EX-99.1 4 exh_991.htm EXHIBIT 99.1

Exhibit 99.1

Precision Drilling Corporation

Third Quarter Report for the three and nine months ended September 30, 2017 and 2016

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s Discussion and Analysis for the three and nine month periods ended September 30, 2017 of Precision Drilling Corporation (“Precision” or the “Corporation”) prepared as at October 26, 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 September 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 18 of this report. This report contains references to Adjusted EBITDA, Operating Earnings (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 17 of this report.

Precision Drilling announces 2017 third quarter financial results:

Third quarter revenue of $315 million was an increase of 47% over the prior year comparative quarter.

Third 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 $73 million was 77% higher than the third quarter of 2016.

Third quarter net loss of $26 million ($0.09 per share) compared with a net loss of $47 million ($0.16 per share) in the third quarter of 2016.

Third quarter capital expenditures were $23 million, with full year capital spending expected to be $104 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 September 30,						Nine months ended September 30,
(Stated in thousands of Canadian dollars, except per share amounts)	2017		2016		% Change		2017		2016		% Change
Revenue⁽¹⁾	314,504		213,668		47.2		974,037		700,580		39.0
Adjusted EBITDA⁽²⁾	73,239		41,411		76.9		214,067		163,075		31.3
Adjusted EBITDA⁽²⁾ % of revenue	23.3	%	19.4	%			22.0		23.3	%
Net loss	(26,287	)	(47,377	)	(44.5	)	(85,031	)	(124,937	)	(31.9	)
Cash provided by operations	56,757		17,515		224.0		93,266		150,354		(38.0	)
Funds provided by operations	85,140		31,688		168.7		155,612		93,909		65.7
Capital spending:
Expansion	2,336		67,672		(96.5	)	10,980		133,605		(91.8	)
Upgrade	7,168		4,902		46.2		34,102		6,335		438.3
Maintenance and infrastructure	13,014		5,588		132.9		27,965		18,807		48.7
Proceeds on sale	(4,273	)	(2,125	)	101.1		(10,054	)	(5,830	)	72.5
Net capital spending	18,245		76,037		(76.0	)	62,993		152,917		(58.8	)

Loss per share:
Basic and diluted	(0.09	)	(0.16	)	(43.8	)	(0.29	)	(0.43	)	(32.6	)

(1) Prior year comparatives have changed to conform to current year presentation. For detail see “RECAST OF COMPARATIVE FINANCIAL INFORMATION.”

(2) See “NON-GAAP MEASURES.”

Operating Highlights

	Three months ended September 30,				Nine months ended September 30,
	2017	2016	% Change		2017	2016	% Change
Contract drilling rig fleet	256	253	1.2		256	253	1.2
Drilling rig utilization days:
Canada	4,487	2,853	57.3		13,945	8,050	73.2
U.S.	5,593	2,689	108.0		15,114	7,773	94.4
International	736	644	14.3		2,184	2,044	6.8
Revenue per utilization day:
Canada ⁽¹⁾⁽²⁾ (Cdn$)	19,980	21,046	(5.1	)	21,092	25,214	(16.3	)
U.S.⁽¹⁾⁽³⁾ (US$)	19,026	24,343	(21.8	)	19,732	28,374	(30.5	)
International (US$)	50,528	43,879	15.2		50,214	43,191	16.3
Operating cost per utilization day:
Canada⁽¹⁾ (Cdn$)	13,656	14,107	(3.2	)	13,764	14,815	(7.1	)
U.S. ⁽¹⁾ (US$)	12,591	15,456	(18.5	)	13,917	16,097	(13.5	)
Service rig fleet	210	163	28.8		210	163	28.8
Service rig operating hours	42,653	26,588	60.4		128,523	66,281	93.9
Revenue per operating hour (Cdn$)	638	599	6.5		635	654	(2.9	)

(1) Prior year comparatives have changed to conform to current year presentation. For detail see “RECAST OF COMPARATIVE FINANCIAL INFORMATION.”

