EX-99.2

Headquartered in Calgary, Alberta, Canada, we are Canada’s largest oilfield services company and one of the largest in the U.S. We also have operations in Mexico and the Middle East.

Our shares trade on the Toronto Stock Exchange, under the symbol PD, and on the New York Stock Exchange, under the symbol PDS.

Vision

Our vision is to be globally recognized as the High Performance, High Value provider of land drilling and related services.

You can read about our strategic priorities on page 22.

STRENGTH AND FLEXIBILITY

From our founding as a private drilling contractor in the 1950s, Precision has grown to become one of the most active drillers in North America. Our strength and flexibility are underpinned by four distinguishing features:

¡   a competitive operating model that drives efficiency, quality and cost control

¡   size and scale of operations that provide higher margins and better service capabilities

¡   liquidity that allows us to take advantage of business cycle opportunities

¡   a capital structure that provides long-term stability and flexibility.

EX-99.2 8 d882522dex992.htm EX-99.2 EX-99.2

Exhibit 99.2









MD&A		This management’s discussion and analysis (MD&A) contains information to help you understand our business and financial performance. Information is as of March 6, 2015. This MD&A focuses on our consolidated financial statements and includes a discussion of known risks and uncertainties relating to 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 3. We adopted IFRS effective January 1, 2011, and restated our 2010 results at that time. The terms we, us, our, Precision Drilling and Precision mean Precision Drilling Corporation and our consolidated subsidiaries, and include any partnerships that we and/or our subsidiaries are part of. All amounts are in Canadian dollars unless otherwise stated.
Management’s Discussion and Analysis

	Precision Drilling Corporation 2014



		2		Management’s Discussion and Analysis

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING INFORMATION AND STATEMENTS

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”).

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

the expected use of the net proceeds from our private offering of 5.25% Senior Notes

the potential development of the LNG export sector in Canada and the U.S. and its potential to serve as a catalyst for future natural gas drilling activity

continuing customer demand for Tier 1 drilling rigs

international expansion plans

our capital expenditure plans including the amounts to be allocated for expansion capital, upgrades and sustaining and infrastructure expenditures

the number of new build rigs to be delivered to customers including timing of delivery

the plans to add a training rig to our Nisku facility

our strategic priorities for 2015, which includes growing our integrated directional drilling service under the Schlumberger alliance

amendments to IFRS and their expected impact on our financial statements.

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

our ability to continue to make advances in drilling and completion techniques and make efficiency gains

our ability to react to customers’ spending plans as a result of the recent decline in oil prices

the status of current negotiations with our customers and vendors

Tier 1 rigs remaining best suited for the drilling of the majority of unconventional wells

increasing demand for integrated directional drilling capabilities

our ability to deliver rigs to customers on a timely basis

the general stability of the economic and political environment in the jurisdictions where we operate.



						Precision Drilling Corporation 2014 Annual Report		3

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, the following:

volatility in the price and demand for oil and natural gas

fluctuations in customer spending and its impact on the demand for contract drilling, well servicing and ancillary oilfield services

the risks associated with our investments in capital assets and changing technology

shortages, delays and interruptions in the delivery of equipment, supplies and other key inputs

the effects of seasonal and weather conditions on operations and facilities

the availability of qualified personnel and management

the existence of competitive operating risks inherent in our businesses

changes in environmental and safety rules or regulations including increased regulatory scrutiny on horizontal drilling and hydraulic fracturing

terrorism, social, civil and political unrest in the foreign jurisdictions where we operate

fluctuations in foreign exchange, interest rates and tax rates

other unforeseen conditions which could impact the use of services supplied by Precision and Precision’s ability to respond to such conditions

other risks and uncertainties set out in this MD&A under the heading Risks in our Business.

You are cautioned that the foregoing list of risk factors is not exhaustive. Other risks and uncertainties are set out in reports on file with applicable securities regulatory authorities, including but not limited to our annual information form (AIF) for the year ended December 31, 2014, which may be accessed on Precision’s SEDAR profile on SEDAR (www.sedar.com) or under Precision’s EDGAR 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 applicable securities law.



		4		Management’s Discussion and Analysis

ADDITIONAL GAAP MEASURES

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.

Adjusted EBITDA

We believe that Adjusted EBITDA (earnings before income taxes, finance charges, foreign exchange, impairment of goodwill, loss on asset decommissioning, and depreciation and amortization), as reported in the Consolidated Statement of Earnings, 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 excluding the impact of foreign exchange, taxation, non-cash depreciation, amortization and impairment charges, and non-cash decommissioning charges.

Operating Earnings

We believe that operating earnings, as reported in the Consolidated Statement of Earnings, 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 excluding the impact of foreign exchange and taxation.

Funds Provided by Operations

We believe that funds provided by operations, as reported in the Consolidated Statement 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.



						Precision Drilling Corporation 2014 Annual Report		5








								Management’s
								Discussion and
								Analysis
		About Precision

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



		6		Management’s Discussion and Analysis

TWO BUSINESS SEGMENTS

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

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						Precision Drilling Corporation 2014 Annual Report		7

Contract Drilling Services

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 the second largest land drilling contractor in North America, servicing approximately 23% of the active land drilling market in Canada and 5% of the active U.S. market. We also have an international presence with operations in Mexico and the Middle East.

At December 31, 2014, our Contract Drilling Services segment consisted of:

313 land drilling rigs, including:

– 174 in Canada

– 124 in the U.S.

– 6 in Mexico

– 4 in Saudi Arabia

– 2 in Kuwait

– 2 in the Kurdistan region of Iraq

– 1 in the country of Georgia

capacity for approximately 88 concurrent directional drilling jobs in Canada and the U.S.

engineering, manufacturing and repair services primarily for Precision’s operations

centralized procurement, inventory and distribution of consumable supplies for our global operations.

Drilling Rigs at December 31, 2014


Horsepower	< 1000		1000-1500		>1500		Total
Tier 1		95		115		7		217
Tier 2		39		20		15		74
PSST ⁽¹⁾		14		4		4		22
Total		148		139		26		313

Geographic location	Canada		U.S.		International		Total
Tier 1		119		93		5		217
Tier 2		41		23		10		74
PSST ⁽¹⁾		14		8		–		22
Total		174		124		15		313

⁽¹⁾ Precision seasonal, stratification and turnkey rigs.

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		8		Management’s Discussion and Analysis

Completion and Production Services

We provide completion and workover services and ancillary services and equipment rentals to oil and natural gas exploration and production companies primarily in Canada, with a presence in the U.S.

On an operating hour basis in 2014, we serviced approximately 11% of the well completion and workover service rig market demand in Canada.

At December 31, 2014, our Completion and Production Services segment consisted of:

156 well completion and workover service rigs, including:

– 148 in Canada

– 8 in the U.S.

17 snubbing units in Canada

4 coil tubing units in Canada

approximately 2,600 oilfield rental items including surface storage, small-flow wastewater treatment, power generation, and solids control equipment primarily in Canada

221 wellsite accommodation units in Canada and 65 in the U.S.

50 drilling camps and four base camps in Canada

10 large-flow wastewater treatment units, 25 pump houses and eight potable water production units in Canada.

Service Rig Fleet as at December 31, 2014


Type	2010		2011		2012		2013		2014
Well Completion and Workover Service
Singles:
Freestanding mobile		94		90		90		90		74
Doubles:
Mobile		25		19		19		19		7
Freestanding mobile		35		40		40		40		41
Skid		28		22		22		22		14
Slants:
Freestanding		18		18		19		20		20
Total service rigs		200		189		190		191		156
Snubbing units		20		18		19		19		17
Coil tubing units		–		–		5		12		4
Total service rigs, snubbing units and coil tubing units		220		207		214		222		177

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						Precision Drilling Corporation 2014 Annual Report		9








								Management’s
								Discussion and
								Analysis
		2014 Highlights and Outlook

Adjusted EBITDA and funds provided by operations are additional GAAP measures. See page 5 for more information.

Financial Highlights


Year ended December 31 (thousands of dollars, except where noted)	2014		% increase/ (decrease	)	2013		% increase/ (decrease	)	2012		% increase/ (decrease	)
Revenue	2,350,538		15.8		2,029,977		(0.5	)	2,040,741		4.6
Adjusted EBITDA	800,370		25.3		638,833		(4.8	)	670,792		(3.5	)
Adjusted EBITDA % of revenue	34.1%				31.5%				32.9%
Net earnings	33,152		(82.7	)	191,150		265.1		52,360		(72.9	)
Cash provided by operations	680,159		58.9		428,086		(32.6	)	635,286		19.2
Funds provided by operations	697,474		51.0		461,973		(22.9	)	598,812		1.1
Investing activities
Capital spending
Expansion	571,383		102.5		282,145		(52.7	)	596,194		30.9
Upgrade	136,475		(3.3	)	141,132		8.5		130,094		(13.2	)
Maintenance and infrastructure	148,832		32.3		112,527		(20.6	)	141,769		16.9
Proceeds on sale	(101,826	)	661.5		(13,372	)	(57.4	)	(31,423	)	96.6
Net capital spending	754,864		44.5		522,432		(37.6	)	836,634		17.8
Business acquisitions (net of cash acquired)	–		–		–		(100.0	)	25		(100.0	)
Earnings per share ($)
Basic	0.11		(84.1	)	0.69		263.2		0.19		(72.9	)
Diluted	0.11		(83.3	)	0.66		266.7		0.18		(73.1	)
Dividends per share ($)	0.25		19.0		0.21		320.0		0.05		n/m
n/m – calculation not meaningful.
Operating Highlights
Year ended December 31	2014		% increase/ (decrease	)	2013		% increase/ (decrease	)	2012		% increase/ (decrease	)
Contract drilling rig fleet	313		(4.3	)	327		1.9		321		(4.7	)
Drilling rig utilization days
Canada	32,810		7.5		30,530		(5.6	)	32,352		(14.8	)
U.S.	35,075		15.9		30,268		(12.5	)	34,597		(8.7	)
International	4,036		13.5		3,555		70.4		2,086		197.2
Service rig fleet	177		(20.3	)	222		3.7		214		3.4
Service rig operating hours	273,194		(3.7	)	283,576		(3.8	)	294,681		(7.2	)



		10		Management’s Discussion and Analysis

Financial Position and Ratios


(thousands of dollars, except ratios)	December 31, 2014		December 31, 2013		December 31, 2012
Working capital		653,630		305,783		278,021
Working capital ratio		2.3		1.9		1.7
Long-term debt		1,852,186		1,323,268		1,218,796
Total long-term financial liabilities		1,881,275		1,355,535		1,245,290
Total assets		5,308,996		4,579,123		4,300,263
Enterprise value ⁽¹⁾		3,265,865		3,919,763		3,213,406
Long-term debt to long-term debt plus equity ⁽²⁾		0.43		0.36		0.36
Long-term debt to cash provided by operations		2.72		3.09		1.92
Long-term debt to enterprise value		0.57		0.34		0.38

⁽¹⁾

Share price multiplied by the number of shares outstanding plus long-term debt minus working capital. See page 39 for more information.

