EX-99.2

Exhibit 99.2

Management’s

Discussion and Analysis

MD&A

Precision

Drilling

Corporation

2013

This management’s discussion and analysis (MD&A) contains information to help you understand our business and financial performance. Information is as of March 7, 2014. 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 About Forward-Looking Information on page 3. We adopted IFRS effective January 1, 2011, and restated our 2010 results at that time. Results for 2009 and prior years were prepared in accordance with previous Canadian generally accepted accounting principles (previous Canadian GAAP).

The terms we, us, our, the Corporation 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.

ABOUT FORWARD-LOOKING INFORMATION

We disclose forward-looking information to help current and prospective investors understand our future prospects. This MD&A contains statements about what we believe, intend and expect about developments, results and events that may or will occur in the future and are forward-looking within the meaning of Canadian securities legislation and the safe harbor provisions of the United States (U.S.) Private Securities Litigation Reform Act of 1995 (collectively, the forward-looking information and statements).

Forward-looking information and statements are often, but not always, identified by the use of words and phrases such as “anticipate”, “could”, “should”, “can”, “expect”, “seek”, “may”, “intend”, “likely”, “will”, “plan”, “estimate”, “believe” and other similar expressions. In particular, this MD&A includes statements about the following:

our strategic priorities

our new-build and upgradable rigs giving us favourable positioning in the market for premium drilling rigs

continuing improvements in unconventional drilling and completion techniques, allowing customers to realize favourable economics and drive additional investment capital towards oil and liquids-rich natural gas plays

our capital expenditure plans in 2014 including the amount of funds allocated for expansion capital, rig upgrade capital and sustaining and infrastructure expenditures

growth opportunities for our Contract Drilling Services land drilling rig fleet both in North America and internationally, including potential for additional rigs going to work in Mexico, two new-builds being delivered to Kuwait in the second quarter and rig additions to our Middle East fleet

the completion and production work associated with unconventional oil and natural gas plays providing the most profitable growth opportunities for our Completion and Production Services segment

the additional supply of drilling rigs potentially intensifying price competition and possibly leading to lower rates in the oilfield services industry generally and lower utilization of our existing rigs

cost increases, delays in delivery due to the strong activity or financial hardship of our suppliers or contractors, or other unforeseen circumstances relating to third parties

the outcome from the tax reassessment proceedings in Ontario involving one of our subsidiaries

our expectations regarding our ability to comply with our financial ratio covenants.

The forward-looking information and statements in this MD&A are based on certain factors and assumptions made by us 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 expectations regarding our customers’ capital budgets and geographical areas of focus

the status of current negotiations with our customers

the demand drivers for natural gas including growing potential of LNG export development

the economic viability of unconventional oil and gas projects in North America

the advantages of our premium rigs in respect of drilling in unconventional oil and natural gas plays

our ability to obtain qualified personnel, equipment and services in a timely and cost-efficient manner

our ability to operate our business in a safe, efficient and effective manner

our ability to obtain capital financing

the ‘retooling’ of the industry-wide fleet having made Tier 3 rigs obsolete in North America

potential customers’ focus on pricing, rig availability and other considerations when selecting a drilling contractor

unconventional drilling being the primary opportunity in the North American marketplace and the suitability of our Tier 1 rigs for drilling wells in unconventional oil and natural gas plays

new or newer rigs continuing to enter markets where we operate

the inherently challenging cyclical natures of the energy services business

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

our knowledge and understanding of applicable tax legislation and court proceedings.

Since forward-looking information and statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated or implied by such forward-looking information and statements due to a number of factors and risks including the following:

volatility in the price and demand for oil and natural gas

delays or changes in plans with respect to our customers’ exploration or production projects or capital expenditures

liquidity of the capital markets to fund our customers’ drilling programs

the availability of cash flow, debt and equity sources to fund our capital and operating requirements, as needed

the impact of weather and seasonal conditions on our operations and facilities

changes in rig technology and our ability to integrate such technologies on a timely and cost-effective basis

general economic, market or business conditions

changes in tax, health and safety and environmental legislation including potentially more stringent regulation or restriction of hydraulic fracturing

the availability of qualified personnel, management or other key inputs

a decline in our safety performance possibly resulting in lower demand for our services

fluctuations in foreign exchange, interest rates and tax rates

operating in foreign countries

uncertainty in judicial decision-making and proceedings

other unforeseen conditions that could affect the use of our services

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

You are cautioned that the foregoing list of assumptions, risks and uncertainties is not exhaustive. Additional information on these and other factors that could affect our business, operations or financial results are also discussed in our annual information form (AIF) on file with the Canadian securities commissions on SEDAR (www.sedar.com) and with the U.S. Securities and Exchange Commission on EDGAR (www.sec.gov). Our AIF may also be accessed from our corporate website (www.precisiondrilling.com).

The forward-looking information and statements contained in this MD&A are made as of the date hereof and Precision undertakes no obligation to update publicly or revise this forward-looking information as a result of new information, future events or otherwise, unless we are required to do so by law.


	Management’s
	Discussion and
	Analysis

About Precision		1

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

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.

Strength and Flexibility

From our founding as a private drilling contractor in the 1950s, Precision Drilling has grown to become one of the most active drillers in North America.

our High Performance, High Value operating model drives efficiency and quality of service

size and scale provide higher margins and better service capabilities

liquidity allows us to take advantage of business cycle opportunities

capital structure provides long-term stability and flexibility

Vision

Our vision is to be recognized as the High Performance, High Value provider of services for global energy exploration and development.

Strategic Priorities

Execute our High Performance, High Value strategy – Invest in Precision’s physical and human capital infrastructure to advance field level professional development, provide industry leading service to customers and promote safe operations. Continue to measure and benchmark performance with a view to exceeding the high standards we set.

2.	Leverage our scale in operations – Utilize established systems to promote consistent and reliable service and to improve operating efficiencies across all geographies and service lines.

Execute on existing organic growth opportunities – Deliver new-build and upgraded rigs to customer contracts, expand international activity in existing operating regions and grow our Canadian LNG drilling leadership position. Be a recognized leader in the integrated directional drilling transformation.

4.	Increase returns for our investors.

CONTRACT DRILLING SERVICES

We provide onshore drilling services to exploration and production companies in the oil and natural gas industry, operating in the U.S., Canada 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. land drilling market. We also have an international presence with operations in Mexico and the Middle East.

At December 31, 2013, our Contract Drilling Services segment consisted of:

327 land drilling rigs, including:

–

187 in Canada

–

127 in the U.S.

–

8 in Mexico

–

3 in Saudi Arabia

–

2 in the Kurdistan region of northern Iraq

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 primarily for our Canadian, U.S. and Mexican operations.

