EX-99.1 4 exh_991.htm EXHIBIT 99.1

Exhibit 99.1

Precision Drilling Corporation

First Quarter Report for the three months ended March 31, 2018 and 2017

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s Discussion and Analysis for the three month period ended March 31, 2018 of Precision Drilling Corporation (“Precision” or the “Corporation”) prepared as at April 25, 2018 focuses on the unaudited Interim Consolidated Financial Statements and related notes and pertains to known risks and uncertainties relating to the oilfield services sector. This discussion should not be considered all inclusive as it does not include all changes regarding general economic, political, governmental and environmental events. This discussion should be read in conjunction with the Corporation’s 2017 Annual Report, Annual Information Form, unaudited March 31, 2018 Interim Consolidated Financial Statements and related notes.

This report contains “forward-looking information and statements” within the meaning of applicable securities laws. For a full disclosure of the forward-looking information and statements and the risks to which they are subject, see the “Cautionary Statement Regarding Forward-Looking Information and Statements” on page 13 of this report. This report contains references to Adjusted EBITDA, Covenant EBITDA, Operating Earnings (Loss), Funds Provided by Operations and Working Capital. These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies, see “Non-GAAP Measures” on page 12 of this report.

Precision Drilling announces 2018 first quarter financial results:

• First quarter revenue of $401 million was an increase of 9% over the prior year comparative quarter.

• First quarter net loss of $18 million ($0.06 per share) compares to a net loss of $23 million ($0.08 per share) in the first quarter of 2017.

• First quarter earnings before income taxes, finance charges, foreign exchange, and depreciation and amortization (adjusted EBITDA see “NON-GAAP MEASURES”) of $97 million was 16% higher than the first quarter of 2017.

• Funds provided by operations (see “NON-GAAP MEASURES”) in the first quarter of $104 million was an increase of 21% over the prior year comparative quarter.

• First quarter capital expenditures were $30 million.

1

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 March 31,
(Stated in thousands of Canadian dollars, except per share amounts)		2018				2017					% Change
Revenue(1)			401,006				368,673				8.8
Adjusted EBITDA(2)			97,469				84,308				15.6
Net loss			(18,077	)			(22,614	)			(20.1	)
Cash provided by operations			38,189				33,770				13.1
Funds provided by operations(2)			104,026				85,659				21.4
Capital spending:
Expansion			685				3,792				(81.9	)
Upgrade			11,363				13,647				(16.7	)
Maintenance and infrastructure			10,243				2,984				243.3
Intangibles			7,791				1,669				366.8
Proceeds on sale			(6,050	)			(2,218	)			172.8
Net capital spending			24,032				19,874				20.9
Net loss per share:
Basic			(0.06	)			(0.08	)			(25.0	)
Diluted			(0.06	)			(0.08	)			(25.0	)

(1) Prior year comparatives have changed to reflect a recast of certain amounts previously netted against operating expense. See our 2017 Annual Report.

(2) See “NON-GAAP MEASURES”.

Operating Highlights

		Three months ended March 31,
			2018				2017				% Change
Contract drilling rig fleet			256				255				0.4
Drilling rig utilization days:
Canada			6,468				6,819				(5.1	)
U.S.			5,795				4,190				38.3
International			720				720				-
Revenue per utilization day:
Canada(1)(2) (Cdn$)			22,209				21,405				3.8
U.S.(1)(3) (US$)			20,603				20,555				0.2
International (US$)			50,038				50,434				(0.8	)
Operating cost per utilization day:
Canada (Cdn$)			13,331				12,828				3.9
U.S. (US$)			14,026				15,264				(8.1	)
Service rig fleet			210				210				-
Service rig operating hours			52,701				52,057				1.2
Revenue per operating hour (Cdn$)			700				636				10.1

(1) Prior year comparatives have changed to reflect a recast of certain amounts previously netted against operating expense. See our 2017 Annual Report.

(2) Includes lump sum revenue from contract shortfall.

(3) 2017 comparative includes revenue from idle but contracted rig days.

2

Financial Position

(Stated in thousands of Canadian dollars, except ratios)			March 31, 2018				December 31, 2017
Working capital(1)			270,173				232,121
Cash			81,873				65,081
Long-term debt(2)			1,776,763				1,730,437
Total long-term financial liabilities			1,792,810				1,754,059
Total assets			3,929,703				3,892,931
Long-term debt to long-term debt plus equity ratio(2)			0.50				0.49

(1) See “NON-GAAP MEASURES”.

