Exhibit 99.1

NEWS RELEASE

Calgary, Alberta, Canada – February 11, 2016

(Canadian dollars except as indicated)

PRECISION DRILLING CORPORATION

ANNOUNCES 2015 FOURTH QUARTER FINANCIAL RESULTS

 ADDITIONAL ANNOUNCEMENTS INCLUDE COMPLETED TRANSFORMATION

TO TIER 1 FLEET AND STEPS TO FURTHER STRENGTHEN LIQUIDITY POSITION,

INCLUDING SUSPENSION OF DIVIDENDS

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 2015, we recorded earnings before income taxes, finance charges, foreign exchange, impairment of goodwill, impairment of property, plant and equipment, loss on asset decommissioning and depreciation and amortization (adjusted EBITDA see "Additional GAAP Measures") of $111 million or 53% lower than the fourth quarter of 2014. Our activity for the quarter, as measured by drilling rig utilization days, decreased 51% in Canada, 55% in the U.S. and 23% internationally, compared to the fourth quarter of 2014. Our adjusted EBITDA as a percentage of revenue was 32% this quarter, compared to 38% in the fourth quarter of 2014. The decrease in adjusted EBITDA as a percentage of revenue was mainly due to a decrease in activity and profitability in our Contract Drilling Services and Completion and Production Services segments and restructuring costs incurred in the current quarter.

Cash provided by operations for the quarter was $71 million, which was 47% lower than the fourth quarter of 2014 as lower operating earnings were partially offset by a reduction in working capital.

Precision substantially reduced capital spending during the fourth quarter with permanent reductions that strengthened our cash position and total liquidity.   We concluded 2015 with $459 million in capital expenditures, a decrease of $72 million compared to the $531 million capital plan that we announced in October 2015.  The decrease was due to $50 million of capital cancelled as a result of lower activity and $34 million of capital deferred to 2016, partially offset by $12 million in foreign exchange impacts.  Planned capital expenditures for 2016 are now $202 million, up from the third quarter 2015 press release of $180 million due to the above-mentioned $34 million in capital carried forward from 2015 and foreign exchange impacts of $19 million, offset by an additional $31 million in cancelled capital.  The 2016 capital includes expenditures to complete the two international new-build rigs announced in 2015 that will be completed in early 2017.  One new-build rig scheduled for customer delivery in 2015 was deferred to the first quarter of 2016 and has now been delivered. A portion of the 2016 capital plan is utilization based and if activity levels increase or decline, Precision has the ability to adjust the plan accordingly.

Effective immediately, Precision is suspending its dividend and believes the suspension will further strengthen liquidity during a challenging and extended industry downturn.

We recorded a net loss this quarter of $271 million, or net loss per diluted share of $0.93, compared to a net loss of $114 million, or $0.39 per diluted share, in the fourth quarter of 2014.  We incurred asset decommissioning and impairment charges totaling $369 million that, after-tax, reduced net earnings by $254 million and net earnings per diluted share by $0.87.

Revenue this quarter was $345 million or 44% lower than the fourth quarter of 2014, mainly due to lower drilling activity in the U.S., Canada and internationally.  Revenue from our Contract Drilling Services and Completion and Production Services segments both decreased over the comparative prior year period by 42% and 53%, respectively.

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For the year ended December 31, 2015, net loss was $363 million, or $1.24 per diluted share, compared to net earnings of $33 million, or $0.11 per diluted share in 2014, while revenue was $1.6 billion, or 34% less than in 2014. During the year we recorded asset decommissioning, and asset impairment charges totaling $466 million that after-tax reduced net earnings by $329 million and net earnings per diluted share by $1.12.

Kevin Neveu, Precision's President and Chief Executive Officer, stated: "During the fourth quarter Precision delivered stronger than expected cash flows and improved the company's liquidity and financial position despite intensifying market headwinds. The land drilling industry is almost a year and a half into a deep downturn, a result of lower commodity prices pushing customer spending down and decreasing drilling demand.  There is limited visibility with few positive market signals.  In this protracted challenging environment, financial stability is paramount for both survival and sustaining competitive advantage."

"The organization's focus on cost reduction, safe and efficient field operations supported by our robust contract position resulted in continued strong operating margins and the benefits of the resulting cash flows are reflected on our year-end balance sheet.  With a cash balance of $445 million and ample capacity in our revolving credit facility, Precision's liquidity position ensures we can perform through an extended downturn. The dividend suspension, while a result of a debt covenant restriction, further strengthens the balance sheet as we continue to maneuver through uncharted waters."

"Our decision to accelerate our transformation to a Tier 1 driller by retiring and fully writing down the value of our legacy rigs is directly tied to our long-term High Performance, High Value strategy.  This transformation has been completed over a number of years, beginning in 2009 when Precision had 93 Tier 1 rigs, representing 25% of our fleet.  After a six-year Super Series new-build program and the cumulative decommissioning of 236 legacy rigs, Precision's fleet consists of 238 Tier 1 rigs.  These Super Series rigs are configured for pad-type resource development and are designed for maximum efficiency with mechanized pipe handling, digital drilling controls and available with bi-directional pad walking systems."

"Despite the current market conditions, I am encouraged by our gains in market share and strong operating performance, including our all-time best safety performance and record low unplanned downtime, all of which reinforce our long-term High Performance strategy.  Today we are operating 57 rigs in Canada, 32 in the U.S. and nine rigs internationally.  With the majority of these rigs under term contract, our margins are holding up well. However, in a market where incremental opportunities are limited, dayrates can be expected to trend lower, which we plan to partially offset by ongoing cost reduction initiatives."

"Strict capital discipline remains the core focus for our management team.  Sustaining cash and reducing operating and capital costs are Precision's top priority for the foreseeable future.  Above all, our achievements in the current environment would not have been possible without the hard work and dedication of our employees in the field and office. I am proud to be a member of the Precision family and look forward to overcoming a challenging market this year," concluded Mr. Neveu.

