pds-ex992_12.htm

We disclose forward-looking information to help current and prospective investors understand our future prospects.

Certain statements contained in this MD&A, 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).

Our forward-looking information and statements in this MD&A include, but are not limited to, the following:

The 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 and expected future developments as well as other factors we believe are appropriate in the circumstances. These include, among other things:

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:

Readers are cautioned that the foregoing list of risk factors is not exhaustive. You can find more information about these and other factors that could affect our business, operations or financial results in reports on file with securities regulatory authorities from time to time, including but not limited to our annual information form (AIF) for the year ended December 31, 2017, which you can find in our profile on SEDAR (www.sedar.com) or in our profile on EDGAR ( www.sec.gov).

All of the forward-looking information and statements made in this MD&A are expressly qualified by these cautionary statements. There can be no assurance that actual results or developments that we anticipate will be realized. We caution you not to place undue reliance on forward-looking information and statements. The forward-looking information and statements made in this MD&A are made as of the date hereof. We will not necessarily update or revise this forward-looking information as a result of new information, future events or otherwise, unless we are required to by securities law.

In this MD&A, we reference additional generally accepted accounting principles (GAAP) measures that are not defined terms under IFRS to assess performance because we believe they provide useful supplemental information to investors.

We believe that Adjusted EBITDA (earnings before income taxes, loss on redemption and repurchase of unsecured senior notes, finance charges, foreign exchange, impairment of goodwill, gain on re-measurement of property, plant and equipment, impairment of property, plant and equipment, loss on asset decommissioning, and depreciation and amortization), as reported in the Consolidated Statements of Loss, is a useful supplemental measure because it gives us, and our investors, an indication of the results from our principal business activities before consideration of how our activities are financed and exclude the impact of foreign exchange, taxation, and non-cash impairment, decommissioning, depreciation, and amortization charges.

Covenant EBITDA, as defined in our Senior Credit Facility agreement differs from Adjusted EBITDA by the exclusion of bad debt expense, restructuring costs and certain foreign exchange amounts that may differ from what is disclosed on the Consolidated Statements of Loss. Covenant EBITDA is a useful measure as it used in the determination on our Senior Credit Facility covenants.

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

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

We define working capital as current assets less current liabilities as reported on the Consolidated Statements of Financial Position.

Precision Drilling Corporation provides onshore drilling and completion and production services to exploration and production companies in the oil and natural gas industry.

From our founding as a private oilfield drilling contractor in the 1950s, Precision has grown to become one of the most active drillers in North America. Our competitive advantage is underpinned by five distinguishing features:

At Precision, we believe that a transparent culture of corporate governance and ethical behaviour in decision-making is fundamental to the way we do business.

We have a diverse and experienced Board of Directors (Board). Our directors have a history of achievement and an effective mix of skills, knowledge, and business experience. The directors oversee the conduct of our business, provide oversight in support of future operations and monitor regulatory developments and governance best practices in Canada and the U.S. Our Board also reviews our governance charters, guidelines, policies and procedures to make sure they are appropriate and that we maintain high governance standards.

Our Board has established three standing committees, comprised of independent directors, to help it carry out its responsibilities effectively:

The Board may also create special ad hoc committees from time to time to deal with important matters that arise.

You can find more information about our approach to governance in our management information circular, available on our website (www.precisiondrilling.com).

We operate our business in two segments, supported by vertically integrated business support systems.

We provide onshore drilling services to exploration and production companies in the oil and natural gas industry, operating in Canada, the U.S. and internationally.

We are a large, multi-basin oilfield operator servicing approximately 25% of the active land drilling market in Canada and 7% of the active U.S. market. We also have an international presence with operations in Mexico and the Middle East.

At March 9, 2018, we had 240 Super Series drilling rigs, with 16 additional rigs that are good candidates to be upgraded. Our Tier 1, or Super Series rigs are highly mobile and mechanized, which make them safer and more efficient in drilling directional and horizontal wells than older generation drilling rigs. Our Super Series rigs have a broad range of features to meet a diverse range of customer needs with a focus on high efficiency development drilling applications, from drilling shallow- to medium-depth wells to deeper, extended reach horizontal well bores and all depths of conventional wells. Available features include alternating current (AC) power, digital control systems, integrated top drive, omni-directional pad walking systems for multi-pad well drilling, highly mechanized pipe handling, and high capacity mud pumps.

We provide well completion, workover, abandonment, and re-entry preparation services, as well as snubbing units for pressure control services and equipment rentals to oil and natural gas exploration and production companies in Canada and the U.S.

In December 2016 we acquired 48 well service rigs and ancillary equipment in a business acquisition for consideration of $12 million and our coil tubing assets and associated equipment.

On an operating hour basis in 2017, we serviced approximately 14% of the well completion and workover service rig market demand in Canada and less than 1% in the U.S.

At December 31, 2017, our Completion and Production Services segment consisted of:

Adjusted EBITDA, funds provided by operations and working capital are Non-GAAP measures. See page 3 for more information.

Year ended December 31 (thousands of dollars, except where noted)	2017			% increase/ (decrease)			2016			% increase/ (decrease)			2015			% increase/ (decrease)
Revenue		1,321,224			31.7			1,003,233			(38.6	)		1,634,758			(34.3	)
Adjusted EBITDA		304,981			33.7			228,075			(51.9	)		473,865			(40.8	)
Adjusted EBITDA % of revenue		23.1	%					22.7	%					29.0	%
Net loss		(132,036	)		(15.1	)		(155,555	)		(57.2	)		(363,436	)		(1,196.3	)
Cash provided by operations		116,555			(4.9	)		122,508			(76.3	)		517,016			(24.0	)
Funds provided by operations		183,935			74.6			105,375			(70.5	)		357,090			(48.8	)
Investing activities
Capital spending
Expansion		11,946			(92.0	)		148,887			(58.8	)		361,425			(36.7	)
Upgrade		37,086			86.7			19,862			(59.0	)		48,487			(64.5	)
Maintenance and infrastructure		25,791			(25.7	)		34,723			(28.8	)		48,798			(67.2	)
Intangibles		23,179		n/m				—			—			—			—
Proceeds on sale		(14,841	)		89.3			(7,840	)		(19.9	)		(9,786	)		(90.4	)
Net capital spending		83,161			(57.5	)		195,632			(56.4	)		448,924			(40.5	)
Business acquisition		—			(100.0	)		12,200		n/m				—			—
Loss per share ($)
Basic and diluted		(0.45	)		(15.1	)		(0.53	)		(57.3	)		(1.24	)		(1,227.3	)
Dividends per share ($)		—			—			—			(100.0	)		0.28			12.0

Year ended December 31	2017		% increase/ (decrease)			2016		% increase/ (decrease)			2015		% increase/ (decrease)
Contract drilling rig fleet		256		0.4			255		1.6			251		(19.8	)
Drilling rig utilization days
Canada		18,883		48.4			12,722		(26.2	)		17,238		(47.5	)
U.S.		20,479		80.5			11,343		(46.4	)		21,172		(39.6	)
International		2,920		4.8			2,786		(31.8	)		4,084		1.2
Revenue per utilization day
Canada (Cdn$)		21,143		(13.7	)		24,509		(9.1	)		26,976		6.0
U.S. (US$)		19,861		(24.0	)		26,145		(2.2	)		26,728		6.3
International (US$)		50,240		9.8			45,753		5.2			43,491		(0.9	)
Operating cost per utilization day
Canada (Cdn$)		13,140		(7.8	)		14,258		(4.2	)		14,884		5.4
U.S. (US$)		13,846		(10.9	)		15,547		(0.5	)		15,618		4.9

Service rig fleet		210		1.4			207		27.0			163		(7.9	)
Service rig operating hours		172,848		73.8			99,451		(33.5	)		149,574		(45.2	)
Revenue per operating hour (Cdn$)		637		(1.4	)		646		(17.6	)		784		(13.6	)

(thousands of dollars, except ratios)	December 31, 2017		December 31, 2016		December 31, 2015
Working capital⁽¹⁾		232,121		230,874		536,815
Working capital ratio		2.1		2.0		3.2
Long-term debt		1,730,437		1,906,934		2,180,510
Total long-term financial liabilities		1,754,059		1,946,742		2,210,231
Total assets		3,892,931		4,324,214		4,878,690
Enterprise value⁽²⁾		2,782,596		3,937,737		3,337,980
Long-term debt to long-term debt plus equity⁽³⁾		0.5		0.5		0.5
Long-term debt to cash provided by operations		14.8		15.6		4.2
Long-term debt to enterprise value		0.6		0.5		0.7

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

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

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

	For the Year Ended December 31, 2016									For the Year Ended December 31, 2015
(thousands of dollars)	As previously reported		Revenue recast		Expense recast			As recast		As previously reported		Revenue recast		Expense recast			As recast
Revenue		951,411		51,822		—			1,003,233		1,555,624		79,134		—			1,634,758
Expenses:
Operating		607,295		51,822		2,598			661,715		934,693		79,134		7,657			1,021,484
General and administrative		110,287		—		(2,598	)		107,689		126,423		—		(7,657	)		118,766
Restructuring		5,754		—		—			5,754		20,643		—		—			20,643
Adjusted EBITDA⁽¹⁾		228,075		—		—			228,075		473,865		—		—			473,865

Crude oil prices began to decline in mid-2014, reaching a low point in 2016 and resulting in a severe, industry-wide downturn with low oil and natural gas prices reducing our customers’ cash flows, causing them to scale back their capital budgets. As a result, customer demand and drilling activity declined significantly over this period which had a negative impact on our activity and resulting cash flow. In the fourth quarter of 2016, the Organization of Petroleum Exporting Countries (OPEC) and certain non-OPEC countries agreed to production caps, resulting in more stable and higher crude oil prices. Although natural gas prices remain historically low, higher oil prices in 2017 resulted in significantly higher customer demand and drilling activity for us in 2017 with total utilization days increasing 64% over 2016 levels.

For the year ended December 31, 2017, our net loss was $132 million, or $0.45 per diluted share, compared with a net loss of $156 million, or $0.53 per diluted share in 2016. During 2017 we incurred an asset impairment charge of $15 million, related to our Mexico contract drilling business, that after tax increased our net loss by $12 million and net loss per diluted share by $0.04.

Revenue in 2017 was $1,321 million, or 32% higher than in 2016, mainly due to higher activity. Contract Drilling Services revenue was up 29%, while Completion and Production Services revenue was up 54%. Our Canadian, U.S. and international drilling activity increased 48%, 81% and 5%, respectively.

Adjusted EBITDA in 2017 was $305 million, or 34% higher than in 2016. Our Adjusted EBITDA margin was 23%, in-line with 2016. Adjusted EBITDA improved because of lower share-based compensation expense and higher utilization in North America offset by the expiry of some legacy long-term drilling rig contracts. Adjusted EBITDA margin for the year in our Contract Drilling Services segment was 29%, compared with 33% in the prior year, while Adjusted EBITDA margin from our Completion and Production Services segment was 8%, compared with a prior year margin of negative 4%. Increased activity has led to fixed costs and operating overhead being spread over a larger base resulting in improved margins compared with the prior year in our Completion and Production Services segment. Our portfolio of term customer contracts, a scalable operating cost structure, and economies achieved through vertical integration of the supply chain help us manage our Adjusted EBITDA margin.

We undertook several measures to manage our variable costs during the industry downturn including reducing our capital and operating expenditures. We also reduced our fixed cost structure by consolidating several of our North American operating facilities, streamlining management reporting structures, and reducing staff, which resulted in one-time costs of $6 million in 2016. We have continued to maintain the reduced overhead levels despite the significant increase in activity.

Capital expenditures for the purchase of property, plant and equipment were $98 million in 2017, a decrease of $105 million over 2016. Capital spending for 2017 included $12 million on expansion capital, $37 million on upgrade capital, $26 million on the maintenance of existing assets and infrastructure and $23 million on intangibles, which primarily related to information technology infrastructure. Expansion capital relates to the completion of the two new-build drilling rigs for Kuwait delivered in the fourth quarter of 2016.

In 2017, we added one Super Series drilling rig to the U.S. fleet compared with the addition of four in 2016 (one in Canada, one in the U.S. and two in Kuwait). In December 2016, we also added 48 well service rigs and ancillary equipment in a business acquisition for consideration of $12 million and our coil tubing units and associated equipment.

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. Because of no activity in 2017, we completed an impairment test for our Mexico contract drilling CGU as of December 31, 2017. 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. Because of this test it was determined that property, plant and equipment in our Mexico contract drilling business was impaired by US$12 million.

In November 2017 we issued US$400 million of 7.125% senior notes due in 2026 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 all our outstanding 6.625% unsecured senior notes due 2020 and redeem a portion of our 6.5% unsecured senior notes due 2021. In addition, we agreed with our lending group to amend the terms of our Senior Credit Facility to among other things, reduce the Covenant EBITDA, as defined in the debt agreement, (see NON-GAAP MEASURES on page 4 of this report) to interest expense coverage ratio, reduce the size of the facility to US$500 million and extend the maturity to November 21, 2021. For added amendments and detail on the new debt and redemption of our existing debt see LIQUIDITY on page 34 of this report.

generate 365 utilization days per rig year. In 2017, we had an average of 57 drilling rigs working under term contracts and revenue from these contracts was approximately 47% of our total contract drilling revenue for the year.

While global crude oil prices remained volatile throughout 2017, production cuts put in place by OPEC and select non-OPEC countries in late-2016 have supported higher oil prices and provided a level of stability in the market. In 2017, West Texas Intermediate (WTI) crude oil prices averaged US$50.95 per barrel, increasing from cyclical lows in 2016. Following the decision in late-2017 to extend the cuts through the end of 2018, global crude oil prices strengthened further with WTI crude closing the year at US$60.46 per barrel and averaging US$62.96 per barrel for the first two months of 2018. Although global crude prices have strengthened, certain Canadian grades of crude, such as Western Canada Select (WCS) became deeply discounted from WTI in the second half of 2017 because of takeaway capacity constraints from oil producing regions in Western Canada, a dynamic that continued into 2018. In the first two months of 2018 WCS averaged US$36.75 or a US$26.21 discount from the average WTI price.

