Precision Drilling Corporation Announces 2016 Four

CALGARY, ALBERTA--(Marketwired - Feb. 9, 2017) - Precision Drilling Corporation (TSX:PD)(NYSE:PDS) - (Canadian dollars except as indicated) -

This news release contains "forward-looking information and statements" within the meaning of applicable securities laws. For a full disclosure of the forward-looking information and statements and the risks to which they are subject, see the "Cautionary Statement Regarding Forward-Looking Information and Statements" later in this news release.

For the fourth quarter of 2016, we recorded earnings before income taxes, loss on repurchase of unsecured senior notes, finance charges, foreign exchange, impairment of goodwill, impairment of property, plant and equipment, gain on re-measurement of property, plant and equipment and depreciation and amortization (adjusted EBITDA see "Additional GAAP Measures") of $65 million, 42% lower than the fourth quarter of 2015. Our activity for the quarter, as measured by drilling rig utilization days, increased 12% in Canada compared with the fourth quarter of 2015, while the U.S. and international decreased 13% and 10%, respectively. Our adjusted EBITDA as a percentage of revenue was 23% this quarter, compared with 32% in the fourth quarter of 2015. The decrease in adjusted EBITDA as a percent of revenue was mainly due to decreased activity in the U.S. and international and lower spot market pricing.

We recorded a net loss this quarter of $31 million, or $0.10 per diluted share, compared with a net loss of $271 million, or $0.93 per diluted share, in the fourth quarter of 2015. In the fourth quarter of 2015 we incurred decommissioning and impairment charges that reduced net earnings by $254 million and net earnings per diluted share by $0.87.

Revenue this quarter was $284 million or 18% lower than the fourth quarter of 2015, due to decreased activity in our U.S. and international contract drilling operations along with lower day rates in Canada and the U.S. Revenue from our Contract Drilling Services and Completion and Production Services segments decreased over the comparative prior year period by 17% and 26%, respectively.

For the year ended December 31, 2016 the net loss was $156 million, or $0.53 per diluted share, compared with a net loss of $363 million, or $1.24 per diluted share in 2015, while revenue was $951 million, or 39% less than 2015. In 2015 we incurred decommissioning and impairment charges that reduced net earnings by $329 million and net earnings per diluted share by $1.12.

Our capital expenditures for 2016 were $203 million, a decrease of $10 million compared with the $213 million capital plan announced in December 2016. The decrease is due to a reduction in actual spend compared with forecast. In addition, we acquired 48 well service rigs and ancillary equipment in a business acquisition for consideration of $12 million and our coil tubing assets.

During the quarter we issued US$350 million of 7.75% senior notes due 2023 ("Notes") in a private offering. The Notes are guaranteed on a senior unsecured basis by current and future U.S. and Canadian subsidiaries that also guarantee our revolving credit facility and certain other indebtedness. The net proceeds from the offering, along with cash on hand, were used to redeem all $200 million of our 2019 notes, redeem on a pro rata basis US$250 million of our outstanding 2020 notes and repurchase US$53 million of our 2021 notes.

Kevin Neveu, Precision's President and Chief Executive Officer, stated: "The improving customer sentiment we reported in the third quarter gained momentum through the end of the year as stabilized commodity prices and improving industry cash flows continued to drive demand for our services. Today, Precision has 138 rigs drilling or moving; 48 in the U.S. and 90 in Canada. The intentions by both OPEC and non-OPEC producers to implement production quotas should lead to improved market-balancing fundamentals. We expect this stabilized and improving oil price will lead to increased spending for resource development programs, which will be positive for Precision's activity levels and service pricing."

"Precision's activity levels are underpinned by strengthening customer demand for our pad walking Super Series rigs, and reflective of our organization's ability to respond, activating over 100 rigs since our trough activity levels in the second quarter of 2016. I am very pleased to report that Precision has managed this rebound with essentially no increase in fixed costs or reactivation charges. This is a significant achievement for Precision and validates our stated 2016 priority; to be positioned for a rebound."

"With the increased demand for Precision's Super Series rigs we began to increase customer pricing on a select number of rigs in the third quarter, the majority of spot market rigs in the fourth quarter, and are in the process of implementing price increases across all of the active spot market rigs in our fleet. While recent trends are positive, pricing remains below the level necessary to achieve appropriate returns on our capital base, however we believe execution of our High Performance, High Value competitive strategy will generate attractive returns in an improving market."

"In the quarter, we delivered two new-build drilling rigs to Kuwait, earlier than scheduled and on budget and performing very well for our customer. With five rigs operating in Kuwait, we have established appropriate critical mass as well as a strong track record of High Performance, High Value services. We continue to see opportunities for additional work in the region and have been actively discussing new contracts with several customers in the Middle East."

"Throughout Precision's history we have been at the forefront of deploying new technologies to advance the efficiency of our customers' drilling programs. We demonstrated this through our deployment of the first Super Single in 1992, deployment of our first Super Triple XY pad walking rig in 2009, and our integrated directional offering in 2011. We expect to continue these efforts in 2017 working with our technology partners to advance the technology on our Super Triple rigs, including automation of several drilling processes and furthering our de-manned directional drilling service where we have recently completed five autonomous jobs across North America. In the coming months, we will deploy this technology to more rigs and we will be hosting customers at our Technical Center in Houston to showcase the technology enhancements we have already deployed to the field," concluded Mr. Neveu.