(2) Includes lump sum revenue from contract shortfall.

(3) Comparatives and nine month period ended September 30, 2017 includes revenue from idle but contracted rig days.

Financial Position

(Stated in thousands of Canadian dollars, except ratios)	September 30, 2017	December 31, 2016
Working capital	266,159	230,874
Cash	131,742	115,705
Long-term debt⁽¹⁾	1,777,667	1,906,934
Total long-term financial liabilities	1,801,212	1,946,742
Total assets	3,967,987	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.

RECAST OF COMPARATIVE FINANCIAL INFORMATION

During the third quarter of 2017, we changed our treatment of how certain amounts that were historically netted against operating expense should be classified. In particular, certain amounts that were historically netted against operating expenses are now treated as revenue, with a corresponding increase to operating expenses. The primary nature of these amounts related to additional labour above our standard drilling crew configuration, subsistence allowances paid to the drilling crew which varies depending on whether the crews were staying in a camp or hotel and equipment rental. As a result, previously reported revenues and operating expenses were understated by equivalent amounts.

To conform to current year presentation, certain immaterial reclassifications between operating and general administrative expenses have also been made in the comparative periods.

As a result of these reclassifications, we have recast prior year’s comparative amounts as follows:

Three months ended September 30, 2016 (Stated in thousands of Canadian dollars except per day amounts)	As previously reported	Revenue recast	Expense recast		As recast

Revenue	201,802	11,866	-		213,668
Expenses:
Operating	137,935	11,866	576		150,377
General and administrative	21,748	-	(576	)	21,172
Restructuring	708	-	-		708
Adjusted EBITDA⁽¹⁾	41,411	-	-		41,411
(1) See “NON-GAAP MEASURES.”

Revenue per utilization day:
Canada (Cdn$)	17,523	3,523	-		21,046
U.S. (US$)	23,826	517	-		24,343
International (US$)	43,879	-	-		43,879
Operating cost per utilization day:
Canada (Cdn$)	10,584	3,523	-		14,107
U.S. (US$)	14,939	517	-		15,456

Nine months ended September 30, 2016 (Stated in thousands of Canadian dollars except per day amounts)	As previously reported	Revenue recast	Expense recast		As recast

Revenue	667,508	33,072	-		700,580
Expenses:
Operating	419,914	33,072	2,146		455,132
General and administrative	78,765	-	(2,146	)	76,619
Restructuring	5,754	-	-		5,754
Adjusted EBITDA⁽¹⁾	163,075	-	-		163,075
(1) See “NON-GAAP MEASURES.”

Revenue per utilization day:
Canada (Cdn$)	21,792	3,422	-		25,214
U.S. (US$)	27,842	532	-		28,374
International (US$)	43,191	-	-		43,191
Operating cost per utilization day:
Canada (Cdn$)	11,393	3,422	-		14,815
U.S. (US$)	15,565	532	-		16,097

The tables below reflect the recast amounts for the last eight quarters:

(Stated in thousands of Canadian dollars)

As recast	2016		2017
Quarters ended	December 31		March 31	June 30	September 30
Revenue	302,653		368,673	290,860	314,504
Operating expense	206,583		259,079	214,332	218,936
General and administrative expense	31,070		25,286	20,008	22,329
Adjusted EBITDA⁽¹⁾	65,000		84,308	56,520	73,239
Recast
Revenue	18,750		22,873	15,336	-
Operating expense	19,202		22,873	15,336	-
General and administrative expense	(452	)	-	-	-
Adjusted EBITDA⁽¹⁾	-		-	-	-

(1) See “NON-GAAP MEASURES.”

