EX-99.1 4 exh_991.htm EXHIBIT 99.1

Exhibit 99.1

Precision Drilling Corporation

Second Quarter Report for the three and six months ended June 30, 2017 and 2016

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s Discussion and Analysis for the three and six month period ended June 30, 2017 of Precision Drilling Corporation (“Precision” or the “Corporation”) prepared as at July 28, 2017 focuses on the unaudited Interim Consolidated Financial Statements and related notes and pertains to known risks and uncertainties relating to the oilfield services sector. This discussion should not be considered all inclusive as it does not include all changes regarding general economic, political, governmental and environmental events. This discussion should be read in conjunction with the Corporation’s 2016 Annual Report, Annual Information Form, unaudited June 30, 2017 Interim Consolidated Financial Statements and related notes.

This report contains “forward-looking information and statements” within the meaning of applicable securities laws. For a full disclosure of the forward-looking information and statements and the risks to which they are subject, see the “Cautionary Statement Regarding Forward-Looking Information and Statements” on page 16 of this report. This press release contains references to Adjusted EBITDA, Operating Loss and Funds Provided By (Used In) Operations. These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies, see “Non-GAAP Measures” on page 15 of this report.

Precision Drilling announces 2017 second quarter financial results:

Second quarter revenue was $276 million, an increase of 68% over the second quarter of 2016.

Second quarter earnings before income taxes, gain on repurchase of unsecured senior notes, finance charges, foreign exchange, and depreciation and amortization (adjusted EBITDA see “Non- GAAP Measures”) of $57 million was 152% higher than the second quarter of 2016.

Second quarter net loss was $36 million ($0.12 per share) compared with a net loss of $58 million ($0.20 per share) in the second quarter of 2016.

Second quarter capital expenditures were $28 million, with full year capital spending expected to be $138 million.

SELECT Financial And Operating INFORMATION

Adjusted EBITDA and funds provided by operations are Non-GAAP measures. See “NON-GAAP MEASURES.”

Financial Highlights

	Three months ended June 30,							Six months ended June 30,
(Stated in thousands of Canadian dollars, except per share amounts)		2017		2016		% Change			2017		2016		% Change
Revenue		275,524		163,979		68.0			621,324		465,706		33.4
Adjusted EBITDA⁽¹⁾		56,520		22,400		152.3			140,828		121,644		15.8
Adjusted EBITDA % of revenue		20.5	%	13.7	%				22.7	%	26.1	%
Net loss		(36,130	)	(57,677	)	(37.4	)		(58,744	)	(77,560	)	(24.3	)
Cash provided by operations		2,739		20,665		(86.7	)		36,509		132,839		(72.5	)
Funds provided by (used in) operations⁽¹⁾		(15,187	)	(31,372	)	(51.6	)		70,472		62,221		13.3
Capital spending:
Expansion		4,852		46,732		(89.6	)		8,644		65,933		(86.9	)
Upgrade		13,287		-		n/m			26,934		1,433		1,779.6
Maintenance and infrastructure		10,298		6,692		53.9			14,951		13,219		13.1
Proceeds on sale		(3,563	)	(1,548	)	130.2			(5,781	)	(3,705	)	56.0
Net capital spending		24,874		51,876		(52.1	)		44,748		76,880		(41.8	)

Net loss per share:
Basic and diluted		(0.12	)	(0.20	)	(40.0	)		(0.20	)	(0.26	)	(23.1	)

(1)

See “NON-GAAP MEASURES.”

n/m - calculation not meaningful.

Operating Highlights

	Three months ended June 30,					Six months ended June 30,
		2017	2016	% Change			2017	2016	% Change
Contract drilling rig fleet		256	252	1.6			256	252	1.6
Drilling rig utilization days:
Canada		2,639	1,202	119.6			9,458	5,197	82.0
U.S.		5,331	2,198	142.5			9,521	5,084	87.3
International		728	637	14.3			1,448	1,400	3.4
Revenue per utilization day:
Canada ⁽¹⁾⁽³⁾ (Cdn$)		18,245	24,980	(27.0	)		18,446	24,134	(23.6	)
U.S.⁽²⁾⁽³⁾ (US$)		19,134	27,519	(30.5	)		19,503	29,966	(34.9	)
International (US$)		49,679	44,391	11.9			50,054	42,874	16.7
Operating cost per utilization day:
Canada (Cdn$)		12,436	14,954	(16.8	)		10,641	11,836	(10.1	)
U.S. (US$)		13,556	14,899	(9.0	)		14,052	15,896	(11.6	)
Service rig fleet		210	163	28.8			210	163	28.8
Service rig operating hours		33,813	14,862	127.5			85,870	39,693	116.3
Revenue per operating hour (Cdn$)		629	602	4.5			633	691	(8.4	)

(1) Includes lump sum revenue from contract shortfall.

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

(3) Six months ended June 30, 2016 comparative includes revenue from contract cancellation payments.