Drilling Rigs at December 31, 2013


Horsepower	< 1000		1000-1500		>1500		Total
Tier 1		96		101		3		200
Tier 2		63		21		19		103
PSST		15		4		5		24
Total		174		126		27		327

Geographic location	Canada		U.S.		International		Total
Tier 1		110		87		3		200
Tier 2		62		31		10		103
PSST		15		9		–		24
Total		187		127		13		327

LOGO

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 growing presence in the U.S.

Service rigs and snubbing units each serve about 18% of the market for these services in Canada.

At December 31, 2013, our Completion and Production Services segment consisted of:

191 well completion and workover service rigs, including:

–

184 in Canada

–

7 in the U.S.

19 snubbing units, including:

–

17 in Canada

–

2 in the U.S.

12 coil tubing units, including:

–

4 in Canada

–

8 in the U.S.

approximately 3,800 oilfield rental items including surface storage, small-flow wastewater treatment, power generation, and solids control equipment primarily in Canada

235 wellsite accommodation units in Canada and 67 in the U.S.

50 drilling camps and three base camps in Canada and two drilling camps and one base camp in the U.S.

10 large-flow wastewater treatment units, 24 pump houses and seven potable water production units in Canada.

Well Servicing Fleet as at December 31


Type of Service Rig	Horsepower		2009		2010		2011		2012		2013
Singles:
Freestanding mobile		150-400		94		94		90		90		90
Doubles:
Mobile		250-550		28		25		19		19		19
Freestanding mobile		200-550		30		35		40		40		40
Skid		300-860		30		28		22		22		22
Slants:
Freestanding		250-400		18		18		18		19		20
Total service rigs				200		200		189		190		191
Snubbing units				20		20		18		19		19
Coil tubing units				–		–		–		5		12
Total service rigs, snubbing units and coil tubing units				220		220		207		214		222

LOGO


	Management’s
	Discussion and
	Analysis

2013 Highlights and Outlook		2

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)	2013		% increase/ (decrease)		2012		% increase/ (decrease)		2011		% increase/ (decrease)
Revenue		2,029,977		(0.5)		2,040,741		4.6		1,951,027		36.5
Adjusted EBITDA		638,833		(4.8)		670,792		(3.5)		695,064		59.8
Adjusted EBITDA % of revenue		31.5%				32.9%				35.6%
Net earnings		191,150		265.1		52,360		(72.9)		193,477		344.4
Cash provided by operations		428,086		(32.6)		635,286		19.2		532,772		74.0
Funds provided by operations		461,973		(22.9)		598,812		1.1		592,388		46.6
Investing activities
Capital spending
Expansion		282,145		(52.7)		596,194		30.9		455,302		539.7
Upgrade		141,132		8.5		130,094		(13.2)		149,811		174.0
Maintenance and infrastructure		112,527		(20.6)		141,769		16.9		121,244		142.3
Proceeds on sale		(13,372)		(57.4)		(31,423)		96.6		(15,983)		30.4
Net capital spending		522,432		(37.6)		836,634		17.8		710,374		334.1
Business acquisitions (net of cash acquired)		–		(100.0)		25		(100.0)		92,886		n/m
Earnings per share ($)
Basic		0.69		263.2		0.19		(72.9)		0.70		337.5
Diluted		0.66		266.7		0.18		(73.1)		0.67		346.7
Dividends per share ($)		0.21		320.0		0.05		n/m		–		–
n/m – calculation not meaningful.
Operating Highlights
Year ended December 31	2013		% increase/ (decrease)		2012		% increase/ (decrease)		2011		% increase/ (decrease)
Contract drilling rig fleet		327		1.9		321		(4.7)		337		(5.1)
Drilling rig utilization days
Canada		30,530		(5.6)		32,352		(14.8)		37,970		21.8
U.S.		30,268		(12.5)		34,597		(8.7)		37,887		16.8
International		3,555		70.4		2,086		197.2		702		16.6
Service rig fleet		222		3.7		214		3.4		207		(5.9)
Service rig operating hours		283,576		(3.8)		294,681		(7.2)		317,418		7.9

Financial Position and Ratios


Year ended December 31 (thousands of dollars, except ratios)	2013		2012		2011
Working capital		305,783		278,021		610,429
Working capital ratio		1.9		1.7		2.4
Long-term debt		1,323,268		1,218,796		1,239,616
Total long-term financial liabilities		1,355,535		1,245,290		1,267,040
Total assets		4,579,123		4,300,263		4,427,874
Enterprise value¹		3,919,763		3,213,406		3,528,046
Long-term debt to long-term debt plus equity		0.36		0.36		0.37
Long-term debt to cash provided by operations		3.09		1.92		2.33
Long-term debt to enterprise value		0.34		0.38		0.35

¹	Share price multiplied by the number of shares outstanding plus long-term debt minus working capital. See page 40 for more information.

2013 OVERVIEW

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. The 2012 results include the impact of charges associated with asset decommissioning and an impairment charge to the goodwill attributable to our Canadian directional drilling operations.

Revenue in 2013 was $2,030 million, 1% lower than 2012, mainly due to lower utilization days in North America, although this loss was partially offset by improved drilling rig revenue per day in both Canada and the United States and growth in international operations. Contract Drilling Services revenue was down less than 1%, while revenue from Completion and Production Services was down 1%. Our international drilling activity increased 70% with an average of 10 rigs working in 2013 compared to six in 2012.

Adjusted EBITDA in 2013 was $639 million, 5% lower than 2012. Our adjusted EBITDA margin was 31%, compared to 33% in 2012. The decrease in adjusted EBITDA margin was mainly the result of reduced margin in the Completion and Production Services segment. Lower activity, costs associated with starting up in the United States and fixed costs all contributed to lower margin in our Completion and Production Services segment. EBITDA margin for the year in our Contract Drilling Services segment was 38%, in line with the prior year. 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.

North American industry activity was down from the prior year as a result of volatile oil and natural gas prices, oil transportation bottlenecks resulting in regional oil price discounts, record inventory levels resulting in depressed natural gas prices, and general global economic uncertainty persisting for much of the year.

In the fourth quarter of 2013, we increased our quarterly dividend to $0.06 per common share.

Outlook

Contracts

Our strong portfolio of term customer contracts provides a base level of activity and revenue and, as of March 7, 2014, we had term contracts in place for an average of 101 rigs: 51 in Canada, 43 in the United States and seven internationally for 2014. In Canada, term contracted rigs normally generate 250 utilization days per rig year because of the seasonal nature of wellsite access. In most regions in the United States and internationally, term contracts normally generate 365 utilization days per rig year. In 2013, approximately 58% of our total contract drilling revenue was generated from rigs under term contract.

Pricing, Demand and Utilization

The demand for energy has been rising with the improvement in the global economic situation, and per capita energy consumption has increased in many countries. These demand fundamentals, along with the challenges of maintaining or growing global supply, have supported stronger oil prices since 2009.

Natural gas prices, however, have been depressed, reaching 10-year lows in 2012 before recovering slightly in 2013 to average US$3.73 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, production remained stable and kept prices low.

