EX-99.1 4 exh99_1.htm EXHIBIT 99.1

Exhibit 99.1

Precision Drilling Corporation

Second Quarter Report for the six months ended June 30, 2016 and 2015

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's Discussion and Analysis for the three and six month period ended June 30, 2016 of Precision Drilling Corporation ("Precision" or the "Corporation") prepared as at July 20, 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 June 30, 2016 Interim Consolidated Financial Statements and related notes and the cautionary statement regarding forward-looking information and statements on page 13 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 June 30,												Six months ended June 30,
(Stated in thousands of Canadian dollars, except per share amounts)		2016				2015				% Change				2016				2015				% Change
Revenue			163,979				334,462				(51.0	)			465,706				846,582				(45.0	)
Adjusted EBITDA			22,400				88,355				(74.6	)			121,664				251,739				(51.7	)
Adjusted EBITDA  % of revenue			13.7	%			26.4	%							26.1	%			29.7	%
Net loss			(57,677	)			(29,817	)			93.4				(77,560	)			(5,784	)			1,240.9
Cash provided by operations			20,665				169,877				(87.8	)			132,839				385,015				(65.5	)
Funds provided by (used in) operations			(31,372	)			53,173				(159.0	)			62,221				208,359				(70.1	)
Capital spending:
Expansion			46,732				94,204				(50.4	)			65,933				291,521				(77.4	)
Upgrade			-				12,092				(100.0	)			1,433				32,035				(95.5	)
Maintenance and infrastructure			6,692				6,749				(0.8	)			13,219				15,311				(13.7	)
Proceeds on sale			(1,548	)			(3,598	)			(57.0	)			(3,705	)			(6,474	)			(42.8	)
Net capital spending			51,876				109,447				(52.6	)			76,880				332,393				(76.9	)
Loss per share:
Basic			(0.20	)			(0.10	)			(100.0	)			(0.26	)			(0.02	)			1,200.0
Diluted			(0.20	)			(0.10	)			(100.0	)			(0.26	)			(0.02	)			1,200.0
Dividends paid per share			-				0.07				(100.0	)			-				0.14				(100.0	)

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Operating Highlights

		Three months ended June 30,												Six months ended June 30,
		2016				2015				% Change				2016				2015				% Change
Contract drilling rig fleet			252				329				(23.4	)			252				329				(23.4	)
Drilling rig utilization days:         Canada			1,202				2,327				(48.3	)			5,197				8,557				(39.3	)
U.S.			2,198				5,219				(57.9	)			5,084				12,416				(59.1	)
International			637				1,129				(43.6	)			1,400				2,263				(38.1	)
Service rig fleet			163				177				(7.9	)			163				177				(7.9	)
Service rig operating hours			14,862				28,374				(47.6	)			39,693				76,375				(48.0	)

Financial Position

(Stated in thousands of Canadian dollars, except ratios)		June 30, 2016				December 31, 2015
Working capital			502,359				536,815
Long-term debt(1)			2,049,286				2,180,510
Total long-term financial liabilities			2,079,745				2,210,231
Total assets			4,512,400				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 $58 million, or net loss per diluted share of $0.20, compared to net loss of $30 million, or $0.10 per diluted share, in the second quarter of 2015.

Revenue this quarter was $164 million or 51% lower than the second 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 51% and 53%, 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 $22 million or 75% lower than the second quarter of 2015.

Adjusted EBITDA as a percentage of revenue was 14% this quarter, compared to 26% in the second quarter of 2016. The decrease in adjusted EBITDA as a percent of revenue was mainly due to decreased activity in all of our businesses and lower spot market pricing. Our activity for the quarter, as measured by drilling rig utilization days, decreased 48% in Canada, 58% in the U.S. and 44% internationally, compared to the first quarter of 2015.

Net loss for the first six months of 2016 was $78 million, or $0.26 per diluted share, compared to a loss of $6 million, or $0.02 per diluted share for the same period in 2015.

Revenue for the first half of 2016 was $466 million compared to $847 million for the corresponding period of 2015.  Adjusted EBITDA totaled $122 million for the first six months of 2016 compared to $252 million in the first six months of 2015.  The decrease in revenue and EBITDA was mainly the result of lower activity levels and day rates across all of our operations.  Activity for Precision, as measured by drilling utilization days, decreased 39% in Canada, 59% in the United States and 38% internationally for the first six months of the year compared with the same period in 2015.

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.

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Precision's strategic priorities for 2016 are as follows:

1. 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 continue a multi-year plan for net debt reduction.

