exh99_1.htm

Exhibit 99.1

Precision Drilling Corporation

Second Quarter Report for the six months ended June 30, 2015 and 2014

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s Discussion and Analysis for the three and six month period ended June 30, 2015 of Precision Drilling Corporation (“Precision” or the “Corporation”) prepared as at July 22, 2015 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 2014 Annual Report, Annual Information Form, unaudited June 30, 2015 Interim Consolidated Financial Statements and related notes and the cautionary statement regarding forward-looking information and statements on page 14 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)	2015			2014			% Change			2015			2014			% Change
Revenue		334,462			475,174			(29.6	)		846,582			1,147,423			(26.2	)
Adjusted EBITDA		88,355			129,695			(31.9	)		251,739			366,969			(31.4	)
Adjusted EBITDA % of revenue		26.4	%		27.3	%					29.7	%		32.0	%
Net earnings (loss)		(29,817	)		(7,174	)		315.6			(5,784	)		94,383			(106.1	)
Cash provided by operations		169,877			228,412			(25.6	)		385,015			398,539			(3.4	)
Funds provided by operations		53,173			97,805			(45.6	)		208,359			329,198			(36.7	)
Capital spending:
Expansion		94,204			117,654			(19.9	)		291,521			185,839			56.9
Upgrade		12,092			25,593			(52.8	)		32,035			45,450			(29.5	)
Maintenance and infrastructure		6,749			31,607			(78.6	)		15,311			49,564			(69.1	)
Proceeds on sale		(3,598	)		(9,979	)		(63.9	)		(6,474	)		(17,236	)		(62.4	)
Net capital spending		109,447			164,875			(33.6	)		332,393			263,617			26.1

Earnings (loss) per share:
Basic		(0.10	)		(0.02	)		400.0			(0.02	)		0.32			(106.3	)
Diluted		(0.10	)		(0.02	)		400.0			(0.02	)		0.32			(106.3	)
Dividends paid per share		0.07			0.06			16.7			0.14			0.12			16.7

Operating Highlights

	Three months ended June 30,							Six months ended June 30,
	2015		2014		% Change			2015		2014		% Change
Contract drilling rig fleet		329		333		(1.2	)		329		333		(1.2	)
Drilling rig utilization days: Canada		2,327		4,805		(51.6	)		8,557		16,189		(47.1	)
U.S.		5,219		8,490		(38.5	)		12,416		16,963		(26.8	)
International		1,129		962		17.4			2,263		1,952		15.9
Service rig fleet		177		221		(19.9	)		177		221		(19.9	)
Service rig operating hours		28,374		51,270		(44.7	)		76,375		133,834		(42.9	)

Financial Position

(Stated in thousands of Canadian dollars, except ratios)	June 30, 2015		December 31, 2014
Working capital		508,738		653,630
Long-term debt(1)		1,980,575		1,852,186
Total long-term financial liabilities		2,012,913		1,881,275
Total assets		5,193,847		5,308,996
Long-term debt to long-term debt plus equity ratio(1)		0.45		0.43

(1) Net of unamortized debt issue costs.

Net loss this quarter was $30 million, or $0.10 per diluted share, compared to a net loss of $7 million, or $0.02 per diluted share, in the second quarter of 2014.

Revenue this quarter was $334 million, or 30% less than the second quarter of 2014. The decrease, of $141 million, was primarily due to a year-over-year decrease in activity from our North American operations. Revenue from our Contract Drilling Services and Completion and Production Services segments both decreased over the comparative prior year period by 27% and 46%, respectively.

Earnings before income taxes, finance charges, foreign exchange, and depreciation and amortization (adjusted EBITDA see “Additional GAAP Measures”) this quarter were $88 million or 32% lower than the second quarter of 2014.

Adjusted EBITDA as a percent of revenue was 26% this quarter, compared to 27% in the second quarter of 2014. The decrease in adjusted EBITDA as a percent of revenue was mainly due decreased activity and lower pricing in our Completion and Production Services segment and costs associated with restructuring, which were $3 million this quarter partially offset by improved average pricing in our North America contract drilling operations. Our activity for the quarter, as measured by drilling rig utilization days, decreased 52% in Canada and 39% in the U.S. and increased 17% internationally, compared to the second quarter of 2014.