(Stated in thousands of Canadian dollars)

As recast	2015		2016
Quarters ended	December 31		March 31		June 30		September 30
Revenue	362,117		316,505		170,407		213,668
Operating expense	216,217		186,615		118,140		150,377
General and administrative expense	27,705		27,187		28,260		21,172
Restructuring	7,100		3,439		1,607		708
Adjusted EBITDA⁽¹⁾	111,095		99,264		22,400		41,411

Recast
Revenue	17,164		14,778		6,428		11,866
Operating expense	18,926		15,545		7,231		12,442
General and administrative expense	(1,762	)	(767	)	(803	)	(576	)
Restructuring	-		-		-		-
Adjusted EBITDA⁽¹⁾	-		-		-		-

(1) See “NON-GAAP MEASURES.”

The tables below reflect the recast amounts for the last three years ended December 31:

(Stated in thousands of Canadian dollars)

As recast
Year ended December 31,	2014		2015		2016
Revenue	2,487,653		1,634,758		1,003,233
Operating expense	1,563,458		1,021,484		661,715
General and administrative expense	123,825		118,766		107,689
Restructuring	-		20,643		5,754
Adjusted EBITDA⁽¹⁾	800,370		473,865		228,075

Recast
Revenue	137,115		79,134		51,822
Operating expense	157,631		86,791		54,420
General and administrative expense	(20,516	)	(7,657	)	(2,598	)
Restructuring	-		-		-
Adjusted EBITDA⁽¹⁾	-		-		-

(1) See “NON-GAAP MEASURES.”

There is no impact on net earnings (loss) or comprehensive income (loss) and the consolidated statement of financial position, consolidated statement of changes in equity and the consolidated statement of cash flows remain unchanged as a result of this recast.

Summary for the three months ended September 30, 2017

• Revenue this quarter was $315 million which is 47% higher than the third quarter of 2016. The increase in revenue was primarily the result of higher activity in all of our North American based businesses and higher average day rates from our international contract drilling business, partially offset by lower contract short-fall payments, a decrease in average day rate in all of our North American contract drilling businesses and no utilization in our Mexico based contract drilling business. Compared with the third quarter of 2016 our activity, as measured by drilling rig utilization days, increased 57% in Canada, 108% 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 46% and 57%, respectively.

• Adjusted EBITDA this quarter was $73 million, an increase of $32 million from the third quarter of 2016. Our adjusted EBITDA as a percentage of revenue was 23% this quarter, compared with 19% in the third quarter of 2016. The increase in adjusted EBITDA as a percent of revenue was mainly due to fixed costs spread over higher activity in our North American business partially offset by lower average pricing.

• Operating loss (see “NON-GAAP MEASURES”) this quarter was $17 million compared with an operating loss of $56 million in the third 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 $22 million, $1 million higher than the third quarter of 2016. The increase is due to higher share based compensation expense that is tied to our common shares, partially offset by a moderate strengthening of the Canadian dollar on our U.S. dollar denominated costs. As at September 30, 2017 we have a total share based incentive compensation liability of $24 million compared with $23 million at June 30, 2017 after having paid out $0.2 million in the quarter.

• Net finance charges were $32 million, a decrease of $2 million compared with the third quarter of 2016 primarily due to the effect of a stronger Canadian dollar on our U.S. dollar denominated interest expense and 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 third quarter of 2017 to $19,980 from $21,046 in the prior year third quarter as a result of fewer rigs working under legacy contracts and a higher proportion of revenue from shallower drilling activity, partially offset by higher contract shortfall payments relative to the 2016 comparative period. During the quarter, we recognized $5 million in revenue associated with contract shortfall payments in Canada which was an increase of $3 million from the prior year period. On a sequential basis, revenue per utilization day in Canada decreased by $2,197 as a result of rig mix, lower shortfall payments and lower boiler revenue when compared to the second quarter of 2017. In the U.S. revenue per utilization day decreased to US$19,026 from US$24,343 over the same period. The decrease in the U.S. revenue rate was the result of long-term contracts ending and rigs contracting at lower spot market rates, lower revenue from idle but contracted rigs and no turnkey activity in the current quarter. During the quarter we had no turnkey revenue compared with US$3 million in the 2016 comparative period and had no revenue from idle but contracted rigs in the current quarter versus US$6 million in the comparative period. On a sequential basis, revenue per utilization day excluding revenue from idle but contracted rigs increased by US$287 as higher fleet average day rates was partially offset by lower turnkey revenue when compared to the second quarter of 2017.