(2) Net of unamortized debt issue costs.

Summary for the three months ended March 31, 2018:

• Revenue this quarter was $401 million which is 9% higher than the first quarter of 2017. The increase in revenue is primarily the result of higher activity in our U.S. contract drilling business. Compared with the first quarter of 2017 our activity for the quarter, as measured by drilling rig utilization days, increased 38% in the U.S. and decreased 5% in Canada and remained consistent internationally. Revenue from our Contract Drilling Services and Completion and Production Services segments both increased over the comparative prior year period by 9% and 8%, respectively.

• Adjusted EBITDA this quarter of $97 million is an increase of $13 million from the first quarter of 2017. Our adjusted EBITDA as a percentage of revenue was 24% this quarter, compared with 23% in the first quarter of 2017. The increase in adjusted EBITDA as a percent of revenue was mainly due to higher average day rates in Canada, fixed costs spread over higher activity in the U.S. and lower average daily operating costs in the U.S. and International.

• Operating earnings (see “NON-GAAP MEASURES”) this quarter were $10 million compared with an operating loss of $13 million in the first quarter of 2017. Operating earnings this quarter were positively impacted by the increase in activity in our U.S. contract drilling business and lower depreciation expense.

• General and administrative expenses this quarter were $29 million, $4 million higher than the first quarter of 2017. The increase is due to higher share-based compensation expense tied to our common shares partially offset by a strengthening of the Canadian dollar on our U.S. dollar denominated costs. As at March 31, 2018 we have a total share-based incentive compensation liability of $16 million compared with $22 million at December 31, 2017 with $13 million paid in the quarter.

• Net finance charges were $32 million, a decrease of $1 million compared with the first quarter of 2017, primarily due to a reduction in interest expense related to debt retired in 2017 and the strengthening Canadian dollar impact on our U.S. dollar denominated costs partially offset by lower interest income in the current quarter.

• In Canada, average revenue per utilization day for contract drilling rigs increased in the first quarter of 2018 to $22,209 from $21,405 in the prior year first quarter as higher spot market day rates more than offset fewer rigs working under higher priced legacy contracts. During the quarter, we recognized $10 million in revenue associated with contract shortfall payments in Canada which was an increase of $1 million from the prior year period. In the U.S., revenue per utilization day increased in the first quarter of 2018 to US$20,603 from US$20,555 in the prior year first quarter. The increase in the U.S. revenue rate was the result of higher spot market day rates and higher turnkey revenue offset by rig mix, lower mobilization revenue and lower revenue from idle but contracted rigs. During the quarter, we had turnkey revenue of US$7 million compared with US$1 million in the 2017 comparative period and no revenue from idle but contracted rigs in the current quarter versus US$3 million in the comparative period. On a sequential basis, revenue per utilization day excluding revenue from idle but contracted rigs increased by US$566 due to higher fleet average day rates and higher turnkey revenue when compared to the fourth quarter of 2017.

• Average operating costs per utilization day for drilling rigs in Canada increased to $13,331 compared with the prior year first quarter of $12,828. The increase in average costs was due to larger average crew formations and the timing of equipment certifications. On a sequential basis, operating costs per day decreased by $213 compared to the fourth 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$14,026 in 2018 compared with US$15,264 in 2017 due to lower lump sum move costs and fixed costs spread over a greater number of utilization days partially offset by turnkey work. On a sequential basis, operating costs per day increased by US$379 compared to the fourth quarter of 2017 due to increased turnkey work.

3

• We realized revenue from international contract drilling of US$36 million in the first quarter of 2018, in-line with the prior year period. Average revenue per utilization day in our international contract drilling business was US$50,038 in-line with the comparable prior year quarter.

• Directional drilling services realized revenue of $9 million in the first quarter of 2018 compared with $13 million in the prior year period. 

• Funds provided by operations in the first quarter of 2018 were $104 million, an increase of $18 million from the prior year comparative quarter of $86 million. The increase was primarily the result of improved operating results.

• Capital expenditures were $30 million in the first quarter, an increase of $8 million over the same period in 2017. Capital spending for the quarter included $12 million for upgrade and expansion capital, $10 million for the maintenance of existing assets and infrastructure spending and $8 million for intangibles.