S ELECT FINANCIAL AND OPERATING INFORMATION

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

Financial Highlights
			Three months ended December 31,									Year ended December 31,
(Stated in thousands of Canadian dollars, except per share amounts)			2016			2015			% Change			2016			2015			% Change
Revenue			283,903			344,953			(17.7	)		951,411			1,555,624			(38.8	)
Adjusted EBITDA			65,000			111,095			(41.5	)		228,075			473,865			(51.9	)
Adjusted EBITDA % of revenue			22.9%			32.2%						24.0%			30.5%
Net loss			(30,618	)		(270,952	)		(88.7	)		(155,555	)		(363,436	)		(57.2	)
Cash provided by (used in) operations			(27,846	)		70,952			(139.2	)		122,508			517,016			(76.3	)
Funds provided by operations			11,466			49,503			(76.8	)		105,375			357,090			(70.5	)
Capital spending:
	Expansion		15,282			39,386			(61.2	)		148,887			361,425			(58.8	)
	Upgrade		13,527			6,342			113.3			19,862			48,487			(59.0	)
	Maintenance and infrastructure		15,916			20,523			(22.4	)		34,723			48,798			(28.8	)
	Proceeds on sale		(2,010	)		(2,227	)		(9.7	)		(7,840	)		(9,786	)		(19.9	)
Net capital spending			42,715			64,024			(33.3	)		195,632			448,924			(56.4	)
Business acquisitions			12,200			-			n/m			12,200			-			n/m
Loss per share:
	Basic		(0.10	)		(0.93	)		(89.2	)		(0.53	)		(1.24	)		(57.3	)
	Diluted		(0.10	)		(0.93	)		(89.2	)		(0.53	)		(1.24	)		(57.3	)
Dividends paid per share			-			0.07			(100.0	)		-			0.28			(100.0	)

n/m - calculation not meaningful

Operating Highlights
			Three months ended December 31,							Year ended December 31,
			2016		2015		% Change			2016		2015		% Change
Contract drilling rig fleet			255		251		1.6			255		251		1.6
Drilling rig utilization days:
	Canada		4,672		4,176		11.9			12,722		17,238		(26.2	)
	U.S.		3,570		4,109		(13.1	)		11,343		21,172		(46.4	)
	International		742		822		(9.7	)		2,786		4,084		(31.8	)
Revenue per utilization day:
	Canada (1) (Cdn$)		19,867		25,589		(22.4	)		21,084		23,670		(10.9	)
	U.S. (2) (US$)		20,721		24,498		(15.4	)		25,601		25,901		(1.2	)
	International (US$)		52,816		46,767		12.9			45,753		43,491		5.2
Operating cost per utilization day:
	Canada (Cdn$)		9,867		10,354		(4.7	)		10,832		11,577		(6.4	)
	U.S. (US$)		13,778		13,593		1.4			15,003		14,839		1.1
Service rig fleet (3)			207		163		27.0			207		163		27.0
Service rig operating hours			33,170		36,526		(9.2	)		99,451		149,574		(33.5	)
Revenue per operating hour (Cdn$)			629		760		(17.2	)		646		784		(17.6	)

(1)	Includes lump sum revenue from contract shortfall.
(2)	For the three month periods ended December 31 includes revenue from idle but contracted rig days. For the years ended December 31 includes idle but contracted rig days and contract cancellation payments.
(3)	Includes 48 well service rigs acquired in a business acquisition.

Financial Position
(Stated in thousands of Canadian dollars, except ratios)		December 31, 2016		December 31, 2015
Working capital		230,874		536,815
Long-term debt (1)		1,906,934		2,180,510
Total long-term financial liabilities		1,946,742		2,210,231
Total assets		4,324,214		4,878,690
Long-term debt to long-term debt plus equity ratio (1)		0.49		0.51

(1)	Net of unamortized debt issue costs.

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

Precision's strategic priorities for 2016 were as follows:

1. Maintain strong liquidity to manage through an extended downturn - Sustain adequate liquidity by generating positive operating cash flow, ensure access to our revolving credit facility, and continue a multi-year plan for net debt reduction. We maintained full access to our revolving credit facility throughout the year, with only letters of credit drawn. We reduced total debt by $213 million and extended the first maturity date on our senior notes by 18 months from June 2019 to November 2020.
2. Sustain High Performance, High Value service offering - Continue to deliver maximum efficiency and lower risks to support development drilling programs by operating the highest quality assets in the industry with well-trained, professional crews supported by robust systems that eliminate manual processes and improve automation throughout the Precision organization. We operated a fleet of Tier 1 rigs with continued excellent performance in safety, mechanical downtime, move time and crew strength through experience levels and retention of senior field leadership. In addition, we advanced our technology position through rig automation, remote monitoring of integrated directional drilling jobs and enhanced our fleet through upgrades of walking systems, higher pressure mud systems and third mud pumps.
3. Position for an eventual rebound - Concurrent with right-sizing the organization for the extended downturn, we will take steps to prepare for a rebound:
   1. Asset integrity - maintain high quality and integrity of our Tier 1 drilling fleet by utilizing spare equipment, avoiding fleet cannibalization and maintaining rigorous equipment standards. Our maintenance standards and spending did not deteriorate during the year. As a result, we were able to reactivate over 100 rigs with no significant reactivation costs and no catch up purchases of critical components, such as drill pipe.
   2. People - retain field leadership within the organization, maintain relationships with former crew members and continue to develop leadership and skills of workers within our organization. We retained the appropriate field leadership to staff over 100 incremental rigs with highly-trained crews. Additionally, we maintained contact with former Precision workers and kept strong recruiting and training programs in place to support a rebound.
   3. Ample liquidity - maintain strong liquidity to fund working capital requirements and other short term commitments that arise when activity levels increase. Our cash balance remained strong and we retained access to our revolver throughout the year, with only letters of credit drawn.

For the fourth quarter of 2016, the average prices for Henry Hub and AECO natural gas and West Texas Intermediate oil were higher than the 2015 comparable averages.