For the six months ended June 30, 2015, Precision reported a net loss of $6 million or $0.02 per diluted share compared to net earnings of $94 million or $0.32 per diluted share for the same period of 2014.

Revenue for the first half of 2015 was $847 million compared to $1,147 million for the corresponding period of 2014. Adjusted EBITDA totaled $252 million for the first six months of 2015 compared to $367 million in the first six months of 2014. The decrease in revenue and EBITDA was mainly the result of lower activity levels and day rates across our North American operations partially offset by higher activity and higher average day rates in our international contract drilling operations. Activity for Precision, as measured by drilling utilization days, decreased 47% in Canada, 27% in the United States and increased 16% internationally for the first six months of the year compared with the same period in 2014.

Our current expected capital plan for 2015 is $546 million, an increase of $40 million compared to the $506 million capital plan announced in April 2015. The capital increase is due to one additional new-build contract for a ST-1200 rig for deep basin drilling in Canada and long lead items. A portion of the 2015 capital plan is utilization based and if activity levels change, Precision has the ability to adjust its plan accordingly. Of the 18 new-build drilling rigs scheduled for delivery in 2015 (13 rigs in the U.S., four in Canada and one internationally) ten were delivered in the first quarter and four were delivered in the second quarter. After delivery of the remaining contracted new-build rig in 2015, Precision’s drilling rig fleet will consist of 331 drilling rigs, including 236 Tier 1 rigs, 73 Tier 2 rigs and 22 PSST rigs. For the Tier 1 rigs, 124 will be in Canada, 106 in the U.S. and six internationally.

On July 22, 2015 the Board of Directors declared a dividend of $0.07 per common share payable on August 21, 2015 to shareholders of record on August 10, 2015.

Precision’s strategic priorities for 2015 are as follows:

Work with our customers to lower well costs – Deliver High Performance, High Value services to customers to create maximum efficiency and lower risks for development drilling programs. Utilize our unique platform of Tier 1 assets, geographically diverse operations and highly efficient service offering to deliver cost-reducing solutions. Grow our cost-reducing integrated directional drilling service.

Maximize cost efficiency throughout the organization – Continue to leverage Precision’s scale to reduce costs and continue to deliver High Performance. Maximize the benefits of the variable nature of operating and capital expenses. Maintain an efficient corporate cost structure by optimizing systems for assets, people and business management. Maintain our uncompromising focus on worker safety, premium service quality and employee development.

Reinforce our competitive advantage – Gain market share as Tier 1 assets remain most in demand rigs. High-grade our active rig fleet by delivering new-build rigs and maximizing customer opportunities to utilize High Performance assets. Deliver consistent, reliable, High Performance service. Retain and continue to develop the industry’s best people.

Manage liquidity and focus activities on cash flow generation. Monitor working capital, debt and liquidity. Maintain a scalable cost structure that is responsive to changing competition and market demand. Adjust capital plans according to utilization and customer demand.

For the second quarter of 2015, the average natural gas prices and the West Texas Intermediate price of oil were lower than the 2014 averages.

	Three months ended June 30,				Year ended Dec 31,
	2015		2014		2014
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)		57.68		103.14		93.06

Natural gas
Canada
AECO (per MMBtu) (Cdn$)		2.66		4.69		4.45
U.S.
Henry Hub (per MMBtu) (US$)		2.72		4.58		4.33

Summary for the three months ended June 30, 2015:

Operating loss (see “Additional GAAP Measures” in this news release) this quarter was $32 million, or negative 9% of revenue, compared to operating earnings of $24 million and 5% of revenue in 2014. Operating results were negatively impacted by the decrease in drilling activity and day rates in our North American operating segments partially offset by improved results internationally.

General and administrative expenses this quarter were $37 million, $5 million lower than the second quarter of 2014. The decrease is primarily due to cost saving initiatives and lower incentive compensation which is tied to the price of our common shares partially offset by the effect of the weakening Canadian dollar on our U.S. dollar denominated expenses and restructuring charges incurred this quarter.