STRATEGY

Precision’s strategic priorities for 2018 are as follows:

1. Reduce debt by generating free cash flow while continuing to fund only the most attractive investment opportunities – we generated $104 million in funds from operations (see “NON-GAAP MEASURES”) representing a 21% increase over the prior year comparative period.

2. Reinforce Precision’s High Performance competitive advantage by deploying Process Automation Controls (PAC), Directional Guidance Systems (DGS) and Drilling Apps on a wide scale basis – year to date in 2018 we have drilled 57 wells using our DGS which is the same number of wells as we drilled in all of 2017. In addition, over 75% of these jobs used a reduced crew compared to only 30% in 2017. We have 21 rigs currently running in the field with PAC and have drilled 137 wells with this technology in 2018 compared to 154 in all of 2017. Earlier this year we also equipped our training rigs in Nisku and Houston with PAC technology. Customer adoption is rising, and we expect to be running an additional five to ten systems by year end, continuing full scale deployment and commercialization. Additionally, we are deploying revenue generating Apps on several rigs including both customer and Precision written applications.

3. Enhance financial performance through higher utilization and improved operating margins – overall utilization days are 11% higher than the prior year comparative period while average operating margins (revenue less operating costs) are up 24%, 17% and 4% in our U.S., international and Canada contract drilling businesses respectively.

OUTLOOK

For the first quarter of 2018, the average West Texas Intermediate price of oil was 21% higher than the prior year comparative period while the average Henry Hub gas price was 7% lower and the average AECO price was 22% lower.

		Three months ended March 31,									Year ended December 31,
			2018				2017				2017
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)			62.95				52.00				50.95
Natural gas
Canada
AECO (per MMBtu) (CDN$)			2.05				2.63				2.16
United States
Henry Hub (per MMBtu) (US$)			2.86				3.07				2.98

4

Contracts

Year to date in 2018 we have entered into 19 term contracts. The following chart outlines the average number of drilling rigs by quarter that we had under contract for 2017, the first quarter of 2018 and the average number of drilling rigs by quarter we have under contract for 2018 as of April 25, 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 April 25, 2018:
Canada			27				23				19				12				8				6				6				6
U.S.			26				33				31				27				36				47				38				24
International			8				8				8				8				8				8				7				6
Total			61				64				58				47				52				61				51				36

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 of April 25, 2018.

		Average for the year ended
		2017				2018
Average rigs under term contract as at April 25, 2018:
Canada			20				7
U.S.			29				36
International			8				7
Total			57				50

In Canada, term contracted rigs normally generate 250 utilization days per year because of the seasonal nature of well site access. In most regions in the U.S. and internationally, term contracts normally generate 365 utilization days per year.

Drilling Activity

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

		Average for the quarter ended 2017																2018
			Mar. 31				June 30				Sept. 30				Dec. 31				Mar. 31
Average Precision active rig count:
Canada			76				29				49				54				72
U.S.			47				59				61				58				64
International			8				8				8				8				8
Total			131				96				118				120				144

To start 2018, drilling activity has increased relative to this time last year in the U.S. and is down slightly in Canada. According to industry sources, as of April 20, 2018, the U.S. active land drilling rig count was up approximately 19% from the same point last year and the Canadian active land drilling rig count was down approximately 8%. In North America, the trend towards oil-directed drilling continues. To date in 2018, approximately 64% of the Canadian industry’s active rigs and 81% of the U.S. industry’s active rigs were drilling for oil targets, compared with 53% for Canada and 80% for the U.S. at the same time last year.

5

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. Our AC Super Triple rig dayrates have increased substantially 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.

Industry Conditions

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

Capital Spending

Capital spending in 2018 is expected to be $116 million and includes $57 million for sustaining and infrastructure, $45 million for upgrade and expansion and $14 million on intangibles. We expect that the $116 million will be split $97 million in the Contract Drilling Services segment, $5 million in the Completion and Production Services segment and $14 million to the Corporate segment.