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SELECT FINANCIAL AND OPERATING INFORMATION

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

Financial Highlights

	Three months ended December 31,									Year ended December 31,
(Stated in thousands of Canadian dollars, except per share amounts)	2015			2014			% Change			2015			2014			% Change
Revenue		344,953			618,525			(44.2	)		1,555,624			2,350,538			(33.8	)
Adjusted EBITDA		111,095			234,011			(52.5	)		473,865			800,370			(40.8	)
Adjusted EBITDA  % of revenue		32.2	%		37.8	%					30.5	%		34.1	%
Net earnings (loss)		(270,952	)		(114,044	)		137.6			(363,436	)		33,152			(1,196.3	)
Cash provided by operations		70,952			134,887			(47.4	)		517,016			680,159			(24.0	)
Funds provided by operations		49,503			172,059			(71.2	)		357,090			697,474			(48.8	)
Capital spending:
Expansion		39,386			235,636			(83.3	)		361,425			571,383			(36.7	)
Upgrade		6,342			42,529			(85.1	)		48,487			136,475			(64.5	)
Maintenance and infrastructure		20,523			60,085			(65.8	)		48,798			148,832			(67.2	)
Proceeds on sale(1)		(2,227	)		(53,304	)		(95.8	)		(9,786	)		(101,826	)		(90.4	)
Net capital spending		64,024			284,946			(77.5	)		448,924			754,864			(40.5	)
Earnings (loss) per share:
Basic		(0.93	)		(0.39	)		138.5			(1.24	)		0.11			(1,227.3	)
Diluted		(0.93	)		(0.39	)		138.5			(1.24	)		0.11			(1,227.3	)
Dividends paid per share		0.07			0.07			-			0.28			0.25			12.0

(1) For the three months ended December 31, 2014 includes proceeds of $44 million from the disposal of our U.S. coil tubing assets and for the year ended 2014. Also includes proceeds of $26 million from the disposal in the third quarter of 2014 of certain trucks and other related assets used to support drilling rig moves in Texas and New Mexico.

Operating Highlights

	Three months ended December 31,							Year ended December 31,
	2015		2014		% Change			2015		2014		% Change
Contract drilling rig fleet		251		313		(19.8	)		251		313		(19.8	)
Drilling rig utilization days:         Canada		4,176		8,550		(51.2	)		17,238		32,810		(47.5	)
U.S.		4,109		9,214		(55.4	)		21,172		35,075		(39.6	)
International		822		1,072		(23.3	)		4,084		4,036		1.2
Service rig fleet		163		177		(7.9	)		163		177		(7.9	)
Service rig operating hours		36,526		70,350		(48.1	)		149,574		273,194		(45.2	)

Financial Position

(Stated in thousands of Canadian dollars, except ratios)	December 31, 2015		December 31, 2014
Working capital		536,815		653,630
Long-term debt(1)		2,180,510		1,852,186
Total long-term financial liabilities		2,210,231		1,881,275
Total assets		4,878,690		5,308,996
Long-term debt to long-term debt plus equity ratio(1)		0.51		0.43

(1) Net of unamortized debt issue costs.

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

Precision's strategic priorities for 2016 are as follows:

1. Maintain strong liquidity to manage through an extended downturn – Sustain adequate liquidity by generating positive operating cash flow, ensuring full access to the revolving credit facility, and begin a multi-year plan for net debt reduction.

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.

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:

a. 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.

b. 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.

c. Ample liquidity–maintain strong liquidity to fund working capital requirements and other short term commitments that arise when activity levels increase.

Crude oil prices have decreased significantly since the third quarter of 2014, reducing our customers' cash flows and resulting in a decrease in capital budgets.  This decrease has significantly impacted our activity and resulting cash flow.  During the fourth quarter of 2015, we evaluated our fleet of equipment and decided to decommission older, lower tiered equipment due to the high cost to maintain, low demand and highly competitive market.  The asset decommissioning charge of $166 million is associated with 79 drilling rigs, including 30 rigs in the U.S., 48 rigs in Canada, and one international rig.  The drop in oil prices and the number of new-build drilling rigs that entered the market are expected to effectively render legacy assets obsolete. After the rig decommissioning and delivery of two additional rigs for Kuwait in 2017, Precision will have 238 Tier 1 drilling rigs and 16 additional rigs that are good candidates to be upgraded to Tier 1 status. Our drilling rig fleet includes 102 drilling rigs in the U.S., 135 in Canada and 17 internationally.  Two additional rigs for Kuwait are expected to be delivered early in 2017.

Under International Financial Reporting Standards, we are required to assess the carrying value of assets in our cash generating units (CGUs) containing goodwill annually and when indicators of impairment exist.  As a result of continued low commodity prices and their impact on current and future industry activity, we completed an impairment test for all of our CGUs as at December 31, 2015.  The test involves determining a value in use based on a multi-year discounted cash flow using assumptions on expected future results.  The resulting value in use is then compared to the carrying value of the CGU.  As a result of these tests it was determined that property, plant and equipment in our U.S. contract drilling business were impaired by US$73 million and property, plant and equipment in our international contract drilling business were impaired by US$75 million.

As a result of similar tests during the third quarter of 2015, it was determined that property, plant and equipment in our Canadian well service business were impaired by $73 million and property, plant and equipment in our U.S. completion and production business were impaired by $7 million.  In addition, goodwill associated with our rentals cash generating unit was impaired for its full value of $17 million.  These impairment adjustments were reflected in our third quarter 2015 financial statements.

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For the fourth quarter of 2015, the average West Texas Intermediate price of oil was 42% lower than the fourth quarter of 2014 average while Henry Hub natural gas price was 45% lower.