2. 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.

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

a. 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.

b. 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.

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

For the second quarter of 2016, the average natural gas prices and the West Texas Intermediate price of oil were lower than the 2015 comparable averages.

		Three months ended June 30,								Year ended December 31,
		2016				2015				2015
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)			45.45				57.68				48.77
Natural gas
Canada
AECO (per MMBtu) (CDN$)			1.41				2.66				2.70
United States
Henry Hub (per MMBtu) (US$)			2.11				2.72				2.60

Summary for the three months ended June 30, 2016:

• Operating loss (see "Additional GAAP Measures" in this news release) this quarter was $74 million, or negative 45% of revenue, compared to an operating loss of $32 million and negative 9% of revenue in 2015.  Operating results were negatively impacted by the decrease in drilling activity and day rates in all of our operating segments.

• General and administrative expenses this quarter were $29 million, $3 million lower than the second quarter of 2015.  The decrease is primarily due to cost savings initiatives partially offset by higher accrued incentive compensation, which is tied to the price of our common shares, and the effect of the weakening Canadian dollar on our U.S. dollar denominated costs.

• Net finance charges were $33 million, an increase of $1 million compared with the second quarter of 2015 due to the impact of foreign exchange on our U.S. dollar denominated interest partially offset by interest received in the current quarter on a tax dispute settlement.

• Average revenue per utilization day for contract drilling rigs increased in the second quarter of 2016 to $24,980 from the prior year second quarter of $22,939 in Canada and decreased slightly in the U.S. to US$27,519 from US$27,731.  The increase in Canada is the result of a higher proportion of revenue from Super Triple rigs relative to the 2015 comparative period and contract shortfall payments received in the quarter partially offset by lower spot market rates. The decrease in the U.S. is the result of lower spot market rates and lower turnkey activity partially offset by a higher daily revenue impact from idle but contracted rigs.  We had US$6 million in turnkey revenue for the second quarter of 2016 compared with US$17 million in the 2015 comparative period and US$7 million in idle but contracted revenue in the current quarter versus US$9 million in the prior year.

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•       Average operating costs per utilization day for drilling rigs in Canada increased to $14,954, compared to the prior year second quarter of $12,818 primarily because of the impact of fixed costs on lower activity partially offset by crew wage reductions and cost savings initiatives. In the U.S., operating costs for the quarter on a per day basis decreased to US$14,899 in 2016 compared to US$15,896 in 2015 due to sales tax adjustments, lower turnkey activity and cost savings initiatives partially offset by fixed costs spread over fewer active rigs.

•      We realized revenue from international contract drilling of $36 million in the second quarter of 2016, a $27 million decrease over the prior year period.  Average revenue per utilization day in our international contract drilling business was US$44,391 a decrease of 3% over the comparable prior year quarter.

•      Directional drilling services realized revenue of $3 million in the second quarter of 2016 compared with $5 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 used in operations in the second quarter of 2016 were $31 million, a decrease of $85 million from the funds provided by operations in the prior year comparative quarter of $53 million.  The decrease was primarily the result of lower activity levels in the current year period.

• Capital expenditures for the purchase of property, plant and equipment were $53 million in the second quarter, a decrease of $60 million over the same period in 2015.  Capital spending for the second quarter of 2016 included $47 million primarily for international expansion capital and $6 million for the maintenance of existing assets and infrastructure spending.

Summary for the six months ended June 30, 2016:

• Revenue for the first half of 2016 was $466 million, a decrease of 45% from the 2015 period.

• Operating loss was $70 million, a decrease of $86 million over the same period in 2015.  Operating loss was 15% of revenue in 2016 compared to operating earnings of 2% of revenue in 2015.  Operating earnings were negatively impacted by the decreased drilling activity and rates in our North American operations.

• General and administrative costs were $57 million, a decrease of $16 million over the first half of 2015.  The decrease is due to efforts in reducing fixed costs through the downturn and lower 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.

• Net finance charges were $69 million, an increase of $17 million from the first half 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.

• Funds provided by operations (see "Additional GAAP Measures" in this news release) in the first half of 2016 were $62 million, a decrease of $146 million from the prior year comparative period of $208 million.

• Capital expenditures for the purchase of property, plant and equipment were $81 million in the first half of 2016, a decrease of $258 million over the same period in 2015.  Capital spending for 2016 to date included $66 million for expansion capital, $2 million for upgrade capital and $13 million for the maintenance of existing assets and infrastructure.

