EX-99.1 4 exh99_1.htm EXHIBIT 99.1

Exhibit 99.1

Precision Drilling Corporation

First Quarter Report for the three months ended March 31, 2017 and 2016

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s Discussion and Analysis for the three month period ended March 31, 2017 of Precision Drilling Corporation (“Precision” or the “Corporation”) prepared as at April 21, 2017 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 2016 Annual Report, Annual Information Form, unaudited March 31, 2017 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, Operating Earnings (Loss) and Funds Provided by Operations.  These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies, see “Non-GAAP Measures” on page 12 of this report.

Precision Drilling announces 2017 first quarter financial results:

· First quarter revenue of $346 million was an increase of 15% over the prior year comparative quarter.

· First quarter earnings before income taxes, gain on repurchase of unsecured senior notes, finance charges, foreign exchange, and depreciation and amortization (adjusted EBITDA see “NON-GAAP MEASURES”) of $84 million was 15% lower than the first quarter of 2016.

· First quarter net loss of $23 million compared with a net loss of $20 million in the prior year comparative period.

· First quarter net loss per share of $0.08 compared with a net loss of $0.07 per share in the prior year comparative period.

· First quarter capital expenditures were $22 million, with full year capital spending expected to be $119 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)		2017				2016				% Change
Revenue			345,800				301,727				14.6
Adjusted EBITDA(1)			84,308				99,264				(15.1	)
Net loss			(22,614	)			(19,883	)			13.7
Cash provided by operations			33,770				112,174				(69.9	)
Funds provided by operations(1)			85,659				93,593				(8.5	)
Capital spending:
Expansion			3,792				19,201				(80.3	)
Upgrade			13,647				1,433				852.3
Maintenance and infrastructure			4,653				6,527				(28.7	)
Proceeds on sale			(2,218	)			(2,157	)			2.8
Net capital spending			19,874				25,004				(20.5	)
Net loss per share:
Basic			(0.08	)			(0.07	)			(14.3	)
Diluted			(0.08	)			(0.07	)			(14.3	)

(1) See “NON-GAAP MEASURES”

Operating Highlights

						Three months ended March 31,
		2017				2016				% Change
Contract drilling rig fleet			255				251				1.6
Drilling rig utilization days: Canada			6,819				3,995				70.7
U.S.			4,190				2,886				45.2
International			720				763				(5.6	)
Revenue per utilization day:
Canada (1)(3) (Cdn$)			18,524				23,880				(22.4	)
U.S.(2)(3) (US$)			19,972				31,830				(37.3	)
International (US$)			50,434				41,609				21.2
Operating cost per utilization day:
Canada (Cdn$)			9,947				10,899				(8.7	)
U.S. (US$)			14,682				16,656				(11.9	)
Service rig fleet			210				163				28.8
Service rig operating hours			52,057				24,831				109.6
Revenue per operating hour (Cdn$)			636				745				(14.6	)

(1) Includes lump sum revenue from contract shortfall.

(2) Includes revenue from idle but contracted rig days.

(3) 2016 comparative includes revenue from contract cancellation payments.

2

Financial Position

(Stated in thousands of Canadian dollars, except ratios)		March 31, 2017				December 31, 2016
Working capital			248,892				230,874
Cash			120,580				115,705
Long-term debt(1)			1,892,739				1,906,934
Total long-term financial liabilities			1,918,636				1,946,742
Total assets			4,261,536				4,324,214
Long-term debt to long-term debt plus equity ratio(1)			0.49				0.49

(1) Net of unamortized debt issue costs.

Summary for the three months ended March 31, 2017:

• Revenue this quarter was $346 million which is 15% higher than the first quarter of 2016.  The increase in revenue is primarily the result of greater activity in all of our North American based businesses and higher average day rates from our international contract drilling business partially offset by lower contract short-fall payments, a decrease in average day rates in all of our North American businesses and no utilization in our Mexico based contract drilling business.  Compared with the first quarter of 2016 our activity for the quarter, as measured by drilling rig utilization days, increased 71% in Canada and 45% in the U.S. and it decreased 6% internationally.  Revenue from our Contract Drilling Services and Completion and Production Services segments both increased over the comparative prior year period by 10% and 63%, respectively.