⁽²⁾

Net of unamortized debt issue costs.

2014 OVERVIEW

Net earnings in 2014 were $33 million, or $0.11 per diluted share, compared to $191 million, or $0.66 per diluted share in 2013. During the year, we recorded a before-tax asset decommissioning charge and goodwill write down totaling $222 million that reduced net earnings by $182 million and net earnings per diluted share by $0.62. Effective January 1, 2014, we began calculating depreciation on our drilling rigs and service rigs on a straight-line basis, which reduced net earnings for the year by approximately $29 million, or $0.10 per diluted share, from what net earnings would have been using the previous depreciation method. We believe that, due to technological developments within the industry, straight-line depreciation better reflects the allocation of the cost of the assets over their expected lives.

Revenue in 2014 was $2,351 million, 16% higher than in 2013, mainly due to improved utilization and higher average pricing in our Contract Drilling Services segment. Contract Drilling Services revenue was up 17%, while revenue from Completion and Production Services was up 6%. Our international drilling activity increased 15% with an average of 15 rigs working in 2014 compared to 13 in 2013.

Adjusted EBITDA in 2014 was $800 million, 25% higher than in 2013. Our Adjusted EBITDA margin was 34%, compared to 31% in 2013. The increase in Adjusted EBITDA margin was mainly the result of higher utilization and improved margin in our Contract Drilling Services segment. Adjusted EBITDA margin for the year in our Contract Drilling Services segment was 41%, compared with 38% in the prior year, while Adjusted EBITDA margin from our Completion and Production segment was 17% compared to a prior year margin of 19%. A competitive industry and fixed costs contributed to the lower margin 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 all help us manage our Adjusted EBITDA margin.

On June 3, 2014, we issued US$400 million of 5.25% Senior Notes due in 2024 in a private offering. The Notes are guaranteed on a senior unsecured basis by current and future U.S. and Canadian subsidiaries that also guarantee our revolving credit facility and certain other indebtedness. We expect to use the net proceeds from this placement for general corporate purposes, including building new drilling rigs.

Drilling activity was robust throughout most of 2014, despite rapidly falling oil prices in the second half of the year. On the strength of oil prices, the industry momentum at the end of 2013 continued into 2014 as customers in North America focused on unconventional oil and natural gas liquids targets. Drilling activity in the Middle East and Mexico was strong throughout 2014, driven primarily by higher oil prices. Natural gas prices were higher for most of the year relative to 2013, but not high enough to encourage increased gas-directed drilling activity.



						Precision Drilling Corporation 2014 Annual Report		11

During the year, we decommissioned 29 drilling rigs, 35 well servicing rigs and two snubbing units and recognized a non-cash pre-tax decommissioning charge of $127 million. Certain components of the decommissioned equipment will be used in our ongoing operations. We also recorded a $95 million impairment charge to the goodwill attributable to Canadian well servicing and the wastewater treatment businesses as it was determined that their carrying values exceeded their recoverable amounts.

In the fourth quarter of 2014, we increased our quarterly dividend to $0.07 per common share.

OUTLOOK

Contracts

Pricing, Demand and Utilization

The demand for energy is highly correlated with global economic growth and has been rising over the past several years with the improvement in the global economic situation. In addition, per capita energy consumption has been increasing in many developing countries. These demand fundamentals, along with the challenges of maintaining or growing global supply, supported stronger oil prices from 2009 through much of 2014. However, in late 2014 the price of crude oil on global markets began declining rapidly as global oversupply drove prices down sharply. For the first three quarters of 2014, West Texas Intermediate (WTI) averaged US$99.82 per barrel while from October 1, 2014 to March 6, 2015 WTI averaged US$63.21 per barrel. WTI closed at US$49.61 per barrel on March 6, 2015.

Natural gas prices have been depressed for a few years, reaching 10-year lows in 2012 before recovering slightly in 2014 to average US$4.33 per MMBtu at Henry Hub. Lower natural gas prices have persisted due to increased production from unconventional resource development, higher than average storage levels, and the lack of an export market from North America. Despite the industry-wide decline in natural gas drilling activity, U.S. production has continued to grow, keeping prices low.

Natural gas demand in North America largely depends on the weather with colder winter temperatures and, to a lesser extent, warmer summer temperatures resulting 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. As well, the potential of liquefied natural gas (LNG) export development in both Canada and the U.S. could serve as a catalyst for natural gas directed drilling activity over the medium to long term.

The oil rig count at March 6, 2015 was 37% lower in the U.S. than it was a year ago, and 61% lower in Canada. Despite declines of over 40% from peak levels in November 2014, the overall North American land oil directed rig count on March 6, 2015 was approximately three times higher than it was on March 6, 2009, supported by unconventional oil drilling in plays such as Bakken, Cardium, Montney, Duvernay, Eagle Ford, Granite Wash, Niobrara and Permian. We expect exploration and production companies drilling unconventional oil and gas wells will continue to seek ways to increase efficiencies and lower costs in their operations, supporting demand for highly efficient Tier 1 drilling rigs.



		12		Management’s Discussion and Analysis

International

We currently have 15 rigs in Mexico and the Middle East, and we plan to deliver another new-build rig to Kuwait in the first half of 2015.

Upgrading the Fleet

We and some of our competitors have been upgrading the drilling rig fleet by building new rigs and upgrading existing rigs. We believe this retooling of the industry-wide fleet has been making Tier 3 rigs virtually obsolete in North America. In the fourth quarter of 2012, we decommissioned 52 rigs from our fleet and exited the conventional Tier 3 contract drilling business. In the fourth quarter of 2014, we decommissioned a further 29 drilling rigs (19 in Canada and 10 in the U.S.). Our focus on the Tier 1 market is aligned with our corporate strategy, customer relationships and competitive position.

Capital Spending

We expect capital spending in 2015 to be approximately $487 million ($481 million in the Contract Drilling Services segment and $6 million in the Completion and Production Services segment):

$370 million for expansion capital, which includes the cost to complete construction of the 17 remaining drilling rigs from the 2014 new-build rig program

$40 million for upgrade capital

$77 million for sustaining and infrastructure expenditures, which is based on currently anticipated activity levels.

Following is a new-build delivery schedule of expected deliveries in 2015. All of the rigs shown on the table below are backed by customer contracts.


					2015
	Q1		Q2		Q3		Q4		Total
Rig Deliveries:
Canada		2		–		1		–		3
U.S.		7		6		–		–		13
International		–		1		–		–		1
		9		7		1		–		17

The 13 rigs for the U.S. are Super Triple rigs and are scheduled to be delivered to multiple unconventional basins for five different customers. The new-build rigs in Canada are ST-1200 rigs for three different customers. The international new-build ST-1500 rig is expected to be delivered to Kuwait in June 2015. As at March 6, 2015, eight of the 17 rigs had been delivered and placed into service.



						Precision Drilling Corporation 2014 Annual Report		13

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		14		Management’s Discussion and Analysis

Management’s

Discussion and

Analysis

Understanding our Business Drivers

THE ENERGY INDUSTRY

Precision operates in the energy services business, which is an inherently challenging cyclical industry. Customer demand depends on the end price for their products: crude oil, natural gas, and natural gas liquids.

We depend on oil and natural gas exploration and production companies to contract our services as part of their development activities. The economics of their business 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.

Commodity Prices

Our customers’ cash flow to fund exploration and development is dependent on commodity prices: higher prices increase cash flow and encourage investment.

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. Oil prices had generally been relatively strong since 2009 as supply and demand fundamentals remained tight. Strong prices contributed to significant drilling activity in North America, resulting in supply growth, particularly from shale plays in the U.S. This activity, combined with slower than expected global demand growth and sustained production levels from OPEC, led to a supply-demand imbalance, which resulted in price deterioration beginning in late 2014 and continuing into 2015.

Natural gas and natural gas liquids continue to be priced regionally. In North America, colder weather late in 2013 and early 2014 increased demand for natural gas, depleting inventories and causing spot prices to rise at the beginning of the year. But as the year progressed, supplies of unconventional natural gas increased and inventories reached levels that are viewed as adequate to keep North American markets well supplied.

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						Precision Drilling Corporation 2014 Annual Report		15

New Technology

Technological advancements in horizontal drilling, fracturing and stimulation have brought about a shift in development from conventional to unconventional natural gas and oil reservoirs. This is giving companies cost-effective access to more complex reservoirs in North America, in existing basins and in new basins that have not been economic in the past.

The following chart shows the consistent trend away from vertical wells to more demanding directional/horizontal well programs, which require higher capacity equipment and greater technical expertise for drilling. These trends are driving the demand for high performing, Tier 1 drilling rigs, which garner premium contract rates.

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These technical innovations have been a major factor in the increase in natural gas production in the U.S., which is becoming less reliant on Canada as a source of natural gas. Natural gas production in Canada has been declining because of lower natural gas directed drilling due to pricing pressure and Canada’s lack of an export market other than the U.S.

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		16		Management’s Discussion and Analysis

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Drilling Activity

The graphs below show that, since 2010, drilling activity in the U.S. and Canada has been shifting from natural gas to oil. The Canadian drilling rig activity graph also shows how Canadian drilling activity fluctuates with the seasons, a market dynamic that in general is not present in the U.S.