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OUTLOOK

Contracts

Our portfolio of term customer contracts provides a base level of activity and revenue.  As of July 20, 2016, for the third quarter of 2016 we had, on average, term contracts for 29 rigs in Canada, 21 in the U.S. and seven internationally.  For the 2016 calendar year we have on average 30 rigs contracted in Canada, 21 in the U.S. and seven internationally and a total average of 35 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 quarter was 24 rigs, down 33 rigs over the second quarter in 2015 and down eight rigs from the first quarter of 2016.  We currently have 28 rigs active in the U.S.

In Canada, our average active rig count in the quarter was 13 rigs, a decrease of 12 over the second quarter in 2015. We currently have 27 rigs active in Canada and expect typical seasonal volatility through the third quarter, but in general we expect to benefit from the fleet enhancements over the past several years.

In general, lower oil prices have caused producers to significantly reduce drilling budgets decreasing demand for drilling rigs, 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 seven rigs, down five rigs over the second quarter in 2015 and down one rig from the first quarter of 2016.  The decrease from the first quarter is the result of one fewer rig working in Mexico while the decrease over the prior year is primarily coming from fewer rigs working in Mexico and no rigs currently working in Kurdistan.  We currently have seven rigs active internationally.

Industry Conditions

To date in 2016, drilling activity has decreased relative to this time last year for both Canada and the U.S.  According to industry sources, as of July 15, 2016, the U.S. active land drilling rig count was down approximately 49% from the same point last year and the Canadian active land drilling rig count was down approximately 51%.  The decrease in the North American rig count has resulted in the trend of high-grading toward Tier 1 rigs, which continue to show relative strength given the current market conditions.

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 trend towards oil-directed drilling in the U.S. continues. To date in 2016, approximately 45% of the Canadian industry's active rigs and 80% of the U.S. industry's active rigs were drilling for oil targets, compared to 45% for Canada and 77% 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 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.

••••

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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 June 30,												Six months ended June 30,
(Stated in thousands of Canadian dollars)		2016				2015				% Change				2016				2015				% Change
Revenue:
Contract Drilling Services			147,780				299,943				(50.7	)			422,617				748,008				(43.5	)
Completion and Production Services			16,731				35,589				(53.0	)			45,185				101,671				(55.6	)
Inter-segment eliminations			(532	)			(1,070	)			(50.3	)			(2,096	)			(3,097	)			(32.3	)
			163,979				334,462				(51.0	)			465,706				846,582				(45.0	)
Adjusted EBITDA:(1)
Contract Drilling Services(2)			42,503				106,419				(60.1	)			158,120				286,615				(44.8	)
Completion and Production Services			(2,568	)			(704	)			264.8				(4,775	)			6,353				(175.2	)
Corporate and other(2)			(17,535	)			(17,360	)			1.0				(31,681	)			(41,229	)			(23.2	)
			22,400				88,355				(74.6	)			121,664				251,739				(51.7	)

(1) See "ADDITIONAL GAAP MEASURES".

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

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

		Three months ended June 30,												Six months ended June 30,
(Stated in thousands of Canadian dollars, except where noted)
		2016				2015				% Change				2016				2015				% Change
Revenue			147,780				299,943				(50.7	)			422,617				748,008				(43.5	)
Expenses:(1)
Operating			95,224				178,359				(46.6	)			241,353				426,851				(43.5	)
General and administrative			9,592				12,542				(23.5	)			20,727				28,410				(27.0	)
Restructuring			461				2,623				(82.4	)			2,417				6,132				(60.6	)
Adjusted EBITDA(2)			42,503				106,419				(60.1	)			158,120				286,615				(44.8	)
Depreciation			86,412				108,407				(20.3	)			170,691				212,238				(19.6	)
Operating earnings (loss)(2)			(43,909	)			(1,988	)			2,108.7				(12,571	)			74,377				(116.9	)
Operating earnings (loss) as a percentage of revenue			(29.7	%)			(0.7	%)							(3.0	%)			9.9	%
Drilling rig revenue per utilization day in Canada			24,980				22,939				8.9				24,134				23,357				3.3
Drilling rig revenue per utilization day in the United States(3) (US$)			27,519				27,731				(0.8	)			29,966				26,251				14.1
Drilling rig revenue per utilization day in International  (US$)			44,391				45,700				(2.9	)			42,874				44,331				(3.3	)

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

(2) See "ADDITIONAL GAAP MEASURES".

(3) For the three month periods ended June 30 and the six months ended June 30, 2015 includes revenue from idle but contracted rig days.  For the six months ended June 30, 2016 includes idle but contracted rig days and contract cancellation payments.