• Adjusted EBITDA this quarter of $84 million is a decrease of $15 million from the first quarter of 2016. Our adjusted EBITDA as a percentage of revenue was 24% this quarter, compared with 33% in the first quarter of 2016. The decrease in adjusted EBITDA as a percent of revenue was mainly due to lower average day rates in North America and lower contract shortfall payments in the U.S.  During the quarter, we incurred costs associated with repositioning drilling rigs to higher demand basins and time-based maintenance.  These costs were primarily incurred in our U.S. operations.

• Operating loss (see “NON-GAAP MEASURES”) this quarter was $13 million compared with operating earnings of $4 million in the first quarter of 2016.  Operating results this quarter were negatively impacted by decreased pricing in all of our North American businesses.

• General and administrative expenses this quarter were $25 million, $2 million lower than the first quarter of 2016.  The decrease is due to cost saving initiatives undertaken in 2016 and a moderate strengthening of the Canadian dollar on our U.S. dollar denominated costs partially offset by an increase in our share based incentive compensation that is tied to the price of our common shares.

• Net finance charges were $33 million, a decrease of $3 million compared with the first quarter of 2016 primarily due to a reduction in interest expense related to debt retired in 2016.

• Average revenue per utilization day for contract drilling rigs decreased in the first quarter of 2017 to $18,524 from the prior year first quarter of $23,880 in Canada and decreased in the U.S. to US$19,972 from US$31,830.  The decrease in Canada is the result of lower spot market rates and a higher proportion of revenue from shallower drilling activity relative to the 2016 comparative period.  During the quarter, we recognized $9 million in revenue associated with contract shortfall payments in Canada which was in line with shortfall and contract cancellation revenue recognized in the prior year period.  The decrease in the U.S. revenue rate is the result of fewer rigs working under long-term contracts and a lower daily revenue impact from idle but contracted rigs.  We recognized US$1 million in turnkey revenue compared with US$6 million in the 2016 comparative period and US$3 million in idle but contracted revenue in the current quarter versus US$7 million in the comparative period.  In the U.S. for the prior year comparative quarter, we recognized US$13 million in incremental revenue related to three one-time payments for contract terminations.

3

· Average operating costs per utilization day for drilling rigs in Canada decreased to $9,947 compared with the prior year first quarter of $10,899.  The decrease in average costs is due to cost saving initiatives and improved absorption of fixed costs with a higher utilization base. In the U.S., operating costs for the quarter on a per day basis decreased to US$14,682 in 2017 compared with US$16,656 in 2016 due to fixed costs spread over higher utilization partially offset by costs associated with repositioning drilling rigs to more active basins and completing time-based maintenance.  In addition, higher turnkey activity increased per day costs in 2016.

· We realized revenue from international contract drilling of US$36 million in the first quarter of 2017, a US$5 million increase over the prior year period.  The increase was due to the startup of two new rigs in Kuwait in the fourth quarter of 2016 partially offset by a reduction in activity in our Mexico operations. Average revenue per utilization day in our international contract drilling business was US$50,434 an increase of 21% over the comparable prior year quarter primarily due to rig mix as we had fewer rigs working in the lower day rate jurisdictions.

· Directional drilling services realized revenue of $13 million in the first quarter of 2017 compared with $8 million in the prior year period.  The increase was primarily the result of increased activity in Canada and a greater proportion of higher day rate activity in the U.S.

· Funds provided by operations in the first quarter of 2017 were $86 million, a decrease of $8 million from the prior year comparative quarter of $94 million.  The decrease was primarily the result of lower operating results.

· Capital expenditures for the purchase of property, plant and equipment were $22 million in the first quarter, a decrease of $5 million over the same period in 2016.  Capital spending for the quarter included $4 million for expansion capital, $13 million for upgrade capital and $5 million for the maintenance of existing assets and infrastructure spending.

STRATEGY

Precision’s strategic priorities for 2017 are as follows:

1. Deliver High Performance, High Value service offering in an improving demand environment while demonstrating fixed cost leverage – In the U.S., we grew our active rig count by 44% throughout the first quarter of 2017, the highest quarterly growth in our history. In Canada, we began the year with 50 active rigs and reached a seasonal peak of 91 rigs. Year-over-year our first quarter utilization days were up 60% across our North American drilling operations and was achieved without any meaningful increase in fixed costs.