Natural gas prices have remained rangebound by historical standards as growth in associated gas from unconventional oil development, higher than average storage levels, infrastructure constraints and the lack of a fully developed export market from North America continue to cap pricing. Natural gas prices in the U.S., referenced by the Henry Hub price on the New York Mercantile Exchange (NYMEX), averaged US$2.98 per MMBtu in 2017, and closed the year at US$3.69 per MMBtu. In Canada, the AECO gas benchmark witnessed price weakness and volatility in 2017 particularly in the summer months driven by plant maintenance, pipeline shut-ins, and challenges exporting gas as a Canadian LNG export industry has not been developed leaving a well-supplied U.S. market as the only export option for Canadian gas. Differences between NYMEX (U.S.) prices and AECO (Canada) prices are expected to continue if Canadian export markets remained challenged.

The rig count at March 9, 2018 was 13% lower in Canada than it was a year ago while the year-to-date rig count has averaged 8% less than 2017. Activity for the remainder of the year is expected to be determined by the strength in commodity prices and the resulting oil and gas customer budgets.

In the U.S., strengthening crude prices have resulted in increased drilling activity and demand for our rigs. As a result, spot market pricing and activity each increased throughout 2017 and have improved further year-to-date in 2018. As of March 9, 2018, the rig count was 30% higher than the same time last year and has averaged 34% higher year-to-date compared to 2017. Activity levels for the remainder of 2018 are expected to be dependent on commodity prices and resulting customer budgets.

The Canadian dollar averaged US$0.7704 (Cdn$/US$1.2979) for 2017 and closed the year at US$0.7954 (Cdn$/US$1.2573). The lower Canadian dollar relative to the U.S. dollar serves to partially offset the impact of lower U.S. dollar-denominated crude oil and natural gas prices for Canadian exploration and production companies. Year to date, the Canadian dollar has weakened in relation to the U.S. dollar and as of March 9, 2018, the Canadian dollar closed at US$0.7802.

Our international drilling rig fleet consists of 17 rigs with five in Kuwait, five in Mexico, four in the Kingdom of Saudi Arabia, two in the Kurdistan region of Iraq and one in the country of Georgia. We currently have eight rigs working on term contracts with five in Kuwait and three in the Kingdom of Saudi Arabia.

The industry trend toward more complex drilling programs has accelerated the retirement of older generation, less capable rigs. Over the past several years, we and some of our competitors have been upgrading the drilling rig fleet by building new rigs, upgrading existing rigs, and decommissioning lower capacity rigs. We believe this retooling of the industry-wide fleet has been making legacy rigs virtually obsolete in North America.

After our new-build program, the upgrading of a number of existing rigs, and the cumulative decommissioning of 236 legacy rigs, our fleet now consists of 240 Tier 1 rigs with 16 additional rigs that are good candidates for upgrade.

We expect capital spending in 2018 to be $94 million, including $34 million on expansion and upgrade, $45 million on maintenance and infrastructure expenditures and $15 million on intangibles, primarily relating to information technology infrastructure. We expect that the $94 million will be split $74 million in the Contract Drilling segment, $5 million in the Completion and Production Services segment and $15 million in the Corporate segment. Precision’s sustaining and infrastructure capital plan is based on currently anticipated activity levels for 2018. If we can obtain attractive term contracts we would consider additional upgrade and expansion capital opportunities. Maintenance capital is variable and will increase or decrease with activity.

Precision operates in the energy services business, which is an inherently challenging cyclical sector of the energy industry. We depend on oil and natural gas exploration and production companies to contract our services as part of their exploration and development activities. The economics of their businesses are dictated by the current and expected future margin between their finding and development costs and the eventual market price for the commodities they produce: crude oil, natural gas, and natural gas liquids.

Oil and gas reservoirs can be conventional, where a vertical well is drilled into a highly pressurized reservoir allowing the oil and gas to flow freely shortly after completing the drilling process. Unconventional reservoirs are exploited by drilling a vertical section of a well followed by a horizontal section to access a large portion of the oil or gas formation. These “unconventional” or “shale” reservoirs are typically lower pressure and require extra stimulation to generate production. The practice of “hydraulic fracturing” follows the unconventional drilling process with high horsepower equipment pumping water and proppant down a wellbore at high pressure to frack the rock, releasing hydrocarbons.

Cash flow to fund exploration and development is dependent on commodity prices: higher prices increase cash flow and encourage investment and when prices decline, the opposite is true.

Oil can be transported relatively easily, so it is generally priced in a global market that is influenced by an array of economic and political factors. Higher oil prices typically result in stronger demand for drilling services with funding for drilling programs directed toward the most economically attractive drilling opportunities. As the volume of unconventional oil development has dramatically increased over the past decade, generating efficiencies through industrialized processes, more capital has been directed toward unconventional oil development in North America, reflecting the region’s competitiveness globally.

Natural gas and natural gas liquids continue to be priced more regionally. In North America, natural gas demand largely depends on the weather. Colder winter temperatures, and to a lesser extent, warmer summer temperatures, result in greater natural gas demand. Other demand drivers, such as natural gas fired power generation, industrial applications, and transportation, have shown positive growth over the past several years driven by a preference for natural gas over coal, favourable regulation, and lower prices. The potential for liquefied natural gas (LNG) export development in Canada and continued development in the U.S. could serve as a catalyst for natural gas directed drilling activity over the medium to long term.

The key natural gas price driver continues to be increased production from unconventional shale gas drilling. Since the winter of 2014, pricing for natural gas in North America has been depressed, as supplies of unconventional natural gas have increased, and current inventory levels are viewed as adequate to keep North American markets well supplied.

	2017		2016		2015
Oil
WTI (US$ per barrel)		50.95		43.30		48.77
Natural gas
Canada
AECO ($ per MMBtu)		2.16		2.14		2.70
U.S.
Henry Hub (US$ per MMBtu)		2.98		2.48		2.60
Source: WTI and Henry; Hub Energy Information Administration, AECO; Gas Alberta Inc.

Exploration and production companies across the U.S. and Canada have been increasingly focused on drilling and completion efficiency as they have adapted to a lower commodity price environment. Our customers have adopted large-scale industrialization techniques, utilizing multi-well pads and high efficiency rig systems in order to remain competitive in today’s environment. The next wave of efficiency is centered around rig automation technologies with customers desiring consistent, predictable and repeatable results in their development-style drilling programs.

Natural gas production in Canada has been flat because of lower natural gas directed drilling due to pricing pressure and Canada’s lack of an export market other than the U.S.

Following a decline in activity in 2015 and 2016, the North American land drilling market showed increased activity levels in 2017 as customer demand improved with higher oil prices.

In 2017, the industry drilled 6,959 wells in western Canada, compared with 3,963 in 2016 and 5,241 in 2015. Total industry drilling operating days were 66,138 in 2017 compared with 42,391 in 2016 and 64,880 in 2015. Average industry drilling operating days per well was 9.5 compared with 10.7 in 2016 and 12.4 in 2015. From 2017 to 2016 the average depth of a well increased 5% compared with an increase of 2% from 2015 to 2016.

In 2017 approximately 15,800 wells were started onshore in the U.S., compared with approximately 11,200 in 2016 and 20,400 in 2015.

In Canada, there has been relative strength in natural gas liquids and light tight oil drilling activity in the deeper basins of northwestern Alberta and northeastern British Columbia, while in the U.S. the bias towards oil-directed drilling continues. In 2017, approximately 53% of the Canadian industry’s active rigs and 80% of the U.S. industry’s active rigs were drilling for oil targets, compared with 48% for Canada and 80% for the U.S. in 2016.

The graphs below show the shift in drilling activity to oil targets since 2013, in both the U.S. and Canada. The Canadian drilling rig activity graph also shows how Canadian drilling activity fluctuates with the seasons, a market dynamic that generally is not present in the U.S.

The contract drilling business is highly competitive, with many industry participants. We compete for drilling contracts that are often awarded in a competitive bid process. We believe potential customers focus on pricing and rig availability when selecting a drilling contractor, but also consider many other things, including drilling capabilities, condition of rigs, quality of rig crews, breadth of service, technology offering, and safety record, among others.

Providing High Performance, High Value services to our customers is the core of our competitive strategy. We deliver High Performance through passionate people supported by quality business systems, drilling technology, equipment and infrastructure designed to optimize results and reduce risks. We create High Value by operating safely and sustainably, lowering our customers’ risks and costs while improving efficiency, developing our people, and generating superior financial returns for our investors.

We keep customer well costs down by maximizing the efficiency of operations in several ways:

We focus on providing efficient, cost-reducing drilling technologies. Design innovations and technology improvements, such as multi-well pad capability and rapid mobility between wells, capture incremental time savings during the drilling process.

Our Super Series rigs have a broad range of features to meet a diverse range of customer needs with a focus on high-efficiency development drilling applications, from drilling shallow- to medium-depth wells to deeper, extended reach horizontal well bores. Available features include alternating current (AC) power, digital control systems, integrated top drives, omni-directional pad walking systems for multi-pad well drilling, highly mechanized pipe handling, and high capacity mud pumps. Our Super Series fleet includes a number of smaller, fast-moving, hydraulically-powered mechanized rigs that are optimized for shallow- to medium-depth resource plays found across North America.

Geographic proximity and fleet versatility support the High Performance, High Value services we provide to our customers. Our large, diverse fleet of rigs is strategically deployed across the most active drilling regions in North America, including all major unconventional oil and natural gas basins.

Minimizing downtime is a key operating metric for us and our customers. Reliable and well-maintained equipment minimizes downtime and non-productive time during operations. We manage mechanical downtime through preventative maintenance programs, detailed inspection processes, an extensive fleet of strategically-located spare equipment, and an in-house supply chain. We minimize non-productive time (to move, rig-up and rig-out) by utilizing walking systems, reducing the number of move loads per rig, and using mechanized equipment for safer and quicker rig component connections.

We unitize key financial information per day and per hour and compare these measures to established benchmarks and past performance. We evaluate the relative strength of our financial position by monitoring our working capital, debt ratios, and returns on capital employed. We track industry rig utilization statistics to evaluate our performance against competitors.

We reward executives and eligible employees through incentive compensation plans for performance against the following measures:

We pride ourselves on providing quality equipment operated by experienced and well-trained crews. We also strive to align our capabilities with evolving technical requirements associated with more complex well bore programs.

Our fleet of drilling rigs is well positioned to address the unconventional drilling programs of our customers. The vast majority of our drilling rigs have been designed or significantly upgraded to drill horizontal wells. With a breadth of horsepower types and drilling depth capabilities, our large fleet can address every type of onshore unconventional and conventional oil and natural gas drilling opportunity in North America.

Our service rigs provide completion, workover, abandonment, well maintenance, high pressure operations and critical sour gas well work, and well re-entry preparation across the Western Canada Sedimentary Basin and in the northern U.S. Service rigs are supported by four field locations in Alberta, two in Saskatchewan, and one each in Manitoba, British Columbia and North Dakota.

Snubbing units complement traditional natural gas well servicing by allowing customers to work on wells while they are pressurized and production has been suspended. We have two kinds of snubbing units: rig-assist and self-contained. Self-contained units do not require a service rig on site and are capable of snubbing and performing many other well servicing procedures. Included in our self-contained units are three patented L-frame units, which are more efficient in the rig up and rig out process than standard self-contained units.

We leverage our internal manufacturing and repair capabilities and inventory of quality rigs to address market demand through upgraded drilling rigs. For drilling rigs, the upgrade is typically performed at the request of a customer and includes a term contract. Certain upgrades have sometimes resulted in a change in tier classification.

An inventory of equipment (top drives, loaders, boilers, tubulars, and well control equipment) supports our fleet of drilling and service rigs. We also maintain an inventory of key rig components to minimize downtime due to equipment failure.

We benefit from internal services for equipment certifications and component manufacturing from our manufacturing division in Canada and for standardization and distribution of consumable oilfield products through our procurement divisions in Canada and the U.S.

Precision Rentals provides specialized equipment and wellsite accommodations to customers on a rental basis. Precision Camp Services provides food and accommodation to personnel working at the wellsite, typically in remote locations in Western Canada. Terra Water Systems designs, fabricates and rents units to customers including: portable wastewater handling, treatment and disposal facilities, potable water production plants, and potable water delivery systems for remote sites in Western Canada.

We operate two contract drilling technical centres, one in Nisku, Alberta and one in Houston, Texas. We also operate one completion and production services technical centre in Red Deer, Alberta. These centres accommodate our technical service and field training groups and enable us to consolidate support and training for our operations. Both of our contract drilling technical centres include fully functioning training rigs with the latest drilling technologies. In addition, our Houston facility accommodates our rig manufacturing group.

reputation to attract and retain employees. Our people strategies focus on initiatives that provide a safe and productive work environment, opportunity for advancement, and added wage security. We have centralized personnel, orientation, and training programs in Canada and the U.S. Our people strategies have enabled us to deliver sufficient and good quality field crews at all points in the industry cycle.

In 2017 we commenced an upgrade to our enterprise-wide reporting system (ERP) with completion expected in the second quarter of 2018. The upgraded system will fully integrate our drilling rigs with our field facilities and corporate offices increasing operating efficiencies and positioning the organization to better handle the increased data flows associated with our business. All our divisions operate using standardized business processes across marketing, equipment maintenance, procurement, manufacturing, HSE, inventory control, engineering, finance, payroll and human resources.

We continue to invest in information systems that provide competitive advantages. Electronic links between field and financial systems provide accuracy and timely processing. This repository of rig data improves response time to customer inquiries. Rig manufacturing projects also benefit from scheduling and budgeting tools, which identify and help leverage economies of scale as construction demands increase.

Safety, environmental stewardship and employee wellness are critical for us and for our customers and are the foundation of our culture.

Total Recordable Incident Frequency (TRIF) is an industry standard and benchmarks our success and isolates areas for improvement. We have taken it to another level by tracking and measuring all injuries, regardless of severity, because they are leading indicators for the potential for more serious events. In 2017, 86% of our drilling rigs and 91% of our service rigs achieved Target Zero. Facilities recordable free includes all of our rigs, operating centers and offices and measures how many of our facilities do not have a recordable during the year. In addition, we have a goal of achieving “Triple Target Zero” every day. A Triple Target Zero day is a day when we have no vehicle incidents, no recordable injuries and no spills. For 2017 we achieved 282 Triple Target Zero days.

