exh99_1.htm

PRECISION DRILLING CORPORATION

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s Discussion and Analysis for the three month period ended September 30, 2013 of Precision Drilling Corporation (“Precision” or the “Corporation”) prepared as at October 23, 2013 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 2012 Annual Report, Annual Information Form, the unaudited September 30, 2013 Interim Consolidated Financial Statements and related notes and the cautionary statement regarding forward-looking information and statements on page 11 of this report.

SELECT FINANCIAL AND OPERATING INFORMATION

Financial Highlights
	Three months ended September 30,									Nine months ended September 30,
(Stated in thousands of Canadian dollars, except where noted)	2013			2012			% Change			2013			2012			% Change
Revenue		488,450			484,761			0.8			1,463,068			1,506,793			(2.9	)
Adjusted EBITDA(1)		137,660			151,000			(8.8	)		441,089			493,766			(10.7	)
Adjusted EBITDA % of revenue		28.2	%		31.1	%					30.1	%		32.8	%
Net earnings		29,443			39,357			(25.2	)		123,229			168,699			(27.0	)
Cash provided by operations		88,341			61,183			44.4			333,634			498,969			(33.1	)
Funds provided by operations(1)		127,684			146,124			(12.6	)		306,157			456,236			(32.9	)
Capital spending:
Expansion		70,108			177,783			(60.6	)		228,411			473,131			(51.7	)
Upgrade		39,548			23,166			70.7			111,206			107,388			3.6
Maintenance and infrastructure		36,264			37,701			(3.8	)		73,145			100,888			(27.5	)
Proceeds on sale		(3,335	)		(5,011	)		(33.4	)		(10,021	)		(13,820	)		(27.5	)
Net capital spending		142,585			233,639			(39.0	)		402,741			667,587			(39.7	)

Net earnings - per share ($):
Basic		0.11			0.14			(21.4	)		0.45			0.61			(26.2	)
Diluted		0.10			0.14			(28.6	)		0.43			0.59			(27.1	)
Dividend paid per share ($)		0.05			-			n/m			0.15			-			n/m

(1)	Adjusted EBITDA and funds provided by operations are additional GAAP measures. See “ADDITIONAL GAAP MEASURES”.

n/m --calculation not meaningful

Operating Highlights
	Three months ended September 30,							Nine months ended September 30,
	2013		2012		% Change			2013		2012		% Change
Contract drilling rig fleet		326		363		(10.2	)		326		363		(10.2	)
Drilling rig utilization days:
Canada		7,622		7,735		(1.5	)		22,329		24,110		(7.4	)
United States		7,412		8,305		(10.8	)		22,010		26,583		(17.2	)
International		969		736		31.7			2,503		1,319		89.8
Service rig fleet		222		210		5.7			222		210		5.7
Service rig operating hours		70,493		72,766		(3.1	)		211,595		217,368		(2.7	)

Financial Position

(Stated in thousands of Canadian dollars, except ratio)	September 30, 2013		December 31, 2012
Working capital		208,255		278,021
Long-term debt(1)		1,270,976		1,218,796
Total long-term financial liabilities		1,302,883		1,245,290
Total assets		4,424,413		4,300,263
Long-term debt to long-term debt plus equity ratio(1)		0.36		0.36

(1)	Net of unamortized debt issue costs.

Net earnings this quarter were $29 million or $0.10 per diluted share compared to $39 million or $0.14 per diluted share in the third quarter of 2012.

Revenue this quarter was $488 million, $4 million or 1% higher than the third quarter of 2012. The increase was the result of growth in our international and U.S. Completion and Production Services divisions and higher average dayrates in Canadian contract drilling substantially offset by a decrease in activity days in both Canada and the United States as a result of lower levels of customer spending. Compared to the third quarter of 2012, revenue from our Contract Drilling Services segment was up 1% and revenue in our Completion and Production Services segment was up 2%.

Earnings before income taxes, finance charges, foreign exchange, and depreciation and amortization ("adjusted EBITDA" see “Additional GAAP Measures”) this quarter was $138 million, 9% lower than the third quarter of 2012. The decrease in adjusted EBITDA was mainly the result of lower activity levels across most North American business lines partially offset by higher average dayrates and increased international profitability. Our activity in this quarter, as measured by drilling rig utilization days, decreased 1% in Canada and 11% in the United States compared to the third quarter of 2012.