SEGMENTED FINANCIAL RESULTS

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

		Three months ended March 31,
(Stated in thousands of Canadian dollars)			2018				2017				% Change
Revenue:(1)
Contract Drilling Services			352,802				323,930				8.9
Completion and Production Services			50,042				46,349				8.0
Inter-segment eliminations			(1,838	)			(1,606	)			14.4
			401,006				368,673				8.8
Adjusted EBITDA:(2)
Contract Drilling Services			110,966				93,665				18.5
Completion and Production Services			4,644				4,587				1.2
Corporate and other			(18,141	)			(13,944	)			30.1
			97,469				84,308				15.6

(1) Prior year comparatives have changed to reflect a recast of certain amounts previously netted against operating expense. See our 2017 Annual Report.

(2) See “NON-GAAP MEASURES”.

6

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

		Three months ended March 31,
(Stated in thousands of Canadian dollars, except where noted)			2018				2017				% Change
Revenue(1)			352,802				323,930				8.9
Expenses:
Operating(1)			233,148				220,817				5.6
General and administrative			8,688				9,448				(8.0	)
Adjusted EBITDA(2)			110,966				93,665				18.5
Depreciation			77,700				86,189				(9.8	)
Operating earnings(2)			33,266				7,476				345.0
Operating earnings as a percentage of revenue			9.4	%			2.3	%

(1) Prior year comparatives have changed to reflect a recast of certain amounts previously netted against operating expense. See our 2017 Annual Report.

(2) See “NON-GAAP MEASURES”.

		Three months ended March 31,
Canadian onshore drilling statistics:(1)		2018								2017
			Precision				Industry(2)				Precision				Industry(2)
Number of drilling rigs (end of period)			136				620				135				641
Drilling rig operating days (spud to release)			5,654				22,845				6,041				23,323
Drilling rig operating day utilization			47	%			41	%			50	%			41	%
Number of wells drilled			515				2,203				564				2,284
Average days per well			11.0				10.4				10.7				10.2
Number of metres drilled (000s)			1,498				6,365				1,471				6,160
Average metres per well			2,908				2,889				2,608				2,697
Average metres per day			265				279				243				264

(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)		2018								2017
			Precision				Industry(2)				Precision				Industry(2)
Average number of active land rigs for quarters ended:
March 31			64				951				47				722

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $353 million this quarter, or 9% higher than the first quarter of 2017, while adjusted EBITDA increased by 18% to $111 million. The increase in revenue was primarily due to higher utilization days in the U.S. During the quarter we recognized $10 million in shortfall payments in our Canadian contract drilling business, which was $1 million higher than in the prior year. During the quarter in the U.S. we recognized turnkey revenue of US$7 million compared with US$1 million in the comparative period and we did not recognize any idle but contracted revenue compared with US$3 million in the comparative quarter of 2017.

Drilling rig utilization days in Canada (drilling days plus move days) were 6,468 during the first quarter of 2018, a decrease of 5% compared to 2017 primarily due to a decrease in industry activity resulting from lower natural gas prices. Drilling rig utilization days in the U.S. were 5,795, or 38% higher than the same quarter of 2017 as our U.S. activity was up with higher industry activity. Drilling rig utilization days in our international business were 720, in-line with the same quarter of 2017.

Compared with the same quarter in 2017, drilling rig revenue per utilization day was up 4% in Canada due to an increase in spot market rates. Drilling rig revenue per utilization day for the quarter in the U.S. was in-line with the prior year as higher average day rates and higher turnkey revenue were offset by lower lump sum move revenue and lower idle but contract revenue. International revenue per utilization day was in-line with the prior year comparative period.

7

In Canada, 8% of our utilization days in the quarter were generated from rigs under term contract, compared with 31% in the first quarter of 2017. In the U.S., 58% of utilization days were generated from rigs under term contract as compared with 54% in the first quarter of 2017.

Operating costs were 66% of revenue for the quarter which was two percentage points lower than the prior year period. On a per utilization day basis, operating costs for the drilling rig division in Canada were higher than the prior year period primarily because of larger average crew sizes and higher repairs and maintenance costs related to the timing of 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 higher lump sum move costs in the prior period and the impact of fixed costs spread over higher activity partially offset by higher costs associated with turnkey activity.

Depreciation expense in the quarter was 10% lower than in the first quarter of 2017. The decrease in depreciation expense was primarily due to the strengthening of the Canadian dollar on our U.S. dollar denominated costs and a lower capital asset base as assets become fully depreciated.

SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES

		Three months ended March 31,
(Stated in thousands of Canadian dollars, except where noted)			2018				2017				% Change
Revenue			50,042				46,349				8.0
Expenses:
Operating			43,264				39,868				8.5
General and administrative			2,134				1,894				12.7
Adjusted EBITDA(1)			4,644				4,587				1.2
Depreciation			6,875				7,403				(7.1	)
Operating loss(1)			(2,231	)			(2,816	)			(20.8	)
Operating loss as a percentage of revenue			(4.5	)%			(6.1	)%
Well servicing statistics:
Number of service rigs (end of period)			210				210				-
Service rig operating hours			52,701				52,057				1.2
Service rig operating hour utilization			28	%			28	%			-
Service rig revenue per operating hour			700				636				10.1

(1) See “NON-GAAP MEASURES”.

Revenue from Completion and Production Services was up $4 million or 8% compared with the first quarter of 2017 due to higher activity in our Canada well servicing and our camp and catering businesses partially offset by lower activity in our rental business where we sold certain U.S. assets. Our well servicing activity in the quarter was up 1% from the first quarter of 2017 while rates increased an average of 10%. Approximately 97% of our first quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 94% of its revenue from Canadian operations and 6% from U.S. operations compared with the first quarter of 2017 of 91% from Canada and 9% from U.S. operations.

Average service rig revenue per operating hour in the quarter was $700 or $64 higher than the first quarter of 2017. The increase was primarily the result of rig mix and higher costs associated with increased northern work which were passed through to the customer.

Adjusted EBITDA was in-line with the first quarter of 2017 as increased revenue was the result of the recovery of increased costs in our Canada well servicing business.

Operating costs as a percentage of revenue was in-line with the prior year comparative quarter at 86%.

Depreciation in the quarter was $1 million lower than the prior year comparative period. The lower depreciation is due to a lower asset base as assets become fully depreciated.

8

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 $18 million a $4 million greater loss compared with the first quarter of 2017 primarily due to higher share-based incentive compensation.

OTHER ITEMS

Net financial charges for the quarter were $32 million, a decrease of $1 million compared with the first quarter of 2017 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 2017 partially offset by lower interest income in the current period.

Income tax expense for the quarter was a recovery of $5 million compared with a recovery of $23 million in the same quarter in 2017. The recoveries are due to negative pretax earnings.

LIQUIDITY AND CAPITAL RESOURCES

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

Our maintenance capital expenditures are tightly governed by and highly responsive to activity levels with additional cost savings leverage provided through our internal manufacturing and supply 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.

As at March 31, 2018 we had $1,804 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 March 31, 2018 our consolidated senior debt to Covenant EBITDA ratio was 0.08:1.

9

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 period ending 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 March 31, 2018 our senior credit facility consolidated Covenant EBITDA to consolidated interest expense ratio was 2.34:1.

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 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 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.

Senior Notes

The senior notes require that we comply with financial covenants including an incurrence based consolidated interest coverage ratio test of consolidated cash flow, as defined in the senior note agreements, to consolidated interest expense of greater than 2.0:1 for the most recent four consecutive fiscal quarters. In the event 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 March 31, 2018, our senior notes consolidated interest coverage ratio was 2.29:1.

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 as a result of changes in foreign exchange rates.

We have designated our U.S. dollar denominated long-term debt as a net investment hedge in our U.S. operations and other foreign operations that have a U.S. dollar functional currency. To be accounted for as a hedge, the foreign currency denominated long-term debt must be designated and documented as such and must be effective at inception and on an ongoing basis. We recognize the effective amount of this hedge (net of tax) in other comprehensive income. We recognize ineffective amounts (if any) in net earnings (loss).

10

QUARTERLY FINANCIAL SUMMARY

(Stated in thousands of Canadian dollars, except per share amounts)		2017												2018
Quarters ended		June 30				September 30				December 31				March 31
Revenue			290,860				314,504				347,187				401,006
Adjusted EBITDA(1)			56,520				73,239				90,914				97,469
Net loss			(36,130	)			(26,287	)			(47,005	)			(18,077	)
Net loss per basic and diluted share			(0.12	)			(0.09	)			(0.16	)			(0.06	)
Funds provided by (used in) operations(1)			(15,187	)			85,140				28,323				104,026
Cash provided by operations			2,739				56,757				23,289				38,189

(Stated in thousands of Canadian dollars, except per share amounts)		2016												2017
Quarters ended		June 30				September 30				December 31				March 31
Revenue			170,407				213,668				302,653				368,673
Adjusted EBITDA(1)			22,400				41,411				65,000				84,308
Net loss			(57,677	)			(47,377	)			(30,618	)			(22,614	)
Net loss per basic and diluted share			(0.20	)			(0.16	)			(0.10	)			(0.08	)
Funds provided by (used in) operations(1)			(31,372	)			31,688				11,466				85,659
Cash provided by (used in) operations			20,665				17,515				(27,846	)			33,770

(1) Prior year comparatives have changed to reflect a recast of certain amounts previously netted against operating expense. See our 2017 Annual Report.