We continuously review our rig designs and components and use advanced technologies to improve the life cycle, maintain safety and operational efficiency, reduce energy use, and manage our energy and resources.

Together with our customers, we are continuously looking for opportunities to reduce our consumption of non-renewable resources and reduce our environmental footprint. We use technology to minimize our impact on the environment, including:

Precision’s vision is to be globally recognized as the High Performance, High Value provider of land drilling services. We work toward this vision by defining and measuring our results against strategic priorities we establish at the beginning of every year.

Our Corporate and Competitive Strategies are designed to optimize resource allocation and differentiate us from the competition, generating value for investors. Unconventional drilling is the primary opportunity in the North American marketplace. Unconventional resource development requires advanced Tier 1 drilling rigs and other highly developed services that facilitate the drilling of reliable, predictable and repeatable horizontal wells. Customer adoption of large-scale industrialization techniques and high efficiency rig systems continues to increase and Precision’s Super Series rig fleet and High Performance, High Value strategy positions the Company to benefit from that trend. The completion and production work associated with unconventional wells provides the most profitable growth opportunities for our Completion and Production Services segment.

Adjusted EBITDA and operating loss are Non-GAAP measures. See page 3 for more information.

Year ended December 31 (thousands of dollars)	2017			2016			2015
Revenue
Contract Drilling Services		1,173,930			907,821			1,457,470
Completion and Production Services		154,146			100,049			186,317
Inter-segment elimination		(6,852	)		(4,637	)		(9,029	)
		1,321,224			1,003,233			1,634,758
Adjusted EBITDA⁽¹⁾
Contract Drilling Services		342,970			296,651			535,394
Completion and Production Services		11,888			(3,649	)		10,239
Corporate and Other		(49,877	)		(64,927	)		(71,768	)
		304,981			228,075			473,865
Depreciation and amortization		377,746			391,659			486,655
Impairment of property, plant and equipment		15,313			—			281,987
Gain on re-measurement of property, plant and equipment		—			(7,605	)		—
Loss on asset decommissioning		—			—			166,486
Operating loss⁽¹⁾		(88,078	)		(155,979	)		(461,263	)
Impairment of goodwill		—			—			17,117
Foreign exchange		(2,970	)		6,008			(33,251	)
Finance charges		137,928			146,360			121,043
Loss on redemption and repurchase of unsecured senior notes		9,021			239			—
Loss before income taxes		(232,057	)		(308,586	)		(566,172	)
Income taxes		(100,021	)		(153,031	)		(202,736	)
Net loss		(132,036	)		(155,555	)		(363,436	)

Year ended December 31 (thousands of dollars)	2017			2016			2015
Revenue
Canada		578,817			418,030			646,753
U.S.		568,573			426,546			781,612
International		190,401			169,286			226,129
Inter-segment elimination		(16,567	)		(10,629	)		(19,736	)
		1,321,224			1,003,233			1,634,758
Total assets
Canada		1,631,838			1,738,853			2,077,077
U.S.		1,666,368			1,861,908			2,096,214
International		594,725			723,453			705,399
		3,892,931			4,324,214			4,878,690

Net loss in 2017 was $132 million, or $0.45 per diluted share, compared with net loss of $156 million, or $0.53 per diluted share, in 2016.

Revenue was $1,321 million (32% higher than 2016) because of higher activity in all our operations.

Adjusted EBITDA in 2017 was $305 million (34% higher than 2016), mainly because activity levels were higher in all our operations. Activity, as measured by drilling utilization days, increased 48% in Canada, 81% in the U.S., and 5% internationally compared with 2016.

We recognized a foreign exchange gain of $3 million in 2017 (2016 – $6 million loss) because the Canadian dollar strengthened in value against the U.S. dollar and this affected the net U.S. dollar denominated monetary position in our Canadian dollar-based companies.

Finance charges were $138 million, a decrease of $8 million compared with 2016. The decrease is the result of a stronger Canadian dollar on our U.S. dollar denominated interest expense and a reduction in interest expense related to debt retired during the past two years.

During the year we redeemed and/or repurchased US$442 million of our previously outstanding senior notes incurring a loss of $9 million.

Income taxes were a recovery of $100 million, $53 million lower than the $153 million recovery booked in 2016 mainly due to higher operating results in 2017 and from the fourth quarter tax reform implemented in the U.S. reducing tax rates which reduced the benefit of our losses carried forward.

Net loss in 2016 was $156 million, or $0.53 per diluted share, compared with net loss of $363 million, or $1.24 per diluted share, in 2015. In 2015 we recorded a pre-tax asset decommissioning charge, impairment of property, plant and equipment and goodwill write down totaling $466 million that increased after-tax net loss by $329 million and net loss per diluted share by $1.12.

Revenue was $1,003 million (39% lower than 2015) because of lower activity in all of our operations.

Adjusted EBITDA in 2016 was $228 million (52% lower than 2015), mainly because activity levels were lower in all of our operations. Activity, as measured by drilling utilization days, decreased 26% in Canada, 46% in the U.S., and 32% internationally compared with 2015.

With activity and results in-line with expectations and the stabilization of commodity prices in the fourth quarter indications of impairment did not exist as of any reporting dates in 2016 with the exception of our Mexico contract drilling operations as of December 31, 2016. As a result we completed an impairment test on only the CGUs that contained goodwill and our Mexico drilling business. The tests did not result in any impairments for the year ended December 31, 2016.

As a result of continued low commodity prices and their impact on industry activity, we completed an impairment test for all of our CGUs as of December 31, 2015. As a result of these tests, it was determined that property, plant and equipment was impaired by US$73 million in our U.S. contract drilling business, by US$49 million in our international contract drilling business, and by US$26 million in our Mexico contract drilling business. From 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.

We recognized a foreign exchange loss of $6 million in 2016 (2015 – $33 million gain) because the Canadian dollar strengthened in value against the U.S. dollar and this affected the net U.S. dollar denominated monetary position in our Canadian dollar-based companies.

Finance charges were $146 million, an increase of $25 million compared with 2015. The increase is the result of 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 partly offset by a reduction in interest expense related to debt retired during the year.

Income taxes were a recovery of $153 million, $50 million lower than the $203 million recovery booked in 2015 mainly due to lower operating results in 2015 from the loss on asset decommissioning and impairment charges in the year.

Adjusted EBITDA and operating loss are Non-GAAP measures. See page 3 for more information.

Year ended December 31 (thousands of dollars, except where noted)	2017			% of revenue			2016			% of revenue			2015			% of revenue
Revenue		1,173,930						907,821						1,457,470
Expenses⁽¹⁾
Operating		798,655			68.0			574,104			63.2			868,467			59.6
General and administrative		32,305			2.8			34,026			3.7			42,700			2.9
Restructuring		—			—			3,040			0.3			10,909			0.7
Adjusted EBITDA⁽²⁾		342,970			29.2			296,651			32.7			535,394			36.7
Depreciation and amortization		334,587			28.5			348,005			38.3			439,261			30.1
Loss on asset decommissioning		—			—			—			—			165,109			11.3
Impairment of property, plant and equipment		15,313			1.3			—			—			202,414			13.9
Operating loss⁽²⁾		(6,930	)		(0.6	)		(51,354	)		(5.7	)		(271,390	)		(18.6	)

Revenue from Contract Drilling Services was $1,174 million, 29% higher than 2016, mainly because of higher activity in all our contract drilling operations and higher average day rates in our international business partially offset by lower average day rates in North America.

In 2017, total shortfall payments in Canada and idle but contracted revenue in the U.S. were $31 million and US$6 million, compared with $29 million and US$42 million, respectively in 2016.

Operating expenses were 68% of revenue, compared with 63% in 2016. On a per utilization day basis, operating costs for our international drilling rig division were 6% higher than 2016 due to the addition of two rigs in the fourth quarter of 2016 in our Kuwait business and no activity in our Mexico business. In the U.S., operating costs on a per utilization day basis were 11% lower than 2016 because of cost saving initiatives and fixed costs spread across higher activity. In Canada, operating costs on a per utilization day basis were lower than the prior year by 8% primarily due to cost saving initiatives and fixed costs spread across higher activity. General and administrative expenses for 2017 were lower due to the strengthening Canadian dollar on our U.S. dollar denominated costs and cost saving initiatives. Restructuring costs incurred in 2016 were primarily severance related to right sizing the business for current activity levels.

Operating loss was $7 million, compared with an operating loss of $51 million in 2016. Operating results in 2017 were positively impacted by an increase in drilling activity in all of the regions in which we operate. Depreciation in the year was down from 2016 due to lower capital asset base. Operating results in 2017 were affected by the impairment of property, plant and equipment of certain drilling rigs and spare equipment. Excluding asset impairment and decommissioning charges, operating earnings would have been $8 million in 2017.

Capital expenditures in 2017 for our Contract Drilling segment were $69 million:

Year ended December 31	2017		% increase/ (decrease)			2016		% increase/ (decrease)			2015		% increase/ (decrease)
Number of drilling rigs (year-end)		256		0.4			255		1.6			251		(19.8	)
Drilling utilization days (operating and moving)
Canada		18,883		48.4			12,722		(26.2	)		17,238		(47.5	)
U.S.		20,479		80.5			11,343		(46.4	)		21,172		(39.6	)
International		2,920		4.8			2,786		(31.8	)		4,084		1.2
Drilling revenue per utilization day
Canada (Cdn$)		21,143		(13.7	)		24,509		(9.1	)		26,976		6.0
U.S. (US$)		19,861		(24.0	)		26,145		(2.2	)		26,728		6.3
International (US$)		50,240		9.8			45,753		5.2			43,491		(0.9	)
Drilling statistics (Canadian operations only)
Wells drilled		1,729		79.7			962		(28.8	)		1,351		(56.3	)
Average days per well		9.7		(17.1	)		11.7		2.6			11.4		21.3
Metres drilled (hundreds)		4,597		80.4			2,548		(21.0	)		3,224		(45.0	)
Average metres per well		2,659		0.4			2,649		11.0			2,386		25.8

Revenue from Canadian drilling was $399 million, 28% higher than 2016. Drilling rig activity, as measured by utilization days, was up 48% while average day rates were down 14%.

Adjusted EBITDA was $142 million, 15% higher than 2016, because of higher drilling activity offset by lower average day rates.

In 2017, we transferred one drilling rig from the U.S. to Canada, bringing our Canadian 2017 year-end net rig count to 136 (2016 –135).

The industry drilling rig fleet has decreased – there were approximately 627 rigs at the end of 2017 compared with 668 at the end of 2016. Our operating day utilization was 34% (2016 – 22%), compared with industry utilization of 29% (2016 – 17%).

Revenue from U.S. drilling was US$407 million, 37% higher than 2016. Drilling rig activity, as measured by utilization days, was up 81% while average revenue per day was down 24%.

Adjusted EBITDA was US$106 million, 4% higher than 2016, mainly because of higher industry activity offset by lower average day rates and lower idle but contracted revenue.

Depreciation expense for the year was US$121 million, US$5 million lower than 2016 because of a lower capital asset base.

In 2017, we completed one new-build rig and transferred one rig to Canada leaving our U.S. year-end net rig count unchanged at 103. In 2017, we averaged 56 rigs working, an 81% increase from 31 rigs in 2016. The industry drilling fleet increased as well, averaging 856 active land rigs in 2017, up 76% from 486 rigs in 2016.

Our average dayrates in the U.S. decreased 24% in 2017 as legacy contracts expired and newly contracted rigs were at lower day rates. Revenue from idle but contracted rigs was US$35 million less than 2016. Turnkey utilization days decreased 24% over 2016 and accounted for approximately 2% of our revenue compared with 5% in 2016.

	2017				2016				2015
	Precision		Industry⁽¹⁾		Precision		Industry⁽¹⁾		Precision		Industry⁽¹⁾
Average number of active land rigs for quarters ended:
March 31		47		722		32		516		80		1,353
June 30		59		874		24		397		57		873
September 30		61		927		29		465		51		829
December 31		58		902		39		567		45		720
Annual average		56		856		31		486		58		944

Adjusted EBITDA and operating loss are Non-GAAP measures. See page 3 for more information.

Year ended December 31 (thousands of dollars, except where noted)	2017			% of revenue			2016			% of revenue			2015			% of revenue
Revenue		154,146						100,049						186,317
Expenses⁽¹⁾
Operating		134,368			87.2			92,248			93.0			162,046			87.0
General and administrative		7,890			5.1			9,429			8.6			10,398			5.6
Restructuring		—			—			2,021			2.0			3,634			2.0
Adjusted EBITDA⁽²⁾		11,888			7.7			(3,649	)		(3.6	)		10,239			5.5
Depreciation and amortization		29,638			19.2			29,272			29.3			32,396			17.4
Gain on re-measurement of property, plant and equipment		—			—			(7,605	)	n/m				—			—
Loss on asset decommissioning		—			—			—			—			1,377			0.7
Impairment of property, plant and equipment		—			—			—			—			79,573			42.7
Operating loss⁽²⁾		(17,750	)		(11.5	)		(25,316	)		(25.3	)		(103,107	)		(55.3	)

Revenue from Completion and Production Services was $154 million in 2017, 54% higher than 2016, mainly because of higher activity across all our product lines.

Operating loss was $18 million in 2017, compared with a loss of $25 million in 2016. The decrease in our operating loss was because of higher activity in all our product lines partially offset by moderately lower average rates resulting from a highly competitive market.

Operating expenses were 87% of revenue, 6% points lower than 2016, mainly because of higher activity over fixed costs.

Capital expenditures in 2017 for our Completions and Production segment were $5 million:

In December 2016 we acquired 48 well service rigs and ancillary equipment in a business acquisition for consideration of $12 million and our coil tubing assets and associated equipment.

Revenue from Precision Well Servicing in Canada was $98 million, up $41 million from 2016 as activity was up 71% and average revenue rates were in-line with the prior year.

Revenue from our U.S. based completion and production businesses was US$12 million, 39% higher than 2016. The increase was the result of both higher activity and average rates.