· Average operating costs per utilization day for drilling rigs in Canada decreased to $13,656 compared with the prior year third quarter of $14,107. 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$12,591 in 2017 compared with US$15,456 in 2016 due to fixed costs spread over higher utilization, no regional repositioning of rigs and no turnkey work in the quarter.

· Average operating margin per utilization day excluding revenue from idle but contracted rigs in the third quarter of 2017 increased by $515 in Canada and increased by US$1,252 in the U.S. when compared to the second quarter of 2017. In Canada, the increase was a result of higher fixed cost absorption more than offsetting a reduction in revenue per utilization day. In the U.S., the sequential increase was primarily a result of higher fleet average day rates.

· We realized revenue from international contract drilling of US$37 million in the third quarter of 2017, a US$9 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 a reduction in activity in our Mexico operations. Average revenue per utilization day in our international contract drilling business was US$50,528 an increase of 15% over the comparable prior year quarter primarily due to rig mix as we had fewer rigs working in the lower day rate jurisdictions.

· Directional drilling services realized revenue of $6 million in the third quarter of 2017 in line with the prior year period.

· Funds provided by operations in the third quarter of 2017 were $85 million, an increase of $53 million from the prior year comparative quarter and an increase of $100 million from the second quarter of 2017. The increases were primarily the result of improved operating results.

· Capital expenditures for the purchase of property, plant and equipment were $23 million in the third quarter, a decrease of $56 million over the same period in 2016. Capital spending for the quarter included $2 million for expansion capital, $7 million for upgrade capital and $13 million for the maintenance of existing assets and infrastructure.

Summary for the nine months ended September 30, 2017:

• Revenue for the nine months of 2017 was $974 million, an increase of 39% from the 2016 period.

• Operating loss was $69 million, a decrease of $56 million over the same period in 2016. Operating loss was 7% of revenue in 2017 compared to 18% 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 $68 million, a decrease of $9 million over the first nine months of 2016. The decrease was due to fixed cost reductions implemented through the downturn and lower share based incentive compensation that is tied to the price of our common shares.

• Net finance charges were $100 million, a decrease of $4 million from the first nine months of 2016 primarily due to a reduction in interest expense related to debt retired in 2016 and the effect of a stronger Canadian dollar on our U.S. dollar denominated interest expense partially offset by higher interest income earned in the comparative period.

• Funds provided by operations (see “NON-GAAP MEASURES”) in the first nine months of 2017 were $156 million, an increase of $62 million from the prior year comparative period of $94 million.

• Capital expenditures for the purchase of property, plant and equipment were $73 million in the first nine months of 2017, a decrease of $86 million over the same period in 2016. Capital spending for 2017 to date included $11 million for expansion capital, $34 million for upgrade capital and $28 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 58% throughout the nine months 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 nine months of 2017 our utilization days were up 84% 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 – Beta-style field trials utilizing rig automation technologies, including Process Automation Control (PAC), Directional Guidance System and High Speed Downhole Data are ongoing and we expect to progress the commercialization of these automation features during 2017. We have drilled approximately 70 wells utilizing PAC technology which is installed on 20 Super Triple Rigs.

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. Precision reduced 2017 capital expenditures by approximately $34 million with the reduction relating primarily to upgrade and maintenance capital. Our revised 2017 capital plan brings spending in line with expected activity levels while continuing to focus on free cash flow to drive debt reduction. In the first nine months of 2017, we generated funds from operations of $156 million – see “NON-GAAP MEASURES.”