Net finance charges were $32 million, an increase of $7 million compared with the second quarter of 2014 due to the issuance of US$400 million of 5.25% Senior Notes on June 3, 2014 and the effect of the weakening Canadian dollar on our U.S. dollar denominated interest.

Average revenue per utilization day for contract drilling rigs increased in the second quarter of 2015 to $22,939 from the prior year second quarter of $22,217 in Canada and increased in the U.S. to US$27,731 from US$24,320. The increase in revenue rates for Canada is primarily due to rig mix and additional Tier 1 rigs operating partially offset by competitive pricing in some rig segments. In Canada, for the second quarter of 2015, 62% of our utilization days were achieved from drilling rigs working under term contracts compared to 53% in the 2014 comparative period. The increase in revenue rates for the U.S. was primarily due to a higher percentage of revenue being generated from Tier 1 rigs compared to the prior year quarter, idle-but-contracted payments and larger turnkey jobs relative to the prior year quarter. In the U.S., for the second quarter of 2015, 78% of our utilization days were generated from rigs working under term contracts compared to 72% in the 2014 comparative period. Turnkey revenue for the second quarter of 2015 was US$17 million compared with US$20 million in the 2014 comparative period. Within the Completion and Production Services segment, average hourly rates for service rigs were $718 in the second quarter of 2015 compared to $940 in the second quarter of 2014. The decrease in the average hourly rate is the result of pricing pressure across all service rig classes and the absence of our U.S. coil tubing assets, which were sold in the fourth quarter of 2014.

Average operating costs per utilization day for drilling rigs increased in the second quarter of 2015 in both Canada and the United States. In Canada costs increased to $12,818, compared to the prior year second quarter of $11,695 and in the U.S. costs increased to US$15,896 in 2015 compared to US$13,502 in 2014. The cost increase in both markets was primarily due to higher labour burden and a lower activity base to spread fixed costs and larger turnkey jobs during the quarter in the United States.

We realized revenue from international contract drilling of $63 million in the second quarter of 2015, a $17 million increase over the prior year period due to expansion in the Middle East with three new-build rigs deployed in 2014, one rig deployed to the country of Georgia in the first quarter of 2015 and one new-build rig deployed in the second quarter of 2015 to Kuwait. Average revenue per utilization day in our international contract drilling business was US$45,700 an increase of 4% over the comparable prior year quarter.

Directional drilling services realized revenue of $5 million in the second quarter of 2015 compared with $23 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 in the second quarter of 2015 were $53 million, a decrease of $45 million from the prior year comparative quarter of $98 million. The decrease was primarily the result of lower activity levels.

Capital expenditures for the purchase of property, plant and equipment were $113 million in the second quarter, a decrease of $62 million over the same period in 2014. Capital spending for the second quarter of 2015 included $94 million for expansion capital, $12 million for upgrade capital and $7 million for the maintenance of existing assets and infrastructure spending.

Summary for the six months ended June 30, 2015:

Revenue for the first half of 2015 was $847 million, a decrease of 26% from the 2014 period.

Operating earnings were $16 million, a decrease of $140 million or 90% from 2014. Operating earnings were 2% of revenue in 2015 compared to 14% in 2014. Operating earnings were negatively impacted by the decreased drilling activity and rates in our North American operations and depreciation from capital asset additions over the past year and a half.

General and administrative costs were $82 million, an increase of $1 million over the first half of 2014 primarily as a result of restructuring costs of $[5] million and the effect of the weakening Canadian dollar on our U.S. dollar denominated expenses partially offset by cost savings initiatives and lower incentive compensation.

Net finance charges were $52 million, an increase of $2 million from the first half of 2014 due to the issuance of US$400 million of 5.25% Senior Notes on June 3, 2014 and the effect of the weakening Canadian dollar on our U.S. dollar denominated interest partially offset by $14 million in interest revenue related to an income tax dispute settlement.

Funds provided by operations (see “Additional GAAP Measures” in this news release) in the first half of 2015 were $208 million, a decrease of $121 million from the prior year comparative period of $329 million.