Financial Position

(Stated in thousands of Canadian dollars, except ratios)	June 30, 2017	December 31, 2016
Working capital	243,903	230,874
Cash	95,064	115,705
Long-term debt⁽¹⁾	1,844,773	1,906,934
Total long-term financial liabilities	1,868,073	1,946,742
Total assets	4,078,083	4,324,214
Long-term debt to long-term debt plus equity ratio⁽¹⁾	0.49	0.49

(1)

Net of unamortized debt issue costs.

Summary for the three months ended June 30, 2017

· Revenue this quarter was $276 million representing a 68% increase over the second quarter of 2016. The increase in revenue was primarily the result of greater activity in all of our North American based businesses and higher average day rates from our international contract drilling business partially offset by fewer idle but contracted rigs, a decrease in average day rates in all of our North American businesses and no activity in our Mexico based contract drilling business. Compared with the second quarter of 2016 our activity for the quarter, as measured by drilling rig utilization days, increased 120% in Canada, 143% in the U.S. and 14% internationally. Revenue from our Contract Drilling Services and Completion and Production Services segments both increased over the comparative prior year period by 67% and 76%, respectively.

· Adjusted EBITDA this quarter of $57 million was an increase of $34 million from the second quarter of 2016. Our adjusted EBITDA as a percentage of revenue was 21% this quarter, compared with 14% in the second quarter of 2016. The increase in adjusted EBITDA as a percent of revenue was mainly due to fixed costs spread over higher activity in the quarter partially offset by lower average day rates in North America.

· Operating loss (see “Non-GAAP Measures”) this quarter was $39 million compared with an operating loss of $74 million in the second quarter of 2016. Operating results this quarter were positively impacted by increased activity in our North American businesses partially offset by lower average pricing.

· General and administrative expenses this quarter were $20 million, $8 million lower than the second quarter of 2016. The decrease was due to cost saving initiatives undertaken in 2016 and a decrease in our share based incentive compensation that is tied to the price of our common shares partially offset by a weaker Canadian dollar on our U.S. dollar denominated costs. As at June 30, 2017 we have a total share based incentive compensation liability of $23 million compared with $28 million at March 31, 2017 after having paid out $0.4 million in the quarter.

· Net finance charges were $35 million, an increase of $1 million compared with the second quarter of 2016 primarily due to higher interest income in 2016 and a weaker Canadian dollar on our U.S. dollar denominated interest expense, partially offset by a reduction in interest expense related to debt retired in 2016.

· In Canada, average revenue per utilization day for contract drilling rigs decreased in the second quarter of 2017 to $18,245 from $24,980 in the prior year and decreased in the U.S. to US$19,134 from US$27,519 over the same period. The decrease in Canada was the result of fewer rigs working under legacy contracts, lower contract shortfall payments and a higher proportion of revenue from shallower drilling activity relative to the 2016 comparative period. During the quarter, we recognized $4 million in revenue associated with contract shortfall payments in Canada which was a decrease of $2 million from the prior year period. The decrease in the U.S. revenue rate was the result of fewer rigs working under long-term contracts with legacy pricing and a lower daily revenue impact from idle but contracted rigs. We recognized US$5 million in turnkey revenue in the second quarter compared with US$6 million in the 2016 comparative period and US$2 million in idle but contracted revenue in the current quarter versus US$7 million in the comparative period.

· Average operating costs per utilization day for drilling rigs in Canada decreased to $12,436 compared with the prior year second quarter of $14,954. The decrease in average costs was due to improved absorption of fixed costs with higher utilization. In the U.S., operating costs for the quarter on a per day basis decreased to US$13,556 in 2017 compared with US$14,899 in 2016 due to fixed costs spread over higher utilization partially offset by favourable sales tax adjustments in the prior year comparative period.

· We realized revenue from international contract drilling of US$36 million in the second quarter of 2017, a US$8 million increase over the prior year period. The increase was due to the startup of two new rigs in Kuwait in the fourth quarter of 2016 partially offset by no activity in our Mexico operations. Average revenue per utilization day in our international contract drilling business was US$49,679 an increase of 12% over the comparable prior year quarter primarily due to rig mix as we had fewer rigs working in the lower day rate jurisdictions.

· During the quarter we added nine term contracts for drilling rigs, adding seven rig years to our contract book.

· Directional drilling services realized revenue of $12 million in the second quarter of 2017 compared with $3 million in the prior year period. The increase was the result of higher activity levels and day rates in both Canada and the U.S.

· Funds used in operations (see “Non-GAAP Measures”) in the second quarter of 2017 were $15 million, a decrease of $16 million from the prior year comparative quarter of $31 million. The improvement was primarily the result of stronger operating results in the current quarter compared with the prior year comparative quarter.

· Capital expenditures for the purchase of property, plant and equipment were $28 million in the second quarter, a decrease of $25 million over the same period in 2016. Capital spending for the quarter included $5 million for expansion capital, $13 million for upgrade capital and $10 million for the maintenance of existing assets and infrastructure spending.

