EX-99.1 4 exh99_1.htm EXHIBIT 99.1

Exhibit 99.1

Precision Drilling Corporation

Third Quarter Report for the nine months ended September 30, 2015 and 2014

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's Discussion and Analysis for the three and nine month period ended September 30, 2015 of Precision Drilling Corporation ("Precision" or the "Corporation") prepared as at October 21, 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 September 30, 2015 Interim Consolidated Financial Statements and related notes and the cautionary statement regarding forward-looking information and statements on page 15 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 September 30,												Nine months ended September 30,
(Stated in thousands of Canadian dollars, except per share amounts)		2015				2014				% Change				2015				2014				% Change
Revenue			364,089				584,590				(37.7	)			1,210,671				1,732,013				(30.1	)
Adjusted EBITDA			111,031				199,390				(44.3	)			362,770				566,359				(35.9	)
Adjusted EBITDA  % of revenue			30.5	%			34.1	%							30.0	%			32.7	%
Net earnings (loss)			(86,700	)			52,813				(264.2	)			(92,484	)			147,196				(162.8	)
Cash provided by operations			61,049				146,733				(58.4	)			446,064				545,272				(18.2	)
Funds provided by operations			99,228				196,217				(49.4	)			307,587				525,415				(41.5	)
Capital spending:
Expansion			30,518				149,908				(79.6	)			322,039				335,747				(4.1	)
Upgrade			10,110				48,496				(79.2	)			42,145				93,946				(55.1	)
Maintenance and infrastructure			12,964				39,183				(66.9	)			28,275				88,747				(68.1	)
Proceeds on sale			(1,085	)			(31,286	)			(96.5	)			(7,559	)			(48,522	)			(84.4	)
Net capital spending			52,507				206,301				(74.5	)			384,900				469,918				(18.1	)
Earnings (loss) per share:
Basic			(0.30	)			0.18				(266.7	)			(0.32	)			0.50				(164.0	)
Diluted			(0.30	)			0.18				(266.7	)			(0.32	)			0.50				(164.0	)
Dividends paid per share			0.07				0.06				16.7				0.21				0.18				16.7

Operating Highlights

		Three months ended September 30,												Nine months ended September 30,
		2015				2014				% Change				2015				2014				% Change
Contract drilling rig fleet			330				335				(1.5	)			330				335				(1.5	)
Drilling rig utilization days:         Canada			4,505				8,071				(44.2	)			13,062				24,260				(46.2	)
U.S.			4,647				8,898				(47.8	)			17,063				25,861				(34.0	)
International			999				1,012				(1.3	)			3,262				2,964				10.1
Service rig fleet			177				221				(19.9	)			177				221				(19.9	)
Service rig operating hours			36,673				69,010				(46.9	)			113,048				202,844				(44.3	)

Financial Position

(Stated in thousands of Canadian dollars, except ratios)		September 30, 2015				December 31, 2014
Working capital			534,958				653,630
Long-term debt(1)			2,114,900				1,852,186
Total long-term financial liabilities			2,145,015				1,881,275
Total assets			5,268,980				5,308,996
Long-term debt to long-term debt plus equity ratio(1)			0.47				0.43

(1) Net of unamortized debt issue costs.

Financial Results

Net loss this quarter was $87 million, or $0.30 per diluted share, compared to net earnings of $53 million, or $0.18 per diluted share, in the third quarter of 2014.  Precision reviews the carrying value of its long-lived assets at each reporting period for indications of impairment.  During the period, significant decreases in industry activity resulting from the decline in oil and natural gas prices and its impact on current and future activity levels were indicators of impairment in seven of our cash generating asset groups and compelled us to complete an asset recovery test on these groups. The recoverable amount of property plant and equipment and goodwill was determined using a multi-year discounted cash flow with cash flow assumptions based on historical and expected future results. As a result of these tests, it was determined that property, plant and equipment in our Canadian well service business were impaired by $73 million and property, plant and equipment in our U.S. completion and production business were impaired by $7 million.  In addition, goodwill associated with our rentals cash generating unit was impaired for its full value of $17 million.  The after tax total impairments recorded in the current quarter was $74 million, or $0.25 per share.