Capital expenditures for the purchase of property, plant and equipment were $339 million in the first half of 2015, an increase of $58 million over the same period in 2014. Capital spending for 2015 to date included $292 million for expansion capital, $32 million for upgrade capital and $15 million for the maintenance of existing assets and infrastructure.

OUTLOOK

Contracts

Our portfolio of term customer contracts provides a base level of activity and revenue and, as of July 22, 2015, we had term contracts in place for an average of 45 rigs in Canada, 43 in the U.S. and nine internationally for the third quarter of 2015 and an average of 46 rig contracts in Canada, 47 in the U.S. and 11 internationally for the full year. 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 58 rigs, down 36 rigs over the second quarter in 2014 and down 22 rigs from the first quarter of 2015. We currently have 52 rigs active in the U.S.

In Canada, our average active rig count in the quarter was 26 rigs, a decrease of 27 over the second quarter in 2014. We currently have 56 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.

Internationally, our average active rig count in the quarter was 13 rigs, up 2 rigs over the second quarter in 2014 and in line with the first quarter of 2015. During the quarter one new-build rig went to work in Kuwait and was operating at the end of the quarter. We currently have 12 rigs active internationally.

Industry Conditions

To date in 2015, drilling activity has decreased relative to this time last year for both Canada and the U.S. According to industry sources, as of July 17, 2015, the U.S. active land drilling rig count was down approximately 54% from the same point last year and the Canadian active land drilling rig count was down approximately 50%. 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 2015, approximately 45% of the Canadian industry’s active rigs and 77% of the U.S. industry’s active rigs were drilling for oil targets, compared to 60% for Canada and 82% for the U.S. at the same time last year.

Capital Spending

Capital spending in 2015 is expected to be $546 million:

The 2015 capital expenditure plan includes $422 million for expansion capital, $78 million for sustaining and infrastructure expenditures, and $46 million to upgrade existing rigs. We expect that the $546 million will be split $540 million in the Contract Drilling segment and $6 million in the Completion and Production Services segment.

Precision’s expansion capital plan for 2015 includes 18 new-build drilling rigs, 16 of which were delivered in the first half of the year. Of the remaining two rigs, one rig was deployed to Canada early in the third quarter and one is expected to be deployed in Canada in the fourth quarter. Of the 16 rigs delivered, 13 rigs went to the U.S., two to Canada and one to Kuwait, all of which are on long-term contracts.

Precision’s sustaining and infrastructure capital plan is based upon currently anticipated activity levels for 2015.

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)	2015			2014			% Change			2015			2014			% Change
Revenue:
Contract Drilling Services		299,943			410,882			(27.0	)		748,008			982,804			(23.9	)
Completion and Production Services		35,589			66,508			(46.5	)		101,671			169,573			(40.0	)
Inter-segment eliminations		(1,070	)		(2,216	)		(51.7	)		(3,097	)		(4,954	)		(37.5	)
		334,462			475,174			(29.6	)		846,582			1,147,423			(26.2	)
Adjusted EBITDA:(1)
Contract Drilling Services		109,897			148,491			(26.0	)		293,016			388,189			(24.5	)
Completion and Production Services		(704	)		5,137			(113.7	)		6,353			24,590			(74.2	)
Corporate and other		(20,838	)		(23,933	)		(12.9	)		(47,630	)		(45,810	)		4.0
		88,355			129,695			(31.9	)		251,739			366,969			(31.4	)

(1) See “ADDITIONAL GAAP MEASURES”.

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)
	2015			2014			% Change			2015			2014			% Change
Revenue		299,943			410,882			(27.0	)		748,008			982,804			(23.9	)
Expenses:
Operating		178,630			249,937			(28.5	)		429,869			568,844			(24.4	)
General and administrative		11,416			12,454			(8.3	)		25,123			25,771			(2.5	)
Adjusted EBITDA(1)		109,897			148,491			(26.0	)		293,016			388,189			(24.5	)
Depreciation		108,407			92,365			17.4			212,238			184,476			15.0
Operating earnings(1)		1,490			56,126			(97.3	)		80,778			203,713			(60.3	)
Operating earnings as a percentage ofrevenue		0.5	%		13.7	%					10.8	%		20.7	%
Drilling rig revenue per utilization day inCanada		22,939			22,217			3.2			23,357			22,608			3.3
Drilling rig revenue per utilization day inthe United States(2) (US$)		27,731			24,320			14.0			26,251			24,235			8.3
Drilling rig revenue per utilization day inInternational (US$)		45,700			43,864			4.2			44,331			41,362			7.2

(1) See “ADDITIONAL GAAP MEASURES”.