Summary for the six months ended June 30, 2017:

· Revenue for the first half of 2017 was $621 million, an increase of 33% from the 2016 period.

· Operating loss was $52 million, a decrease of $18 million over the same period in 2016. Operating loss was 8% of revenue in 2017 compared to 15% of revenue in 2016. Operating results this year were positively impacted by increased activity in our North American businesses partially offset by lower average pricing.

· General and administrative costs were $45 million, a decrease of $10 million over the first half of 2016. The decrease was primarily due to fixed cost reductions implemented in 2016 and lower share based incentive compensation that is tied to the price of our common shares.

· Net finance charges were $68 million, a decrease of $2 million from the first half of 2016 primarily due to a reduction in interest expense related to debt retired in 2016 partially offset by higher interest income earned in the comparative period.

· Funds provided by operations (see “Non-GAAP Measures”) in the first half of 2017 were $70 million, an increase of $8 million from the prior year comparative period of $62 million.

· Capital expenditures for the purchase of property, plant and equipment were $51 million in the first half of 2017, a decrease of $30 million over the same period in 2016. Capital spending for 2017 to date included $9 million for expansion capital, $27 million for upgrade capital and $15 million for the maintenance of existing assets and infrastructure.

STRATEGY

Precision’s strategic priorities for 2017 are as follows:

Deliver High Performance, High Value service offering in an improving demand environment while demonstrating fixed cost leverage – In the U.S., we grew our active rig count by 56% throughout the first half of 2017. In Canada, we began the year with 50 active rigs and reached a seasonal peak of 91 rigs. Year-over-year in the first half 2017 our utilization days were up 134% across our North American drilling operations and was achieved without any material increase in fixed costs. In addition, we are upgrading our existing ERP system to increase operating efficiencies, improve our fixed cost leverage and position the organization to better handle the increased data flows associated with our business.

Commercialize rig automation and efficiency-driven technologies across our Super Series fleet – We have now installed 20 Process Automation Control systems on our rigs and beta-style field trials are progressing as planned. Year-to-date we have completed 30 jobs utilizing a Directional Guidance system and continue to prove out the synergies and efficiencies gained in using the software and reducing crew count. We expect to commercialize these automation features during 2017.

Maintain strict financial discipline in pursuing growth opportunities with a focus on free cash flow and debt reduction – Effectively all upgrade capital spending is supported by take-or-pay term contracts priced at a level that allows for attractive rates of return. In the first half of 2017, we generated funds from operations of $70 million (see “Non-GAAP Measures”).

OUTLOOK

For the second quarter of 2017, the average West Texas Intermediate price of oil was 6% higher than the prior year comparative period while average Henry Hub natural gas price was 39% higher.

	Three months ended June 30,		Year ended December 31,
	2017	2016	2016
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)	48.33	45.45	43.30
Natural gas
Canada
AECO (per MMBtu) (CDN$)	2.69	1.41	2.14
United States
Henry Hub (per MMBtu) (US$)	2.94	2.11	2.48

Contracts

The following chart outlines the average number of drilling rigs that we have under contract as of July 28, 2017 for the remaining quarters of 2017 and the full years 2017 and 2018.

	Average for the quarter ended 2017					Average for the year ended
		March 31	June 30	September 30	December 31	2017	2018
Average rigs under term contract as at July 28, 2017:
Canada		27	22	21	17	22	8
U.S.		26	30	29	21	27	7
International		8	8	8	8	8	7
Total		61	60	58	46	57	22

In Canada, term contracted rigs normally generate 250 utilization days per year because of the seasonal nature of well site access. In most regions in the U.S. and internationally, term contracts normally generate 365 utilization days per year. Year to date as of July 28, 2017 we have added 16 term contracts with durations of six months or longer.

Drilling Activity

The following chart outlines the average number of drilling rigs that we had working or moving by quarter for the periods noted.

Average for the quarter ended	2016			2017
	June 30	September 30	December 31	March 31	June 30
Average Precision active rig count:
Canada	13	31	51	76	29
U.S.	24	29	39	47	59
International	7	7	8	8	8
Total	44	67	98	131	96

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

On the back of improved commodity prices and industry activity levels, we were able to increase pricing across the majority of our fleet in the first half of 2017. Further pricing increases will be dependent on capital spending plans by our customers and resulting demand for our rigs, both of which are directly tied to commodity prices. The most competitive market in which we operate remains the shallower parts of the Western Canadian Sedimentary Basin, where pricing remains constrained due to excess rig availability.

Industry Conditions

In 2017, drilling activity has increased relative to this time last year for both Canada and the U.S. According to industry sources, as of July 28, 2017, the U.S. active land drilling rig count was up approximately 85% from the same point last year and the Canadian active land drilling rig count was up approximately 110%.

