Precision Drilling Corporation Announces 2016 Second

CALGARY, ALBERTA--(Marketwired - July 21, 2016) - Precision Drilling Corporation - (TSX:PD)(NYSE:PDS)

(Canadian dollars except as indicated)

This news release 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" later in this news release.

For the second quarter of 2016, we recorded earnings before income taxes, finance charges, foreign exchange, and depreciation and amortization (adjusted EBITDA see "Additional GAAP Measures") of $22 million, 75% lower than the second quarter of 2015. Our activity for the quarter, as measured by drilling rig utilization days, decreased 48% in Canada, 58% in the U.S. and 44% internationally, compared to the second quarter of 2015. Our adjusted EBITDA as a percentage of revenue was 14% this quarter, compared to 26% in the second quarter of 2015. The decrease in adjusted EBITDA as a percent of revenue was mainly due to decreased activity in all of our businesses and lower spot market pricing.

We recorded a net loss this quarter of $58 million, or $0.20 per diluted share, compared to a net loss of $30 million, or $0.10 per diluted share, in the second quarter of 2015.

Revenue this quarter was $164 million or 51% lower than the second quarter of 2015, mainly due to lower 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 51% and 53%, respectively.

Net loss for the first six months of 2016 was $78 million, or $0.26 per diluted share, compared to a net loss of $6 million, or $0.02 per diluted share in 2015, while revenue was $466 million, or 45% less than 2015.

Kevin Neveu, Precision's President and Chief Executive Officer, stated: "Precision's second quarter results were adversely affected by weak customer demand and seasonally low Canadian spring break-up activity levels. During the quarter, North American oil and gas companies demonstrated a near instantaneous reaction to the low commodity prices experienced earlier this year by slashing spending, which resulted in the lowest drilling activity levels in decades. Despite this industry-wide pullback, Precision did not record any further cancelations in its contracted rig backlog, and all customer contracts continue to perform as expected. In addition, our second quarter results highlight the ability of Precision to generate strong field level margins on a full cycle basis. This is a result of Precision's High Performance Tier 1 asset base, variable cost operating model and most importantly the efforts and results of our people focused on safe and highly efficient operations."

"As commodity prices have recently improved, our activity levels have also modestly improved, up 27% in the US from trough levels to 28 active rigs and seasonally increasing in Canada to 26 active rigs. Notably, we have increased our contract backlog by one rig in 2016 and added four rigs on average under contract for 2017. Our customers appear to be looking beyond the oil price lows of earlier this year, resetting spending to current commodity price levels, and beginning the early stages of planning for improved longer term fundamentals."

"While the customer base is facing similar commodity price pressure in our international markets, Precision's activity and pricing held steady through the quarter. For our two new-build Kuwait rigs, we continue to take advantage of improved supplier lead times and expect to finish construction early and on budget, delivering the rigs sequentially to Kuwait later this quarter and early in the fourth quarter. Ending 2016 with a five rig operating base in Kuwait will provide both the scale and market position we seek in one of the lowest cost hydrocarbon producing regions in the world."

"For the balance of the year, we remain committed to our 2016 priorities. We will maintain strong liquidity, continue to deliver the Precision High Performance, High Value services to the field with leading safety and mechanical uptime performance, and be prepared for a rebound in activity. Precision's fleet of Tier 1 rigs are maintained to the best industry standards, and our recruitment and training teams are working rigorously to identify and bring back as many field employees to the Precision family when activity resumes," concluded Mr. Neveu.

