Precision Drilling Corporation
Annual Report 2013

Plain-text annual report

Annual Report Precision Drilling Corporation 2013 What’s Inside 6 About Precision 10 2013 Highlights and Outlook 14 Understanding our Business Drivers The Energy Industry A Competitive Operating Model An Effective Strategy Risks to our Business 26 2013 Results 36 Financial Condition 41 Accounting Policies and Estimates 44 Evaluation of Disclosure Controls and Procedures 45 Corporate Governance 46 Consolidated Financial Statements and Notes 86 Supplemental Information 88 Shareholder Information 89 Corporate Information Management’s Discussion and Analysis Consolidated Financial Statements and Notes Precision Precision Drilling Corporation 2013 2013 SHARE TRADING SUMMARY The Toronto Stock Exchange (TSX) P D Volume (millions) Share Price (Cdn$) (1) 10 $15 $12 $9 $6 $3 ) $ n d C ( e c i r P e r a h S 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec (1) On December 5, 2013, Precision’s then largest shareholder sold its entire equity position in the Corporation, approximately 56 million shares which contributed to a total volume of 74 million shares traded that day. Toronto (TSX: PD) High: $11.53 Low: $7.47 Close: $9.94 Volume Traded: 297,457,268 The New York Stock Exchange (NYSE) P DS Volume (millions) Share Price (US$) $15 $12 $9 $6 $3 ) $ S U ( e c i r P e r a h S 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec New York (NYSE: PDS) High: US$11.21 Low: US$7.29 Close: US$9.37 Volume Traded: 288,801,100 ) s n o i l l i m ( e m u o V l ) s n o i l l i m ( e m u o V l 8 6 4 2 0 10 8 6 4 2 0 Precision Drilling Corporation 2013 Annual Report 1 Management’s Discussion and Analysis MD&A Precision Drilling Corporation 2013 This management’s discussion and analysis (MD&A) contains information to help you understand our business and financial performance. Information is as of March 7, 2014. This MD&A focuses on our consolidated financial statements and includes a discussion of known risks and uncertainties relating to the oilfield services sector. It does not, however, cover the potential effects of general economic, political, governmental and environmental events, or other events that could affect us in the future. You should read this MD&A with the accompanying audited consolidated financial statements and notes, which have been prepared in accordance with International Financial Reporting Standards (IFRS) and with the information in About Forward-Looking Information on page 3. We adopted IFRS effective January 1, 2011, and restated our 2010 results at that time. Results for 2009 and prior years were prepared in accordance with previous Canadian generally accepted accounting principles (previous Canadian GAAP). The terms we, us, our, the Corporation and Precision mean Precision Drilling Corporation and our consolidated subsidiaries, and include any partnerships that we and/or our subsidiaries are part of. All amounts are in Canadian dollars unless otherwise stated. 2 Management’s Discussion and Analysis 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. Precision Drilling Corporation 2013 Annual Report 3 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 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. Precision Drilling Corporation 2013 Annual Report 5 About Precision Management’s Discussion and Analysis 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 Two Business Segments We operate our business in two segments, supported by vertically integrated business support systems. Precision Drilling Corporation Completion and Production Services (cid:127) Canada and U.S. – Service rigs, snubbing and coil tubing – Equipment rentals – Camps, catering and water systems Contract Drilling Services (cid:127) Drilling rig operations – Canada – U.S. – International (cid:127) Directional drilling operations – Canada – U.S. Business support systems (cid:127) Sales and marketing (cid:127) Procurement and distribution (cid:127) Manufacturing (cid:127) Equipment maintenance and certification (cid:127) Engineering Corporate support (cid:127) Governance (cid:127) Information systems (cid:127) Health, safety and environment (cid:127) Human resources (cid:127) Finance (cid:127) Enterprise risk management 2013 Adjusted EBITDA by Operating Segment 2013 Revenue by Region Contract Drilling Services 91% Completion and Production Services 9% International 7% Canada 49% U.S. 44% Precision Drilling Corporation 2013 Annual Report 7 CONTRACT DRILLING SERVICES We provide onshore drilling services to exploration and production companies in the oil and natural gas industry, operating in 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 Tier 1 Tier 2 PSST Total < 1000 1000-1500 >1500 96 63 15 174 101 21 4 126 3 19 5 27 