In Canada there has been a strengthening in natural gas and gas liquids drilling activity related to Deep Basin drilling in northwestern Alberta and northeastern British Columbia while the trend towards oil-directed drilling in the U.S. continues. To date in 2017, approximately 53% of the Canadian industry’s active rigs and 80% of the U.S. industry’s active rigs were drilling for oil targets, compared with 45% for Canada and 80% for the U.S. at the same time last year.

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

Capital Spending

Capital spending in 2017 is expected to be $138 million, split $132 million in the Contract Drilling Services segment and $6 million in the Completion and Production Services segment:

The 2017 capital expenditure plan includes $13 million for expansion capital, $71 million for sustaining and infrastructure expenditures, and $54 million to upgrade existing rigs. The increase in sustaining and infrastructure capital spending is primarily related to a substantial upgrade to our existing enterprise resource planning system (ERP). We are upgrading our existing ERP system to increase operating efficiencies, improve our fixed cost leverage and position the organization to better handle the increased data flows associated with our business.

Segmented Financial Results

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

	Three months ended June 30,							Six months ended June 30,
(Stated in thousands of Canadian dollars)		2017		2016		% Change			2017		2016		% Change
Revenue:
Contract Drilling Services		247,122		147,780		67.2			548,179		422,617		29.7
Completion and Production Services		29,381		16,731		75.6			75,730		45,185		67.6
Inter-segment eliminations		(979	)	(532	)	84.0			(2,585	)	(2,096	)	23.3
		275,524		163,979		68.0			621,324		465,706		33.4
Adjusted EBITDA:⁽¹⁾
Contract Drilling Services		67,031		42,503		57.7			160,696		158,120		1.6
Completion and Production Services		336		(2,568	)	(113.1	)		4,923		(4,775	)	(203.1	)
Corporate and other		(10,847	)	(17,535	)	(38.1	)		(24,791	)	(31,681	)	(21.7	)
		56,520		22,400		152.3			140,828		121,664		15.8

(1) See “NON-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)		2017		2016		% Change			2017		2016		% Change
Revenue		247,122		147,780		67.2			548,179		422,617		29.7
Expenses:
Operating⁽¹⁾		172,744		96,137		79.7			370,688		243,316		52.3
General and administrative⁽¹⁾		7,347		8,679		(15.3	)		16,795		18,764		(10.5	)
Restructuring		-		461		(100.0	)		-		2,417		(100.0	)
Adjusted EBITDA⁽²⁾		67,031		42,503		57.7			160,696		158,120		1.6
Depreciation		85,065		86,412		(1.6	)		171,254		170,691		0.3
Operating loss⁽²⁾		(18,034	)	(43,909	)	(58.9	)		(10,558	)	(12,571	)	(16.0	)
Operating loss as a percentage of revenue		(7.3	%)	(29.7	%)				(1.9	)	(3.0	%)

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

(2) See “NON-GAAP MEASURES”.

	Three months ended June 30,
Canadian onshore drilling statistics:⁽¹⁾		2017				2016
		Precision		Industry⁽²⁾		Precision		Industry⁽²⁾
Number of drilling rigs (end of period)		136		634		135		672
Drilling rig operating days (spud to release)		2,358		9,252		1,073		4,011
Drilling rig operating day utilization		19	%	16	%	9	%	7	%
Number of wells drilled		267		1,024		89		313
Average days per well		8.8		9.0		12.1		12.8
Number of metres drilled (000s)		758		2,928		301		931
Average metres per well		2,839		2,859		3,384		2,974
Average metres per day		321		316		281		232

	Six months ended June 30,
Canadian onshore drilling statistics:⁽¹⁾		2017				2016
		Precision		Industry⁽²⁾		Precision		Industry⁽²⁾
Number of drilling rigs (end of period)		136		634		135		672
Drilling rig operating days (spud to release)		8,400		32,756		4,644		17,177
Drilling rig operating day utilization		34	%	28	%	19	%	14	%
Number of wells drilled		831		3,308		338		1,375
Average days per well		10.1		9.9		13.7		12.5
Number of metres drilled (000s)		2,229		9,088		990		3,760
Average metres per well		2,682		2,747		2,928		2,735
Average metres per day		265		277		213		219

(1) Canadian operations only.

(2) Canadian Association of Oilwell Drilling Contractors (“CAODC”), and Precision – excludes non-CAODC rigs and non-reporting CAODC members.

United States onshore drilling statistics:⁽¹⁾	2017			2016
		Precision	Industry⁽²⁾		Precision	Industry⁽²⁾
Average number of active land rigs for quarters ended:
March 31		47	722		32	516
June 30		59	874		24	397
Year to date average		53	798		28	457

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $247 million this quarter, or 67% higher than the second quarter of 2016, while adjusted EBITDA increased by 58% to $67 million. The increase in revenue was due to higher utilization days in Canada and the U.S. and higher average day rates for international contract drilling. During the quarter we recognized $4 million in shortfall payments in our Canadian contract drilling business, which was $2 million lower than in the prior year comparative quarter. During the quarter in the U.S. we recognized US$2 million of idle but contracted revenue compared with US$7 million in the comparative quarter of 2016.