SELECT FINANCIAL AND OPERATING INFORMATION

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


Financial Highlights
		Three months ended June 30,						Six months ended June 30,
(Stated in thousands of Canadian dollars, except per share amounts)		2016		2015		% Change		2016		2015		% Change
Revenue		163,979		334,462		(51.0	)	465,706		846,582		(45.0	)
Adjusted EBITDA		22,400		88,355		(74.6	)	121,644		251,739		(51.7	)
Adjusted EBITDA % of revenue		13.7	%	26.4	%			26.1	%	29.7	%
Net loss		(57,677	)	(29,817	)	93.4		(77,560	)	(5,784	)	1,240.9
Cash provided by operations		20,665		169,877		(87.8	)	132,839		385,015		(65.5	)
Funds provided by (used in) operations		(31,372	)	53,173		(159.0	)	62,221		208,359		(70.1	)
Capital spending:
	Expansion	46,732		94,204		(50.4	)	65,933		291,521		(77.4	)
	Upgrade	-		12,092		(100.0	)	1,433		32,035		(95.5	)
	Maintenance and infrastructure	6,692		6,749		(0.8	)	13,219		15,311		(13.7	)
	Proceeds on sale	(1,548	)	(3,598	)	(57.0	)	(3,705	)	(6,474	)	(42.8	)
Net capital spending		51,876		109,447		(52.6	)	76,880		332,393		(76.9	)

Loss per share:
	Basic	(0.20	)	(0.10	)	(100.0	)	(0.26	)	(0.02	)	1,200.0
	Diluted	(0.20	)	(0.10	)	(100.0	)	(0.26	)	(0.02	)	1,200.0
Dividends paid per share		-		0.07		(100.0	)	-		0.14		(100.0	)


Operating Highlights
		Three months ended June 30,				Six months ended June 30,
		2016	2015	% Change		2016	2015	% Change
Contract drilling rig fleet		252	329	(23.4	)	252	329	(23.4	)
Drilling rig utilization days:
	Canada	1,202	2,327	(48.3	)	5,197	8,557	(39.3	)
	U.S.	2,198	5,219	(57.9	)	5,084	12,416	(59.1	)
	International	637	1,129	(43.6	)	1,400	2,263	(38.1	)
Service rig fleet		163	177	(7.9	)	163	177	(7.9	)
Service rig operating hours		12,972	28,374	(54.3	)	37,803	76,375	(50.5	)


Financial Position
(Stated in thousands of Canadian dollars, except ratios)	June 30, 2016	December 31, 2015
Working capital	502,359	536,815
Long-term debt⁽¹⁾	2,049,286	2,180,510
Total long-term financial liabilities	2,079,745	2,210,231
Total assets	4,512,400	4,878,690
Long-term debt to long-term debt plus equity ratio⁽¹⁾	0.50	0.51

⁽¹⁾ Net of unamortized debt issue costs.

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

Precision's strategic priorities for 2016 are as follows:

Maintain strong liquidity to manage through an extended downturn - Sustain adequate liquidity by generating positive operating cash flow, ensure access to our revolving credit facility, and continue a multi-year plan for net debt reduction.
Sustain High Performance, High Value service offering - Continue to deliver maximum efficiency and lower risks to support development drilling programs by operating the highest quality assets in the industry with well-trained, professional crews supported by robust systems that eliminate manual processes and improve automation throughout the Precision organization.
Position for an eventual rebound - Concurrent with right-sizing the organization for the extended downturn, we will take steps to prepare for a rebound:
Asset integrity - maintain high quality and integrity of our Tier 1 drilling fleet by utilizing spare equipment, avoiding fleet cannibalization and maintaining rigorous equipment standards.
People - retain field leadership within the organization, maintain relationships with former crew members and continue to develop leadership and skills of workers within our organization.
Ample liquidity - maintain strong liquidity to fund working capital requirements and other short term commitments that arise when activity levels increase.

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


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

Summary for the three months ended June 30, 2016:

Operating loss (see "Additional GAAP Measures" in this news release) this quarter was $74 million, or negative 45% of revenue, compared to an operating loss of $32 million and negative 9% of revenue in 2015. Operating results were negatively impacted by the decrease in drilling activity and day rates in all of our operating segments.
General and administrative expenses this quarter were $29 million, $3 million lower than the second quarter of 2015. The decrease is primarily due to cost savings initiatives partially offset by higher accrued incentive compensation, which is tied to the price of our common shares, and the effect of the weakening Canadian dollar on our U.S. dollar denominated costs.
Net finance charges were $33 million, an increase of $1 million compared with the second quarter of 2015 due to the impact of foreign exchange on our U.S. dollar denominated interest partially offset by interest received in the current quarter on a tax dispute settlement.
Average revenue per utilization day for contract drilling rigs increased in the second quarter of 2016 to $24,980 from the prior year second quarter of $22,939 in Canada and decreased slightly in the U.S. to US$27,519 from US$27,731. The increase in Canada is the result of a higher proportion of revenue from Super Triple rigs relative to the 2015 comparative period and contract shortfall payments received in the quarter partially offset by lower spot market rates. The decrease in the U.S. is the result of lower spot market rates and lower turnkey activity partially offset by a higher daily revenue impact from idle but contracted rigs. We had US$6 million in turnkey revenue for the second quarter of 2016 compared with US$17 million in the 2015 comparative period and US$7 million in idle but contracted revenue in the current quarter versus US$9 million in the prior year.
Average operating costs per utilization day for drilling rigs in Canada increased to $14,954, compared to the prior year second quarter of $12,818 primarily because of the impact of fixed costs on lower activity partially offset by crew wage reductions and cost savings initiatives. In the U.S., operating costs for the quarter on a per day basis decreased to US$14,899 in 2016 compared to US$15,896 in 2015 due to sales tax adjustments, lower turnkey activity and cost savings initiatives partially offset by fixed costs spread over fewer active rigs.
We realized revenue from international contract drilling of $36 million in the second quarter of 2016, a $27 million decrease over the prior year period. Average revenue per utilization day in our international contract drilling business was US$44,391 a decrease of 3% over the comparable prior year quarter.
Directional drilling services realized revenue of $3 million in the second quarter of 2016 compared with $5 million in the prior year period. The decrease was primarily the result of a decline in activity in both the U.S. and Canada.
Funds used in operations in the second quarter of 2016 were $31 million, a decrease of $85 million from the funds provided by operations in the prior year comparative quarter of $53 million. The decrease was primarily the result of lower activity levels in the current year period.
Capital expenditures for the purchase of property, plant and equipment were $53 million in the second quarter, a decrease of $60 million over the same period in 2015. Capital spending for the second quarter of 2016 included $47 million primarily for international expansion capital and $6 million for the maintenance of existing assets and infrastructure spending.

Summary for the six months ended June 30, 2016:

Revenue for the first half of 2016 was $466 million, a decrease of 45% from the 2015 period.
Operating loss was $70 million, a decrease of $86 million over the same period in 2015. Operating loss was 15% of revenue in 2016 compared to operating earnings of 2% of revenue in 2015. Operating earnings were negatively impacted by the decreased drilling activity and rates in our North American operations.
General and administrative costs were $57 million, a decrease of $16 million over the first half of 2015. The decrease is due to efforts in reducing fixed costs through the downturn and lower share based incentive compensation that is tied to the price of our common shares partially offset by the weakening Canadian dollar on U.S. dollar denominated costs.
Net finance charges were $69 million, an increase of $17 million from the first half of 2015 primarily due to the recognition of $14 million interest revenue in the comparative period related to an income tax dispute settlement and the impact of foreign exchange on our U.S. dollar denominated interest.
Funds provided by operations (see "Additional GAAP Measures" in this news release) in the first half of 2016 were $62 million, a decrease of $146 million from the prior year comparative period of $208 million.
Capital expenditures for the purchase of property, plant and equipment were $81 million in the first half of 2016, a decrease of $258 million over the same period in 2015. Capital spending for 2016 to date included $66 million for expansion capital, $2 million for upgrade capital and $13 million for the maintenance of existing assets and infrastructure.

OUTLOOK

Contracts

Our portfolio of term customer contracts provides a base level of activity and revenue. As of July 20, 2016, for the third quarter of 2016 we had, on average, term contracts for 29 rigs in Canada, 21 in the U.S. and seven internationally. For the 2016 calendar year we have on average 30 rigs contracted in Canada, 21 in the U.S. and seven internationally and a total average of 35 rigs for the full year in 2017. In Canada, term contracted rigs normally generate 250 utilization days per year because of the seasonal nature of well site access. In most regions in the U.S. and internationally, term contracts normally generate 365 utilization days per year.