Revenue from Precision Rentals was $23 million, 18% higher than 2016. The increase was due to higher activity partially offset by slightly lower average revenue rates.

Revenue from Precision Camp Services was $13 million, 103% higher than 2016, because of an increase in camp activity. Precision operated four base camps and 43 drill camps during 2017.

Year ended December 31	2017		% increase/ (decrease)			2016		% increase/ (decrease)			2015		% increase/ (decrease)
Number of service rigs (end of year)		210		1.4			207		(27.0	)		163		(7.9	)
Service rig operating hours		172,848		73.8			99,451		(33.5	)		149,574		(45.2	)
Revenue per operating hour		637		(1.4	)		646		(17.6	)		784		(13.6	)

In December 2016, we acquired 48 well service rigs for consideration of $12 million and our coil tubing assets and associated equipment.

Service rig hours increased 74% due to the December 2016 acquisition and increased industry activity. Service rig rates were in-line with the prior year.

Adjusted EBITDA and operating loss are Non-GAAP measures. See page 3 for more information.

Year ended December 31 (thousands of dollars, except where noted)	2017			2016			2015
Revenue		—			—			—
Expenses
Operating		—			—			—
General and administrative		49,877			64,234			65,668
Restructuring		—			693			6,100
Adjusted EBITDA⁽¹⁾		(49,877	)		(64,927	)		(71,768	)
Depreciation and amortization		13,521			14,382			14,998
Operating loss⁽¹⁾		(63,398	)		(79,309	)		(86,766	)

Our Corporate and Other segment has support functions that provide assistance to our other business segments. It includes costs incurred in corporate groups in both Canada and the U.S.

Corporate and Other expenses were $50 million in 2017, $14 million less than 2016. The decrease is mainly related to lower share-based incentive compensation expense and foreign exchange translation on U.S. dollar based costs. In 2017, corporate general and administrative costs were 3.8% of consolidated revenue compared with 6.4% in 2016 and 4.0% in 2015.

Adjusted EBITDA and funds provided by (used in) operations are Non-GAAP measures. See page 3 for more information.

2017 – Quarters Ended (thousands of dollars, except per share amounts)	March 31			June 30			September 30			December 31
Revenue		368,673			290,860			314,504			347,187
Adjusted EBITDA⁽¹⁾		84,308			56,520			73,239			90,914
Net loss		(22,614	)		(36,130	)		(26,287	)		(47,005	)
per basic and diluted share		(0.08	)		(0.12	)		(0.09	)		(0.16	)
Funds provided by (used in) operations⁽¹⁾		85,659			(15,187	)		85,140			28,323
Cash provided by (used in) operations		33,770			2,739			56,757			23,289

2016 – Quarters Ended (thousands of dollars, except per share amounts)	March 31			June 30			September 30			December 31
Revenue		316,505			170,407			213,668			302,653
Adjusted EBITDA⁽¹⁾		99,264			22,400			41,411			65,000
Net loss		(19,883	)		(57,677	)		(47,377	)		(30,618	)
per basic and 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	)

Drilling and well servicing activity is affected by seasonal weather patterns and ground conditions. In northern Canada, some drilling sites can only be accessed in the winter once the terrain is frozen, which is usually late in the fourth quarter. As a result activity peaks in the winter, in the fourth and first quarters. In the spring, wet weather and the spring thaw in Canada and the northern U.S. make the ground unstable. Government road bans restrict the movement of rigs and other heavy equipment, reducing activity in the second quarter. This leads to quarterly fluctuations in operating results and working capital requirements.

In the fourth quarter of 2017, we recorded a net loss of $47 million, or net loss per diluted share of $0.16, compared with a net loss of $31 million, or a net loss of $0.10 per diluted share, in the fourth quarter of 2016. During the current quarter we incurred an asset impairment charge for $15 million, related to our Mexico contract drilling business, that after tax increased our net loss by $12 million and net loss per diluted share by $0.04.

Revenue in the fourth quarter was $347 million or 15% higher than the fourth quarter of 2016, mainly due to increased activity in our North American based business partially offset by a decrease in our average day rate in our U.S. contract drilling business and no utilization in our Mexico based contract drilling business. Compared with the fourth quarter of 2016 our activity, as measured by drilling rig utilization days, increased by 6% in Canada and 50% in the U.S. and decreased by 1% internationally. Revenue from our Contract Drilling Services and Completion and Production Services segments both increased over the comparative prior year period by 13% and 32%, respectively.

Adjusted EBITDA this quarter was $91 million, an increase of $26 million from the fourth quarter of 2016. Our Adjusted EBITDA as a percentage of revenue was 26% this quarter, compared with 21% in the fourth quarter of 2016. The increase in Adjusted EBITDA as a percent of revenue was mainly due to fixed costs spread over higher activity in our North American businesses partially offset by lower average pricing in our U.S. contract drilling business.

As a percentage of revenue, operating costs were 67% in the fourth quarter of 2017 compared with 68% in the same quarter of 2016. The decrease is primarily due to the impact of higher activity on fixed costs partially offset by lower average day rates in our U.S. contract drilling business. Our portfolio of term customer contracts and a highly variable operating cost structure, helped us manage our Adjusted EBITDA margin.

Revenue from Contract Drilling Services was $309 million this quarter, or 13% higher than the fourth quarter of 2016, while adjusted EBITDA increased by 16% to $100 million. The increase in revenue was primarily due to higher utilization days in Canada and the U.S. During the quarter we recognized $13 million in shortfall payments in our Canadian contract drilling business, which was $1 million higher than in the prior year. In the U.S. we recognized idle but contracted revenue of US$1 million in the quarter compared with US$5 million in the comparative period and current period turnkey revenue of US$3 million with no revenue in the comparative quarter of 2016.

Drilling rig utilization days in Canada (drilling days plus move days) were 4,938 during the fourth quarter of 2017, an increase of 6% compared to 2016 primarily due to the increase in industry activity resulting from higher oil prices. Drilling rig utilization days in the U.S. were 5,365, or 50% higher than the same quarter of 2016 as U.S. activity was up with higher industry activity. Drilling rig utilization days in our international businesses were 736 or 1% lower than the same quarter of 2016 due to no activity in Mexico in the fourth quarter of 2017.

Compared with the same quarter in 2016, drilling rig revenue per utilization day was up 1% in Canada due to higher average spot market rates partially offset by fewer legacy contracts. Drilling rig revenue per utilization day for the quarter in the U.S. and international were each down 5% from the prior comparative period. The decrease in the U.S. average day rate was due to long-term contracts ending and rigs being re-contracted at lower spot market rates, lower idle but contracted revenue partially offset by an increase in turnkey activity in the current quarter and strengthening spot market rates. International revenue per utilization day was down due to demobilization revenue received in Mexico in the fourth quarter of 2016.

In Canada, 13% of our utilization days in the quarter were generated from rigs under term contract, compared with 35% in the fourth quarter of 2016. In the U.S., 55% of utilization days were generated from rigs under term contract as compared with 56% in the fourth quarter of 2016.

Operating costs were 65% of revenue for the quarter which was in-line with the prior year period. On a per utilization day basis, operating costs for the drilling rig division in Canada were slightly higher than the prior year period primarily due to timing of equipment certifications. In the U.S., operating costs for the quarter on a per day basis were lower than the prior year period primarily due to fixed costs spread over higher utilization and lower lump sum move costs partially offset by turnkey work and higher repair costs for rig activations. Both Canada and U.S. operating costs benefited from cost saving initiatives taken in 2015 and 2016.

Depreciation expense in the quarter was 9% lower than in the fourth quarter of 2016.

Revenue from Completion and Production Services was up $10 million or 32% compared with the fourth quarter of 2016 due to higher activity levels. As oil prices have recovered, customers have increased spending and activity in well completion and production programs. Our well servicing activity in the quarter was up 34% from the fourth quarter of 2016 as a result of improved industry activity levels and a larger fleet following the acquisition of service rigs late in the fourth quarter of 2016. Approximately 96% of our fourth quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 92% of its revenue from Canadian operations and 8% from U.S. operations compared with 88% from Canada and 12% from U.S. operations in the fourth quarter of 2016.

Average service rig revenue per operating hour in the quarter was $644 or $15 higher than the fourth quarter of 2016. The increase was primarily the result of increased labour costs which were passed through to the customer.

Adjusted EBITDA was $2 million higher than the fourth quarter of 2016 due to increased activity in the segment.

Operating costs as a percentage of revenue decreased to 88% in the fourth quarter of 2017, from 92% in the fourth quarter of 2016. The decrease is the result of the impact of fixed costs spread across greater activity combined with our reduced cost structure.

While we were successful in 2017 in reducing our fixed costs, margins in our Completion and Production Services have been challenged primarily due to intense pricing pressure, repair and maintenance as well as labor costs associated with service rig reactivations.

Depreciation in the quarter was $8 million in-line with the previous year comparative period.

Our Corporate and Other segment provides support functions to our operating segments. The Corporate and Other segment had an adjusted EBITDA loss of $12 million a decrease of $10 million compared with the fourth quarter of 2016 primarily due to higher share-based incentive compensation.

Net financial charges for the quarter were $38 million, a decrease of $4 million compared with the fourth quarter of 2016 primarily because of a stronger Canadian dollar and its impact on our U.S. dollar denominated interest expense and a reduction in interest expense related to debt retired in 2016.

During the quarter, we redeemed and/or repurchased US$442 million of our previously outstanding senior notes incurring a loss on redemption of $9 million. For the current quarter, we incurred a foreign exchange gain of $2 million in-line with the fourth quarter of 2016.

Income tax expense for the quarter was a recovery of $17 million compared with a recovery of $51 million in the same quarter in 2016. The recoveries are due to negative pretax earnings. During the quarter the U.S. implemented tax reform legislation reducing tax rates which reduced the benefit of our losses carried forward.

Capital expenditures were $25 million in the fourth quarter compared with $45 million in the fourth quarter of 2016. Spending in the fourth quarter of 2017 included:

The oilfield services business is inherently cyclical. To manage this variability, we focus on maintaining a strong balance sheet so we have the financial flexibility we need to continue to manage our capital expenditures and cash flows, no matter where we are in the business cycle.

We apply a disciplined approach to managing and tracking the results of our operations to keep costs down. We maintain a scalable cost structure so we can be responsive to changing competition and market demand. We also invest in our fleet to make sure we remain competitive. 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 help provide more certainty of future revenues and return on our growth capital investments.

On November 21, 2017 we agreed with our lenders to the following amendments to our senior credit facility:

On January 20, 2017 we agreed with our lenders to the following amendments to our senior credit facility:

On November 22, 2017, we issued US$400 million of 7.125% senior notes due in 2026 in a private offering. These 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. These notes were issued to redeem and repurchase existing debt.

On November 22, 2017 we also repurchased pursuant to an early tender offer US$310 million of our 6.625% unsecured senior notes due 2020 and US$70 million of our 6.5% unsecured senior notes due 2021 for US$387 plus accrued and unpaid interest incurring a loss on the repurchase of US$6 million.

On December 7, 2017 we redeemed our remaining outstanding 6.625% unsecured senior notes due 2020 for US$62 million plus accrued and unpaid interest incurring a loss on redemption of US$1 million.

During 2016 we 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, realizing a total gain on repurchase of $10 million.

On November 4, 2016, we issued US$350 million of 7.75% 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 also 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 incurring a loss on redemption of $11 million.

As of December 31, 2017, our liquidity was supported by a cash balance of $65 million, our Senior Credit Facility of US$500 million, operating facilities totaling approximately $59 million, and a US$30 million secured facility for letters of credit. Our ability to draw on our Senior Credit Facility is governed by financial covenants. See Capital Structure – Covenants on page 37.

We expect that cash provided by operations and our sources of financing, including our Senior Credit Facility, will be sufficient to meet our debt obligations and to fund future capital expenditures.

We ended 2017 with a long-term debt to long-term debt plus equity ratio of 0.5 (2016 – 0.5) and a ratio of long-term debt to cash provided by operations of 14.8 (2016 – 15.6).

We evaluate the relative strength of our financial position by monitoring our working capital, debt ratios and liquidity.

We also monitor returns on capital, and we link our executives’ incentive compensation to the returns to our shareholders relative to the shareholder returns of our peers.

(in thousands of dollars, except ratios)	December 31, 2017		December 31, 2016		December 31, 2015
Working capital⁽¹⁾		232,121		230,874		536,815
Working capital ratio		2.10		2.0		3.2
Long-term debt		1,730,437		1,906,934		2,180,510
Total long-term financial liabilities		1,754,059		1,946,742		2,210,231
Total assets		3,892,931		4,324,214		4,878,690
Enterprise value (see table on page 40)		2,782,596		3,937,737		3,337,980
Long-term debt to long-term debt plus equity		0.5		0.5		0.5
Long-term debt to cash provided by operations		14.8		15.6		4.2
Long-term debt to Adjusted EBITDA		5.7		8.4		4.6
Long-term debt to enterprise value		0.6		0.5		0.7

Credit ratings affect our ability to obtain short and long-term financing, the cost of this financing, and our ability to engage in certain business activities cost-effectively. In November 2017 we initiated rating coverage with Fitch which issued a corporate credit rating of B+, senior credit facility rating of BB+, and a senior unsecured rating of BB-. In March, 2016, Moody’s downgraded our corporate credit rating from Ba2 to B2 and senior unsecured credit rating from Ba2 to B3 and, S&P downgraded our corporate rating from BB+ to BB.

To maintain and grow our business, we invest in growth, upgrade and sustaining capital. We base expansion and upgrade capital decisions on return on capital employed and payback, and we mitigate the risk that we may not be able to fully recover our capital by requiring two- to five-year term contracts for new-build rigs.

We base our maintenance capital decisions on actual activity levels, using key financial indicators that we express as per operating day or per operating hour. Sourcing internally (through our manufacturing and supply divisions) helps keep our maintenance capital costs as low as possible.

Our U.S. and international operations have revenue, expenses, assets and liabilities denominated in currencies other than the Canadian dollar (mostly in U.S. dollars and currencies that are pegged to the U.S. dollar). This means that changes in currency exchange rates can materially affect our income statement, balance sheet and statement of cash flow. We manage this risk by matching the currency of our debt obligations with the currency of cash flows generated by the operations that the debt supports.