(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 2017 Annual Report and there have been no material changes to our critical accounting judgments and estimates during the three months ended March 31, 2018 except for those impacted by the adoption of new accounting standards.

CHANGES IN ACCOUNTING POLICY

New standards adopted

The following standards became effective on January 1, 2018:

• IFRS 9 Financial Instruments

• IFRS 15 Revenue from Contracts with Customers

The Corporation adopted these standards using the cumulative-effect method with no material impact or adjustment to the consolidated financial statements on the date of adoption. Please see the unaudited March 31, 2018 Interim Consolidated Financial Statements and related notes for further details on the adoption of these standards.

New standards not yet adopted

IFRS 16 Leases

IFRS 16 introduces a comprehensive model for the identification of lease arrangements and accounting treatments for both lessors and lessees. It replaces existing lease guidance including IAS 17 Leases and IFRIC 4 Determining whether an Arrangement contains a lease. The new standard is effective for annual periods beginning on or after January 1, 2019, with earlier application permitted for entities that apply IFRS 15 at or before the date of initial adoption of IFRS 16.

IFRS 16 brings most leases on-balance sheet for lessees under a single model, eliminating the distinction between operating and finance leases. A right-of use asset and a corresponding liability will be recognized for all leases by the lessee except for short-term leases and leases of low value assets.

The Corporations initial assessment indicates that many of the operating lease arrangements will meet the definition of a lease under IFRS 16 and thus be recognized in the Statement of Financial Position as a right-of-use asset with a corresponding liability. In addition, the nature of expenses related to these arrangements will change as the current presentation of lease expense will be replaced with a depreciation charge for the right-of use asset and interest expense on the lease liabilities. As well, the classification of cash flows will be impacted as the current presentation of lease payments as operating cash flows will be split into financing (principal portion) and operating (interest portion) cash flows under IFRS 16.

Lessor accounting will not significantly change under the new standard. However, some differences may arise as a result of new guidance on the definition of a lease. Under IFRS 16 a contract is, or contains a lease if the contract conveys control of the use of an identified asset for a period of time in exchange for some form of consideration. Precision is assessing whether this new guidance will impact the treatment of its drilling rigs under long term contracts.

11

Additional disclosures will also be required under IFRS 16.

Precision plans to apply IFRS 16 initially on January 1, 2019 using the cumulative effect method whereby the cumulative impact of adopting the standard will be recognized in retained earnings as of January 1, 2019 and the comparative periods will not be restated.

IFRIC 23 Uncertainty over Income Tax Treatments

IFRIC 23 clarifies the accounting for uncertainties in income taxes. The interpretation requires the entity to use the most likely amount or the expected value of the tax treatment if it concludes that it is not probable that a particular tax treatment will be accepted. It requires an entity to assume that a taxation authority with the right to examine any amounts reported to it will examine those amounts and will have full knowledge of all relevant information when doing so.

IFRIC 23 is effective for annual reporting periods beginning on or after 1 January 2019. Earlier application is permitted. The requirements are applied by recognizing the cumulative effect of initially applying them in retained earnings, or in other appropriate components of equity, at the start of the reporting period in which an entity first applies them, without adjusting comparative information. Full retrospective application is permitted, if an entity can do so without using hindsight. The Corporation has yet to determine the impact this standard will have on its consolidated financial statements.

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, finance charges, foreign exchange, and depreciation and amortization), as reported in the Interim Consolidated Statement of Loss, is a useful measure, because it gives an indication of the results from our principal business activities prior to consideration of how our activities are financed and the impact of foreign exchange, taxation and depreciation and amortization charges.