Adjusted EBITDA margin (adjusted EBITDA as a percentage of revenue) was 28% this quarter, compared to 31% in the third quarter of 2012. The decrease in adjusted EBITDA margin was a result of the impact of lower utilization on fixed costs, a non-recurring vendor issue and a difficult turnkey project, partially offset by higher dayrates from the new build and upgraded Tier 1 rigs that we have deployed over the past few years. Our portfolio of term customer contracts, a highly variable operating cost structure and economies achieved through vertical integration of the supply chain all help in managing our adjusted EBITDA margins.

For the nine months ended September 30, 2013, Precision reported net earnings of $123 million or $0.43 per diluted share compared to $169 million or $0.59 per diluted share for the same period of 2012. Revenue for the first nine months of 2013 was $1,463 million compared to $1,507 million for the corresponding period of 2012. Adjusted EBITDA totalled $441 million for the first nine months of 2013 compared to $494 million in the same period in 2012. The decrease in revenue and EBITDA was mainly the result of lower activity levels across most North American business lines partially offset by higher dayrates and increased international activity. Activity for Precision, as measured by drilling utilization days, decreased 7% in Canada and 17% in the United States for the first nine months of the year compared with the same period in 2012.

Precision has firm customer commitments to add three new build Super Series rigs to its North American drilling fleet bringing the total number of announced new build rigs in 2013 to nine.

On October 23, 2013 the Board of Directors declared a dividend of $0.06 per common share payable on November 15, 2013 to shareholders of record on November 4, 2013.

Our vision is to be recognized as the High Performance, High Value provider of services for global energy exploration and development. We work toward that vision by defining and measuring our results against strategic priorities. Our 2013 priorities are threefold:

1.	Execute our High Performance, High Value strategy

Continue to drive execution excellence in our people, internal systems and infrastructure supporting our world class safety, training and development programs, upgrading and consolidating our Nisku operations and leveraging our investments in our Houston and Red Deer Tech Centers.

To September 30, 2013 our safety performance and mechanical downtime have shown improvement over the same period in 2012 and we continue to invest in our systems and infrastructure.

2 | Management's Discussion and Analysis

2.	Execute on existing organic growth opportunities

Remain poised to seize growth opportunities, leveraging our balance sheet strength and flexibility. Deliver new build rigs to the North American market and upgrade existing drilling rigs to higher specification assets on customer contracts globally.

To September 30, 2013 we have delivered the two remaining rigs from the 2012 new build program, announced nine new build rigs for 2013 and we continue to deliver upgraded rigs to customers under contract.

Grow High Performance, High Value service lines for unconventional field development, such as integrated directional drilling, coil tubing and rentals.

To September 30, 2013 we have increased our coil tubing fleet to 12 units from five as at December 31, 2012.

We continue to promote our integrated directional drilling services to oil and gas customers and have invested in people and equipment to execute the strategy. Although overall industry adoption has been slower than expected, we are currently experiencing an increase in the percentage of integrated service jobs on Precision drilling rigs, particularly in Canada.

3.	Build our brand

Uphold our reputation and market breadth in North America while strengthening our presence in select oilfield markets internationally.

To September 30, 2013 we continue to operate a high percentage of our rigs drilling directional or horizontal wells in unconventional basins across North America and have expanded our activities in Mexico and entered a new market in Northern Iraq.

For the third quarter of 2013, natural gas prices and the West Texas Intermediate price of oil were higher than the 2012 averages.


	Three months ended September 30,				Year ended December 31,
	2013		2012		2012
Average oil and natural gas prices:
Oil
West Texas Intermediate (per barrel) (US$)		105.94		92.26		94.13
Natural gas
Canada
AECO (per MMBtu) (Cdn$)		2.45		2.28		2.39
United States
Henry Hub (per MMBtu) (US$)		3.55		2.88		2.75

Summary for the three months ended September 30, 2013:

● Operating earnings (see “Additional GAAP Measures”) this quarter were $52 million and 11% of revenue, compared to $74 million and 15% of revenue in 2012. Operating earnings were negatively impacted by the decrease in activity in most of our North American based operations compared to the third quarter in 2012 and higher depreciation as a result of a greater proportion of operating days from our Tier 1 drilling rigs and depreciation on rigs working internationally.

