Precision Drilling Corporation

First Quarter Report for the three months ended March 31, 2016 and 2015

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's Discussion and Analysis for the three month period ended March 31, 2016 of Precision Drilling Corporation ("Precision" or the "Corporation") prepared as at April 22, 2016 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 2015 Annual Report, Annual Information Form, unaudited March 31, 2016 Interim Consolidated Financial Statements and related notes and the cautionary statement regarding forward-looking information and statements on page 12 of this report.

SELECT FINANCIAL AND OPERATING INFORMATION

Adjusted EBITDA and funds provided by operations are additional GAAP measures. See "ADDITIONAL GAAP MEASURES".

Financial Highlights

	Three months ended March 31,
(Stated in thousands of Canadian dollars, except per share amounts)	2016			2015			% Change
Revenue	$	301,727		$	512,120			(41.1	)
Adjusted EBITDA		99,264			163,384			(39.2	)
Net earnings (loss)		(19,883	)		24,033			(182.7	)
Cash provided by operations		112,174			215,138			(47.9	)
Funds provided by operations		93,593			155,186			(39.7	)
Capital spending:
Expansion		19,201			197,317			(90.3	)
Upgrade		1,433			19,943			(92.8	)
Maintenance and infrastructure		6,527			8,562			(23.8	)
Proceeds on sale		(2,157	)		(2,876	)		(25.0	)
Net capital spending		25,004			222,946			(88.8	)

Earnings (loss) per share:
Basic		(0.07	)		0.08			(187.5	)
Diluted		(0.07	)		0.08			(187.5	)
Dividends paid per share		-			0.07			(100.0	)

Operating Highlights

	Three months ended March 31,
	2016		2015		% Change
Contract drilling rig fleet		251		323		(22.3	)
Drilling rig utilization days: Canada		3,995		6,230		(35.9	)
U.S.		2,886		7,197		(59.9	)
International		763		1,134		(32.7	)
Service rig fleet		163		177		(7.9	)
Service rig operating hours		24,831		48,001		(48.3	)

Financial Position

(Stated in thousands of Canadian dollars, except ratios)	March 31, 2016		December 31, 2015
Working capital		545,415		536,815
Cash		476,356		444,759
Long-term debt⁽¹⁾		2,042,846		2,180,510
Total long-term financial liabilities		2,066,452		2,210,231
Total assets		4,619,026		4,878,690
Long-term debt to long-term debt plus equity ratio⁽¹⁾		0.50		0.51

(1)

Net of unamortized debt issue costs.

Net loss for the quarter was $20 million, or net loss per diluted share of $0.07, compared to net earnings of $24 million, or $0.08 per diluted share, in the first quarter of 2015.

Revenue this quarter was $302 million or 41% lower than the first quarter of 2015, mainly due to lower drilling activity in the U.S., Canada and internationally. Revenue from our Contract Drilling Services and Completion and Production Services segments both decreased over the comparative prior year period by 39% and 57%, respectively.

Earnings before income taxes, gain on repurchase of unsecured senior notes, finance charges, foreign exchange, and depreciation and amortization (adjusted EBITDA see "Additional GAAP Measures") this quarter were $99 million or 39% lower than the first quarter of 2015. During the quarter, we received one-time contract cancellation payments related to five contract terminations, three in the U.S. and two in Canada for approximately $23 million that was expected to be earned beyond the first quarter of 2016, and incurred $3 million in restructuring costs.

Adjusted EBITDA as a percentage of revenue was 33% this quarter, compared to 32% in the first quarter of 2015. The increase in adjusted EBITDA as a percentage of revenue was mainly due to one-time payments received in the quarter related to contract cancellations partially offset by a decrease in activity in all of our businesses. Our activity for the quarter, as measured by drilling rig utilization days, decreased 36% in Canada, 60% in the U.S. and 33% internationally, compared to the first quarter of 2015.

Cash provided by operations for the quarter was $112 million, which was 48% lower than the first quarter of 2015 due to lower operating earnings compared with the first quarter of 2015.

We agreed with our lending group to amend our credit agreement governing our senior revolving credit facility to, among other things, amend the covenant of Adjusted EBITDA to consolidated interest expense from 2:1 to 1.5:1 reverting to 2.5:1 for periods ending after March 31, 2018. For more detail see the liquidity section later in this report.