OUTLOOK

For the third quarter of 2017, the average West Texas Intermediate price of oil was 7% higher than the prior year comparative period while the average Henry Hub natural gas price was 3% higher. The average AECO price was 29% lower than the prior year comparative period as a result of infrastructure constraints due to planned maintenance and high storage levels.

	Three months ended September 30,		Year ended December 31,
	2017	2016	2016
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)	48.03	44.97	43.30
Natural gas
Canada
AECO (per MMBtu) (CDN$)	1.66	2.34	2.14
United States
Henry Hub (per MMBtu) (US$)	2.93	2.85	2.48

Contracts

The following chart outlines the average number of drilling rigs that we have under contract as of October 26, 2017 for the fourth quarter of 2017 and the full years 2017 and 2018.

	Average for the quarter ended				Average for the year ended
	March 31	June 30	September 30	December 31	2017	2018
Average rigs under term contract as at October 26, 2017:
Canada	27	23	19	12	20	7
U.S.	26	33	31	28	29	12
International	8	8	8	8	8	7
Total	61	64	58	48	57	26

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 October 26, 2017 we have added 22 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.

	2016		2017
Quarter ended	September 30	December 31	March 31	June 30	September 30
Average Precision active rig count:
Canada	31	51	76	29	49
U.S.	29	39	47	59	61
International	7	8	8	8	8
Total	67	98	131	96	118

With improved commodity prices and increasing activity levels, earlier this year we were able to increase prices on spot market rigs across the majority of our fleet. Despite the slight lull in third quarter 2017 activity pricing increase have held firm. Should commodity prices continue to improve, we expect sequential improvements in pricing in the U.S. and the Deep Basin in Canada. We expect pricing improvements in the shallower parts of the Canadian market; however, the increases are not expected to be of the same magnitude as other North American markets in which we operate.

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 October 20, 2017, the U.S. active land drilling rig count was up approximately 68% from the same point last year and the Canadian active land drilling rig count was up approximately 41%.

In Canada there has been a strengthening in natural gas and gas liquids drilling activity related to the Deep Basin in northwestern Alberta and northeastern British Columbia although recent weakness in AECO pricing has caused some producers to delay work programs specifically related to dry gas. In the U.S., the trend towards oil-directed drilling 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 48% 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 has 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 $104 million:

•

The 2017 capital expenditure plan includes $13 million for expansion capital, $52 million for sustaining and infrastructure expenditures, and $39 million to upgrade existing rigs. We expect that the $104 million will be split $99 million in the Contract Drilling Services segment and $5 million in the Completion and Production Services segment.

Segmented Financial Results

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

	Three months ended September 30,					Nine months ended September 30,
(Stated in thousands of Canadian dollars)	2017		2016		% Change	2017		2016		% Change
Revenue:
Contract Drilling Services⁽¹⁾	278,569		190,329		46.4	864,957		634,152		36.4
Completion and Production Services	37,816		24,158		56.5	113,546		69,343		63.7
Inter-segment eliminations	(1,881	)	(819	)	129.7	(4,466	)	(2,915	)	53.2
	314,504		213,668		47.2	974,037		700,580		39.0
Adjusted EBITDA:⁽²⁾
Contract Drilling Services	81,994		52,180		57.1	242,690		210,300		15.4
Completion and Production Services	4,251		736		477.6	9,174		(4,039	)	(327.1	)
Corporate and other	(13,006	)	(11,505	)	13.0	(37,797	)	(43,186	)	(12.5	)
	73,239		41,411		76.9	214,067		163,075		31.3

(1) Prior year comparatives have changed to conform to current year presentation. For detail see “RECAST OF COMPARATIVE FINANCIAL INFORMATION.”

(2) See “NON-GAAP MEASURES”.

