Exhibit 99.1

NEWS RELEASE

Calgary, Alberta, Canada – October 27, 2017

(Canadian dollars except as indicated)

PRECISION DRILLING CORPORATION

ANNOUNCES 2017 THIRD QUARTER FINANCIAL RESULTS

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

Precision Drilling announces 2017 third quarter financial results:

• Third quarter revenue of $315 million was an increase of 47% over the prior year comparative quarter.

• Third quarter earnings before income taxes, gain on repurchase of unsecured senior notes, finance charges, foreign exchange, and depreciation and amortization (adjusted EBITDA see “NON-GAAP MEASURES”) of $73 million was 77% higher than the third quarter of 2016.

• Third quarter net loss of $26 million ($0.09 per share) compared with a net loss of $47 million ($0.16 per share) in the third quarter of 2016.

• Third quarter capital expenditures were $23 million, with full year capital spending expected to be $104 million.

Kevin Neveu, Precision’s President and Chief Executive Officer, stated: “I am pleased with our reported third quarter results which include solid cash flow generation driving a $37 million increase in our quarter end cash balance, and the first sequential increase in both our U.S. fleet average day rates (excluding idle but contracted revenue) and margins since early in 2015. Despite commodity price volatility and lower than anticipated WTI and Canadian AECO prices during the third quarter, demand and pricing for Precision’s Super Series rigs remained firm through the quarter. We anticipate demand to further strengthen as our customers initiate their 2018 drilling programs.”

“As our customers across the U.S. and Canada have learned to operate in a “lower for longer” commodity price environment, they have focused on drilling and completion efficiency utilizing long or extended-reach horizontal wells and adopted large-scale industrialization techniques, such as multi-well pads and high efficiency rig systems. Precision’s Super Triple rigs are configured to optimize long reach drilling performance combined with pad walking capability, and are active in virtually every resource play in North America.”

“During the third quarter we continued to demonstrate the “next tier” of drilling efficiency improvement with Process Automation Control (PAC) and other technology initiatives we are implementing in our beta testing program. Precision has drilled approximately 70 wells utilizing PAC technology, which is currently installed on 20 Super Triple rigs, and the results continue to show improved efficiency, consistency and repeatability, exactly what our customers desire. Precision along with its partner have made significant strides towards making Precision’s PAC a commercial success in 2018 as outlined as one of our three key priorities for the year. We believe these initiatives will further strengthen the competitive positioning of Precision’s Super Triple fleet while driving additional revenue streams for each of our technology offerings.”

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“We are encouraged by the improvement in commodity fundamentals as the global oil supply and demand balance tightens and the WTI/Brent strip has returned to above US$50 per barrel. We believe these fundamentals form a constructive environment as our customers finalize 2018 drilling budgets, with customer bookings for additional rig deployments in late Q4 and Q1 2018 supporting this view.”

“In the U.S. we signed three term contracts in the third quarter and have signed an additional three contracts quarter to date. Volatile and lower than anticipated commodity prices caused industry rig activity to retract mid-Q3 with the trend continuing in recent weeks. Precision experienced a modest reduction in our active rig count with 55 rigs currently active, but overall demand for our Pad Walking Super Triple rigs has remained strong and we expect utilization in the high spec rig market to remain tight and pricing to remain firm. We expect our active rig count to return to 2017 peak levels later this year and into the first quarter of 2018 with the potential for additional utilization improvement as the year progresses should commodity prices hold in the low-to-mid $50’s.”

“Our third quarter activity in Canada was slightly lower than expected as a result of weather delays and a lack of urgency from our customers driven by soft commodity prices, particularly seasonally depressed AECO gas prices which resulted in lower cash flows for some of our customers. Precision’s rig count rose to 57 rigs in the third quarter, with the expectation that activity continues to trend higher as we ramp up into the 2018 winter drilling season. Canadian activity has trended upwards into Q4 hitting 62 rigs last week but has since pulled back to 57 rigs as weather slowed some rig moves. While customer budgets have yet to firm up, early indications point to Q1 peak demand mirroring 2017 levels with a potential for activity to exceed those levels should commodity prices remain firm.”

“Operational performance from our international business continues to be strong with zero recordable incidents in the quarter and a 30% year-over-year improvement in downtime. We expect robust cash flow from the division throughout the year with eight active rigs in the Middle East on contract and no rollovers in 2017. Additionally, we are actively bidding our four idle rigs to attractive opportunities in the region.”

“Precision, as published in 2017 objectives, manages its capital spending based on activity. As such we have reduced our 2017 capital spending program by $34 million to $104 million. The reduction relates primarily to upgrade and maintenance capital. We now plan to spend $39 million in upgrade capital which includes approximately 30 rig upgrades. Precision practices tight capital discipline and will continue to focus on debt reduction until customer demand translates to economics that warrant additional upgrade spending” concluded Mr. Neveu.

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SELECT Financial And Operating INFORMATION

Adjusted EBITDA and funds provided by operations are Non-GAAP measures. See “NON-GAAP MEASURES.”

Financial Highlights

	Three months ended September 30,									Nine months ended September 30,
(Stated in thousands of Canadian dollars, except per share amounts)	2017			2016			% Change			2017			2016			% Change
Revenue(1)		314,504			213,668			47.2			974,037			700,580			39.0
Adjusted EBITDA(2)		73,239			41,411			76.9			214,067			163,075			31.3
Adjusted EBITDA(2) % of revenue		23.3	%		19.4	%					22.0			23.3	%
Net loss		(26,287	)		(47,377	)		(44.5	)		(85,031	)		(124,937	)		(31.9	)
Cash provided by operations		56,757			17,515			224.0			93,266			150,354			(38.0	)
Funds provided by operations		85,140			31,688			168.7			155,612			93,909			65.7
Capital spending:
Expansion		2,336			67,672			(96.5	)		10,980			133,605			(91.8	)
Upgrade		7,168			4,902			46.2			34,102			6,335			438.3
Maintenance and infrastructure		13,014			5,588			132.9			27,965			18,807			48.7
Proceeds on sale		(4,273	)		(2,125	)		101.1			(10,054	)		(5,830	)		72.5
Net capital spending		18,245			76,037			(76.0	)		62,993			152,917			(58.8	)
Loss per share:
Basic and diluted		(0.09	)		(0.16	)		(43.8	)		(0.29	)		(0.43	)		(32.6	)

(1) Prior year comparatives have changed to conform to current year presentation. For detail see “RECAST OF COMPARATIVE FINANCIAL INFORMATION.”