Our portfolio of term customer contracts, a scalable operating cost structure and economies achieved through vertical integration of the supply chain all help us manage our business through the industry cycles.

Precision's strategic priorities for 2016 are as follows:

Maintain strong liquidity to manage through an extended downturn – Sustain adequate liquidity by generating positive operating cash flow, ensure access to our revolving credit facility, and begin a multi-year plan for net debt reduction.

Sustain High Performance, High Value service offering – Continue to deliver maximum efficiency and lower risks to support development drilling programs by operating the highest quality assets in the industry with well-trained, professional crews supported by robust systems that eliminate manual processes and improve automation throughout the Precision organization.

Position for an eventual rebound – Concurrent with right-sizing the organization for the extended downturn, we will take steps to prepare for a rebound:

Asset integrity – maintain high quality and integrity of our Tier 1 drilling fleet by utilizing spare equipment, avoiding fleet cannibalization and maintaining rigorous equipment standards.

People – retain field leadership within the organization, maintain relationships with former crew members and continue to develop leadership and skills of workers within our organization.

Ample liquidity – maintain strong liquidity to fund working capital requirements and other short term commitments that arise when activity levels increase.

For the first quarter of 2016, the average West Texas Intermediate price of oil and Henry Hub natural gas were 31% lower than the first quarter of 2015.

	Three months ended March 31,				Year ended December 31,
	2016		2015		2015
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)		33.51		48.74		48.77
Natural gas
Canada
AECO (per MMBtu) (CDN$)		1.84		2.78		2.70
United States
Henry Hub (per MMBtu) (US$)		1.98		2.86		2.60

Summary for the three months ended March 31, 2016:

• Operating earnings (see "Additional GAAP Measures" in this news release) this quarter of $4 million is a decrease of $43 million from the first quarter 2015. Operating results were negatively affected by the decrease in activity in all our operating segments partially offset by one-time payments received for contract shortfall and contract cancellations.

• General and administrative expenses this quarter were $28 million, $15 million lower than the first quarter of 2015. The decrease is due to efforts in reducing overhead through the down turn and a decrease in our share based incentive compensation that is tied to the price of our common shares partially offset by the weakening Canadian dollar on U.S. dollar denominated costs.

• Restructuring costs were $3 million in the quarter and were primarily related to severance costs associated with right-sizing the operations and administrative support for current activity levels.

• Net finance charges were $36 million, an increase of $17 million compared with the first quarter of 2015 primarily due to the recognition of $14 million interest revenue in the comparative quarter related to an income tax dispute settlement and the impact of foreign exchange on our U.S. dollar denominated interest.

• During the quarter we acquired and cancelled US$10 million face value of our 6.5% unsecured notes due 2021 for US$6 million, realizing a gain on cancellation of US$4 million.

• Average revenue per utilization day for contract drilling rigs increased in the first quarter of 2016 to $23,880 from the prior year first quarter of $23,515 in Canada and increased in the U.S. to US$31,830 from US$25,180. The increase in Canada is the result of an incremental one-time payment for the cancellation of two drilling rig contracts for $4 million. Excluding the contract cancellation payment, average revenue per day was $22,847 versus the prior year comparative of $23,515. The decrease in the quarter is the result of lower spot market rates. The increase in the U.S. is the result of three one-time payments for contract terminations of US$13 million in incremental revenue in the current quarter compared with none in the prior year comparative period. Excluding the contract cancellation payments average revenue per day was US$27,155 versus the prior year comparative period of US$25,180. The increase was primarily a result of revenue from idle but contracted rigs of $7 million compared with $5 million in the comparative period of 2015 and a higher proportion of turnkey work partially offset by lower spot market rates. We had US$6 million in turnkey revenue for the first quarter of 2016 compared with US$10 million in the 2015 comparative period.

• Average operating costs per utilization day for drilling rigs decreased in the first quarter of 2016 to $10,899 from the prior year first quarter of $11,527 in Canada and increased in the U.S. to US$16,656 in 2016 from US$14,075 in 2015. The cost decrease in Canada was primarily due to labour rate decreases and overhead cost reduction initiatives. The increase in the U.S. was primarily due to proportionately higher turnkey activity and fixed costs spread across lower activity.