Geographic location Canada U.S. International Tier 1 Tier 2 PSST Total 110 62 15 187 87 31 9 127 3 10 – 13 Total 200 103 24 327 Total 200 103 24 327 Contract Drilling Revenue Contract Drilling Adjusted EBITDA $ Millions $2,000 $1,500 $1,000 $500 0 $ Millions $800 $600 $400 $200 0 Contract Drilling Utilization Days Utilization Days 80,000 60,000 40,000 20,000 0 2009 2010 2011 2012 2013 2009 2010 2011 2012 2013 2009 2010 2011 2012 2013 Note: 2009 was prepared under previous Canadian generally accepted accounting principles 8 Management’s Discussion and Analysis COMPLETION AND PRODUCTION SERVICES We provide completion and workover services and ancillary services and equipment rentals to oil and natural gas exploration and production companies primarily in Canada, with a 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 Singles: Freestanding mobile Doubles: Mobile Freestanding mobile Skid Slants: Freestanding Total service rigs Snubbing units Coil tubing units Total service rigs, snubbing units and coil tubing units Horsepower 2009 2010 2011 2012 2013 150-400 250-550 200-550 300-860 250-400 94 28 30 30 18 200 20 – 220 94 25 35 28 18 200 20 – 220 90 19 40 22 18 189 18 – 207 90 19 40 22 19 190 19 5 214 90 19 40 22 20 191 19 12 222 Completion and Production Revenue Completion and Production Adjusted EBITDA Completion and Production Service Rig Hours $ Millions $400 $300 $200 $100 0 $ Millions $125 $100 $75 $50 $25 0 Hours 400,000 300,000 200,000 100,000 0 2009 2010 2011 2012 2013 2009 2010 2011 2012 2013 2009 2010 2011 2012 2013 Note: 2009 was prepared under previous Canadian generally accepted accounting principles Precision Drilling Corporation 2013 Annual Report 9 2013 Highlights and Outlook Management’s Discussion and Analysis 2 Adjusted EBITDA and funds provided by operations are additional GAAP measures. See page 5 for more information. Financial Highlights Year ended December 31 (thousands of dollars, except where noted) % increase/ 2013 (decrease) 2012 % increase/ (decrease) 2,029,977 638,833 31.5% 191,150 428,086 461,973 282,145 141,132 112,527 (13,372) 522,432 (0.5) (4.8) 265.1 (32.6) (22.9) (52.7) 8.5 (20.6) (57.4) (37.6) 2,040,741 670,792 32.9% 52,360 635,286 598,812 596,194 130,094 141,769 (31,423) 836,634 4.6 (3.5) (72.9) 19.2 1.1 30.9 (13.2) 16.9 96.6 17.8 – (100.0) 25 (100.0) 92,886 0.69 0.66 0.21 263.2 266.7 320.0 0.19 0.18 0.05 (72.9) (73.1) n/m 0.70 0.67 – 2011 1,951,027 695,064 35.6% 193,477 532,772 592,388 455,302 149,811 121,244 (15,983) 710,374 % increase/ (decrease) 36.5 59.8 344.4 74.0 46.6 539.7 174.0 142.3 30.4 334.1 n/m 337.5 346.7 – % increase/ 2013 (decrease) 327 1.9 30,530 30,268 3,555 222 283,576 (5.6) (12.5) 70.4 3.7 (3.8) 2012 321 32,352 34,597 2,086 214 294,681 % increase/ (decrease) (4.7) (14.8) (8.7) 197.2 3.4 (7.2) 2011 337 37,970 37,887 702 207 317,418 % increase/ (decrease) (5.1) 21.8 16.8 16.6 (5.9) 7.9 Revenue Adjusted EBITDA Adjusted EBITDA % of revenue Net earnings Cash provided by operations Funds provided by operations Investing activities Capital spending Expansion Upgrade Maintenance and infrastructure Proceeds on sale Net capital spending Business acquisitions (net of cash acquired) Earnings per share ($) Basic Diluted Dividends per share ($) n/m – calculation not meaningful. Operating Highlights Year ended December 31 Contract drilling rig fleet Drilling rig utilization days Canada U.S. International Service rig fleet Service rig operating hours 10 Management’s Discussion and Analysis Financial Position and Ratios Year ended December 31 (thousands of dollars, except ratios) Working capital Working capital ratio Long-term debt Total long-term financial liabilities Total assets Enterprise value1 Long-term debt to long-term debt plus equity Long-term debt to cash provided by operations Long-term debt to enterprise value 2013 305,783 1.9 1,323,268 1,355,535 4,579,123 3,919,763 0.36 3.09 0.34 2012 278,021 1.7 1,218,796 1,245,290 4,300,263 3,213,406 0.36 1.92 0.38 2011 610,429 2.4 1,239,616 1,267,040 4,427,874 3,528,046 0.37 2.33 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. Precision Drilling Corporation 2013 Annual Report 11 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 i % n g r a M 50 40 30 20 10 0 2009 2010 2011 2012 2013 Revenue and Adjusted EBITDA Adjusted EBITDA Margin Adjusted EBITDA Revenue Source: Precision Drilling Funds From Operations Note: 2009 was prepared under previous Canadian GAAP 2,500 2,000 s n o i l l i m $ 1,500 1,000 500 0 700 600 500 400 300 200 100 0 s n o i l l i M $ Source: Precision Drilling 2009 2010 2011 2012 2013 Drilling Utilization Days 80,000 60,000 s y a D 40,000 20,000 0 International USA Canada Source: Precision Drilling 2009 2010 2011 2012 2013 Precision Drilling Corporation 2013 Annual Report 13 Understanding our Business Drivers Management’s Discussion and Analysis 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. 