Segment Review of Contract Drilling Services

	Three months ended September 30,						Nine months ended September 30,
(Stated in thousands of Canadian dollars, except where noted)	2017		2016		% Change		2017		2016		% Change
Revenue⁽¹⁾	278,569		190,329		46.4		864,957		634,152		36.4
Expenses:
Operating⁽¹⁾	189,143		129,457		46.1		598,040		393,979		51.8
General and administrative⁽¹⁾	7,432		8,069		(7.9	)	24,227		26,833		(9.7	)
Restructuring	-		623		(100.0	)	-		3,040		(100.0	)
Adjusted EBITDA⁽²⁾	81,994		52,180		57.1		242,690		210,300		15.4
Depreciation	80,653		86,643		(6.9	)	251,907		257,334		(2.1	)
Operating earnings (loss)⁽²⁾	1,341		(34,463	)	(103.9	)	(9,217	)	(47,034	)	(80.4	)
Operating earnings (loss) as a percentage of revenue	0.5	%	(18.1	%)			(1.1	%)	(7.4	%)

(1) Prior year comparatives have changed to conform to current year presentation. For detail see “RECAST OF COMPARATIVE FINANCIAL INFORMATION.”

(2) See “NON-GAAP MEASURES”.

	Three months ended September 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)	3,998		16,288		2,538		10,401
Drilling rig operating day utilization	32	%	28	%	20	%	17	%
Number of wells drilled	451		1,977		269		1,115
Average days per well	8.9		8.2		9.4		9.3
Number of metres drilled (000s)	1,123		5,179		627		2,568
Average metres per well	2,490		2,620		2,330		2,303
Average metres per day	281		318		247		247

	Nine months ended September 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)	12,398		49,889		7,183		27,833
Drilling rig operating day utilization	34	%	29	%	19	%	15	%
Number of wells drilled	1,282		5,285		607		2,490
Average days per well	9.7		9.4		11.8		11.2
Number of metres drilled (000s)	3,352		14,267		1,616		6,328
Average metres per well	2,615		2,700		2,663		2,542
Average metres per day	270		286		225		227

(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
September 30	61	927	29	465
Year to date average	55	841	28	459

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $279 million this quarter, or 46% higher than the third quarter of 2016, while adjusted EBITDA increased by 57% to $82 million. The increase in revenue was primarily due to higher utilization days in Canada and the U.S. and higher average day rates for international contracts. During the quarter we recognized $5 million in shortfall payments in our Canadian contract drilling business, which was $3 million higher than in the prior year. During the quarter in the U.S. we did not recognize any idle but contracted or turnkey revenue compared with US$6 million and US$3 million, respectively, in the comparative quarter of 2016.

Drilling rig utilization days in Canada (drilling days plus move days) were 4,487 during the third quarter of 2017, an increase of 57% compared to 2016 primarily due to the increase in industry activity resulting from higher oil prices. Drilling rig utilization days in the U.S. were 5,593, or 108% 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 736 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 5% in Canada due to fewer legacy contracts. Drilling rig revenue per utilization day for the quarter in the U.S. was down 22% from the prior comparative period, while international revenue per utilization day was up 15%. The decrease in the U.S. average rate was due to long-term contracts ending and rigs being re-contracted at lower spot market rates, no idle but contracted revenue and no turnkey activity in the current quarter. 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, 18% of our utilization days in the quarter were generated from rigs under term contract, compared with 33% in the third quarter of 2016. In the U.S., 55% of utilization days were generated from rigs under term contract as compared with 53% in the third quarter of 2016.

Operating costs were 68% of revenue for the quarter which was in line with 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. In the U.S., operating costs for the quarter on a per day basis were lower than the prior year period primarily due to no turnkey activity in the current year quarter and the impact of fixed costs spread over higher activity. Both Canada and U.S. operating costs benefited from cost saving initiatives taken in 2015 and 2016.

Depreciation expense in the quarter was 7% lower than in the third quarter of 2016.