Drilling rig utilization days in Canada (drilling days plus move days) were 2,639 during the second quarter of 2017, an increase of 120% compared to 2016 primarily due to the increase in industry activity resulting from higher oil and natural gas prices. Drilling rig utilization days in the U.S. were 5,331, or 143% higher than the same quarter of 2016 as U.S. activity was up with higher industry activity. Drilling rig utilization days in our international business were 728 or 14% higher than the same quarter of 2016 due to the addition of two rigs in Kuwait during the fourth quarter of 2016 partially offset by no activity in Mexico.

Compared with the same quarter in 2016, drilling rig revenue per utilization day was down 27% in Canada due to fewer rigs working on legacy contracts, lower shortfall revenue and a higher proportion of revenue from shallower drilling activity relative to the 2016 comparative period. Drilling rig revenue per utilization day for the quarter in the U.S. was down 30% from the prior comparative period, while international revenue per utilization day was up 12%. The decrease in the U.S. average rate was a result of fewer rigs working under long-term contracts with legacy pricing and a lower daily revenue impact from idle but contracted rigs. International revenue per utilization day was up due to rig mix with a higher proportion of days from Kuwait during the quarter and no activity in Mexico.

In Canada, 31% of our utilization days in the quarter were generated from rigs under term contract, compared with 55% in the second quarter of 2016. In the U.S., 57% of utilization days were generated from rigs under term contract as compared with 70% in the second quarter of 2016.

Operating costs were 70% of revenue for the quarter, which was 5 percentage points higher than the prior year period. On a per utilization day basis, operating costs for the drilling rig division in Canada were lower than the prior year period primarily because of improved absorption of fixed costs with higher utilization and the timing of certifications. In the U.S., operating costs for the quarter on a per day basis were lower than the prior year period due to fixed costs spread over higher utilization partially offset by favourable sales tax adjustments in the prior year comparative period. Both Canada and U.S. operating costs benefited from cost saving initiatives taken in 2015 and 2016.

Depreciation expense in the quarter was 2% lower than in the second quarter of 2016.

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)		2017		2016		% Change			2017		2016		% Change
Revenue		29,381		16,731		75.6			75,730		45,185		67.6
Expenses:
Operating⁽¹⁾		27,231		16,107		69.1			67,099		42,329		58.5
General and administrative⁽¹⁾		1,814		2,644		(31.4	)		3,708		5,664		(34.5	)
Restructuring		-		548		(100.0	)		-		1,967		(100.0	)
Adjusted EBITDA⁽²⁾		336		(2,568	)	(113.1	)		4,923		(4,775	)	(203.1	)
Depreciation		7,094		6,568		8.0			14,497		13,778		5.2
Operating loss⁽²⁾		(6,758	)	(9,136	)	(26.0	)		(9,574	)	(18,553	)	(48.4	)
Operating loss as a percentage of revenue		(23.0	%)	(54.6	%)				(12.6	%)	(41.1	%)

Well servicing statistics:
Number of service rigs (end of period)		210		163		28.8			210		163		28.8
Service rig operating hours		33,813		14,862		127.5			85,870		39,693		116.3
Service rig operating hour utilization		18	%	10	%				23	%	13	%
Service rig revenue per operating hour		629		602		4.5			633		691		(8.4	)

(1)

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

(2)

See “NON-GAAP MEASURES”.

Revenue from Completion and Production Services was up $13 million or 76% compared with the second quarter of 2016 due to higher activity levels in all service lines partially offset by lower average rates. As oil and natural gas prices have recovered somewhat, customers have increased spending and activity in well completion and production programs. Our well servicing activity in the quarter was up 128% from the second quarter of 2016 as a result of improved industry activity levels and a larger fleet following the acquisition of service rigs late in the fourth quarter of 2016. Approximately 86% of our second quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 87% of its revenue from Canadian and 13% from U.S. operations in line with the second quarter of 2016.

Average service rig revenue per operating hour in the quarter was $629 or $27 higher than the second quarter of 2016. The increase was primarily the result of increased labour costs passed through to the customer.

Adjusted EBITDA was $3 million higher than the second quarter of 2016 as increased activity combined with cost cutting initiatives more than offset lower rates.

Operating costs as a percentage of revenue decreased to 93% in the second quarter of 2017, from 96% in the second quarter of 2016. The decrease was the result of the impact of fixed costs spread across greater activity combined with our reduced cost structure.

Depreciation in the quarter was 8% higher than the second quarter of 2016 due to the addition of well servicing units at the end of the fourth quarter of 2016 offset by assets becoming fully depreciated.

Segment Review of Corporate and Other

Our Corporate and Other segment provides support functions to our operating segments. The Corporate and Other segment had an adjusted EBITDA loss of $11 million a decrease of $7 million compared with the second quarter of 2016 primarily due to lower share based incentive compensation and cost saving initiatives.