Revenue this quarter was $364 million or 38% lower than the third quarter of 2014, mainly due to lower activity from our North American operations.  Revenue from our Contract Drilling Services and Completion and Production Services segments decreased over the comparative prior year period by 36% and 49%, respectively.

Earnings before income taxes, finance charges, foreign exchange, impairment of goodwill, impairment of property, plant and equipment and depreciation and amortization (adjusted EBITDA see "Additional GAAP Measures") this quarter were $111 million or 44% lower than the third quarter of 2014.

Our adjusted EBITDA as a percentage of revenue was 30% this quarter, compared to 34% in the third quarter of 2014. The decrease in adjusted EBITDA as a percent of revenue was mainly due to decreased activity in our Contract Drilling Services segment, decreased activity and lower pricing in our Completion and Production Services segment and costs associated with restructuring, which were $3 million this quarter.  Our activity for the quarter, as measured by drilling rig utilization days, decreased 44% in Canada, 48% in the U.S. and 1% internationally, compared to the third quarter of 2014.

Net loss for the first nine months of 2015 was $92 million, or $0.32 per diluted share, compared to net earnings of $147 million, or $0.50 per diluted share in 2014, while revenue was $1,211 million, or 30% less than 2014.

Revenue for the first nine months of 2015 was $1,211 million compared to $1,732 million for the corresponding period of 2014.  Adjusted EBITDA totaled $363 million for the first nine months of 2015 compared to $566 million in the first nine months of 2014.  The decrease in revenue and EBITDA was mainly the result of lower activity levels across our North American operations partially offset by higher average day rates in our contract drilling operations.  Activity for Precision, as measured by drilling utilization days, decreased 46% in Canada, 34% in the United States and increased 10% internationally for the first nine months of the year compared with the same period in 2014.

International Contract Award

Precision's wholly-owned international subsidiary, Grey Wolf Drilling International Ltd., recently contracted two new-build rigs for deep drilling operations in Kuwait. The two new 3000 HP Super Triple rigs are expected to be deployed in early 2017 on five year contracts with a possible one year extension period at the customer's discretion. Precision anticipates spending US$125 million on the completion of these two new build rigs, US$15 million in 2015, US$98 million in 2016, and US$12 million in 2017.

Capital Plan

Our current expected capital plan for 2015 is $531 million, a decrease of $15 million compared to the $546 million capital plan announced in July 2015.  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, four in the second and three in the third.  During the quarter four Tier 1 Super Triple drilling rigs were moved from the U.S. to Canada and we expect to move one more in the fourth 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, 129 will be in Canada, 101 in the U.S. and six internationally.

Precision expects its 2016 capital expenditure plan to be $180 million which includes $120 million for expansion capital and $60 million for maintenance and infrastructure expenditure. Precision expects that the $180 million will be split $175 million in the Contract Drilling segment and $5 million in the Completion and Production Services segment.

Amendment to Senior Credit Facility

During the quarter we agreed with the lending group to amend our credit agreements governing our senior credit facility to, among other things, reduce the size from US$650 million to US$550 million; eliminate the covenant of a maximum ratio of total debt to Adjusted EBITDA; amend the covenant of a maximum ratio of consolidated senior debt to Adjusted EBITDA from 3:1 to 2.5:1; amend the covenant of Adjusted EBITDA to consolidated interest expense from 2.75:1 to 2:1 on a temporary basis until first quarter of 2018 when it reverts to 2.5:1; and limit our ability to incur additional unsecured debt to US$250 million unless the new debt is to refinance existing unsecured debt or in the event debt is assumed in an acquisition. The approved amending agreement is expected to be finalized by the end of October 2015.  For more detail see the Liquidity and Capital Resources section later in this report.