• We realized revenue from international contract drilling of $44 million in the first quarter of 2016 down from the prior year first quarter of $61 million. Average revenue per utilization day decreased to US$41,609 from the prior year first quarter of US$42,968 with the decrease resulting from reduced activity in the northern region of Iraq and Georgia.

• Directional drilling services realized revenue of $8 million in the first quarter of 2016 compared with $15 million in the prior year period. The decrease was primarily the result of a decline in activity in both the U.S. and Canada.

• Funds provided by operations (see "Additional GAAP Measures") in the first quarter of 2016 were $94 million, a decrease of $62 million from the prior year comparative quarter of $155 million. The decrease was primarily the result of lower activity levels.

• Capital expenditures for the purchase of property, plant and equipment were $27 million in the first quarter, a decrease of $199 million over the same period in 2015. Capital spending for the first quarter of 2016 included $19 million for expansion capital, $1 million for upgrade capital and $7 million for the maintenance of existing assets and infrastructure spending.

OUTLOOK

Contracts

Our portfolio of term customer contracts provides a base level of activity and revenue and, as of April 25, 2016, we had term contracts in place for an average of 30 rigs in Canada, 21 in the U.S. and seven internationally for the second quarter of 2016, an average of 29 rig contracts in Canada, 20 in the U.S. and seven internationally for the full year in 2016, and an average of 31 rigs for the full year in 2017. 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

In the U.S., our average active rig count in the first quarter was 32 rigs, down 48 rigs over the first quarter in 2015 and down 13 rigs over the fourth quarter of 2015. To date in 2016, approximately 73% of our active rigs were drilling for oil targets versus 71% in 2015.We currently have 25 rigs active in the United States.

In Canada, our average active rig count in the first quarter was 44 rigs, a decrease of 25 rigs over the first quarter in 2015 and one fewer rig than fourth quarter of 2015. To date in 2016, approximately 40% of our active rigs were drilling for oil targets versus 62% in 2015. We currently have 13 rigs active in Canada.

In general, lower oil prices have caused producers to significantly reduce drilling budgets decreasing demand for drilling rigs and resulting in pricing pressure on spot market day rates. We expect Tier 1 rigs to remain the preferred rigs of customers globally and for us to benefit from our completed fleet enhancements.

Internationally, our average active rig count in the quarter was eight rigs, a decrease of four rigs over the first quarter in 2015 and down three rigs over the fourth quarter of 2015 with the decrease coming from fewer rigs working in Mexico. We currently have seven active rigs internationally.

Industry Conditions

Seasonally adjusted drilling activity consistently decreased in both Canada and the U.S. According to industry sources, as of April 22, 2016, the U.S. active land drilling rig count was down approximately 55% from the same point last year and the Canadian active land drilling rig count was down approximately 49%.

In Canada, there has been strength in natural gas and gas liquids drilling activity related to deep basin drilling in northwestern Alberta and northeastern British Columbia, while the bias towards oil-directed drilling in the U.S. continues. To date in 2016, approximately 80% of the U.S. industry's active rigs and 46% of the Canadian industry's active rigs were drilling for oil targets, compared to 79% for Canada and 45% for the U.S. at the same time last year.

Capital Spending

Capital spending in 2016 is expected to be $202 million:

•

The 2016 capital expenditure plan includes $158 million for expansion capital, $42 million for sustaining and infrastructure expenditures, and $2 million to upgrade existing rigs. We expect that the $202 million will be split $199 million in the Contract Drilling Services segment and $3 million in the Completion and Production Services segment.

•	Precision's expansion capital plan for 2016 includes two new-build drilling rigs for Kuwait, to be delivered late 2016.

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, coil tubing, rental, camp and catering and wastewater treatment divisions.

