Exhibit 99.2  Managements
Discussion and Analysis

MD&APrecision
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
Informationon 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 Corporationand Precisionmean 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.










2    Managements Discussion and Analysis




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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.









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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.










4    Managements Discussion and Analysis




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ADDITIONAL GAAP MEASURES In this MD&A, we reference additional GAAP measures that are not defined terms under IFRS to assess performance because we believe they provide useful
supplemental information to investors. Adjusted EBITDA We believe that Adjusted EBITDA (earnings before income taxes, finance charges, foreign exchange, impairment of goodwill, loss on asset decommissioning,
and depreciation and amortization), as reported in the Consolidated Statement of Earnings, is a useful supplemental measure because it gives us, and our investors, an indication of the results from our principal business activities before
consideration of how our activities are financed and excluding the impact of foreign exchange, taxation, non-cash depreciation and amortization charges, and non-cash decommissioning charges. Operating Earnings We believe
that operating earnings, as reported in the Consolidated Statement of Earnings, is a useful measure of our income because it gives us, and our investors, an indication of the results of our principal business activities before consideration of how
our activities are financed and excluding the impact of foreign exchange and taxation. Funds Provided by Operations We believe that funds provided by operations, as reported in the Consolidated Statement of Cash Flow, is a useful measure because it gives us, and our
investors, an indication of the funds our principal business activities generated prior to consideration of working capital, which is primarily made up of highly liquid balances.









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|Precision Drilling Corporation 2013 Annual Report     5



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ManagementsDiscussion andAnalysisAbout 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 1.
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.  3.
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.










6    Managements Discussion and Analysis




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Two Business Segments We operate our business in two segments, supported by vertically integrated business support systems.  LOGO  LOGO









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|Precision Drilling Corporation 2013 Annual Report     7



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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


TotalTier 1


96



101



3



200Tier 2


63



21



19



103PSST


15



4



5



24Total


174



126



27



327Geographic location

Canada


U.S.


International


TotalTier 1


110



87



3



200Tier 2


62



31



10



103PSST


15



9







24Total


187



127



13



327  LOGO










8    Managements Discussion and Analysis




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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


2013Singles:Freestanding mobile


150-400



94



94



90



90



90Doubles:Mobile


250-550



28



25



19



19



19Freestanding mobile


200-550



30



35



40



40



40Skid


300-860



30



28



22



22



22Slants:Freestanding


250-400



18



18



18



19



20Total service rigs






200



200



189



190



191Snubbing units






20



20



18



19



19Coil tubing units


















5



12Total service rigs, snubbing units and coil tubing units






220



220



207



214



222  LOGO









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ManagementsDiscussion andAnalysis2013 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



36.5Adjusted EBITDA


638,833



(4.8)



670,792



(3.5)



695,064



59.8Adjusted EBITDA % of revenue


31.5%







32.9%







35.6%Net earnings


191,150



265.1



52,360



(72.9)



193,477



344.4Cash provided by operations


428,086



(32.6)



635,286



19.2



532,772



74.0Funds provided by operations


461,973



(22.9)



598,812



1.1



592,388



46.6Investing activitiesCapital spendingExpansion


282,145



(52.7)



596,194



30.9



455,302



539.7Upgrade


141,132



8.5



130,094



(13.2)



149,811



174.0Maintenance and infrastructure


112,527



(20.6)



141,769



16.9



121,244



142.3Proceeds on sale


(13,372)



(57.4)



(31,423)



96.6



(15,983)



30.4Net capital spending


522,432



(37.6)



836,634



17.8



710,374



334.1Business acquisitions (net of cash acquired)






(100.0)



25



(100.0)



92,886



n/mEarnings per share ($)Basic


0.69



263.2



0.19



(72.9)



0.70



337.5Diluted


0.66



266.7



0.18



(73.1)



0.67



346.7Dividends per share ($)


0.21



320.0



0.05



n/m







n/m  calculation not meaningful.Operating HighlightsYear 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 daysCanada


30,530



(5.6)



32,352



(14.8)



37,970



21.8U.S.