(2) See “NON-GAAP MEASURES.”

Operating Highlights

	Three months ended September 30,							Nine months ended September 30,
	2017		2016		% Change			2017		2016		% Change
Contract drilling rig fleet		256		253		1.2			256		253		1.2
Drilling rig utilization days:
Canada		4,487		2,853		57.3			13,945		8,050		73.2
U.S.		5,593		2,689		108.0			15,114		7,773		94.4
International		736		644		14.3			2,184		2,044		6.8
Revenue per utilization day:
Canada (1)(2) (Cdn$)		19,980		21,046		(5.1	)		21,092		25,214		(16.3	)
U.S.(1)(3) (US$)		19,026		24,343		(21.8	)		19,732		28,374		(30.5	)
International (US$)		50,528		43,879		15.2			50,214		43,191		16.3
Operating cost per utilization day:
Canada(1) (Cdn$)		13,656		14,107		(3.2	)		13,764		14,815		(7.1	)
U.S. (1)  (US$)		12,591		15,456		(18.5	)		13,917		16,097		(13.5	)
Service rig fleet		210		163		28.8			210		163		28.8
Service rig operating hours		42,653		26,588		60.4			128,523		66,281		93.9
Revenue per operating hour (Cdn$)		638		599		6.5			635		654		(2.9	)

(1) Prior year comparatives have changed to conform to current year presentation. For detail see “RECAST OF COMPARATIVE FINANCIAL INFORMATION.”

(2) Includes lump sum revenue from contract shortfall.

(3) Comparatives and nine month period ended September 30, 2017 includes revenue from idle but contracted rig days.

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Financial Position

(Stated in thousands of Canadian dollars, except ratios)	September 30, 2017		December 31, 2016
Working capital		266,159		230,874
Cash		131,742		115,705
Long-term debt(1)		1,777,667		1,906,934
Total long-term financial liabilities		1,801,212		1,946,742
Total assets		3,967,987		4,324,214
Long-term debt to long-term debt plus equity ratio(1)		0.49		0.49

(1) Net of unamortized debt issue costs.

RECAST OF COMPARATIVE FINANCIAL INFORMATION

During the third quarter of 2017, we changed our treatment of how certain amounts that were historically netted against operating expense should be classified. In particular, certain amounts that were historically netted against operating expenses are now treated as revenue, with a corresponding increase to operating expenses. The primary nature of these amounts related to additional labour above our standard drilling crew configuration, subsistence allowances paid to the drilling crew which varies depending on whether the crews were staying in a camp or hotel and equipment rental. As a result, previously reported revenues and operating expenses were understated by equivalent amounts.

To conform to current year presentation, certain immaterial reclassifications between operating and general administrative expenses have also been made in the comparative periods.

As a result of these reclassifications, we have recast prior year’s comparative amounts as follows:

Three months ended September 30, 2016 (Stated in thousands of Canadian dollars except per day amounts)	As previously reported		Revenue recast		Expense recast			As recast
Revenue		201,802		11,866		-			213,668
Expenses:
Operating		137,935		11,866		576			150,377
General and administrative		21,748		-		(576	)		21,172
Restructuring		708		-		-			708
Adjusted EBITDA(1)		41,411		-		-			41,411
(1) See “NON-GAAP MEASURES.”
Revenue per utilization day:
Canada (Cdn$)		17,523		3,523		-			21,046
U.S. (US$)		23,826		517		-			24,343
International (US$)		43,879		-		-			43,879
Operating cost per utilization day:
Canada (Cdn$)		10,584		3,523		-			14,107
U.S. (US$)		14,939		517		-			15,456

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Nine months ended September 30, 2016 (Stated in thousands of Canadian dollars except per day amounts)	As previously reported		Revenue recast		Expense recast			As recast
Revenue		667,508		33,072		-			700,580
Expenses:
Operating		419,914		33,072		2,146			455,132
General and administrative		78,765		-		(2,146	)		76,619
Restructuring		5,754		-		-			5,754
Adjusted EBITDA(1)		163,075		-		-			163,075
(1) See “NON-GAAP MEASURES.”
Revenue per utilization day:
Canada (Cdn$)		21,792		3,422		-			25,214
U.S. (US$)		27,842		532		-			28,374
International (US$)		43,191		-		-			43,191
Operating cost per utilization day:
Canada (Cdn$)		11,393		3,422		-			14,815
U.S. (US$)		15,565		532		-			16,097

The tables below reflect our recast of day rates and operating costs per day for each of the previous six quarters:

As recast	2016								2017
Quarters ended	March 31		June 30		September 30		December 31		March 31		June 30		September 30
Revenue per utilization day:
Canada (Cdn$)		26,966		29,283		21,046		23,298		21,405		22,177		19,980
U.S. (US$)		32,442		27,962		24,343		21,293		20,554		19,826		19,026
International (US$)		41,609		44,391		43,879		52,816		50,434		49,679		50,528
Operating cost per utilization day:
Canada (Cdn$)		13,985		19,257		14,107		13,298		12,828		16,368		13,656
U.S. (US$)		17,268		15,342		15,456		14,350		15,264		14,248		12,591

There is no impact on net loss or comprehensive loss and the consolidated statement of financial position, consolidated statement of changes in equity and the consolidated statement of cash flows remain unchanged as a result of this recast.

