EXHIBIT 99.1

Precision Drilling Corporation Announces 2017 Fourth Quarter and Year-End Unaudited Financial Results

CALGARY, Alberta, Feb. 15, 2018 (GLOBE NEWSWIRE) --

(Canadian dollars except as indicated)

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, 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” later in this news release. 

Precision Drilling 2017 fourth quarter and year-end financial results and highlights:

• Fourth quarter revenue of $347 million was an increase of 15% over the prior year comparative quarter.
  
  
• Fourth quarter net loss of $47 million ($0.16 per share) compared with a net loss of $31 million ($0.10 per share) in the fourth quarter of 2016.  During the current quarter we incurred an asset impairment charge for $15 million, related to our Mexico contract drilling business, that after tax, increased our net loss by $10 million and net loss per diluted share by $0.03.  In addition, because of changes in U.S. tax regulations, we recorded a $16 million future tax expense ($0.05 per diluted share) in the quarter.
  
  
• Fourth quarter earnings before income taxes, loss on redemption and repurchase of unsecured senior notes, finance charges, foreign exchange, impairment of property, plant and equipment, gain on re-measurement of property, plant and equipment and depreciation and amortization, (adjusted EBITDA see “NON-GAAP MEASURES”) of $91 million was 40% higher than the fourth quarter of 2016.
  
  
• Full year revenue of $1,321 million was a 32% increase from $1,003 million in 2016.
  
  
• Full year net loss of $132 million ($0.45 per share) compared with a net loss of $156 million ($0.53 per share) in 2016.
  
  
• Full year adjusted EBITDA of $305 million was a 34% increase from $228 million of adjusted EBITDA in 2016.
  
  
• Funds provided by operations (see “NON-GAAP MEASURES”) of $28 million in the fourth quarter and $184 for the full year representing a 147% and 75% year-over-year increase, respectively.
  
  
• During the fourth quarter we issued US$400 million of 7.125% senior notes due 2026 and used the proceeds along with US$49 million of cash to repurchase all our outstanding US$372 million 2020 senior notes and US$70 million of our 2021 senior notes plus redemption costs.
  
  
• Long-term debt net of cash as of December 31, 2017 was $1,665 million, a decrease of $126 million from December 31, 2016.
  
  
• Fourth quarter capital expenditures were $25 million, with full year capital spending of $98 million.
  
  
• Exited 2017 with 63 active rigs in the U.S. representing a 62% increase from where we entered the year.

Precision’s President and CEO Kevin Neveu stated: “Precision’s strong financial performance in the fourth quarter of 2017 is a result of our High Performance, High Value strategy executed through Precision’s skilled crews, high-efficiency Super Series drilling rigs, and our focus on cost management.  The strategic priorities we set for 2017 helped direct our organization to gain market share, grow revenue and margin, commercialize automation technologies, leverage fixed costs, and generate cash to reduce debt.”

“As projected, Precision’s U.S. activity recovered to peak 2017 levels during the fourth quarter with 63 active rigs by year end. Pricing momentum returned during the fourth quarter with well-to-well and term contract renewals pricing into higher day rates as customer demand for the most efficient rigs remains strong.  Precision’s Super Triple pad walking rigs with long-reach horizontal capability are now pricing US$10,000 per day higher than the lows in 2016.  We have signed 21 term contracts in the U.S. since the end of the third quarter and have 65 rigs running today. With confirmed customer contracts we expect our active rig count will move through 70 rigs later this quarter.”

“In Canada, Precision remains well positioned in the deep basins and heavy oil regions where our Super Triple and Super Single fleets represent the rigs of choice for high-efficiency drilling applications in each region.  Rates for these rigs have remained firm, and our continued efforts to reduce cost with the benefit of our scale have underpinned our financial results.  While our current activity of 85 rigs is slightly lower than expected, our deep basin and heavy oil activity remains on track.  We expect the spring break-up slowdown in Canada will be customer spending driven rather than weather related, and at this stage visibility for activity levels in the second half of 2018 is limited.  With relatively low exposure to dry gas activity and leading market share in the most attractive basins, we expect to leverage our scale and fleet investment to generate strong free cash flow in 2018.”

“In Kuwait and Saudi Arabia our activity levels are steady with eight rigs running today, and our operational performance is excellent.  We are actively bidding our four idle rigs to opportunities in the Middle East region and plan to grow our presence in the region only if financial returns warrant.  With recent Brent oil price strength, I would expect more idle rig redeployment opportunities from what we have experienced over the past few years.”

“Looking back at 2017, I am pleased with the successes related to our strategic priorities. First, our High Performance, High Value service offering delivered 99.6% and 99.0% uptime in Canada and the U.S., respectively.  Second, we generated $184 million in funds provided by operations in 2017 with $83 million in capital expenditures net of disposals and achieved a 16% reduction in general and administrative costs with a 64% increase in North American activity levels when compared to 2016.  We extended the maturity profile of our senior notes and used US$49 million of cash to pay down long-term debt. Finally, we progressed our technology initiatives utilizing our Super Series rigs as the platform for technology deployment to the field.  We managed the field testing and confirmation of our rig automation technologies throughout the year setting the stage for full commercialization in 2018.  We anticipate strong customer adoption in process automation control (PAC) and directional guidance system (DGS) technology in the coming twelve months.”

“For 2018, High Performance, High Value services to safely help customers realize efficiency gains will continue to be key for our field operations.  Precision will further enhance our Super Series fleet with PAC, walking systems, increased pressure and hydraulic pumping capacity, and DGS offerings.  All growth and upgrade investments will be backed by customer contracts with pricing that ensures attractive rates of return on our investments.  In 2017, we completed 29 rig upgrades at an average of approximately $1.3 million per rig for pumping capacity increases, PAC technology and walking systems.  We currently have 10-20 rig upgrades slated for 2018, all of which are under $3 million per rig and we expect to spend less than $34 million on these upgrades.  This approach will ensure we continue to generate free cash flow and reduce our debt levels during the year,” concluded Mr. Neveu.