30,268



(12.5)



34,597



(8.7)



37,887



16.8International


3,555



70.4



2,086



197.2



702



16.6Service 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










10    Managements Discussion and Analysis




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Financial Position and Ratios  Year ended December 31
(thousands of dollars, except ratios)

2013


2012


2011Working capital


305,783



278,021



610,429Working capital ratio


1.9



1.7



2.4Long-term debt


1,323,268



1,218,796



1,239,616Total long-term financial liabilities


1,355,535



1,245,290



1,267,040Total assets


4,579,123



4,300,263



4,427,874Enterprise value1


3,919,763



3,213,406



3,528,046Long-term debt to long-term debt plus equity


0.36



0.36



0.37Long-term debt to cash provided by operations


3.09



1.92



2.33Long-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.









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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.










12    Managements Discussion and Analysis




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LOGO









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|Precision Drilling Corporation 2013 Annual Report     13



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ManagementsDiscussion andAnalysisUnderstanding 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










14    Managements Discussion and Analysis




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New Technology Technological advancements in fracturing, stimulation and horizontal drilling have brought about a shift in development from conventional to
unconventional natural gas and oil reservoirs. This is giving companies cost-effective access to more complex wells in North America, in existing basins and in new basins that havent been economic in the past. The following chart shows the consistent trend away from vertical wells to more demanding directional/horizontal well programs, which require higher
capacity equipment and greater technical expertise for drilling. These trends are driving the demand for high performing drilling rigs, which garner premium contract rates.  LOGO These technical innovations have been a major factor in the increase in natural gas production in the U.S., which is
becoming less reliant on Canada as a source of natural gas. Natural gas production in Canada has been declining because of lower natural gas directed drilling due to pricing pressure and Canadas lack of an export market other than the U.S.  LOGO









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










16    Managements Discussion and Analysis




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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.









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|Precision Drilling Corporation 2013 Annual Report     17



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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 pipeTier 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 pumpsPSST(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.










18    Managements Discussion and Analysis




---




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.









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|Precision Drilling Corporation 2013 Annual Report     19



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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.










20    Managements Discussion and Analysis




---




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 2014Execute 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.









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|Precision Drilling Corporation 2013 Annual Report     21



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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.










22    Managements Discussion and Analysis




---




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









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|Precision Drilling Corporation 2013 Annual Report     23



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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.










24    Managements Discussion and Analysis




---




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.









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|Precision Drilling Corporation 2013 Annual Report     25



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ManagementsDiscussion andAnalysis2013 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


2011RevenueContract Drilling Services


1,719,910



1,725,240



1,632,037Completion and Production Services


323,353



326,079



330,225Inter-segment elimination


(13,286
)


(10,578
)


(11,235
)2,029,977



2,040,741



1,951,027Adjusted EBITDAContract Drilling Services


653,664



649,281



665,389Completion and Production Services


61,032



93,554



104,252Corporate and other


(75,863
)


(72,043
)


(74,577
)638,833



670,792



695,064Depreciation and amortization


333,159



307,525



251,483Loss on asset decommissioning






192,469



114,893Operating earnings


305,674



170,798



328,688Impairment of goodwill






52,539



Foreign exchange


(9,112
)


3,753



(23,674
)Finance charges


93,248



86,829



111,578Earning before income taxes


221,538



27,677



240,784Income taxes


30,388



(24,683
)


47,307Net earnings


191,150



52,360



193,477Results by Geographic SegmentYear ended December 31 (thousands of dollars)

2013


2012


2011RevenueCanada


1,002,199



1,053,966



1,071,526U.S.


901,246



936,113



866,776International


137,681



64,017



22,994Inter-segment elimination


(11,149
)


(13,355
)


(10,269
)2,029,977



2,040,741



1,951,027Total assetsCanada


2,082,958



2,119,891



2,252,084U.S.


2,006,519



1,913,810



2,027,676International


489,646



266,562



148,1144,579,123



4,300,263



4,427,874










26    Managements Discussion and Analysis




---




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


2011OilWest Texas Intermediate (per barrel)


US$98.02



US$94.13



US$95.02Natural gasCanadaAECO (per MMBtu)


$3.18



$2.39



$3.62U.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.









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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.