	Three months ended December 31,				Year ended December 31,
	2015		2014		2015		2014
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$)		42.04		72.99		48.77		93.06
Natural gas
Canada
AECO (per MMBtu) (Cdn$)		2.47		3.61		2.70		4.45
U.S.
Henry Hub (per MMBtu) (US$)		2.08		3.75		2.60		4.33

Summary for the three months ended December 31, 2015:

•Operating loss (see "Additional GAAP Measures" in this news release) this quarter of $383 million is a decrease of $361 million from the fourth quarter 2014 operating loss of $22 million.  Operating results were negatively affected by the impairment of property, plant and equipment, the decommissioning of drilling rigs and the decrease in activity in all our operating segments.  Excluding the decommissioning and asset impairment charges, operating loss was $14 million, compared to operating earnings of $105 million in 2014.

•General and administrative expenses this quarter were $33 million, $7 million higher than the fourth quarter of 2014.  The increase is due to a significant drop in our share price in the fourth quarter of 2014 and the impact this drop had on share based incentive compensation that is tied to the price of our common shares, and the negative impact of a weakening Canadian dollar on U.S. dollar denominated costs, partially offset by efforts in reducing overhead through the down cycle.

•Restructuring costs were $7 million in the quarter and were primarily related to severance costs associated with right-sizing the operations and administrative support for current activity levels.

•During the quarter, we evaluated our fleet of equipment and decommissioned older, lower tiered equipment due to the high cost to maintain, low demand and highly competitive market.  The asset decommissioning resulted in a pre-tax charge of $166 million.

•Under International Financial Reporting Standards, we are required to assess the carrying value of our assets in CGU's when indicators of impairment exist. Due to the decrease in oil and natural gas well drilling and the outlook for pricing, we recognized a pre-tax $203 million asset impairment charge in the quarter attributable to our Contract Drilling segment.

•Net finance charges were $34 million, an increase of $4 million compared with the fourth quarter of 2014 due to the impact of foreign exchange on our U.S. dollar denominated interest and increased amortization on debt issue costs.

•Average revenue per utilization day for contract drilling rigs increased in the fourth quarter of 2015 to $25,589 from the prior year fourth quarter of $22,648 in Canada and increased in the U.S. to US$24,498 from US$24,118.  The increase in revenue rates for Canada and the U.S. is primarily due to a higher percentage of activity from drilling rigs under term contract in both regions and payments from customers for contracted shortfalls in Canada and idle but contracted rigs in the U.S.   We had no turnkey revenue for the fourth quarter of 2015 compared with US$11 million in the 2014 comparative period.  Within the Completion and Production Services segment, the average hourly rate for service rigs was $760 in the fourth quarter of 2015 compared to $896 in the fourth quarter of 2014.  The decrease in the average hourly rate is the result of weakened demand from customers in all of our operating regions.

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•Average operating costs per utilization day for drilling rigs decreased in the fourth quarter of 2015 to $10,312 from the prior year fourth quarter of $10,670 in Canada and increased in the U.S. to US$13,593 in 2015 from US$13,522 in 2014.  The cost decrease in Canada was primarily due to labour rate decreases and overhead cost reduction initiatives.  The nominal cost increase in the U.S. was primarily due to fixed costs spread across lower activity, partially offset by lower costs associated with having no turnkey activity.

• We realized revenue from international contract drilling of $51 million in the fourth quarter of 2015, in-line with the prior year comparative quarter. Decreased activity in the Northern region of Iraq was offset by increased activity in Kuwait.

•Directional drilling services realized revenue of $13 million in the fourth quarter of 2015 compared with $31 million in the prior year period.  The decrease was primarily the result of a decline in activity in the U.S. and Canada.

•Funds provided by operations (see "Additional GAAP Measures") in the fourth quarter of 2015 were $50 million, a decrease of $122 million from the prior year comparative quarter of $172 million.  The decrease was primarily the result of lower activity levels.

•Capital expenditures for the purchase of property, plant and equipment were $66 million in the fourth quarter, a decrease of $272 million over the same period in 2014.  Capital spending for the fourth quarter of 2015 included $39 million for expansion capital, $6 million for upgrade capital and $21 million for the maintenance of existing assets and infrastructure spending.

Summary for the year ended December 31, 2015:

•Revenue for 2015 was $1,556 million, a decrease of 34% from 2014.

•Operating loss was $461 million, a decrease of $686 million from operating earnings of $225 million in 2014.  Operating results were negatively impacted by the impairment of property, plant and equipment; the decommissioning of certain drilling rigs and spare equipment; the decrease in activity in our North American operating segments; and depreciation from capital asset additions in 2015 and 2014.

• General and administrative costs were $137 million, a decrease of $8 million from 2014 primarily as a result of cost saving initiatives and a decrease in incentive compensation costs tied to the performance of Precision's common shares in 2015 partially offset by higher costs from a weakening Canadian dollar on the U.S. dollar denominated costs of our foreign operations.

•Restructuring costs of $21 million were primarily related to severance costs associated with right-sizing the operations and administrative support for current activity levels.

•Under International Financial Reporting Standards, we are required to assess the carrying value of our assets in cash generating units when indicators of impairment exist.  Due to the decrease in oil and natural gas well drilling in North America and the outlook for future activity, in 2015 we recognized $282 million impairment of property, plant and equipment and a goodwill impairment charge of $17 million associated with our rentals division.  In addition, we incurred asset decommissioning charges of $166 million for the year.

•Net finance charges were $121 million in 2015, an increase of $11 million from 2014 due to the issuance of US$400 million of 5.25% Senior Notes on June 3, 2014 and the effect of the weakening Canadian dollar on our U.S. dollar denominated interest partially offset by $14 million in interest revenue related to the settlement of an income tax dispute.

•Funds provided by operations (see "Additional GAAP Measures") in 2015 were $357 million, a decrease of $340 million from 2014.

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•We realized revenue from international contract drilling of $226 million in 2015, a $31 million increase over 2014 due to expansion in the Middle East with three new-build rigs deployed in 2014 and one in 2015.

•Directional drilling services realized revenue of $45 million in 2015, a decrease of $79 million from 2014.