(2) Includes revenue from idle but contracted rig days and lump sum payouts.

	Three months ended June 30,
Canadian onshore drilling statistics:(1)	2015						2014
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		176			766			189			810
Drilling rig operating days (spud to release)		2,088			8,868			4,312			18,293
Drilling rig operating day utilization		13	%		13	%		25	%		25	%
Number of wells drilled		205			733			393			1,430
Average days per well		10.2			12.1			11.0			12.8
Number of metres drilled (000s)		529			2,005			793			3,430
Average metres per well		2,580			2,736			2,018			2,399
Average metres per day		253			226			184			188

	Six months ended June 30,
Canadian onshore drilling statistics:(1)	2015						2014
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		176			766			189			810
Drilling rig operating days (spud to release)		7,545			33,686			14,366			63,070
Drilling rig operating day utilization		24	%		24	%		42	%		43	%
Number of wells drilled		672			2,516			1,343			4,881
Average days per well		11.2			13.4			10.7			12.9
Number of metres drilled (000s)		1,560			6,711			2,627			11,090
Average metres per well		2,321			2,667			1,956			2,272
Average metres per day		207			199			183			176

(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)	2015				2014
	Precision		Industry(2)		Precision		Industry(2)
Average number of active land rigs for quarters ended:
March 31		80		1,353		94		1,724
June 30		57		873		93		1,802
Year to date average		69		1,104		94		1,760

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $300 million this quarter, or 27% lower than the second quarter of 2014, while adjusted EBITDA decreased by 26% to $110 million. The decreases were mainly due to lower drilling rig utilization days in our Canadian and U.S. contract drilling businesses partially offset by higher average day rates in Canada and the U.S. along with higher activity and average day rates in our international drilling business.

Drilling rig utilization days in Canada (drilling days plus move days) were 2,327 during the second quarter of 2015, a decrease of 52% compared to 2014 primarily due to the decrease in industry activity resulting from lower commodity prices. Drilling rig utilization days in the U.S. were 5,219 or 39% lower than the same quarter of 2014 as U.S. activity was down due to lower industry activity. The majority of our North American activity came from oil and liquids-rich natural gas related plays. Drilling rig utilization days in our international business were 1,129 or 17% higher than the same quarter of 2014 due to contracted rigs added in Kuwait and the Kingdom of Saudi Arabia in 2014 and the country of Georgia and Kuwait in 2015 partially offset by lower activity in Mexico.

Compared to the same quarter in 2014, drilling rig revenue per utilization day was up 3% in Canada, 14% in the U.S. and 4% in international. The increase in average day rates for the U.S. was primarily due to a higher percentage of revenue being generated from Tier 1 rigs compared to the prior year quarter, idle-but-contracted payments and large turnkey jobs in the quarter relative to the prior year comparative quarter. In Canada the day rate increase was the result of rig mix as proportionately more Tier 1 rigs are working compared to the prior year. The average international day rate is up as we are realizing a higher percentage of our fleet utilization from our Middle East operations.

In Canada, 62% of utilization days in the quarter were generated from rigs under term contract, compared to 53% in the second quarter of 2014. In the U.S., 78% of utilization days were generated from rigs under term contract as compared to 72% in the second quarter of 2014. At the end of the quarter, we had 48 drilling rigs under contract in Canada, 47 in the U.S. and 12 internationally.

Operating costs were 60% of revenue for the quarter, which was one percentage point lower 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 increase and an increase in crew labour rates. In the U.S., operating costs for the quarter on a per day basis were higher than the prior year primarily from higher labour burden costs and large turnkey jobs in the quarter relative to the prior year comparative quarter.