● General and administrative expenses this quarter were $38 million or $5 million higher than the third quarter of 2012 primarily because of a vendor insolvency issue.

● Net finance charges were $23 million, an increase of $2 million compared with the third quarter of 2012 primarily because of foreign exchange on our U.S. dollar denominated interest payments and lower interest income.

Precision Drilling Corporation | 3

● Average revenue per utilization day for contract drilling rigs increased in the third quarter of 2013 to $20,862 from the prior year third quarter of $20,099 in Canada and decreased in the United States to $22,595 from $23,110 for the third quarter of 2012. The increase in revenue rates for the third quarter in Canada was due to rig mix in part from Tier 1 and upgraded rigs entering the fleet compared to the prior year quarter. In Canada, for the third quarter of 2013, 46% of Precision’s utilization days were achieved from drilling rigs working under term contracts compared to 42% in the 2012 comparative period. In the United States, the decrease in dayrates for the third quarter was due to rig mix as we experienced lower turnkey activity and a higher proportion of rigs working in the spot market. In the United States, for the third quarter of 2013, 60% of Precision’s utilization days were generated from rigs working under term contracts compared to 73% in the 2012 comparative period. Turnkey revenue for the third quarter of 2013 was US$7 million, compared with US$11 million in the 2012 comparative period. Within Precision’s Completion and Production Services segment, average hourly rates for service rigs were $863 in the third quarter of 2013 compared to $769 in the third quarter of 2012. The increase in the average hourly rate is the result of rig mix with the introduction of coil tubing rigs in the United States. Canadian well servicing rig average hourly rate decreased by $6 per hour quarter over quarter due to competitive pressure in the industry resulting from lower industry activity.

● Average operating costs per utilization day for drilling rigs decreased in the third quarter of 2013 to US$14,789 from the prior year third quarter of US$14,816 in the United States while in Canada costs increased to $10,310 in 2013 from $9,828 in 2012. The cost decrease per day in the United States was primarily due to lower turnkey activity. The cost increase in Canada was primarily due to a labour rate increase that became effective in the fourth quarter of 2012. Within Precision’s Completion and Production Services segment, average hourly operating costs for service rigs increased to $674 in the third quarter of 2013 as compared to $535 in the third quarter of 2012 primarily due to costs associated with coil tubing and fixed costs spread over a lower activity base. Operating costs were also impacted by rig mix with eight coil tubing rigs operating in the United States in the third quarter of 2013. Canadian well servicing rig average hourly operating costs were up $55 per hour in the current quarter over the prior year comparative, due to higher repairs and maintenance costs and fixed costs spread over a lower activity base.

● We realized revenue from directional services of $32 million in the third quarter of 2013, in line with the prior year period.

● Funds provided by operations (see “Additional GAAP Measures”) in the third quarter of 2013 were $128 million, a decrease of $18 million from the prior year comparative quarter of $146 million. The decrease is the result of lower earnings for the quarter compared to last year and more income tax paid in the current year quarter.

● Capital expenditures for the purchase of property, plant and equipment were $146 million in the third quarter, a decrease of $93 million over the same period in 2012. Capital spending for the third quarter of 2013 included $70 million for expansion capital, $40 million for upgrade capital and $36 million for the maintenance of existing assets and infrastructure spending.

Summary for the nine months ended September 30, 2013:

● Revenue for the nine months ended September 30, 2013 was $1,463 million, a decrease of 3% from the 2012 period.

● Operating earnings were $198 million, a decrease of $77 million or 28% from 2012. Operating earnings were 14% of revenue in 2013 compared to 18% in 2012.

● General and administrative costs were $109 million, an increase of $12 million over the first nine months of 2012 primarily as a result of the increase in incentive compensation costs tied to the performance of Precision’s common shares in 2013 and costs associated with a vendor’s insolvency problem.

● Net finance charges were $70 million, an increase of $5 million over the first nine months of 2012.

● Funds provided by operations in the first nine months of 2013 were $306 million, a decrease of $150 million from the prior year comparative period of $456 million.