Natural gas demand largely depends on the weather. Moderate North American winter temperatures in 2011 and 2012 hampered overall demand, but colder weather at the end of 2013 resulted in near-term reduction of inventories and caused spot prices to rise. Other demand drivers, however, such as natural gas fired power generation, industrial applications and transport, 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 growing 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.

Industry wide, drilling utilization has declined year-over-year in North America; however, demand for higher specification Tier 1 drilling assets has remained strong, supporting improved dayrates charged to customers. We have deployed 69 new-build Tier 1 Super Series drilling rigs since the beginning of 2010. As at March 7, 2014 we had a total fleet of 203 Tier 1 drilling rigs, and we have additional upgradable rigs within our fleet, which we believe favourably positions us in the market for premium drilling rigs.

The oil rig count at March 7, 2014 was 8% higher in the U.S. than it was a year ago, and 14% lower in Canada. The overall North American land oil directed rig count on March 7, 2014 was more than five times higher than it was on March 6, 2009, supported by unconventional oil and liquids-rich natural gas drilling in plays such as Bakken, Cardium, Montney, Duvernay, Eagle Ford, Granite Wash, Niobrara and Permian. As exploration and production companies continue to improve unconventional oil drilling and completion techniques, we expect that the favourable economics that our customers realize will drive additional investment capital toward these unconventional plays, supporting continued drilling activity, and especially demand for Tier 1 rigs.

International

We currently have 13 rigs in international locations, in Mexico and the Middle East, and expect our active rig count to grow over the next two quarters as two new-build drilling rigs on long-term contract for the Kuwait market are delivered in the second quarter. Additionally, we see potential for additional rigs going to work in Mexico in 2014 and potential rig additions to our Middle East fleet.

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 made Tier 3 rigs virtually obsolete in North America. In the fourth quarter of 2012, we decommissioned 42 Tier 3 rigs and 10 Tier 2 rigs from our fleet, exiting the Tier 3 contract drilling business. Our focus on the Tier 1 and Tier 2 market is aligned with our corporate strategy, customer relationships and competitive position.

Capital Spending

We expect capital spending in 2014 to be approximately $582 million ($545 million in the Contract Drilling Services segment and $37 million in the Completion and Production Services segment):

$268 million for expansion capital, which includes:

–

six new-build rigs for the Canadian market and two for the U.S.

–

one new-build rig that will only be completed once a firm customer contract is secured

–

the costs to complete two new-build rigs going to Kuwait

–

new equipment in our Completion and Production Services segment and

–

long-lead items.

$119 million for upgrade capital for 15 to 19 upgrades, four of which represent the completion of the 2013 rig upgrade program

$195 million for sustaining and infrastructure expenditures, which is based on currently anticipated activity levels, and includes the cost to consolidate and upgrade our operations facility in Nisku, Alberta. The Nisku facility will support Canadian operations for several decades. The portion of the 2014 budget allocated to this facility is approximately $30 million.


	Management’s
	Discussion and
	Analysis

Understanding our Business Drivers		3

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 funding.

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 moved lower during the economic crisis of 2008, but have increased since the beginning of 2009 as supply and demand fundamentals have tightened.

Natural gas and natural gas liquids continue to be priced regionally. In 2013, natural gas prices remained at depressed levels for most of the year as supplies of unconventional natural gas, particularly in North America, are keeping markets well supplied. The onset of colder weather late in 2013 and early 2014 increased demand for natural gas and caused spot prices to rise at the beginning of 2014. Overall, natural gas prices remain depressed compared to oil, supporting the projected growth in worldwide natural gas consumption.

LOGO

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, safety record and adaptability, 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’s efficient and reduces costs

having equipment that’s geographically dispersed, reliable and well maintained

monitoring and maintaining our equipment to minimize mechanical downtime

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

compensating our executive 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 Single design features technical innovations in safety and drilling efficiency for drilling slant or directional wells on single or multiple well pad locations in shallow to medium depth well applications. Precision Super Single rigs use extended length tubulars, 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 and remotely operated torque wrenches.

Triple rigs have greater hoisting capacity and are used in deeper exploration and development drilling. Our Super Triple electric rigs (ST-1200, ST-1500 and ST-3000) are designed to keep the load count as low as possible using widely available conventional rig moving equipment. Power capabilities are a major design criterion for the new 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. These rigs use extended length drill pipe and have an integrated top drive, automated pipe handling with iron roughnecks, and automated control.

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 all the major unconventional oil and natural gas basins.

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. 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 predetermined target of available billable time.

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

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

Investment returns – total shareholder return performance against an industry peer group, including dividends, 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 in North America.

In 2013, we high-graded our drilling rig fleet by:

adding seven Tier 1 new-build drilling rigs

upgrading 19 drilling rigs – about a quarter of these were Tier upgrades.

As at December 31, 2013, 93% of our 327 drilling rigs were Tier 1 or Tier 2 rigs.


Tier 1 – 200 drilling rigs 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 – 103 drilling rigs 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, stratigraphic and turnkey) – 24 drilling rigs Typically, conventional mechanical rigs with no automation and lower pumping capacity		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 ¡ Other than 24 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, Texas 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, North Dakota, Texas, and Pennsylvania.

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.

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.

Systematic Maintenance

We consistently reinvest capital to sustain existing property, plant and equipment. Also 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.

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 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. In 2008, we launched Toughnecks ( www.toughnecks.com), our highly successful field recruiting program.

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. Target Zero – our safety vision for eliminating workplace incidents – is a core belief that all injuries can be prevented. We track safety using an industry standard recordable frequency statistic that benchmarks successes and isolates areas for improvement. We have taken it to another level by tracking and measuring all injuries, regardless of severity, because they are leading indicators of the potential for a more serious incident. In 2013, 252 of our drilling rigs and 208 of our service rigs achieved Target Zero. We continue to embrace technological advancements that make operations safer.

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.


Strategic Priorities	2013 Results	Plans for 2014
Execute our High Performance, High Value strategy Continue to drive execution excellence in our people, internal systems and infrastructure. Support our world class safety, training and development programs. Upgrade and consolidate our Nisku operations and leverage our investments in our Houston and Red Deer Technology Centres.	Improved safety performance in both operating segments in 2013, matching the best results in our history. Began construction of our Nisku Centre.	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. Increase returns for our investors.
Execute on existing organic growth opportunities Remain poised to seize growth opportunities, leveraging our balance sheet strength and flexibility. Deliver new-build rigs to the North American market and upgrade existing drilling rigs to higher specification assets on customer contracts. Grow High Performance, High Value service lines for unconventional field development, such as integrated directional drilling, coil tubing and rentals.	Delivered seven new-build Super Series rigs to customers on term contracts and upgraded 19 existing drilling rigs to higher specification assets under term contracts. Expanded international operations with rig additions to Mexico and the Middle East. Expanded service lines in Completion and Production Services by adding higher end rental offerings and expanding our coil tubing business. Expanded penetration into northern U.S. markets.	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.
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. dayrates throughout 2013 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.	Uphold our reputation and market breadth in North America while improving our visibility in select oilfield markets internationally.