Dividend

On October 21, 2015 The Board of Directors declared a dividend on its common shares of $0.07 per common share, payable on November 18, 2015, to shareholders of record on November 6, 2015.  Precision's senior notes contain covenants that limit our ability to make restricted payments, which could limit our ability to declare and pay future dividends.  For further information please see the Liquidity and Capital Resources section later in this release.

Strategic Priorities

Precision's strategic priorities for 2015 are as follows:

1. 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.

2. 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.

3. 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.

4. 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 third 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 September 30,								Year ended December 31,
		2015				2014				2014
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)			46.73				97.69				93.06
Natural gas
Canada
AECO (per MMBtu) (Cdn$)			2.91				4.03				4.45
U.S.
Henry Hub (per MMBtu) (US$)			2.74				3.93				4.33

Summary for the three months ended September 30, 2015:

• Operating loss (see "Additional GAAP Measures" in this news release) this quarter was $94 million, or negative 26% of revenue, compared to operating earnings of $92 million and 16% of revenue in 2014.  Operating results were negatively impacted by the impairment of property, plant and equipment and the decrease in activity in our North American operating segments.

• General and administrative expenses this quarter were $26 million, $12 million lower than the third 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.

• Under International Financial Reporting Standards, we are required to review the carrying value of our long-lived assets at each reporting period for indications of impairment.  Due to the decrease in oil and natural gas well drilling in Canada and the outlook for pricing, we recognized a $17 million goodwill impairment charge in the quarter which represents the full amount of goodwill attributable to our Canadian rental operation.

• Net finance charges were $35 million, an increase of $6 million compared with the third quarter of 2014 due to 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 third quarter of 2015 to $22,484 from the prior year third quarter of $21,110 in Canada and increased in the U.S. to US$26,202 from US$24,734.  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 third quarter of 2015, 62% of our utilization days were achieved from drilling rigs working under term contracts compared to 45% 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 and idle-but-contracted payments in the current quarter. In the U.S., for the third quarter of 2015, 71% of our utilization days were generated from rigs working under term contracts compared to 65% in the 2014 comparative period.  Turnkey revenue for the third quarter of 2015 was US$6 million compared with US$18 million in the 2014 comparative period.  Within the Completion and Production Services segment, average hourly rates for service rigs were $786 in the third quarter of 2015 compared to $889 in the third 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 third quarter of 2015 in both Canada and the United States.  In Canada costs increased to $11,684, compared to the prior year third quarter of $10,778 and in the U.S. costs increased to US$15,784 in 2015 compared to US$14,826 in 2014.  The cost increase in Canada was primarily due to costs associated with moving rigs from the U.S. to Canada.  The cost increase in the U.S. was primarily due to higher repair and maintenance costs and a lower activity base to spread fixed costs.

· We realized revenue from international contract drilling of $51 million in the third quarter of 2015, a $4 million decrease over the prior year period.  The decrease is due to an early termination payment of $8 million related to our Mexico operations in the third quarter of 2014 partially offset by adding a contracted rig in the Kingdom of Saudi Arabia in the fourth quarter of 2014 and a contracted rig in Kuwait in the second quarter of 2015.  Average revenue per utilization day in our international contract drilling business was US$38,893 a decrease of 23% over the comparable prior year quarter, primarily due to the termination payment received during the prior year quarter.

· Directional drilling services realized revenue of $12 million in the third quarter of 2015 compared with $36 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 third quarter of 2015 were $99 million, a decrease of $97 million from the prior year comparative quarter of $196 million.  The decrease was primarily the result of lower activity levels.

• Capital expenditures for the purchase of property, plant and equipment were $54 million in the third quarter, a decrease of $184 million over the same period in 2014.  Capital spending for the third quarter of 2015 included $31 million for expansion capital, $10 million for upgrade capital and $13 million for the maintenance of existing assets and infrastructure spending.

Summary for the nine months ended September 30, 2015:

• Revenue for the first nine months of 2015 was $1,211 million, a decrease of 30% from the 2014 period.