Drilling Activity

In the U.S., our average active rig count in the quarter was 24 rigs, down 33 rigs over the second quarter in 2015 and down eight rigs from the first quarter of 2016. We currently have 28 rigs active in the U.S.

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

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

Internationally, our average active rig count in the quarter was seven rigs, down five rigs over the second quarter in 2015 and down one rig from the first quarter of 2016. The decrease from the first quarter is the result of one fewer rig working in Mexico while the decrease over the prior year is primarily coming from fewer rigs working in Mexico and no rigs currently working in Kurdistan. We currently have seven rigs active internationally.

Industry Conditions

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

In Canada there has been strength in natural gas and gas liquids drilling activity related to deep basin drilling in northwestern Alberta and northeastern British Columbia while the trend towards oil-directed drilling in the U.S. continues. To date in 2016, approximately 45% of the Canadian industry's active rigs and 80% of the U.S. industry's active rigs were drilling for oil targets, compared to 45% for Canada and 77% for the U.S. at the same time last year.

Capital Spending

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

The 2016 capital expenditure plan includes $158 million for expansion capital, $42 million for sustaining and infrastructure expenditures, and $2 million to upgrade existing rigs. We expect that the $202 million will be split $199 million in the Contract Drilling segment and $3 million in the Completion and Production Services segment.
Precision's expansion capital plan for 2016 includes two new-build drilling rigs for Kuwait, to be delivered late 2016.

SEGMENTED FINANCIAL RESULTS

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


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

⁽¹⁾ See "ADDITIONAL GAAP MEASURES".

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


SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

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

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

⁽²⁾ See "ADDITIONAL GAAP MEASURES".

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


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


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

⁽¹⁾ Canadian operations only.

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


United States onshore drilling statistics:⁽¹⁾		2016		2015
		Precision	Industry⁽²⁾	Precision	Industry⁽²⁾
Average number of active land rigs for quarters ended:
	March 31	32	516	80	1,353
	June 30	24	397	57	873
Year to date average		28	457	69	1,104

⁽¹⁾ United States lower 48 operations only.

⁽²⁾ Baker Hughes rig counts.

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

Drilling rig utilization days in Canada (drilling days plus move days) were 1,202 during the second quarter of 2016, a decrease of 48% compared to 2015 primarily due to the decrease in industry activity resulting from lower commodity prices. Drilling rig utilization days in the U.S. were 2,198 or 58% lower than the same quarter of 2015 as U.S. activity was down due to lower industry activity. Drilling rig utilization days in our international business were 637 or 44% lower than the same quarter of 2015 due to lower activity in the Middle East and Mexico.

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

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

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

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

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

Depreciation expense in the quarter was 20% lower than in the second quarter of 2015 because of a lower asset base after decommissioning equipment and the recording of an impairment charge to our property, plant and equipment in the fourth quarter of 2015 partially offset by new-build rigs deployed in 2015 and the impact of the weakening Canadian dollar compared with the U.S. dollar and the associated impact on our U.S. denominated depreciation expense.


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

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

⁽²⁾ See "ADDITIONAL GAAP MEASURES".

Revenue from Completion and Production Services was down $19 million or 53% compared to the second quarter of 2015 due to lower activity levels in all service lines and lower average rates. In response to lower oil prices, customers curtailed spending and activity including well completion and production programs. Our well servicing activity in the quarter was down 48% from the second quarter of 2015. Approximately 89% of our second quarter Canadian service rig activity was oil related.

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

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

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

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

Depreciation in the quarter was 25% lower than the second quarter of 2015 because of a lower asset base after an impairment charge in the third quarter of 2015.

SEGMENT REVIEW OF CORPORATE AND OTHER

Our Corporate and Other segment provides support functions to our operating segments. The Corporate and Other segment had an adjusted EBITDA loss of $18 million for the second quarter of 2016, in line with the prior year comparable as higher share based incentive compensation was partially offset by cost saving initiatives.