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 December 31,									Year ended December 31,
(Stated in thousands of Canadian dollars, except per share amounts)	2017			2016			% Change			2017			2016			% Change
Revenue(1)		347,187			302,653			14.7			1,321,224			1,003,233			31.7
Adjusted EBITDA(2)		90,914			65,000			39.9			304,981			228,075			33.7
Adjusted EBITDA(2) % of revenue		26.2	%		21.5	%					23.1	%		22.7	%
Net loss		(47,005	)		(30,618	)		53.5			(132,036	)		(155,555	)		(15.1	)
Cash provided by (used in) operations		23,289			(27,846	)		(183.6	)		116,555			122,508			(4.9	)
Funds provided by operations(2)		28,323			11,466			147.0			183,935			105,375			74.6
Capital spending:
Expansion		965			15,282			(93.7	)		11,946			148,887			(92.0	)
Upgrade		2,984			13,527			(77.9	)		37,086			19,862			86.7
Maintenance and infrastructure		13,601			15,916			(14.5	)		25,791			34,723			(25.7	)
Intangibles		7,405			-		n/m				23,179			-		n/m
Proceeds on sale		(4,787	)		(2,010	)		138.2			(14,841	)		(7,840	)		89.3
Net capital spending		20,168			42,715			(52.8	)		83,161			195,632			(57.5	)
Loss per share:
Basic and diluted		(0.16	)		(0.10	)		60.0			(0.45	)		(0.53	)		(15.1	)

(1)    Prior year comparatives have changed to conform to current year presentation. 
(2)    See “NON-GAAP MEASURES”.
n/m  calculation not meaningful.

Operating Highlights

	Three Months Ended December 31,							For the Year Ended December 31,
	2017		2016		% Change			2017		2016		% Change
Contract drilling rig fleet		256		255		0.4			256		255		0.4
Drilling rig utilization days:
Canada		4,938		4,672		5.7			18,883		12,722		48.4
U.S.		5,365		3,570		50.3			20,479		11,343		80.5
International		736		742		(0.8	)		2,920		2,786		4.8
Revenue per utilization day:
Canada(1)(2) (Cdn$)		23,457		23,298		0.7			21,143		24,509		(13.7	)
U.S.(1)(3) (US$)		20,226		21,292		(5.0	)		19,861		26,145		(24.0	)
International (US$)		50,319		52,816		(4.7	)		50,240		45,753		9.8
Operating cost per utilization day:
Canada(1) (Cdn$)		13,544		13,298		1.8			13,140		14,258		(7.8	)
U.S.(1)  (US$)		13,647		14,349		(4.9	)		13,846		15,547		(10.9	)
Service rig fleet		210		207		1.4			210		207		1.4
Service rig operating hours		44,325		33,170		33.6			172,848		99,451		73.8
Revenue per operating hour (Cdn$)		644		629		2.4			637		646		(1.4	)

(1)    Prior year comparatives have changed to conform to current year presentation. 
(2)    Includes lump sum revenue from contract shortfall.
(3)    2016 comparatives and periods ended December 31, 2017 includes revenue from idle but contracted rig days.

Financial Position

(Stated in thousands of Canadian dollars, except ratios)	December 31, 2017		December 31, 2016
Working capital(1)		232,121		230,874
Cash		65,081		115,705
Long-term debt(2)		1,730,437		1,906,934
Total long-term financial liabilities		1,754,059		1,946,742
Total assets		3,892,931		4,324,214
Long-term debt to long-term debt plus equity ratio(2)		0.49		0.49

(1) See “NON-GAAP MEASURES”.   
(2) Net of unamortized debt issue costs.

RECAST OF COMPARATIVE FINANCIAL INFORMATION

As discussed in our third quarter 2017 report we changed our treatment of how certain amounts were historically netted against operating expense. In addition, certain immaterial reclassifications between operating and general and 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 December 31, 2016									For the Year Ended December 31, 2016
(Stated in thousands of Canadian dollars)	As previously reported		Revenue recast		Expense recast			As recast		As previously reported		Revenue recast		Expense recast			As recast
Revenue		283,903		18,750		—			302,653		951,411		51,822		—			1,003,233
Expenses:
Operating		187,381		18,750		452			206,583		607,295		51,822		2,598			661,715
General and administrative		31,522		—		(452	)		31,070		110,287		—		(2,598	)		107,689
Restructuring		—		—		—			—		5,754		—		—			5,754
Adjusted EBITDA(1)		65,000		—		—			65,000		228,075		—		—			228,075

(1)    See “NON-GAAP MEASURES”.   

Summary for the three months ended December 31, 2017

• Revenue this quarter was $347 million which is 15% higher than the fourth quarter of 2016.  The increase in revenue was primarily the result of higher activity in our North American based businesses partially offset by a decrease in average day rate in our U.S. contract drilling business and no utilization in our Mexico based contract drilling business.  Compared with the fourth quarter of 2016 our activity, as measured by drilling rig utilization days, increased by 6% in Canada and 50% in the U.S. and decreased by 1% internationally.  Revenue from our Contract Drilling Services and Completion and Production Services segments both increased over the comparative prior year period by 13% and 32%, respectively.
  
  
• Adjusted EBITDA this quarter was $91 million, an increase of $26 million from the fourth quarter of 2016. Our adjusted EBITDA as a percentage of revenue was 26% this quarter, compared with 21% in the fourth 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 businesses partially offset by lower average pricing in our U.S. contract drilling business.
  