• Operating loss was $78 million, a decrease of $325 million from operating earnings of $247 million in 2014.  Operating loss was 6% of revenue in 2015 compared to operating earnings of 14% in 2014.  Operating results were negatively impacted by the impairment of property, plant and equipment, the decrease in activity in our North American operating segments and depreciation from capital asset additions in 2015 and 2014.

• General and administrative costs were $104 million, a decrease of $15 million over the first nine months of 2014 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.

• Due to the decrease in oil and natural gas well drilling in Canada and the outlook for pricing, we recognized a $17 million goodwill impairment charge which represents the full amount of goodwill attributable to our Canadian rental operation.

• Net finance charges were $87 million, an increase of $8 million from the first nine months 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 nine months of 2015 were $308 million, a decrease of $217 million from the prior year comparative period of $525 million.

• Capital expenditures for the purchase of property, plant and equipment were $392 million in the first nine months of 2015, a decrease of $126 million over the same period in 2014.  Capital spending for 2015 to date included $322 million for expansion capital, $42 million for upgrade capital and $28 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 October 21, 2015, we had term contracts in place for an average of 41 rigs in Canada, 37 in the U.S. and nine internationally for the fourth quarter of 2015 and an average of 46 rigs contracted in Canada, 47 in the U.S. and 12 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 51 rigs, down 46 rigs over the third quarter in 2014 and down seven rigs from the second quarter of 2015.  We currently have 45 rigs active in the U.S.

In Canada, our average active rig count in the quarter was 49 rigs, a decrease of 39 over the third quarter in 2014. We currently have 54 rigs active in Canada and despite tempered expectations for the upcoming drilling season in general, we expect to benefit from our fleet enhancements over the past several years.

Internationally, our average active rig count in the quarter was 11 rigs, in line with the third quarter in 2014 and down two rigs from the second quarter of 2015.  We currently have nine 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 October 16, 2015, the U.S. active land drilling rig count was down approximately 59% from the same point last year and the Canadian active land drilling rig count was down approximately 57%.

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 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 59% for Canada and 82% for the U.S. at the same time last year.

Capital Spending

Capital spending in 2015 is expected to be $531 million:

• The 2015 capital expenditure plan includes $423 million for expansion capital, $59 million for sustaining and infrastructure expenditures, and $49 million to upgrade existing rigs. We expect that the $531 million will be split $527 million in the Contract Drilling segment and $4 million in the Completion and Production Services segment.

• Precision's expansion capital plan for 2015 includes 18 new-build drilling rigs, 17 of which were delivered in the first nine months of the year.  The remaining rig is expected to be deployed in Canada in the fourth quarter.  Of the 17 rigs delivered, 13 rigs went to the U.S., three to Canada and one to Kuwait, all of which are on long-term contracts. Precision's recently contracted two new rigs for deep drilling operations in Kuwait. The two new 3000 HP Super Triple rigs are expected to be deployed in early 2017 on five year contracts with a possible one year extension period at the customer's discretion. Precision anticipates spending US$125 million on the completion of these two new build rigs, US$15 million in 2015, US$98 million in 2016, and US$12 million in 2017.

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

Precision expects its 2016 capital expenditure plan to be $180 million which includes $120 million for expansion capital and $60 million for maintenance and infrastructure expenditure. Precision expects that the $180 million will be split $175 million in the Contract Drilling segment and $5 million in the Completion and Production Services segment.

SEGMENTED FINANCIAL RESULTS

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

		Three months ended September 30,												Nine months ended September 30,
(Stated in thousands of Canadian dollars)		2015				2014				% Change				2015				2014				% Change
Revenue:
Contract Drilling Services			324,067				502,596				(35.5	)			1,072,075				1,485,400				(27.8	)
Completion and Production Services			42,961				84,539				(49.2	)			144,632				254,112				(43.1	)
Inter-segment eliminations			(2,939	)			(2,545	)			15.5				(6,036	)			(7,499	)			(19.5	)
			364,089				584,590				(37.7	)			1,210,671				1,732,013				(30.1	)
Adjusted EBITDA:(1)
Contract Drilling Services			120,093				200,865				(40.2	)			413,109				589,054				(29.9	)
Completion and Production Services			4,304				17,350				(75.2	)			10,657				41,940				(74.6	)
Corporate and other			(13,366	)			(18,825	)			(29.0	)			(60,996	)			(64,635	)			(5.6	)
			111,031				199,390				(44.3	)			362,770				566,359				(35.9	)

 (1) See "ADDITIONAL GAAP MEASURES".