OTHER ITEMS

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

Liquidity

In April, 2016 we agreed with our lending group to the following amendments to our senior credit facility:

The Adjusted EBITDA (as defined in the debt agreement) to interest expense coverage ratio of greater than 2:1 was temporarily reduced to 1.5:1 and reverts to 2.5:1 for periods ending after March 31, 2018;
Permit second lien debt not to exceed US$400 million subject to certain terms and conditions;
Amend certain negative covenants to, among other things, prohibit distributions during the covenant relief period;
Add a new covenant with respect to anti-cash hoarding whereby we are only permitted to draw a maximum of $50 million on the facility if the only purpose is to accumulate cash;
Add a new covenant that restricts the repurchase and redemption of unsecured debt subject to a pro-forma minimum liquidity of US$500 million.

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

As at June 30, 2016 we had $2,073 million outstanding under our senior unsecured notes. The current blended cash interest cost of our debt is approximately 6.2%.


Amount	Availability	Used for	Maturity
Senior facility (secured)
US$550 million (extendible, revolving term credit facility with US$250 million accordion feature)	Undrawn, except US$46 million in outstanding letters of credit	General corporate purposes	June 3, 2019
Operating facilities (secured)
$40 million	Undrawn, except $21 million in outstanding letters of credit	Letters of credit and general corporate purposes
US$15 million	Undrawn	Short term working capital requirements
Demand letter of credit facility (secured)
US$30 million	Undrawn, except US$5 million in outstanding letters of credit	Letters of credit
Senior notes (unsecured)
$200 million	Fully drawn	Debt repayment	March 15, 2019
US$650 million	Fully drawn	Debt repayment and general corporate purposes	November 15, 2020
US$390 million	Fully drawn	Capital expenditures and general corporate purposes	December 15, 2021
US$400 million	Fully drawn	Capital expenditures and general corporate purposes	November 15, 2024

Covenants

Senior Facility

The senior credit facility requires that we comply with certain financial covenants including a leverage ratio of consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (Adjusted EBITDA) of less than 2.5:1. For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness. Adjusted EBITDA, as defined in our revolving term facility, agreement differs from Adjusted EBITDA as defined under Additional GAAP Measures by the exclusion of bad debt expense and certain foreign exchange amounts. As at June 30, 2016 our consolidated senior debt to Adjusted EBITDA ratio was negative 0.97:1.

Under the senior credit facility we are required to maintain an Adjusted EBITDA coverage ratio, calculated as Adjusted EBITDA to interest expense, of greater than 1.5:1 reverting to 2.5:1 for periods ending after March 31, 2018 for the most recent four consecutive fiscal quarters. As at June 30, 2016 our Adjusted EBITDA coverage ratio was 2.68:1.

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

In addition, the senior credit facility contains certain covenants that place restrictions on our ability to incur or assume additional indebtedness; dispose of assets; pay dividends, share redemptions or other distributions; change our primary business; incur liens on assets; engage in transactions with affiliates; enter into mergers, consolidations or amalgamations; and enter into speculative swap agreements. At June 30, 2016, we were in compliance with the covenants of the revolving credit facility.

Senior Notes

The senior notes require that we comply with certain financial covenants including an Adjusted EBITDA to interest coverage ratio of greater than 2.0:1 for the most recent four consecutive fiscal quarters. In the event that our Adjusted EBITDA to interest coverage ratio is less than 2.0:1 for the most recent four consecutive fiscal quarters the senior notes restrict our ability to incur additional indebtedness. The senior notes contain a restricted payments covenant that limits our ability to make payments in the nature of dividends, distributions and repurchases from shareholders. This restricted payment basket grows by, among other things, 50% of consolidated net earnings and decreases by 100% of consolidated net losses as defined in the note agreements, and payments made to shareholders. As at June 30, 2016 our restricted payments basket is negative and we are no longer able to make dividend payments until such time as the basket once again becomes positive. For further information please see the senior note indentures which are available on SEDAR and EDGAR.

In addition, the senior notes contain certain covenants that limit our ability, and the ability of certain subsidiaries, to incur additional indebtedness and issue preferred shares; create liens; create or permit to exist restrictions on our ability or certain subsidiaries to make certain payments and distributions; engage in amalgamations, mergers or consolidations; make certain dispositions and engage in transactions with affiliates. At June 30, 2016, we were in compliance with the covenants of our senior notes.