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 November 22, 2017, we included the US$400 million of 7.125% senior notes due in 2026 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.

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 in earnings.

In 2017, we generated cash from operations of $117 million compared with $123 million in 2016. The decrease is primarily the result of an increase in non-cash working capital.

The $98 million in capital expenditures in 2017 was split between segments as follows:

Expansion and upgrade capital includes the cost of long-lead items purchased for our capital inventory, such as integrated top drives, drill pipe, control systems, engines and other items we can use to complete new-build projects or upgrade our rigs in North America and internationally.

We sold underutilized capital assets for proceeds of $15 million in 2017 compared with $8 million in 2016.

As discussed on page 34 during the year we issued US$400 million of senior notes, redeemed US$62 million of senior notes and repurchased and cancelled US$380 million of senior notes.

During 2016 we issued US$350 million of senior notes, redeemed US$250 million and $200 million of senior notes and repurchased and cancelled US$109 million of senior notes.

In April 2016, we reduced the size of our demand facility for letters of credit with HSBC Canada to US$30 million to align with our expected requirements for this facility.

As of December 31, 2017, our operating facility of $40 million with Royal Bank of Canada was undrawn except for $21 million in outstanding letters of credit; our operating facility of US$15 million with Wells Fargo remained undrawn; and our demand facility for letters of credit of US$30 million with HSBC Canada had US$17 million available.

As of December 31, 2017, we had a cash balance of $65 million and available capacity under our secured facilities of $661 million.

As of December 31, 2017, we had $1,759 million outstanding under our senior unsecured notes.

Amount	Availability	Used for	Maturity
Senior facility (secured)
US$500 million (extendible, revolving term credit facility with US$250 million⁽¹⁾ accordion feature)	Undrawn, except US$21 million in outstanding letters of credit	General corporate purposes	November 21, 2021
Operating facilities (secured)
$40 million	Undrawn, except $21 million in outstanding letters of credit	Letters of credit and general corporate purposes
US$15 million	Undrawn	Short term working capital requirements
Demand letter of credit facility (secured)
US$30 million	Undrawn, except US$13 million in outstanding letters of credit	Letters of credit
Senior notes (unsecured)
US$249 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
US$400 million – 7.125%	Fully drawn	Debt redemption and repurchases	January 15, 2026

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 (Covenant EBITDA) of less than or equal to 2.5:1. For purposes of calculating the leverage ratio, consolidated senior debt only includes secured indebtedness. Covenant EBITDA as defined in our Senior Credit Facility agreement differs from Adjusted EBITDA as defined

under Non-GAAP Measures by the exclusion of bad debt expense and certain foreign exchange amounts. As of December 31, 2017, our consolidated senior debt to Adjusted EBITDA ratio was 0.12:1.

Under the Senior Credit Facility, we are required to maintain an Covenant EBITDA coverage ratio, calculated as Covenant EBITDA to interest expense for the most recent four consecutive fiscal quarters, of greater than or equal to 1.5:1, which, after the January 2017 amendment, reduced to 1.25:1 for the periods ending March 31, June 30 and September 30, 2017, and increased to 1.5:1 for the periods ending December 31, 2017 and March 31, 2018 and pursuant to the November 2017 amendment increases to 2.0:1 for the periods June 30, September 30, December 31, 2018 and March 31, 2019 and reverts to 2.5:1 for periods ending after March 31, 2019 until the maturity date of the facility. As of December 31, 2017, our Covenant EBITDA coverage ratio was 2.22:1.

The Senior Credit Facility prevents us from making distributions prior to April 1, 2019, after which, distributions are subject to a pro forma senior net leverage covenant of less than or equal to 1.75:1. The Senior Credit Facility also limits the redemption and repurchase of junior debt subject to a pro forma senior net leverage covenant test of less than or equal to 1.75:1.

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, 2017, we were in compliance with the covenants of the Senior Credit Facility.

The senior notes require that we comply with certain covenants including an incurrence based consolidated interest coverage ratio test, as defined in the senior note agreements, of greater than or equal to 2.0:1 for the most recent four consecutive fiscal quarters. In the event that our consolidated interest coverage ratio is less than 2.0:1 for the most recent four consecutive fiscal quarters the senior notes restrict our ability to incur additional indebtedness, 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. As of December 31, 2017, our senior notes consolidated interest coverage ratio was 2.16:1.

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. The restricted payments basket grows from a starting point of October 1, 2010 for the 2021 and 2024 Senior Notes, from October 1, 2016 for the 2023 Senior Note and October 1, 2017 for the 2026 Senior Note by, among other things, 50% of cumulative consolidated net earnings, and decreases by 100% of cumulative consolidated net losses as defined in the note agreements, and cumulative payments made to shareholders. Based on our consolidated financial results for the period ended December 31, 2015, the governing net restricted payments basket under the senior notes was negative $152 million prohibiting us from making any further dividend payments for dividends declared on or after December 31, 2015 until the restricted payments baskets become positive. As a result, Precision suspended our dividend on February 11, 2016.

Based on our consolidated financial results for the period ended December 31, 2017, the governing net restricted payments basket was negative $213 million.

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.

In August 2016, we completed the filing of a short form base shelf prospectus with the securities regulatory authorities in each of the provinces of Canada and a corresponding registration statement in the U.S., for the offering of up to $1 billion of common shares, preferred shares, debt securities, warrants, subscription receipts or units (the Securities). The Securities may be offered from time to time during the 25-month period for which the short form base shelf prospectus remains valid.

Our contractual obligations include both financial obligations (long-term debt and interest) and non-financial obligations (new-build rig commitments, operating leases, and equity-based compensation for key executives and officers).

The table below shows the amounts of these obligations and when payments are due for each.

At December 31, 2017 (thousands of dollars)	Payments due (by period)
	Less than 1 year		1-3 years		4-5 years		More than 5 years		Total
Long-term debt⁽¹⁾		—		—		312,601		1,445,918		1,758,519
Interest on long-term debt⁽¹⁾		116,661		233,322		212,157		191,185		753,325
Purchase of property, plant and equipment⁽¹⁾⁽²⁾		5,187		109,469		18,244		—		132,900
Operating leases⁽¹⁾		12,248		15,627		11,818		21,909		61,602
Contractual incentive plans⁽¹⁾⁽³⁾		8,658		19,000		—		—		27,658
Total		142,754		377,418		554,820		1,659,012		2,734,004

You can find more information about our capital structure in our AIF, available on our website and on SEDAR.

Our articles of amalgamation allow us to issue an unlimited number of common shares.

In the fourth quarter of 2012, our Board of Directors approved the introduction of an annualized dividend of $0.20 per common share, payable quarterly. In the fourth quarter of 2013, our Board of Directors approved an increase in the quarterly dividend payment to $0.06 per common share and in the fourth quarter of 2014, our Board of Directors approved an increase in the quarterly dividend to $0.07 per common share.

In the first quarter of 2016, we suspended our quarterly dividend. See Covenants – Senior Notes on page 38 for more information.

We can issue preferred shares in one or more series. The number of preferred shares that may be authorized for issue at any time cannot exceed more than half of the number of issued and outstanding common shares. We currently have no preferred shares issued.

(thousands of dollars, except shares outstanding and per share amounts)	December 31, 2017			December 31, 2016			December 31, 2015
Shares outstanding		293,238,858			293,238,858			292,912,090
Year-end share price on the TSX		3.81			7.32			5.47
Shares at market		1,117,240			2,146,508			1,602,229
Long-term debt		1,730,437			1,906,934			2,180,510
Less cash		(65,081	)		(115,705	)		(444,759	)
Enterprise value		2,782,596			3,937,737			3,337,980

Because of the nature of our business, we are required to make estimates about the future that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent liabilities. Estimates are based on our past experience, our best judgment and assumptions we think are reasonable.

Our significant accounting policies are described in Note 3 to the Consolidated Financial Statements. We believe the following are the most difficult, subjective or complex judgments, and are the most critical to how we report our financial position and results of operations:

Long-lived assets, which include property, plant and equipment, intangibles and goodwill, comprise the majority of our assets. The carrying value of these assets is reviewed for impairment periodically or whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. For property, plant and equipment, this requires us to forecast future cash flows to be derived from the utilization of these assets based on assumptions about future business conditions and technological developments. Significant, unanticipated changes to these assumptions could require a provision for impairment in the future.

For goodwill, we conduct impairment tests annually in the fourth quarter or whenever there is a change in circumstance that indicates that the carrying value may not be recoverable. The recoverability of goodwill requires a calculation of the recoverable amount of the CGU or groups of CGUs to which goodwill has been allocated. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Judgment is required in the aggregation of assets into CGUs. The recoverability calculation requires an estimation of the future cash flows from the CGU or group of CGUs, and judgment is required in projecting cash flows and selecting the appropriate discount rate. We use observable market data inputs to develop a discount rate that we believe approximates the discount rate from market participants.

In deriving the underlying projected cash flows, assumptions must also be made about future drilling activity, margins and market conditions over the long-term life of the assets or CGUs. We cannot predict if an event that triggers impairment will occur, when it will occur or how it will occur, or how it will affect reported asset amounts. Although we believe the estimates are reasonable and consistent with current conditions, internal planning, and expected future operations, such estimations are subject to significant uncertainty and judgment.

Our property, plant and equipment and intangible assets are depreciated and amortized based on estimates of useful lives and salvage values. These estimates consider data and information from various sources, including vendors, industry practice, and our own historical experience, and may change as more experience is gained, market conditions shift, or new technological advancements are made.

Determination of which parts of the drilling rig equipment represent a significant cost relative to the entire rig and identifying the consumption patterns along with the useful lives of these significant parts are matters of judgment. This determination can be complex and subject to differing interpretations and views, particularly when rig equipment comprises individual components for which different depreciation methods or rates are appropriate.

Uncertainties exist with respect to the interpretation of complex tax regulations, changes in tax laws, and the amount and timing of future taxable income. Differences arising between the actual results and the assumptions made, or future changes to such assumptions, could necessitate future adjustments to taxable income and expenses already recorded. We establish provisions, based on reasonable estimates, for possible consequences of audits by the tax authorities of the respective countries in which we operate. The amount of such provisions is based on various factors, such as experience of previous tax audits and differing interpretations of tax regulations by the taxable entity and the responsible tax authority.

We applied the following mandatorily effective amendments to IFRSs in the current year. Outside of additional disclosure requirements, these amendments had no impact on the amounts recorded in our financial statements.

These amendments require an entity to provide disclosures that enable users of financial statements to evaluate changes in liabilities arising from financing activities, including both cash and non-cash changes.

Our liabilities arising from financing activities consist entirely of long-term debt. A reconciliation between opening and closing balances of long-term debt has been provided in Note 11. Consistent with the transition provisions of the amendments, we have not disclosed comparative information for the prior year.

These amendments clarify how an entity should evaluate whether there will be sufficient future taxable profits against which it can utilize a deductible temporary difference.

ACCOUNTING STANDARDS, INTERPRETATIONS AND AMENDMENTS TO EXISTING STANDARDS NOT YET EFFECTIVE

Effective for annual periods beginning on or after January 1, 2018, IFRS 9 replaces IAS 39 Financial Instruments, Recognition and Measurement. IFRS 9 contains three principal classification categories for financial assets: measured at amortized cost, fair value through other comprehensive income and fair value through profit or loss. The classification of financial assets under IFRS 9 is generally based on the business model in which a financial asset is managed and the characteristics of its contractual cash flows. IFRS 9 eliminates the previous IAS 39 categories of held to maturity, loans and receivables and available for sale. Under IFRS 9, derivatives embedded in contracts where the host is a financial asset under the standard are never separated. Instead the hybrid financial instrument as a whole is assessed for classification.

For us, accounts receivable will continue to be classified and measured at amortized cost. Accounts payable and accrued liabilities and long-term debt will also continue to be classified and measured at amortized cost.

IFRS 9 replaces the incurred loss model of IAS 39 with an expected credit loss model. The loss allowance to be recorded against trade receivables is measured as the lifetime expected credit losses. As we have very short credit periods for trade receivables, we do not expect a material adjustment to our allowance for credit losses.

IFRS 9 requires entities to ensure its hedge accounting relationships align with its risk management objectives and strategies and to apply a more qualitative and forward-looking approach to assessing hedge effectiveness. This may allow for more types of instruments and risk components to qualify for hedge accounting.

We do not expect the application of the hedge accounting requirements under IFRS 9 to have a material impact on our consolidated financial statements.

IFRS 9 also introduces expanded disclosure requirements and changes in presentation. These are expected to change the nature and extent of our disclosures about financial instruments. We are drafting the relevant disclosures to reflect the requirements of the new standard.

IFRS 15 establishes a single comprehensive model to address how and when to recognize revenue as well as requiring entities to provide users of financial statements with more informative, relevant disclosures in order to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. It replaces existing revenue recognition guidance including IAS 18 Revenue and IAS 11 Construction Contracts.

The standard provides a principle based five-step model to be applied to all contracts with customers. This five-step model involves identifying the contract(s) with a customer; identifying the performance obligations in the contract; determining the transaction price; allocating the transaction price to the performance obligations in the contract; and recognizing revenue when (or as) the entity satisfies a performance obligation.

Application of this new standard is mandatory for annual reporting periods beginning on or after January 1, 2018.

There are two methods by which the new guidance can be adopted: (1) a full retrospective approach with a restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment recognized in retained earnings as of the date of adoption. We plan to adopt IFRS 15 using the modified retrospective method whereby the cumulative impact of adopting the standard will be recognized in retained earnings as at January 1, 2018 and the comparative periods will not be restated.

We have assessed the estimated impact that the initial application of IFRS 15 will have on our consolidated financial statements. Our evaluation of the new standard included the identification of accounting and disclosure gaps specific to the individual revenue streams of the Corporation, and mapping of the processes to determine whether changes were required to policies, procedures, and controls.