Our corporate and competitive growth strategies are designed to optimize resource allocation and differentiate us from the competition, generating value for investors.

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.

RISKS TO OUR BUSINESS

Our key business risks are summarized below. You’ll find more information and other risks to our business in our annual information form, which is on file with the Canadian securities commissions on SEDAR (www.sedar.com) and with the U.S. Securities and Exchange Commission on EDGAR (www.sec.gov).

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.

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

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.

Competition

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 revenues, operations and financial condition.

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 lead time required from when a decision is made to upgrade or build new equipment to when the equipment is placed into service. Excess supply resulting from industry-wide capital expenditures could lead to lower demand for term drilling contracts and for our equipment and services. The additional supply of drilling rigs has intensified price competition in the past and could continue to do so, possibly leading 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 revenues, cash flows, 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 critical to our continued success. We have an experienced internal engineering department that works closely with operations and marketing on equipment design and improvements. We cannot assure, however, that our rig technology will continue to meet the needs of our customers, especially as rigs age and technology advances, or that competitors won’t develop technological improvements that are more advantageous, timely or cost effective.

Employees and Suppliers

Finding and Keeping Employees

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. 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.

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 overseas. We also outsource some or all construction services for drilling and service rigs, including new-build rigs, as part of our capital expenditure program.

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 the 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 for the construction of new-build drilling rigs, it can delay service to our customers and have a material adverse effect on our revenues, cash flows 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 revenues, cash flows and earnings.

Our operations are affected by numerous laws, regulations and guidelines relating to spills, releases, emissions, and discharges of hazardous substances or other waste materials into the environment. These may require removal or remediation of pollutants or contaminants, and can impose 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, which are subject to special protective measures, and this 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 some of our customers that involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. This 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. The outcome of these developments and their effect on the regulatory landscape and the contract drilling industry is uncertain.

Financial

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.

Access to Additional Financing

We will need sufficient cash flows in the future to service and repay our debt. Our ability to generate cash in the future is affected to some extent by general economic, financial, competitive and other factors that may be beyond our control. If we need to borrow funds in the future to service our debt, our ability will depend on covenants in the secured facility, the 2019 Notes, the 2020 Notes, the 2021 Notes, and other debt agreements we 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 36 for information about our liquidity.

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 – Some of our long-term debt is denominated in U.S. dollars. We have designated our U.S. dollar denominated unsecured senior notes (the 2020 Notes and the 2021 Notes) as a hedge against the net asset position of our U.S. operations. We convert the debt at the exchange rate in effect at the balance sheet dates and include the resulting gains or losses 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. Most of our international operations are transacted in U.S. dollars or U.S. dollar-pegged currencies. Transactions for our Canadian operations are mainly in Canadian dollars, but we occasionally buy goods and supplies for our Canadian operations using U.S. dollars. However, U.S. dollar denominated transactions and foreign exchange exposure in our Canadian operations 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

restrictions under 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.

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.


	Management’s
	Discussion and
	Analysis

2013 Results		4

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)	2013			2012			2011
Revenue

Contract Drilling Services		1,719,910			1,725,240			1,632,037

Completion and Production Services		323,353			326,079			330,225

Inter-segment elimination		(13,286	)		(10,578	)		(11,235	)
		2,029,977			2,040,741			1,951,027
Adjusted EBITDA

Contract Drilling Services		653,664			649,281			665,389

Completion and Production Services		61,032			93,554			104,252

Corporate and other		(75,863	)		(72,043	)		(74,577	)
		638,833			670,792			695,064
Depreciation and amortization		333,159			307,525			251,483

Loss on asset decommissioning		–			192,469			114,893
Operating earnings		305,674			170,798			328,688

Impairment of goodwill		–			52,539			–

Foreign exchange		(9,112	)		3,753			(23,674	)

Finance charges		93,248			86,829			111,578
Earning before income taxes		221,538			27,677			240,784

Income taxes		30,388			(24,683	)		47,307
Net earnings		191,150			52,360			193,477
Results by Geographic Segment
Year ended December 31 (thousands of dollars)	2013			2012			2011
Revenue

Canada		1,002,199			1,053,966			1,071,526

U.S.		901,246			936,113			866,776

International		137,681			64,017			22,994

Inter-segment elimination		(11,149	)		(13,355	)		(10,269	)
		2,029,977			2,040,741			1,951,027
Total assets

Canada		2,082,958			2,119,891			2,252,084

U.S.		2,006,519			1,913,810			2,027,676

International		489,646			266,562			148,114
		4,579,123			4,300,263			4,427,874

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 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.

Average Oil and Natural Gas Prices

2013

2012

2011

Oil

West Texas Intermediate (per barrel)

US$98.02

US$94.13

US$95.02

Natural gas

Canada

AECO (per MMBtu)

$3.18

$2.39

$3.62

U.S.

Henry Hub (per MMBtu)

US$3.73

US$2.75

US$3.98

Key Statistics

There were 10,903 wells drilled in western Canada in 2013, 1% more than the 10,753 drilled in 2012. Despite the increases, total industry drilling operating days was 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.

Approximately 35,700 wells were started onshore in the U.S., 3% less than the approximately 36,800 wells started there in 2012.

Fleet

We and many of our competitors have been in the process of upgrading the drilling rig fleet by building new rigs and upgrading existing ones. In 2013, we added 7 new-build drilling rigs and upgraded another 19. In the fourth quarter of 2012, we decommissioned 42 Tier 3 drilling rigs and 10 Tier 2 rigs from our fleet and recorded an impairment charge of $192 million. In the fourth quarter of 2011, we recorded an impairment charge of $115 million related to the decommissioning of 36 drilling rigs and 13 well servicing rigs. We have exited the Tier 3 contract drilling business but retained 24 drilling rigs for seasonal, stratification and turnkey drilling work (the PSST rigs). Our focus on the Tier 1 and Tier 2 market is aligned with our corporate strategy, customer relationships and competitive position.

Goodwill

Under IFRS, we are required to assess the carrying value of cash-generating units that contain goodwill every year. Goodwill in 2013 remains unchanged except for foreign currency translation. We recognized a $53 million goodwill impairment charge in 2012 (the goodwill attributable to our Canadian directional drilling operations), because of the outlook for natural gas pricing and the reduction in natural gas drilling in Canada.

Foreign Exchange

We recognized a foreign exchange gain of $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 $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 earnings were higher.

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

2012 Compared to 2011

Net earnings in 2012 were $52 million or $0.18 per diluted share, compared to $193 million or $0.67 per diluted share in 2011. Revenue was $2,041 million, 5% higher than 2011. 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.

Adjusted EBITDA in 2012 was $671 million, 3% lower than 2011. Lower activity levels were partially offset by improved pricing in both operating segments. Activity, as measured by drilling utilization days, dropped 15% in Canada and 9% in the U.S. compared to 2011.