● Capital expenditures for the purchase of property, plant and equipment were $413 million in the first nine months of 2013, a decrease of $269 million over the same period in 2012. Capital spending for 2013 to date included $229 million for expansion capital, $111 million for upgrade capital and $73 million for the maintenance of existing assets and infrastructure.

4 | Management's Discussion and Analysis

OUTLOOK

Contracts

Our portfolio of term customer contracts provides a base level of activity and revenue, and as of October 23, 2013 we have term contracts in place for an average of 54 rigs in Canada, 50 in the United States and 11 internationally for the fourth quarter of 2013 and an average of 56 rig contracts in Canada, 46 in the United States and 10 internationally for the 2013 year. In Canada, term contracted rigs normally generate 250 utilization days per rig year because of the seasonal nature of well access. In most regions in the United States and internationally, term contracts normally generate 365 utilization days per rig year.

Drilling Activity

In the United States, our average active rig count in the quarter was 81 rigs, down nine rigs over the third quarter in 2012 and up one rig over the second quarter of 2013. We currently have 87 rigs active in the United States.

In Canada, our average active rig count in the quarter was 83 rigs, down one rig over the third quarter of 2012 and up 43 rigs over the second quarter of 2013. We currently have 96 rigs active in Canada and expect activity to increase moderately through the fourth quarter.

Internationally, our average active rig count in the quarter was 11 rigs, up three over the third quarter in 2012 and up two rigs over the second quarter of 2013. Our active rig count internationally is expected to grow by one rig before the end of the year as a rig is going to work in Mexico during the fourth quarter.

Industry Conditions

According to industry sources, as of October 18, 2013, the U.S. active land drilling rig count was down about 6% from the same point last year and the Canadian active land drilling rig count was up 9% over the prior year. Despite the active industry rig count softness, demand for Tier 1 assets continues to be strong, benefiting those drilling contractors with a high percentage of Tier 1 assets.

The trend toward oil-directed drilling in North America has continued in 2013. To date approximately 69% of the Canadian industry’s active rigs and 78% of the U.S. industry’s active rigs were drilling for oil targets, compared to 72% for Canada and 70% for the U.S. at the same time last year.

Capital Spending

Capital expenditures in 2013 are expected to decrease from $654 million announced in July to $609 million primarily as a result of decreased activity based maintenance and discretionary expansion capital expenditures offset by the additional new build rigs. Our capital spend for the first nine months of 2013 was $413 million:

$322 million for expansion capital, which includes the cost to complete the two remaining new build drilling rigs from the 2012 new build rig program, more than 85% of the costs to complete the 2013 nine new build rigs for the North American market, the cost to complete about 60% of two new build rigs going to Kuwait, long lead equipment and new equipment for our Completion and Production Services segment;

·	$145 million for upgrade capital, which includes the upgrade of approximately 20 rigs, including international and North American rigs and to purchase long lead time items for our capital inventory; and

·	$142 million for sustaining and infrastructure expenditures, which is based on currently anticipated activity levels and some of the cost to consolidate and upgrade our operating facilities.

Precision Drilling Corporation | 5

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, coil tubing, 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)	2013			2012			% Change			2013			2012			% Change
Revenue:
Contract Drilling Services		411,987			409,889			0.5			1,235,561			1,273,136			(3.0	)
Completion and Production Services		78,960			77,506			1.9			237,968			240,854			(1.2	)
Inter-segment eliminations		(2,497	)		(2,634	)		(5.2	)		(10,461	)		(7,197	)		45.4
		488,450			484,761			0.8			1,463,068			1,506,793			(2.9	)

Adjusted EBITDA:(1)
Contract Drilling Services		144,633			146,080			(1.0	)		453,393			477,112			(5.0	)
Completion and Production Services		12,363			23,143			(46.6	)		44,771			71,332			(37.2	)
Corporate and other		(19,336	)		(18,223	)		6.1			(57,075	)		(54,678	)		4.4
		137,660			151,000			(8.8	)		441,089			493,766			(10.7	)

(1) See “ADDITIONAL GAAP MEASURES”.