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						Precision Drilling Corporation 2014 Annual Report		17

A COMPETITIVE OPERATING MODEL

The contract drilling business is highly competitive, with numerous industry participants. We compete for long-term drilling contracts that are often awarded based on 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 and condition of rigs, quality of rig crews, breadth of service 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 by employing passionate people supported by superior systems and equipment designed to maximize productivity and reduce risks. We create High Value by operating safely, lowering customer risks and costs, developing people, generating financial growth, and attracting investment.

Operating Efficiency

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

using innovative and advanced drilling technology that is efficient and reduces costs

having equipment that is geographically dispersed, reliable and well maintained

monitoring our equipment to minimize mechanical downtime

effectively managing operations to keep non-productive time to a minimum

compensating our executives and eligible employees based on performance against safety, operational, employee retention, and financial measures.

Efficient, Cost-Reducing Technology

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

The versatile Precision Super Series design features technical innovations in safety and drilling efficiency for horizontal wells on a single or multiple well pad. Precision Super Series rigs use extended length drill pipe, an integrated top drive, innovative unitization to facilitate quick moves between well locations, a small footprint to minimize environmental impact, and enhanced safety features such as automated pipe handling with iron roughnecks and remotely operated torque wrenches.

Super Triple electric rigs (ST-1200 and ST-1500) have greater hoisting capacity and are used in deeper exploration and development drilling, while Super Single rigs are used in shallow to medium depth applications. Power capabilities are a major design criterion for Super Triple rigs. Drilling productivity and reliability with AC power drive systems provides added precision and measurability, while a computerized electronic auto driller feature precisely controls weight, rotation and torque on the drill bit.

Broad Geographic Footprint

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



		18		Management’s Discussion and Analysis

Managing Downtime

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 (move, rig-up and rig-out time) by utilizing walking and skidding systems, reducing the number of move loads per rig, having lighter move loads, and using mechanized equipment for safer and quicker rig component connections.

Tracking Our Results

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. And we link incentive compensation for our senior team to returns generated compared to established benchmarks.

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

Safety performance – total recordable incident frequency per 200,000 man-hours. Measured against prior year performance and current year industry performance in Canada and the U.S.

Operational performance – rig down time for repair as measured by time not billed to the customer. Measured against a predetermined target of available billable time.

Key field employee retention – senior field employee retention rates. Measured against predetermined target rates of retention.

Financial performance – Adjusted EBITDA and return on capital employed calculated as a percentage of pre-tax operating earnings divided by total assets less current liabilities. Measured against predetermined targets.

Investment returns – total shareholder return performance, including dividends, against an industry peer group over a three year period. Measured against predetermined competitors in the established peer group.

Top Tier Service

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.

High Performance Rig Fleet

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 oil and natural gas drilling opportunity in North America.

69%

As at December 31, 2014, 69% of our 313 drilling rigs were Tier 1 rigs.

In 2014, we high-graded our drilling rig fleet, as follows:

added 15 Tier 1 new-build drilling rigs, with 17 additional Tier 1 new-build drilling rigs in various stages of completion expected to be delivered by mid 2015

upgraded 12 drilling rigs, half of which were tier upgrades

decommissioned 29 legacy drilling rigs (19 in Canada and 10 in the U.S.).



						Precision Drilling Corporation 2014 Annual Report		19

As at December 31, 2014, 69% of our 313 drilling rigs were Tier 1 rigs.


Tier 1 Rigs are better suited to meet the challenges of complex customer requirements for resource exploitation in North American shale and unconventional plays	High performance Super Series rigs, innovative in design, capable of drilling directionally or horizontally, highly mobile (move with pad walking or skidding systems or require fewer trucking loads) Features


	¡	highly mechanized tubular handling equipment
	¡	integrated top drive or top drive adaptability
	¡	advanced AC, silicone controlled rectifier (SCR) and mechanical power distribution and
		control efficiencies
	¡	electronic or hydraulic control of the majority of operating parameters
	¡	specialized drilling tubulars
	¡	high-capacity mud pumps
	¡	majority use Range III drill pipe
Tier 2 High performance rigs with new equipment and modifications to improve performance and enhance directional and horizontal drilling capability	High performance rigs, capable of drilling directionally or horizontally, generally less mobile than Tier 1 rigs Features

	¡	some mechanization of tubular handling equipment
	¡	top drive adaptability
	¡	SCR or mechanical-type power systems
	¡	increased hookload and or racking capabilities
	¡	upgraded power generating, control systems and other major components
	¡	high-capacity mud pumps
PSST (Precision seasonal, stratification and turnkey)	Acceptable level of performance for certain drilling requirements but would require major equipment upgrades to meet the criteria of a Tier 2 or Tier 1 rig
Typically, conventional mechanical rigs with no automation and lower pumping capacity	¡	Other than 22 rigs retained for seasonal, stratification and turnkey drilling work, we have exited the Tier 3 market. We believe that developments in the land drilling industry have made the Tier 3 rigs virtually obsolete 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 the northern U.S. Service rigs are supported by three field locations in Alberta, two in Saskatchewan, and one in each of 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.

Coil tubing units have the ability to service horizontal wells by pushing the tubing rather than relying on gravity. Coil tubing often works more effectively in the unconventional horizontal wells that are becoming more common. We began using our first coil tubing unit in the first quarter of 2012 and by the end of 2013 we had 12 units operating. However, in the fourth quarter of 2014, we sold our U.S. coil tubing assets for cash consideration of $44 million. Our remaining four coil tubing units continue to serve the Canadian market.

Ancillary Equipment and Services

An inventory of equipment (portable 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 provided by Rostel Industries and for standardization and distribution of consumable oilfield products through Columbia Oilfield Supply in Canada and Precision Supply in the U.S.

Precision Rentals supplies customers with an inventory of specialized equipment and wellsite accommodations. Precision Camp Services supplies meals and provides accommodation for crews at remote oilfield worksites. Terra Water Systems plays an essential role in providing water treatment services as well as potable water production plants for Precision Camp Services and other camp facilities.



		20		Management’s Discussion and Analysis

Systematic Maintenance

We consistently reinvest capital to sustain and upgrade existing property, plant and equipment. We match equipment repair and maintenance expenses to activity levels under our maintenance and certification programs. We use computer systems to track key preventative maintenance indicators for major rig components, record equipment performance history, schedule equipment certifications, reduce downtime, and better manage our assets. We have a continuous maintenance program for essential elements, such as tubulars and engines.

Technical Centres

We operate two contract drilling technical centres, one in Nisku, Alberta and the other in Houston, Texas. We also operate one Completion and Production Services technical centre in Red Deer, Alberta. These centres house our technical service and field training groups and enable us to consolidate support and training for our operations. The Houston facility includes a fully functioning training rig with the latest drilling technologies; a training rig will be added at the Nisku facility in 2015. In addition, our Houston facility houses our rig manufacturing group.

Upgrade Opportunities

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

People


Having an experienced, high performance crew is a competitive strength and highly valued by our customers. There are often shortages of industry manpower in peak operating periods. We rely heavily on our		In 2008, we launched Toughnecks (www.toughnecks.com), our highly successful field recruiting program.
safety record, investment in employee development, and 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. In the U.S., these functions are managed to align with regional labour and customer service requirements.

Systems

Our fully integrated, enterprise-wide reporting system has improved business performance through real-time access to information across all functional areas. All of our divisions operate on a common integrated system using standardized business processes across finance, payroll, equipment maintenance, procurement, and inventory control functions.

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 as economies of scale can be identified and leveraged as construction demands increase.

Safe Operations

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


Safety performance is a fundamental contributor to operating performance and the financial results we generate for our shareholders. We track safety using an industry standard recordable frequency statistic that benchmarks successes and isolates areas for improvement. We		Target Zero Our safety vision for eliminating workplace incidents is a core belief that all injuries can be prevented.
have taken it to another level by tracking and measuring all injuries,
regardless of severity, because they are leading indicators of the potential for a more serious incident. In 2014, 256 of our drilling rigs and 195 of our service rigs achieved Target Zero. We continue to embrace technological advancements that make operations safer.



						Precision Drilling Corporation 2014 Annual Report		21

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:

heat recovery and distribution systems

power generation and distribution

fuel management

fuel type

noise reduction

recycling of used materials

use of recycled materials

efficient equipment designs

spill containment.

AN EFFECTIVE STRATEGY

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

2014 Strategic Priorities

2014 Results

Execute our High Performance, High Value strategy

Invest in our physical and human capital infrastructure to advance field level professional development.

Provide industry leading service to customers and demand safe operations.

Leverage our scale of operations and utilize established systems to promote consistent and reliable service. field level professional development.

Improved safety performance in both operating segments in 2014,

resulting in the best performance in our history.

Completed construction of our Nisku Technical Centre.

Entered into a technology service agreement and marketing alliance with Schlumberger that enables us to market a full range of downhole technology.

Increased the utilization of our centralized U.S. repair and

maintenance facility.

Achieved Target Zero for more than 75% of our drilling rigs and 90% of our service rigs.

Achieved better than predetermined targets for mechanical downtime.

Execute on existing organic growth opportunities

Deliver new-build and upgraded drilling rigs to customer contracts, expand international activity in existing locations and grow our LNG

drilling leadership position.

Be a recognized leader in the integrated directional drilling transformation.

Grow our U.S. presence in Completion and Production Services.

Delivered 15 new-build Super Series rigs to customers on long-term contracts and upgraded 12 existing drilling rigs to higher specification assets under long-term contracts.

Signed customer contracts for the delivery of 17 new-build rigs in 2015.

Seven of the new-build deliveries in 2014 and 2015 are for customers with an ownership interest in resources expected to support potential Canadian LNG exports.

Expanded international operations with rig additions in the Middle East.

Build our brand

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

Delivered strong Canadian and U.S. financial performance throughout 2014 and exceeded employee retention goals across all targeted skill positions.

Increased recognition from U.S. and international investors while retaining strong support from Canadian base.

Our corporate and competitive growth strategies are designed to optimize resource allocation and differentiate us from the competition, generating value for investors. Despite the recent drop in industry activity, long-term we see opportunities for growth in our Contract Drilling Services land drilling rig fleet both in North America and internationally. 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. The completion and production work associated with unconventional wells provides the most profitable growth opportunities for Completion and Production Services.



		22		Management’s Discussion and Analysis

STRATEGIC PRIORITIES FOR 2015

Work with our customers to lower well costs

Deliver High Performance, High Value services to customers to create maximum efficiency and lower risks for development drilling programs.