Other items

Net financial charges for the quarter were $35 million, an increase of $2 million compared with the second quarter of 2016 primarily due to higher interest income in 2016 and a weaker Canadian dollar on our U.S. dollar denominated interest expense partially offset by a reduction in interest expense related to debt retired in 2016. For the current quarter we incurred a $1 million foreign exchange gain compared with a loss of $1 million during the second quarter of 2016.

Income tax expense for the quarter was a recovery of $37 million compared with a recovery of $50 million in the same quarter in 2016. The recoveries are due to negative pretax earnings.

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

Liquidity

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

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

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

As at June 30, 2017 we had $1,870 million outstanding under our senior unsecured notes. The current blended cash interest cost of our debt is approximately 6.5%.

Amount	Availability	Used for	Maturity
Senior facility (secured)
US$525 million (extendible, revolving term credit facility with US$250 million⁽¹⁾ accordion feature)	Drawn US$25 million in outstanding letters of credit	General corporate purposes	June 3, 2019
Operating facilities (secured)
$40 million	Undrawn, except $21 million in outstanding letters of credit	Letters of credit and general corporate purposes
US$15 million	Undrawn	Short term working capital requirements
Demand letter of credit facility (secured)
US$30 million	Undrawn, except US$4 million in outstanding letters of credit	Letters of credit
Senior notes (unsecured)
US$372 million – 6.625%	Fully drawn	Debt repayment and general corporate purposes	November 15, 2020
US$319 million – 6.5%	Fully drawn	Capital expenditures and general corporate purposes	December 15, 2021
US$350 million – 7.75%	Fully drawn	Debt redemption and repurchases	December 15, 2023
US$400 million – 5.25%	Fully drawn	Capital expenditures and general corporate purposes	November 15, 2024

(1)

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

Covenants

Senior Facility

The senior credit facility requires that we comply with certain covenants including a leverage ratio of consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (Adjusted EBITDA) of less than 2.5:1. For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness. Adjusted EBITDA, as defined in our revolving term facility agreement differs from Adjusted EBITDA as defined under Non-GAAP Measures by the exclusion of bad debt expense, restructuring costs and certain foreign exchange amounts. As at June 30, 2017 our consolidated senior debt to Adjusted EBITDA ratio was negative 0.2:1.

Effective January 20, 2017, under the senior credit facility, we are required to maintain a ratio of Adjusted EBITDA to interest expense for the most recent four consecutive quarters, of greater than 1.25:1 for the periods ending March 31, June 30 and September 30, 2017. For the periods ending December 31, 2017 and March 31, 2018 the ratio is 1.5:1 reverting to 2.5:1 thereafter. As at June 30, 2017 our senior credit facility Adjusted EBITDA to interest expense ratio was 1.71:1.

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

In addition, the senior credit facility contains certain covenants that place restrictions on our ability to incur or assume additional indebtedness; dispose of assets; pay dividends, undertake share redemptions or other distributions; change our primary business; incur liens on assets; engage in transactions with affiliates; enter into mergers, consolidations or amalgamations; and enter into speculative swap agreements.

At June 30, 2017, we were in compliance with the covenants of the senior credit facility.

Senior Notes

The senior notes require that we comply with financial covenants including an incurrence based consolidated interest coverage ratio test of consolidated cash flow, as defined in the senior note agreements, to interest coverage ratio of greater than 2.0:1 for the most recent four consecutive fiscal quarters. In the event that our consolidated interest coverage ratio is less than 2.0:1 for the most recent four consecutive fiscal quarters the senior notes restrict our ability to incur additional indebtedness. As at June 30, 2017, our senior notes consolidated interest coverage ratio was 1.58:1, which limits our ability to incur additional indebtedness, except as permitted under the agreements, until such time as we are in compliance with the ratio test, but would not restrict our access to available funds under the senior credit facility or to refinance our existing debt. Furthermore, it does not give rise to any cross-covenant violations, give the lenders the right to demand repayment of any outstanding portion of the senior notes prior to the stated maturity dates, or provide any other forms of recourse to the lenders.

The senior notes contain a restricted payments covenant that limits our ability to make payments in the nature of dividends, distributions and repurchases from shareholders. This restricted payment basket grows from a starting point of October 1, 2010 for the 2020, 2021 and 2024 Senior Notes and from October 1, 2016 for the 2023 Senior Notes by, among other things, 50% of cumulative net earnings and decreases by 100% of cumulative net losses as defined in the note agreements, and payments made to shareholders. Beginning with the December 31, 2015 calculation the governing net restricted payments basket was negative and as of that date we were no longer able to declare and make dividend payments until such time as the restricted payments baskets once again become positive. For further information, please see the senior note indentures which are available on SEDAR and EDGAR.

In addition, the senior notes contain certain covenants that limit our ability, and the ability of certain subsidiaries, to incur additional indebtedness and issue preferred shares; create liens; create or permit to exist restrictions on our ability or certain subsidiaries to make certain payments and distributions; engage in amalgamations, mergers or consolidations; make certain dispositions and engage in transactions with affiliates.