  
• Operating loss (see “NON-GAAP MEASURES”) this quarter was $19 million compared with an operating loss of $30 million in the fourth quarter of 2016.  Operating results this quarter were positively impacted by increased activity in our North American businesses, partially offset by lower average pricing in the U.S. and a $15 million impairment charge to our property, plant and equipment.
  
  
• General and administrative expenses this quarter were $22 million, $9 million lower than the fourth quarter of 2016.  The decrease is due to lower share-based compensation expense that is tied to our common shares and the effect of a strengthening Canadian dollar on our U.S. dollar denominated costs.  As at December 31, 2017 we have a total share-based incentive compensation liability of $22 million compared with $24 million at September 30, 2017 with no payments in the quarter.
  
  
• Under International Financial Reporting Standards, we are required to assess the carrying value of assets in our cash generating units (CGUs) containing goodwill annually and when indicators of impairment exist.  As a result of no activity in 2017, we completed an impairment test for our Mexico contract drilling CGU as at December 31, 2017.  The test involves determining a value in use based on a multi-year discounted cash flow using assumptions on expected future results.  The resulting value in use is then compared to the carrying value of the CGU.  As a result of this test it was determined that property, plant and equipment in our Mexico contract drilling business was impaired by US$12 million.
  
  
• Net finance charges were $38 million, a decrease of $4 million compared with the fourth quarter of 2016 primarily because 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.
  
  
• During the quarter we redeemed US$442 million of our previously outstanding senior notes incurring a loss on redemption of $9 million.
      
• In Canada, average revenue per utilization day for contract drilling rigs increased in the fourth quarter of 2017 to $23,457 from $23,298 in the prior year fourth quarter as we had higher spot market dayrates partially offset by fewer rigs working under legacy contracts. During the quarter, we recognized $12.6 million in revenue associated with contract shortfall payments in Canada which was an increase of $1.3 million from the prior year period. Of the $12.6 million in shortfall revenue recorded in the fourth quarter of 2017, $3.4 million would have been earned within the quarter. On a quarter-over-quarter basis, revenue per utilization day in Canada increased by $3,477 as a result of higher shortfall payments and higher boiler revenue when compared to the third quarter of 2017. In the U.S., revenue per utilization day decreased in the fourth quarter of 2017 to US$20,226 from US$21,292 in the prior year fourth quarter. 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 partially offset by higher turnkey activity in the current quarter. During the quarter, we had turnkey revenue of US$3 million compared with no revenue in the 2016 comparative period and had US$1 million in revenue from idle but contracted rigs in the current quarter versus US$5 million in the comparative period. On a sequential basis, revenue per utilization day excluding revenue from idle but contracted rigs increased by US$1,012 due to higher fleet average day rates and higher turnkey revenue when compared to the third quarter of 2017.

• Average operating costs per utilization day for drilling rigs in Canada increased to $13,544 compared with the prior year fourth quarter of $13,298. The increase in average costs was due to timing of equipment certifications. On a sequential basis, operating costs per day decreased by $112 compared to the third quarter of 2017 due to improved fixed cost absorption. In the U.S., operating costs for the quarter on a per day basis decreased to US$13,647 in 2017 compared with US$14,349 in 2016 due to fixed costs spread over higher utilization, lower lump sum move costs partially offset by turnkey work and higher repair costs for rig activations. On a sequential basis, operating costs per day increased by US$1,056 compared to the third quarter of 2017 due to increased turnkey work, higher repair costs for rig activations and higher lump sum move costs.
  
  
• Average operating margin per utilization day excluding revenue from idle but contracted rigs and shortfall revenue in the fourth quarter of 2017 increased by $3,341 in Canada and was relatively unchanged in the U.S. when compared to the third quarter of 2017. In Canada, the increase was a result of higher fixed cost absorption, higher boiler revenue and higher spot market day rates.
  
  
• We realized revenue from international contract drilling of US$37 million in the fourth quarter of 2017, a US$2 million decrease over the prior year period.  The decrease was due to a reduction in activity in our Mexico operations and lump sum demobilization revenue received in Mexico and early mobilization payments in Kuwait in the fourth quarter of 2016 partially offset by increased activity in Kuwait, as the two rigs we added in the fourth quarter of 2016 were operational for the full year in 2017. Average revenue per utilization day in our international contract drilling business was US$50,319 a decrease of 5% over the comparable prior year quarter primarily due to demobilization and mobilization revenue received in the fourth quarter of 2016.
  
  
• Directional drilling services realized revenue of $4 million in the fourth quarter of 2017 compared with $9 million in the prior year period.
  
  
• Funds provided by operations in the fourth quarter of 2017 were $28 million, an increase of $17 million from the prior year comparative quarter. The increase was primarily the result of improved operating results.
  
  
• Capital expenditures for the purchase of property, plant and equipment were $25 million in the fourth quarter, a decrease of $20 million over the same period in 2016.  Capital spending for the quarter included $1 million for expansion capital, $3 million for upgrade capital, $14 million for the maintenance of existing assets and infrastructure and $7 million for intangibles. 

Summary for the year ended December 31, 2017:

• Revenue for 2017 was $1,321 million, an increase of 32% from the 2016 period.
  
  
• Operating loss (see “NON-GAAP MEASURES”) was $88 million, a decrease of $68 million over the same period in 2016. Operating loss was 7% of revenue in 2017 compared to 16% 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 in our U.S. contract drilling division.
  
  
• General and administrative costs were $90 million, a decrease of $18 million from 2016. The decrease was due to lower share-based incentive compensation that is tied to the price of our common shares, fixed cost reductions implemented through the downturn and the effect of a strengthening Canadian dollar on our U.S. dollar denominated costs.
  