Utilize our unique platform of Tier 1 assets, geographically diverse operations, and highly efficient service offering to deliver cost-reducing solutions.

Grow our cost-reducing integrated directional drilling service with the Schlumberger alliance.

Maximize cost efficiency throughout the organization

Continue to leverage Precision’s scale to reduce costs and deliver High Performance.

Maximize the benefits of the variable nature of operating and capital costs.

Maintain an efficient corporate cost structure by optimizing systems for assets, people and business management.

Maintain our uncompromising focus on worker safety, premium service quality, and employee development.

Reinforce our competitive advantage

Gain market share as Tier 1 rigs remain most in demand.

High-grade our active rig fleet by delivering new-build rigs and maximizing customer opportunities to utilize High Performance assets.

Deliver consistent, reliable, High Performance service.

Retain and continue to develop the industry’s best people.

Manage liquidity and focus activities on cash flow generation

Monitor working capital, debt and liquidity ratios.

Maintain a scalable cost structure that is responsive to changing competition and market demand.

Adjust capital plans according to utilization and customer demand.

Link executive incentive compensation to our performance.



						Precision Drilling Corporation 2014 Annual Report		23

Management’s

Discussion and

Analysis

2014 Results

Adjusted EBITDA and operating earnings are additional GAAP measures. See page 5 for more information.

Consolidated Statements of Earnings Summary


Year ended December 31 (thousands of dollars)	2014			2013			2012
Revenue
Contract Drilling Services		2,017,110			1,719,910			1,725,240
Completion and Production Services		343,556			323,353			326,079
Inter-segment elimination		(10,128	)		(13,286	)		(10,578	)
		2,350,538			2,029,977			2,040,741
Adjusted EBITDA
Contract Drilling Services		821,490			653,664			649,281
Completion and Production Services		57,954			61,032			93,554
Corporate and Other		(79,074	)		(75,863	)		(72,043	)
		800,370			638,833			670,792

Depreciation and amortization		448,669			333,159			307,525
Loss on asset decommissioning		126,699			–			192,469
Operating earnings		225,002			305,674			170,798
Impairment of goodwill		95,170			–			52,539
Foreign exchange		(946	)		(9,112	)		3,753
Finance charges		109,701			93,248			86,829
Earning before income taxes		21,077			221,538			27,677
Income taxes		(12,075	)		30,388			(24,683	)
Net earnings		33,152			191,150			52,360

Results by Geographic Segment


Year ended December 31 (thousands of dollars)	2014			2013			2012
Revenue
Canada		1,077,814			1,002,199			1,053,966
U.S.		1,096,918			901,246			936,113
International		195,487			137,681			64,017
Inter-segment elimination		(19,681	)		(11,149	)		(13,355	)
		2,350,538			2,029,977			2,040,741
Total assets
Canada		2,434,774			2,082,958			2,119,891
U.S.		2,244,867			2,006,519			1,913,810
International		629,355			489,646			266,562
		5,308,996			4,579,123			4,300,263



		24		Management’s Discussion and Analysis

2014 COMPARED TO 2013

Net earnings in 2014 were $33 million, or $0.11 per diluted share, compared to $191 million, or $0.66 per diluted share, in 2013. During the year, we recorded a before-tax asset decommissioning charge and goodwill write down totaling $222 million that reduced net earnings by $182 million and net earnings per diluted share by $0.62. Effective January 1, 2014, we began calculating depreciation on our drilling rigs and service rigs on a straight-line basis, which reduced net earnings by approximately $29 million, or $0.10 per diluted share, compared with what net earnings would have been using the previous depreciation method.

Revenue was $2,351 million, 16% higher than 2013. The increase was the result of improved utilization and average pricing in our Contract Drilling Services segment.

Adjusted EBITDA in 2014 was $800 million, 25% higher than 2013, primarily because of higher activity levels and higher average pricing in our Contract Drilling Services segment. Activity, as measured by drilling utilization days, increased 8% in Canada, 16% in the U.S., and 14% internationally compared to 2013.

Average Oil and Natural Gas Prices

2014

2013

2012

Oil

West Texas Intermediate (per barrel)

US $93.06

US $98.02

US $94.13

Natural gas

Canada

AECO (per MMBtu)

$4.45

$3.18

$2.39

U.S.

Henry Hub (per MMBtu)

US $4.33

US $3.73

US $2.75

Key Statistics

There were 10,942 wells drilled in western Canada in 2014, consistent with the 10,903 drilled in 2013. Despite only increasing 39 wells, total industry drilling operating days were 9% higher than 2013, at 131,021. Average industry drilling operating days per well was 12.0 compared to 11.0 in 2013. Average depth of a well increased 8%.

Approximately 37,500 wells were started onshore in the U.S., 5% more than the approximately 35,700 wells started in 2013.

Goodwill

Under IFRS, we are required annually to assess the carrying value of our assets in cash generating units containing goodwill. Due to the decrease in oil and natural gas well drilling in Canada and the outlook for pricing, we recognized a $95 million impairment charge on goodwill in 2014, which represented the full amount of goodwill attributable to our Canadian well servicing operation and water treatment operations.

Foreign Exchange

We recognized a foreign exchange gain of $1 million in 2014 (2013 – $9 million) because the Canadian dollar weakened 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

Finance charges were $110 million, an increase of $16 million compared with 2013. The increase is the result of the issuance of the US$400 million 5.25% Senior Notes due in 2024 and the impact of the weaker Canadian dollar on our U.S. dollar denominated interest.



						Precision Drilling Corporation 2014 Annual Report		25

Income Taxes

Income taxes were a recovery of $12 million, $42 million lower than 2013 mainly because operating results were lower.

On August 7, 2014, the Ontario Court of Appeal ruled in favour of Precision’s wholly owned subsidiary, Inter-Leasing, Inc., reversing a decision by the Ontario Superior Court of Justice dated June 2013, regarding the reassessment of Ontario income tax for Inter-Leasing, Inc.’s 2001 through 2004 taxation years. The Ontario Minister of Revenue made an application to the Supreme Court of Canada seeking leave to appeal this decision. On March 5, 2015, the Supreme Court of Canada denied the Ontario Minister of Revenue’s application for leave to appeal. The decision by the Supreme Court of Canada brought the appeal process to an end and Precision has reflected the $55 million paid to the Ontario tax authorities in 2008, related to the reassessed taxation years, as a current receivable. It is expected that this amount plus interest and costs will be received from the Ontario Minister of Revenue in 2015.

2013 COMPARED TO 2012

Net earnings in 2013 were $191 million, or $0.66 per diluted share, compared to $52 million, or $0.18 per diluted share, in 2012. For 2012, net earnings and net earnings per diluted share include the impact of charges associated with asset decommissioning and an impairment charge to the goodwill attributable to our Canadian directional drilling operations.

Revenue was $2,030 million, 1% lower than in 2012. Improved pricing in Canada and increased activity internationally were offset by lower activity levels in both the Contract Drilling Services and Completion and Production Services segments.

Adjusted EBITDA in 2013 was $639 million, 5% lower than 2012. Lower activity levels were partially offset by higher average pricing in both operating segments due to changes in product mix. Activity, as measured by drilling utilization days, dropped 6% in Canada and 13% in the U.S. compared to 2012 but increased 70% internationally.

The volatile global environment and low natural gas prices in much of 2013 reduced utilization for us and for the industry in general.

Key Statistics

There were 10,903 wells drilled in western Canada in 2013, 1% more than the 10,753 drilled in 2012. Despite the 150 well increase, total industry drilling operating days were 3% lower than 2012, at 120,043. Average industry drilling operating days per well was 11.0 compared to 11.6 in 2012. Average depth of a well increased 7%. The decrease in days per well while average depth increased reflects the use of top tier rigs and greater industry experience with unconventional drilling.

U.S. activity, as measured by onshore well starts, was down 3% year over year. Approximately 35,700 wells were started in 2013, compared to approximately 36,800 wells in 2012.

Foreign Exchange

We recognized a foreign exchange gain of $9 million in 2013 because the Canadian dollar weakened 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

Finance charges were $93 million, an increase of $6 million compared with 2012 primarily due to the increase in average outstanding debt in Canadian dollars.

Income Taxes

Income taxes were $30 million, $55 million higher than in 2012 mainly because operating results were higher.



		26		Management’s Discussion and Analysis

Segmented Results

CONTRACT DRILLING SERVICES

Financial Results

Adjusted EBITDA and operating earnings are additional GAAP measures. See page 5 for more information.


Year ended December 31 (thousands of dollars, except where noted)	2014		% of revenue		2013		% of revenue		2012		% of revenue
Revenue		2,017,110				1,719,910				1,725,240
Expenses
Operating		1,147,826		56.9		1,019,156		59.3		1,036,553	60.1
General and administrative		47,794		2.4		47,090		2.7		39,406	2.3
Adjusted EBITDA		821,490		40.7		653,664		38.0		649,281	37.6
Depreciation and amortization		381,465		18.9		292,217		17.0		271,993	15.8
Loss on asset decommissioning		97,947		4.8		–		–		192,469	11.1
Operating earnings		342,078		17.0		361,447		21.0		184,819	10.7
2014 Compared to 2013 Revenue from Contract Drilling Services was $2,017 million, 17% higher than 2013, mainly due to improved utilization days and higher average day rates in all of our geographic business units. Operating expenses were 57% of revenue, compared to 59% in 2013, mainly because of improved results from our international drilling business and lower operating costs per utilization day in the U.S. Operating expenses per day were 1% higher in Canada and 4% lower in the U.S. mainly because of a reduction in crew labour costs and a larger activity base over which to spread fixed costs. General and administrative expense for 2014 was in line with 2013. Operating earnings were $342 million, 5% lower than 2013, and equated to 17% of revenue compared to 21% in 2013. Included in the 2014 Contract Drilling Services results was a loss on asset decommissioning charge of $98 million related to the decommissioning of 29 drilling rigs in the fourth quarter. Capital expenditures in 2014 were $822 million: ¡ $564 million – to expand our asset base ¡ $137 million – to upgrade existing equipment ¡ $121 million – on maintenance and infrastructure. Most of the expansion capital was on 32 new-build rigs, as part of our rig build program; 15 of these were completed and placed into service by December 31, 2014, the remaining 17 are expected to be placed into service in 2015. *Operating Statistics*
Year ended December 31	2014		% increase/ (decrease)		2013		% increase/ (decrease)		2012		% increase/ (decrease)
Number of drilling rigs (year-end)		313		(4.3)		327		1.9		321	(4.7)
Drilling utilization days (operating and moving)
Canada		32,810		7.5		30,530		(5.6)		32,352	(14.8)
U.S.		35,075		15.9		30,268		(12.5)		34,597	(8.7)
International		4,036		13.5		3,555		70.4		2,086	197.2
Drilling revenue per utilization day
Canada (Cdn$)		22,250		0.6		22,108		5.1		21,030	14.0
U.S. (US$)		24,330		3.2		23,575		(0.5)		23,696	9.0
Drilling statistics (Canadian operations only)
Wells drilled		3,091		(3.7)		3,211		4.1		3,085	(13.5)
Average days per well		9.4		11.9		8.4		(10.6)		9.4	(1.1)
Metres drilled (hundreds)		5,864		5.2		5,576		6.6		5,233	(8.5)
Average metres per well		1,897		9.2		1,736		2.4		1,696	5.8



						Precision Drilling Corporation 2014 Annual Report		27

Canadian Drilling

Revenue from Canadian drilling was up $55 million or 8% from 2013. Drilling rig activity, as measured by utilization days, was up 7%.