Hedge of investments in foreign operations

We utilize foreign currency long-term debt to hedge our exposure to changes in the carrying values of our net investment in certain foreign operations as a result of changes in foreign exchange rates.

We have designated our U.S. dollar denominated long-term debt as a net investment hedge in our U.S. operations and other foreign operations that have a U.S. dollar functional currency. To be accounted for as a hedge, the foreign currency denominated long-term debt must be designated and documented as such and must be effective at inception and on an ongoing basis. We recognize the effective amount of this hedge (net of tax) in other comprehensive income. We recognize ineffective amounts (if any) in net earnings (loss).

Quarterly Financial Summary

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

	2016					2017
Quarters ended		September 30		December 31			March 31		June 30
Revenue		201,802		283,903			345,800		275,524
Adjusted EBITDA⁽¹⁾		41,411		65,000			84,308		56,520
Net loss:		(47,377	)	(30,618	)		(22,614	)	(36,130	)
Per basic and diluted share		(0.16	)	(0.10	)		(0.08	)	(0.12	)
Funds provided by (used in) operations⁽¹⁾		31,688		11,466			85,659		(15,187	)
Cash provided by (used in) operations		17,515		(27,846	)		33,770		2,739

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

	2015					2016
Quarters ended		September 30		December 31			March 31		June 30
Revenue		364,089		344,953			301,727		163,979
Adjusted EBITDA⁽¹⁾		111,031		111,095			99,264		22,400
Net loss:		(86,700	)	(270,952	)		(19,883	)	(57,677	)
Per basic and diluted share		(0.30	)	(0.93	)		(0.07	)	(0.20	)
Funds provided by (used in) operations⁽¹⁾		99,228		49,503			93,593		(31,372	)
Cash provided by operations		61,049		70,952			112,174		20,665
Dividends paid per share		0.07		0.07			-		-

(1) See “NON-GAAP MEASURES”.

CRITICAL ACCOUNTING JUDGEMENTS AND ESTIMATES

Because of the nature of our business, we are required to make judgements and estimates in preparing our Consolidated Interim Financial Statements that could materially affect the amounts recognized. Our judgements and estimates are based on our past experiences and assumptions we believe are reasonable in the circumstances. The critical judgements and estimates used in preparing the Interim Financial Statements are described in our 2016 Annual Report and there have been no material changes to our critical accounting judgements and estimates during the three and six month periods ended June 30, 2017.

Changes in Accounting Policy

New Standards Not Yet Adopted

IFRS 9, Financial Instruments

In November 2009, the International Accounting Standards Board (IASB) issued IFRS 9, replacing IAS 39, Financial Instruments, Recognition and Measurement. IFRS 9 will be issued in three phases. The first phase, which has already been issued, addresses the accounting for financial assets and financial liabilities. The second phase will address impairment of financial instruments, while the third phase will address hedge accounting. IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, and replaces the multiple category and measurement models in IAS 39. The approach in IFRS 9 focuses on how an entity manages its financial instruments in the context of its business model, as well as the contractual cash flow characteristics of the financial assets. The new standard also requires a single impairment method to be used, replacing the multiple impairment methods currently provided in IAS 39.

Requirements for financial liabilities were added to IFRS 9 in October 2010. Although the classification criteria for financial liabilities will not change under IFRS 9, the fair value option may require different accounting for changes to the fair value of a financial liability resulting from changes to an entity’s own credit risk.

In December 2013, new hedge accounting requirements were incorporated into IFRS 9 that increase the scope of items that can qualify as a hedged item and change the requirements of hedge effectiveness testing that must be met to use hedge accounting.

In July 2014, the IASB issued final amendments to IFRS 9, replacing earlier versions of IFRS 9. These amendments to IFRS 9 introduce a single, forward-looking ‘expected loss’ impairment model for financial assets, which will require more timely recognition of expected credit losses, and a fair value through other comprehensive income category for financial assets that are debt instruments.

The amendments to IFRS 9 are effective for annual periods beginning on or after January 1, 2018 and are available for earlier adoption. We do not expect that the implementation of IFRS 9 will have a material effect on the financial statements.

IFRS 15, Revenue from Contracts with Customers

In May 2014, the IASB issued IFRS 15 to address how and when to recognize revenue as well as requiring entities to provide users of financial statements with more informative, relevant disclosures in order to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard provides a principles based, five-step model to be applied to all contracts with customers. This five-step model involves identifying the contract(s) with a customer; identifying the performance obligations in the contract; determining the transaction price; allocating the transaction price to the performance obligations in the contract; and recognizing revenue when (or as) the entity satisfies a performance obligation.

Application of this new standard is mandatory for annual reporting periods beginning on or after January 1, 2018, with earlier application permitted. We do not expect that the implementation of IFRS 15 will have a material effect on the financial statements.