				Three months ended December 31,				Year ended December 31,
				2016		2015		2016
Average oil and natural gas prices
Oil
	West Texas Intermediate (per barrel) (US$)			49.21		42.04		43.30
Natural gas
	Canada
		AECO (per MMBtu) (Cdn$)		2.96		2.47		2.14
	U.S.
		Henry Hub (per MMBtu) (US$)		2.99		2.08		2.48

Summary for the three months ended December 31, 2016:

• Operating loss (see "Additional GAAP Measures" in this news release) this quarter was $30 million, or 11% of revenue, compared with an operating loss of $383 million and 111% of revenue in 2015. Operating results this quarter were negatively impacted by the decrease in drilling activity in the U.S. and internationally, and pricing in all of our operating segments except international where two new rigs in Kuwait were added in the quarter. In the fourth quarter of 2015 our operating results were negatively impacted by the recognition of asset decommissioning and impairment charges to our property, plant and equipment of $369 million.
• General and administrative expenses this quarter were $32 million, $2 million higher than the fourth quarter of 2015. The increase is primarily due to higher share based incentive compensation, which is tied to the price of our common shares, partially offset by cost saving initiatives. The share based incentive compensation charge recorded to general and administrative expenses for the fourth quarter of 2016 was $13 million compared with $9 million in 2015.
• In December we acquired 48 well service rigs and ancillary equipment for $12 million cash and our coil tubing assets. The total fair value of the assets acquired and consideration provided was $28 million. The book value of our coil tubing assets was $8 million and we recorded a gain on re-measuring these assets of $8 million.
• Net finance charges were $42 million, $8 million higher than the fourth quarter of 2015 due to the early recognition of debt issue costs from the current quarter redemption of long-term debt and additional interest expense for the refinancing overlap period partially offset by a reduction in interest expense related to debt retired during the year.
• During the quarter we redeemed all $200 million of our 6.5% unsecured senior notes due 2019, redeemed on a pro rata basis US$250 million face value of our 6.625% unsecured senior notes due 2020 and purchased and cancelled US$53 million face value of our 6.5% unsecured senior notes due 2021, incurring a net loss of $10 million for all the transactions.
• Average revenue per utilization day for contract drilling rigs decreased in the fourth quarter of 2016 to $19,867 from the prior year fourth quarter of $25,589 in Canada and decreased in the U.S. to US$20,721 from US$24,498. The decrease in Canada is the result of lower spot market rates, less contract shortfall revenue received in the current quarter and a higher proportion of revenue from shallower drilling activity relative to the 2015 comparative period. The decrease in the U.S. is the result of fewer rigs working under long-term contracts and lower daily revenue impact from idle but contracted rigs. We had nil turnkey revenue for the fourth quarter of 2016 in line with the 2015 comparative period and US$5 million in idle but contracted revenue in the current quarter versus US$12 million in the prior year.
• Average operating costs per utilization day for drilling rigs in Canada decreased to $9,867, compared with the prior year fourth quarter of $10,354 primarily because of the prior year recognition of costs associated with moving rigs from the U.S. to Canada. In the U.S., operating costs for the quarter on a per day basis increased slightly to US$13,778 in 2016 compared with US$13,593 in 2015 due to fixed costs spread over fewer active rigs.
• We realized revenue from international contract drilling of $52 million in the fourth quarter of 2016, a $1 million increase over the prior year period. The increase was due to the startup of two new rigs in Kuwait during the quarter partially offset by a reduction in activity in our Mexico based business. Average revenue per utilization day in our international contract drilling business was US$52,816 an increase of 13% over the comparable prior year quarter primarily due to rig mix as we have fewer rigs working in the lower day rate jurisdictions and the recognition of an early mobilization bonus.
• Directional drilling services realized revenue of $9 million in the fourth quarter of 2016 compared with $13 million in the prior year period. The decrease was primarily the result of a decline in activity in both the U.S. and Canada.
• Funds provided by operations in the fourth quarter of 2016 were $11 million, a decrease of $39 million from the prior year comparative quarter of $50 million. The decrease was primarily the result of lower activity levels in the current year period and the costs for the early redemption of our senior unsecured notes in the quarter.
• Capital expenditures for the purchase of property, plant and equipment were $45 million in the fourth quarter, a decrease of $22 million over the same period in 2015. Capital spending for the fourth quarter of 2016 included $15 million for expansion capital, $14 million for upgrade capital and $16 million for the maintenance of existing assets and infrastructure spending.

Summary for the year ended December 31, 2016:

• Revenue for 2016 was $951 million, a decrease of 39% from the 2015 period.
• Operating loss for 2016 was $156 million, or 16% of revenue, compared with an operating loss of $461 million, or 30% of revenue, in 2015. In 2015 our operating results were negatively impacted by the impairment of property, plant and equipment and the decommissioning of certain drilling rigs and spare equipment of $448 million with no comparative amounts recorded in 2016. Operating earnings for 2016 and 2015 were negatively impacted by the decreased drilling activity and rates in our North American operations.
• General and administrative costs were $110 million, a decrease of $16 million from 2015. The decrease is due to efforts in reducing fixed costs through the downturn partially offset by higher share based incentive compensation that is tied to the price of our common shares and by the weakening Canadian dollar on U.S. dollar denominated costs. The share based incentive compensation charge recorded to general and administrative expenses for 2016 was $21 million compared with $16 million in 2015.
• Net finance charges were $146 million, an increase of $25 million from 2015 primarily due to the recognition of $14 million of interest revenue in the comparative period related to an income tax dispute settlement, the recognition of deferred financing costs related to the early redemption of our senior unsecured notes and the impact of foreign exchange on our U.S. dollar denominated interest partially offset by a reduction in interest expense related to debt retired during the year.
• During the year we redeemed all $200 million of our 6.5% unsecured senior notes due 2019 and redeemed on a pro rata basis US$250 million face value of our 6.625% unsecured senior notes due 2020. In addition, we repurchased and cancelled US$81 million face value of our 6.5% unsecured senior notes due 2021 and US$28 million face value of our 6.625% unsecured senior notes due 2020. The combined loss for the redemptions and acquisitions was $0.2 million.
• During the year we reduced total debt by $213 million.
• Funds provided by operations (see "Additional GAAP Measures" in this news release) in 2016 were $105 million, a decrease of $252 million from the prior year comparative period of $357 million.
• Capital expenditures for the purchase of property, plant and equipment were $203 million in 2016, a decrease of $255 million over the same period in 2015. Capital spending for 2016 included $149 million for expansion capital, $20 million for upgrade capital and $34 million for the maintenance of existing assets and infrastructure.