2. Commercialize rig automation and efficiency-driven technologies across our Super Series fleet – Beta-style field trials utilizing rig automation technologies, including advisory software and wired drill pipe are ongoing and we expect to commercialize these automation features during 2017.

3. Maintain strict financial discipline in pursuing growth opportunities with a focus on free cash flow and debt reduction – Effectively all upgrade capital spending is supported by take-or-pay term contracts priced at a level that allows for attractive rates of return. In the first quarter, we generated funds from operations of $86 million – see “NON-GAAP MEASURES.”

4

OUTLOOK

For the first quarter of 2017, the average West Texas Intermediate price of oil and average Henry Hub natural gas price were 55% higher than the prior year comparative period.

		Three months ended March 31,								Year ended December 31,
		2017				2016				2016
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)			52.00				33.51				43.30
Natural gas
Canada
AECO (per MMBtu) (CDN$)			2.63				1.84				2.14
United States
Henry Hub (per MMBtu) (US$)			3.07				1.98				2.48

Contracts

The following chart outlines the average number of drilling rigs that we have under contract as of April 21, 2017 for the remaining quarters of 2017 and the full years 2017 and 2018.

						Average for the quarter ended 2017												Average for the year ended
		March 31				June 30				September 30				December 31				2017				2018
Average rigs under term contract as of April 21, 2017:
Canada			27				22				17				15				20				8
U.S.			26				30				27				19				26				6
International			8				8				8				8				8				7
Total			61				60				52				42				54				21

In Canada, term contracted rigs normally generate 250 utilization days per year because of the seasonal nature of well site access.  In most regions in the U.S. and internationally, term contracts normally generate 365 utilization days per year.  Year to date as of April 21, 2017 we have added nine 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.

						Average for the quarter ended 2016												2017
		March 31				June 30				September 30				December 31				March 31
Average Precision active rig count:
Canada			44				13				31				51				76
U.S.			32				24				29				39				47
International			8				7				7				8				8
Total			84				44				67				98				131

In general, lower oil prices caused producers to significantly reduce their drilling budgets in 2015 and 2016, decreasing demand for drilling rigs, resulting in pricing pressure on spot market day rates and significantly depressed industry activity levels. Following OPEC’s actions to limit production to stabilize oil prices, we have experienced increased demand for our rigs and if current commodity prices continue to improve we expect our customers to enhance their drilling programs further strengthening rig demand. 

5

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

Industry Conditions

In 2017, drilling activity has increased relative to this time last year for both Canada and the U.S.  According to industry sources, as of April 21, 2017, the U.S. active land drilling rig count was up approximately 107% from the same point last year and the Canadian active land drilling rig count was up approximately 148%.

In Canada there has been a strengthening in natural gas and gas liquids drilling activity related to Deep Basin drilling in northwestern Alberta and northeastern British Columbia while the trend towards oil-directed drilling in the U.S. continues. To date in 2017, approximately 53% of the Canadian industry’s active rigs and 80% of the U.S. industry’s active rigs were drilling for oil targets, compared with 46% for Canada and 80% for the U.S. at the same time last year.

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

Capital Spending

Capital spending in 2017 is expected to be $119 million:

• The 2017 capital expenditure plan includes $13 million for expansion capital, $52 million for sustaining and infrastructure expenditures, and $54 million to upgrade existing rigs. We expect that the $119 million will be split $113 million in the Contract Drilling Services segment and $6 million in the Completion and Production Services 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 wastewater treatment divisions.

		Three months ended March 31,
(Stated in thousands of Canadian dollars)		2017				2016				% Change
Revenue:
Contract Drilling Services			301,057				274,837				9.5
Completion and Production Services			46,349				28,454				62.9
Inter-segment eliminations			(1,606	)			(1,564	)			2.7
			345,800				301,727				14.6
Adjusted EBITDA:(1)
Contract Drilling Services			93,665				115,617				(19.0	)
Completion and Production Services			4,587				(2,207	)			(307.8	)
Corporate and other			(13,944	)			(14,146	)			(1.4	)
			84,308				99,264				(15.1	)

(1) See “NON-GAAP MEASURES”.