Segment Review of Completion and Production Services

	Three months ended September 30,						Nine months ended September 30,
(Stated in thousands of Canadian dollars, except where noted)	2017		2016		% Change		2017		2016		% Change
Revenue	37,816		24,158		56.5		113,546		69,343		63.7
Expenses:
Operating⁽¹⁾	31,674		21,739		45.7		98,773		64,068		54.2
General and administrative⁽¹⁾	1,891		1,629		16.1		5,599		7,293		(23.2	)
Restructuring	-		54		(100.0	)	-		2,021		(100.0	)
Adjusted EBITDA⁽²⁾	4,251		736		477.6		9,174		(4,039	)	(327.1	)
Depreciation	6,731		6,759		(0.4	)	21,228		20,537		3.4
Operating loss⁽²⁾	(2,480	)	(6,023	)	(58.8	)	(12,054	)	(24,576	)	(51.0	)
Operating loss as a percentage of revenue	(6.6	%)	(24.9	%)			(10.6	%)	(35.4	%)
Well servicing statistics:
Number of service rigs (end of period)	210		163		28.8		210		163		28.8
Service rig operating hours	42,653		26,588		60.4		128,523		66,281		93.9
Service rig operating hour utilization	22	%	18	%			22	%	15	%
Service rig revenue per operating hour	638		599		6.5		635		654		(2.9	)

(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 $14 million or 57% compared with the third quarter of 2016 due to higher activity levels in all service lines. As oil prices have recovered, customers have increased spending and activity in well completion and production programs. Our well servicing activity in the quarter was up 60% from the third 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 97% of our third quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 90% of its revenue from Canadian operations and 10% from U.S. operations which is in line with the third quarter of 2016.

Average service rig revenue per operating hour in the quarter was $638 or $39 higher than the third quarter of 2016. The increase was primarily the result of increased labour costs which are passed through to the customer.

Adjusted EBITDA was $4 million higher than the third quarter of 2016 due to increased activity in all divisions.

Operating costs as a percentage of revenue decreased to 84% in the third quarter of 2017, from 90% in the third quarter of 2016. The decrease is the result of the impact of fixed costs spread across greater activity combined with our reduced cost structure.

Depreciation in the quarter was $7 million in line with the previous year comparative period. The added depreciation costs in the quarter associated with additional well service units was 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 $13 million an increase of $2 million compared with the third quarter of 2016 primarily due to higher share based incentive compensation.

Net financial charges for the quarter were $32 million, a decrease of $2 million compared with the third quarter of 2016 primarily due to the effect of a stronger Canadian dollar on our U.S. dollar denominated interest expense and a reduction in interest expense related to debt retired in 2016. For the current quarter we incurred a foreign exchange gain of $1 million in line with the third quarter of 2016.

Income tax expense for the quarter was a recovery of $23 million compared with a recovery of $36 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

Amount	Availability	Used for	Maturity
Senior facility (secured)
US$525 million (extendible, revolving term credit facility with US$250 million⁽¹⁾ accordion feature)	Undrawn, except 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.

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

Reduce the consolidated Adjusted EBITDA (as defined in the debt agreement) to consolidated interest expense 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 from US$250 million to US$275 million until the end of covenant relief period.

As at September 30, 2017 we had $1,802 million outstanding under our senior unsecured notes. The current blended cash interest cost of our debt is approximately 6.5%.

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 September 30, 2017 our consolidated senior debt to Adjusted EBITDA ratio was negative 0.14:1.

Effective January 20, 2017, under the senior credit facility, we are required to maintain a ratio of consolidated 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 September 30, 2017 our senior credit facility consolidated Adjusted EBITDA to consolidated interest expense ratio was 2.04:1.