Summary for the three months ended September 30, 2017

•     Revenue this quarter was $315 million which is 47% higher than the third quarter of 2016. The increase in revenue was primarily the result of higher activity in all of our North American based businesses and higher average day rates from our international contract drilling business, partially offset by lower contract short-fall payments, a decrease in average day rate in all of our North American contract drilling businesses and no utilization in our Mexico based contract drilling business. Compared with the third quarter of 2016 our activity, as measured by drilling rig utilization days, increased 57% in Canada, 108% in the U.S. and 14% internationally. Revenue from our Contract Drilling Services and Completion and Production Services segments both increased over the comparative prior year period by 46% and 57%, respectively.

•     Adjusted EBITDA this quarter was $73 million, an increase of $32 million from the third quarter of 2016. Our adjusted EBITDA as a percentage of revenue was 23% this quarter, compared with 19% in the third quarter of 2016. The increase in adjusted EBITDA as a percent of revenue was mainly due to fixed costs spread over higher activity in our North American business partially offset by lower average pricing.

•     Operating loss (see “NON-GAAP MEASURES”) this quarter was $17 million compared with an operating loss of $56 million in the third quarter of 2016. Operating results this quarter were positively impacted by increased activity in our North American businesses, partially offset by lower average pricing.

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•     General and administrative expenses this quarter were $22 million, $1 million higher than the third quarter of 2016. The increase is due to higher share based compensation expense that is tied to our common shares, partially offset by a moderate strengthening of the Canadian dollar on our U.S. dollar denominated costs. As at September 30, 2017 we have a total share based incentive compensation liability of $24 million compared with $23 million at June 30, 2017 after having paid out $0.2 million in the quarter.

•     Net finance charges were $32 million, a decrease of $2 million compared with the third quarter of 2016 primarily due to the effect of a stronger Canadian dollar on our U.S. dollar denominated interest expense and a reduction in interest expense related to debt retired in 2016.

•     In Canada, average revenue per utilization day for contract drilling rigs decreased in the third quarter of 2017 to $19,980 from $21,046 in the prior year third quarter as a result of fewer rigs working under legacy contracts and a higher proportion of revenue from shallower drilling activity, partially offset by higher contract shortfall payments relative to the 2016 comparative period. During the quarter, we recognized $5 million in revenue associated with contract shortfall payments in Canada which was an increase of $3 million from the prior year period. On a sequential basis, revenue per utilization day in Canada decreased by $2,197 as a result of rig mix, lower shortfall payments and lower boiler revenue when compared to the second quarter of 2017. In the U.S. revenue per utilization day decreased to US$19,026 from US$24,343 over the same period. The decrease in the U.S. revenue rate was the result of long-term contracts ending and rigs contracting at lower spot market rates, lower revenue from idle but contracted rigs and no turnkey activity in the current quarter. During the quarter we had no turnkey revenue compared with US$3 million in the 2016 comparative period and had no revenue from idle but contracted rigs in the current quarter versus US$6 million in the comparative period. On a sequential basis, revenue per utilization day excluding revenue from idle but contracted rigs increased by US$287 as higher fleet average day rates was partially offset by lower turnkey revenue when compared to the second quarter of 2017.

•     Average operating costs per utilization day for drilling rigs in Canada decreased to $13,656 compared with the prior year third quarter of $14,107. The decrease in average costs was due to improved absorption of fixed costs with higher utilization. In the U.S., operating costs for the quarter on a per day basis decreased to US$12,591 in 2017 compared with US$15,456 in 2016 due to fixed costs spread over higher utilization, no regional repositioning of rigs and no turnkey work in the quarter.

•     Average operating margin per utilization day excluding revenue from idle but contracted rigs in the third quarter of 2017 increased by $515 in Canada and increased by US$1,252 in the U.S. when compared to the second quarter of 2017. In Canada, the increase was a result of higher fixed cost absorption more than offsetting a reduction in revenue per utilization day. In the U.S., the sequential increase was primarily a result of higher fleet average day rates.

•     We realized revenue from international contract drilling of US$37 million in the third quarter of 2017, a US$9 million increase over the prior year period. The increase was due to the startup of two new rigs in Kuwait in the fourth quarter of 2016, partially offset by a reduction in activity in our Mexico operations. Average revenue per utilization day in our international contract drilling business was US$50,528 an increase of 15% over the comparable prior year quarter primarily due to rig mix as we had fewer rigs working in the lower day rate jurisdictions.

•     Directional drilling services realized revenue of $6 million in the third quarter of 2017 in line with the prior year period.

•     Funds provided by operations in the third quarter of 2017 were $85 million, an increase of $53 million from the prior year comparative quarter and an increase of $100 million from the second quarter of 2017. The increases were primarily the result of improved operating results.

•     Capital expenditures for the purchase of property, plant and equipment were $23 million in the third quarter, a decrease of $56 million over the same period in 2016. Capital spending for the quarter included $2 million for expansion capital, $7 million for upgrade capital and $13 million for the maintenance of existing assets and infrastructure.

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Summary for the nine months ended September 30, 2017:

•     Revenue for the nine months of 2017 was $974 million, an increase of 39% from the 2016 period.

•     Operating loss was $69 million, a decrease of $56 million over the same period in 2016. Operating loss was 7% of revenue in 2017 compared to 18% of revenue in 2016. Operating results this year were positively impacted by increased activity in our North American businesses partially offset by lower average pricing.

•     General and administrative costs were $68 million, a decrease of $9 million over the first nine months of 2016. The decrease was due to fixed cost reductions implemented through the downturn and lower share based incentive compensation that is tied to the price of our common shares.

•     Net finance charges were $100 million, a decrease of $4 million from the first nine months of 2016 primarily due to a reduction in interest expense related to debt retired in 2016 and the effect of a stronger Canadian dollar on our U.S. dollar denominated interest expense partially offset by higher interest income earned in the comparative period.

•     Funds provided by operations (see “NON-GAAP MEASURES”) in the first nine months of 2017 were $156 million, an increase of $62 million from the prior year comparative period of $94 million.

•     Capital expenditures for the purchase of property, plant and equipment were $73 million in the first nine months of 2017, a decrease of $86 million over the same period in 2016. Capital spending for 2017 to date included $11 million for expansion capital, $34 million for upgrade capital and $28 million for the maintenance of existing assets and infrastructure.