Depreciation expense in the quarter was 17% higher than in the second quarter of 2014 due to the addition of new-build rigs deployed in 2014 and the first half of 2015.

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)	2015			2014			% Change			2015			2014			% Change
Revenue		35,589			66,508			(46.5	)		101,671			169,573			(40.0	)
Expenses:
Operating		31,993			56,564			(43.4	)		85,970			135,548			(36.6	)
General and administrative		4,300			4,807			(10.5	)		9,348			9,435			(0.9	)
Adjusted EBITDA(1)		(704	)		5,137			(113.7	)		6,353			24,590			(74.2	)
Depreciation		8,706			11,433			(23.9	)		17,464			22,861			(23.6	)
Operating earnings (loss)(1)		(9,410	)		(6,296	)		49.5			(11,111	)		1,729			(742.6	)
Operating earnings (loss) as a percentage of revenue		(26.4	%)		(9.5	%)					(10.9	%)		1.0	%
Well servicing statistics:
Number of service rigs (end of period)		177			221			(19.9	)		177			221			(19.9	)
Service rig operating hours		28,374			51,270			(44.7	)		76,375			133,834			(42.9	)
Service rig operating hour utilization		17	%		25	%					23	%		36	%
Service rig revenue per operating hour(2)		718			940			(23.6	)		792			904			(12.4	)

(1)

See “ADDITIONAL GAAP MEASURES”.

(2)

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

Revenue from Completion and Production Services was down $31 million or 46% compared to the second quarter of 2014 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 45% from the second quarter of 2014. Revenue was also negatively impacted by the sale of our U.S. coil tubing operations in the fourth quarter of last year. Approximately 92% of our first quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 76% of its revenue from Canadian and 24% from U.S. operations.

Average service rig revenue per operating hour in the second quarter was $718 or $222 lower than the second quarter of 2014. The decrease was primarily the result of industry pricing pressure and the sale of our U.S. coil tubing assets which generally received a higher rate per hour.

Adjusted EBITDA was $6 million lower than the second quarter of 2014 due to a decline in activity and pricing.

Operating costs as a percentage of revenue increased to 90% in the second quarter of 2015, from 85% in the second quarter of 2014. Operating costs per service rig operating hour were lower than in the second quarter of 2014 due to cost cutting measures and the sale of our U.S. coil tubing which typically operates at a higher cost per hour.

Depreciation in the quarter was 24% lower than the second quarter of 2014 because of decommissioning assets in the fourth quarter of 2014 and the disposal of our U.S. coil tubing assets.

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 $21 million for the second quarter of 2015, $3 million less than 2014 comparative period due primarily to lower share based incentive compensation.

OTHER ITEMS

Net financial charges for the quarter were $32 million, an increase of $7 million from the second quarter of 2014. The increase is due to the impact of the weaker Canadian dollar on the value of our U.S. dollar denominated debt and the issuance of US$400 million 5.25% Senior Notes on June 3, 2014. We had a foreign exchange loss of $8 million during the second quarter of 2014 due to the strengthening of the Canadian dollar versus the U.S. dollar from March 31, 2015, which affected our net U.S. dollar denominated monetary position in the Canadian dollar-based companies.

Income tax expense for the quarter was a recovery of $43 million compared with an expense of $6 million in the same quarter in 2014. 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. On June 29, 2015, the province of Alberta increased the Alberta corporate income tax rate from 10% to 12% effective July 1, 2015. The impact of this income tax rate increase was recognized in the current quarter.

In August 2014 the Ontario Court of Appeal ruled in favour of Precision’s wholly owned subsidiary, reversing a decision by the Ontario Superior Court of Justice in June 2013 regarding the reassessment of Ontario income tax for the subsidiary’s 2001 through 2004 taxation years. The Ontario Minister of Revenue made an application to the Supreme Court of Canada seeking leave to appeal this decision. On March 5, 2015, the Supreme Court of Canada brought the appeal process to an end and in April we received payment of $69 million from the Ontario tax authorities, $55 million for the refund of assessed taxes and $14 million in interest.

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 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.