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 September 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 cashflow, as defined in the senior note agreements, to consolidated interest expense 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 September 30, 2017, our senior notes consolidated interest coverage ratio was 1.89:1 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	December 31		March 31		June 30		September 30
Revenue⁽¹⁾	302,653		368,673		290,860		314,504
Adjusted EBITDA⁽²⁾	65,000		84,308		56,520		73,239
Net loss:	(30,618	)	(22,614	)	(36,130	)	(26,287	)
Per basic and diluted share	(0.10	)	(0.08	)	(0.12	)	(0.09	)
Funds provided by (used in) operations⁽²⁾	11,466		85,659		(15,187	)	85,140
Cash provided by (used in) operations	(27,846	)	33,770		2,739		56,757

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

	2015		2016
Quarters ended	December 31		March 31		June 30		September 30
Revenue⁽¹⁾	362,117		316,505		170,407		213,668
Adjusted EBITDA⁽²⁾	111,095		99,264		22,400		41,411
Net loss:	(270,952	)	(19,883	)	(57,677	)	(47,377	)
Per basic and diluted share	(0.93	)	(0.07	)	(0.20	)	(0.16	)
Funds provided by (used in) operations⁽²⁾	49,503		93,593		(31,372	)	31,688
Cash provided by operations	70,952		112,174		20,665		17,515
Dividends paid per share	0.07		-		-		-

(1) Prior year comparatives have changed to conform to current year presentation. For detail see “RECAST OF COMPARATIVE FINANCIAL INFORMATION.”

(2) See “NON-GAAP MEASURES”.

CRITICAL ACCOUNTING JUDGEMENTS AND ESTIMATES

Because of the nature of our business, we are required to make judgments and estimates in preparing our Consolidated Interim Financial Statements that could materially affect the amounts recognized. Our judgments and estimates are based on our past experiences and assumptions we believe are reasonable in the circumstances. The critical judgments 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 judgments and estimates during the three and nine month periods ended September 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 nine 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 Earnings (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, loss (gain) on repurchase of unsecured senior notes, finance charges, foreign exchange, impairment of goodwill, impairment of property, plant and equipment, loss on asset decommissioning, gain on re-measurement of property, plant and equipment 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 depreciation and amortization charges.

Operating Earnings (Loss)

We believe that operating earnings (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

Stock Exchange Listings

Shares of Precision Drilling Corporation are listed on the Toronto Stock Exchange under the trading symbol PD and on the New York Stock Exchange under the trading symbol PDS.

Transfer Agent and Registrar

Computershare Trust Company of Canada
Calgary, Alberta

Transfer Point

Computershare Trust Company NA
Canton, Massachusetts

Q3 2017 Trading Profile

Toronto (TSX: PD)

High: $4.57

Low: $3.01

Close: $3.88

Volume Traded: 132,515,300

New York (NYSE: PDS)

High: US$3.47

Low: US$2.41

Close: US$3.20

Volume Traded: 197,426,800

Account Questions

Precision’s Transfer Agent can help you with a variety of shareholder related services, including:

• change of address

• lost unit certificates

• transfer of shares to another person

• estate settlement

Computershare Trust Company of Canada
100 University Avenue
9th Floor, North Tower
Toronto, Ontario M5J 2Y1
Canada

1-800-564-6253 (toll free in Canada and the United States)

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.

CORPORATE INFORMATION

Directors

William T. Donovan

Brian J. Gibson

Allen R. Hagerman, FCA

Catherine J. Hughes

Steven W. Krablin

Stephen J.J. Letwin

Susan M. MacKenzie

Kevin O. Meyers

Kevin A. Neveu

Officers

Kevin A. Neveu

President and Chief Executive Officer

Douglas B. Evasiuk

Senior Vice President, Sales and Marketing

Veronica H. Foley

Senior Vice President, General Counsel and Corporate Secretary

Carey T. Ford

Senior Vice President and Chief Financial Officer

Darren J. Ruhr

Senior Vice President, Corporate Services

Gene C. Stahl

President, Drilling Operations

Auditors

KPMG LLP

Calgary, Alberta

Head Office

Suite 800, 525 8^th Avenue SW

Calgary, Alberta, Canada T2P 1G1

Telephone: 403-716-4500

Facsimile: 403-264-0251

Email: info@precisiondrilling.com