160 140 120 100 80 60 40 20 0 l e r r a b / $ S U Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 WTI Oil Prices and Henry Hub Natural Gas Prices Henry Hub Natural Gas Prices West Texas Intermediate (“WTI”) Oil Prices Source: Precision Drilling 16 14 12 10 8 6 4 2 t u B M M / $ S U 0 Jan-09 14 Management’s Discussion and Analysis 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. Rigs Drilling Directional/Horizontal Wells in Canada Precision’s capabilities are demonstrated by the high proportion of rigs drilling complex wells. Precision Canada Active Land Rigs Canada Industry Excluding Precision Source: Whelby Data 100 90 80 70 60 50 40 30 20 10 s l l e W l t a n o z i r o H / l a n o i t c e r i D f t o e g a n e c r e P 0 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 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. U.S. Lower 48 Production 80 70 60 50 ) d / f c B ( s a G l a r u a N t U.S. Lower 48 Natural Gas Production U.S. Crude Oil Production Source: Energy Information Administration 40 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 8 7 6 5 4 l ) d / s b b M M ( l i O e d u r C Precision Drilling Corporation 2013 Annual Report 15 Canadian Production 18 ) d / f c B ( s a G l a r u a N t 16 14 Canadian Natural Gas Production Canadian Crude Oil Production Source: Energy Information Administration and First Energy Capital 12 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 4.0 3.0 2.0 1.0 l ) d / s b b M M ( l i O e d u r C 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. U.S. Drilling Rig Activity 1,600 i g n k r o W s g R i 1,200 800 400 0 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Natural Gas Rigs Crude Oil Rigs Source: Baker Hughes, Inc. Canadian Drilling Rig Activity 600 i g n k r o W s g R i 400 200 0 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Natural Gas Rigs Crude Oil Rigs Source: Baker Hughes, Inc. 16 Management’s Discussion and Analysis 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. Precision Drilling Corporation 2013 Annual Report 17 Tracking Our Results We unitize key financial information per day and per hour, and compare these measures to established benchmarks and past performance. We evaluate the relative strength of our financial position by monitoring our working capital, debt ratios, and returns on capital employed. We track industry rig utilization statistics to evaluate our performance against competitors. We link incentive compensation for our senior team to returns generated compared to established benchmarks. We reward executives and eligible employees through incentive compensation plans for performance against the following measures:  Safety performance – total recordable incident frequency per 200,000 man-hours. Measured against prior year performance and current year industry performance in Canada and the U.S.  Operational performance – rig down time for repair as measured by time not billed to the customer. Measured against predetermined target of available billable time.  Key field employee retention – senior field employee retention rates. Measured against predetermined target of retention.  Financial performance – return on capital employed calculated as a percentage of pre-tax operating earnings divided by total assets less current liabilities. Measured against predetermined target percentage.  Investment returns – total shareholder return performance against an industry peer group, including dividends, over a three year period. Measured against predetermined competitors in the established peer group. Top Tier Service We pride ourselves on providing quality equipment operated by experienced and well trained crews. We also strive to align our capabilities with evolving technical requirements associated with more complex well bore programs. High Performance Rig Fleet Our fleet of drilling rigs is well positioned to address the unconventional drilling programs of our customers. The vast majority of our drilling rigs have been designed or significantly upgraded to drill horizontal wells. With a breadth of horsepower types and drilling depth capabilities, our large fleet can address every type of onshore unconventional oil and natural gas drilling in North America. In 2013, we high-graded our drilling rig fleet by:  adding seven Tier 1 new-build drilling rigs  upgrading 19 drilling rigs – about a quarter of these were Tier upgrades. As at December 31, 2013, 93% of our 327 drilling rigs were Tier 1 or Tier 2 rigs. Tier 1 – 200 drilling rigs Rigs are better suited to meet the challenges of complex customer requirements for resource exploitation in