We contract individual drilling rig packages, including crews and support equipment, to our customers. Depending on the customer’s drilling program, contracts may be for a single well, multiple wells or a fixed term. We expect that revenue recognition on these contracts under IFRS 15 will be materially the same as revenue recognition under the existing standard. Revenue from contract drilling services will be recognized over time from spud to rig release, on a daily basis. Operating days are measured through the use of industry standard tour sheets that document the daily activity of the rig. Revenue will be recognized at the applicable average day rate for each well, based on rates specified in each contract.

We also provide services under turnkey contracts, whereby we are required to drill a well to an agreed upon depth under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. Revenue from turnkey drilling contracts is recognized over time using the input method based on costs incurred to date in relation to estimated total contract costs, as that most accurately depicts our performance. As this method is permitted under the new standard, we will continue in its application, and do not expect this to have a significant impact, if any, on our cumulative-effect adjustment.

We also provide directional drilling services, which include the provision of directional drilling equipment, tools and personnel to the wellsite, and performance of daily directional drilling services. We expect that revenue recognition on these contracts under IFRS 15 will be materially the same as revenue recognition under the existing standard. Directional drilling revenue will be recognized over time, upon the daily completion of operating activities. Operating days are to be measured through the use of daily tour sheets. Revenue will be recognized at the applicable day rate, as stipulated in the directional drilling contract.

We provide a variety of well completion and production services including well servicing and snubbing. In general, service rigs do not involve long-term contracts or penalties for termination. We expect that revenue recognition on these contracts under IFRS 15 will be materially the same as revenue recognition under the existing standard. Revenue will be recognized daily. Operating days are measured through daily tour sheets and field tickets. Revenue will be recognized at the applicable daily or hourly rate, as stipulated in the contract.

We also offer a variety of oilfield equipment for rental to our customers. We expect that revenue recognition on these contracts under IFRS 15 will be materially the same as revenue recognition under the existing standard. Rental revenue will be

recognized daily. Rental days are measured through field tickets. Revenue will be recognized at the applicable daily rate, as stipulated in the contract.

Based on its detailed assessment, we do not expect the application of IFRS 15 to result in a material impact to our consolidated financial statements. The actual impact of adopting the standard at January 1, 2018 may differ as the accounting policies are subject to change until we present our first interim financial statements that include the date of initial application.

As a result of the adoption of the new standard, we will be required to include significant disclosures in the financial statements based on the prescribed requirements. These new disclosures will include information regarding the significant judgments used in evaluating how and when revenues are recognized and information related to contract assets and deferred revenues. In addition, IFRS 15 requires that our revenue recognition policy disclosure include additional detail regarding the various performance obligations and the nature, amount, timing, and estimates of revenues and cash flows generated from contracts with customers. We are drafting the relevant disclosures to reflect the requirements of the new standard.

IFRS 16 introduces a comprehensive model for the identification of lease arrangements and accounting treatments for both lessors and lessees. It replaces existing lease guidance including IAS 17 Leases and IFRIC 4 Determining whether an Arrangement contains a Lease. The new standard is effective for annual periods beginning on or after January 1, 2019.

IFRS 16 brings most leases on-balance sheet for lessees under a single model, eliminating the distinction between operating and finance leases. A right-of-use asset and a corresponding liability will be recognized for all leases by the lessee except for short-term leases and leases of low value assets.

Our initial assessment indicates that many of the operating lease arrangements identified in Note 18 will meet the definition of a lease under IFRS 16 and thus be recognized in the statement of financial position as a right-of-use asset with a corresponding liability. In addition, the nature of expenses related to these arrangements will change as the current presentation of operating lease expense will be replaced with a depreciation charge for the right-of use asset and interest expense on the lease liabilities. As well, the classification of cash flows will be impacted as the current presentation of operating lease payments as operating cash flows will be split into financing (principal portion) and operating (interest portion) cash flows under IFRS 16.

Lessor accounting will not significantly change under the new standard. However, some differences may arise upon adoption of IFRS 16 as a result of new guidance on the definition of a lease. Under IFRS 16 a contract is, or contains a lease if the contract conveys control of the use of an identified asset for a period of time in exchange for some form of consideration. We are assessing whether this new guidance will impact the treatment of its drilling rigs under long-term contracts.

We plan to apply IFRS 16 initially on January 1, 2019 using the cumulative effect method whereby the cumulative impact of adopting the standard will be recognized in retained earnings as at January 1, 2019 and the comparative periods will not be restated.

IFRIC 23 clarifies the accounting for uncertainties in income taxes. The interpretation requires the entity to use the most likely amount or the expected value of the tax treatment if it concludes that it is not probable that a particular tax treatment will be accepted. It requires an entity is to assume that a taxation authority with the right to examine any amounts reported to it will examine those amounts and will have full knowledge of all relevant information when doing so.

IFRIC 23 is effective for annual reporting periods beginning on or after 1 January 2019. Earlier application is permitted. The requirements are applied by recognizing the cumulative effect of initially applying them in retained earnings, or in other appropriate components of equity, at the start of the reporting period in which an entity first applies them, without adjusting comparative information. Full retrospective application is permitted, if an entity can do so without using hindsight. We have yet to determine the impact this standard will have on our consolidated financial statements.

Our key business risks are summarized below. Additional information and other risks in business are discussed in our AIF, available on our website (www.precisiondrilling.com).

Our enterprise risk management framework operates at the business and functional levels and is designed to identify, evaluate, and mitigate risks within each of the risk categories below. It leverages the risk framework in each of our businesses, which includes our risk policies, guidelines and review mechanisms.

Our businesses routinely encounter and manage risks, some of which may cause our future results to be different, sometimes materially different, than what we presently anticipate. We describe certain important strategic, operational, financial, and legal and compliance risks. Our response to development in those risk areas and our reactions to material future developments will affect our future results.

We sell our services to oil and natural gas exploration and production companies. Macroeconomic and geopolitical factors associated with oil and natural gas supply and demand are the primary factors driving pricing and profitability in the oilfield services industry. Generally, we experience high demand for our services when commodity prices are relatively high and the opposite is true when commodity prices are low, as is currently the case. The volatility of crude oil and natural gas prices accounts for much of the cyclical nature of the oilfield services business.

The markets for oil and natural gas are separate and distinct. Oil is a global commodity with a vast distribution network, although the differential between benchmarks such as West Texas Intermediate, Western Canadian Select, and European Brent crude oil can fluctuate. As in all markets, when supply, demand, inability to access domestic or export markets and other factors change, so can the spreads between benchmarks. The most economical way to transport natural gas is in its gaseous state by pipeline, and the natural gas market depends on pipeline infrastructure and regional supply and demand. However, developments in the transportation of liquefied natural gas in ocean going tanker ships have introduced an element of globalization to the natural gas market.

Worldwide military, political and economic events, such as conflict in the Middle East, expectations for global economic growth, or initiatives by OPEC and other major petroleum exporting countries, can affect supply and demand for oil and natural gas. Weather conditions, governmental regulation (in Canada and elsewhere), levels of consumer demand, the availability and pricing of alternate sources of energy (including renewal energy initiatives), the availability of pipeline capacity, U.S. and Canadian natural gas storage levels, and other factors beyond our control can also affect the supply of and demand for oil and natural gas and lead to future price volatility.

The North American land drilling industry has been in a deep downturn for over three years, a result of lower commodity prices restricting customer spending and decreasing drilling demand. In 2017, approximately 15,800 wells were started onshore in the U.S., compared to approximately 11,200 in 2016, 20,500 in 2015 and 43,700 in 2014. In 2017, the industry drilled 6,959 wells in western Canada, compared to 3,963 in 2016, 5,241 in 2015 and 10,942 in 2014. According to industry sources, the U.S. average active land drilling rig count was up approximately 76% in 2017, compared to 2016, and the Canadian average active land drilling rig count was up approximately 58% during the same period. However, oil and natural gas prices remained volatile throughout 2017 and could continue at these relatively low levels or lower levels for the foreseeable future. Prices have been negatively affected since late 2014 by a combination of factors, including increased production, the decisions of OPEC and a strengthening in the U.S. dollar relative to most other currencies. These factors have adversely affected, and could continue to adversely affect, the prices of oil and natural gas, which would adversely affect the level of capital spending by our customers and in turn could have a material and adverse effect on our results of operations. As a result of the continued pressure on commodity prices, many of our customers have reduced spending budgets for 2018 compared to periods prior to the downturn, and further reductions in commodity prices or prices remaining at current levels for a prolonged period may result in further reductions in capital budgets in the future. Moreover, the prolonged reduction in oil and natural gas prices has depressed, and may continue to depress, and the availability and pricing of alternative sources of energy may depress, the

overall level of exploration and production activity, resulting in corresponding decline in the demand for our services that has had, could continue to have and may have, as applicable, a material adverse effect on our revenue, cash flow and profitability and restrict our ability to make capital expenditures compared to periods prior to the downturn. In addition, sustained periods with oil and natural gas prices at current or lower levels could also lead to lower future revenues if these prices caused our customers to avoid re-contracting rigs currently under contract, therefore making our Senior Credit Facility financial covenants more difficult to attain.

Lower oil and natural gas prices could also cause our customers to renegotiate, terminate or fail to honour their drilling contracts with us, which could affect the anticipated revenues that support our capital expenditure program and future contracted deliveries of new-build rigs. In addition, lower oil and natural gas prices, lower demand for oilfield services or lower rig utilization could affect the existing fair market value of our rig fleet, which in turn could trigger a write down for accounting purposes. There is no assurance that demands for our services or conditions in the oil and natural gas and oilfield services sector will not decline in the future, and a significant decline in demand could have a material adverse effect on our financial condition.

We have accounts receivable with customers in the oil and natural gas industry and their revenues may be affected by fluctuations in commodity prices. Our ability to collect receivables may be adversely affected by any prolonged weakness in oil and natural gas prices.

Intense price competition and the cyclical nature of the contract drilling industry could have an adverse effect on revenue and profitability

The contract drilling business is highly competitive with many industry participants. We compete for drilling contracts that are usually awarded based on competitive bids. We believe pricing and rig availability are the primary factors potential customers consider when selecting a drilling contractor. We believe other factors are also important, such as the drilling capabilities and condition of drilling rigs, the quality of service and experience of rig crews, the safety record of the contractor and the particular drilling rig, the offering of ancillary services, the ability to provide drilling equipment that is adaptable to and having personnel familiar with new technologies and drilling techniques, and rig mobility and efficiency.

Historically, contract drilling has been cyclical with periods of low demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and increasing dayrates. Periods of excess drilling rig supply intensify the competition and often result in rigs being idle. There are numerous contract drilling companies in the markets where we operate, and an oversupply of drilling rigs can cause greater price competition. Contract drilling companies compete primarily on a regional basis, and the intensity of competition can vary significantly from region to region at any particular time. If demand for drilling services is better in a region where we operate, our competitors might respond by moving suitable drilling rigs in from other regions, reactivating previously stacked rigs or purchasing new drilling rigs. An influx of drilling rigs into a market from any source could rapidly intensify competition and make any improvement in the demand for our drilling rigs short-lived, which could in turn have a material adverse effect on our revenue, cash flow and earnings.

Our business results and the strength of our financial position are affected by our ability to strategically manage our capital expenditure program in a manner consistent with industry cycles and fluctuations in the demand for contract drilling services. If we do not effectively manage our capital expenditures or respond to market signals relating to the supply or demand for contract drilling and oilfield services, it could have a material adverse effect on our revenue, operations and financial condition.

New capital expenditures in the contract drilling industry expose us to the risk of oversupply of equipment

Periods of high demand often lead to higher capital expenditures on drilling rigs and other oilfield services equipment. The number of newer drilling rigs competing for work in markets where we operate has increased as the industry has added new and upgraded rigs. The industry supply of drilling rigs may exceed actual demand because of the relatively long-life span of oilfield services equipment as well as the typically long time from when a decision is made to upgrade or build new equipment to when the equipment is built and placed into service. Excess supply resulting from industry-wide capital expenditures could lead to lower demand for term drilling contracts and for our equipment and services. The additional supply of drilling rigs has intensified price competition in the past and could continue to do so. This could lead to lower rates in the oilfield services industry generally and lower utilization of existing rigs. If any of these factors materialize, it would have an adverse effect on our revenue, cash flow, earnings and asset valuation.

We will need sufficient cash flows in the future to service and repay our debt. Our ability to generate cash in the future is affected to some extent by general economic, financial, competitive and other factors that may be beyond our control. If we need to borrow funds in the future to service our debt, our ability will depend on covenants in the Senior Credit Facility, the 2021 Note Indenture, the 2023 Note Indenture, the 2024 Note Indenture, the 2026 Note indenture and other debt agreements

we may have in the future, and on our credit ratings. We may not be able to access sufficient amounts under the Senior Credit Facility or from the capital markets in the future to pay our obligations as they mature or to fund other liquidity requirements. If we are not able to borrow a sufficient amount or generate enough cash flow from operations to service and repay our debt, we will need to refinance our debt or we will be in default, and we could be forced to reduce or delay investments and capital expenditures or dispose of material assets or issue equity. We may not be able to refinance or arrange alternative measures on favourable terms or at all. If we are unable to service, repay or refinance our debt, it could have a negative impact on our financial condition and results of operations.

Repaying the debt depends on our guarantor subsidiaries generating cash flow and making it available to us by dividend, debt repayment or otherwise. Our guarantor subsidiaries may not be able to, or may not be permitted to, make distributions to allow us to make payments on our debt. Each guarantor subsidiary is a distinct legal entity, and, under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from the subsidiaries. While the agreements governing certain existing debt limits the ability of our subsidiaries to incur consensual restrictions on their ability to pay dividends or make other intercompany payments to us, these limitations are subject to qualifications and exceptions.

A substantial portion of our operations is carried out through subsidiaries, and some of them are not guarantors of our debt. The assets and operations of the non-guarantor subsidiaries are not material, and these subsidiaries do not have any obligation to pay amounts due on the debt or to make funds available for that purpose.

If we do not receive dividends from our guarantor subsidiaries, we may be unable to make the required principal and interest payments, which could have a material adverse effect on our financial position and results of operations.

