(5,810	)	-		n/m
Operating earnings(1)		34,591		14,854		132.9			138,269		51,382		169.1
Operating earnings(1) as a percentage of revenue		10.0	%	4.3	%				13.0	%	5.1	%

(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
September 30		72		896		76		1,032
Year to date average		76		962		71		1,001

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

	Three months ended September 30,
Canadian onshore drilling statistics:(1)	2019					2018
		Precision		Industry(2)			Precision		Industry(2)
Number of drilling rigs (end of period)		116		548			135		604
Drilling rig operating days (spud to release)		3,432		11,362			4,279		16,875
Drilling rig operating day utilization		32	%	23	%		35	%	30	%
Number of wells drilled		370		1,381			520		2,046
Average days per well		9.3		8.2			8.2		8.2
Number of metres drilled (000s)		1,095		3,949			1,313		5,502
Average metres per well		2,961		2,860			2,526		2,689
Average metres per day		319		348			307		326

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	Nine months ended September 30,
Canadian onshore drilling statistics:(1)	2019					2018
		Precision		Industry(2)			Precision		Industry(2)
Number of drilling rigs (end of period)		116		548			135		604
Drilling rig operating days (spud to release)		9,404		33,942			12,459		49,256
Drilling rig operating day utilization		30	%	22	%		34	%	29	%
Number of wells drilled		964		3,609			1,262		5,179
Average days per well		9.8		9.4			9.9		9.5
Number of metres drilled (000s)		2,475		10,641			3,542		14,704
Average metres per well		2,567		2,948			2,806		2,839
Average metres per day		263		313			284		299

(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 for the third quarter of 2019 was $346 million, $1 million lower than the third quarter of 2018, while Adjusted EBITDA (see “NON-GAAP MEASURES”) increased 10% to $105 million. The lower revenue in 2019 was primarily due to lower U.S. and Canada utilization days offset by higher U.S. and international day rates and international activity. In the U.S., idle but contracted rigs and turnkey revenue was nil, as compared to third quarter 2018 idle but contracted rig and turnkey revenue of US$0.3 million and US$0.4 million, respectively.

Drilling rig utilization days (drilling days plus move days) in the U.S. were 6,613, or 6% lower than the same quarter of 2018, consistent with overall lower industry activity. Drilling rig utilization days in Canada were 3,822 during the third quarter of 2019, a decrease of 20% compared with 2018 primarily due to lower industry activity. Drilling rig utilization days in our international business was 827, 12% higher than the same quarter of 2018. The increased activity was primarily due to the deployment of our sixth Kuwait rig which commenced drilling operations on July 1, 2019.

Revenue per utilization day in the U.S. increased in the third quarter of 2019 to US$23,092 from US$21,399 in the prior year quarter. The increase was the result of higher day rates, third-party cost recoveries and rig technology revenue, partially offset by lower turnkey activity, rig mobilizations and idle but contracted rig revenue. In the U.S., on a sequential basis, revenue per utilization day, excluding revenue from turnkey and idle but contracted rigs, decreased by US$218 due to lower fleet average day rates partially offset by technology revenue. In Canada, average revenue per utilization day for contract drilling rigs was $19,311 compared with $19,538 in the third quarter of 2018. The lower average revenue per utilization day in the third quarter of 2019 was primarily because of lower day rates and boiler revenue. Average revenue per utilization day in our international contract drilling business was US$51,233 compared with US$50,007 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 and the deployment of our sixth Kuwait rig.

In the U.S., 66% of utilization days were generated from rigs under term contract as compared with 67% in the third quarter of 2018. In Canada, 8% of our utilization days in the quarter were generated from rigs under term contract, compared with 11% in the third quarter of 2018.

Operating costs were 67% of revenue for the quarter, 3% lower than the prior year quarter. Our U.S. operating costs, on a per day basis, increased to US$14,487 in the third quarter of 2019 compared with US$14,151 in 2018. The increase was mainly due to higher third-party charges incurred but recovered from the customer, partially offset by lower turnkey costs from decreased activity. In the U.S., on a sequential basis, operating costs per day decreased by US$313 due to certain non-recurring items not related to current period operations. Average operating costs per utilization day for drilling rigs in Canada increased to $14,639 compared with the prior year quarter of $14,164. 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 10% lower than the third quarter of 2018 because of asset sales and assets becoming fully depreciated.

In the third quarter of 2019, through the completion of normal course business operations, we sold used assets resulting in a gain on asset disposals of $4 million as compared to $2 million in the 2018 quarter.