OUTLOOK

Contracts

Our portfolio of term customer contracts provides a base level of activity and revenue. As of February 8, 2017, for the first quarter of 2017 we had, on average, term contracts for 26 rigs in Canada, 26 in the U.S. and eight internationally. As of February 8, 2017, for 2017 we had, on average, term contracts for 20 rigs in Canada, 21 in the U.S. and eight internationally for a total of 49 compared with a year ago when we had an average of 30 under term contracts for 2017. In Canada, term contracted rigs normally generate 250 utilization days per year because of the seasonal nature of well site access. In most regions in the U.S. and internationally, term contracts normally generate 365 utilization days per year.

Drilling Activity

In the U.S., our average active rig count in the quarter was 39 rigs, down six rigs over the fourth quarter in 2015, but up ten rigs from the third quarter of 2016. We currently have 48 rigs active in the U.S.

In Canada, our average active rig count in the quarter was 51 rigs, an increase of six over the fourth quarter in 2015 and an increase of 20 rigs from the third quarter of 2016. We currently have 90 rigs active in Canada.

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

With improved commodity prices and increasing activity levels we have recently been able to increase pricing on spot market rigs across the majority of our fleet. 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.

Internationally, our average active rig count in the quarter was eight rigs, down one rig over the fourth quarter in 2015 but up one rig from the third quarter of 2016. We currently have eight rigs active internationally. In Kuwait, two new-build rigs began working in the fourth quarter of 2016.

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 February 3, 2017, the U.S. active land drilling rig count was up approximately 30% from the same point last year and the Canadian active land drilling rig count was up approximately 42%.

In Canada there has been strength in natural gas and gas liquids drilling activity related to deep basin drilling in northwestern Alberta and northeastern British Columbia while the trend towards oil-directed drilling in the U.S. continues. In 2016, approximately 48% of the Canadian industry's active rigs and 80% of the U.S. industry's active rigs were drilling for oil targets, compared with 45% for Canada and 77% for the U.S. at the same time last year.

We expect Tier 1 rigs to remain the preferred rigs of customers globally. The economic value created by the significant drilling and mobility efficiencies delivered by the most advanced XY pad walking rigs have been highlighted and widely accepted by our customers during this downturn. 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 while 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 $108 million. The 2017 capital expenditure plan includes $4 million for expansion capital, $52 million for sustaining and infrastructure expenditures, and $52 million to upgrade existing rigs. We expect that the $108 million will be split $102 million in the Contract Drilling segment and $6 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 December 31,									Year ended December 31,
(Stated in thousands of Canadian dollars)			2016			2015			% Change			2016			2015			% Change
Revenue:
	Contract Drilling Services		254,919			306,261			(16.8	)		855,999			1,378,336			(37.9	)
	Completion and Production Services		30,706			41,685			(26.3	)		100,049			186,317			(46.3	)
	Inter-segment eliminations		(1,722	)		(2,993	)		(42.5	)		(4,637	)		(9,029	)		(48.6	)
			283,903			344,953			(17.7	)		951,411			1,555,624			(38.8	)
Adjusted EBITDA: (1)
	Contract Drilling Services (2)		86,351			131,330			(34.2	)		296,651			535,394			(44.6	)
	Completion and Production Services		390			(418	)		(193.3	)		(3,649	)		10,239			(135.6	)
	Corporate and other (2)		(21,741	)		(19,817	)		9.7			(64,927	)		(71,768	)		(9.5	)
			65,000			111,095			(41.5	)		228,075			473,865			(51.9	)

(1)	See "ADDITIONAL GAAP MEASURES".
(2)	Certain expenses in the prior year have been reclassified to conform to current year presentation.

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

			Three months ended December 31,									Year ended December 31,
(Stated in thousands of Canadian dollars, except where noted)			2016			2015			% Change			2016			2015			% Change
Revenue			254,919			306,261			(16.8	)		855,999			1,378,336			(37.9	)
Expenses: (1)
	Operating		160,638			162,761			(1.3	)		518,862			781,754			(33.6	)
	General and administrative		7,930			10,177			(22.1	)		37,446			50,279			(25.5	)
	Restructuring		-			1,993			(100.0	)		3,040			10,909			(72.1	)
Adjusted EBITDA (2)			86,351			131,330			(34.2	)		296,651			535,394			(44.6	)
	Depreciation		90,671			113,594			(20.2	)		348,005			439,261			(20.8	)
	Loss on asset decommissioning		-			165,109			(100.0	)		-			165,109			(100.0	)
	Impairment of property, plant and equipment		-			202,414			(100.0	)		-			202,414			(100.0	)
Operating loss (2)			(4,320	)		(349,787	)		(98.8	)		(51,354	)		(271,390	)		(81.1	)
Operating loss as a percentage of revenue			(1.7%	)		(114.2%	)					(6.0%	)		(19.7%	)

(1)	Certain expenses in the prior year have been reclassified to conform to current year presentation.
(2)	See "ADDITIONAL GAAP MEASURES".