Customers’ inability to obtain credit/financing could lead to lower demand for our services

Many of our customers require reasonable access to credit facilities and debt capital markets to finance their oil and gas drilling activity. If the availability of credit to our customers is reduced, they may reduce their drilling and production expenditures, thereby decreasing demand for our products and services. A reduction in spending by our customers could adversely affect our operating results and financial condition.

The Senior Credit Facility, the 2021 Note Indenture, the 2023 Note Indenture, the 2024 Note Indenture and the 2026 Note indenture contain a number of covenants which, among other things, restrict us and some of our subsidiaries from conducting certain activities (see Capital Structure – Covenants – Senior Notes on page 38). In the event Consolidated Interest Coverage Ratio (as defined in our four senior note indentures) is less than 2.0:1 for the most recent four consecutive fiscal quarters the senior note indentures restrict our ability to incur additional indebtedness. As at December 31, 2017, our Consolidated Interest Coverage Ratio, as calculated per our senior notes indentures, was 2.16:1.

In addition, we must satisfy and maintain certain financial ratio tests under the Senior Credit Facility (see Capital Structure – Covenants – Senior Credit Facility on page 37). Events beyond our control could affect our ability to meet these tests in the future. If we breach any of the covenants, it could result in a default under the Senior Credit Facility or any of the note indentures. If there is a default under our Senior Credit Facility, the applicable lenders could decide to declare all amounts outstanding under the Senior Credit Facility or any of the note indentures to be due and payable immediately, and terminate any commitments to extend further credit. If there is an acceleration by the lenders and the accelerated amounts exceed a specific threshold, the applicable noteholders could decide to declare all amounts outstanding under any of the note indentures to be due and payable immediately.

At December 31, 2017, we were in compliance with the covenants of the Senior Credit Facility.

Uncertainty as to the position of the United States in respect of world affairs and events

As a result of the 2016 U.S. presidential election and the related change in political agenda, there is continued uncertainty as to the position the United States will take with respect to world affairs and events. This uncertainty may include issues such as U.S. support for existing treaty and trade relationships with other countries, including Canada. The executive branch of the U.S. government has also initiated the renegotiation of the terms of the North American Free Trade Agreement (NAFTA). Implementation by the U.S. of new legislative or regulatory regimes or revisions to NAFTA could impose additional costs on us, decrease U.S. demand for our services or otherwise negatively impact us or our customers, which may have a material adverse effect on our business, financial condition and operations.

Risks and uncertainties associated with our international operations can negatively affect our business

We conduct some of our business in Mexico and the Middle East. Our growth plans contemplate establishing operations in other international regions, including countries where the political and economic systems may be less stable than in Canada or the U.S.

Our international operations are subject to risks normally associated with conducting business in foreign countries, including, but not limited to, the following:

If there is a dispute relating to our international operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be able to subject foreign persons to the jurisdiction of a court in Canada or the U.S.

Government-owned petroleum companies located in some of the countries where we operate now or in the future may have policies, or may be subject to governmental policies, that give preference to the purchase of goods and services from companies that are majority-owned by local nationals. As such, we may rely on joint ventures, license arrangements and other business combinations with local nationals in these countries, which may expose us to certain counterparty risks, including the failure of local nationals to meet contractual obligations or comply with local or international laws that apply to us.

In the international markets where we operate, we are subject to various laws and regulations that govern the operation and taxation of our businesses and the import and export of our equipment from country to country. There may be uncertainty about how these laws and regulations are imposed, applied or interpreted, and they could be subject to change. Since we derive a portion of our revenues from subsidiaries outside of Canada and the U.S., the subsidiaries paying dividends or making other cash payments or advances may be restricted from transferring funds in or out of the respective countries, or face exchange controls or taxes on any payments or advances. We have organized our foreign operations partly based on certain assumptions about various tax laws (including capital gains and withholding taxes), foreign currency exchange, and capital repatriation laws and other relevant laws of a variety of foreign jurisdictions. We believe these assumptions are reasonable; however, there is no assurance that foreign taxing or other authorities will reach the same conclusion. If these foreign jurisdictions change or modify the laws, we could suffer adverse tax and financial consequences.

While we have developed policies and procedures designed to achieve compliance with applicable international laws, we could be exposed to potential claims, economic sanctions or other restrictions for alleged or actual violations of international laws related to our international operations, including anti-corruption and anti-bribery legislation, trade laws and trade sanctions. The Canadian government, the U.S. Department of Justice, the Securities and Exchange Commission (SEC), the U.S. Office of Foreign Assets Control and similar agencies and authorities in other jurisdictions have a broad range of civil and criminal penalties they may seek to impose against corporations and individuals for such violations, including injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs, among other things. While we cannot accurately predict the impact of any of these factors, if any of those risks materialize, it could have a material adverse effect on our reputation, business, financial condition, results of operations and cash flow.

Our and our customer’s operations are subject to numerous environmental laws, regulations and guidelines

Our operations are affected by numerous laws, regulations and guidelines relating to the protection of the environment, including those governing the management, transportation and disposal of hazardous substances and other waste materials. These include those relating to spills, releases and discharges of hazardous substances or other waste materials into the environment, requiring removal or remediation of pollutants or contaminants, and imposing civil and criminal penalties for violations. Some of these apply to our operations and authorize the recovery of natural resource damages by the government, injunctive relief, and the imposition of stop, control, remediation and abandonment orders. In addition, our land drilling operations may be conducted in or near ecologically sensitive areas, such as wetlands that are subject to special protective measures, which may expose us to additional operating costs and liabilities for noncompliance with certain laws. Some environmental laws and regulations may impose strict and, in certain cases joint and several, liability. This means that in some situations we could be exposed to liability as a result of conduct that was lawful at the time it occurred, or conditions caused by prior operators or other third parties, including any liability related to offsite treatment or disposal facilities. The costs arising from compliance with these laws, regulations and guidelines may be material.

Major projects which would benefit our customers, such as new pipelines and other facilities, may be inhibited, delayed or stopped by a variety of factors, including inability to obtain regulatory or governmental approvals or public opposition. In western Canada, delays and/or the inability to obtain necessary regulatory approvals for pipeline projects that would provide additional transportation capacity and access to refinery capacity for our customers has led to downward price pressure on oil and gas produced in western Canada which has depressed, and may continue to depress, the overall exploration and production activity of our customers, resulting in a corresponding decline in the demand for our services that could have a material adverse effect on our revenue, cash flow and profitability.

We maintain liability insurance, including insurance for certain environmental claims, but coverage is limited and some of our policies exclude coverage for damages resulting from environmental contamination. We cannot assure that insurance will continue to be available to us on commercially reasonable terms, that the possible types of liabilities that we may incur will be covered by insurance, or that the dollar amount of the liabilities will not exceed our policy limits. Even a partially uninsured claim, if successful and of sufficient magnitude, could have a material adverse effect on our business, results of operations and prospects.

The subject of energy and the environment has created intense public debate around the world in recent years. Debate is likely to continue for the foreseeable future and could potentially have a significant impact on all aspects of the economy. The trend in environmental regulation has been to impose more restrictions and limitations on activities that may impact the environment. Any regulatory changes that impose additional environmental restrictions or requirements on us, or our customers, could increase our operating costs and potentially lead to lower demand for our services and have an adverse effect on us. For example, there is growing concern about the apparent connection between the burning of fossil fuels and climate change. Laws, regulations or treaties concerning climate change or greenhouse gas emissions can have an adverse impact on the demand for oil and natural gas, which could have a material adverse effect on us.

Governments in Canada and the U.S. are also considering more stringent regulation or restriction of hydraulic fracturing, a technology used by most of our customers that involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production.

Increasing regulatory restrictions could have a negative impact on the exploration of unconventional energy resources, which are only commercially viable with the use of hydraulic fracturing. Laws relating to hydraulic fracturing are in various stages of development at levels of governments in markets where we operate and the outcome of these developments and their effect on the regulatory landscape and the contract drilling industry is uncertain. Hydraulic fracturing laws or regulations that cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our services could have a material adverse effect on our operations and financial results.

Standards for accident prevention in the oil and natural gas industry are governed by service company safety policies and procedures, accepted industry safety practices, customer-specific safety requirements, and health and safety legislation. Safety is a key factor that customers consider when selecting an oilfield services company. A decline in our safety performance could result in lower demand for services, and this could have a material adverse effect on our revenue, cash flow and earnings.

We are subject to various health and safety laws, rules, legislation and guidelines which can impose material liability, increase our costs or lead to lower demand for our services.

We source certain key rig components, raw materials, equipment and component parts from a variety of suppliers in Canada, the U.S. and overseas. We also outsource some or all construction services for drilling and service rigs, including new-build rigs, as part of our capital expenditure programs. We maintain relationships with several key suppliers and contractors and an inventory of key components, materials, equipment and parts. We also place advance orders for components that have long lead times. We may, however, experience cost increases, delays in delivery due to strong activity or financial hardship of suppliers or contractors, or other unforeseen circumstances relating to third parties. If our current or alternate suppliers are unable to deliver the necessary components, materials, equipment, parts and services we require for our businesses, including the construction of new-build drilling rigs, it can delay service to our customers and have a material adverse effect on our revenue, cash flow and earnings.

Acquisitions entail numerous risks and may disrupt our business or distract management

We consider and evaluate acquisitions of, or significant investments in, complementary businesses and assets as part of our business strategy. Acquisitions involve numerous risks, including unanticipated costs and liabilities, difficulty in integrating the operations and assets of the acquired business, the ability to properly access and maintain an effective internal control environment over an acquired company to comply with public reporting requirements, potential loss of key employees and customers of the acquired companies, and an increase in our expenses and working capital requirements. Any acquisition could have a material adverse effect on our operating results, financial condition or the price of our securities.

We may incur substantial debt to finance future acquisitions and also may issue equity securities or convertible securities for acquisitions. Debt service requirements could be a burden on our results of operations and financial condition. We would also be required to meet certain conditions to borrow money to fund future acquisitions. Acquisitions could also divert the attention of management and other employees from our day-to-day operations and the development of new business opportunities. Even if we are successful in integrating future acquisitions into our operations, we may not derive the benefits, such as operational or administrative synergies, we expect from acquisitions, which may result in us committing capital resources and not receiving the expected returns. In addition, we may not be able to continue to identify attractive acquisition opportunities or successfully acquire identified targets.

New technology could reduce demand for certain rigs or put us at a competitive disadvantage

Complex drilling programs for the exploration and development of conventional and unconventional oil and natural gas reserves demand high performance drilling rigs. The ability of drilling rig service providers to meet this demand depends on continuous improvement of existing rig technology, such as drive systems, control systems, automation, mud systems and top drives, to improve drilling efficiency. Our ability to deliver equipment and services that meet customer demand is essential to our continued success. We cannot guarantee that our rig technology will continue to meet the needs of our customers, especially as rigs age and technology advances, or that our competitors will not develop technological improvements that are more advantageous, timely, or cost effective.

Our operations face many hazards inherent in the drilling and well servicing industries, including blowouts, cratering, explosions, fires, loss of well control, loss of hole, reservoir damage, loss of directional control, damaged or lost equipment, and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage, damage to the property of others, and damage to producing or potentially productive oil and natural gas formations that we drill through.

Generally, drilling and service rig contracts separate the responsibilities of a drilling or service rig company and the customer, and we try to obtain indemnification from our customers by contract for some of these risks even though we also have insurance coverage to protect us. We cannot assure, however, that any insurance or indemnification agreements will adequately protect us against liability from all the consequences described above. If there is an event that is not fully insured or indemnified against, or a customer or insurer does not meet its indemnification or insurance obligations, it could result in substantial losses. In addition, we may not be able to get insurance to cover any or all these risks, or the coverage may not be adequate. Insurance premiums or other costs may rise significantly in the future, making the insurance prohibitively expensive or uneconomic. Significant events, including terrorist attacks in the U.S., severe hurricane damage and well blowout damage in the U.S. Gulf Coast region, have resulted in significantly higher insurance costs, deductibles and coverage restrictions. When we renew our insurance, we may decide to self-insure at higher levels and assume increased risk in order to reduce costs associated with higher insurance premiums.

Seasonal weather patterns in Canada and the northern U.S. affect activity in the oilfield services industry. During the spring months, wet weather and the spring thaw make the ground unstable, so municipalities and counties and provincial and state transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment. This reduces activity and highlights the importance of the location of our equipment prior to the imposition of the road bans. The timing and length of road bans depend on weather conditions leading to the spring thaw and during the thawing period.

Additionally, certain oil and natural gas producing areas are located in parts of western Canada that are only accessible during the winter months because the ground surrounding or containing the drilling sites in these areas consists of terrain known as muskeg. Rigs and other necessary equipment cannot cross this terrain to reach the drilling site until the muskeg freezes. Moreover, once the rigs and other equipment have been moved to a drilling site, they may become stranded or be unable to move to another site if the muskeg thaws unexpectedly. Our business activity depends, at least in part, on the severity and duration of the winter season.

Global climate change could impact the timing and length of the spring thaw and the period in which the muskeg freezes and thaws and it could impact the severity of winter, which could adversely affect our business and operating results. We cannot; however, estimate the degree to which climate change could impact our business and operating results.

Our U.S. and international operations have revenue, expenses, assets and liabilities denominated in currencies other than the Canadian dollar, and are mostly in U.S. dollars and currencies that are pegged to the U.S. dollar. This means that currency exchange rates can affect our income statement, balance sheet and statement of cash flow.

When preparing our consolidated financial statements, we translate the financial statements for foreign operations that do not have a Canadian dollar functional currency into Canadian dollars. We translate assets and liabilities at exchange rates in effect at the period end date. We translate revenues and expenses using average exchange rates for the month of the transaction. We initially recognize gains or losses from these translation adjustments in other comprehensive income, and reclassify them from equity to net earnings on disposal or partial disposal of the foreign operation. Changes in currency exchange rates could materially increase or decrease our foreign currency-denominated net assets, which would increase or decrease shareholders’ equity. Changes in currency exchange rates will affect the amount of revenues and expenses we record for our U.S. and international operations, which will increase or decrease our net earnings. If the Canadian dollar strengthens against the U.S. dollar, the net earnings we record in Canadian dollars from our U.S. and international operations will be lower.