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES


	Three months ended September 30,									Nine months ended September 30,
(Stated in thousands of Canadian dollars, except where noted)	2013			2012			% Change			2013			2012			% Change
Revenue		411,987			409,889			0.5			1,235,561			1,273,136			(3.0	)
Expenses:
Operating		255,683			252,556			1.2			746,049			765,749			(2.6	)
General and administrative		11,671			11,253			3.7			36,119			30,275			19.3
Adjusted EBITDA (1)		144,633			146,080			(1.0	)		453,393			477,112			(5.0	)
Depreciation		75,421			67,659			11.5			212,530			193,666			9.7
Operating earnings(1)		69,212			78,421			(11.7	)		240,863			283,446			(15.0	)
Operating earnings as a percentage of revenue		16.8	%		19.1	%					19.5	%		22.3	%
Drilling rig revenue per utilization day in Canada (Cdn$)		20,862			20,099			3.8			21,805			20,699			5.3
Drilling rig revenue per utilization day in the United States(2) (US$)		22,595			23,110			(2.2	)		23,474			23,162			1.3

(1) See “ADDITIONAL GAAP MEASURES”.

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


	Three months ended September 30,
Canadian onshore drilling statistics:(1)	2013						2012
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		188			821			202			825
Drilling rig operating days (spud to release)		6,779			30,649			6,957			30,220
Drilling rig operating day utilization		39	%		41	%		38	%		40	%
Number of wells drilled		912			3,202			948			3,607
Average days per well		7.4			9.6			7.3			8.4
Number of metres drilled (000s)		1,550			6,481			1,491			5,853
Average metres per well		1,700			2,024			1,573			1,623
Average metres per day		229			211			214			194

6 | Management's Discussion and Analysis


	Nine months ended September 30,
Canadian onshore drilling statistics:(1)	2013						2012
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		188			821			202			825
Drilling rig operating days (spud to release)		19,781			87,527			21,579			93,470
Drilling rig operating day utilization		39	%		39	%		41	%		42	%
Number of wells drilled		2,338			7,928			2,223			7,940
Average days per well		8.5			11.0			9.7			11.8
Number of metres drilled (000s)		4,086			16,433			3,798			15,013
Average metres per well		1,748			2,073			1,708			1,891
Average metres per day		207			188			176			161

(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)	2013				2012
	Precision		Industry(2)		Precision		Industry(2)
Average number of active land rigs for quarters ended:
March 31		81		1,706		104		1,947
June 30		80		1,710		97		1,924
September 30		81		1,709		90		1,855
Year to date average		81		1,708		97		1,909

(1) United States lower 48 land operations only.

(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $412 million this quarter or 1% higher than the third quarter of 2012, while adjusted EBITDA of $145 million decreased 1%. The changes from prior year were mainly due to lower drilling rig utilization in both Canada and the United States and lower average dayrates in the United States offset by growth in our international contract drilling business and increases in average dayrates in Canada.

Operating results for our international business improved as a result of increased activity. On average, we had 11 rigs working internationally during the third quarter of 2013 compared with eight in the corresponding quarter of 2012. Drilling utilization days in our international operations were 969 days, 32% higher than the prior year comparative period.

Drilling rig utilization days in Canada (drilling days plus move days) during the third quarter of 2013 were 7,622, a decrease of 1% compared to 2012 while drilling rig utilization days in the United States were 7,412 or 11% lower than the same quarter of 2012. The declines in activity were primarily due to decreased market demand as customers conserved cash and deferred drilling programs. The majority of our North America activity came from oil and liquids-rich natural gas related plays.

Drilling rig revenue per utilization day during the third quarter was up 4% in Canada while in the U.S. drilling rig revenue per utilization day was down 2% over 2012. The increase in average dayrates for Canada was the result of improved rig mix and continued demand for Tier 1 assets. In the United States, the decrease in revenue per utilization day for the third quarter was due to rig mix as we experienced lower turnkey activity and a higher proportion of rigs working in the spot market.

In Canada, 46% of utilization days in the third quarter were generated from rigs under term contract, compared to 42% in the third quarter of 2012. In the U.S., 60% of utilization days were generated from rigs under term contract as compared to 73% in the third quarter of 2012. At the end of the quarter we had 56 drilling rigs under contract in Canada, 53 in the U.S. and 11 internationally.