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SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES

	Three months ended September 30,							Nine months ended September 30,
(Stated in thousands of Canadian dollars, except where noted)		2019		2018		% Change			2019		2018		% Change
Revenue		30,880		36,297		(14.9	)		112,844		114,045		(1.1	)
Expenses:
Operating		24,994		30,138		(17.1	)		89,950		99,609		(9.7	)
General and administrative		1,289		1,531		(15.8	)		4,541		5,402		(15.9	)
Restructuring		-		-		n/m			457		1,164		(60.7	)
Adjusted EBITDA(1)		4,597		4,628		(0.7	)		17,896		7,870		127.4
Depreciation		4,282		5,636		(24.0	)		13,572		17,385		(21.9	)
Loss (gain) on asset disposals		36		1,005		(96.4	)		(3,566	)	1,143		(412.0	)
Operating earnings (loss)(1)		279		(2,013	)	(113.9	)		7,890		(10,658	)	(174.0	)
Operating earnings (loss)(1) as a percentage of revenue		0.9	%	(5.5	)%				7.0	%	(9.3	)%
Well servicing statistics:
Number of service rigs (end of period)(2)		123		210		(41.4	)		123		210		(41.4	)
Service rig operating hours		34,851		37,169		(6.2	)		107,289		121,694		(11.8	)
Service rig operating hour utilization		31	%	19	%				31	%	21	%
Service rig revenue per operating hour		712		708		0.6			736		696		5.7

(1) See “NON-GAAP MEASURES”.

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

n/m Calculation not meaningful.

Revenue from Completion and Production Services decreased $5 million compared with the third quarter of 2018 due to lower activity in each of our Canadian business lines partially offset by improved well service rig revenue rates and U.S. well service activity. Our service rig operating hours in the quarter were down 6% from the third quarter of 2018 while rates remained consistent. Approximately 90% of our third 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 third quarter of 2018 where 92% of revenue was generated in Canada and 8% in the U.S.

Average service rig revenue per operating hour in the quarter was $712, higher than the third quarter of 2018. The increase was the result of higher activity in the U.S. combined with rate increases in Canada offset by the impact of the sale of our snubbing units that closed in the second quarter of 2019.

Adjusted EBITDA (see “NON-GAAP MEASURES”) of $5 million in the third quarter of 2019 was consistent with the 2018 quarter and was primarily the result of lower Canadian activity offset by higher service rig rates, U.S. service activity and the impact of the snubbing disposal.

Operating costs as a percentage of revenue was 81% compared with the prior year comparative quarter of 83%. 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 24% 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.

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.

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 $12 million, a $7 million decrease compared with the third quarter of 2018 primarily due to lower share-based incentive compensation.

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OTHER ITEMS

Share-based Incentive Compensation Plans

We have several cash-settled share-based incentive plans and two equity-settled share-based incentive plans. Details of vesting conditions, fair value determination and accounting policy for each plan can be found in the notes to our consolidated annual financial statements for the year ended December 31, 2018.

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

	Three months ended September 30,				Nine months ended September 30,
(Stated in thousands of Canadian dollars)		2019		2018		2019	2018
Cash settled share-based incentive plans		(1,655	)	5,128		4,664	20,599
Equity settled share-based incentive plans:
Executive PSU		3,103		1,595		8,499	4,344
Stock option plan		514		937		1,751	2,655
Total share-based incentive compensation plan expense		1,962		7,660		14,914	27,598
Allocated:
Operating		87		2,292		3,314	9,093
General and Administrative		1,875		5,368		11,600	18,505
		1,962		7,660		14,914	27,598

Cash settled shared-based compensation expense decreased $7 million in the current quarter to a recovery of $2 million compared with an expense of $5 million in the same quarter in 2018. The recovery was primarily due to the decreasing share price in the third quarter of 2019.

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 $28 million, a decrease of $3 million compared with the third 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 third quarter of 2019 were US$20 million ($27 million) as compared with US$23 million ($30 million) in 2018.

Income Tax

Income tax recovery for the quarter was $5 million compared with $9 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 year-to-date deferred tax recovery of $3 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.

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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$318 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 September 30, 2019, we had US$1,158 million ($1,533 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 nine months of 2019, Precision repurchased and cancelled US$26 million of the 7.125% unsecured senior notes due 2026 and US$33 million of the 5.25% notes due 2024 and redeemed US$50 million principal amount of its 6.50% senior notes due 2021.

Covenants

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

	Covenant	As at September 30, 2019
Senior Facility
Consolidated senior debt to consolidated covenant EBITDA(1)	≤2.50	0.00
Consolidated covenant EBITDA to consolidated interest expense(1)	≥2.50	3.35
Senior Notes
Consolidated interest coverage ratio	≥2.00	3.30

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

At September 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.