6

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

(Stated in thousands of Canadian dollars, except where noted)		Three months ended March 31
		2017				2016				% Change
Revenue			301,057				274,837				9.5
Expenses:
Operating(1)			197,944				147,179				34.5
General and administrative(1)			9,448				10,085				(6.3	)
Restructuring			-				1,956				(100.0	)
Adjusted EBITDA(2)			93,665				115,617				(19.0	)
Depreciation			86,189				84,279				(2.3	)
Operating earnings(2)			7,476				31,338				(76.1	)
Operating earnings as a percentage of revenue			2.5	%			11.4	%

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

(2) See “NON-GAAP MEASURES”.

		Three months ended March 31,
Canadian onshore drilling statistics:(1)		2017								2016
		Precision				Industry(2)				Precision				Industry(2)
Number of drilling rigs (end of period)			135				641				135				687
Drilling rig operating days (spud to release)			6,041				23,323				3,571				13,166
Drilling rig operating day utilization			50	%			41	%			26	%			20	%
Number of wells drilled			564				2,284				249				1,062
Average days per well			10.7				10.2				14.3				12.4
Number of metres drilled (000s)			1,471				6,160				688				2,829
Average metres per well			2,608				2,697				2,765				2,664
Average metres per day			243				264				193				215

(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

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $301 million this quarter, or 10% higher than the first quarter of 2016, while adjusted EBITDA decreased by 19% to $94 million.  The increase in revenue was due to higher utilization days in Canada and the U.S. and higher average day rates for international contract drilling.  During the quarter we recognized $9 million in shortfall payments in our Canadian contract drilling business, which was in line with the combined shortfall and contract termination payments received in the prior year comparative quarter.  During the quarter in the U.S. we recognized US$3 million of idle but contracted revenue compared with a combined US$24 million in idle but contracted and contract termination payments in the comparative quarter of 2016.

Drilling rig utilization days in Canada (drilling days plus move days) were 6,819 during the first quarter of 2017, an increase of 71% 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 4,190, or 45% higher than the same quarter of 2016 as U.S. activity was up with higher industry activity.  Drilling rig utilization days in our international business were 720 or 6% lower than the same quarter of 2016 due to lower activity in Mexico partially offset by the addition of two rigs in Kuwait during the fourth quarter of 2016.

7

Compared with the same quarter in 2016, drilling rig revenue per utilization day was down 22% in Canada due to the decline of spot market rates as the drop in industry activity has led to a more competitive pricing environment.  Drilling rig revenue per utilization day for the quarter in the U.S. was down 37% from the prior comparative period, while international revenue per utilization day was up 21%.  The decrease in the U.S. average rate was due to lower spot market rates and lower relative idle but contracted revenue.   International revenue per utilization day was up due to rig mix with a higher proportion of days from Kuwait during the quarter and lower activity in Mexico.

In Canada, 31% of our utilization days in the quarter were generated from rigs under term contract, compared with 44% in the first quarter of 2016.  In the U.S., 54% of utilization days were generated from rigs under term contract as compared with 65% in the first quarter of 2016.

Operating costs were 66% of revenue for the quarter, which was 12 percentage points higher than the prior year period.  On a per utilization day basis, operating costs for the drilling rig division in Canada were lower than the prior year period primarily because of the impact of higher activity on fixed costs.  In the U.S., operating costs for the quarter on a per day basis were lower than the prior year period primarily due to lower turnkey costs and the impact of fixed costs spread over higher activity partially offset by higher costs associated with rig repositioning and time-based maintenance. Both Canada and U.S. operating costs benefited from cost saving initiatives taken in 2015 and 2016.

Depreciation expense in the quarter was 2% higher than in the first quarter of 2016.

SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES

		Three months ended March 31,
(Stated in thousands of Canadian dollars, except where noted)		2017				2016				% Change
Revenue			46,349				28,454				62.9
Expenses:
Operating(1)			39,868				26,222				52.0
General and administrative(1)			1,894				3,020				(37.3	)
Restructuring			-				1,419				(100.0	)
Adjusted EBITDA(2)			4,587				(2,207	)			(307.8	)
Depreciation			7,403				7,210				2.7
Operating loss(2)			(2,816	)			(9,417	)			(70.1	)
Operating loss as a percentage of revenue			(6.1	%)			(33.1	%)
Well servicing statistics:
Number of service rigs (end of period)			210				163				28.8
Service rig operating hours			52,057				24,831				109.6
Service rig operating hour utilization			28	%			16	%
Service rig revenue per operating hour			636				745				(14.6	)

(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 $18 million or 63% compared with the first quarter of 2016 due to higher activity levels in all service lines partially offset by lower average rates.  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 110% from the first quarter of 2016.  Approximately 82% of our first quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 91% of its revenue from Canadian and 9% from U.S. operations as compared to the first quarter of 2016 of 90% from Canadian and 10% from U.S. operations.