  
• Net finance charges were $138 million, a decrease of $8 million from 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 2017 were $184 million, an increase of $79 million from the prior year comparative period of $105 million.
  
  
• Capital expenditures for the purchase of property, plant and equipment were $98 million in 2017, a decrease of $105 million over the same period in 2016. Capital spending for 2017 included $12 million for expansion capital, $37 million for upgrade capital, $26 million for the maintenance of existing assets and infrastructure and $23 million for intangibles.
  
  

STRATEGY

Precision’s strategic priorities for 2017 were as follows:

1. Deliver High Performance, High Value service offering in an improving demand environment while demonstrating fixed cost leverage – In the U.S., our activity levels increased by 81% in 2017 versus 2016. In Canada, we began the year with 50 active rigs and reached a seasonal peak of 91 rigs. Year-over-year in 2017 our utilization days were up 64% across our North American drilling operations and was achieved without any material increase in fixed costs. In 2017 we were able to reduce our annual general and administrative costs by 16% and improve EBITDA margins. 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 (DGS) and High Speed Downhole Data are ongoing, and we expect to progress the commercialization of these automation features during 2018. In 2017, we drilled 154 wells utilizing PAC technology which is installed on 20 Super Triple Rigs. Year-to-date in 2018 we have drilled an additional 50 wells utilizing PAC technology. In addition, we have drilled a total of 173 wells including 57 wells in 2017 and 25 wells year-to-date in 2018 utilizing DGS.
   
   
3. Maintain strict financial discipline in pursuing growth opportunities with a focus on free cash flow and debt reduction – Effectively all upgrade capital spending was 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 $40 million from planned levels as a result of lower industry activity than expected with the reduction relating primarily to upgrade and maintenance capital. The reduction was consistent with our focus on free cash flow to drive debt reduction. In 2017, we generated funds from operations of $184 million (see “NON-GAAP MEASURES) while spending $83 million on capital expenditures net of dispositions.

OUTLOOK

For the fourth quarter of 2017, the average West Texas Intermediate price of oil was 13% higher than the prior year comparative period while the average Henry Hub natural gas price was 4% lower. The average AECO price was 44% lower than the prior year comparative period because of infrastructure constraints partially due to planned maintenance, and high storage levels.

	Three months ended December 31,				Year ended December 31,
	2017		2016		2017	2016
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)		55.45		49.21	50.95		43.30
Natural gas
Canada
AECO (per MMBtu) (Cdn$)		1.67		2.96	2.16		2.14
United States
Henry Hub (per MMBtu) (US$)		2.86		2.99	2.98		2.48

Contracts

The following chart outlines the average number of drilling rigs by quarter that we had under contract for 2017 and the average number of drilling rigs by quarter we have under contract for 2018 as at February 14, 2018.

	Average for the quarter ended 2017								Average for the quarter ended 2018
	Mar. 31		June 30		Sept. 30		Dec. 31		Mar. 31		June 30		Sept. 30		Dec. 31
Average rigs under term contract   as at February 14, 2018:
Canada		27		23		19		12		8		6		6		6
U.S.		26		33		31		27		34		34		24		13
International		8		8		8		8		8		8		7		6
Total		61		64		58		47		50		48		37		25

The following chart outlines the average number of drilling rigs that we had under contract for 2017 and the average number of rigs we have under contract for 2018 as at February 14, 2018.

	Average for the year ended
	2017		2018
Average rigs under term contract   as at February 14, 2018:
Canada		20		7
U.S.		29		26
International		8		7
Total		57		40

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.  During 2017 we added 29 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	December 31		March 31		June 30		September 30		December 31
Average Precision active rig count:
Canada		51		76		29		49		54
U.S.		39		47		59		61		58
International		8		8		8		8		8
Total		98		131		96		118		120

To start 2018, drilling activity has increased relative to this time last year in the U.S. and is largely flat in Canada.  According to industry sources, as of February 9, 2018, the U.S. active land drilling rig count was up approximately 33% from the same point last year and the Canadian active land drilling rig count was down approximately 8%.  In the U.S., the trend towards oil-directed drilling continues. To date in 2018, approximately 66% of the Canadian industry’s active rigs and 80% of the U.S. industry’s active rigs were drilling for oil targets, compared with 55% for Canada and 79% for the U.S. at the same time last year.

Tier 1 Rig Demand

With improved commodity prices and increasing activity levels, last year we were able to increase prices on spot market rigs across most of our fleet. Should commodity prices continue to improve, we expect sequential improvements in pricing in the U.S. Day rates for our AC Super Triples have rebounded fairly dramatically in the context of historical price movements and are now pricing US$10,000 per day higher than the lows in 2016.

We expect day rate stability across Canada with particular strength in the Deep Basin in Canada; however, leading edge rates are not expected to be as high as those in the U.S.

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 2018 is expected to be $94 million:

• The 2018 capital expenditure plan includes $45 million for sustaining and infrastructure, $34 million to upgrade existing rigs and $15 million on intangibles. We expect that the $94 million will be split $74 million in the Contract Drilling Services segment, $5 million in the Completion and Production Services segment and $15 million in the Corporate segment.
  
  

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 water treatment divisions.