	Three months ended March 31,
(Stated in thousands of Canadian dollars)	2016			2015			% Change
Revenue:
Contract Drilling Services		274,837			448,065			(38.7	)
Completion and Production Services		28,454			66,082			(56.9	)
Inter-segment eliminations		(1,564	)		(2,027	)		(22.8	)
		301,727			512,120			(41.1	)

Adjusted EBITDA:⁽¹⁾
Contract Drilling Services⁽²⁾		115,617			180,196			(35.8	)
Completion and Production Services⁽²⁾		(2,207	)		7,057			(131.3	)
Corporate and other⁽²⁾		(14,146	)		(23,869	)		(40.7	)
		99,264			163,384			(39.2	)

(1) See "ADDITIONAL GAAP MEASURES".

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

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES


(Stated in thousands of Canadian dollars, except where noted)	Three months ended March 31,
	2016			2015			% Change
Revenue		274,837			448,065			(38.7	)
Expenses:⁽¹⁾
Operating		146,129			248,492			(41.2	)
General and administrative		11,135			15,868			(29.8	)
Restructuring		1,956			3,509			(44.3	)
Adjusted EBITDA⁽²⁾		115,617			180,196			(35.8	)
Depreciation		84,279			103,831			(18.8	)
Operating earnings⁽²⁾		31,338			76,365			(59.0	)
Operating earnings as a percentage of revenue		11.4	%		17.0	%
Drilling rig revenue per utilization day in Canada⁽³⁾		23,880			23,515			1.6
Drilling rig revenue per utilization day in the U.S.⁽³⁾⁽⁴⁾(US$)		31,830			25,180			26.4
Drilling rig revenue per utilization day international(US$)		41,609			42,969			(3.2	)

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

(2) See "ADDITIONAL GAAP MEASURES".

(3) Includes revenue from contract cancellation payments.

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

	Three months ended March 31,
Canadian onshore drilling statistics:⁽¹⁾	2016						2015
	Precision			Industry⁽²⁾			Precision			Industry⁽²⁾
Number of drilling rigs (end of period)		135			687			176			777
Drilling rig operating days (spud to release)		3,571			13,166			5,457			24,820
Drilling rig operating day utilization		26	%		20	%		35	%		35	%
Number of wells drilled		249			1,062			467			1,783
Average days per well		14.3			12.4			11.7			13.9
Number of metres drilled (000s)		688			2,829			1,031			4,705
Average metres per well		2,765			2,664			2,207			2,639
Average metres per day		193			215			189			190

(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⁾	2016				2015
	Precision		Industry⁽²⁾		Precision		Industry⁽²⁾
Average number of active land rigs for quarters ended:
March 31		32		516		80		1,353

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $275 million this quarter, or 39% lower than the first quarter of 2015, while adjusted EBITDA decreased by 36% to $116 million. The decreases were mainly due to lower drilling rig utilization days in our Canadian, U.S. and international contract drilling businesses partially offset by lump sum payouts for contract terminations.

Drilling rig utilization days in Canada (drilling days plus move days) were 3,995 during the first quarter of 2016, a decrease of 36% compared to 2015 primarily due to the decrease in industry activity resulting from lower commodity prices. Drilling rig utilization days in the U.S. were 2,886, or 60% lower than the same quarter of 2015 as U.S. activity was down due to lower industry activity. Drilling rig utilization days in our international business were 763 or 33% lower than the same quarter of 2015 due to lower activity in the Middle East and Mexico partially offset by adding a contracted rig in Kuwait in 2015.

Compared to the same quarter in 2015, drilling rig revenue per utilization day, excluding the impact of one-time contract cancellation payments, was higher by 8% in the U.S., while it was down 3% in both Canada and internationally. The increase in average day rates for the U.S. was the result of idle but contracted revenue and a higher percentage of our revenue coming from turnkey activity partially offset by lower spot market day rates. In Canada the decrease in the average day rate was the result of lower spot market rates, while the decrease in the average international day rate was due to fewer rigs working in our international operations.

In Canada, 44% of utilization days in the quarter were generated from rigs under term contract, compared to 45% in the first quarter of 2015. In the U.S., 65% of utilization days were generated from rigs under term contract in the first quarter of 2016 as compared to 72% in the first quarter of 2015. At the end of the quarter, we had 34 drilling rigs under contract in Canada, 24 in the U.S. and seven internationally.