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

		Three months ended September 30,												Nine months ended September 30,
(Stated in thousands of Canadian dollars, except where noted)		2015				2014				% Change				2015				2014				% Change
Revenue			324,067				502,596				(35.5	)			1,072,075				1,485,400				(27.8	)
Expenses:
Operating			191,434				287,674				(33.5	)			616,734				856,518				(28.0	)
General and administrative			9,756				14,057				(30.6	)			33,316				39,828				(16.4	)
Restructuring			2,784				-				n/	m			8,916				-				n/	m
Adjusted EBITDA(1)			120,093				200,865				(40.2	)			413,109				589,054				(29.9	)
Depreciation			113,429				94,618				19.9				325,667				279,094				16.7
Operating earnings(1)			6,664				106,247				(93.7	)			87,442				309,960				(71.8	)
Operating earnings as a percentage of revenue			2.1	%			21.1	%							8.2	%			20.9	%
Drilling rig revenue per utilization day in Canada			22,484				21,110				6.5				23,056				22,110				4.3
Drilling rig revenue per utilization day in the United States(2) (US$)			26,202				24,734				5.9				26,238				24,407				7.5
Drilling rig revenue per utilization day in International  (US$)			38,893				50,233				(22.6	)			30,755				27,242				12.9

(1) See "ADDITIONAL GAAP MEASURES".

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

n/m - calculation not meaningful.

		Three months ended September 30,
Canadian onshore drilling statistics:(1)		2015								2014
		Precision				Industry(2)				Precision				Industry(2)
Number of drilling rigs (end of period)			181				765				190				814
Drilling rig operating days (spud to release)			4,085				16,752				7,160				34,209
Drilling rig operating day utilization			25	%			24	%			41	%			46	%
Number of wells drilled			398				1,476				829				3,052
Average days per well			10.3				11.3				8.6				11.2
Number of metres drilled (000s)			881				3,549				1,594				6,821
Average metres per well			2,214				2,405				1,922				2,235
Average metres per day			216				212				223				199

		Nine months ended September 30,
Canadian onshore drilling statistics:(1)		2015								2014
		Precision				Industry(2)				Precision				Industry(2)
Number of drilling rigs (end of period)			181				765				190				814
Drilling rig operating days (spud to release)			11,630				50,438				21,527				97,280
Drilling rig operating day utilization			24	%			24	%			42	%			44	%
Number of wells drilled			1,070				3,992				2,172				7,933
Average days per well			10.9				12.6				9.9				12.3
Number of metres drilled (000s)			2,441				10,260				4,220				17,911
Average metres per well			2,281				2,570				1,943				2,258
Average metres per day			210				203				196				184

(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
September 30			51				829				97				1,842
Year to date average			63				1,015				95				1,789

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $324 million this quarter, or 36% lower than the third quarter of 2014, while adjusted EBITDA decreased by 40% to $120 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 higher average day rates in Canada and the United States.

Drilling rig utilization days in Canada (drilling days plus move days) were 4,505 during the third quarter of 2015, a decrease of 44% 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 4,647 or 48% 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 999 or 1% lower than the same quarter of 2014 as activity declines in Kurdistan were partially offset by adding a contracted rig in Kuwait and Georgia in 2015.

Compared to the same quarter in 2014, drilling rig revenue per utilization day was up 7% in Canada, 6% in the U.S. and down 23% in international.  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 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 and idle-but-contracted payments in the quarter relative to the prior year comparative quarter.  The average international day rate is down due to the recognition of an early termination payment of $8 million in the prior year comparative period partially offset by changes in the U.S. to Canadian dollar exchange rate.