STRATEGY

Precision’s strategic priorities for 2017 are as follows:

1. Deliver High Performance, High Value service offering in an improving demand environment while demonstrating fixed cost leverage – In the U.S., we grew our active rig count by 58% throughout the nine months of 2017. In Canada, we began the year with 50 active rigs and reached a seasonal peak of 91 rigs. Year-over-year in the first nine months of 2017 our utilization days were up 84% across our North American drilling operations and was achieved without any material increase in fixed costs. In addition, we are upgrading our existing ERP system to increase operating efficiencies, improve our fixed cost leverage and position the organization to better handle the increased data flows associated with our business.

2. Commercialize rig automation and efficiency-driven technologies across our Super Series fleet – Beta-style field trials utilizing rig automation technologies, including Process Automation Control (PAC), Directional Guidance System and High Speed Downhole Data are ongoing and we expect to progress the commercialization of these automation features during 2017. We have drilled approximately 70 wells utilizing PAC technology which is installed on 20 Super Triple Rigs.

3. Maintain strict financial discipline in pursuing growth opportunities with a focus on free cash flow and debt reduction – Effectively all upgrade capital spending is supported by take-or-pay term contracts priced at a level that allows for attractive rates of return. Precision reduced 2017 capital expenditures by approximately $34 million with the reduction relating primarily to upgrade and maintenance capital. Our revised 2017 capital plan brings spending in line with expected activity levels while continuing to focus on free cash flow to drive debt reduction. In the first nine months of 2017, we generated funds from operations of $156 million – see “NON-GAAP MEASURES.”

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OUTLOOK

For the third quarter of 2017, the average West Texas Intermediate price of oil was 7% higher than the prior year comparative period while the average Henry Hub natural gas price was 3% higher. The average AECO price was 29% lower than the prior year comparative period as a result of infrastructure constraints due to planned maintenance and high storage levels.

	Three months ended September 30,				Year ended December 31,
	2017		2016		2016
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)		48.03		44.97		43.30
Natural gas
Canada
AECO (per MMBtu) (CDN$)		1.66		2.34		2.14
United States
Henry Hub (per MMBtu) (US$)		2.93		2.85		2.48

Contracts

The following chart outlines the average number of drilling rigs that we have under contract as of October 26, 2017 for the remaining quarters of 2017 and the full years 2017 and 2018.

	Average for the quarter ended								Average for the year ended
	March 31		June 30		September 30		December 31		2017		2018
Average rigs under term contract as at October 26, 2017:
Canada		27		23		19		12		20		7
U.S.		26		33		31		28		29		12
International		8		8		8		8		8		7
Total		61		64		58		48		57		26

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. Year to date as of October 26, 2017 we have added 22 term contracts with durations of six months or longer.

Drilling Activity

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

	2016				2017
Quarter ended	September 30		December 31		March 31		June 30		September 30
Average Precision active rig count:
Canada		31		51		76		29		49
U.S.		29		39		47		59		61
International		7		8		8		8		8
Total		67		98		131		96		118

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With improved commodity prices and increasing activity levels, earlier this year we were able to increase prices on spot market rigs across the majority of our fleet. Should commodity prices continue to improve, we expect sequential improvements in pricing in the U.S. and the Deep Basin in Canada. We expect pricing improvements in the shallower parts of the Canadian market; however, the increases are not expected to be of the same magnitude as other North American markets in which we operate.

Industry Conditions

In 2017, drilling activity has increased relative to this time last year for both Canada and the U.S. According to industry sources, as of October 20, 2017, the U.S. active land drilling rig count was up approximately 68% from the same point last year and the Canadian active land drilling rig count was up approximately 41%.

In Canada there has been a strengthening in natural gas and gas liquids drilling activity related to the Deep Basin in northwestern Alberta and northeastern British Columbia although recent weakness in AECO pricing has caused some producers to delay work programs specifically related to dry gas. In the U.S., the trend towards oil-directed drilling continues. To date in 2017, approximately 53% of the Canadian industry’s active rigs and 80% of the U.S. industry’s active rigs were drilling for oil targets, compared with 48% for Canada and 80% for the U.S. at the same time last year.

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 the importance of the rig delivering these complex wells consistently and efficiently has been well established by the industry.  We expect that demand for leading edge high efficiency Tier 1 rigs will continue to strengthen, as the 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 the rigs will continue this technical evolution while creating further cost efficiencies and performance value for customers and further differentiating the specific capabilities of the leading edge Tier 1 rigs and those rig contractors capable of widely deploying those technologies.  

Capital Spending

Capital spending in 2017 is expected to be $104 million:

• The 2017 capital expenditure plan includes $13 million for expansion capital, $52 million for sustaining and infrastructure expenditures, and $39 million to upgrade existing rigs. We expect that the $104 million will be split $99 million in the Contract Drilling Services segment and $5 million in the Completion and Production Services segment.

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Segmented Financial Results

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

	Three months ended September 30,								Nine months ended September 30,
(Stated in thousands of Canadian dollars)	2017			2016			% Change		2017			2016			% Change
Revenue:
Contract Drilling Services(1)		278,569			190,329			46.4		864,957			634,152			36.4
Completion and Production Services		37,816			24,158			56.5		113,546			69,343			63.7
Inter-segment eliminations		(1,881	)		(819	)		129.7		(4,466	)		(2,915	)		53.2
		314,504			213,668			47.2		974,037			700,580			39.0
Adjusted EBITDA:(2)
Contract Drilling Services		81,994			52,180			57.1		242,690			210,300			15.4
Completion and Production Services		4,251			736			477.6		9,174			(4,039	)		(327.1	)
Corporate and other		(13,006	)		(11,505	)		13.0		(37,797	)		(43,186	)		(12.5	)
		73,239			41,411			76.9		214,067			163,075			31.3

(1) Prior year comparatives have changed to conform to current year presentation. For detail see “RECAST OF COMPARATIVE FINANCIAL INFORMATION.”