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		Three months ended June 30,
Canadian onshore drilling statistics:(1)		2016								2015
		Precision				Industry(2)				Precision				Industry(2)
Number of drilling rigs (end of period)			135				672				176				766
Drilling rig operating days (spud to release)			1,073				4,011				2,088				8,868
Drilling rig operating day utilization			9	%			7	%			13	%			13	%
Number of wells drilled			89				313				205				733
Average days per well			12.1				12.8				10.2				12.1
Number of metres drilled (000s)			301				931				529				2,005
Average metres per well			3,384				2,974				2,580				2,736
Average metres per day			281				232				253				226

		Six months ended June 30,
Canadian onshore drilling statistics:(1)		2016								2015
		Precision				Industry(2)				Precision				Industry(2)
Number of drilling rigs (end of period)			135				672				176				766
Drilling rig operating days (spud to release)			4,644				17,177				7,545				33,686
Drilling rig operating day utilization			19	%			14	%			24	%			24	%
Number of wells drilled			338				1,375				672				2,516
Average days per well			13.7				12.5				11.2				13.4
Number of metres drilled (000s)			990				3,760				1,560				6,711
Average metres per well			2,928				2,735				2,321				2,667
Average metres per day			213				219				207				199

(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
June 30			24				397				57				873
Year to date average			28				457				69				1,104

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $148 million this quarter, or 51% lower than the second quarter of 2015, while adjusted EBITDA decreased by 60% to $43 million.  The decreases were mainly due to lower drilling rig utilization days in our Canadian, U.S. and international contract drilling businesses.

Drilling rig utilization days in Canada (drilling days plus move days) were 1,202 during the second quarter of 2016, a decrease of 48% 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 2,198 or 58% 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 637 or 44% lower than the same quarter of 2015 due to lower activity in the Middle East and Mexico.

Compared to the same quarter in 2015, drilling rig revenue per utilization day was up 9% in Canada due to one-time contract shortfall payments.  Excluding one-time contract shortfall payments, drilling rig revenue per utilization day in Canada was down 9% due to the decline of spot market rates as industry activity has dropped.  Drilling rig revenue per utilization day for the current quarter in the U.S. was down 1% from the prior comparative period, while internationally revenue per day was down 3%.  The decrease in the U.S. average rate was due to lower spot market rates and a lower percentage of revenue coming from turnkey activity partially offset by additional relative idle but contracted revenue.

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In Canada, 55% of utilization days in the quarter were generated from rigs under term contract, compared to 62% in the second quarter of 2015.  In the U.S., 70% of utilization days were generated from rigs under term contract as compared to 78% in the second quarter of 2015. At the end of the quarter, we had 32 drilling rigs under contract in Canada, 22 in the U.S. and seven internationally.

Operating costs were 64% of revenue for the quarter, which was five percentage points higher than the prior year period.  On a per utilization day basis, operating costs for the drilling rig division in Canada were higher over the prior year primarily because of the impact of fixed costs on lower activity partially offset by crew wage reductions and cost saving initiatives.  In the U.S., operating costs for the quarter on a per day basis were lower than the prior year primarily due to sales tax adjustments, lower turnkey activity and cost saving initiatives partially offset by fixed costs spread over lower activity.

General and administrative costs are lower than the prior year by $3 million due to cost saving initiatives taken throughout 2015 and in the first half of 2016.

Restructuring costs 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 20% lower than in the second quarter of 2015 because of a lower asset base after decommissioning equipment 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 June 30,												Six months ended June 30,
(Stated in thousands of Canadian dollars, except where noted)		2016				2015				% Change				2016				2015				% Change
Revenue			16,731				35,589				(53.0	)			45,185				101,671				(55.6	)
Expenses:(1)
Operating			16,217				33,794				(52.0	)			42,722				87,593				(51.2	)
General and administrative			2,534				2,884				(12.1	)			5,271				5,969				(11.7	)
Restructuring			548				(385	)			(242.3	)			1,967				1,756				12.0
Adjusted EBITDA(2)			(2,568	)			(704	)			264.8				(4,775	)			6,353				(175.2	)
Depreciation			6,568				8,706				(24.6	)			13,778				17,464				(21.1	)
Operating loss(2)			(9,136	)			(9,410	)			(2.9	)			(18,553	)			(11,111	)			67.0
Operating loss as a percentage of revenue			(54.6	%)			(26.4	%)							(41.1	)			(10.9	%)
Well servicing statistics:
Number of service rigs (end of period)			163				177				(7.9	)			163				177				(7.9	)
Service rig operating hours			14,862				28,374				(47.6	)			39,693				76,375				(48.0	)
Service rig operating hour utilization			10	%			17	%							13	%			23	%
Service rig revenue per operating hour			602				718				(16.2	)			691				792				(12.8	)

(1) Prior year comparative has been changed to conform to the current year calculation.