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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.

Impact of foreign exchange rates

The devaluation of the Canadian dollar during 2019 resulted in higher translated U.S. denominated revenue and costs. On average for the three and nine months ended September 30, 2019, the Canadian dollar weakened by 1% and 3% from the respective 2018 periods. The following table summarizes the average and closing Canada-U.S. foreign exchanges rates:

	Three months ended September 30,		Nine months ended September 30,		December 31,
	2019	2018	2019	2018	2018
Canada-U.S. foreign exchange rates
Average	1.32	1.31	1.33	1.29	1.30
Closing	1.32	1.29	1.32	1.29	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).

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QUARTERLY FINANCIAL SUMMARY

(Stated in thousands of Canadian dollars, except per share amounts)	2018			2019
Quarters ended		December 31			March 31	June 30		September 30
Revenue		427,010			434,043	359,424		375,552
Adjusted EBITDA(1)		134,492			107,697	81,037		97,895
Net earnings (loss)		(198,328	)		25,014	(13,801	)	(3,534	)
Net earnings (loss) per basic share		(0.68	)		0.09	(0.05	)	(0.01	)
Net earnings (loss) per diluted share		(0.68	)		0.08	(0.05	)	(0.01	)
Funds provided by operations(1)		92,595			95,993	40,950		79,930
Cash provided by operations		93,489			40,587	106,035		66,556

(Stated in thousands of Canadian dollars, except per share amounts)	2017			2018
Quarters ended		December 31			March 31		June 30		September 30
Revenue		347,187			401,006		330,716		382,457
Adjusted EBITDA(1)		90,914			97,469		62,182		80,988
Net loss		(47,005	)		(18,077	)	(47,217	)	(30,648	)
Net loss per basic		(0.16	)		(0.06	)	(0.16	)	(0.10	)
Net loss per diluted share		(0.16	)		(0.06	)	(0.16	)	(0.10	)
Funds provided by operations(1)		28,323			104,026		50,225		64,368
Cash provided by operations		23,289			38,189		129,695		31,961

(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 Condensed Interim Consolidated Financial Statements that could materially affect the amounts recognized. Our judgments and estimates are based on our past experiences and assumptions we believe are reasonable in the circumstances. The critical judgments and estimates used in preparing the Condensed Interim Consolidated 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 nine months ended September 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 September 30, 2019 Condensed 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 nine months ended September 30, 2019, Precision recorded lease interest charges of $1 million and $3 million and depreciated its right of use assets by $2 million and $6 million, respectively. As a result of the new lease standard, our Adjusted EBITDA was positively impacted for the three and nine months ended September 30, 2019 by $3 million and $9 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 asset disposals and depreciation and amortization), as reported in the Condensed 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 (loss) is calculated as follows:

	Three months ended September 30,				Nine months ended September 30,
(Stated in thousands of Canadian dollars)	2019		2018		2019		2018
Revenue	375,552		382,457		1,169,019		1,114,179
Expenses:
Operating	256,593		271,596		797,250		782,042
General and administrative	21,064		29,873		78,432		90,334
Restructuring	—		—		6,438		1,164
Depreciation and amortization	82,604		91,348		252,684		270,098
Gain on asset disposals	(3,944	)	(658	)	(46,853	)	(3,479	)
Impairment reversal	—		—		(5,810	)	—
Operating earnings (loss)	19,235		(9,702	)	86,878		(25,980	)
Foreign exchange	1,470		(952	)	(4,416	)	819
Finance charges	28,490		31,176		90,178		94,958
Loss (gain) on repurchase of unsecured notes	(2,239	)	—		(3,637	)	1,176
Earnings (loss) before income taxes	(8,486	)	(39,926	)	4,753		(122,933	)

Funds Provided By (Used In) Operations

We believe that funds provided by (used in) operations, as reported in the Condensed 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 Condensed 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 and 2020;

· our capital expenditure plans for 2019 and 2020;

· 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   Q3 2019 TRADING PROFILE Toronto (TSX: PD) High: $2.51 Low: $1.36 Close: $1.52 Volume Traded: 107,249,319 New York (NYSE: PDS) High: US$2.08 Low: US$1.03 Close: US$1.14 Volume Traded: 65,596,700   ACCOUNT QUESTIONS Precision’s Transfer Agent can help you with a variety of shareholder related services, including:   •  change of address •  lost share certificates •  transfer of shares to another person •  estate settlement   Computershare Trust Company of Canada 100 University Avenue 9th Floor, North Tower Toronto, Ontario, Canada M5J 2Y1   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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