(2) 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)	2017			2016			% Change			2017			2016			% Change
Revenue(1)		278,569			190,329			46.4			864,957			634,152			36.4
Expenses:
Operating(1)		189,143			129,457			46.1			598,040			393,979			51.8
General and administrative(1)		7,432			8,069			(7.9	)		24,227			26,833			(9.7	)
Restructuring		-			623			(100.0	)		-			3,040			(100.0	)
Adjusted EBITDA(2)		81,994			52,180			57.1			242,690			210,300			15.4
Depreciation		80,653			86,643			(6.9	)		251,907			257,334			(2.1	)
Operating earnings (loss)(2)		1,341			(34,463	)		(103.9	)		(9,217	)		(47,034	)		(80.4	)
Operating earnings (loss) as a percentage of revenue		0.5	%		(18.1	%)					(1.1	%)		(7.4	%)

(1) Prior year comparatives have changed to conform to current year presentation. For detail see “RECAST OF COMPARATIVE FINANCIAL INFORMATION.”

(2) See “NON-GAAP MEASURES”.

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	Three months ended September 30,
Canadian onshore drilling statistics:(1)	2017						2016
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		136			634			135			672
Drilling rig operating days (spud to release)		3,998			16,288			2,538			10,401
Drilling rig operating day utilization		32	%		28	%		20	%		17	%
Number of wells drilled		451			1,977			269			1,115
Average days per well		8.9			8.2			9.4			9.3
Number of metres drilled (000s)		1,123			5,179			627			2,568
Average metres per well		2,490			2,620			2,330			2,303
Average metres per day		281			318			247			247

	Nine months ended September 30,
Canadian onshore drilling statistics:(1)	2017						2016
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		136			634			135			672
Drilling rig operating days (spud to release)		12,398			49,889			7,183			27,833
Drilling rig operating day utilization		34	%		29	%		19	%		15	%
Number of wells drilled		1,282			5,285			607			2,490
Average days per well		9.7			9.4			11.8			11.2
Number of metres drilled (000s)		3,352			14,267			1,616			6,328
Average metres per well		2,615			2,700			2,663			2,542
Average metres per day		270			286			225			227

(1) Canadian operations only.

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

United States onshore drilling statistics:(1)	2017				2016
	Precision		Industry(2)		Precision		Industry(2)
Average number of active land rigs for quarters ended:
March 31		47		722		32		516
June 30		59		874		24		397
September 30		61		927		29		465
Year to date average		55		841		28		459

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $279 million this quarter, or 46% higher than the third quarter of 2016, while adjusted EBITDA increased by 57% to $82 million. The increase in revenue was primarily due to higher utilization days in Canada and the U.S. and higher average day rates for international contracts. During the quarter we recognized $5 million in shortfall payments in our Canadian contract drilling business, which was $3 million higher than in the prior year. During the quarter in the U.S. we did not recognize any idle but contracted or turnkey revenue compared with US$6 million and US$3 million, respectively, in the comparative quarter of 2016.

Drilling rig utilization days in Canada (drilling days plus move days) were 4,487 during the third quarter of 2017, an increase of 57% compared to 2016 primarily due to the increase in industry activity resulting from higher oil prices. Drilling rig utilization days in the U.S. were 5,593, or 108% higher than the same quarter of 2016 as U.S. activity was up with higher industry activity. Drilling rig utilization days in our international business were 736 or 14% higher than the same quarter of 2016 due to the addition of two rigs in Kuwait during the fourth quarter of 2016, partially offset by no activity in Mexico.

11

Compared with the same quarter in 2016, drilling rig revenue per utilization day was down 5% in Canada due to fewer legacy contracts. Drilling rig revenue per utilization day for the quarter in the U.S. was down 22% from the prior comparative period, while international revenue per utilization day was up 15%. The decrease in the U.S. average rate was due to long-term contracts ending and rigs being re-contracted at lower spot market rates, no idle but contracted revenue and no turnkey activity in the current quarter. International revenue per utilization day was up due to rig mix with a higher proportion of days from Kuwait during the quarter and no activity in Mexico.

In Canada, 18% of our utilization days in the quarter were generated from rigs under term contract, compared with 33% in the third quarter of 2016. In the U.S., 55% of utilization days were generated from rigs under term contract as compared with 53% in the third quarter of 2016.

Operating costs were 68% of revenue for the quarter which was in line with the prior year period. On a per utilization day basis, operating costs for the drilling rig division in Canada were lower than the prior year period primarily because of improved absorption of fixed costs with higher utilization. In the U.S., operating costs for the quarter on a per day basis were lower than the prior year period primarily due to no turnkey activity in the current year quarter and the impact of fixed costs spread over higher activity. Both Canada and U.S. operating costs benefited from cost saving initiatives taken in 2015 and 2016.

Depreciation expense in the quarter was 7% lower than in the third quarter of 2016.

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)	2017			2016			% Change			2017			2016			% Change
Revenue		37,816			24,158			56.5			113,546			69,343			63.7
Expenses:
Operating(1)		31,674			21,739			45.7			98,773			64,068			54.2
General and administrative(1)		1,891			1,629			16.1			5,599			7,293			(23.2	)
Restructuring		-			54			(100.0	)		-			2,021			(100.0	)
Adjusted EBITDA(2)		4,251			736			477.6			9,174			(4,039	)		(327.1	)
Depreciation		6,731			6,759			(0.4	)		21,228			20,537			3.4
Operating loss(2)		(2,480	)		(6,023	)		(58.8	)		(12,054	)		(24,576	)		(51.0	)
Operating loss as a percentage of revenue		(6.6	%)		(24.9	%)					(10.6	%)		(35.4	%)
Well servicing statistics:
Number of service rigs (end of period)		210			163			28.8			210			163			28.8
Service rig operating hours		42,653			26,588			60.4			128,523			66,281			93.9
Service rig operating hour utilization		22	%		18	%					22	%		15	%
Service rig revenue per operating hour		638			599			6.5			635			654			(2.9	)

(1) Certain expenses in the prior year comparative have been reclassified to conform to current year presentation.