		Three months ended December 31,
Canadian onshore drilling statistics: (1)		2016				2015
		Precision		Industry (2)		Precision		Industry (2)
Number of drilling rigs (end of period)		135		668		134		717
Drilling rig operating days (spud to release)		4,090		14,281		3,768		14,442
Drilling rig operating day utilization		33%		23%		23%		20%
Number of wells drilled		355		1,473		281		1,249
Average days per well		11.5		9.7		13.4		11.6
Number of metres drilled (000s)		932		4,023		783		3,214
Average metres per well		2,625		2,731		2,787		2,573
Average metres per day		228		282		208		223
		Year ended December 31,
Canadian onshore drilling statistics: (1)		2016				2015
		Precision		Industry (2)		Precision		Industry (2)
Number of drilling rigs (end of period)		135		668		134		721
Drilling rig operating days (spud to release)		11,273		42,391		15,399		64,880
Drilling rig operating day utilization		22%		17%		24%		23%
Number of wells drilled		962		3,963		1,351		5,241
Average days per well		11.7		10.7		11.4		12.4
Number of metres drilled (000s)		2,548		10,351		3,224		13,474
Average metres per well		2,649		2,612		2,386		2,571
Average metres per day		226		244		209		208

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

United States onshore drilling statistics: (1)			2016				2015
			Precision		Industry (2)		Precision		Industry (2)
Average number of active land rigs for quarters ended:
	March 31		32		516		80		1,353
	June 30		24		397		57		873
	September 30		29		465		51		829
	December 31		39		567		45		720
Year to date average			31		486		58		944

(1)	United States lower 48 operations only.
(2)	Baker Hughes rig counts.

Revenue from Contract Drilling Services was $255 million this quarter, or 17% lower than the fourth quarter of 2015, while adjusted EBITDA decreased by 34% to $86 million. The decreases were mainly due to lower drilling rig utilization days in our U.S. and international contract drilling businesses along with a decrease in average day rates in our Canadian and U.S. contract drilling businesses.

Drilling rig utilization days in Canada (drilling days plus move days) were 4,672 during the fourth quarter of 2016, an increase of 12% compared with 2015 primarily due to the increase in industry activity resulting from higher commodity prices. Drilling rig utilization days in the U.S. were 3,570 or 13% lower than the same quarter of 2015 as our U.S. activity was down as improved commodity prices have not yet returned industry activity to prior year levels. Drilling rig utilization days in our international business were 742 or 10% lower than the same quarter of 2015 due to lower activity in Mexico partially offset by the addition of two rigs in Kuwait during the current quarter.

Compared with the same quarter in 2015, drilling rig revenue per utilization day was down 22% in Canada due to the decline of spot market rates as the drop in industry activity has led to a more competitive pricing environment. Drilling rig revenue per utilization day for the quarter in the U.S. was down 15% from the prior comparative period, while international revenue per day was up 13%. The decrease in the U.S. average rate was due to lower spot market rates and lower relative idle but contracted revenue. International revenue per day was up due to rig mix with a higher proportion of days from Kuwait during the quarter and lower activity in Mexico.

In Canada, 35% of utilization days in the quarter were generated from rigs under term contract, compared with 53% in the fourth quarter of 2015. In the U.S., 56% of utilization days were generated from rigs under term contract as compared with 64% in the fourth quarter of 2015. At the end of the quarter, we had 27 drilling rigs under contract in Canada, 25 in the U.S. and eight internationally.

Operating costs were 63% of revenue for the quarter, which was ten percentage points higher than the prior year period. On a per utilization day basis, operating costs for the drilling rig division in Canada were lower than the prior year period primarily because of 2015 rig move costs and the impact of fixed costs on higher activity. In the U.S., operating costs for the quarter on a per day basis were higher than the prior year primarily due to the impact of fixed costs spread over lower activity. Both Canada and U.S. operating costs benefited from cost saving initiatives taken in 2015 and 2016.

General and administrative costs are lower than the prior year by $2 million due to cost saving initiatives taken throughout 2015 and 2016.

Depreciation expense in the quarter was 20% lower than in the fourth quarter of 2015 because of a lower asset base after decommissioning equipment and the recording of an impairment charge to our property, plant and equipment in the fourth quarter of 2015 partially offset by new-build rigs deployed in 2015 and 2016.

SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES

			Three months ended December 31,									Year ended December 31,
(Stated in thousands of Canadian dollars, except where noted)			2016			2015			% Change			2016			2015			% Change
Revenue			30,706			41,685			(26.3	)		100,049			186,317			(46.3	)
Expenses: (1)
	Operating		28,465			37,523			(24.1	)		93,070			161,968			(42.5	)
	General and administrative		1,851			2,760			(32.9	)		8,607			10,476			(17.8	)
	Restructuring		-			1,820			(100.0	)		2,021			3,634			(44.4	)
Adjusted EBITDA (2)			390			(418	)		(193.3	)		(3,649	)		10,239			(135.6	)
	Depreciation		8,735			6,218			40.5			29,272			32,396			(9.6	)
	Gain on re-measurement of property, plant and equipment		(7,605	)		-			n/m			(7,605	)		-			n/m
	Loss on asset decommissioning		-			1,377			(100.0	)		-			1,377			(100.0	)
	Impairment of property, plant and equipment		-			-			-			-			79,573			(100.0	)
Operating loss (2)			(740	)		(8,013	)		(90.8	)		(25,316	)		(103,107	)		(75.4	)
Operating loss as a percentage of revenue			(2.4%	)		(19.2%	)					(25.3%	)		(55.3%	)
Well servicing statistics:
	Number of service rigs (end of period)		207			163			27.0			207			163			27.0
	Service rig operating hours		33,170			36,526			(9.2	)		99,451			149,574			(33.5	)
	Service rig operating hour utilization		21%			22%						17%			22%

(1)	Certain expenses in the prior year have been reclassified to conform to current year presentation.
(2)	See "ADDITIONAL GAAP MEASURES".
	n/m calculation not meaningful

Revenue from Completion and Production Services was down $11 million or 26% compared with the fourth quarter of 2015 due to lower activity levels in all service lines, except our rentals business, and lower average rates. In response to lower oil prices, customers curtailed spending and activity including well completion and production programs through the majority of 2016. Our well servicing activity in the quarter was down 9% from the fourth quarter of 2015. Approximately 78% of our fourth quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 88% of its revenue from Canadian and 12% from U.S. operations compared the fourth quarter of 2015 of 87% from Canada and 13% from U.S. operations.

Average service rig revenue per operating hour in the quarter was $629 or $131 lower than the fourth quarter of 2015. The decrease was primarily the result of industry pricing pressure.