28    Managements Discussion and Analysis




---




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


% ofrevenue


2012


% ofrevenue


2011


% ofrevenueRevenue


1,719,910







1,725,240







1,632,037ExpensesOperating


1,019,156



59.3



1,036,553



60.1



931,062



57.0General and administrative


47,090



2.7



39,406



2.3



35,586



2.2Adjusted EBITDA


653,664



38.0



649,281



37.6



665,389



40.8Depreciation and amortization


292,217



17.0



271,993



15.8



219,194



13.4Loss on asset decommissioning










192,469



11.1



113,366



7.0Operating 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.









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|Precision Drilling Corporation 2013 Annual Report     29



---




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



21.8U.S.


30,268



(12.5)



34,597



(8.7)



37,887



16.8International


3,555



70.4



2,086



197.2



702



16.6Drilling revenue per utilization dayCanada(Cdn$)


22,108



5.1



21,030



14.0



18,442



14.3U.S.(US$)


23,575



(0.5)



23,696



9.0



21,744



14.7Drilling statistics (Canadian operations only)Wells drilled


3,211



4.1



3,085



(13.5)



3,566



11.6Average days per well


8.4



(10.6)



9.4



(1.1)



9.5



8.0Metres drilled (hundreds)


5,576



6.6



5,233



(8.5)



5,717



11.7Average 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.










30    Managements Discussion and Analysis




---




Drilling Statistics  U.S. 2013


2012Precision


Industry1


Precision


Industry1Average number of active land rigs for quarters ended:March 31


81



1,706



104



1,947June 30


80



1,710



97



1,924September 30


81



1,709



90



1,855December 31


90



1,697



87



1,759Annual 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


% ofrevenue


2012


% ofrevenue


2011


% ofrevenueRevenue


323,353







326,079







330,225ExpensesOperating


242,768



75.1



217,326



66.6



211,195



64.0General and administrative


19,553



6.0



15,199



4.7



14,778



4.5Adjusted EBITDA


61,032



18.9



93,554



28.7



104,252



31.6Depreciation and amortization


32,630



10.1



30,758



9.4



25,598



7.8Loss on asset decommissioning


















1,527



0.5Operating 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.









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|Precision Drilling Corporation 2013 Annual Report     31



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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



7.9Revenue 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


2011Revenue










ExpensesOperating










General and administrative


75,863



72,043



74,577Adjusted EBITDA


(75,863
)


(72,043
)


(74,577
)Depreciation and amortization


8,312



4,774



6,691Operating 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.










32    Managements Discussion and Analysis




---




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 31Revenue


595,720



378,898



488,450



566,909Adjusted EBITDA


215,181



88,248



137,660



197,744Net earnings (loss)


93,313



473



29,443



67,921Per basic share


0.34



0.00



0.11



0.24Per diluted share


0.33



0.00



0.10



0.24Funds provided by operations


144,682



33,791



127,684



155,816Cash provided by operations


62,948



182,345



88,341



94,452Dividends per share


0.05



0.05



0.05



0.062012  Quarters Ended
(thousands of dollars, except per share amounts)

March 31


June 30


September 30


December 31Revenue


640,066



381,966



484,761



533,948Adjusted EBITDA


245,574



97,192



151,000



177,026Net 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



142,576Cash provided by operations


162,440



275,346



61,183



136,317Dividends 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.









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|Precision Drilling Corporation 2013 Annual Report     33



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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.










34    Managements Discussion and Analysis




---




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.









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|Precision Drilling Corporation 2013 Annual Report     35



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ManagementsDiscussion andAnalysisFinancial 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.