Operating costs were 62% 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 above the prior year primarily because of an increase in crew wage expense. In the U.S., operating costs for the quarter on a per day basis were in line with the third quarter in 2012 as the impact of fixed costs on lower activity was offset by turnkey costs.

Precision Drilling Corporation | 7

Depreciation expense in the quarter was 11% higher than in the third quarter of 2012. Depreciation was higher, despite a decrease in overall drilling activity, as a result of a greater proportion of operating days from our Tier 1 drilling rigs in 2013 relative to 2012 and international contract drilling. With the exception of certain PSST drilling rigs and directional drilling equipment, contract drilling operations use the unit of production method of calculating depreciation.

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)	2013			2012			% Change			2013			2012			% Change
Revenue		78,960			77,506			1.9			237,968			240,854			(1.2	)
Expenses:
Operating		59,364			50,474			17.6			177,569			157,943			12.4
General and administrative		7,233			3,889			86.0			15,628			11,579			35.0
Adjusted EBITDA(1)		12,363			23,143			(46.6	)		44,771			71,332			(37.2	)
Depreciation		7,988			7,640			4.6			24,306			21,775			11.6
Operating earnings(1)		4,375			15,503			(71.8	)		20,465			49,557			(58.7	)

Operating earnings as a percentage of revenue		5.5	%		20.0	%					8.6	%		20.6	%

Well servicing statistics:
Number of service rigs (end of period)		222			210			5.7			222			210			5.7
Service rig operating hours		70,493			72,766			(3.1	)		211,595			217,368			(2.7	)
Service rig operating hour utilization		32	%		37	%					34	%		38	%
Service rig revenue per operating hour (Cdn$)		863			769			12.2			844			794			6.3

(1)	See “ADDITIONAL GAAP MEASURES”.

Revenue from Completion and Production Services was up $1 million or 2% compared to the third quarter of 2012 due to expansion of services in the United States partially offset by lower activity in Canada. Adjusted EBITDA was $11 million lower than the third quarter of 2012 due to start-up costs associated with expanding activity in the United States and lower activity in Canada and a loss recognized due to a vendor’s insolvency. The decline in industry activity was mainly because customers reduced spending to work within their cash flow, which reduced activity in the majority of our service lines.

Well servicing activity in the third quarter was 3% lower than the third quarter of 2012 primarily due to reduced activity in Canada partially offset by our expansion in the United States. Approximately 84% of our third quarter Canadian service rig activity was oil related. Our rental division activity in the third quarter was lower than the third quarter of 2012 mainly due to the excess amount of surface storage capacity in the Western Canada Sedimentary Basin.

Average service rig revenue per operating hour in the third quarter was $863, or $94 higher than the third quarter of 2012. Increased coil tubing operations in the current quarter, which operate at higher rates, were partially offset by a reduction in the average service rig rate due to industry competition with less activity.

Operating costs as a percentage of revenue increased to 75% in the third quarter of 2013, from 65% in the third quarter of 2012. Operating costs per service rig operating hour were higher than in the third quarter of 2012 because of higher repairs and maintenance, fixed costs spread over a lower activity base and cost associated with start-up of the new coil tubing operations.

Depreciation in the third quarter of 2013 was 5% higher than the third quarter of 2012 because of depreciation expense associated with new equipment. We use the straight-line method of calculating depreciation for our completion and production business lines, except for the well servicing division, where we use the unit of production method.

SEGMENT REVIEW OF CORPORATE AND OTHER

Our corporate segment is viewed as support functions that provide assistance to more than one segment. The Corporate and other segment had an adjusted EBITDA loss of $19 million for the third quarter of 2013, $1 million higher than the prior period.

8 | Management's Discussion and Analysis

OTHER ITEMS

Net financial charges for the quarter were $23 million, an increase of $2 million from the third quarter of 2012. The increase was primarily because of foreign exchange on U.S. dollar denominated interest payments and lower interest income.

We had a foreign exchange loss of $3 million during the third quarter of 2013 due to the strengthening of the Canadian dollar versus the U.S. dollar from June 30, 2013 and the impact thereof on the net U.S. dollar denominated monetary position in the Canadian dollar-based companies.

Income taxes for the quarter were a recovery of $4 million compared to an $8 million expense in the prior year period. Our effective tax rate on earnings before income taxes for the first nine months of 2013 was 8%.