The volatile global environment and lower natural gas prices in much of 2012 reduced utilization for us and for the industry in general.

Key Statistics

There were 10,753 wells drilled in western Canada in 2012, 9% fewer than the 11,832 drilled in 2011. Approximately 38,600 wells were started onshore in the U.S., 2% more than the approximately 37,800 wells started there in 2011.

In Canada, total industry drilling operating days were 14% lower than 2011, at 124,319. Average industry drilling operating days per well was 11.6 compared to 12.2 in 2011. Average depth of a well increased 2%. The decrease in days per well while average depth increased reflects the use of top tier rigs and greater industry experience with unconventional drilling.

Foreign Exchange

We recognized a foreign exchange loss of $4 million because the Canadian dollar strengthened in value against the U.S. dollar and this affected the net U.S. dollar denominated monetary position in our Canadian dollar-based companies.

Finance Charges

Finance charges were $87 million, $25 million lower than 2011. In 2011, we incurred a $27 million charge for the make-whole premium from the refinancing of a previously outstanding debt, and the interest expense associated with Canadian income tax settlements. These were offset by higher interest costs from a higher average long-term debt balance and a non-recurring gain we recognized in 2011.

Income Taxes

Income taxes were $72 million lower than in 2011 mainly because operating results were lower.

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)	2013		% of revenue		2012		% of revenue		2011		% of revenue
Revenue		1,719,910				1,725,240				1,632,037

Expenses

Operating		1,019,156		59.3		1,036,553		60.1		931,062		57.0

General and administrative		47,090		2.7		39,406		2.3		35,586		2.2
Adjusted EBITDA		653,664		38.0		649,281		37.6		665,389		40.8

Depreciation and amortization		292,217		17.0		271,993		15.8		219,194		13.4

Loss on asset decommissioning		–		–		192,469		11.1		113,366		7.0
Operating earnings		361,447		21.0		184,819		10.7		332,829		20.4

2013 Compared to 2012

Revenue from Contract Drilling Services was $1,720 million, slightly lower than 2012, mainly due to lower utilization days in North America, partially offset by higher drilling rig revenue per day in both Canada and the U.S. and growth in our international drilling operations.

Operating expenses were 59% of revenue, compared to 60% in 2012, mainly because of improved results from our international drilling business. Operating expenses per day were 3% higher in Canada and 1% lower in the U.S. mainly because of higher crew labour-related costs offset in the U.S. by lower turnkey activity. General and administrative expense was higher because of the growth in our international business.

Operating earnings were $361 million, 96% higher than 2012, and equated to 21% of revenue compared to 11% in 2012. Included in 2012 was a loss on asset decommissioning charge of $192 million on the decommissioning of 52 drilling rigs in the fourth quarter.

Capital expenditures in 2013 were $447 million:

$208 million – to expand the underlying asset base

$141 million – to upgrade existing equipment

$98 million – on maintenance and infrastructure.

Most of the expansion capital was for our rig build program; seven of these were completed and placed into service by December 31, 2013.

Operating Statistics


Year ended December 31	2013		% increase/ (decrease)		2012		% increase/ (decrease)		2011		% increase/ (decrease)
Number of drilling rigs (year-end)		327		1.9		321		(4.7)		337		(5.1)

Drilling utilization days (operating and moving)

Canada		30,530		(5.6)		32,352		(14.8)		37,970		21.8

U.S.		30,268		(12.5)		34,597		(8.7)		37,887		16.8

International		3,555		70.4		2,086		197.2		702		16.6

Drilling revenue per utilization day

Canada (Cdn$)		22,108		5.1		21,030		14.0		18,442		14.3

U.S.(US$)		23,575		(0.5)		23,696		9.0		21,744		14.7

Drilling statistics (Canadian operations only)

Wells drilled		3,211		4.1		3,085		(13.5)		3,566		11.6

Average days per well		8.4		(10.6)		9.4		(1.1)		9.5		8.0

Metres drilled (hundreds)		5,576		6.6		5,233		(8.5)		5,717		11.7

Average metres per well		1,736		2.4		1,696		5.8		1,603		0.0

Canadian Drilling

Revenue from Canadian drilling was down $5 million or 1% from 2012. Drilling rig activity, as measured by utilization days, was down 6%.

In 2013, the industry drilled 10,903 wells in western Canada, 1% more than in 2012. Industry operating days decreased 3% to 120,043. These were the result of lower activity as customer demand for oil and liquids-rich natural gas related drilling activity declined.

Adjusted EBITDA was $334 million, in line with $332 million in 2012, as higher pricing offset the decline in drilling activity.

Depreciation expense for the year was $5 million lower than 2012 because of lower utilization of our rigs and a recognized loss on sale of assets in 2012.

Drilling Statistics – Canada

In 2013, we completed two new-build rigs and decommissioned one, bringing our Canadian 2013 year-end net rig count to 187 (up by one).

The industry drilling rig fleet decreased slightly – there were approximately 819 rigs at the end of 2013 compared to 822 at the end of 2012. Our operating day utilization was 39% (2012 – 40%), compared to industry utilization of 40% (2012 – 42%).

Our average dayrates in Canada increased 5% in 2013 because we had a favourable rig mix and demand for our Tier 1 rigs was strong.

U.S. Drilling

Revenue from U.S. drilling was lower than 2012 by US$106 million or 13%. Drilling rig activity, as measured by utilization days, was down 13%.

Adjusted EBITDA was US$270 million, 12% lower than US$308 million in 2012, mainly because of lower industry activity due to weak natural gas economics.

Depreciation expense for the year was $21 million lower than 2012 because of lower utilization of our drilling rigs and higher losses on sale of assets in 2012.

Drilling Statistics – U.S.

In 2013, we completed five new-build rigs, and transferred five rigs to our international fleet, leaving our U.S. year-end net rig count unchanged at 127. In 2013, we averaged 83 rigs working, a 13% decrease from 2012.

Our average dayrates in the U.S. decreased 1% in 2013 because we had fewer average rigs working turnkey jobs offset by a better rig mix as demand for our Tier 1 rigs was strong. We also added new-build Tier 1 rigs and upgraded rigs to the fleet.

Drilling Statistics – U.S.


	2013				2012
	Precision		Industry¹		Precision		Industry¹
Average number of active land rigs for quarters ended:

March 31		81		1,706		104		1,947

June 30		80		1,710		97		1,924

September 30		81		1,709		90		1,855

December 31		90		1,697		87		1,759
Annual average		83		1,705		95		1,871

¹ Source: Baker Hughes

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)	2013		% of revenue		2012		% of revenue		2011		% of revenue
Revenue		323,353				326,079				330,225

Expenses

Operating		242,768		75.1		217,326		66.6		211,195		64.0

General and administrative		19,553		6.0		15,199		4.7		14,778		4.5
Adjusted EBITDA		61,032		18.9		93,554		28.7		104,252		31.6

Depreciation and amortization		32,630		10.1		30,758		9.4		25,598		7.8

Loss on asset decommissioning		–				–		–		1,527		0.5
Operating earnings		28,402		8.8		62,796		19.3		77,127		23.4

Revenue from Completion and Production Services was $323 million in 2013, 1% lower than 2012, mainly because industry activity was lower; customers reduced their spending on production activity as natural gas prices remained weak. Reduced activity was partially offset by higher average day rates due to product mix and expansion of our services into the U.S.