	Three months ended December 31,									Year ended December 31,
(Stated in thousands of Canadian dollars)	2017			2016			% Change			2017			2016			% Change
Revenue:
Contract Drilling Services(1)		308,973			273,669			12.9			1,173,930			907,821			29.3
Completion and Production Services		40,600			30,706			32.2			154,146			100,049			54.1
Inter-segment eliminations		(2,386	)		(1,722	)		38.6			(6,852	)		(4,637	)		47.8
		347,187			302,653			14.7			1,321,224			1,003,233			31.7
Adjusted EBITDA:(2)
Contract Drilling Services		100,280			86,351			16.1			342,970			296,651			15.6
Completion and Production Services		2,714			390			595.9			11,888			(3,649	)		(425.8	)
Corporate and other		(12,080	)		(21,741	)		(44.4	)		(49,877	)		(64,927	)		(23.2	)
		90,914			65,000			39.9			304,981			228,075			33.7

(1)    Prior year comparatives have changed to conform to current year presentation.  
(2)    See “NON-GAAP MEASURES”.

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

	Three months ended December 31,									Year ended December 31,
(Stated in thousands of Canadian dollars, except   where noted)	2017			2016			% Change			2017			2016			% Change
Revenue(1)		308,973			273,669			12.9			1,173,930			907,821			29.3
Expenses:
Operating(1)		200,615			180,125			11.4			798,655			574,104			39.1
General and administrative(1)		8,078			7,193			12.3			32,305			34,026			(5.1	)
Restructuring		—			—			—			—			3,040			(100.0	)
Adjusted EBITDA(2)		100,280			86,351			16.1			342,970			296,651			15.6
Depreciation		82,680			90,671			(8.8	)		334,587			348,005			(3.9	)
Impairment of property, plant and equipment		15,313			—		n/m				15,313			—		n/m
Operating earnings (loss)(2)		2,287			(4,320	)		(152.9	)		(6,930	)		(51,354	)		(86.5	)
Operating earnings (loss) as a percentage of revenue		0.7	%		(1.6	%)					(0.6	%)		(5.7	%)

(1)    Prior year comparatives have changed to conform to current year presentation.
(2)    See “NON-GAAP MEASURES”.
n/m calculation not meaningful.

	Three Months Ended December 31,
Canadian onshore drilling statistics:(1)	2017						2016
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		136			627			135			668
Drilling rig operating days (spud to release)		4,298			16,249			4,090			14,281
Drilling rig operating day utilization		35	%		29	%		33	%		23	%
Number of wells drilled		447			1,674			355			1,473
Average days per well		9.6			9.7			11.5			9.7
Number of metres drilled (000s)		1,245			4,780			932			4,023
Average metres per well		2,786			2,855			2,625			2,731
Average metres per day		290			294			228			282
	For the Year Ended December 31,
Canadian onshore drilling statistics:(1)	2017						2016
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		136			627			135			668
Drilling rig operating days (spud to release)		16,696			66,138			11,273			42,391
Drilling rig operating day utilization		34	%		29	%		22	%		17	%
Number of wells drilled		1,729			6,959			962			3,963
Average days per well		9.7			9.5			11.7			10.7
Number of metres drilled (000s)		4,597			19,047			2,548			10,351
Average metres per well		2,659			2,737			2,649			2,612
Average metres per day		275			288			226			244

(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
December 31		58		902		39		567
Year to date average		56		856		31		486

(1)    United States lower 48 operations only.
(2)    Baker Hughes rig counts.

Revenue from Contract Drilling Services was $309 million this quarter, or 13% higher than the fourth quarter of 2016, while adjusted EBITDA increased by 16% to $100 million.  The increase in revenue was primarily due to higher utilization days in Canada and the U.S. During the quarter, we recognized $12.6 million in revenue associated with contract shortfall payments in Canada which was an increase of $1.3 million from the prior year period. Of the $12.6 million in shortfall revenue recorded in the fourth quarter of 2017, $3.4 million would have been earned within the quarter. During the quarter in the U.S. we recognized idle but contracted revenue of US$1 million compared with US$5 million in the comparative period and current period turnkey revenue of US$3 million with no revenue in the comparative quarter of 2016.

Drilling rig utilization days in Canada (drilling days plus move days) were 4,938 during the fourth quarter of 2017, an increase of 6% 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 5,365, or 50% higher than the same quarter of 2016 as U.S. activity was up with higher industry activity.  Drilling rig utilization days in our international businesses were 736 or 1% lower than the same quarter of 2016 due to no activity in Mexico in the fourth quarter of 2017.

Compared with the same quarter in 2016, drilling rig revenue per utilization day was up 1% in Canada due to higher average spot market rates partially offset by fewer legacy contracts.  Drilling rig revenue per utilization day for the quarter in the U.S. and international were each down 5% from the prior comparative period.  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, lower idle but contracted revenue partially offset by an increase in turnkey activity in the current quarter and strengthening spot market rates. International revenue per utilization day was down due to demobilization revenue received in Mexico in the fourth quarter of 2016.  

In Canada, 13% of our utilization days in the quarter were generated from rigs under term contract, compared with 35% in the fourth quarter of 2016.  In the U.S., 55% of utilization days were generated from rigs under term contract as compared with 56% in the fourth quarter of 2016.

Operating costs were 65% 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 slightly higher than the prior year period primarily due to timing of equipment certifications.  In the U.S., operating costs for the quarter on a per day basis were lower than the prior year period primarily due to fixed costs spread over higher utilization and lower lump sum move cost partially offset by turnkey work and higher repair costs for rig activations. Both Canada and U.S. operating costs benefited from cost saving initiatives taken in 2015 and 2016. 

Depreciation expense in the quarter was 9% lower than in the fourth quarter of 2016.

SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES

	Three months ended December 31,									Year ended December 31,
(Stated in thousands of Canadian dollars, except   where noted)	2017			2016			% Change			2017			2016			% Change
Revenue		40,600			30,706			32.2			154,146			100,049			54.1
Expenses:
Operating(1)		35,595			28,180			26.3			134,368			92,248			45.7
General and administrative(1)		2,291			2,136			7.3			7,890			9,429			(16.3	)
Restructuring		—			—			—			—			2,021			—
Adjusted EBITDA(2)		2,714			390			595.9			11,888			(3,649	)		(425.8	)
Depreciation		8,410			8,735			(3.7	)		29,638			29,272			1.3
Gain on re-measurement of property, plant and equipment		—			(7,605	)		—			—			(7,605	)		—
Operating loss(2)		(5,696	)		(740	)		669.7			(17,750	)		(25,316	)		(29.9	)
Operating loss as a percentage of revenue		(14.0	%)		(2.4	%)					(11.5	%)		(25.3	%)
Well servicing statistics:
Number of service rigs (end of period)		210			207			1.4			210			207			1.4
Service rig operating hours		44,325			33,170			33.6			172,848			99,451			73.8
Service rig operating hour utilization		23	%		21	%					23	%		17	%
Service rig revenue per operating hour		644			629			2.4			637			646			(1.4	)

(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 $10 million or 32% compared with the fourth quarter of 2016 due to higher activity levels.  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 34% from the fourth 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 96% of our fourth quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 92% of its revenue from Canadian operations and 8% from U.S. operations compared with the fourth quarter of 2016 of 88% from Canada and 12% from U.S. operations.

Average service rig revenue per operating hour in the quarter was $644 or $15 higher than the fourth quarter of 2016.  The increase was primarily the result of increased labour costs which were passed through to the customer.   

Adjusted EBITDA was $2 million higher than the fourth quarter of 2016 due to increased activity in the segment. 

Operating costs as a percentage of revenue decreased to 88% in the fourth quarter of 2017, from 92% in the fourth quarter of 2016.  The decrease is the result of the impact of fixed costs spread across greater activity combined with our reduced cost structure.

While we were successful in 2017 in reducing our fixed costs, margins in our Completion and Production Services have been challenged primarily due to intense pricing pressure, repair and maintenance as well as labor costs associated with service rig reactivations.

Depreciation in the quarter was $8 million in line with the previous year comparative period.

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 $12 million a decrease of $10 million compared with the fourth quarter of 2016 primarily due to lower share-based incentive compensation.

OTHER ITEMS

Net financial charges for the quarter were $38 million, a decrease of $4 million compared with the fourth quarter of 2016 primarily because 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.

During the quarter, we redeemed and repurchased US$442 million of our previously outstanding senior notes incurring a loss of $9 million.  For the quarter, we incurred a foreign exchange gain of $2 million in line with the fourth quarter of 2016. 

Income tax expense for the quarter was a recovery of $17 million compared with a recovery of $51 million in the same quarter in 2016. The recoveries are due to negative pretax earnings in the fourth quarter of 2017 offset by a $16 million charge to future tax expense as a result of tax changes implemented in the U.S.

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.

Liquidity

Amount	Availability	Used for	Maturity
Senior facility (secured)
US$500 million (extendible, revolving term credit facility with US$250 million(1) accordion feature)	Undrawn, except US$21 million in outstanding letters of credit	General corporate purposes	November 21, 2021
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$13 million in outstanding letters of credit	Letters of credit
Senior notes  (unsecured)
US$249 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
US$400 million – 7.125%	Fully drawn	Debt redemption and repurchases	January 15, 2026

 (1) Increases to US$300 million at the end of the covenant relief period of March 31, 2019.

On November 21, 2017 we agreed with our lending group to the following amendments to our senior credit facility:

• Reduce the Covenant EBITDA (see “NON-GAAP MEASURES”), as defined in the credit agreement, to interest expense coverage ratio to greater than 2.0:1 for the periods ending June 30, September 30, and December 31, 2018 and March 31, 2019 reverting to 2.5:1 thereafter;
• Reduced the size of the facility to US$500 million;
• Extend the maturity date of the facility to November 21, 2021 subject to certain spring forward provisions if junior debt is not refinanced in a timely manner;
• Amend certain negative covenants, to among other things, permit the redemption and repurchase of junior debt subject to a pro forma consolidated senior net leverage covenant ratio of less than or equal to 1.75:1., and;
• Amend the negative covenant with respect to distributions to permit distributions after March 31, 2019 subject to a pro forma consolidated senior net leverage covenant ratio of less than or equal to 1.75:1.

On November 22, 2017 we issued US$400 million of 7.125% senior notes due in 2026 in a private offering. The Notes are guaranteed on a senior unsecured basis by current and future U.S. and Canadian subsidiaries that also guarantee our Senior Credit Facility and certain other indebtedness. The Notes were issued to redeem and repurchase existing debt.

On November 22, 2017 we repurchased, pursuant to an early tender offer, US$310 million of our 6.625% unsecured senior notes due 2020 and US$70 million of our 6.5% unsecured senior notes due 2021 for combined US$387 million plus accrued and unpaid interest incurring a loss on the repurchase of US$6 million.

On December 7, 2017 we redeemed our remaining outstanding 6.625% unsecured senior notes due 2020 for US$62 million plus accrued and unpaid interest incurring a loss on redemption of US$1 million.

As at December 31, 2017 we had $1,759 million outstanding under our senior unsecured notes.  The current blended cash interest cost of our debt is approximately 6.6%.

Covenants

Senior Facility

The senior credit facility requires that we comply with certain covenants including a leverage ratio of consolidated senior debt to 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. As at December 31, 2017 our consolidated senior debt to Covenant EBITDA ratio was negative 0.12:1.