We have long-term debt denominated in U.S. dollars. We have designated our U.S. dollar denominated unsecured senior notes as a hedge against the net asset position of our U.S. and foreign operations. This debt is converted at the exchange rate in effect at the period end dates with the resulting gains or losses included in the statement of comprehensive income. If the Canadian dollar strengthens against the U.S. dollar, we will incur a foreign exchange gain from the translation of this debt. Similarly, if the Canadian dollar weakens against the U.S. dollar, we will incur a foreign exchange loss from the translation of this debt. The vast majority of our international operations are transacted in U.S. dollars or U.S. dollar-pegged currencies. Transactions for our Canadian operations are primarily transacted in Canadian dollars. We occasionally purchase goods and supplies in U.S. dollars for our Canadian operations, and we maintain U.S. dollar cash in our Canadian operations.

We may need to obtain additional debt or equity financing in the future to support ongoing operations, undertake capital expenditures, repay existing or future debt (including the Senior Credit Facility, the 2021 Notes, the 2023 Notes, the 2024 Notes and the 2026 Notes), or pursue acquisitions or other business combination transactions. Volatility or uncertainty in the credit markets may increase costs associated with issuing debt or equity, and there is no assurance that we will be able to access additional financing when we need it, or on terms we find acceptable or favourable. If we are unable to obtain financing to support ongoing operations or to fund capital expenditures, acquisitions, debt repayments, or other business combination transactions, it could limit growth and may have a material adverse effect on our revenue, cash flow and profitability.

Risks associated with turnkey drilling operations could adversely affect our business

We earn some of our revenue from turnkey drilling contracts. We expect that turnkey drilling will continue to be part of our service offering; however, turnkey contracts pose substantially more risk than wells drilled on a daywork basis. Under a typical turnkey drilling contract, we agree to drill a well for a customer to a specified depth and under specified conditions for a fixed price. We typically provide technical expertise and engineering services, as well as most of the equipment required for the drilling of turnkey wells, and use subcontractors for related services. We typically do not receive progress payments and are entitled to payment by the customer only after we have met the full terms of the drilling contract. We sometimes encounter difficulties on wells and incur unanticipated costs, and not all the costs are covered by insurance. As a result, under turnkey contracts we assume most of the risks associated with drilling operations that are generally assumed by customers under a daywork contract. Operating cost overruns or operational difficulties on turnkey jobs could have a material adverse effect on our financial position and results of operations.

The timing and amount of capital expenditures we incur will directly affect the amount of cash available to us. The cost of equipment generally escalates as a result of high input costs during periods of high demand for our drilling rigs and oilfield services equipment and other factors. There is no assurance that we will be able to recover higher capital costs through rate increases to our customers.

A successful challenge by the tax authorities of expense deductions could negatively affect the value of our common shares

Taxation authorities may not agree with the classification of expenses we or our subsidiaries have claimed, or they may challenge the amount of interest expense deducted. If the taxation authorities successfully challenge our classifications or deductions, it could have an adverse effect on our return to shareholders.

Losing key management could reduce our competitiveness and prospects for future success

Our future success and growth depends partly on the expertise and experience of our key management. There is no assurance that we will be able to retain key management. Losing these individuals could have a material adverse effect on our operations and financial condition.

Our assessment of goodwill or capital assets for impairment may result in a non-cash charge against our consolidated net income

We are required to assess our goodwill balance for impairment at least annually, and our capital assets balance for impairment when certain internal and external factors indicate the need for further analysis. We calculate impairment based on management’s estimates and assumptions. We may consider several factors, including any declines in our share price and market capitalization, lower future cash flow and earnings estimates, significantly reduced or depressed markets in our industry, and general economic conditions, among other things. Any impairment write down to goodwill or capital assets would result in a non-cash charge against net earnings, and it could be material.

Credit ratings affect our financing costs, liquidity and operations over the long term and are intended as an independent measure of the credit quality of long-term debt. Credit ratings affect our ability to obtain short and long-term financing and the cost of this financing, and our ability to engage in certain business activities cost-effectively.

If a rating agency reduces its current rating on our debt, or downgrades us, or we experience a negative change in our ratings outlook, it could have an adverse effect on our financing costs and access to liquidity and capital.

Several factors can cause volatility in our share price, including increases or decreases in revenue or earnings, changes in revenue or earnings estimates by the investment community, failure to meet analysts’ expectations, changes in credit ratings, and speculation in the media or investment community about our financial condition or results of operations. General market conditions and Canadian, U.S. or international economic factors and political events unrelated to our performance may also affect the price of our common shares. Investors should therefore not rely on past performance of our common shares to predict the future performance of our common shares or financial results.

We may issue additional common shares in the future to fund our needs or those of other entities owned directly or indirectly by us, as authorized by the Board. We do not need shareholder approval to issue additional common shares, and shareholders do not have any pre-emptive rights related to share issues (see Capital Structure on page 37).

Any difficulty in retaining, replacing, or adding personnel could adversely affect our business

Our ability to provide reliable services depends on the availability of well-trained, experienced crews to operate our field equipment. We must also balance our need to maintain a skilled workforce with cost structures that fluctuate with activity levels. We retain the most experienced employees during periods of low utilization by having them fill lower level positions on field crews. Many of our businesses experience manpower shortages in peak operating periods, and we may experience more severe shortages if the industry adds more rigs, oilfield services companies expand and new companies enter the business.

We may not be able to find enough skilled labour to meet our needs, and this could limit growth. We may also have difficulty finding enough skilled and unskilled labour in the future if demand for our services increases. Shortages of qualified personnel have occurred in the past during periods of high demand. The demand for qualified rig personnel generally increases with stronger demand for land drilling services and as new and refurbished rigs are brought into service. Increased demand typically leads to higher wages that may or may not be reflected in any increases in service rates.

Other factors can also affect our ability to find enough workers to meet our needs. Our business requires skilled workers who can perform physically demanding work. Volatility in oil and natural gas activity and the demanding nature of the work, however, may prompt workers to pursue other kinds of jobs that offer a more desirable work environment and wages competitive to ours. Our success depends on our ability to continue to employ and retain skilled technical personnel and qualified rig personnel. If we are unable to, it could have a material adverse effect on our operations.

Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. Cybersecurity attacks could include, but are not limited to, malicious software, attempts to gain unauthorized access to data and the unauthorized release, corruption or loss of data and personal information, account takeovers, and other electronic security breaches that could lead to disruptions in our critical systems. Risks associated with these attacks include, among other things, loss of intellectual property, disruption of our and our customers’ business operations and safety procedures, loss or damage to our data delivery systems, unauthorized disclosure of personal information and increased costs to prevent, respond to or mitigate cybersecurity events. Although we use various procedures and controls to mitigate our exposure to such risk, cybersecurity attacks are evolving and unpredictable. The occurrence of such an attack could go unnoticed for a period of time. Any such attack could have a material adverse effect on our business, financial condition and results of operations.

As a foreign private issuer in the U.S., we may file less information with the SEC than a company incorporated in the U.S.

As a foreign private issuer, we are exempt from certain rules under the United States Exchange Act of 1934 (the Exchange Act) that impose disclosure requirements, as well as procedural requirements, for proxy solicitations under Section 14 of the Exchange Act. Our directors, officers and principal shareholders are also exempt from the reporting and short-swing profit recovery provisions of Section 16 of the Exchange Act. We are not required to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act, nor are we generally required to comply with Regulation FD, which restricts the selective disclosure of material non-public information. As a result, there may be less publicly available information about us than U.S. public companies and this information may not be provided as promptly. In addition, we are permitted, under a multi-jurisdictional disclosure system adopted by the U.S. and Canada, to prepare our disclosure documents in accordance with Canadian disclosure requirements, including preparing our financial statements in accordance with International Financial Reporting Standards (IFRS), which differs in some respects from U.S. GAAP. We are required to assess our foreign private issuer status under U.S. securities laws annually at the end of the second quarter. If we were to lose our status as a foreign private issuer under U.S. securities laws, we would be required to fully comply with U.S. securities and accounting requirements.

We have retained all liabilities of our predecessor companies, including liabilities relating to corporate and income tax matters.

We may become a passive foreign investment company, which could result in adverse U.S. tax consequences to U.S. investors

Management does not believe that we are or will be treated as a passive foreign investment company (PFIC) for U.S. tax purposes. However, because PFIC status is determined annually and will depend on the composition of our income and assets from time to time, it is possible that we could be considered a PFIC in the future. This could result in adverse U.S. tax consequences to a U.S. investor. In particular, a U.S. investor would be subject to U.S. federal income tax at ordinary income rates, plus a possible interest charge, for any gain derived from a disposition of common shares, as well as certain distributions by us. In addition, a step-up in the tax basis of our common shares would not be available if an individual holder dies.

An investor who acquires 10% or more of our common shares may be subject to taxation under the controlled foreign corporation (CFC) rules.

Under certain circumstances, a U.S. person who directly or indirectly owns 10% or more of the voting power of a foreign corporation that is a CFC (generally, a foreign corporation where 10% of the U.S. shareholders own more than 50% of the voting power or value of the stock of the foreign corporation) for 30 straight days or more during a taxable year and who holds any shares of the foreign corporation on the last day of the corporation’s tax year must include in gross income for U.S. federal income tax purposes its pro rata share of certain income of the CFC even if the share is not distributed to the person. We are not currently a CFC, but this could change in the future.

We maintain internal control over financial reporting that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a – 15(f) and 15d – 15(f) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act) and under National Instrument 52-109 Certification of Disclosure in Issuer’s Annual and Interim Filings (NI 52-109).

Management, including the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO), has conducted an evaluation of our internal control over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013).

Based on management’s assessment as of December 31, 2017, management has concluded that our internal control over financial reporting is effective.

The effectiveness of internal control over financial reporting as of December 31, 2017 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their Report of Independent Registered Public Accounting Firm, which is included in this annual report.

Due to its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of our financial statements would be prevented or detected. Further, the evaluation of the effectiveness of internal control over financial reporting was made as of a specific date, and continued effectiveness in future periods is subject to the risks that controls may become inadequate.

We maintain disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed in our interim and annual filings is reviewed, recognized and disclosed accurately and in the appropriate time period.

Management, including the CEO and CFO, carried out an evaluation, as of December 31, 2017, of the effectiveness of the design and operation of Precision’s disclosure controls and procedures, as defined in Rule 13a – 15(e) and 15d – 15(e) under the Exchange Act and NI 52-109. Based on that evaluation, the CEO and CFO have concluded that the design and operation of Precision’s disclosure controls and procedures were effective to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act or Canadian securities legislation is recorded, processed, summarized and reported within the time periods specified in the rules and forms therein.

It should be noted that while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that these disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

2017 Strategic Priorities		2017 Results
Deliver High Performance, High Value service offerings in an improving demand environment while demonstrating fixed cost leverage.		Delivered 99.56% and 98.97% uptime in Canada and the U.S. respectively Reduced general and administrative costs by approximately $18 million representing a 16% year-over-year decrease Maintained a stable corporate headcount notwithstanding a 64% increase in North American drilling activity Achieved a near record low operating cost per utilization day in the U.S. in the third quarter Achieved a 1.14 Total Recordable Incident Rate (TRIR) and 282 Triple Target Zero Days with no life altering incidents.
Commercialize rig automation and efficiency-driven technologies across our Super Series fleet.		Installed and ran 20 Process Automation Control systems on our rigs and drilled 154 wells in 2017 utilizing the technology Drilled 57 wells in 2017 using a Directional Guidance System, 30% of which were integrated jobs with a reduced crew Remained the industry leader in utilizing wired drill pipe having drilled over 95% of wells on land utilizing this technology Initiated the implementation of a new ERP system aimed at driving increased operating efficiencies, improving our fixed cost leverage and positioning the organization to better handle increased data flows.
Maintain strict financial discipline in pursuing growth opportunities with a focus on free cash flow and debt reduction.		Generated $184 million of funds from operations, see Non-GAAP Measures on page 3 In 2017 we added 29 contracts greater than six months, the majority of which were linked to covering the capital investment for upgrades Reduced long-term debt by $52 million utilizing cash on hand following a $213 million reduction in 2016 Extended the earliest maturity of our long-term debt by 13 months to December 2021 Maintained modest capital plan in 2017 with actual spend $40 million below initial plan Extended the maturity of our Senior Credit Facility to November 2021 to reinforce strong liquidity position.

At December 31 (thousands of dollars)	2017			2016			2015
Cash from operations		116,555			122,508			517,016
Cash used in investing		(91,150	)		(213,925	)		(541,102	)
Surplus (deficit)		25,405			(91,417	)		(24,086	)
Cash used in financing		(73,784	)		(218,324	)		(84,044	)
Effect of exchange rate changes on cash		(2,245	)		(19,313	)		(61,408	)
Net cash used		(50,624	)		(329,054	)		(46,722	)

	March 9, 2018		December 31, 2017		December 31, 2016		December 31, 2015
Shares outstanding		293,238,858		293,238,858		293,238,858		292,912,090
Deferred shares outstanding		195,743		195,743		195,743		195,743
Share options outstanding		11,577,331		10,458,981		11,525,742		10,750,833

MD&A Management’s Discussion and Analysis		This management’s discussion and analysis (MD&A) contains information to help you understand our business and financial performance. Information is as of March 9, 2018. This MD&A focuses on our Consolidated Financial Statements and Notes and includes a discussion of known risks and uncertainties relating to our business and the oilfield services sector. It does not, however, cover the potential effects of general economic, political, governmental and environmental events, or other events that could affect us in the future. You should read this MD&A with the accompanying audited Consolidated Financial Statements and Notes, which have been prepared in accordance with International Financial Reporting Standards (IFRS) and with the information in Cautionary Statement About Forward-Looking Information and Statements on page 2. The terms we, us, our, Precision Drilling and Precision mean Precision Drilling Corporation and our subsidiaries and include any partnerships that we and/or our subsidiaries, of which we are part. All amounts are in Canadian dollars unless otherwise stated.

	Precision Drilling Corporation 2017

	Moody’s	S&P	Fitch
Corporate credit rating	B2	BB	B+
Senior Credit Facility rating	Not rated	Not rated	BB+
Senior unsecured credit rating	B3	BB	BB-