Operating earnings were $28 million in 2013, 55% lower than 2012, and equated to 9% of revenue compared to 19% in 2012 as service rig activity was down in 2013 and rental equipment saw less activity.

Operating expenses were 75% of revenue, 8 percentage points higher than 2012, mainly because of lower equipment utilization, which increased daily or hourly operating costs associated with fixed operating costs, and higher crew wages starting in the fourth quarter.

Depreciation expense for the year was $2 million higher than 2012 mainly because of depreciation on equipment purchases in 2012 and 2013.

Capital expenditures were $83 million:

$74 million – to expand the underlying asset base

$9 million – on maintenance and infrastructure.

Revenue from Precision Well Servicing was $189 million, 14% lower than 2012, because operating activity was down 14%.

Revenue from Precision Rentals was $39 million, 26% lower than 2012. Activity was lower because drilling, well servicing, and frac-related activity was down. Precision Rentals expanded from three major product lines (surface equipment, wellsite accommodations, and tubular equipment) to also provide power generation equipment, solids control equipment, and WaterDams (containment rings).

Revenue from Precision Camp Services was $33 million, 5% higher than 2012, because there were more base camp days. Precision operated three base camps and 50 drill camps during 2013.

Operating Results


Year ended December 31	2013		% increase/ (decrease)		2012		% increase/ (decrease)		2011		% increase/ (decrease)
Number of service rigs (end of year)¹		222		3.7		214		3.4		207		(5.9)

Service rig operating hours²		283,576		(3.8)		294,681		(7.2)		317,418		7.9

Revenue per operating hour²		854		14.8		744		8.1		688		8.0

¹ Now includes snubbing services. Comparative numbers have been restated to reflect this change.

² Prior year comparatives have been changed to include U.S. based service rig activity.

In 2013, we added one coil tubing unit in Canada and six in the U.S. In addition, we moved two service rigs from Canada to the U.S., added one service rig to Canada and moved one snubbing unit from the U.S. to Canada. We also added rental equipment as we continue to expand our North American footprint.

Service rig rates increased 15% 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 partially offset 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)	2013			2012			2011
Revenue		–			–			–

Expenses

Operating		–			–			–

General and administrative		75,863			72,043			74,577
Adjusted EBITDA		(75,863	)		(72,043	)		(74,577	)

Depreciation and amortization		8,312			4,774			6,691
Operating earnings (loss)		(84,175	)		(76,817	)		(81,268	)

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 $76 million in 2013, $4 million more than 2012, mainly related to costs resulting from international growth. In 2013, corporate general and administrative costs were 3.7% of consolidated revenue compared to 3.5% in 2012 and 3.8% in 2011.

QUARTERLY FINANCIAL RESULTS

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

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 (loss)

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

0.06

2012 – Quarters Ended

(thousands of dollars, except per share amounts)

March 31

June 30

September 30

December 31

Revenue

640,066

381,966

484,761

533,948

Adjusted EBITDA

245,574

97,192

151,000

177,026

Net earnings (loss)

111,081

18,261

39,357

(116,339

)

Per basic share

0.40

0.07

0.14

(0.42

)

Per diluted share

0.39

0.06

0.14

(0.42

)

Funds provided by operations

247,739

62,373

146,124

142,576

Cash provided by operations

162,440

275,346

61,183

136,317

Dividends per share

–

0.05

Seasonality

The Canadian drilling industry is affected by weather patterns. Activity peaks in the winter, in the fourth and first quarters. In the spring, wet weather and the spring thaw 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 2013 Compared to Fourth Quarter 2012

We had net earnings in the fourth quarter of $68 million or $0.24 per diluted share, compared to a net loss of $116 million or $0.42 per diluted share in the fourth quarter of 2012. In the fourth quarter of 2012, we recognized charges associated with asset decommissioning and a goodwill impairment that, combined, reduced net earnings by $179 million and net earnings per diluted share by $0.63 compared to the fourth quarter of 2013.

Revenue was $33 million higher in the fourth quarter of 2013 than the fourth quarter of 2012, mainly because of higher international and U.S. drilling activity and higher pricing in Canadian contract drilling partially offset by lower turnkey activity in the U.S.

Adjusted EBITDA was $21 million higher in the fourth quarter of 2013 than the fourth quarter of 2012 mainly because of increases in international activity and U.S. contract drilling activity, and lower costs in U.S. contract drilling.

Our adjusted EBITDA margin was 35% in the fourth quarter of 2013, compared to 33% in the fourth quarter of 2012. The increase in EBITDA margin was mainly due to improved profitability in international and U.S. contract drilling operations and new-build and upgraded rigs that we have deployed over the past few years partially offset by weaker demand for our completion and production services.

Operating costs were higher because of increased activity internationally and in contract drilling in the U.S. As a percentage of revenue, operating costs were 59% in the fourth quarter of 2013 and 61% in the same quarter of 2012. 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.

Fourth quarter drilling rig utilization days (drilling days plus move days) in Canada were 8,201 in 2013, in line with 2012. Drilling rig utilization days in the U.S. were 8,258 this quarter, 3% higher than the fourth quarter of 2012 as a result of an improvement in market share as we were able to put more rigs to work in a period when industry land drilling rigs declined 4%.

The majority of activity was in oil and liquids-rich natural gas related plays. We averaged a total of 190 rigs working in the quarter (89 in Canada, 90 in the U.S., and 11 internationally), compared to an average of 175 rigs in the third quarter of 2013 and 185 rigs in the fourth quarter of 2012.

Our North America service rig activity in the fourth quarter was 7% lower than the fourth quarter of 2012 (71,981 operating hours compared to 77,234 hours in the fourth quarter of 2012).

Contract Drilling Services

Revenue and adjusted EBITDA from Contract Drilling Services were both up in the fourth quarter compared to the fourth quarter of 2012: revenue was $484 million, 7% higher than the fourth quarter of 2012 and adjusted EBITDA was $200 million, 16% higher than the fourth quarter of 2012. These results were mainly because of higher drilling rig activity in international and the U.S. and higher average rates per day in Canada partially offset by lower turnkey activity in the U.S.

Operating results for our international operations improved as we averaged 11 rigs working compared to eight in the prior year comparative quarter. Drilling utilization days in our international operations for the quarter were 1,052 days, 43% higher than the fourth quarter of 2012.