In 2014, the industry drilled 10,942 wells in western Canada, in line with the 10,903 wells drilled in 2013. Industry operating days increased 9% to 131,021 as wells drilled in 2014 were on average 8% deeper than wells drilled in 2013.

Adjusted EBITDA was $357 million, 7% higher than 2013, because of higher drilling activity.

Depreciation expense for the year was $19 million higher than 2013 because of changes in the estimated remaining useful life of our capital equipment, a change to straight-line depreciation, and depreciation expense associated with new equipment.

Drilling Statistics – Canada

In 2014, we completed five new-build rigs, transferred one rig from the U.S. to Canada, and decommissioned 19 legacy rigs, bringing our Canadian 2014 year-end net rig count to 174 (from 187 in the prior year).

The industry drilling rig fleet decreased as well – there were approximately 797 rigs at the end of 2014 compared to 819 at the end of 2013. Our operating day utilization was 42% (2013 – 39%), compared to industry utilization of 44% (2013 – 40%).

Our average dayrates in Canada increased 1% in 2014 because of rig mix and new-build and upgraded rigs entering the fleet compared to the prior year, partially offset by competitive pricing in some rig segments.

U.S. Drilling

Revenue from U.S. drilling was higher than 2013 by US$140 million or 20%. Drilling rig activity, as measured by utilization days, was up 16% while average revenue per day was up 3%.

Adjusted EBITDA was US$359 million, 33% higher than US$270 million in 2013, mainly because of higher industry activity.

Depreciation expense for the year was $29 million higher than 2013 because of changes in the estimated remaining useful life of our capital equipment, a change to straight-line depreciation, and depreciation expense associated with new equipment.

Drilling Statistics – U.S.

In 2014, we completed seven new-build rigs, transferred one net rig into our U.S. fleet from our international operations, transferred one rig to our Canadian fleet, and decommissioned ten rigs, leaving our U.S. year-end net rig count at 124 (127 in 2013). In 2014, we averaged 96 rigs working, a 16% increase from 2013.

Our average dayrates in the U.S. increased 3% in 2014 with the addition of new-build and upgraded rigs to our fleet, resulting in a better rig mix. Turnkey utilization days increased 24% over 2013 and accounted for approximately 3% of our U.S. rig utilization.

Drilling Statistics – U.S.


	2014				2013
	Precision		Industry⁽¹⁾		Precision		Industry⁽¹⁾
Average number of active land rigs for quarters ended:
March 31		94		1,724		81		1,706
June 30		93		1,802		80		1,710
September 30		97		1,842		81		1,709
December 31		100		1,856		90		1,697
Annual average		96		1,806		83		1,705

⁽¹⁾

Source: Baker Hughes



		28		Management’s Discussion and Analysis

COMPLETION AND PRODUCTION SERVICES

Financial Results

Adjusted EBITDA and operating earnings are additional GAAP measures. See page 5 for more information.


Year ended December 31 (thousands of dollars, except where noted)	2014			% of revenue			2013		% of revenue		2012		% of revenue
Revenue		343,556						323,353				326,079
Expenses
Operating		268,129			78.0			242,768		75.1		217,326		66.6
General and administrative		17,473			5.1			19,553		6.0		15,199		4.7
Adjusted EBITDA		57,954			16.9			61,032		18.9		93,554		28.7
Depreciation and amortization		58,621			17.1			32,630		10.1		30,758		9.4
Loss on asset decommissioning		28,752			8.4			–				–
Operating earnings (loss)		(29,419	)		(8.6	)		28,402		8.8		62,796		19.3

Revenue from Completion and Production Services was $344 million in 2014, 6% higher than 2013, mainly because of higher average pricing for our well servicing product line due to product mix, partially offset by lower activity.

Operating earnings were negative $29 million in 2014, $58 million lower than 2013 because of a loss on asset decommissioning of $29 million and a loss on disposal of our U.S. coil tubing assets of $14 million and higher depreciation due to the change to straight-line depreciation.

Operating expenses were 78% of revenue, 3% higher than 2013, mainly because of product mix.

Depreciation excluding the loss on disposal of our coil tubing assets in the year was 37% more than 2013 because of changes in the estimated remaining useful life of our capital equipment, a change to straight-line depreciation, and depreciation associated with new equipment.

Capital expenditures were $24 million:

$8 million – to expand our asset base

$16 million – on maintenance and infrastructure.

Revenue from Precision Well Servicing in Canada was $189 million, in line with 2013, as higher average hourly pricing offset lower operating activity.

Revenue from our U.S. based completion and production businesses was US$57 million, 12% higher than 2013. The increase was the result of continued growth in activity. During the fourth quarter, we sold our U.S. based coil tubing assets.

Revenue from Precision Rentals was $42 million, 6% lower than 2013. Lower average rates from product mix were partially offset by higher activity. In 2013 Precision Rentals expanded from three major product lines (surface equipment, wellsite accommodations, and small flow wastewater treatment systems) to also provide power generation equipment, solids control equipment, and WaterDams (containment rings).

Revenue from Precision Camp Services was $37 million, 13% higher than 2013, because of an increase in base camp activity days. Precision operated four base camps and 50 drill camps during 2014.



						Precision Drilling Corporation 2014 Annual Report		29

Operating Results


Year ended December 31	2014		% increase/ (decrease)			2013		% increase/ (decrease)			2012		% increase/ (decrease)
Number of service rigs (end of year)		177		(20.3	)		222		3.7			214		3.4
Service rig operating hours ⁽¹⁾		273,194		(3.7	)		283,576		(3.8	)		294,681		(7.2	)
Revenue per operating hour ⁽¹⁾		907		6.2			854		14.8			744		8.1

⁽¹⁾

2012 comparatives have been changed to include U.S. based service rig activity.

In 2014, we decommissioned 35 service rigs and two snubbing units and moved one service rig from Canada to the U.S. In addition, we moved two snubbing units from the U.S. to Canada and sold our eight U.S. based coil tubing units. We also added rental equipment to our North American footprint.

Service rig rates increased 6% as we provided higher-end services and crew wage increases were passed through to customers. Our service rig hours decreased 4% although higher rig rates and our U.S. expansion in well service rigs partially offset the impact of market activity declines.

CORPORATE AND OTHER

Financial Results

Adjusted EBITDA is an additional GAAP measure. See page 5 for more information.


Year ended December 31 (thousands of dollars, except where noted)	2014			2013			2012
Revenue		–			–			–
Expenses
Operating		–			–			–
General and administrative		79,074			75,863			72,043
Adjusted EBITDA		(79,074	)		(75,863	)		(72,043	)
Depreciation and amortization		8,583			8,312			4,774
Operating earnings (loss)		(87,657	)		(84,175	)		(76,817	)

Our corporate 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 $79 million in 2014, $3 million more than 2013. The increase mainly related to costs resulting from international growth and the foreign exchange translation on U.S. dollar based costs. In 2014, corporate general and administrative costs were 3.4% of consolidated revenue compared to 3.7% in 2013 and 3.5% in 2012.

QUARTERLY FINANCIAL RESULTS

Adjusted EBITDA and funds provided by operations are additional GAAP measures. See page 5 for more information.

2014 – Quarters Ended

(thousands of dollars, except per share amounts)

March 31

June 30

September 30

December 31

Revenue

672,249

475,174

584,590

618,525

Adjusted EBITDA

237,274

129,695

199,390

234,011

Net earnings (loss)

101,557

(7,174

)

52,813

(114,044

)

Per basic share

0.35

(0.02

)

0.18

(0.39

)

Per diluted share

0.35

(0.02

)

0.18

(0.39

)

Funds provided by operations

231,393

97,805

196,217

172,059

Cash provided by operations

170,127

228,412

146,733

134,887

Dividends per share

0.06

0.07



		30		Management’s Discussion and Analysis


2013 – Quarters Ended (thousands of dollars, except per share amounts)	March 31		June 30		September 30		December 31
Revenue		595,720		378,898		488,450		566,909
Adjusted EBITDA		215,181		88,248		137,660		197,744
Net earnings		93,313		473		29,443		67,921
Per basic share		0.34		0.00		0.11		0.24
Per diluted share		0.33		0.00		0.10		0.24
Funds provided by operations		144,682		33,791		127,684		155,816
Cash provided by operations		62,948		182,345		88,341		94,452
Dividends per share		0.05		0.05		0.05		0.06

Seasonality

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. Thus, 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.

Fourth Quarter 2014 Compared to Fourth Quarter 2013

In the fourth quarter, we recorded a net loss of $114 million, or a net loss per diluted share of $0.39, compared to net earnings of $68 million, or $0.24 per diluted share, in the fourth quarter of 2013. During the quarter, we recorded a before-tax asset decommissioning charge and goodwill write down totaling $222 million that reduced net earnings by $182 million and net earnings per diluted share by $0.62. Effective January 1, 2014, we began calculating depreciation on our drilling rigs and service rigs on a straight-line basis which reduced net earnings for the fourth quarter by approximately $2 million, or $0.01 per diluted share, from what net earnings would have been using the previous depreciation method.