(2) See “NON-GAAP MEASURES”.

Revenue from Completion and Production Services was up $14 million or 57% compared with the third quarter of 2016 due to higher activity levels in all service lines. As oil prices have recovered, customers have increased spending and activity in well completion and production programs. Our well servicing activity in the quarter was up 60% from the third quarter of 2016 as a result of improved industry activity levels and a larger fleet following the acquisition of service rigs late in the fourth quarter of 2016. Approximately 97% of our third quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 90% of its revenue from Canadian operations and 10% from U.S. operations which is in line with the third quarter of 2016.

Average service rig revenue per operating hour in the quarter was $638 or $39 higher than the third quarter of 2016. The increase was primarily the result of increased labour costs which are passed through to the customer.

12

Adjusted EBITDA was $4 million higher than the third quarter of 2016 due to increased activity in all divisions.

Operating costs as a percentage of revenue decreased to 84% in the third quarter of 2017, from 90% in the third quarter of 2016. The decrease is the result of the impact of fixed costs spread across greater activity combined with our reduced cost structure.

Depreciation in the quarter was $7 million in line with the previous year comparative period. The added depreciation costs in the quarter associated with additional well service units was offset by assets becoming fully depreciated.

Segment Review of Corporate and Other

Our Corporate and Other segment provides support functions to our operating segments. The Corporate and Other segment had an adjusted EBITDA loss of $13 million an increase of $2 million compared with the third quarter of 2016 primarily due to higher share based incentive compensation.

Other items

Net financial charges for the quarter were $32 million, a decrease of $2 million compared with the third quarter of 2016 primarily due to the effect of a stronger Canadian dollar on our U.S. dollar denominated interest expense and a reduction in interest expense related to debt retired in 2016. For the current quarter we incurred a foreign exchange gain of $1 million in line with the third quarter of 2016.

Income tax expense for the quarter was a recovery of $23 million compared with a recovery of $36 million in the same quarter in 2016. The recoveries are due to negative pretax earnings.

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 apply a disciplined approach to managing and tracking results of our operations to keep costs down. We maintain a variable 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 divisions. Term contracts on expansion capital for new-build rig programs provide more certainty of future revenues and return on our capital investments.

13

Liquidity

Amount	Availability	Used for	Maturity
Senior facility (secured)
US$525 million (extendible, revolving term credit facility with US$250 million(1) accordion feature)	Undrawn, except US$25 million in outstanding letters of credit	General corporate purposes	June 3, 2019
Operating facilities (secured)
$40 million	Undrawn, except $21 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$4 million in outstanding letters of credit	Letters of credit
Senior notes (unsecured)
US$372 million – 6.625%	Fully drawn	Debt repayment and general corporate purposes	November 15, 2020
US$319 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$400 million – 5.25%	Fully drawn	Capital expenditures and general corporate purposes	November 15, 2024

(1) Increases to US$275 million at the end of the covenant relief period of March 31, 2018.

In January, 2017 we agreed with our lending group to the following amendments to our senior credit facility:

• Reduce the consolidated Adjusted EBITDA (as defined in the debt agreement) to consolidated interest expense ratio to greater than 1.25:1 for the periods ending March 31, June 30 and September 30, 2017. For the periods ending December 31, 2017 and March 31, 2018 the ratio is 1.5:1 reverting to 2.5:1 thereafter.

• Reduce the size of the facility to US$525 million and suspended the increase in the accordion feature from US$250 million to US$275 million until the end of covenant relief period.

As at September 30, 2017 we had $1,802 million outstanding under our senior unsecured notes. The current blended cash interest cost of our debt is approximately 6.5%.

Covenants

Senior Facility

The senior credit facility requires that we comply with certain covenants including a leverage ratio of consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (Adjusted EBITDA) of less than 2.5:1. For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness. Adjusted EBITDA, as defined in our revolving term facility agreement differs from Adjusted EBITDA as defined under Non-GAAP Measures by the exclusion of bad debt expense, restructuring costs and certain foreign exchange amounts. As at September 30, 2017 our consolidated senior debt to Adjusted EBITDA ratio was negative 0.14:1.

Effective January 20, 2017, under the senior credit facility, we are required to maintain a ratio of consolidated Adjusted EBITDA to consolidated interest expense for the most recent four consecutive quarters, of greater than 1.25:1 for the periods ending March 31, June 30 and September 30, 2017. For the periods ending December 31, 2017 and March 31, 2018 the ratio is 1.5:1 reverting to 2.5:1 thereafter. As at September 30, 2017 our senior credit facility consolidated Adjusted EBITDA to consolidated interest expense ratio was 2.04:1.

The senior credit facility also prevents us from making distributions prior to April 1, 2018 and restricts our ability to repurchase our unsecured senior notes subject to a pro forma liquidity test of US$500 million.

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In addition, 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.

At September 30, 2017, we were in compliance with the covenants of the senior credit facility.

Senior Notes

The senior notes require that we comply with financial covenants including an incurrence based consolidated interest coverage ratio test of consolidated cashflow, 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 that 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. As at September 30, 2017, our senior notes consolidated interest coverage ratio was 1.89:1 which limits our ability to incur additional indebtedness, except as permitted under the agreements, until such time as we are in compliance with the ratio test, but would not restrict our access to available funds under the senior credit facility or to refinance our existing debt. Furthermore, it does not give rise to any cross-covenant violations, give the lenders the right to demand repayment of any outstanding portion of the senior notes prior to the stated maturity dates, or provide any other forms of recourse to the lenders.

The senior notes contain a restricted payments covenant that limits our ability to make payments in the nature of dividends, distributions and repurchases from shareholders. This restricted payment basket grows from a starting point of October 1, 2010 for the 2020, 2021 and 2024 Senior Notes and from October 1, 2016 for the 2023 Senior Notes by, among other things, 50% of cumulative net earnings and decreases by 100% of 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 and as of that date we were no longer able to declare and make dividend payments until such time as the restricted payments baskets once again become positive. For further information, please see the senior note indentures which are available on SEDAR and EDGAR.