Adjusted EBITDA was $1 million higher than the fourth quarter of 2015 as cost cutting initiatives have reduced the cost structure partially offset by lower activity and rates.

Operating costs as a percentage of revenue increased to 93% in the fourth quarter of 2016, from 90% in the fourth quarter of 2015. The increase is the result of lower revenue from pricing pressure and the impact of fixed costs spread across lower activity levels.

Depreciation in the quarter was 40% higher than the fourth quarter of 2015 because of a change in estimate on the salvage value in our rentals division.

The gain in re-measurement of property, plant and equipment relates to the acquisition of 48 well service rigs and ancillary equipment in exchange for $12 million cash and our coil tubing assets. The total fair value of the assets acquired and consideration provided was $28 million. The book value of our coil tubing assets was $8 million and, we recorded a gain on re-measuring these assets of $8 million.

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 $22 million for the fourth quarter of 2016, $2 million higher than the prior year period as higher share based incentive compensation was partially offset by cost saving initiatives and restructuring costs incurred in the prior year.

OTHER ITEMS

Net finance charges were $42 million, $8 million higher than the fourth quarter of 2015 due to the early recognition of debt issue costs from the current quarter redemption of long-term debt and additional interest expense from the refinancing overlap period in the quarter partially offset by a reduction in interest expense related to debt retired during the year.

During the quarter we redeemed all $200 million of our 6.5% unsecured senior notes due 2019, redeemed on a pro rata basis US$250 million face value of our 6.625% unsecured senior notes due 2020 and repurchased and cancelled US$53 million face value of our 6.5% unsecured senior notes due 2021, incurring a net loss of $10 million.

Income tax expense for the quarter was a recovery of $51 million compared with a recovery of $146 million in the same quarter in 2015. Income tax expense is recognized by applying the income tax rate expected for the full financial year to the pre-tax income of the interim reporting period with adjustments for transactions specific to the quarter. The reduction in the income tax recovery over the prior year period is primarily because of the impact of the 2015 loss on asset decommissioning and impairment charges.

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

Liquidity

Subsequent to year end we agreed with our lending group to the following amendments to our senior credit facility:

• Reduce the Adjusted EBITDA (as defined in the debt agreement) to interest expense coverage ratio to greater than 1.25:1 for the periods ending March 31, June 30 and September 30, 2017. For the periods ending December 31, 2017 and March 31, 2018 the ratio is 1.5:1 reverting to 2.5:1 thereafter.
• Reduce the size of the facility to US$525 million.

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

• Permit second lien debt not to exceed US$400 million subject to certain terms and conditions;
• Amend certain negative covenants to, among other things, prohibit distributions during the covenant relief period;
• Add a new covenant with respect to anti-cash hoarding whereby we are only permitted to draw a maximum of $50 million on the facility if the only purpose is to accumulate cash;
• Add a new covenant that restricts the repurchase and redemption of unsecured debt subject to a pro-forma minimum liquidity of US$500 million.

During the year we have repurchased and cancelled US$28 million face value of our 6.625% unsecured senior notes due 2020 and US$81 million face value of our 6.5% unsecured senior notes due 2021 for a total of $135 million, realizing a total gain on repurchase of $10 million.

On November 4, 2016, we issued US$350 million of 7.75% unsecured senior notes due in 2023 in a private offering. The Notes are guaranteed on a senior unsecured basis by current and future U.S. and Canadian subsidiaries that also guarantee our senior credit facility and certain other indebtedness. The Notes were issued to redeem and repurchase existing debt.

On December 4, 2016 we redeemed in full our $200 million 6.5% unsecured senior notes due 2019 for $203 million plus accrued and unpaid interest and redeemed on a pro rata basis US$250 million of our then outstanding 6.625% unsecured senior notes due 2020 for US$256 million plus accrued and unpaid interest. Our total loss on redemption of unsecured senior notes was $10 million.

As at December 31, 2016 we had $1,934 million outstanding under our unsecured senior notes. The current blended cash interest cost of our debt is approximately 6.5%.

Amount		Availability		Used for		Maturity
Senior facility (secured)
US$550 million (1) (extendible, revolving term credit facility with US$250 million accordion feature)		Undrawn, except US$41 million in outstanding letters of credit		General corporate purposes		June 3, 2019
Operating facilities (secured)
$40 million		Undrawn, except $22 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$6 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)	Subsequent to December 31, 2016 we reduced our revolving term facility to US$525 million.

Covenants

Senior Facility

The senior credit facility requires that we comply with certain financial covenants including a leverage ratio of consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (Adjusted EBITDA) of less than 2.5:1. For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness. Adjusted EBITDA, as defined in our revolving term facility agreement differs from Adjusted EBITDA as defined under Additional GAAP Measures by the exclusion of bad debt expense, restructuring costs and certain foreign exchange amounts. As at December 31, 2016 our consolidated senior debt to Adjusted EBITDA ratio was negative 0.02:1.

Effective January 20, 2017, under the senior credit facility, we are required to maintain an Adjusted EBITDA coverage ratio, calculated as 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 December 31, 2016 our senior credit facility Adjusted EBITDA coverage ratio was 1.69:1.

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 December 31, 2016, we were in compliance with the covenants of the senior credit facility.

Senior Notes

The senior notes require that we comply with certain financial covenants including an incurrence based test of Adjusted EBITDA, as defined in the senior note agreements, to interest coverage ratio of greater than 2.0:1 for the most recent four consecutive fiscal quarters. In the event that our Adjusted EBITDA to interest coverage ratio is less than 2.0:1 for the most recent four consecutive fiscal quarters the senior notes restrict our ability to incur additional indebtedness. As at December 31, 2016, our senior notes Adjusted EBITDA to interest coverage ratio was 1.58:1 which limits our ability to incur additional indebtedness, except as permitted under the agreements, until such time as we are in compliance with the ratio test but would not restrict our access to available funds under the senior credit facility or 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 by, among other things, 50% of consolidated net earnings and decreases by 100% of consolidated net losses as defined in the note agreements, and payments made to shareholders. As at December 31, 2015 our 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 basket once again becomes positive. For further information, please see the senior note indentures which are available on SEDAR and EDGAR.