In Canada, 62% of utilization days in the quarter were generated from rigs under term contract, compared to 45% in the third quarter of 2014.  In the U.S., 71% of utilization days were generated from rigs under term contract as compared to 65% in the third quarter of 2014. At the end of the quarter, we had 44 drilling rigs under contract in Canada, 33 in the U.S. and nine internationally.

Operating costs were 59% of revenue for the quarter, which was two 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 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 fixed costs spread across fewer rigs and large turnkey jobs in the quarter relative to the prior year comparative quarter.

Depreciation expense in the quarter was 20% higher than in the third quarter of 2014 due to the addition of new-build rigs deployed in 2014 and the first nine months of 2015.

SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES

		Three months ended September 30,												Nine months ended September 30,
(Stated in thousands of Canadian dollars, except where noted)		2015				2014				% Change				2015				2014				% Change
Revenue			42,961				84,539				(49.2	)			144,632				254,112				(43.1	)
Expenses:
Operating			35,377				62,581				(43.5	)			120,046				198,129				(39.4	)
General and administrative			3,222				4,608				(30.1	)			12,115				14,043				(13.7	)
Restructuring			58				-				n/	m			1,814				-				n/	m
Adjusted EBITDA(1)			4,304				17,350				(75.2	)			10,657				41,940				(74.6	)
Depreciation			8,714				10,911				(20.1	)			26,178				33,772				(22.5	)
Impairment or property, plant and equipment			79,573				-				n/	m			79,573				-				n/	m
Operating earnings (loss) (1)			(83,983	)			6,439				(1,404.3	)			(95,094	)			8,168				(1,264.2	)
Operating earnings (loss) as a percentage of revenue			(195.5	%)			7.6	%							(65.7	%)			3.2	%
Well servicing statistics:
Number of service rigs (end of period)			177				221				(19.9	)			177				221				(19.9	)
Service rig operating hours			36,673				69,010				(46.9	)			113,048				202,844				(44.3	)
Service rig operating hour utilization			22	%			32	%							23	%			31	%
Service rig revenue per operating hour(2)			786				889				(11.6	)			791				900				(12.1	)

(1) See "ADDITIONAL GAAP MEASURES".

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

n/m - calculation not meaningful.

Revenue from Completion and Production Services was down $42 million or 49% compared to the third 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 including well completion and production programs lowering activity.  Our well servicing activity in the quarter was down 47% from the third 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 86% of our third quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 84% of its revenue from Canadian and 16% from U.S. operations.

Average service rig revenue per operating hour in the third quarter was $786 or $103 lower than the third 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 $13 million lower than the third quarter of 2014 due to declines in activity and pricing.

Operating costs as a percentage of revenue increased to 82% in the third quarter of 2015, from 74% in the third quarter of 2014. Service rig operating costs per hour were lower in the third quarter of 2015 due to cost cutting measures and the sale of our U.S. coil tubing which typically operated at a higher cost per hour.

Due to the significant decrease in industry activity resulting from the decline in oil and natural gas prices we completed an impairment test of our businesses in our Completion and Production Services Segment in the third quarter of 2015.  The recoverable amount of property plant and equipment and goodwill was determined using a multi-year discounted cash flow approach with cash flow assumptions based on historical and expected future results.  As a result of this test it was determined that property, plant and equipment in our Canadian well service business were impaired by $73 million and property, plant and equipment in our U.S. completion and productions business were impaired by $7 million.

Depreciation in the quarter was 20% lower than the third 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 $13 million for the third quarter of 2015, $5 million less than 2014 comparative period due primarily to lower share based incentive compensation.