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.

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).

Average shares outstanding

The following table reconciles the weighted average shares outstanding used in computing basic and diluted net loss per share:

	Three months ended September 30,				Nine months ended September 30,
(Stated in thousands)	2017		2016		2017		2016
Weighted average shares outstanding – basic		293,239		293,238		293,239		293,098
Effect of stock options and other equity compensation plans		-		-		-		-
Weighted average shares outstanding – diluted		293,239		293,238		293,239		293,098

15

Quarterly Financial Summary

(Stated in thousands of Canadian dollars, except per share amounts)

	2016			2017
Quarters ended	December 31			March 31			June 30			September 30
Revenue(1)		302,653			368,673			290,860			314,504
Adjusted EBITDA(2)		65,000			84,308			56,520			73,239
Net loss:		(30,618	)		(22,614	)		(36,130	)		(26,287	)
Per basic and diluted share		(0.10	)		(0.08	)		(0.12	)		(0.09	)
Funds provided by (used in) operations(2)		11,466			85,659			(15,187	)		85,140
Cash provided by (used in) operations		(27,846	)		33,770			2,739			56,757

(Stated in thousands of Canadian dollars, except per share amounts)

	2015			2016
Quarters ended	December 31			March 31			June 30			September 30
Revenue(1)		362,117			316,505			170,407			213,668
Adjusted EBITDA(2)		111,095			99,264			22,400			41,411
Net loss:		(270,952	)		(19,883	)		(57,677	)		(47,377	)
Per basic and diluted share		(0.93	)		(0.07	)		(0.20	)		(0.16	)
Funds provided by (used in) operations(2)		49,503			93,593			(31,372	)		31,688
Cash provided by operations		70,952			112,174			20,665			17,515
Dividends paid per share		0.07			-			-			-

(1) Prior year comparatives have changed to conform to current year presentation. For detail see “RECAST OF COMPARATIVE FINANCIAL INFORMATION.”

(2) See “NON-GAAP MEASURES”.

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 2016 Annual Report and there have been no material changes to our critical accounting judgments and estimates during the three and nine month periods ended September 30, 2017.

NON-GAAP MEASURES

In this press release we reference non-GAAP (Generally Accepted Accounting Principles) measures. Adjusted EBITDA, Operating Earnings (Loss) and Funds Provided by (Used In) Operations 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, gain on repurchase of unsecured senior notes, financing charges, foreign exchange and depreciation and amortization), as reported in the Interim Consolidated Statement of 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.

Operating Earnings (Loss)

We believe that operating earnings (loss), as reported in the Interim Consolidated Statements of 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.

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.

16

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 2017;

• our capital expenditure plans for 2017 and our scheduled ERP upgrade;

• anticipated activity levels in 2017;

• anticipated demand for Tier 1 rigs; and

• the average number of term contracts in place for 2017 and 2018.

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, 2016, 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 news release are made as of the date hereof and Precision undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a results of new information, future events or otherwise, except as required by law.

17

Interim Consolidated Statements of financial position (UNAUDITED)

(Stated in thousands of Canadian dollars)	September 30, 2017			December 31, 2016
Assets
Current assets:
Cash	$	131,742		$	115,705
Accounts receivable		298,016			293,682
Income tax recoverable		29,913			38,087
Inventory		25,282			24,136
Total current assets		484,953			471,610
Non-current assets:
Property, plant and equipment		3,275,629			3,641,889
Intangibles		2,403			3,316
Goodwill		205,002			207,399
Total non-current assets		3,483,034			3,852,604
Total assets	$	3,967,987		$	4,324,214
liabilities and equity
Current liabilities:
Accounts payable and accrued liabilities	$	218,794		$	240,736
Total current liabilities		218,794			240,736
Non-current liabilities:
Share based compensation		12,213			27,387
Provisions and other		11,332			12,421
Long-term debt		1,777,667			1,906,934
Deferred tax liabilities		90,599			174,618
Total non-current liabilities		1,891,811			2,121,360
Shareholders’ equity:
Shareholders’ capital		2,319,293			2,319,293
Contributed surplus		42,841			38,937
Deficit		(637,599	)		(552,568	)
Accumulated other comprehensive income		132,847			156,456
Total shareholders’ equity		1,857,382			1,962,118
Total liabilities and shareholders’ equity	$	3,967,987		$	4,324,214

18

Interim Consolidated Statements OF Loss (UNAUDITED)

	Three months ended September 30,						Nine months ended September 30,
(Stated in thousands of Canadian dollars, except per share amounts)	2017			2016			2017			2016
				(recast)						(recast)
Revenue	$	314,504		$	213,668		$	974,037		$	700,580
Expenses:
Operating		218,936			150,377			692,347			455,132
General and administrative		22,329			21,172			67,623			76,619
Restructuring		–			708			–			5,754
Earnings before income taxes, gain on repurchase of unsecured senior notes, finance charges, foreign exchange and depreciation and amortization		73,239			41,411			214,067			163,075
Depreciation and amortization		90,555			96,998			283,517			288,858
Operating loss		(17,316	)		(55,587	)		(69,450	)		(125,783	)
Foreign exchange		(685	)		(1,402	)		(1,436	)		6,933
Finance charges		32,218			34,673			99,732			104,071
Gain on repurchase of unsecured senior notes		–			(5,108	)		–			(9,981	)
Loss before income taxes		(48,849	)		(83,750	)		(167,746	)		(226,806	)
Income taxes:
Current		89			(9,999	)		339			(24,358	)
Deferred		(22,651	)		(26,374	)		(83,054	)		(77,511	)
		(22,562	)		(36,373	)		(82,715	)		(101,869	)
Net loss	$	(26,287	)	$	(47,377	)	$	(85,031	)	$	(124,937	)
Net loss per share:
Basic	$	(0.09	)	$	(0.16	)	$	(0.29	)	$	(0.43	)
Diluted	$	(0.09	)	$	(0.16	)	$	(0.29	)	$	(0.43	)