•Capital expenditures for the purchase of property, plant and equipment were $459 million in 2015, a decrease of $398 million over 2014.  Capital spending for 2015 included $361 million for expansion capital, $49 million for upgrade capital and $49 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 and, as of February 10, 2016, we had term contracts in place for an average of 36 rigs in Canada, 25 in the U.S. and nine internationally for the first quarter of 2016, an average of 31 rig contracts in Canada, 21 in the U.S. and eight internationally for the full year in 2016, and an average of 30 rigs for the full year in 2017. In Canada, term contracted rigs normally generate 250 utilization days per year because of the seasonal nature of well site access.  In most regions in the U.S. and internationally, term contracts normally generate 365 utilization days per year.

Drilling Activity

In the U.S., our average active rig count in the fourth quarter was 45 rigs, down 55 rigs over the fourth quarter in 2014 and down 6 rigs over the third quarter of 2015.  We currently have 32 rigs active in the United States.

In Canada, our average active rig count in the fourth quarter was 45 rigs, a decrease of 48 rigs over the fourth quarter in 2014 and down four rigs over the third quarter of 2015. We currently have 57 rigs active in Canada.

In general, we expect lower drilling activity levels and pricing pressure on spot market rigs in North America as lower oil prices have caused producers to significantly reduce drilling budgets.  We expect Tier 1 rigs to remain the preferred rigs of customers globally and for us to benefit from our completed fleet enhancements.

Internationally, our average active rig count in the quarter was nine rigs, a decrease of two rigs over the fourth quarter in 2014 and down two rigs over the third quarter of 2015.  We currently have nine active rigs internationally.

Industry Conditions

During 2015, seasonally adjusted drilling activity consistently decreased in both Canada and the U.S.  According to industry sources, as of February 5, 2016, the U.S. active land drilling rig count was down approximately 61% from the same point last year and the Canadian active land drilling rig count was down approximately 36%.

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 bias towards oil-directed drilling in the U.S. continues. For the 2015 year, approximately 45% of the Canadian industry's active rigs and 77% of the U.S. industry's active rigs were drilling for oil targets, compared to 57% for Canada and 82% for the U.S. in 2014.

Capital Spending

Capital spending in 2016 is expected to be $202 million and includes: $156 million for expansion capital; $44 million for sustaining and infrastructure expenditures; and $2 million to upgrade existing rigs. We expect that the $202 million will be split $197 million in the Contract Drilling segment and $5 million in the Completion and Production Services segment.  The expansion capital plan for 2016 includes the construction of two new-build drilling rigs to be delivered early in 2017 for our customer in Kuwait. Precision's sustaining and infrastructure capital plan is based upon currently anticipated activity levels for 2016.

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SEGMENTED FINANCIAL RESULTS

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

	Three months ended December 31,									Year ended December 31,
(Stated in thousands of Canadian dollars)	2015			2014			% Change			2015			2014			% Change
Revenue:
Contract Drilling Services		306,261			531,710			(42.4	)		1,378,336			2,017,110			(31.7	)
Completion and Production Services		41,685			89,444			(53.4	)		186,317			343,556			(45.8	)
Inter-segment eliminations		(2,993	)		(2,629	)		13.8			(9,029	)		(10,128	)		(10.9	)
		344,953			618,525			(44.2	)		1,555,624			2,350,538			(33.8	)
Adjusted EBITDA:(1)
Contract Drilling Services		133,611			232,436			(42.5	)		546,720			821,490			(33.4	)
Completion and Production Services		(418	)		16,014			(102.6	)		10,239			57,954			(82.3	)
Corporate and other		(22,098	)		(14,439	)		53.0			(83,094	)		(79,074	)		5.1
		111,095			234,011			(52.5	)		473,865			800,370			(40.8	)

 (1) See "ADDITIONAL GAAP MEASURES".

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

(Stated in thousands of Canadian dollars, except where noted)	Three months ended December 31									Year ended December 31,
	2015			2014			% Change			2015			2014			% Change
Revenue		306,261			531,710			(42.4	)		1,378,336			2,017,110			(31.7	)
Expenses:
Operating		160,546			291,308			(44.9	)		777,280			1,147,826			(32.3	)
General and administrative		10,111			7,966			26.9			43,427			47,794			(9.1	)
Restructuring		1,993			-			n/	m		10,909			-			n/	m
Adjusted EBITDA(1)		133,611			232,436			(42.5	)		546,720			821,490			(33.4	)
Depreciation		113,594			102,371			11.0			439,261			381,465			15.2
Loss on asset decommissioning		165,109			97,947			68.6			165,109			97,947			68.6
Impairment of property, plant and   equipment		202,414			-			n/	m		202,414			-			n/	m
Operating earnings (loss)(1)		(347,506	)		32,118			(1,182.0	)		(260,064	)		342,078			(176.0	)
Operating earnings (loss) as a percentage ofrevenue		(113.5	%)		6.0	%					(18.9	%)		17.0	%
Drilling rig revenue per utilization day inCanada		25,589			22,648			13.0			23,670			22,250			6.4
Drilling rig revenue per utilization day inthe U.S.(2) (US$)		24,498			24,118			1.6			25,901			24,330			6.5
Drilling rig revenue per utilization dayinternational (US$)		46,767			42,485			10.1			43,491			43,885			(0.9	)

(1) See "ADDITIONAL GAAP MEASURES".