Hedge of investments in foreign operations

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

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

Average shares outstanding

The following table reconciles the weighted average shares outstanding used in computing basic and diluted earnings per share:


	Three months ended June 30,		Six months ended June 30,
	2016	2015	2016	2015
Weighted average shares outstanding - basic	293,134	292,865	293,027	292,843
Effect of stock options and other equity compensation plans	-	-	-	-
Weighted average shares outstanding - diluted	293,134	292,865	293,027	292,843


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

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

⁽¹⁾ See "ADDITIONAL GAAP MEASURES".

ADDITIONAL GAAP MEASURES

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

Adjusted EBITDA

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

Operating Loss

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

Funds Provided By (Used In) Operations

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

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

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

our capital expenditure plans for 2016;
the principal use of our free cash in 2016;
timing on the commissioning and delivery of two new rigs for Kuwait;
our strategic priorities for 2016;
continuing demand for Tier 1 rigs; and
the average number of term contracts in place for 2016 and 2017.

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

the decline in oil prices will continue to pressure customers into reducing or limiting their drilling budgets;
the status of current negotiations with our customers and vendors;
customer focus on safety performance;
existing term contracts are neither renewed nor terminated prematurely;
our ability to deliver rigs to customers on a timely basis; and
the general stability of the economic and political environments in the jurisdictions where we operate.

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

volatility in the price and demand for oil and natural gas;
fluctuations in the demand for contract drilling, well servicing and ancillary oilfield services;
Our customers' inability to obtain adequate credit or financing to support their drilling and production activity;
changes in drilling and well servicing technology which could reduce demand for certain rigs or put us at a competitive disadvantage;
shortages, delays and interruptions in the delivery of equipment supplies and other key inputs;
the effects of seasonal and weather conditions on operations and facilities;
the availability of qualified personnel and management;
a decline in our safety performance which could result in lower demand for our services;
changes in environmental laws and regulations such as increased regulation of hydraulic fracturing or restrictions on the burning of fossil fuels and greenhouse gas emissions, which could have an adverse impact on the demand for oil and gas;
terrorism, social, civil and political unrest in the foreign jurisdictions where we operate;
fluctuations in foreign exchange, interest rates and tax rates; and
other unforeseen conditions which could impact the use of services supplied by Precision and Precision's ability to respond to such conditions.

Readers are cautioned that the forgoing list of risk factors is not exhaustive. Additional information on these and other factors that could affect our business, operations or financial results are included in reports on file with applicable securities regulatory authorities, including but not limited to Precision's Annual Information Form for the year ended December 31, 2015, which may be accessed on Precision's SEDAR profile at www.sedar.com or under Precision's EDGAR profile at www.sec.gov. The forward-looking information and statements contained in this news release are made as of the date hereof and Precision undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a results of new information, future events or otherwise, except as required by law.


INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)

(Stated in thousands of Canadian dollars)		June 30, 2016			December 31, 2015
ASSETS
Current assets:
	Cash	$	455,679		$	444,759
	Accounts receivable		175,006			311,595
	Income tax recoverable		14,762			-
	Inventory		23,748			24,245
Total current assets			669,195			780,599
Non-current assets:
	Income tax recoverable		-			2,917
	Property, plant and equipment		3,632,922			3,883,332
	Intangibles		3,977			3,363
	Goodwill		206,306			208,479
Total non-current assets			3,843,205			4,098,091
Total assets		$	4,512,400		$	4,878,690

LIABILITIES AND EQUITY
Current liabilities:
	Accounts payable and accrued liabilities	$	166,836		$	235,948
	Income tax payable		-			7,836
Total current liabilities			166,836			243,784
Non-current liabilities:
	Share based compensation		16,463			15,201
	Provisions and other		13,996			14,520
	Long-term debt		2,049,286			2,180,510
	Deferred tax liabilities		246,264			303,466
Total non-current liabilities			2,326,009			2,513,697
Shareholders' equity:
	Shareholders' capital		2,319,276			2,316,321
	Contributed surplus		36,742			35,800
	Deficit		(474,573	)		(397,013	)
	Accumulated other comprehensive income		138,110			166,101
Total shareholders' equity			2,019,555			2,121,209
Total liabilities and shareholders' equity		$	4,512,400		$	4,878,690