Drilling rig utilization days in Canada (drilling days plus move days) during the fourth quarter of 2013 were 8,201, a decrease of 1% compared to 2012 while drilling rig utilization days in the U.S. were 8,258, or 3% higher than the same quarter of 2012. The increase in U.S. activity was primarily due to strong demand for Tier 1 assets and resulted in market share gains by Precision during the second half of the year. The majority of our North America activity came from oil and liquids-rich natural gas related plays.

In Canada, we generated 44% of utilization days in the fourth quarter from rigs under term contract, compared to 41% in the fourth quarter of 2012. In the U.S., we generated 62% of utilization days from rigs under term contract as compared to 64% in the fourth quarter of 2012. At the end of the quarter, we had 57 drilling rigs working under term contracts in Canada, 58 in the U.S. and 10 internationally.

Operating costs were 56% of revenue for the fourth quarter of 2013 (2012 – 60%). On a per utilization day basis, operating costs for the drilling rig division in Canada were above the prior year primarily because of an increase in crew wage expense. In the U.S., operating costs for the quarter on a per day basis were down from the fourth quarter of 2012 as a result of proportionately lower turnkey activity and cost savings from operational efficiencies. Labour rate increases are typically recovered through higher dayrates.

Depreciation expense in the quarter was 2% higher than the prior year due to an increase in drilling activity and a greater proportion of operating days from our Tier 1 drilling rigs. In 2012, we decommissioned 52 rigs in the fourth quarter (22 in Canada and 30 in the U.S.) and recorded an impairment charge of $192 million.

We use the unit-of-production method of calculating depreciation for our contract drilling operations except for certain PSST and directional drilling equipment, where we use the straight-line method.

Completion and Production Services

Revenue for the fourth quarter of 2013, from Completion and Production Services was $85 million in-line with the prior year while adjusted EBITDA was $16 million, down 27% from the prior year, as weaker demand in the Canadian market offset the expansion of services in the U.S. Activity in Canadian well servicing was down 16% but was offset by a 158% increase in U.S. well servicing activity and higher average hourly rates in both Canada and the U.S.

Well servicing activity in the fourth quarter was 7% lower than the fourth quarter of 2012, as lower customer demand in Canada more than offset our growing U.S. presence. Approximately 83% of the fourth quarter service rig activity was oil related. Our rental division activity in the fourth quarter was lower than the fourth quarter of 2012 mainly due to the excess amount of surface storage capacity in Western Canada.

Average service rig revenue per operating hour in the fourth quarter was $878, or $83 higher than the fourth quarter of 2012. The increase was primarily the result of increased coil tubing operations in 2013, which operate at higher rates.

Operating costs as a percentage of revenue increased to 76% in the fourth quarter of 2013, from 70% in the fourth quarter of 2012. Operating costs per service rig operating hour were higher than in the fourth quarter of 2012 mainly because of the increase in costs associated with the new coil tubing operations and fixed costs spread over a lower activity base.

Depreciation in the fourth quarter of 2013 was 7% lower than the fourth quarter of 2012 because of lower equipment utilization and losses on disposal realized in the fourth quarter of 2012. We use the straight-line method of calculating depreciation for our completion and production business lines, except for the well servicing division, where we use the unit-of-production method.

Consolidated

General and administrative expenses were $34 million in the fourth quarter, $4 million higher than the fourth quarter of 2012 because of the year to date recording of incentive compensation liabilities, which are tied to the price of our common shares and our annual operating results.

Net finance charges were $23 million in the fourth quarter, $1 million higher than the fourth quarter of 2012, mainly because of the increase in average outstanding debt stated in Canadian dollars.

Capital expenditures were $123 million in the fourth quarter compared to $187 million in the fourth quarter of 2012. Spending in the fourth quarter of 2013 included:

$54 million – to expand the underlying asset base

$30 million – to upgrade existing equipment

$39 million – on maintenance and infrastructure.


	Management’s
	Discussion and
	Analysis

Financial Condition		5

The oilfield services business is inherently cyclical. To manage this, we focus on maintaining a strong balance sheet so we have the financial flexibility we need to continue to manage our growth and cash 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 rightly 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 capital investments.

Liquidity

As at December 31, 2013, our liquidity was supported by a cash balance of $81 million, a senior secured credit facility of US$850 million, operating facilities totalling approximately $55 million, and a US$25 million secured facility for letters of credit.

At December 31, 2013, including letters of credit, we had approximately $1,394 million (2012 – $1,290 million) outstanding under our secured and unsecured credit facilities and $23 million in unamortized debt issue costs. Our secured facility includes financial ratio covenants that are tested quarterly. We are compliant with these covenants and expect to remain compliant.

We ended 2013 with a long-term debt to long-term debt plus equity ratio of 0.36 (compared to 0.36 in 2012) and a ratio of long-term debt to cash provided by operations of 3.09 (compared to 1.92 in 2012).

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

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 we generate compared to our peers.

Financial Position and Ratios


At December 31 (thousands of dollars, except ratios)	2013		2012		2011
Working capital		305,783		278,021		610,429

Working capital ratio		1.9		1.7		2.4

Long-term debt		1,323,268		1,218,796		1,239,616

Total long-term financial liabilities		1,355,535		1,245,290		1,267,040

Total assets		4,579,123		4,300,263		4,427,874

Enterprise value (see table on page 40)		3,919,763		3,213,406		3,528,046

Long-term debt to long-term debt plus equity		0.36		0.36		0.37

Long-term debt to cash provided by operations		3.09		1.92		2.33

Long-term debt to adjusted EBITDA		2.07		1.82		1.78

Long-term debt to enterprise value		0.34		0.38		0.35

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

Senior unsecured credit rating

Ba1

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.

Interest Rate Risk

We minimize interest rate risk by staggering long-term debt maturities.

Hedge of Investments in U.S. Operations

We have designated our U.S. dollar denominated long-term debt as a hedge of our investment in our operations in the U.S. 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)	2013			2012			2011
Cash from operations		428,086			635,286			532,772

Cash used in investing		(526,535	)		(930,121	)		(715,462	)
Deficit		(98,449	)		(294,835	)		(182,690	)

Cash (used in) from financing		21,517			(14,899	)		366,887

Effect of exchange rate changes on cash		4,770			(4,974	)		26,448
Net cash generated (used)		(72,162	)		(314,708	)		210,645

Cash from Operations

In 2013, we generated cash from operations of $428 million compared to $635 million in 2012. The reduction is primarily the result of higher income taxes paid in 2013 and lower operating results than 2012.

Investing Activity

We made growth and sustaining capital investments of $536 million in 2013:

$282 million in expansion capital

$141 million in upgrade capital

$113 million in maintenance and infrastructure capital.

The $536 million in capital expenditures in 2013 was split between segments:

$447 million in Contract Drilling Services

$83 million in Completion and Production Services

$6 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.

Financing Activity

As at December 31, 2013, we had drawn US$28 million on our senior secured revolving facility, which in prior years had only been used for letters of credit. No other changes, with the exception of foreign exchange translation, were made to our net borrowings in 2013.