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

n/m – calculation not meaningful

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	Three months ended December 31,
Canadian onshore drilling statistics:(1)	2015						2014
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		134			717			174			797
Drilling rig operating days (spud to release)		3,768			14,442			7,567			33,741
Drilling rig operating day utilization		23	%		20	%		43	%		45	%
Number of wells drilled		281			1,249			919			3,009
Average days per well		13.4			11.6			8.2			11.2
Number of metres drilled (000s)		783			3,214			1,643			6,746
Average metres per well		2,787			2,573			1,788			2,242
Average metres per day		208			223			217			200

	Year ended December 31,
Canadian onshore drilling statistics:(1)	2015						2014
	Precision			Industry(2)			Precision			Industry(2)
Number of drilling rigs (end of period)		134			721			174			797
Drilling rig operating days (spud to release)		15,399			64,880			29,093			131,021
Drilling rig operating day utilization		24	%		23	%		42	%		44	%
Number of wells drilled		1,351			5,241			3,091			10,942
Average days per well		11.4			12.4			9.4			12.0
Number of metres drilled (000s)		3,224			13,474			5,864			24,657
Average metres per well		2,386			2,571			1,897			2,253
Average metres per day		209			208			202			188

(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)	2015				2014
	Precision		Industry(2)		Precision		Industry(2)
Average number of active land rigs        for quarters ended:
March 31		80		1,353		94		1,724
June 30		57		873		93		1,802
September 30		51		829		97		1,842
December 31		45		720		100		1,856
Year to date average		58		944		96		1,806

(1) United States lower 48 operations only.

(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $306 million this quarter, or 42% lower than the fourth quarter of 2014, while adjusted EBITDA decreased by 43% to $134 million.  The decreases were mainly due to lower drilling rig utilization days in our Canadian, U.S. and international contract drilling businesses partially offset by higher average day rates in all markets.

Drilling rig utilization days in Canada (drilling days plus move days) were 4,176 during the fourth quarter of 2015, a decrease of 51% compared to 2014 primarily due to the decrease in industry activity resulting from lower commodity prices.  Drilling rig utilization days in the U.S. were 4,109, or 55% lower than the same quarter of 2014 as U.S. activity was down due to lower industry activity.  Drilling rig utilization days in our international business were 822 or 23% lower than the same quarter of 2014 as activity declines in Kurdistan were partially offset by adding a contracted rig in Kuwait in 2015.

Compared to the same quarter in 2014, drilling rig revenue per utilization day was up 13% in Canada, 2% in the U.S. and 10% internationally.  In Canada the day rate increase was the result of rig mix as we are working proportionately more Tier 1 rigs compared to the prior year and one-time payments from customers due to contractual shortfalls.  The increase in average day rates for the U.S. was primarily due to a higher percentage of revenue being generated from Tier 1 rigs compared to the prior year quarter and idle-but-contracted payments in the quarter relative to the prior year comparative quarter.  The average international day rate is up due to the recognition of an early termination payment of US$6 million in the quarter and the addition of a new-build contracted rig in Kuwait.

9

In Canada, 53% of utilization days in the quarter were generated from rigs under term contract, compared to 42% in the fourth quarter of 2014.  In the U.S., 64% of utilization days were generated from rigs under term contract in the fourth quarter of 2015 as compared to 69% in the fourth quarter of 2014.  At the end of the quarter, we had 37 drilling rigs under contract in Canada, 27 in the U.S. and nine internationally.

Operating costs were 52% of revenue for the quarter, which was three percentage points lower 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 primarily because of crew wage reduction and cost saving initiatives.  In the U.S., operating costs for the quarter on a per day basis were slightly higher from the fourth quarter of 2014 primarily as a result of having fixed costs spread across lower activity, partially offset by no turnkey activity in the current quarter.

General and administrative costs are higher than the prior year by $2 million due to a recovery of share based compensation in the fourth quarter of 2014.

Restructuring costs of $2 million in the quarter relate to cost cutting measures taken in response to the persistent down turn in industry activity levels.

Depreciation expense in the quarter was 11% higher than in the fourth quarter of 2014 due to the addition of new-build rigs deployed in 2014 and 2015, the impact of the weakening Canadian dollar compared with the U.S. dollar and the associated impact on our U.S. denominated depreciation expense.

Due to the significant decrease in industry activity resulting from the decline in oil and natural gas prices, we completed an impairment test of our businesses in our Contract Drilling Services Segment in the fourth quarter of 2015.  The recoverable amount of property, plant and equipment and goodwill was determined using a multi-year discounted cash flow approach with cash flow assumptions based on historical and expected future results.  As a result of this test it was determined that property, plant and equipment in our U.S. contract drilling business were impaired by US$73 million, and property, plant and equipment in our international contract drilling business were impaired by US$75 million.

During the fourth quarter the Contract Drilling Services segment recognized a loss of $165 million related to the decommissioning of 79 drilling rigs, comprised of 48 in Canada, 30 in the United States and one in Mexico, along with certain spare equipment.

10

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)	2015			2014			% Change			2015			2014			% Change
Revenue		41,685			89,444			(53.4	)		186,317			343,556			(45.8	)
Expenses:
Operating		36,043			70,000			(48.5	)		156,089			268,129			(41.8	)
General and administrative		4,240			3,430			23.6			16,355			17,473			(6.4	)
Restructuring		1,820			-			n/	m		3,634			-			n/	m
Adjusted EBITDA(1)		(418	)		16,014			(102.6	)		10,239			57,954			(82.3	)
Depreciation		6,218			24,849			(75.0	)		32,396			58,621			(44.7	)
Loss on asset decommissioning		1,377			28,752			(95.2	)		1,377			28,752			(95.2	)
Impairment of property, plant and   equipment		-			-			n/m			79,573			-			n/m
Operating loss(1)		(8,013	)		(37,587	)		(78.7	)		(103,107	)		(29,419	)		250.5
Operating loss as a percentage of revenue		(19.2	%)		(42.0	%)					(55.3	%)		(8.6	%)
Well servicing statistics:
Number of service rigs (end of period)		163			177			(7.9	)		163			177			(7.9	)
Service rig operating hours(2)		36,526			71,008			(48.6	)		149,574			275,702			(45.7	)
Service rig operating hour utilization		22	%		33	%					22	%		32	%
Service rig revenue per operating hour(2)		760			896			(15.2	)		784			907			(13.6	)

(1) See "ADDITIONAL GAAP MEASURES".