Interim Consolidated Statements of Comprehensive Loss (UNAUDITED)

	Three months ended September 30,						Nine months ended September 30,
(Stated in thousands of Canadian dollars)	2017			2016			2017			2016
Net loss	$	(26,287	)	$	(47,377	)	$	(85,031	)	$	(124,937	)
Unrealized gain (loss) on translation of assets and liabilities of operations denominated in foreign currency		(79,729	)		17,895			(155,691	)		(130,096	)
Foreign exchange gain (loss) on net investment hedge with U.S. denominated debt, net of tax		68,057			(15,467	)		132,082			104,533
Comprehensive loss	$	(37,959	)	$	(44,949	)	$	(108,640	)	$	(150,500	)

19

Interim Consolidated Statements of Cash Flow (UNAUDITED)

	Three months ended September 30,						Nine months ended September 30,
(Stated in thousands of Canadian dollars)	2017			2016			2017			2016
Cash provided by (used in):
Operations:
Net loss	$	(26,287	)	$	(47,377	)	$	(85,031	)	$	(124,937	)
Adjustments for:
Long-term compensation plans		1,945			983			4,276			16,072
Depreciation and amortization		90,555			96,998			283,517			288,858
Gain on repurchase of unsecured senior notes		–			(5,108	)		–			(9,981	)
Foreign exchange		(239	)		(2,563	)		(1,593	)		8,974
Finance charges		32,218			34,673			99,732			104,071
Income taxes		(22,562	)		(36,373	)		(82,715	)		(101,869	)
Other		72			425			(705	)		565
Income taxes paid		(539	)		(2,512	)		(3,300	)		(13,087	)
Income taxes recovered		11,600			536			11,932			603
Interest paid		(1,877	)		(8,685	)		(72,136	)		(78,194	)
Interest received		254			691			1,635			2,834
Funds provided by operations		85,140			31,688			155,612			93,909
Changes in non-cash working capital balances		(28,383	)		(14,173	)		(62,346	)		56,445
		56,757			17,515			93,266			150,354
Investments:
Purchase of property, plant and equipment		(22,518	)		(78,162	)		(73,047	)		(158,747	)
Proceeds on sale of property, plant and equipment		4,273			2,125			10,054			5,830
Income taxes recovered		–			–			–			2,917
Changes in non-cash working capital balances		(150	)		9,394			(10,716	)		(9,890	)
		(18,395	)		(66,643	)		(73,709	)		(159,890	)
Financing:
Repurchase of unsecured senior notes		–			(55,916	)		–			(64,325	)
Debt issue costs		–			(59	)		(341	)		(1,214	)
Issuance of common shares on the exercise of options		–			12			–			1,926
		–			(55,963	)		(341	)		(63,613	)
Effect of exchange rate changes on cash and cash equivalents		(1,684	)		1,606			(3,179	)		(19,416	)
Increase (decrease)  in cash and cash equivalents		36,678			(103,485	)		16,037			(92,565	)
Cash and cash equivalents, beginning of period		95,064			455,679			115,705			444,759
Cash and cash equivalents, end of period	$	131,742		$	352,194		$	131,742		$	352,194

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Interim Consolidated Statements of Changes in Equity (UNAUDITED)

(Stated in thousands of Canadian dollars)	Shareholders’ capital		Contributed surplus		Accumulated other comprehensive income			Deficit			Total equity
Balance at January 1, 2017	$	2,319,293	$	38,937	$	156,456		$	(552,568	)	$	1,962,118
Net loss for the period		–		–		–			(85,031	)		(85,031	)
Other comprehensive loss for the period		–		–		(23,609	)		–			(23,609	)
Share based compensation expense		–		3,904		–			–			3,904
Balance at September 30, 2017	$	2,319,293	$	42,841	$	132,847		$	(637,599	)	$	1,857,382

(Stated in thousands of Canadian dollars)	Shareholders’ capital		Contributed surplus			Accumulated other comprehensive income			Deficit			Total equity
Balance at January 1, 2016	$	2,316,321	$	35,800		$	166,101		$	(397,013	)	$	2,121,209
Net loss for the period		–		–			–			(124,937	)		(124,937	)
Other comprehensive loss for the period		–		–			(25,563	)		–			(25,563	)
Share options exercised		2,972		(1,046	)		–			–			1,926
Share based compensation expense		–		3,065			–			–			3,065
Balance at September 30, 2016	$	2,319,293	$	37,819		$	140,538		$	(521,950	)	$	1,975,700

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THIRD QUARTER 2017 EARNINGS CONFERENCE CALL AND WEBCAST

Precision Drilling Corporation has scheduled a conference call and webcast to begin promptly at 12:00 noon MT (2:00 p.m. ET) on Friday, October 27, 2017.

The conference call dial in numbers are 1-844-515-9176 or 614-999-9312.

A live webcast of the conference call will be accessible on Precision’s website at www.precisiondrilling.com by selecting “Investor Relations”, then “Webcasts & Presentations”. Shortly after the live webcast, an archived version will be available for approximately 60 days.

An archived recording of the conference call will be available approximately one hour after the completion of the call until October 30, 2017 by dialing 1-855-859-2056 or 404-537-3406, pass code 93161565.

About Precision

Precision is a leading provider of safe and High Performance, High Value services to the oil and gas industry. Precision provides customers with access to an extensive fleet of contract drilling rigs, directional drilling services, well service and snubbing rigs, camps, rental equipment, and water treatment units backed by a comprehensive mix of technical support services and skilled, experienced personnel.

Precision is headquartered in Calgary, Alberta, Canada. Precision is listed on the Toronto Stock Exchange under the trading symbol “PD” and on the New York Stock Exchange under the trading symbol “PDS”.

For further information, please contact:

Carey Ford, Senior Vice President and Chief Financial Officer

403.716.4566

Ashley Connolly, Manager Investor Relations

403.716.4725

800, 525 - 8th Avenue S.W.

Calgary, Alberta, Canada T2P 1G1

Website: www.precisiondrilling.com

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