In June 2013, a wholly owned subsidiary of Precision lost a tax appeal in the Ontario Superior Court of Justice related to a reassessment of Ontario income tax for the subsidiary’s 2001 thru 2004 taxation years. Precision has appealed the decision to the Ontario Court of Appeal and we expect this appeal to be heard in the latter half of 2014. Despite the decision in the Superior Court, management believes it is more likely than not that Precision will prevail on appeal. Should Precision lose on appeal, approximately $55 million of the long-term income tax recoverable related to this issue would be expensed.

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, no matter 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

As at September 30, 2013 our liquidity is supported by a cash balance of $82 million, an undrawn balance on our senior secured credit facility of approximately US$805 million, availability on our operating facilities totaling approximately $40 million and a US$25 million secured facility for letters of credit.

At September 30, 2013, including letters of credit, we had approximately $1,341 million outstanding under our senior notes and secured and unsecured credit facilities and $24 million in unamortized debt issue costs.


Amount	Availability	Used for	Maturity
Senior facility (secured)
US$850 million (extendible, revolving term credit facility with US$250 million accordion feature)	$15 million drawn, and US$29 million in outstanding letters of credit	General corporate purposes	November 17, 2018
Operating facilities (secured)
$40 million	Undrawn, except $17 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$25 million	Undrawn	Letters of credit
Senior notes (unsecured)
$200 million	Fully drawn	Debt repayment	March 15, 2019
US$650 million	Fully drawn	Debt repayment and general corporate purposes	November 15, 2020
US$400 million	Fully drawn	Capital expenditures and general corporate purposes	December 15, 2021

Our secured facility includes financial ratio covenants that are tested quarterly and we are compliant with these covenants and expect to remain compliant.

The current blended cash interest cost of our debt is about 6.5%.

Precision Drilling Corporation | 9

Hedge of investments in U.S. operations

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

QUARTERLY FINANCIAL SUMMARY

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


	2012			2013
Quarters ended	December 31			March 31		June 30		September 30
Revenue		533,948			595,720		378,898		488,450
Adjusted EBITDA(1)		177,026			215,181		88,248		137,660
Net earnings (loss):		(166,339	)		93,313		473		29,443
Per basic share		(0.42	)		0.34		0.00		0.11
Per diluted share		(0.42	)		0.33		0.00		0.10
Funds provided by operations(1)		142,576			144,682		33,791		127,684
Cash provided by operations		136,317			62,948		182,345		88,341
Dividends per share		0.05			0.05		0.05		0.05


	2011		2012
Quarters ended	December 31		March 31		June 30		September 30
Revenue		587,408		640,066		381,966		484,761
Adjusted EBITDA(1)		229,839		245,574		97,192		151,000
Net earnings:		28,046		111,081		18,261		39,357
Per basic share		0.10		0.40		0.07		0.14
Per diluted share		0.10		0.39		0.06		0.14
Funds provided by operations(1)		256,103		247,739		62,373		146,124
Cash provided by operations		218,857		162,440		275,346		61,183

(1) See “ADDITIONAL GAAP MEASURES”.

ADDITIONAL GAAP MEASURES

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

Adjusted EBITDA

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

Operating Earnings

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

Funds Provided by Operations

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

10 | Management's Discussion and Analysis

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

During the nine months ended September 30, 2013, there were no changes in internal control over financial reporting that materially affected (or are reasonably likely to materially affect) our internal control over financial reporting.

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: that firm customer commitments to build three new build Super Series rigs will result in term contracts; declared the payment of a fourth quarter dividend; we currently have 96 rigs active in Canada and expect activity to increase moderately through the fourth quarter; our active rig count internationally is expected to grow by one rig before the end of the year; demand for Tier 1 assets continues to be strong, benefitting those drilling contractors with a high percentage of Tier 1 assets; capital expenditures in 2013 are expected to decrease from $654 million announced in July to $609 million; the anticipated uses and timing of this capital spending; and that Precision expects the appeal to the Ontario Court of Appeal related to an assessment of Ontario income tax to be heard in the latter half of 2014 and management of Precision believes it is more likely than not that Precision will prevail on the appeal however should Precision lose on appeal, approximately $55 million of the long-term income tax recoverable related to this issue would be expensed.