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

n/m – calculation not meaningful

Revenue from Completion and Production Services was down $48 million or 53% compared to the fourth quarter of 2014 due to lower activity levels in all service lines and lower average rates.  In response to lower oil prices, customers curtailed spending including well completion and production programs.  Our well servicing activity in the quarter was down 49% from the fourth quarter of 2014.  Revenue was also negatively impacted by the sale of our U.S. coil tubing operations in the fourth quarter of last year.  Approximately 87% of our fourth quarter Canadian service rig activity was oil related.

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

Average service rig revenue per operating hour in the fourth quarter was $760 or $136 lower than the fourth quarter of 2014.  The decrease was primarily the result of industry pricing pressure and the sale of our U.S. coil tubing assets, which generally received a higher rate per hour.

Adjusted EBITDA was $16 million lower than the fourth quarter of 2014 due to declines in activity and pricing and $2 million in restructuring costs in the current quarter.

Operating costs as a percentage of revenue increased to 86% in the fourth quarter of 2015, from 78% in the fourth quarter of 2014.

General and administrative costs are higher than the prior year by $1 million due to a recovery of share based compensation in the fourth quarter of 2014 partially offset by cost saving initiatives.

Restructuring costs of $2 million in the quarter relate to cost cutting measures taken during the quarter in response to the persistent decline in industry activity levels.

11

Depreciation in the quarter was 75% lower than the fourth quarter of 2014 because of a lower asset base after decommissioning equipment in the fourth quarter of 2014, the recording of an impairment charge in the third quarter of 2015 and the disposal of our U.S. coil tubing assets part way through the fourth quarter of 2014.

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 2015, $8 million more than the 2014 comparative period due primarily to restructuring charges of $3 million incurred in the current year quarter and higher share based incentive compensation.

OTHER ITEMS

Net financial charges for the quarter were $34 million, an increase of $4 million from the fourth quarter of 2014, driven by the impact of the weaker Canadian dollar on our U.S. dollar denominated interest partially offset by customer related interest income of $2 million in the current quarter.  We had a foreign exchange gain of $1 million during the fourth quarter of 2015 due to the weakening of the Canadian dollar versus the U.S. dollar, which affected the net U.S. dollar denominated monetary position in the Canadian dollar-based companies.

Income tax expense for the quarter was a recovery of $146 million compared with a recovery of $35 million in the same quarter in 2014. The increased recovery is mainly due to the lower operating results from the loss on asset decommissioning and impairment charges in the current quarter compared with the prior year fourth quarter.

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

Liquidity

During the third quarter, we agreed with our lending group to the following amendments to our senior credit facility:

· The consolidated total debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (Adjusted EBITDA) covenant ratio was eliminated in its entirety;

· The Adjusted EBITDA to interest expense coverage ratio of greater than 2.75:1 was temporarily reduced to 2:1 for the period up to and including December 31, 2017, reverting to 2.5:1 in January 2018;

· The consolidated senior debt to Adjusted EBITDA covenant ratio was reduced from less than 3.0:1 to less than 2.5:1;

· The size of the  facility was reduced from US$650 million to US$550 million;

· A limitation was added to not incur or assume more than US$250 million in new unsecured debt unless the new debt is to refinance existing unsecured debt or the new debt is assumed through an acquisition.

12

As at December 31, 2015 we had $2,207 million outstanding under our senior unsecured notes.  The current blended cash interest cost of our debt is approximately 6.2%.

Amount	Availability	Used for	Maturity
Senior facility (secured)
US$550 million (extendible, revolving term credit facility with US$250 million accordion feature)	Drawn US$46 million in outstanding letters of credit	General corporate purposes	June 3, 2019
Operating facilities (secured)
$40 million	Undrawn, except $25 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$40 million	Undrawn, except US$25 million in outstanding letters of credit	Letters of credit
Senior notes  (unsecured)
$200 million	Fully drawn	Debt repayment	March 15, 2019
US$650 million	Fully drawn	Debt repayment and general corporate purposes	November 15, 2020
US$400 million	Fully drawn	Capital expenditures and general corporate purposes	December 15, 2021
US$400 million	Fully drawn	Capital expenditures and general corporate purposes	November 15, 2024

Covenants

Senior Facility

The senior credit facility requires that we comply with certain financial covenants including a leverage ratio of consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (Adjusted EBITDA) of less than 2.5:1.  For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness. Adjusted EBITDA as defined in our revolving term facility agreement differs from Adjusted EBITDA as defined under Additional GAAP Measures by the exclusion of bad debt expense and certain foreign exchange amounts.  As at December 31, 2015 our consolidated senior debt to Adjusted EBITDA ratio was negative 0.55:1.

Under the senior credit facility we are required to maintain an Adjusted EBITDA coverage ratio, calculated as Adjusted EBITDA to interest expense, of greater than 2:1 reverting to 2.5:1 for periods ending after December 31, 2017 for the most recent four consecutive fiscal quarters.  As at December 31, 2015 our Adjusted EBITDA coverage ratio was 4.26:1.

In addition, the senior credit facility contains certain covenants that place restrictions on our ability to incur or assume additional indebtedness; dispose of assets; pay dividends, share redemptions or other distributions; change our primary business; incur liens on assets; engage in transactions with affiliates; enter into mergers, consolidations or amalgamations; and enter into speculative swap agreements.  At December 31, 2015, we were in compliance with the covenants of the revolving credit facility.

Senior Notes

The senior notes require that we comply with certain financial covenants including an Adjusted EBITDA to interest coverage ratio of greater than 2.0:1 for the most recent four consecutive fiscal quarters.   In the event that our Adjusted EBITDA to interest coverage ratio is less than 2.0:1 for the most recent four consecutive fiscal quarters the senior notes restrict our ability to incur additional indebtedness. The senior notes contain a restricted payments covenant that limits our ability to make payments in the nature of dividends, distributions and repurchases from shareholders.  This restricted payment basket grows by, among other things, 50% of consolidated net earnings and decreases by 100% of consolidated net losses as defined in the note agreements, and payments made to shareholders.  Based on the unaudited interim financial statements, as at December 31, 2015, the restricted payments basket was negative $152 million and we are no longer able to make dividend payments until such time as the basket once again becomes positive.  For further information please see the senior note indentures which are available on SEDAR and EDGAR.