Covenant EBITDA

Covenant EBITDA, as defined in our senior credit facility agreement, is used in determining the Corporation’s compliance with its covenants. Covenant EBITDA differs from Adjusted EBITDA by the exclusion of bad debt expense, restructuring costs 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.

12

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;

• anticipated activity levels in 2018 and our scheduled infrastructure projects;

• anticipated demand for Tier 1 rigs; and

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

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

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

• the status of current negotiations with our customers and vendors;

• customer focus on safety performance;

• existing term contracts are neither renewed nor terminated prematurely;

• our ability to deliver rigs to customers on a timely basis; and

• the general stability of the economic and political environments in the jurisdictions where we operate.

Undue reliance should not be placed on forward-looking information and statements. Whether actual results, performance or achievements will conform to our expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results to differ materially from our expectations. Such risks and uncertainties include, but are not limited to:

• volatility in the price and demand for oil and natural gas;

• fluctuations in the demand for contract drilling, well servicing and ancillary oilfield services;

• our customers’ inability to obtain adequate credit or financing to support their drilling and production activity;

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

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

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

• the availability of qualified personnel and management;

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

• changes in environmental laws and regulations such as increased regulation of hydraulic fracturing or restrictions on the burning of fossil fuels and greenhouse gas emissions, which could have an adverse impact on the demand for oil and gas;

• terrorism, social, civil and political unrest in the foreign jurisdictions where we operate;

• fluctuations in foreign exchange, interest rates and tax rates; and

• other unforeseen conditions which could impact the use of services supplied by Precision and Precision’s ability to respond to such conditions.

Readers are cautioned that the forgoing list of risk factors is not exhaustive. Additional information on these and other factors that could affect our business, operations or financial results are included in reports on file with applicable securities regulatory authorities, including but not limited to Precision’s Annual Information Form for the year ended December 31, 2017, 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 result of new information, future events or otherwise, except as required by law.

13

SHAREHOLDER INFORMATION   STOCK EXCHANGE LISTINGS Shares of Precision Drilling Corporation are listed on the Toronto Stock Exchange under the trading symbol PD and on the New York Stock Exchange under the trading symbol PDS.   TRANSFER AGENT AND REGISTRAR Computershare Trust Company of Canada Calgary, Alberta   TRANSFER POINT Computershare Trust Company NA Canton, Massachusetts   Q1 2018 TRADING PROFILE Toronto (TSX: PD) High: $4.84 Low: $3.43 Close: $3.58 Volume Traded: 182,029,701 New York (NYSE: PDS) High: US$3.93 Low: US$2.65 Close: US$2.77 Volume Traded: 181,430,800   ACCOUNT QUESTIONS Precision’s Transfer Agent can help you with a variety of shareholder related services, including:   •  change of address •  lost unit certificates •  transfer of shares to another person •  estate settlement   Computershare Trust Company of Canada 100 University Avenue 9th Floor, North Tower Toronto, Ontario M5J 2Y1 Canada   1-800-564-6253 (toll free in Canada and the United States) 1-514-982-7555 (international direct dialing) Email: service@computershare.com   ONLINE INFORMATION To receive news releases by email, or to view this interim report online, please visit Precision’s website at www.precisiondrilling.com and refer to the Investor Relations section. Additional information relating to Precision, including the Annual Information Form, Annual Report and Management Information Circular has been filed with SEDAR and is available at www.sedar.com and on the EDGAR website www.sec.gov CORPORATE INFORMATION   DIRECTORS Michael R. Culbert William T. Donovan Brian J. Gibson Allen R. Hagerman, FCA Catherine J. Hughes Steven W. Krablin Stephen J.J. Letwin Susan M. MacKenzie Kevin O. Meyers Kevin A. Neveu   OFFICERS Kevin A. Neveu President and Chief Executive Officer   Douglas B. Evasiuk Senior Vice President, Sales and Marketing   Veronica H. Foley Senior Vice President, General Counsel and Corporate Secretary   Carey T. Ford Senior Vice President and Chief Financial Officer   Darren J. Ruhr Senior Vice President, Corporate Services   Gene C. Stahl President, Drilling Operations   AUDITORS KPMG LLP Calgary, Alberta   HEAD OFFICE Suite 800, 525 8 th Avenue SW Calgary, Alberta, Canada T2P 1G1 Telephone: 403-716-4500 Facsimile: 403-264-0251 Email: info@precisiondrilling.com www.precisiondrilling.com  

14