These forward‐looking information and statements are based on certain assumptions and analysis made by the Corporation in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. However, whether actual results, performance or achievements will conform to the Corporation’s expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results to differ materially from the Corporation’s expectations. Such risks and uncertainties include, but are not limited to: fluctuations in the price and demand for oil and natural gas; fluctuations in the level of oil and natural gas exploration and development activities; fluctuations in the demand for contract drilling, well servicing and ancillary oilfield services; capital market liquidity available to fund customer drilling programs; viability of its vendors; availability of cash flow, debt and/or equity sources to fund the Corporation’s capital and operating requirements, as needed; sustainability of our dividend; the effects of seasonal and weather conditions on operations and facilities; the existence of competitive operating risks inherent in its businesses; general economic, market or business conditions; changes in laws or regulations; the availability of qualified personnel, management or other key inputs; currency exchange fluctuations; and other unforeseen conditions which could impact the use of services supplied by Precision and Precision’s ability to respond to such conditions.

Consequently, all of the forward‐looking information and statements made in this report are qualified by these cautionary statements and there can be no assurance that the actual results or developments anticipated by the Corporation will be realized or, even if substantially realized, that they will have the expected consequences to, or effects on, the Corporation or its business or operations. Readers are therefore cautioned not to place undue reliance on such forward‐looking information and statements. Except as may be required by law, the Corporation assumes no obligation to update publicly any such forward‐looking information and statements, whether as a result of new information, future events or otherwise.

Precision Drilling Corporation | 11

SHAREHOLDER INFORMATION

STOCK EXCHANGE LISTINGS	ACCOUNT QUESTIONS	ONLINE INFORMATION
Shares of Precision Drilling Corporation are listed on the Toronto Stock Exchange ("TSX") under the trading symbol PD and on the New York Stock Exchange ("NYSE") under the trading symbol PDS. Q3 2013 TRADING PROFILE	Precision’s Transfer Agent can help you with a variety of shareholder related services, including: • Change of address • Lost unit certificates • Transfer of units to another person • Estate settlement	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.
Toronto (TSX: PD)
High: $11.11	You can contact Precision’s Transfer Agent at:
Low: $8.99	Computershare Trust Company of Canada
Close: $10.22	100 University Avenue
Volume Traded: 61,627,072	9th Floor, North Tower
	Toronto, Ontario M5J 2Y1
New York (NYSE: PDS)	Canada
High: US$10.77
Low: US$8.55	Telephone: 1-800-564-6253
Close: US9.92	(toll free in Canada and the United States)
Volume Traded: 58,457,700
	1-514-982-7555
TRANSFER AGENT AND REGISTRAR	(international direct dialing)
Computershare Trust Company of Canada
Calgary, Alberta	Email: service@computershare.com

TRANSFER POINT
Computershare Trust Company NA
Denver, Colorado

CORPORATE INFORMATION

Head Office	Officers	Lead Bank
Precision Drilling Corporation	Kevin A. Neveu	Royal Bank of Canada
Suite 800, 525-8th Avenue SW	President and Chief Executive Officer	Calgary, Alberta
Calgary, Alberta, Canada T2P 1G1
Telephone: 403-716-4500	Joanne L. Alexander	Auditors
Facsimile: 403-264-0251	Senior Vice President, General Counsel and Corporate Secretary	KPMG LLP
Email: info@precisiondrilling.com		Calgary, Alberta
www.precisiondrilling.com	Niels Espeland
	President, International Operations
Directors
William T. Donovan	Douglas B. Evasiuk
Brian J. Gibson	Senior Vice President, Sales and Marketing
Allen R. Hagerman, FCA
Catherine Hughes	Kenneth J. Haddad
Stephen J.J. Letwin	Senior Vice President, Business Development
Kevin O. Meyers
Patrick M. Murray	Robert J. McNally
Kevin A. Neveu	Executive Vice President and Chief Financial Officer
Robert L. Phillips
	Darren J. Ruhr
	Senior Vice President, Corporate Services

	Gene C. Stahl
	President, Drilling Operations

	Douglas J. Strong
	President, Completion and Production Services