Average service rig revenue per operating hour in the quarter was $636 or $109 lower than the first quarter of 2016.  The decrease was primarily the result of industry pricing pressure.

8

Adjusted EBITDA was $7 million higher than the first quarter of 2016 as increased activity combined with cost cutting initiatives more than offset lower rates.

Operating costs as a percentage of revenue decreased to 86% in the first quarter of 2017, from 92% in the first quarter of 2016.  The decrease is the result of the impact of fixed costs spread across greater activity combined with our reduced cost structure.

Depreciation in the quarter was 3% higher than the first quarter of 2016 due to the addition of well servicing units offset by assets becoming fully depreciated.

SEGMENT REVIEW OF CORPORATE AND OTHER

Our Corporate and Other segment provides support functions to our operating segments. The Corporate and Other segment had an adjusted EBITDA loss of $14 million in line with the first quarter of 2016 as slightly higher share based incentive compensation was offset by cost saving initiatives.

OTHER ITEMS

Net financial charges for the quarter were $33 million, a decrease of $3 million compared with the first quarter of 2016 primarily due to a reduction in interest expense related to debt retired in 2016.  For the current quarter we incurred a nominal foreign exchange loss compared with a loss of $8 million during the first quarter of 2016.

Income tax expense for the quarter was a recovery of $23 million compared with a recovery of $15 million in the same quarter in 2016. The recoveries are due to negative pretax earnings.

LIQUIDITY AND CAPITAL RESOURCES

The oilfield services business is inherently cyclical in nature. To manage this, we focus on maintaining a strong balance sheet so we have the financial flexibility we need to continue to manage our growth and cash flow, regardless of where we are in the business cycle.

We apply a disciplined approach to managing and tracking results of our operations to keep costs down. We maintain a variable cost structure so we can be responsive to changes in demand.

Our maintenance capital expenditures are tightly governed by and highly responsive to activity levels with additional cost savings leverage provided through our internal manufacturing and supply divisions. Term contracts on expansion capital for new-build rig programs provide more certainty of future revenues and return on our capital investments.

Liquidity

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

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

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

9

As at March 31, 2017 we had $1,919 million outstanding under our senior unsecured notes.  The current blended cash interest cost of our debt is approximately 6.5%.

Amount	Availability	Used for	Maturity
Senior facility (secured)
US$525 million (extendible, revolving term credit facility with US$250 million(1) accordion feature)	Drawn US$41 million in outstanding letters of credit	General corporate purposes	June 3, 2019
Operating facilities (secured)
$40 million	Undrawn, except $22 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$5 million in outstanding letters of credit	Letters of credit
Senior notes  (unsecured)
US$372 million – 6.625%	Fully drawn	Debt repayment and general corporate purposes	November 15, 2020
US$319 million – 6.5%	Fully drawn	Capital expenditures and general corporate purposes	December 15, 2021
US$350 million – 7.75%	Fully drawn	Debt redemption and repurchases	December 15, 2023
US$400 million – 5.25%	Fully drawn	Capital expenditures and general corporate purposes	November 15, 2024

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

Covenants

Senior Facility

The senior credit facility requires that we comply with certain financial covenants including a leverage ratio of consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (Adjusted EBITDA) of less than 2.5:1. For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness. Adjusted EBITDA, as defined in our revolving term facility agreement differs from Adjusted EBITDA as defined under Non-GAAP Measures by the exclusion of bad debt expense, restructuring costs and certain foreign exchange amounts. As at March 31, 2017 our consolidated senior debt to Adjusted EBITDA ratio was negative 0.09:1.

Effective January 20, 2017, under the senior credit facility, we are required to maintain an Adjusted EBITDA coverage ratio, calculated as Adjusted EBITDA to interest expense for the most recent four consecutive quarters, of greater than 1.25:1 for the periods ending March 31, June 30 and September 30, 2017.  For the periods ending December 31, 2017 and March 31, 2018 the ratio is 1.5:1 reverting to 2.5:1 thereafter. As at March 31, 2017 our senior credit facility Adjusted EBITDA coverage ratio was 1.60:1.