13

In addition, the senior notes contain certain covenants that limit our ability and the ability of certain subsidiaries to incur additional indebtedness and issue preferred shares; create liens; create or permit to exist restrictions on our ability or certain subsidiaries to make certain payments and distributions; engage in amalgamations, mergers or consolidations; make certain dispositions and engage in transactions with affiliates. At December 31, 2015, we were in compliance with the covenants of our senior notes.

Hedge of investments in U.S. 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.

Effective January 1, 2015, we have included the US$400 million of 5.25% Senior Notes due in 2024 as a designated hedge of our investment in our U.S. dollar denominated foreign operations and now all of our U.S. dollar Senior notes are designated as a net investment hedge.

Effective April 30, 2015, a portion of our U.S. dollar denominated debt that was previously treated as a hedge of our net investment in our U.S. operations was designated as a hedge of the investment in our 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 (loss) per share:

	Three months ended December 31,				Year ended December 31,
(Stated in thousands)	2015		2014		2015		2014
Weighted average shares outstanding – basic		292,912		292,791		292,878		292,533
Effect of stock options and other equity compensation plans		-		-		-		1,271
Weighted average shares outstanding – diluted		292,912		292,791		292,878		293,804

14

QUARTERLY FINANCIAL SUMMARY

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

	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

	2014
Quarters ended	March 31		June 30			September 30		December 31
Revenue		672,249		475,174			584,590		618,525
Adjusted EBITDA(1)		237,274		129,695			199,390		234,011
Net earnings (loss):		101,557		(7,174	)		52,813		(114,044	)
Per basic share		0.35		(0.02	)		0.18		(0.39	)
Per diluted share		0.35		(0.02	)		0.18		(0.39	)
Funds provided by operations(1)		231,393		97,805			196,217		172,059
Cash provided by operations		170,127		228,412			146,733		134,887
Dividends paid per share		0.06		0.06			0.06		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, financing charges, foreign exchange, impairment of goodwill, impairment of property, plant and equipment, loss on asset decommissioning and depreciation and amortization), as reported in the 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 impairment, decommissioning, depreciation and amortization charges.

Operating Earnings (Loss)

We believe that operating earnings (loss), as reported in the Consolidated Statements of Earnings (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 Operations

We believe that funds provided by 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.

15

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

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

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

· our capital expenditure plans for 2016;

· the suspension of our dividend will strengthen our liquidity;

· continued focus on preserving cash and reducing maintenance expenditures;

· our strategic priorities for 2016;

· decreasing demand for non-Tier 1 legacy drilling rigs;

· timing on the deployment of two additional rigs to Kuwait;

· average number of term contracts in place for 2016 and 2017; and

· continued lower drilling activity levels throughout North America as well as downward pricing pressure in the North American rig spot market.

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

· the decline in oil prices will continue to pressure customers into reducing or limiting their drilling budgets;

· the status of current negotiations with our customers and vendors;

· customer focus on safety performance;

· continuing demand for Tier 1 rigs;

· 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 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 could result in lower demand for our services;

· changes in laws and regulations, including but not limited to environmental laws, such as increased regulation of hydraulic fracturing or restrictions on the burning of fossil fuels and greenhouse gas emissions, 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 could impact the use of services supplied by Precision and Precision's ability to respond to such conditions.

16

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, 2014, 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, unless so requires by applicable securities laws.

17

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)

(Stated in thousands of Canadian dollars)	December 31, 2015			December 31, 2014
ASSETS
Current assets:
Cash	$	444,759		$	491,481
Accounts receivable		311,595			598,063
Income tax recoverable		-			55,138
Inventory		24,245			9,170
Total current assets		780,599			1,153,852
Non-current assets:
Income tax recoverable		2,917			3,297
Property, plant and equipment		3,883,332			3,928,826
Intangibles		3,363			3,302
Goodwill		208,479			219,719
Total non-current assets		4,098,091			4,155,144
Total assets	$	4,878,690		$	5,308,996
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	235,948		$	493,038
Income tax payable		7,836			7,184
Total current liabilities		243,784			500,222
Non-current liabilities:
Share based compensation		15,201			14,252
Provisions and other		14,520			14,837
Long-term debt		2,180,510			1,852,186
Deferred tax liabilities		303,466			486,133
Total non-current liabilities		2,513,697			2,367,408
Shareholders' equity:
Shareholders' capital		2,316,321			2,315,539
Contributed surplus		35,800			31,109
Retained earnings (deficit)		(397,013	)		48,426
Accumulated other comprehensive income		166,101			46,292
Total shareholders' equity		2,121,209			2,441,366
Total liabilities and shareholders' equity	$	4,878,690		$	5,308,996

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CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) (UNAUDITED)