Effective November 21, 2017, under the senior credit facility, we are required to maintain a ratio of consolidated Covenant EBITDA to consolidated interest expense for the most recent four consecutive quarters, of greater than 1.5:1 for the periods ending December 31, 2017 and March 31, 2018 and 2.0:1 for the periods ending June 30, September 30, and December 31, 2018 and March 31, 2019.  For periods ending after March 31, 2019 the ratio reverts to 2.5:1. As at December 31, 2017 our senior credit facility consolidated Covenant EBITDA to consolidated interest expense ratio was 2.22:1.

The senior credit facility prevents us from making distributions prior to April 1, 2019, after which, distributions are subject to a pro forma consolidated senior net leverage covenant ratio test of less than or equal to 1.75:1. The senior credit facility also limits the redemption and repurchase of junior debt subject to a pro forma consolidated senior net leverage covenant ratio test of less than or equal to 1.75:1.

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 December 31, 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 December 31, 2017, our senior notes consolidated interest coverage ratio was 2.16:1.     

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 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 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 because 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 December 31,				Year ended December 31,
(Stated in thousands)	2017		2016		2017		2016
Weighted average shares outstanding – basic		293,239		293,239		293,239		293,133
Effect of stock options and other equity compensation plans		—		—		—		—
Weighted average shares outstanding – diluted		293,239		293,239		293,239		293,133

QUARTERLY FINANCIAL SUMMARY

(Stated in thousands of Canadian dollars, except per share amounts)
	2017
Quarters ended	March 31			June 30			September 30			December 31
Revenue(1)		368,673			290,860			314,504			347,187
Adjusted EBITDA(2)		84,308			56,520			73,239			90,914
Net loss:		(22,614	)		(36,130	)		(26,287	)		(47,005	)
Per basic and diluted share		(0.08	)		(0.12	)		(0.09	)		(0.16	)
Funds provided by (used in) operations(2)		85,659			(15,187	)		85,140			28,323
Cash provided by operations		33,770			2,739			56,757			23,289

(Stated in thousands of Canadian dollars, except per share amounts)
	2016
Quarters ended	March 31			June 30			September 30			December 31
Revenue(1)		316,505			170,407			213,668			302,653
Adjusted EBITDA(2)		99,264			22,400			41,411			65,000
Net loss:		(19,883	)		(57,677	)		(47,377	)		(30,618	)
Per basic and diluted share		(0.07	)		(0.20	)		(0.16	)		(0.10	)
Funds provided by (used in) operations(2)		93,593			(31,372	)		31,688			11,466
Cash provided by operations		112,174			20,665			17,515			(27,846	)

(1) Prior period comparatives have changed to conform to current year presentation. 
(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 months and the year ended December 31, 2017.

NON-GAAP MEASURES

In this press release we reference non-GAAP (Generally Accepted Accounting Principles) measures.  Adjusted 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 on repurchase of unsecured senior notes, financing charges, foreign exchange, impairment of property, plant and equipment, gain on re-measurement of property, plant and equipment 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.

Covenant EBITDA

Covenant EBITDA, as defined in our senior credit facility agreement differs from Adjusted EBITDA by the exclusion of bad debt expense, restructuring costs and certain foreign exchange amounts.

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.

Working Capital

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

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 2018;
• our capital expenditure plans for 2018 and our scheduled ERP upgrade;
• anticipated activity levels in 2018;
• anticipated demand for Tier 1 rigs; and
• the average number of term contracts in place for 2018 and 2019.  

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 and natural gas 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;
• change in tax legislation; 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.

INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)

(Stated in thousands of Canadian dollars)	December 31, 2017			December 31, 2016
ASSETS
Current assets:
Cash	$	65,081		$	115,705
Accounts receivable		322,585			293,682
Income tax recoverable		29,449			38,087
Inventory		24,631			24,136
Total current assets		441,746			471,610
Non-current assets:
Income tax recoverable		2,256			—
Deferred tax assets		41,822			—
Property, plant and equipment		3,173,824			3,641,889
Intangibles		28,116			3,316
Goodwill		205,167			207,399
Total non-current assets		3,451,185			3,852,604
Total assets	$	3,892,931		$	4,324,214
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	209,625		$	240,736
Total current liabilities		209,625			240,736
Non-current liabilities:
Share based compensation		13,536			27,387
Provisions and other		10,086			12,421
Long-term debt		1,730,437			1,906,934
Deferred tax liabilities		118,911			174,618
Total non-current liabilities		1,872,970			2,121,360
Shareholders’ equity:
Shareholders’ capital		2,319,293			2,319,293
Contributed surplus		44,037			38,937
Deficit		(684,604	)		(552,568	)
Accumulated other comprehensive income		131,610			156,456
Total shareholders’ equity		1,810,336			1,962,118
Total liabilities and shareholders’ equity	$	3,892,931		$	4,324,214

INTERIM CONSOLIDATED STATEMENTS OF LOSS (UNAUDITED)