Revenue in the fourth quarter was $619 million, 9% higher than the fourth quarter of 2013, mainly due to higher drilling activity in the U.S., Canada and internationally along with higher average dayrates in the U.S. and internationally. Revenue from our Contract Drilling Services and Completion and Production Services segments both increased over the comparative prior year period by 10% and 5%, respectively.

Adjusted EBITDA in the fourth quarter was $234 million or 18% higher than the fourth quarter of 2013. Our activity for the quarter, as measured by drilling rig utilization days, increased 4% in Canada, 12% in the U.S. and 2% internationally, compared to the fourth quarter of 2013.

Our Adjusted EBITDA margin was 38% in the fourth quarter of 2014, compared to 35% in the fourth quarter of 2013. The increase in Adjusted EBITDA as a percentage of revenue was mainly due to increases in activity and profitability in our Contract Drilling Services segment and lower costs associated with incentive compensation that is tied to the price of our common shares, which resulted in a recovery of $10 million in the fourth quarter.

As a percentage of revenue, operating costs were 58% in the fourth quarter of 2014 and 59% in the same quarter of 2013. Our portfolio of term customer contracts, a highly variable operating cost structure, and economies achieved through vertical integration of the supply chain all help us manage our Adjusted EBITDA margin.



						Precision Drilling Corporation 2014 Annual Report		31

Contract Drilling Services

Revenue from Contract Drilling Services was $532 million in the fourth quarter, 10% higher than the fourth quarter of 2013, while Adjusted EBITDA increased by 16% to $232 million. The increases were mainly due to higher drilling rig utilization days in our U.S. and Canadian contract drilling businesses and higher average day rates in our U.S. and international drilling businesses.

Operating earnings for our international business improved as average day rates increased 27% while drilling rig utilization days for the quarter were 2% higher than the prior year comparative period. The average day rate was up as we realized a higher percentage of our fleet utilization from our operations in the Middle East.

Drilling rig utilization days in Canada (drilling days plus move days) were 8,550 during the fourth quarter of 2014, an increase of 4% compared to 2013 primarily resulting from the delivery of new-build and upgraded rigs over the last 12 months. Drilling rig utilization days in the U.S. were 9,214, 12% higher than the same quarter of 2013. The increase in U.S. activity was primarily due to strong demand for Tier 1 assets, which has led to market share gains over the past year due to our high percentage of Tier 1 assets. The majority of our North American activity came from oil and liquids-rich natural gas plays.

The majority of activity was in oil and liquids-rich natural gas related plays. We averaged a total of 205 rigs working in the quarter (93 in Canada, 100 in the U.S., and 12 internationally), compared to an average of 190 rigs in the fourth quarter of 2013.

Compared to the same quarter in 2013, drilling rig revenue per utilization day was up 1% in the U.S. and down 1% in Canada. The increase in average dayrates for the U.S. was driven by improved rig mix and higher rates for well-to-well and re-contracted rigs, partially offset by lower turnkey revenue. In Canada, the dayrate decrease was the result of competitive pricing in some rig segments, partially offset by new-build and upgraded rigs entering the fleet compared to the fourth quarter of 2013.

In Canada, 42% of utilization days in the quarter were generated from rigs under term contract, compared to 44% in the fourth quarter of 2013. In the U.S., 69% of utilization days were generated from rigs under term contract as compared to 62% in the fourth quarter of 2013. At the end of the quarter, we had 48 drilling rigs under contract in Canada, 63 in the U.S., and 12 internationally.

Operating costs were 55% of revenue for the fourth quarter, compared to 56% of revenue in the fourth quarter of 2013. On a per utilization day basis, operating costs for the drilling rig division in Canada were higher than the prior year primarily because of higher crew wages and labour burden. In the U.S., operating costs for the quarter on a per day basis were down from the fourth quarter of 2013, primarily as a result of a decrease in turnkey activity and size of turnkey jobs.

During the fourth quarter, the Contract Drilling Services segment recognized a loss of $98 million related to the decommissioning of drilling rigs. Depreciation expense in the quarter was 29% higher than the fourth quarter of 2013 due to changes in the estimated remaining useful life of our capital equipment, a change to straight-line depreciation, and depreciation expense associated with new equipment.



		32		Management’s Discussion and Analysis

Completion and Production Services

Revenue from Completion and Production Services was up $4 million or 5% from the fourth quarter of 2013, as a greater proportion of higher end services were provided in the current quarter compared with the prior year.

Our North America service rig activity in the fourth quarter was 2% lower than the fourth quarter of 2013 (70,350 operating hours compared to 72,013 hours in the fourth quarter of 2013). Approximately 86% of the fourth quarter Canadian service rig activity was oil related. In the fourth quarter of 2014, we sold our U.S. coil tubing assets for total cash of $44 million incurring a loss on disposal of $14 million.

Average service rig revenue per operating hour in the fourth quarter was $906, $28 higher than the fourth quarter of 2013. The increase was primarily the result of rig mix as we provided a greater proportion of higher end services in the current year, partially offset by the sale of our U.S. coil tubing assets that generally received a higher rate per hour.

Adjusted EBITDA was $16 million, in line with the fourth quarter of 2013, as higher average rates were offset by a decline in activity.

Operating costs as a percentage of revenue increased to 78% in the fourth quarter of 2014, from 76% in the fourth quarter of 2013. In 2014, operating costs per service rig operating hour were higher than the fourth quarter of 2013, mainly because of one-time costs associated with the disposition of our U.S. coil tubing operations.

During the fourth quarter, the Completion and Production Services segment recognized a loss of $29 million related to the decommissioning of 35 well servicing and two snubbing units, along with certain spare equipment. Depreciation, excluding the $14 million loss on disposal of our U.S. coil tubing assets in the fourth quarter of 2014, was 32% more than the fourth quarter of 2013 because of changes in the estimated remaining useful life of our capital equipment, a change to straight-line depreciation, and depreciation associated with new equipment.

Corporate and Other

General and administrative expenses for the quarter were $26 million, $8 million lower than the fourth quarter of 2013. The decrease was due to lower costs associated with incentive compensation tied to the price of our common shares, partially offset by increased costs associated with expansion efforts.

Net finance charges were $30 million in the fourth quarter, $7 million higher than the fourth quarter of 2013, mainly because of the issuance of US$400 million of 5.25% Senior Notes on June 3, 2014 and the effect of the weakening Canadian dollar on our U.S. dollar denominated interest expense.

Capital expenditures were $338 million in the fourth quarter compared to $123 million in the fourth quarter of 2013. Spending in the fourth quarter of 2014 included:

$236 million to expand our asset base

$42 million to upgrade existing equipment

$60 million on maintenance and infrastructure.



						Precision Drilling Corporation 2014 Annual Report		33








						Management’s Discussion and Analysis
Financial Condition

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 growth 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. And we 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.

LIQUIDITY

In June 2014, we issued US$400 million of 5.25% Senior Notes due in 2024 in a private offering. The Notes are guaranteed on a senior unsecured basis by current and future U.S. and Canadian subsidiaries that also guarantee our revolving credit facility and certain other indebtedness. We expect to use the net proceeds from this placement for general corporate purposes, including building new drilling rigs.

As at December 31, 2014, our liquidity was supported by a cash balance of $491 million, a senior secured credit facility of US$650 million, operating facilities totalling approximately $55 million, and a US$25 million secured facility for letters of credit. Our ability to draw on our senior secured credit facility is governed by financial covenants including a total debt to EBITDA ratio. See our covenant discussion on page 38.

At December 31, 2014, including letters of credit, we had approximately $1,942 million (2013 – $1,394 million) outstanding under our secured and unsecured credit facilities and $30 million in unamortized debt issue costs. Our secured facility includes financial ratio covenants that are tested quarterly.

Key Ratios

We ended 2014 with a long-term debt to long-term debt plus equity ratio of 0.43, and a ratio of long-term debt to cash provided by operations of 2.72.

We ended 2014 with a long-term debt to long-term debt plus equity ratio of 0.43 (compared to 0.36 in 2013) and a ratio of long-term debt to cash provided by operations of 2.72 (compared to 3.09 in 2013).

The current blended cash interest cost of our debt is about 6.2%.



		34		Management’s Discussion and Analysis

Ratios and Key Financial Indicators

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 that we generate compared to our peers.

Financial Position and Ratios


(thousands of dollars, except ratios)	December 31, 2014		December 31, 2013		December 31, 2012
Working capital		653,630		305,783		278,021
Working capital ratio		2.3		1.9		1.7
Long-term debt		1,852,186		1,323,268		1,218,796
Total long-term financial liabilities		1,881,275		1,355,535		1,245,290
Total assets		5,308,996		4,579,123		4,300,263
Enterprise value (see table on page 39)		3,265,865		3,919,763		3,213,406
Long-term debt to long-term debt plus equity		0.43		0.36		0.36
Long-term debt to cash provided by operations		2.72		3.09		1.92
Long-term debt to adjusted EBITDA		2.31		2.07		1.82
Long-term debt to enterprise value		0.57		0.34		0.38

Credit Rating

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.


	Moody’s	S&P
Corporate credit rating	Ba1	BB+
Senior secured bank credit facility rating	Not rated	Not rated
Senior unsecured credit rating	Ba1	BB

CAPITAL MANAGEMENT

To maintain and grow our business, we invest in both growth and sustaining capital. We base expansion 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.

Foreign Exchange Risk

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 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.



						Precision Drilling Corporation 2014 Annual Report		35

Hedge of Investments in U.S. Operations

To December 31, 2014, we designated our US$650 million 6.625% Senior Notes due in 2020 and our US$400 million 6.5% Senior Notes due in 2021 as a hedge of our investment in our U.S. operations. Effective January 1, 2015, we have included the US$400 million of 5.25% Senior Notes due in 2024 as a designated hedge of our investment in our U.S. operations. We recognize the effective amount of this hedge (net of tax) in other comprehensive income. We recognize ineffective amounts (if any) in earnings.