36    Managements Discussion and Analysis




---




Financial Position and Ratios At December 31 (thousands of dollars, except ratios)

2013


2012


2011Working capital


305,783



278,021



610,429Working capital ratio


1.9



1.7



2.4Long-term debt


1,323,268



1,218,796



1,239,616Total long-term financial liabilities


1,355,535



1,245,290



1,267,040Total assets


4,579,123



4,300,263



4,427,874Enterprise value (see table on page 40)


3,919,763



3,213,406



3,528,046Long-term debt to long-term debt plus equity


0.36



0.36



0.37Long-term debt to cash provided by operations


3.09



1.92



2.33Long-term debt to adjusted EBITDA


2.07



1.82



1.78Long-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&PCorporate credit rating

Ba1











BB+Senior secured bank credit facility rating

Not rated











Not ratedSenior unsecured credit rating

Ba1











BB CAPITAL MANAGEMENT To maintain and grow our business, we invest in both growth and sustaining capital. We base expansion capital decisions on return on capital employed and
payback, and we mitigate the risk that we may not be able to fully recover our capital by requiring two to five year term contracts for new-build rigs. We base our maintenance capital decisions on actual activity levels, using key financial indicators that we express as per operating day or per operating
hour. Sourcing internally (through our manufacturing and supply divisions) helps keep our maintenance capital costs as low as possible. Foreign Exchange Risk Our U.S.
and international operations have revenue, expenses, assets and liabilities denominated in currencies other than the Canadian dollar (mostly in U.S. dollars and currencies that are pegged to the U.S. dollar). This means that changes in currency
exchange rates affect our income statement, balance sheet and statement of cash flow. We manage this risk by matching the currency of our debt obligations with the currency of cash flows generated by the operations that the debt supports. 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.









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|Precision Drilling Corporation 2013 Annual Report     37



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SOURCES AND USES OF CASH At December 31 (thousands of dollars)

2013


2012


2011Cash from operations


428,086



635,286



532,772Cash 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
)


366,887Effect of exchange rate changes on cash


4,770



(4,974
)


26,448Net 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.










38    Managements Discussion and Analysis




---




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

MaturitySenior 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, 2018Operating facilities (secured)$40 million

Undrawn, except $17 million in outstanding
letters of credit

Letters of credit and general corporate
purposesUS$15 million

Undrawn

Short term working capital requirementsDemand letter of credit facility (secured)US$25 million

Undrawn, except $0.2 million in outstanding
letters of credit

Letters of creditSenior notes (unsecured)$200 million

Fully drawn

Debt repayment

March 15, 2019US$650 million

Fully drawn

Debt repayment and general corporate
purposes

November 15, 2020US$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


TotalLong-term










29,781



1,316,780



1,346,561Interest on long-term debt


87,176



174,352



174,263



170,394



606,185Rig construction


150,624















150,624Operating leases


16,833



25,434



15,824



15,714



73,805Contractual incentive plans1


14,952



29,788











44,740Contingent purchase consideration


28,133















28,133Total


297,718



229,574



219,868



1,501,888



2,250,048  1
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.









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|Precision Drilling Corporation 2013 Annual Report     39



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CAPITAL STRUCTURE  March 7,2014


December 31,2013


December 31,2012


December 31,2011Shares outstanding


291,979,671



291,979,671



276,475,770



276,081,797Deferred shares outstanding


221,112



221,112



335,946



417,495Warrants outstanding










15,000,000



15,000,000Share 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, 2011Shares outstanding


291,979,671



276,475,770



276,081,797Year-end share price on the TSX


9.94



8.22



10.50Shares at market


2,902,278



2,272,631



2,898,859Long-term debt


1,323,268



1,218,796



1,239,616Less working capital


(305,783)



(278,021)



(610,429)Enterprise value


3,919,763



3,213,406



3,528,046










40    Managements Discussion and Analysis




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ManagementsDiscussion andAnalysisAccounting 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.









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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.










42    Managements Discussion and Analysis




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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.









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ManagementsDiscussion andAnalysisEvaluation 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.










44    Managements Discussion and Analysis




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ManagementsDiscussion andAnalysisCorporate
Governance



8 At Precision, we believe that a strong culture of corporate governance and ethical behaviour in decision-making is
fundamental to the way we do business. We have a strong board made up of directors with a history of achievement and an effective mix of skills,
knowledge, and business experience. The directors oversee the conduct of our business, provide oversight, and support our future growth. They also monitor regulatory developments in Canada and the U.S. to keep abreast of developments in governance
and enhance transparency of our corporate disclosure. You can find more information about our approach to governance in our Management Information
Circular, available on our website as well as on SEDAR and EDGAR.









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|Precision Drilling Corporation 2013 Annual Report     45