Operating costs were 53% 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 lower than the prior year primarily because of crew wage reductions and cost saving initiatives. In the U.S., operating costs for the quarter on a per day basis were slightly higher from the first quarter of 2015 primarily as a result of having higher turnkey costs relative to overall activity and fixed costs spread across lower activity.

General and administrative costs are lower than the prior year by $5 million due to cost saving initiatives taken throughout 2015 and in the first quarter of 2016.

Restructuring costs of $2 million in the quarter relate to cost cutting measures taken in response to the continued downturn in industry activity levels.

Depreciation expense in the quarter was 19% lower than in the first quarter of 2015 because of a lower asset base after decommissioning equipment in the fourth quarter of 2015 and the recording of an impairment charge to our property, plant and equipment in the fourth quarter of 2015 partially offset by new-build rigs deployed in 2015 and the impact of the weakening Canadian dollar compared with the U.S. dollar and the associated impact on our U.S. denominated depreciation expense.

SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES

	Three months ended March 31,
(Stated in thousands of Canadian dollars, except where noted)	2016			2015			% Change
Revenue		28,454			66,082			(56.9	)
Expenses:⁽¹⁾
Operating		26,505			53,799			(50.7	)
General and administrative		2,737			3,085			(11.3	)
Restructuring		1,419			2,141			(33.7	)
Adjusted EBITDA⁽²⁾		(2,207	)		7,057			(131.3	)
Depreciation		7,210			8,758			(17.7	)
Operating loss⁽²⁾		(9,417	)		(1,701	)		453.6
Operating loss as a percentage of revenue		(33.1	%)		(2.6	%)
Well servicing statistics:
Number of service rigs (end of period)		163			177			(7.9	)
Service rig operating hours		24,831			48,001			(48.3	)
Service rig operating hour utilization		16.2	%		29.2	%
Service rig revenue per operating hour		745			837			(11.0	)

(1)

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

(2)

See "ADDITIONAL GAAP MEASURES".

Revenue from Completion and Production Services was down $38 million or 57% compared to the first quarter of 2015 due to lower activity levels in all service lines and lower average rates. In response to lower oil prices, customers curtailed spending including well completion and production programs. Our well servicing activity in the quarter was down 48% from the comparative quarter in 2015. Approximately 78% of our first quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 90% of its revenue from Canadian and 10% from U.S. operations.

Average service rig revenue per operating hour in the first quarter was $745 or $92 lower than the first quarter of 2015. The decrease was primarily the result of industry pricing pressure.

Adjusted EBITDA was $9 million lower than the first quarter of 2015 due to declines in activity and pricing.

Operating costs as a percentage of revenue increased to 93% in the first quarter of 2016, from 81% in the first quarter of 2015. The increase is due to lower activity levels on fixed costs.

Depreciation in the quarter was 18% lower than the first quarter of 2016 because of a lower asset base after recording an impairment charge in the third quarter of 2015.

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 for the first quarter of 2016, $10 million less than the 2015 comparative period due primarily to lower share based incentive compensation, cost cutting initiatives and restructuring charges of $2 million incurred in the prior year quarter.

OTHER ITEMS

Net financial charges for the quarter were $36 million, an increase of $17 million compared with the first quarter of 2015 primarily due to the recognition of $14 million interest revenue in the prior year comparative quarter related to an income tax dispute settlement and the impact of foreign exchange on our U.S. dollar denominated interest. We had a foreign exchange loss of $8 million during the first quarter of 2016 due to the strengthening of the Canadian dollar versus the U.S. dollar, which affected the net U.S. dollar denominated monetary position in the Canadian dollar-based companies.

During the quarter we acquired and cancelled US$10 million face value of our 6.5% unsecured notes due 2021 for US$6 million, realizing a gain on cancellation of US$4 million.

Income tax expense for the quarter was a recovery of $15 million compared with an expense of $32 million in the same quarter in 2015. The recovery in the current quarter is 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 April, 2016 we agreed with our lending group to the following amendments to our senior credit facility:

The Adjusted EBITDA (as defined in the debt agreement) to interest expense coverage ratio of greater than 2:1 was temporarily reduced to 1.5:1 and reverting to 2.5:1 for periods ending after March 31, 2018;

Permit second lien debt not to exceed US$400 million subject to certain terms and conditions;

Amend certain negative covenants to, among other things, prohibit distributions during the covenant relief period;

Add a new covenant with respect to anti-cash hoarding whereby we are only permitted to draw a maximum of $50 million on the facility if the only purpose is to accumulate cash;

Add a new covenant that restricts the repurchase and redemption of unsecured debt subject to a minimum liquidity of US$500 million.