SOURCES AND USES OF CASH


At December 31 (thousands of dollars)	2014			2013			2012
Cash from operations		680,159			428,086			635,286
Cash used in investing		(629,987	)		(526,535	)		(930,121	)
Surplus (deficit)		50,172			(98,449	)		(294,835	)
Cash from (used in) financing		329,704			21,517			(14,899	)
Effect of exchange rate changes on cash		30,999			4,770			(4,974	)
Net cash generated (used)		410,875			(72,162	)		(314,708	)

Cash from Operations

In 2014, we generated cash from operations of $680 million compared to $428 million in 2013. The increase is primarily the result of better operating results and lower income taxes paid in 2014.

Investing Activity

We made growth and sustaining capital investments of $857 million in 2014:

$571 million in expansion capital

$137 million in upgrade capital

$149 million in maintenance and infrastructure capital.

The $857 million in capital expenditures in 2014 was split between segments as follows:

$822 million in Contract Drilling Services

$24 million in Completion and Production Services

$11 million in Corporate and Other.

Expansion and upgrade capital includes the cost of long-lead items purchased for our capital inventory, such as 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 $102 million in 2014.



		36		Management’s Discussion and Analysis

Financing Activity

In addition, we amended our credit agreement governing our revolving credit facility to, among other things, voluntarily reduce the size of the revolving credit facility from US$850 million to US$650 million and extended the maturity to June 3, 2019. The US$250 million accordion feature remains and allows the facility to be increased to US$900 million with additional lender commitments. As at March 6, 2015, our revolving credit facility remains undrawn except for US$26 million in outstanding letters of credit.

As at March 6, 2015 our operating facility of $40 million with Royal Bank of Canada remained undrawn except for $22 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 $25 million with HSBC Canada had US$12 million available.

Debt

As at December 31, 2014, we had a cash balance of $491 million and available capacity under our secured facilities of $781 million.

As at December 31, 2014, we had $1,882 million outstanding under our senior unsecured notes.


Amount	Availability	Used for	Maturity
Senior facility (secured)
US$650 million	Undrawn, except US$26 million in	General corporate purposes	June 3, 2019
(extendible, revolving term credit facility	outstanding letters of credit
with US$250 million accordion feature)
Operating facilities (secured)
$40 million	Undrawn, except $20 million in	Letters of credit and general
	outstanding letters of credit	corporate purposes
US$15 million	Undrawn	Short term working capital
		requirements
Demand letter of credit facility (secured)
US$25 million	Undrawn, except US$8 million in	Letters of credit
	outstanding letters of credit
Senior notes (unsecured)
$200 million	Fully drawn	Debt repayment	March 15, 2019
US$650 million	Fully drawn	Debt repayment and general	November 15, 2020
		corporate purposes
US$400 million	Fully drawn	Capital expenditures and	December 15, 2021
		general corporate purposes
US$400 million	Fully drawn	Capital expenditures and	November 15, 2024
		general corporate purposes



						Precision Drilling Corporation 2014 Annual Report		37

Covenants

Senior Facility

The revolving term credit facility requires that we comply with certain financial covenants including leverage ratios of consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (EBITDA) of less than 3:1 and consolidated total debt to EBITDA of less than 4:1 for the most recent four consecutive fiscal quarters; and an interest to EBITDA coverage ratio, calculated as EBITDA to interest expense, of greater than 2.75:1 for the most recent four consecutive fiscal quarters. For purposes of calculating the leverage ratios, consolidated total debt includes all outstanding secured and unsecured indebtedness, while consolidated senior debt only includes secured indebtedness. EBITDA as defined in our revolving term facility agreement differs from Adjusted EBITDA as defined under Additional GAAP Measures on page 5 by the exclusion of bad debt expense and certain foreign exchange amounts. As at December 31, 2014 our consolidated senior debt-to-EBITDA ratio was 0.1:1 while our consolidated total debt-to-EBITDA ratio was 2.4:1.

In addition, the revolving 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, 2014, we were in compliance with the covenants of the revolving credit facility.

Senior Notes

The senior notes require that we comply with certain financial covenants including an interest to EBITDA coverage ratio of greater than 2.5:1 for the most recent four consecutive fiscal quarters.

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 stock; create liens; make restricted payments (including the payment of dividends); create or permit to exist restrictions on our ability or certain subsidiaries to make certain payments and distributions; engage in amalgamations, mergers or consolidations; make certain dispositions and engage in transactions with affiliates. At December 31, 2014 we were in compliance with the covenants of the senior notes.

Contractual Obligations

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.


	Payments due (by period)
At December 31, 2014 (thousands of dollars)	Less than 1 year		1-3 years		4-5 years		More than 5 years		Total
Long-term debt		–		–		200,000		1,682,145		1,882,145
Interest on long-term debt		117,482		234,964		224,672		221,546		798,664
Purchase of property, plant and equipment ⁽¹⁾		189,656		–		228,679		–		418,335
Operating leases		19,143		27,456		17,457		11,005		75,061
Contractual incentive plans ⁽²⁾		12,851		29,794		–		–		42,645
Total		339,132		292,214		670,808		1,914,696		3,216,850

⁽¹⁾

The balance due within one year relates to the costs committed to complete the 17 rigs scheduled for delivery in 2015. The balance due in four to five years relates to the costs of rig equipment with a flexible delivery schedule wherein we can take delivery of the equipment between 2016 and 2019 at our discretion.

⁽²⁾

Includes amounts we have not yet accrued but are likely to pay at the end of the contract term. Our long-term incentive plans compensate officers and key employees through cash payments when their awards vest. Equity-based compensation amounts are shown based on a five day weighted average share price of $7.14 at December 31, 2014.



		38		Management’s Discussion and Analysis

CAPITAL STRUCTURE


	March 6, 2015		December 31, 2014		December 31, 2013		December 31, 2012
Shares outstanding		292,819,921		292,819,921		291,979,671		276,475,770
Deferred shares outstanding		226,010		226,010		221,112		335,946
Warrants outstanding		–		–		–		15,000,000
Share options outstanding		11,028,021		8,560,088		8,074,694		6,413,777

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

Common Shares

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.

Warrants

In December 2013, all of our 15,000,000 outstanding warrants were exercised providing proceeds of $48 million. The warrants were issued on April 22, 2009, under a private placement. Each warrant was exercisable for one common share at a price of $3.22 per common share for five years from the date of issue.

Preferred Shares

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.

Enterprise Value


(thousands of dollars, except shares outstanding and per share amounts)	December 31, 2014		December 31, 2013		December 31, 2012
Shares outstanding		292,819,921		291,979,671		276,475,770
Year-end share price on the TSX		7.06		9.94		8.22
Shares at market		2,067,309		2,902,278		2,272,631
Long-term debt		1,852,186		1,323,268		1,218,796
Less working capital		(653,630)		(305,783)		(278,021)
Enterprise value		3,265,865		3,919,763		3,213,406



						Precision Drilling Corporation 2014 Annual Report		39








						Management’s Discussion and Analysis
Accounting Policies and Estimates

CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS

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.

You’ll find all of our significant accounting policies 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:

impairment of long-lived assets

depreciation and amortization

income taxes.

Impairment of Long-Lived Assets

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 periodically reviewed for impairment 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 cash generating unit (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 determining 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 estimates are reasonable and consistent with current conditions, internal planning and expected future operations, such estimations are subject to significant uncertainty and judgment.

We performed an impairment test on the well servicing and water treatment CGUs at December 31, 2014, as described in Note 6 to the Consolidated Financial Statements. These CGUs were found to be impaired and the goodwill associated with these CGUs was expensed in 2014.

Depreciation and Amortization

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.



		40		Management’s Discussion and Analysis

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.

Income Taxes

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 expense 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.

On August 7, 2014, the Ontario Court of Appeal ruled in favour of Precision’s wholly owned subsidiary, Inter-Leasing, Inc., reversing a decision by the Ontario Superior Court of Justice in June 2013, regarding the reassessment of Ontario income tax for Inter-Leasing, Inc.’s 2001 through 2004 taxation years. The Ontario Minister of Revenue made an application to the Supreme Court of Canada seeking leave to appeal this decision. On March 5, 2015, the Supreme Court of Canada denied the Ontario Minister of Revenue’s application for leave to appeal. The decision by the Supreme Court of Canada brought the appeal process to an end and Precision has reflected the $55 million paid to the Ontario tax authorities in 2008, related to the reassessed taxation years, as a current receivable. It is expected that this amount plus interest and costs will be received from the Ontario Minister of Revenue in 2015.

ACCOUNTING POLICIES ADOPTED JANUARY 1, 2014

Following are accounting policies Precision adopted with an initial application date of January 1, 2014:

IAS 32, Financial Instruments: Presentation

On January 1, 2014, we implemented certain amendments to IAS 32 that require us to provide clarification on the requirements for offsetting financial assets and financial liabilities on the statement of financial position.

IAS 36, Impairment of Assets

On January 1, 2014, we implemented certain amendments to IAS 36 that require that we disclose, if appropriate, the recoverable amount of an asset or cash generating unit, and the basis for the determination of fair value less costs of disposal or value-in-use of the asset, when an impairment loss is recognized or when an impairment loss is subsequently reversed.

IFRIC 21, Levies

On January 1, 2014, we implemented IFRIC 21 that provides an interpretation on IAS 37, Provisions, Contingent Liabilities and Contingent Assets, with respect to the accounting for levies imposed by governments. IAS 37 sets out criteria for the recognition of a liability, one of which is the requirement for the entity to have a present obligation as a result of a past event. The interpretation clarifies that the obligating event is the activity described in the relevant legislation that triggers the payment of the levy.

ACCOUNTING POLICIES NOT YET ADOPTED

IFRS 9, Financial Instruments

In November 2009, the IASB issued IFRS 9, replacing IAS 39, Financial Instruments: Recognition and Measurement. IFRS 9 will be issued in three phases. The first phase, which has already been issued, addresses the accounting for financial assets and financial liabilities. The second phase will address impairment of financial instruments, while the third phase will address hedge accounting. IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, and replaces the multiple category and measurement models in IAS 39. The approach in IFRS 9 focuses on how an entity manages its financial instruments in the context of its business model, as well as the contractual cash flow characteristics of the financial assets. The new standard also requires a single impairment method to be used, replacing the multiple impairment methods currently provided in IAS 39.