	Three months ended December 31,						Year ended December 31,
(Stated in thousands of Canadian dollars, except per share  amounts)	2015			2014			2015			2014
Revenue	$	344,953		$	618,525		$	1,555,624		$	2,350,538
Expenses:
Operating		193,596			358,679			924,340			1,405,827
General and administrative		33,162			25,835			136,776			144,341
Restructuring		7,100			-			20,643			-
Earnings before income taxes, finance charges, foreign exchange, impairment of goodwill, impairment of property, plant and equipment, loss on asset decommissioning and depreciation and amortization		111,095			234,011			473,865			800,370
Depreciation and amortization		125,194			129,504			486,655			448,669
Loss on asset decommissioning		166,486			126,699			166,486			126,699
Impairment of property, plant and equipment		202,414			-			281,987			-
Operating earnings (loss)		(382,999	)		(22,192	)		(461,263	)		225,002
Impairment of goodwill		149			95,170			17,117			95,170
Foreign exchange		(653	)		1,169			(33,251	)		(946	)
Finance charges		34,230			30,468			121,043			109,701
Earnings (loss) before income taxes		(416,725	)		(148,999	)		(566,172	)		21,077
Income taxes:
Current		2,942			3,189			11,276			10,172
Deferred		(148,715	)		(38,144	)		(214,012	)		(22,247	)
		(145,773	)		(34,955	)		(202,736	)		(12,075	)
Net earnings (loss)	$	(270,952	)	$	(114,044	)	$	(363,436	)	$	33,152
Net earnings (loss) per share:
Basic	$	(0.93	)	$	(0.39	)	$	(1.24	)	$	0.11
Diluted	$	(0.93	)	$	(0.39	)	$	(1.24	)	$	0.11

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

	Three months ended December 31,						Year ended December 31,
(Stated in thousands of Canadian dollars)	2015			2014			2015			2014
Net earnings (loss)	$	(270,952	)	$	(114,044	)	$	(363,436	)	$	33,152
Unrealized gain on translation of assets and liabilities of operations denominated in foreign currency		96,781			71,779			444,464			171,092
Foreign exchange loss on net investment hedge with U.S. denominated debt, net of tax		(64,670	)		(41,265	)		(324,655	)		(101,325	)
Comprehensive income (loss)	$	(238,841	)	$	(83,530	)	$	(243,627	)	$	102,919

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CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)

	Three months ended December 31,						Year ended December 31,
(Stated in thousands of Canadian dollars)	2015			2014			2015			2014
Cash provided by (used in):
Operations:
Net earnings (loss)	$	(270,952	)	$	(114,044	)	$	(363,436	)	$	33,152
Adjustments for:
Long-term compensation plans		4,978			(4,544	)		15,594			16,197
Depreciation and amortization		125,194			129,504			486,655			448,669
Loss on asset decommissioning		166,486			126,699			166,486			126,699
Impairment of property, plant and equipment		202,414			-			281,987			-
Impairment of goodwill		149			95,170			17,117			95,170
Foreign exchange		(2,797	)		(2,845	)		(36,994	)		(3,971	)
Finance charges		34,230			30,468			121,043			109,701
Income taxes		(145,773	)		(34,955	)		(202,736	)		(12,075	)
Other		(5,699	)		(2,937	)		(4,408	)		(6,033	)
Income taxes paid		(2,374	)		(1,514	)		(13,560	)		(15,601	)
Income taxes recovered		659			49			1,770			8,463
Interest paid		(59,632	)		(49,258	)		(130,325	)		(103,816	)
Interest received		2,620			266			17,897			919
Funds provided by operations		49,503			172,059			357,090			697,474
Changes in non-cash working capital balances		21,449			(37,172	)		159,926			(17,315	)
		70,952			134,887			517,016			680,159
Investments:
Purchase of property, plant and equipment		(66,251	)		(338,250	)		(458,710	)		(856,690	)
Proceeds on sale of property, plant and equipment		2,227			53,304			9,786			101,826
Income taxes recovered		-			-			55,138			-
Changes in non-cash working capital balances		10,945			89,291			(147,316	)		124,877
		(53,079	)		(195,655	)		(541,102	)		(629,987	)
Financing:
Repayment of long-term debt		-			-			-			(30,670	)
Debt issue costs		(1,159	)		-			(2,134	)		(10,166	)
Dividends paid		(20,504	)		(20,496	)		(82,003	)		(73,142	)
Increase in long-term debt		-			-			-			436,600
Issuance of common shares on the exercise of options		-			246			93			7,082
		(21,663	)		(20,250	)		(84,044	)		329,704
Effect of exchange rate changes on cash and cash equivalents		9,676			14,408			61,408			30,999
Increase (decrease)  in cash and cash equivalents		5,886			(66,610	)		(46,722	)		410,875
Cash and cash equivalents, beginning of period		438,873			558,091			491,481			80,606
Cash and cash equivalents, end of period	$	444,759		$	491,481		$	444,759		$	491,481

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (UNAUDITED)

(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

(Stated in thousands of Canadian dollars)	Shareholders' capital		Contributed surplus			Accumulated other comprehensive income (loss)			Retained earnings			Total equity
Balance at January 1, 2014	$	2,305,227	$	29,175		$	(23,475	)	$	88,416		$	2,399,343
Net earnings for the period		–		–			–			33,152			33,152
Other comprehensive income for the period		–		–			69,767			–			69,767
Dividends		–		–			–			(73,142	)		(73,142	)
Share options exercised		10,312		(3,230	)		–			–			7,082
Share based compensation expense		–		5,164			–			–			5,164
Balance at December 31, 2014	$	2,315,539	$	31,109		$	46,292		$	48,426		$	2,441,366

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FOURTH QUARTER 2015 EARNINGS CONFERENCE CALL AND WEBCAST

Precision Drilling Corporation has scheduled a conference call and webcast to begin promptly at 12:00 noon MT (2:00 p.m. ET) on Thursday, February 11, 2016.

The conference call dial in numbers are 1-866-226-1793 or 416-340-2216.

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

An archived recording of the conference call will be available approximately one hour after the completion of the call until March 11, 2016 by dialing 1-800-408-3053 or 905-694-9451, pass code 3267535.

About Precision

Precision is a leading provider of safe and High Performance, High Value services to the oil and gas industry. Precision provides customers with access to an extensive fleet of contract drilling rigs, directional drilling services, well service and snubbing rigs, coil tubing services, camps, rental equipment, and water 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".

For further information, please contact:

Rob McNally, Executive Vice President & CFO

403.716.4771

403.716.4755 (FAX)

800, 525 - 8th Avenue S.W.

Calgary, Alberta, Canada T2P 1G1

Website:  www.precisiondrilling.com

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