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

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 March 31, 2017, we were in compliance with the covenants of the senior credit facility.

Senior Notes

The senior notes require that we comply with certain covenants including an incurrence based consolidated interest coverage ratio test, as defined in the senior note agreements, 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, 2017, our senior notes consolidated interest coverage ratio was 1.40:1 which limits our ability to incur additional indebtedness, except as permitted under the agreements, until such time as we are in compliance with the ratio test, but would not restrict our access to available funds under the senior credit facility or to refinance our existing debt. Furthermore, it does not give rise to any cross-covenant violations, give the lenders the right to demand repayment of any outstanding portion of the senior notes prior to the stated maturity dates, or provide any other forms of recourse to the lenders.

10

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 January 1, 2010 for the 2020, 2021 and 2024 Senior Notes and from November 1, 2016 for the 2023 Senior Notes by, among other things, 50% of consolidated net earnings and decreases by 100% of consolidated 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).

QUARTERLY FINANCIAL SUMMARY

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

						2016								2017
Quarters ended		June 30				September 30				December 31				March 31
Revenue			163,979				201,802				283,903				345,800
Adjusted EBITDA(1)			22,400				41,411				65,000				84,308
Net loss:			(57,677	)			(47,377	)			(30,618	)			(22,614	)
Per basic share			(0.20	)			(0.16	)			(0.10	)			(0.08	)
Per 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

(Stated in thousands of Canadian dollars, except per share amounts)						2015								2016
Quarters ended		June 30				September 30				December 31				March 31
Revenue			334,462				364,089				344,953				301,727
Adjusted EBITDA(1)			88,355				111,031				111,095				99,264
Net loss:			(29,817	)			(86,700	)			(270,952	)			(19,883	)
Per basic share			(0.10	)			(0.30	)			(0.93	)			(0.07	)
Per diluted share			(0.10	)			(0.30	)			(0.93	)			(0.07	)
Funds provided by operations(1)			53,173				99,228				49,503				93,593
Cash provided by operations			169,877				61,049				70,952				112,174
Dividends paid per share			0.07				0.07				0.07				-

(1) See “NON-GAAP MEASURES”.

11

NON-GAAP MEASURES

In this press release we reference non-GAAP (Generally Accepted Accounting Principles) measures.  Adjusted EBITDA, Operating Earnings (Loss) and Funds Provided by Operations are terms used by us to assess performance as we believe they provide useful supplemental information to investors.  These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies.

Adjusted EBITDA

We believe that adjusted EBITDA (earnings before income taxes, gain on repurchase of unsecured senior notes, financing charges, foreign exchange and depreciation and amortization), as reported in the Interim Consolidated Statement of Loss, is a useful measure, because it gives an indication of the results from our principal business activities prior to consideration of how our activities are financed and the impact of foreign exchange, taxation and non-cash impairment, decommissioning, depreciation and amortization charges.

Operating Earnings (Loss)

We believe that operating earnings (loss), as reported in the Interim Consolidated Statements of Loss, is a useful measure because it provides an indication of the results of our principal business activities before consideration of how those activities are financed and the impact of foreign exchange and taxation.

Funds Provided by Operations

We believe that funds provided by 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.

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 2017;

· our capital expenditure plans for 2017;

· anticipated activity levels in 2017 and our scheduled infrastructure projects;

· anticipated demand for Tier 1 rigs; and

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

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

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

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

· customer focus on safety performance;

· existing term contracts are neither renewed nor terminated prematurely;

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

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

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

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

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

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

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

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

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

· the availability of qualified personnel and management;

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

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

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

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

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

Readers are cautioned that the forgoing list of risk factors is not exhaustive.  Additional information on these and other factors that could affect our business, operations or financial results are included in reports on file with applicable securities regulatory authorities, including but not limited to Precision’s Annual Information Form for the year ended December 31, 2016, which may be accessed on Precision’s SEDAR profile at www.sedar.com or under Precision’s EDGAR profile at www.sec.gov.  The forward-looking information and statements contained in this news release are made as of the date hereof and Precision undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a results of new information, future events or otherwise, except as required by law.

13