INTERIM CONSOLIDATED STATEMENTS OF LOSS (UNAUDITED)

		Three months ended June 30,						Six months ended June 30,
(Stated in thousands of Canadian dollars, except per share amounts)		2016			2015			2016			2015
Revenue		$	163,979		$	334,462		$	465,706		$	846,582
Expenses:
	Operating		110,909			211,083			281,979			511,347
	General and administrative		29,063			31,951			57,017			73,254
	Restructuring		1,607			3,073			5,046			10,242
Earnings before income taxes, gain on repurchase of unsecured senior notes, finance charges, foreign exchange and depreciation and amortization			22,400			88,355			121,664			251,739
Depreciation and amortization			96,611			120,128			191,860			236,225
Operating earnings (loss)			(74,211	)		(31,773	)		(70,196	)		15,514
Foreign exchange			754			8,318			8,335			(20,088	)
Finance charges			33,161			32,348			69,398			52,030
Gain on repurchase of unsecured senior notes			-			-			(4,873	)		-
Loss before income taxes			(108,126	)		(72,439	)		(143,056	)		(16,428	)
Income taxes:
	Current		(11,395	)		1,213			(14,359	)		7,516
	Deferred		(39,054	)		(43,835	)		(51,137	)		(18,160	)
			(50,449	)		(42,622	)		(65,496	)		(10,644	)
Net loss		$	(57,677	)	$	(29,817	)	$	(77,560	)	$	(5,784	)
Net loss per share:
	Basic	$	(0.20	)	$	(0.10	)	$	(0.26	)	$	(0.02	)
	Diluted	$	(0.20	)	$	(0.10	)	$	(0.26	)	$	(0.02	)


INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
	Three months ended June 30,						Six months ended June 30,
(Stated in thousands of Canadian dollars)	2016			2015			2016			2015
Net loss	$	(57,677	)	$	(29,817	)	$	(77,560	)	$	(5,784	)
Unrealized gain (loss) on translation of assets and liabilities of operations denominated in foreign currency		6,107			(39,087	)		(147,991	)		165,380
Foreign exchange gain (loss) on net investment hedge with U.S. denominated debt, net of tax		(5,473	)		30,305			120,000			(126,585	)
Comprehensive income (loss)	$	(57,043	)	$	(38,599	)	$	(105,551	)	$	33,011


INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)
			Three months ended June 30,						Six months ended June 30,
(Stated in thousands of Canadian dollars)			2016			2015			2016			2015
Cash provided by (used in):
Operations:
	Net loss		$	(57,677	)	$	(29,817	)	$	(77,560	)	$	(5,784	)
	Adjustments for:
		Long-term compensation plans		7,565			9,300			15,089			12,707
		Depreciation and amortization		96,611			120,128			191,860			236,225
		Gain on repurchase of unsecured senior notes		-			-			(4,873	)		-
		Foreign exchange		3,554			9,068			11,537			(20,377	)
		Finance charges		33,161			32,348			69,398			52,030
		Income taxes		(50,449	)		(42,622	)		(65,496	)		(10,644	)
		Other		518			(50	)		140			1,349
		Income taxes paid		(4,808	)		(4,092	)		(10,575	)		(9,788	)
		Income taxes recovered		67			249			67			1,111
		Interest paid		(61,478	)		(55,744	)		(69,509	)		(63,193	)
		Interest received		1,564			14,405			2,143			14,723
Funds provided by (used in) operations				(31,372	)		53,173			62,221			208,359
Changes in non-cash working capital balances				52,037			116,704			70,618			176,656
				20,665			169,877			132,839			385,015
Investments:
	Purchase of property, plant and equipment			(53,424	)		(113,045	)		(80,585	)		(338,867	)
	Proceeds on sale of property, plant and equipment			1,548			3,598			3,705			6,474
	Income taxes recovered			2,917			55,138			2,917			55,138
	Changes in non-cash working capital balances			6,825			(99,649	)		(19,284	)		(154,276	)
				(42,134	)		(153,958	)		(93,247	)		(431,531	)
Financing:
	Repurchase of unsecured senior notes			-			-			(8,409	)		-
	Debt issue costs			(1,155	)		-			(1,155	)		(975	)
	Dividends paid			-			(20,498	)		-			(40,995	)
	Issuance of common shares on the exercise of options			1,724			93			1,914			93
				569			(20,405	)		(7,650	)		(41,877	)
Effect of exchange rate changes on cash and cash equivalents				223			(11,005	)		(21,022	)		30,605
Increase (decrease) in cash and cash equivalents				(20,677	)		(15,491	)		10,920			(57,788	)
Cash and cash equivalents, beginning of period				476,356			449,184			444,759			491,481
Cash and cash equivalents, end of period			$	455,679		$	433,693		$	455,679		$	433,693


INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (UNAUDITED)
(Stated in thousands of Canadian dollars)	Shareholders' capital		Contributed surplus			Accumulated other comprehensive income			Deficit			Total equity
Balance at January 1, 2016	$	2,316,321	$	35,800		$	166,101		$	(397,013	)	$	2,121,209
Net loss for the period		-		-			-			(77,560	)		(77,560	)
Other comprehensive loss for the period		-		-			(27,991	)		-			(27,991	)
Share options exercised		2,955		(1,041	)		-			-			1,914
Share based compensation expense		-		1,983			-			-			1,983
Balance at June 30, 2016	$	2,319,276	$	36,742		$	138,110		$	(474,573	)	$	2,019,555


(Stated in thousands of Canadian dollars)	Shareholders' capital		Contributed surplus			Accumulated other comprehensive income		Retained earnings			Total equity
Balance at January 1, 2015	$	2,315,539	$	31,109		$	46,292	$	48,426		$	2,441,366
Net loss for the period		-		-			-		(5,784	)		(5,784	)
Other comprehensive income for the period		-		-			38,795		-			38,795
Dividends		-		-			-		(40,995	)		(40,995	)
Share options exercised		142		(49	)		-		-			93
Shares issued on redemption of non-management directors' DSUs		640		(324	)		-		-			316
Share based compensation expense		-		2,548			-		-			2,548
Balance at June 30, 2015	$	2,316,321	$	33,284		$	85,087	$	1,647		$	2,436,339

SECOND QUARTER 2016 EARNINGS CONFERENCE CALL AND WEBCAST

Precision Drilling Corporation has scheduled a conference call and webcast to begin promptly at 11:00 a.m. MT (1:00 p.m. ET) on Thursday, July 21, 2016.

The conference call dial in numbers are 1-866-225-2055 or 416-340-2218.

A live webcast of the conference call will be accessible on Precision's website at www.precisiondrilling.com by selecting "Investor Centre", then "Webcasts". Shortly after the live webcast, an archived version will be available for approximately 30 days.

An archived recording of the conference call will be available approximately one hour after the completion of the call until August 20, 2016 by dialing 1-800-408-3053 or 905-694-9451, pass code 7249285.

About Precision

Precision is a leading provider of safe and High Performance, High Value services to the oil and gas industry. Precision provides customers with access to an extensive fleet of contract drilling rigs, directional drilling services, well service and snubbing rigs, coil tubing services, camps, rental equipment, and wastewater treatment units backed by a comprehensive mix of technical support services and skilled, experienced personnel.

Precision is headquartered in Calgary, Alberta, Canada. Precision is listed on the Toronto Stock Exchange under the trading symbol "PD" and on the New York Stock Exchange under the trading symbol "PDS".

Contact Information:

Precision Drilling Corporation
Carey Ford
Senior Vice President & Chief Financial Officer
403.716.4566
403.716.4755 (FAX)

Suite 800, 525 - 8th Avenue S.W.
Calgary, Alberta, Canada T2P 1G1
www.precisiondrilling.com

Precision Drilling Corporation Announces 2016 Second Quarter Financial Results