OTHER ITEMS

Net financial charges for the quarter were $35 million, an increase of $6 million from the third quarter of 2014.  The increase is due to the impact of the weaker Canadian dollar on our U.S. dollar denominated interest expense.  We had a foreign exchange gain of $13 million during the third quarter of 2015 due to the weakening of the Canadian dollar versus the U.S. dollar from June 30, 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 $46 million compared with an expense of $8 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 second 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.  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 third quarter we agreed with our lending group to certain amendments to our senior credit facility with final completion of the amending agreement expected by the end of October 2015.  The following are the amendments agreed to:

· The consolidated total debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (Adjusted EBITDA) covenant ratio be eliminated in its entirety;

· The Adjusted EBITDA to interest expense coverage ratio of greater than 2.75:1 be temporarily reduced to 2:1 for the period up to and including December 31, 2017, reverting back to 2.5:1 in January 2018;

· The consolidated senior debt to Adjusted EBITDA covenant ratio be reduced from less than 3.0:1 to less than 2.5:1;

· Reduction in the size of the  revolver from US$650 million to US$550 million;

· Place a limitation not to incur or assume more than US$250 million in new unsecured debt unless the new debt is to refinance existing unsecured debt or the new debt is assumed through an acquisition.

As at September 30, 2015 we had $2,142 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) (1)	Undrawn, except US$46 million in outstanding letters of credit	General corporate purposes	June 3, 2019
Operating facilities (secured)
$40 million	Undrawn, except $20 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$31 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

(1)  Subsequent to the period end Precision agreed with its lending group to reduce the size of the senior facility to US$550 million.

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. 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 September 30, 2015 our consolidated senior debt to Adjusted EBITDA ratio was 0.21:1.

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 2:1 reverting to 2.5:1 for periods ending after December 31, 2017 for the most recent four consecutive fiscal quarters.  As at September 30, 2015 our Adjusted EBITDA coverage ratio was 5.70:1.

In addition, the senior credit facility contains certain covenants that place restrictions on our ability to incur or assume additional indebtedness; dispose of assets; pay dividends, 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 September 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.   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.  Although recent net losses have not yet reduced this basket to a size that will prevent us from making such payments, if industry trends persist the basket may reduce such that we are unable to declare and pay dividends in the near future.  Based on the unaudited interim financial statements, as at September 30, 2015, the restricted payments basket was $135 million.  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 September 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		December 31				March 31				June 30				September 30
Revenue			618,525				512,120				334,462				364,089
Adjusted EBITDA(1)			234,011				163,384				88,355				111,031
Net earnings (loss):			(114,044	)			24,033				(29,817	)			(86,700	)
Per basic share			(0.39	)			0.08				(0.10	)			(0.30	)
Per diluted share			(0.39	)			0.08				(0.10	)			(0.30	)
Funds provided by operations(1)			172,059				155,186				53,173				99,228
Cash provided by operations			134,887				215,138				169,877				61,049
Dividends paid per share			0.07				0.07				0.07				0.07

		2013				2014
Quarters ended		December 31				March 31				June 30				September 30
Revenue			566,909				672,249				475,174				584,590
Adjusted EBITDA(1)			197,744				237,274				129,695				199,390
Net earnings (loss):			67,921				101,557				(7,174	)			52,813
Per basic share			0.24				0.35				(0.02	)			0.18
Per diluted share			0.24				0.35				(0.02	)			0.18
Funds provided by operations(1)			155,816				231,393				97,805				196,217
Cash provided by operations			94,452				170,127				228,412				146,733
Dividends paid per share			0.06				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, impairment of goodwill, impairment of property, plant and equipment 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 dividend;

· the contracting and deployment of two new-build drilling rigs to Kuwait;

· our capital expenditure plans for 2016 and for the remainder of 2015;

· changes to the size, breakdown and geographic distribution of our rig fleet upon completion of our 2015 new-build program and redeployment of certain rigs from the U.S. to Canada;

· the amendments to our senior credit facility;

· the expected benefits resulting from our fleet enhancements over the past several years;

· our strategic priorities for the remainder of 2015; and

· our ability to declare and make future payments to shareholders, including dividends if certain financial covenants under our senior note indentures are not met.

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:

· current and anticipated drilling activity levels;

· 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;

· our customers' ability 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, 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.