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

Hedge of investments in foreign operations

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

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

Average shares outstanding

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

		Three months ended December 31,				Year ended December 31,
		2016		2015		2016		2015
Weighted average shares outstanding - basic		293,239		292,912		293,133		292,878
Effect of stock options and other equity compensation plans		-		-		-		-
Weighted average shares outstanding - diluted		293,239		292,912		293,133		292,878

QUARTERLY FINANCIAL SUMMARY
(Stated in thousands of Canadian dollars, except per share amounts)
			2016
Quarters ended			March 31			June 30			September 30			December 31
Revenue			301,727			163,979			201,802			283,903
Adjusted EBITDA (1)			99,264			22,400			41,411			65,000
Net loss:			(19,883	)		(57,677	)		(47,377	)		(30,618	)
	Per basic share		(0.07	)		(0.20	)		(0.16	)		(0.10	)
	Per diluted share		(0.07	)		(0.20	)		(0.16	)		(0.10	)
Funds provided by (used in) operations (1)			93,593			(31,372	)		31,688			11,466
Cash provided by (used in) operations			112,174			20,665			17,515			(27,846	)

			2015
Quarters ended			March 31		June 30			September 30			December 31
Revenue			512,120		334,462			364,089			344,953
Adjusted EBITDA (1)			163,384		88,355			111,031			111,095
Net earnings (loss):			24,033		(29,817	)		(86,700	)		(270,952	)
	Per basic share		0.08		(0.10	)		(0.30	)		(0.93	)
	Per diluted share		0.08		(0.10	)		(0.30	)		(0.93	)
Funds provided by operations (1)			155,186		53,173			99,228			49,503
Cash provided by operations			215,138		169,877			61,049			70,952
Dividends paid per share			0.07		0.07			0.07			0.07

(1)	See "ADDITIONAL GAAP MEASURES".

ADDITIONAL GAAP MEASURES

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

Adjusted EBITDA

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

Operating Loss

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

Funds Provided By (Used In) Operations

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

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

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

• our strategic priorities for 2017;
• our capital expenditure plans for 2017;
• anticipated activity levels in 2017 and our scheduled infrastructure projects;
• anticipated demand for Tier 1 rigs;
• the average number of term contracts in place for 2017.

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

• the 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, 2015, which may be accessed on Precision's SEDAR profile at www.sedar.com or under Precision's EDGAR profile at www.sec.gov . The forward-looking information and statements contained in this news release are made as of the date hereof and Precision undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a results of new information, future events or otherwise, except as required by law.

INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)
(Stated in thousands of Canadian dollars)				December 31 , 2016				December 31, 2015
ASSETS
Current assets:
	Cash		$	115,705			$	444,759
	Accounts receivable			293,682				311,595
	Income tax recoverable			38,087				-
	Inventory			24,136				24,245
Total current assets				471,610				780,599
Non-current assets:
	Income tax recoverable			-				2,917
	Property, plant and equipment			3,641,889				3,883,332
	Intangibles			3,316				3,363
	Goodwill			207,399				208,479
Total non-current assets				3,852,604				4,098,091
Total assets			$	4,324,214			$	4,878,690
LIABILITIES AND EQUITY
Current liabilities:
	Accounts payable and accrued liabilities		$	240,736			$	235,948
	Income tax payable			-				7,836
Total current liabilities				240,736				243,784
Non-current liabilities:
	Share based compensation			27,387				15,201
	Provisions and other			12,421				14,520
	Long-term debt			1,906,934				2,180,510
	Deferred tax liabilities			174,618				303,466
Total non-current liabilities				2,121,360				2,513,697
Shareholders' equity:
	Shareholders' capital			2,319,293				2,316,321
	Contributed surplus			38,937				35,800
	Deficit			(552,568	)			(397,013	)
	Accumulated other comprehensive income			156,456				166,101
Total shareholders' equity				1,962,118				2,121,209
Total liabilities and shareholders' equity			$	4,324,214			$	4,878,690

INTERIM CONSOLIDATED STATEMENTS OF LOSS (UNAUDITED)
			Three months ended December 31,								Year ended December 31,
(Stated in thousands of Canadian dollars, except per share amounts)				2016				2015				2016				2015
Revenue			$	283,903			$	344,953			$	951,411			$	1,555,624
Expenses:
	Operating			187,381				197,291				607,295				934,693
	General and administrative			31,522				29,467				110,287				126,423
	Restructuring			-				7,100				5,754				20,643
Earnings before income taxes, loss 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				65,000				111,095				228,075				473,865
Depreciation and amortization				102,801				125,194				391,659				486,655
Gain on re-measurement of property, plant and equipment				(7,605	)			-				(7,605	)			-
Loss on asset decommissioning				-				166,486				-				166,486
Impairment of property, plant and equipment				-				202,414				-				281,987
Operating loss				(30,196	)			(382,999	)			(155,979	)			(461,263	)
Impairment of goodwill				-				149				-				17,117
Foreign exchange				(925	)			(653	)			6,008				(33,251	)
Finance charges				42,289				34,230				146,360				121,043
Loss on repurchase of unsecured senior notes				10,220				-				239				-
Loss before income taxes				(81,780	)			(416,725	)			(308,586	)			(566,172	)
Income taxes:
	Current			(6,837	)			2,942				(31,195	)			11,276
	Deferred			(44,325	)			(148,715	)			(121,836	)			(214,012	)
				(51,162	)			(145,773	)			(153,031	)			(202,736	)
Net loss			$	(30,618	)		$	(270,952	)		$	(155,555	)		$	(363,436	)
Net loss per share:
Basic			$	(0.10	)		$	(0.93	)		$	(0.53	)		$	(1.24	)
Diluted			$	(0.10	)		$	(0.93	)		$	(0.53	)		$	(1.24	)

INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)
		Three months ended December 31,								Year ended December 31,
(Stated in thousands of Canadian dollars)			2016				2015				2016				2015
Net loss		$	(30,618	)		$	(270,952	)		$	(155,555	)		$	(363,436	)
Unrealized gain (loss) on translation of assets and liabilities of operations denominated in foreign currency			53,488				96,781				(76,608	)			444,464
Foreign exchange gain (loss) on net investment hedge with U.S. denominated debt, net of tax			(37,570	)			(64,670	)			66,963				(324,655	)
Comprehensive loss		$	(14,700	)		$	(238,841	)		$	(165,200	)		$	(243,627	)

INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)
				Three months ended December 31,								Year ended December 31,
(Stated in thousands of Canadian dollars)					2016				2015				2016				2015
Cash provided by (used in):
Operations:
	Net loss			$	(30,618	)		$	(270,952	)		$	(155,555	)		$	(363,436	)
	Adjustments for:
		Long-term compensation plans			12,241				4,978				28,313				15,594
		Depreciation and amortization			102,801				125,194				391,659				486,655
		Gain on re-measurement of property, plant and equipment			(7,605	)			-				(7,605	)			-
		Loss on asset decommissioning			-				166,486				-				166,486
		Impairment of property, plant and equipment			-				202,414				-				281,987
		Impairment of goodwill			-				149				-				17,117
		Foreign exchange			(2,183	)			(2,797	)			6,791				(36,994	)
		Finance charges			42,289				34,230				146,360				121,043
		Loss on repurchase of unsecured senior notes			10,220				-				239				-
		Income taxes			(51,162	)			(145,773	)			(153,031	)			(202,736	)
		Other			(2,454	)			(5,699	)			(1,889	)			(4,408	)
		Income taxes paid			(1,518	)			(2,374	)			(14,605	)			(13,560	)
		Income taxes recovered			192				659				795				1,770
		Interest paid			(61,381	)			(59,632	)			(139,575	)			(130,325	)
		Interest received			644				2,620				3,478				17,897
Funds provided by operations					11,466				49,503				105,375				357,090
Changes in non-cash working capital balances					(39,312	)			21,449				17,133				159,926
					(27,846	)			70,952				122,508				517,016
Investments:
	Business acquisition				(12,200	)			-				(12,200	)			-
	Purchase of property, plant and equipment				(44,725	)			(66,251	)			(203,472	)			(458,710	)
	Proceeds on sale of property, plant and equipment				2,010				2,227				7,840				9,786
	Income taxes recovered				-				-				2,917				55,138
	Changes in non-cash working capital balances				880				10,945				(9,010	)			(147,316	)
					(54,035	)			(53,079	)			(213,925	)			(541,102	)
Financing:
	Repurchase of unsecured senior notes				(613,379	)			-				(677,704	)			-
	Debt issue costs				(10,752	)			(1,159	)			(11,966	)			(2,134	)
	Dividends paid				-				(20,504	)			-				(82,003	)
	Increase in long-term debt				469,420				-				469,420				-
	Issuance of common shares on the exercise of options				-				-				1,926				93
					(154,711	)			(21,663	)			(218,324	)			(84,044	)
Effect of exchange rate changes on cash and cash equivalents					103				9,676				(19,313	)			61,408
Increase (decrease) in cash and cash equivalents					(236,489	)			5,886				(329,054	)			(46,722	)
Cash and cash equivalents, beginning of period					352,194				438,873				444,759				491,481
Cash and cash equivalents, end of period				$	115,705			$	444,759			$	115,705			$	444,759

INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (UNAUDITED)
(Stated in thousands of Canadian dollars)		Shareholders' capital			Contributed surplus				Accumulated other comprehensive income				Deficit				Total equity
Balance at January 1, 2016		$	2,316,321		$	35,800			$	166,101			$	(397,013	)		$	2,121,209
Net loss for the period			-			-				-				(155,555	)			(155,555	)
Other comprehensive loss for the period			-			-				(9,645	)			-				(9,645	)
Share options exercised			2,972			(1,046	)			-				-				1,926
Share based compensation expense			-			4,183				-				-				4,183
Balance at December 31, 2016		$	2,319,293		$	38,937			$	156,456			$	(552,568	)		$	1,962,118
(Stated in thousands of Canadian dollars)		Shareholders' capital			Contributed surplus				Accumulated other comprehensive income				Retained earnings (deficit)				Total equity
Balance at January 1, 2015		$	2,315,539		$	31,109			$	46,292			$	48,426			$	2,441,366
Net loss for the period			-			-				-				(363,436	)			(363,436	)
Other comprehensive income for the period			-			-				119,809				-				119,809
Dividends			-			-				-				(82,003	)			(82,003	)
Share options exercised			142			(49	)			-				-				93
Shares issued on redemption of non-management directors' DSUs			640			(324	)			-				-				316
Share based compensation expense			-			5,064				-				-				5,064
Balance at December 31, 2015		$	2,316,321		$	35,800			$	166,101			$	(397,013	)		$	2,121,209

FOURTH QUARTER 2016 EARNINGS CONFERENCE CALL AND WEBCAST

Precision Drilling Corporation has scheduled a conference call and webcast to begin promptly at 12:00 p.m. MT (2:00 p.m. ET) on Thursday, February 9, 2017.

The conference call dial in numbers are 1-844-515-9176 or 614-999-9312.

A live webcast of the conference call will be accessible on Precision's website at www.precisiondrilling.com by selecting "Investor Centre", then "Webcasts and Presentations".

An archived version of the webcast will be available for approximately 60 days. An archived recording of the conference call will be available approximately one hour after the completion of the call until February 11, 2017 by dialing 855-859-2056 or 404-537-3406, passcode 57747163.

About Precision

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

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