	Three Months Ended December 31,						Years Ended December 31,
(Stated in thousands of Canadian dollars, except per share  amounts)	2017			2016			2017			2016
				(recast)						(recast)
Revenue	$	347,187		$	302,653		$	1,321,224		$	1,003,233
Expenses:
Operating		233,824			206,583			926,171			661,715
General and administrative		22,449			31,070			90,072			107,689
Restructuring		—			—			—			5,754
Earnings before income taxes, loss on redemption and   repurchase of unsecured senior notes, finance charges,   foreign exchange, gain on re-measurement of property,   plant and equipment, impairment of property, plant and   equipment and depreciation and amortization		90,914			65,000			304,981			228,075
Depreciation and amortization		94,229			102,801			377,746			391,659
Impairment of property, plant and equipment		15,313			—			15,313			—
Gain on re-measurement of property, plant and   equipment		—			(7,605	)		—			(7,605	)
Operating loss		(18,628	)		(30,196	)		(88,078	)		(155,979	)
Foreign exchange		(1,534	)		(925	)		(2,970	)		6,008
Finance charges		38,196			42,289			137,928			146,360
Loss on redemption and repurchase of unsecured senior   notes		9,021			10,220			9,021			239
Loss before income taxes
Income taxes:		(64,311	)		(81,780	)		(232,057	)		(308,586	)
Current		(1,670	)		(6,837	)		(1,331	)		(31,195	)
Deferred		(15,636	)		(44,325	)		(98,690	)		(121,836	)
		(17,306	)		(51,162	)		(100,021	)		(153,031	)
Net loss	$	(47,005	)	$	(30,618	)	$	(132,036	)	$	(155,555	)
Net loss per share:
Basic	$	(0.16	)	$	(0.10	)	$	(0.45	)	$	(0.53	)
Diluted	$	(0.16	)	$	(0.10	)	$	(0.45	)	$	(0.53	)

INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)

	Three Months Ended December 31,						Years Ended December 31,
(Stated in thousands of Canadian dollars)	2017			2016			2017			2016
Net loss	$	(47,005	)	$	(30,618	)	$	(132,036	)	$	(155,555	)
Unrealized gain (loss) on translation of assets and   liabilities of operations denominated in foreign currency		9,146			53,488			(146,545	)		(76,608	)
Foreign exchange gain (loss) on net investment hedge   with U.S. denominated debt, net of tax		(10,383	)		(37,570	)		121,699			66,963
Comprehensive loss	$	(48,242	)	$	(14,700	)	$	(156,882	)	$	(165,200	)

INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)

	Three Months Ended December 31,						Years Ended December 31,
(Stated in thousands of Canadian dollars)	2017			2016			2017			2016
Cash provided by (used in):
Operations:
Net loss	$	(47,005	)	$	(30,618	)	$	(132,036	)	$	(155,555	)
Adjustments for:
Long-term compensation plans		2,519			12,241			6,795			28,313
Depreciation and amortization		94,229			102,801			377,746			391,659
Impairment of property, plant and equipment		15,313			—			15,313			—
Gain on re-measurement of property, plant and   equipment		—			(7,605	)		—			(7,605	)
Loss on redemption and repurchase of unsecured   senior notes		9,021			10,220			9,021			239
Foreign exchange		(1,280	)		(2,183	)		(2,873	)		6,791
Finance charges		38,196			42,289			137,928			146,360
Income taxes		(17,306	)		(51,162	)		(100,021	)		(153,031	)
Other		(1,320	)		(2,454	)		(2,025	)		(1,889	)
Income taxes paid		(345	)		(1,518	)		(3,645	)		(14,605	)
Income taxes recovered		-			192			11,932			795
Interest paid		(63,929	)		(61,381	)		(136,065	)		(139,575	)
Interest received		230			644			1,865			3,478
Funds provided by operations		28,323			11,466			183,935			105,375
Changes in non-cash working capital balances		(5,034	)		(39,312	)		(67,380	)		17,133
		23,289			(27,846	)		116,555			122,508
Investments:
Purchase of property, plant and equipment		(17,550	)		(44,725	)		(74,823	)		(203,472	)
Purchase of intangibles		(7,405	)		—			(23,179	)		—
Proceeds on sale of property, plant and   equipment		4,787			2,010			14,841			7,840
Business acquisition, net of cash acquired		—			(12,200	)		—			(12,200	)
Income taxes recovered		—			—			—			2,917
Changes in non-cash working capital balances		2,727			880			(7,989	)		(9,010	)
		(17,441	)		(54,035	)		(91,150	)		(213,925	)
Financing:
Redemption and repurchase of unsecured senior notes		(571,975	)		(613,379	)		(571,975	)		(677,704	)
Debt issue costs		(9,196	)		(10,752	)		(9,196	)		(10,752	)
Debt amendment fees		(1,452	)		—			(1,793	)		(1,214	)
Increase in long-term debt		509,180			469,420			509,180			469,420
Issuance of common shares on the exercise of   options		—			—			—			1,926
		(73,443	)		(154,711	)		(73,784	)		(218,324	)
Effect of exchange rate changes on cash and cash equivalents		934			103			(2,245	)		(19,313	)
Decrease in cash and cash equivalents		(66,661	)		(236,489	)		(50,624	)		(329,054	)
Cash and cash equivalents, beginning of period		131,742			352,194			115,705			444,759
Cash and cash equivalents, end of period	$	65,081		$	115,705		$	65,081		$	115,705

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		—		—		—			(132,036	)		(132,036	)
Other comprehensive loss for the period		—		—		(24,846	)		—			(24,846	)
Share based compensation expense		—		5,100		—			—			5,100
Balance at December 31, 2017	$	2,319,293	$	44,037	$	131,610		$	(684,604	)	$	1,810,336

(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		—		—			—			(155,555	)		(155,555	)
Other comprehensive loss for the period		—		—			(9,645	)		—			(9,645	)
Share options exercised		2,972		(1,046	)		—			—			1,926
Share based compensation expense		—		4,183			—			—			4,183
Balance at December 31, 2016	$	2,319,293	$	38,937		$	156,456		$	(552,568	)	$	1,962,118

FOURTH 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 Thursday, February 15, 2018.

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 February 20, 2018 by dialing 1-855-859-2056 or 404-537-3406, pass code 9053499.

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, CFA
Senior Vice President and Chief Financial Officer
713.435.6111

Ashley Connolly, CFA
Manager, Investor Relations
403.716.4725

800, 525 - 8th Avenue S.W.
Calgary, Alberta, Canada T2P 1G1
Website:  www.precisiondrilling.com