Liquidity

During the quarter we increased the size of our demand letter of credit facility from US$25 million to US$40 million to provide additional availability to issue letters of credit for international opportunities.

In June 2014 we issued US$400 million of 5.25% Senior Notes due in 2024 in a private offering. The Notes are guaranteed on a senior unsecured basis by current and future U.S. and Canadian subsidiaries that also guarantee our revolving credit facility and certain other indebtedness.

In addition, we amended our credit agreement governing our revolving credit facility to, among other things, voluntarily reduce the size of the revolving credit facility from US$850 million to US$650 million and extend the maturity to June 3, 2019.

As at June 30, 2015 we had $2,009 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$650 million (extendible, revolving term credit facility with US$250 million accordion feature)	Undrawn, except US$26 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$40 million	Undrawn, except US$33 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$400 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 revolving term credit facility requires that we comply with certain financial covenants including leverage ratios of consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (Adjusted EBITDA) of less than 3:1 and consolidated total debt to Adjusted EBITDA of less than 4:1 for the most recent four consecutive fiscal quarters. During the first quarter we received temporary relief for the period up to and including December 31, 2016 for the ratio of consolidated total debt to Adjusted EBITDA whereby the ratio of less than 4:1 is increased to less than 6:1. For purposes of calculating the leverage ratios, consolidated total debt includes all outstanding secured and unsecured indebtedness, while consolidated senior debt only includes secured indebtedness. 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, 2015 our consolidated senior debt to Adjusted EBITDA ratio was 0.14:1 while our consolidated total debt to EBITDA ratio was 3.14:1.

Under the revolving credit facility we are also required to maintain an Adjusted EBITDA coverage ratio, calculated as Adjusted EBITDA to interest expense, of greater than 2.75:1 for the most recent four consecutive fiscal quarters. During the first quarter we received temporary relief for the period up to and including December 31, 2016 for the interest to Adjusted EBITDA coverage ratio whereby ratio of greater than 2.75:1 is reduced to greater than 2.5:1. As at June 30, 2015 our Adjusted EBITDA coverage ratio was 5.89:1.

In addition, the revolving 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 its 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, 2015, 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 2.5:1 for the most recent four consecutive fiscal quarters.

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; make restricted payments (including the payment of dividends); 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, 2015, 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.

Effective January 1, 2015 we have included the US$400 million of 5.25% Senior Notes due in 2024 as a designated hedge of our investment in our U.S. dollar denominated foreign operations and now all of our U.S. dollar Senior notes are designated as a net investment hedge.

Effective April 30, 2015 a portion of our U.S. dollar denominated debt that was previously treated as a hedge of our net investment in our U.S. operations was designated as a hedge of the investment in 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)

	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

	2013				2014
Quarters ended	September 30		December 31		March 31		June 30
Revenue		488,450		566,909		672,249		475,174
Adjusted EBITDA(1)		137,660		197,744		237,274		129,695
Net earnings (loss):		29,443		67,921		101,557		(7,174	)
Per basic share		0.11		0.24		0.35		(0.02	)
Per diluted share		0.10		0.24		0.35		(0.02	)
Funds provided by operations(1)		127,684		155,816		231,393		97,805
Cash provided by operations		88,341		94,452		170,127		228,412
Dividends paid per share		0.05		0.06		0.06		0.06

(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, financing charges, foreign exchange, and depreciation and amortization) as reported in the 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 depreciation and amortization charges.

Operating Earnings (Loss)

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

the payment of our declared quarterly dividend;

our capital expenditure plans for 2015;

timing on the expected delivery of rigs under our 2015 new-build program;

the expected changes in the size and distribution of our rig fleet following the delivery of all remaining contracted new-build rigs in 2015; and

our strategic priorities for the remainder of 2015.

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;

continued demand for Tier 1 rigs;

customer focus on safety performance;

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 and its impact on customer spending;

the risks associated with investing in capital assets and the impact arising out of the emergence of potentially disruptive technology;

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;

the existence of competitive operating risks inherent in our businesses;

changes in environmental and safety rules or regulations including increased regulatory burden on horizontal drilling and hydraulic fracturing;

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, 2014, 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.