(2) See "ADDITIONAL GAAP MEASURES".

8

Revenue from Completion and Production Services was down $19 million or 53% compared to the second 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 and activity including well completion and production programs.  Our well servicing activity in the quarter was down 48% from the second quarter of 2015.  Approximately 89% of our second quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 87% of its revenue from Canadian and 13% from U.S. operations.

Average service rig revenue per operating hour in the second quarter was $602 or $116 lower than the second quarter of 2015.  The decrease was primarily the result of industry pricing.

Adjusted EBITDA was $2 million lower than the second quarter of 2015 due to a decline in activity and pricing.

Operating costs as a percentage of revenue increased to 97% in the second quarter of 2016, from 95% in the second quarter of 2015.  The increase is the result of the impact of lower activity levels on fixed costs, as well as lower revenue from pricing pressure.

Depreciation in the quarter was 25% lower than the second quarter of 2015 because of a lower asset base after 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 $18 million for the second quarter of 2016, in line with the prior year comparable as higher share based incentive compensation was partially offset by cost saving initiatives.

OTHER ITEMS

Net finance charges were $33 million, an increase of $1 million compared with the second quarter of 2015 due to the impact of foreign exchange on our U.S. dollar denominated interest partially offset by interest received in the current quarter on a tax dispute settlement.

Income tax expense for the quarter was a recovery of $50 million compared with a recovery of $43 million in the same quarter in 2015. Income tax expense is recognized by applying the income tax rate expected for the full financial year to the pre-tax income of the interim reporting period with adjustments for transactions specific to the quarter.

LIQUIDITY AND CAPITAL RESOURCES

The oilfield services business is inherently cyclical in nature. To manage this, we focus on maintaining a strong balance sheet in order to have the financial flexibility we need to continue to manage our growth and cash flow throughout 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 respond 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.

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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 reverts 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 pro-forma minimum liquidity of US$500 million.

During the quarter we reduced the size of our demand letter of credit facility from US$40 million to US$30 million as the size of the facility was too large for the intended purpose.

As at June 30, 2016 we had $2,073 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)	Undrawn, except US$46 million in outstanding letters of credit	General corporate purposes	June 3, 2019
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$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 June 30, 2016 our consolidated senior debt to Adjusted EBITDA ratio was negative 0.97:1.

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 June 30, 2016 our Adjusted EBITDA coverage ratio was 2.68:1.

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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 June 30, 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 payments 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 June 30, 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 June 30, 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 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 earnings.

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QUARTERLY FINANCIAL SUMMARY

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

		2015								2016
Quarters ended		September 30				December 31				March 31				June 30
Revenue			364,089				344,953				301,727				163,979
Adjusted EBITDA(1)			111,031				111,095				99,264				22,400
Net loss:			(86,700	)			(270,952	)			(19,883	)			(57,677	)
Per basic share			(0.30	)			(0.93	)			(0.07	)			(0.20	)
Per diluted share			(0.30	)			(0.93	)			(0.07	)			(0.20	)
Funds provided by (used in) operations(1)			99,228				49,503				93,593				(31,371	)
Cash provided by operations			61,049				70,952				112,174				20,665
Dividends paid per share			0.07				0.07				-				-

		2014								2015
Quarters ended		September 30				December 31				March 31				June 30
Revenue			584,590				618,525				512,120				334,462
Adjusted EBITDA(1)			199,390				234,011				163,384				88,355
Net earnings (loss):			52,813				(114,044	)			24,033				(29,817	)
Per basic share			0.18				(0.39	)			0.08				(0.10	)
Per diluted share			0.18				(0.39	)			0.08				(0.10	)
Funds provided by operations(1)			196,217				172,059				155,186				53,173
Cash provided by operations			146,733				134,887				215,138				169,877
Dividends paid per share			0.06				0.07				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 senior notes, financing charges, foreign exchange, and depreciation and amortization) as reported in the 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 depreciation and amortization charges.

Operating Earnings (Loss)

We believe that operating earnings (loss), as reported in the 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 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.

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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;

· the principal use of our free cash in 2016;

· timing on the commissioning and delivery of two new rigs for 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, except as required by law.

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