IFRS 16, Leases

In January 2016, the IASB issued IFRS 16, replacing IAS 17. The new standard requires lessees to recognize a lease liability reflecting future lease payments and a right of use asset for virtually all lease contracts. In addition, IFRS 16 has updated the definition of a lease and introduced new disclosure requirements. IFRS 16 is effective for annual periods beginning on or after January 1, 2019, with earlier application permitted in certain circumstances. We have yet to determine the impact this new standard will have on the financial statements.

EVALUATION OF CONTROLS AND PROCEDURES

Precision maintains internal control over financial reporting and disclosure controls and procedures that are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS.

Management is responsible for establishing and maintaining adequate internal control over financial reporting and disclosure controls and procedures, as defined in Rules 13a – 15(f) and 15d – 15(f) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act) and under National Instrument 52-109 Certification of Disclosure in Issuer's Annual and Interim Filings (NI 52-109). Based on management's assessment as at June 30, 2017, management has concluded that Precision's disclosure controls and procedures over financial reporting are effective.

During the first six months of 2017, there were no changes made to Precision’s internal controls over financial reporting that materially affect, or are reasonably likely to materially affect its controls.

NON-GAAP MEASURES

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

Adjusted EBITDA

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

Operating Loss

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

Funds Provided By (Used In) Operations

We believe that funds provided by (used in) operations, as reported in the Interim Consolidated Statements of Cash Flow, is a useful measure because it provides an indication of the funds our principal business activities generate prior to consideration of working capital, which is primarily made up of highly liquid balances.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

Certain statements contained in this report, including statements that contain words such as "could", "should", "can", "anticipate", "estimate", "intend", "plan", "expect", "believe", "will", "may", "continue", "project", "potential" and similar expressions and statements relating to matters that are not historical facts constitute "forward-looking information" within the meaning of applicable Canadian securities legislation and "forward-looking statements" within the meaning of the "safe harbor" provisions of the United States Private Securities Litigation Reform Act of 1995 (collectively, "forward-looking information and statements").

In particular, forward looking information and statements include, but are not limited to, the following:

our strategic priorities for 2017;

our capital expenditure plans for 2017 and our scheduled ERP upgrade;

anticipated activity levels in 2017;

anticipated demand for Tier 1 rigs; and

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

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

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

the status of current negotiations with our customers and vendors;

customer focus on safety performance;

existing term contracts are neither renewed nor terminated prematurely;

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

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

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

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

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

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

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

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

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

the availability of qualified personnel and management;

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

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

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

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

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

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

SHAREHOLDER INFORMATION		CORPORATE INFORMATION

STOCK EXCHANGE LISTINGS
Shares of Precision Drilling Corporation are listed on the Toronto		DIRECTORS
Stock Exchange under the trading symbol PD and on the New York		William T. Donovan
Stock Exchange under the trading symbol PDS.		Brian J. Gibson
		Allen R. Hagerman, FCA
TRANSFER AGENT AND REGISTRAR		Catherine J. Hughes
Computershare Trust Company of Canada		Steven W. Krablin
Calgary, Alberta		Stephen J.J. Letwin
		Kevin O. Meyers
TRANSFER POINT		Kevin A. Neveu
Computershare Trust Company NA
Canton, Massachusetts		OFFICERS
		Kevin A. Neveu
Q2 2017 TRADING PROFILE		President and Chief Executive Officer
Toronto (TSX: PD)
High: $6.76		Douglas B. Evasiuk
Low: $4.08		Senior Vice President, Sales and Marketing
Close: $4.43
Volume Traded: 111,481,822		Veronica Foley
		Senior Vice President, General Counsel and Corporate Secretary
New York (NYSE: PDS)
High: US$4.93		Carey Ford
Low: US$3.05		Senior Vice President and Chief Financial Officer
Close: US$3.41
Volume Traded: 191,750,400		Darren J. Ruhr
		Senior Vice President, Corporate Services
ACCOUNT QUESTIONS
Precision’s Transfer Agent can help you with a variety of		Gene C. Stahl
shareholder related services, including:		President, Drilling Operations
•	change of address
•	lost unit certificates	AUDITORS
•	transfer of shares to another person	KPMG LLP
•	estate settlement	Calgary, Alberta

Computershare Trust Company of Canada		HEAD OFFICE
100 University Avenue		Suite 800, 525 8^th Avenue SW
9th Floor, North Tower		Calgary, Alberta, Canada T2P 1G1
Toronto, Ontario M5J 2Y1		Telephone: 403-716-4500
Canada		Facsimile: 403-264-0251
		Email: info@precisiondrilling.com
1-800-564-6253 (toll free in Canada and the United States)		www.precisiondrilling.com
1-514-982-7555 (international direct dialing)
Email: service@computershare.com

ONLINE INFORMATION
To receive news releases by email, or to view this interim report
online, please visit Precision’s website at www.precisiondrilling.com
and refer to the Investor Relations section. Additional information
relating to Precision, including the Annual Information Form,
Annual Report and Management Information Circular has been
filed with SEDAR and is available at www.sedar.com and on the
EDGAR website www.sec.gov.