As at March 31, 2016 we had $2,068 million outstanding under our senior unsecured notes. The current blended cash interest cost of our debt is approximately 6.2%.

Amount	Availability	Used for	Maturity
Senior facility (secured)
US$550 million (extendible, revolving term credit facility with US$250 million accordion feature)	Drawn US$46 million in outstanding letters of credit	General corporate purposes	June 3, 2019
Operating facilities (secured)
$40 million	Undrawn, except $24 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$40 million	Undrawn, except US$5 million in outstanding letters of credit	Letters of credit
Senior notes (unsecured)
$200 million	Fully drawn	Debt repayment	March 15, 2019
US$650 million	Fully drawn	Debt repayment and general corporate purposes	November 15, 2020
US$390 million	Fully drawn	Capital expenditures and general corporate purposes	December 15, 2021
US$400 million	Fully drawn	Capital expenditures and general corporate purposes	November 15, 2024

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 Additional GAAP Measures by the exclusion of bad debt expense and certain foreign exchange amounts. As at March 31, 2016 our consolidated senior debt to Adjusted EBITDA ratio was negative 0.78:1.

Under the senior credit facility we are required to maintain an Adjusted EBITDA coverage ratio, calculated as Adjusted EBITDA to interest expense, of greater than 1.5:1 reverting to 2.5:1 for periods ending after March 31, 2018 for the most recent four consecutive fiscal quarters. As at March 31, 2016 our Adjusted EBITDA coverage ratio was 3.7:1.

The senior credit facility also prevents us from making distributions prior to April 1, 2018 and restricts our ability to repurchase our unsecured 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, 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, 2016, we were in compliance with the covenants of the revolving credit facility.

Senior Notes

The senior notes require that we comply with certain financial covenants including an Adjusted EBITDA to interest coverage ratio of greater than 2.0:1 for the most recent four consecutive fiscal quarters. In the event that our Adjusted EBITDA to 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. 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 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. As at March 31, 2016 our restricted payments basket is negative and we are no longer able to make dividend payments until such time as the basket once again becomes 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. At March 31, 2016, we were in compliance with the covenants of our senior notes.

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 our 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 earnings.

QUARTERLY FINANCIAL SUMMARY

(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			-

(Stated in thousands of Canadian dollars, except per share amounts)	2014								2015
Quarters ended	June 30			September 30		December 31			March 31
Revenue		475,174			584,590		618,525			512,120
Adjusted EBITDA⁽¹⁾		129,695			199,390		234,011			163,384
Net earnings (loss):		(7,174	)		52,813		(114,044	)		24,033
Per basic share		(0.02	)		0.18		(0.39	)		0.08
Per diluted share		(0.02	)		0.18		(0.39	)		0.08
Funds provided by operations⁽¹⁾		97,805			196,217		172,059			155,186
Cash provided by operations		228,412			146,733		134,887			215,138
Dividends paid per share		0.06			0.06		0.07			0.07

(1) See "ADDITIONAL GAAP MEASURES".

ADDITIONAL GAAP MEASURES

We reference Generally Accepted Accounting Principles (GAAP) measures that are not defined terms under International Financial Reporting Standards to assess performance because we believe they provide useful supplemental information to investors.

Adjusted EBITDA

We believe that adjusted EBITDA (earnings before income taxes, gain on repurchase of unsecured notes, financing charges, foreign exchange, impairment of goodwill, impairment of property, plant and equipment, loss on asset decommissioning and depreciation and amortization), as reported in the Interim Consolidated Statement of Earnings (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 Earnings (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.

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 capital expenditure plans for 2016;

timing on the delivery of two new rigs in Kuwait;

our strategic priorities for 2016;

continuing demand for Tier 1 rigs; and

the average number of term contracts in place for 2016 and 2017.

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 decline in oil prices will continue to 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, 2015, 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, unless so requires by applicable securities laws.