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

CALGARY, Alberta, Feb. 15, 2018 —

(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