Effective August 30, 2012, our senior secured facility was increased from US$550 million to US$850 million and the US$100 million accordion feature was increased to US$250 million, allowing the facility to be increased to US$1,100 million with additional lender commitments. The term was extended to five years and several negative covenants were relaxed.

Also on August 30, 2012, our operating facility with Royal Bank of Canada was increased from $25 million to $40 million and it remained undrawn as at March 7, 2014, except for $17 million in outstanding letters of credit. Our operating facility of US$15 million with Wells Fargo remained undrawn as at March 7, 2014. Effective September 27, 2012, we entered into a new US$25 million demand facility for letters of credit with HSBC Canada and as at March 7, 2014, US$24.8 million was available.

Debt

At December 31, 2013, we had approximately $987 million in secured facilities, and $1,347 million in senior unsecured notes (maturing in 2019, 2020 and 2021).


Amount	Availability	Used for	Maturity
Senior facility (secured)
US$850 million (extendible, revolving term credit facility with US$250 million accordion feature)	Drawn US$28 million and US$29 million in outstanding letters of credit	General corporate purposes	November 17, 2018
Operating facilities (secured)
$40 million	Undrawn, except $17 million in outstanding letters of credit	Letters of credit and general corporate purposes
US$15 million	Undrawn	Short term working capital requirements
Demand letter of credit facility (secured)
US$25 million	Undrawn, except $0.2 million in outstanding letters of credit	Letters of credit
Senior notes (unsecured)
$200 million	Fully drawn	Debt repayment	March 15, 2019
US$650 million	Fully drawn	Debt repayment and general corporate purposes	November 15, 2020
US$400 million	Fully drawn	Capital expenditures and general corporate purposes	December 15, 2021

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, 2013 (thousands of dollars)	Less than 1 year		1-3 years		4-5 years		More than 5 years		Total
Long-term		–		–		29,781		1,316,780		1,346,561

Interest on long-term debt		87,176		174,352		174,263		170,394		606,185

Rig construction		150,624		–		–		–		150,624

Operating leases		16,833		25,434		15,824		15,714		73,805

Contractual incentive plans¹		14,952		29,788		–		–		44,740

Contingent purchase consideration		28,133		–		–		–		28,133
Total		297,718		229,574		219,868		1,501,888		2,250,048

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 share price of $9.83 at December 31, 2013.

CAPITAL STRUCTURE


	March 7, 2014		December 31, 2013		December 31, 2012		December 31, 2011
Shares outstanding		291,979,671		291,979,671		276,475,770		276,081,797

Deferred shares outstanding		221,112		221,112		335,946		417,495

Warrants outstanding		–		–		15,000,000		15,000,000

Share options outstanding		9,515,278		8,074,694		6,413,777		5,154,123

You can find more information about our capital structure in our annual information form, available online on our website as well as on SEDAR and EDGAR.

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.

Warrants

During 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, 2013	December 31, 2012	December 31, 2011
Shares outstanding	291,979,671	276,475,770	276,081,797

Year-end share price on the TSX	9.94	8.22	10.50
Shares at market	2,902,278	2,272,631	2,898,859

Long-term debt	1,323,268	1,218,796	1,239,616

Less working capital	(305,783)	(278,021)	(610,429)
Enterprise value	3,919,763	3,213,406	3,528,046


	Management’s
	Discussion and
	Analysis

Accounting Policies and Estimates		6

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 CGU at December 31, 2013 as described in note 6 to the Consolidated Financial Statements. This CGU has $89 million of goodwill allocated to it. An increase in the discount rate used by 1% would require an impairment charge being recognized on the goodwill assigned to the well servicing CGU.

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.

Determination of which part of the drilling rig equipment represent 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.

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

Accounting Policies Adopted January 1, 2013

Following are accounting policies Precision adopted with an initial application date of January 1, 2013:

IFRS 10 Consolidated Financial Statements

IFRS 10 introduces a new control model that is applicable to all investees; among other things, it requires the consolidation of an investee if the Corporation controls the investee on the basis of de facto circumstances.

Subsidiaries are entities controlled by the Corporation. The Corporation controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.

IFRS 11 Joint Arrangements

Joint arrangements are arrangements of which the Corporation has joint control, established by contracts requiring unanimous consent for decisions about the activities that significantly affect the arrangements’ returns. Under IFRS 11, joint arrangements are classified as either joint operations or joint ventures depending on the Corporation’s rights to the assets and obligations for the liabilities of the arrangements. When making this assessment, the Corporation considers the structure of the arrangements, the legal form of any separate vehicles, the contractual terms of the arrangement and other facts and circumstances. Previously, the structure of the arrangement was the sole focus of classification.

The Corporation has no joint arrangements under IFRS 11.

IFRS 12 Disclosures of Interests in Other Entities

IFRS 12 sets out certain disclosures that are required relating to interests in subsidiaries, associates, joint arrangements and unconsolidated structured entities. The Corporation does not have any investments that are not consolidated nor has it entered into any joint arrangements or structured entities.

The Corporation’s subsidiaries, as detailed in Note 25 to the consolidated financial statements, are all wholly owned. The determination of whether to consolidate these entities did not involve any significant judgments or assumptions. There are no significant restrictions on the ability of the Corporation to access or use the assets and settle the liabilities of the Corporation and its subsidiaries, except for customary limitations in the Corporation’s credit facility.

IFRS 13 Fair Value Measurement

IFRS 13 defines fair value and sets out a single standard a framework for measuring fair value and the required disclosures about fair value measurements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

IFRS 13 is applied prospectively to fair value measurements occurring on or after January 1, 2013. The additional disclosure requirements of IFRS 13 are also applied prospectively and have been presented, as relevant, in the 2013 interim and annual financial statements.

Accounting Policies Not Yet Adopted

IFRS 9 Financial Instruments (2010), IFRS 9 Financial Instruments (2009)

IFRS 9 (2009) introduces new requirements for the classification and measurement of financial assets. Under IFRS 9 (2009), financial assets are classified and measured based on the business model in which they are held and the characteristics of their contractual cash flows. IFRS 9 (2010) introduces additions relating to financial liabilities. The IASB currently has an active project to make limited amendments to the classification and measurement requirements of IFRS 9 and add new requirements to address the impairment of financial assets and hedge accounting.

IFRS 9 (2010 and 2009) is effective for annual periods beginning on or after January 1, 2015, with early adoption permitted. The Corporation is currently evaluating the impact of adopting this standard on its financial statements.


	Management’s
	Discussion and
	Analysis

Evaluation of Disclosure Controls and Procedures		7

Internal Control over Financial Reporting

Precision maintains internal control over financial reporting which 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 Issuers’ 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 (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Based on management’s assessment as at December 31, 2013, 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, 2013 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 2013 Annual Report to Shareholders.

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, 2013, 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.