						Precision Drilling Corporation 2014 Annual Report		41

Requirements for financial liabilities were added to IFRS 9 in October 2010. Although the classification criteria for financial liabilities will not change under IFRS 9, the fair value option may require different accounting for changes to the fair value of a financial liability resulting from changes to an entity’s own credit risk.

In December 2013, new hedge accounting requirements were incorporated into IFRS 9 that increase the scope of items that can qualify as a hedged item and change the requirements of hedge effectiveness testing that must be met to use hedge accounting.

In July 2014, the IASB issued final amendments to IFRS 9, replacing earlier versions of IFRS 9. These amendments to IFRS 9 introduce a single, forward-looking ‘expected loss’ impairment model for financial assets that will require more timely recognition of expected credit losses, and a fair value through other comprehensive income category for financial assets that are debt instruments.

The amendments to IFRS 9 are effective for annual periods beginning on or after January 1, 2018 and are available for earlier adoption. We do not expect that the implementation of IFRS 9 will have a material effect on the financial statements.

IFRS 15, Revenue from Contracts with Customers

In May 2014, the IASB issued IFRS 15 to address how and when to recognize revenue as well as requiring entities to provide users of financial statements with more informative, relevant disclosures in order to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard provides a principles based five-step model to be applied to all contracts with customers. This five-step model involves identifying the contract(s) with a customer; identifying the performance obligations in the contract; determining the transaction price; allocating the transaction price to the performance obligations in the contract; and recognizing revenue when (or as) the entity satisfies a performance obligation.

Application of this new standard is mandatory for annual reporting periods beginning on or after January 1, 2017, with earlier application permitted. We do not expect that the implementation of IFRS 15 will have a material effect on the financial statements.

IFRS 11, Joint Arrangements

In May 2014, the IASB issued amendments to IFRS 11 to address the accounting for acquisitions of interests in joint operations. The amendments address how a joint operator should account for the acquisition of an interest in a joint operation in which the activity of the joint operation constitutes a business. IFRS 11, as amended, now requires that such transactions be accounted for using the principles related to business combinations accounting as outlined in IFRS 3, Business Combinations. The amendments are to be applied prospectively and are effective for annual periods beginning on or after January 1, 2016, with earlier application permitted. We do not expect that these amendments will have an impact on the financial statements.

IAS 16, Property, Plant and Equipment and IAS 38, Intangible Assets

In May 2014, the IASB issued amendments to IAS 16 and IAS 38 to clarify acceptable methods of depreciation and amortization. The amended IAS 16 eliminates the use of a revenue-based depreciation method for items of property, plant and equipment. Similarly, amendments to IAS 38 eliminate the use of a revenue-based amortization model for intangible assets except in certain specific circumstances. The amendments are to be applied prospectively and are effective for annual periods beginning on or after January 1, 2016, with earlier application permitted. We do not expect that these amendments will have an impact on the financial statements.



		42		Management’s Discussion and Analysis








						Management’s Discussion and Analysis
Risks in our Business

Our key business risks are summarized below. You’ll find more information and other risks in business in our AIF, which you can find on our website (www.precisiondrilling.com).

Price of Oil and Natural Gas

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. The volatility of crude oil and natural gas prices accounts for much of the cyclical nature of the energy services business.

Lower oil and natural gas prices could also cause our customers to terminate, renegotiate, or fail to honour their drilling contracts with us, which could affect the anticipated revenues that support our capital expenditure program and 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 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.

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.

We try to manage this risk by keeping our cost structure as variable as we can while still being able to maintain the level of service our customers require.

Weather Patterns

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 results depend partly on how long the winter drilling season lasts.



						Precision Drilling Corporation 2014 Annual Report		43

Competition

The contract drilling business is highly competitive with numerous 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 each of 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 in suitable drilling rigs 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

Periods of high demand often lead to higher capital expenditures on drilling rigs and other oilfield services equipment. The number of drilling rigs competing for work in markets where we operate has increased as the industry adds new and upgraded rigs. We expect new or newer rigs to continue to enter markets where we operate. 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 served to intensify 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.

Technology

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.



		44		Management’s Discussion and Analysis

Employees and Suppliers

Finding and Keeping Employees

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.

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 as the industry adds more rigs, oilfield service companies expand, and new companies enter the business.

We continually monitor crew availability. To retain and attract quality staff, we focus on providing a safe and productive work environment, opportunity for advancement, and added wage security.

Relying on Suppliers

We source certain key rig components, raw materials, equipment and component parts from a variety of suppliers in Canada, the U.S. and internationally. We also outsource some or all construction services for drilling and service rigs, including new-build rigs, as part of our capital expenditure programs.

To manage this risk, we maintain relationships with several key suppliers and contractors and place advance orders for components that have long lead times. We also have an inventory of key components, materials, equipment and parts.

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.

Health, Safety and the Environment

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

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 service 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.



						Precision Drilling Corporation 2014 Annual Report		45

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, emissions 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.

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 the 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 issue of energy and the environment has created intense public debate in Canada, the U.S. and around the world in recent years, and it is likely to continue to be a focus area for the foreseeable future, which 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; however, 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.



		46		Management’s Discussion and Analysis

Financial

Dividends May be Variable

The actual cash flow available for the payment of dividends to shareholders is a function of numerous factors, including our financial performance, debt covenants and obligations, working capital requirements, capital expenditure requirements, tax obligations, the impact of interest rates or foreign exchange rates, the growth of the general economy, the price of crude oil and natural gas, weather and number of common shares outstanding. Dividends may be increased, reduced, or eliminated entirely depending on our operations and the performance of our assets.

We require sufficient cash flow to service and repay our debt. The market value of our common shares may deteriorate if we are unable to meet dividend expectations in the future, and that deterioration may be material.

Credit Market Conditions

The ability to make scheduled debt repayments, refinance debt obligations, or access financing depends on our financial condition and operating performance, which may be affected by prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. Volatility in the credit markets can increase costs associated with debt instruments due to increased spreads over relevant interest rate benchmarks, or affect our ability to access those markets or the ability of third parties we wish to do business with. We may be unable to maintain sufficient cash flow from operating activities to allow us to pay the principal, premium, if any, and interest on our debt.

In addition, if there is continued or future volatility or uncertainty in the capital markets, access to financing may be uncertain, and this can have an adverse effect on the industry and our business, including future operating results. Our customers may curtail their drilling programs, which could result in reduced dayrates, lower demand for drilling rigs, well service rigs, directional drilling, turnkey jobs, and other wellsite services, or lower equipment utilization. In addition, certain customers may be unable to pay suppliers, including us, if they are unable to access the capital markets to fund their business operations.

Our Debt Facilities Contain Restrictive Covenants

Our revolving credit facility and each note indenture contain a number of covenants which, among other things, restrict us and some of our subsidiaries from conducting certain activities. In addition, we must satisfy and maintain certain financial ratio tests under the Secured Facility. Events beyond our control could affect our ability to meet these tests. If we breach any of the covenants, it could result in a default under the Secured Facility or any of the note indentures. If there is a default, the applicable lenders or note holders could decide to declare all amounts outstanding under the Secured Facility or any of the note indentures to be due and payable immediately, and terminate any commitments to extend further credit.

Access to Additional Financing

We will need sufficient cash flow 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 our revolving credit facility, our note indentures 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 secured 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. 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.

We regularly assess our credit policies and capital structure, and have enough liquidity to meet our needs. See page 34 for information about our liquidity.



						Precision Drilling Corporation 2014 Annual Report		47

Foreign Exchange

Our U.S. and international operations have revenues, 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 affect our income statement, balance sheet and statement of cash flow.

Translation into Canadian dollars – When preparing our consolidated financial statements, we translate the financial statements for foreign operations that don’t have a Canadian dollar functional currency into Canadian dollars. We translate assets and liabilities at exchange rates in effect at the balance sheet 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 for our international operations will be lower.

Transaction Exposure – We have long-term debt denominated in U.S. dollars. We have designated our senior notes as a hedge against the net asset position of our U.S. operations. This debt is converted at the exchange rate in effect at the balance sheet 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; however, we occasionally purchase goods and supplies in U.S. dollars for our Canadian operations. However, the U.S. dollar denominated transactions and foreign exchange exposure would not typically have a material impact on our financial results.

Liabilities from Prior Reorganizations

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

International Operations

We conduct some of our business in Mexico and the Middle East. Our growth plans contemplate establishing operations in other foreign countries, 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 among others:

an uncertain political and economic environment

the loss of revenue, property and equipment as a result of expropriation, confiscation, nationalization, contract deprivation and force majeure

war, terrorist acts or threats, civil insurrection, and geopolitical and other political risks

fluctuations in foreign currency and exchange controls

restrictions on the repatriation of income or capital

increases in duties, taxes and governmental royalties

renegotiation of contracts with governmental entities

changes in laws and policies governing operations of foreign-based companies

compliance with anti-corruption and anti-bribery legislation in Canada, the U.S. and other countries

trade restrictions or embargoes imposed by the U.S. or other countries.



		48		Management’s Discussion and Analysis

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.



						Precision Drilling Corporation 2014 Annual Report		49





						Management’s
						Discussion and
		Evaluation of				Analysis
		Controls and Procedures

Internal Control over Financial Reporting

Precision maintains 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 Precision’s 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 at December 31, 2014, management has concluded that Precision’s internal control over financial reporting is effective.

The effectiveness of internal control over financial reporting as of December 31, 2014 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 Precision’s 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.

Disclosure Controls and Procedures

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

An evaluation, as of December 31, 2014, 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, was carried out by management, including the CEO and the CFO. 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 that Precision files or submits 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 Precision’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that Precision’s 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.



		50		Management’s Discussion and Analysis









								Management’s
								Discussion and
								Analysis
		Corporate Governance

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

We have a strong Board made up of directors with a history of achievement and an effective mix of skills, knowledge, and business experience. The directors oversee the conduct of our business, provide oversight, and support our future growth. They also monitor regulatory developments in Canada and the U.S. to keep abreast of developments in governance and enhance transparency of our corporate disclosure.

You can find more information about our approach to governance in our management information circular, available on our website.



						Precision Drilling Corporation 2014 Annual Report		51