North American shale and unconventional plays High performance Super Series rigs, innovative in design, capable of drilling directionally or horizontally, highly mobile (move with pad walking or skidding systems or require fewer trucking loads) Features  highly mechanized tubular handling equipment  integrated top drive or top drive adaptability  advanced AC, silicone controlled rectifier (SCR) and mechanical power distribution and control efficiencies  electronic or hydraulic control of the majority of operating parameters  specialized drilling tubulars  high-capacity mud pumps  majority use Range III drill pipe Tier 2 – 103 drilling rigs High performance rigs, capable of drilling directionally or horizontally, generally less mobile than Tier 1 rigs High performance rigs with new equipment and modifications to improve performance and enhance directional and horizontal drilling capability PSST (Precision seasonal, stratigraphic and turnkey) – 24 drilling rigs Typically, conventional mechanical rigs with no automation and lower pumping capacity Features  some mechanization of tubular handling equipment  top drive adaptability  SCR or mechanical type power systems  increased hookload and or racking capabilities  upgraded power generating, control systems and other major components  high-capacity mud pumps 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. Precision Drilling Corporation 2013 Annual Report 19 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 2014 Execute our High Performance, High Value strategy Continue to drive execution excellence in our people, internal systems and infrastructure. Improved safety performance in both operating segments in 2013, matching the best results in our history. Began construction of our Nisku Centre. 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. 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. Build our brand Uphold our reputation and market breadth in North America while strengthening our presence in select oilfield markets internationally. 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. 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. 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. 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. 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. Precision Drilling Corporation 2013 Annual Report 21 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 Precision Drilling Corporation 2013 Annual Report 23 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. Precision Drilling Corporation 2013 Annual Report 25 2013 Results Management’s Discussion and Analysis 4 Adjusted EBITDA and operating earnings are additional GAAP measures. See page 5 for more information. Consolidated Statements of Earnings Summary Year ended December 31 (thousands of dollars) 2013 2012 2011 1,719,910 323,353 (13,286) 2,029,977 653,664 61,032 (75,863) 638,833 333,159 – 305,674 – (9,112) 93,248 221,538 30,388 191,150 1,725,240 326,079 (10,578) 2,040,741 649,281 93,554 (72,043) 670,792 307,525 192,469 170,798 52,539 3,753 86,829 27,677 (24,683) 52,360 1,632,037 330,225 (11,235) 1,951,027 665,389 104,252 (74,577) 695,064 251,483 114,893 328,688 – (23,674) 111,578 240,784 47,307 193,477 2013 2012 2011 1,002,199 1,053,966 1,071,526 901,246 137,681 (11,149) 936,113 64,017 (13,355) 866,776 22,994 (10,269) 2,029,977 2,040,741 1,951,027 2,082,958 2,006,519 489,646 4,579,123 2,119,891 1,913,810 266,562 4,300,263 2,252,084 2,027,676 148,114 4,427,874 Revenue Contract Drilling Services Completion and Production Services Inter-segment elimination Adjusted EBITDA Contract Drilling Services Completion and Production Services Corporate and other Depreciation and amortization Loss on asset decommissioning Operating earnings Impairment of goodwill Foreign exchange Finance charges Earning before income taxes Income taxes Net earnings Results by Geographic Segment Year ended December 31 (thousands of dollars) Revenue Canada U.S. International Inter-segment elimination Total assets Canada U.S. International 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 Oil 2013 2012 2011 West Texas Intermediate (per barrel) US$98.02 US$94.13 US$95.02 Natural gas Canada AECO (per MMBtu) U.S. Henry Hub (per MMBtu) $3.18 $2.39 $3.62 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. Precision Drilling Corporation 2013 Annual Report 27 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) Revenue Expenses Operating General and administrative Adjusted EBITDA Depreciation and amortization Loss on asset decommissioning Operating earnings 2013 1,719,910 1,019,156 47,090 653,664 292,217 – 361,447 % of revenue 59.3 2.7 38.0 17.0 – 21.0 2012 1,725,240 1,036,553 39,406 649,281 271,993 192,469 184,819 % of revenue 60.1 2.3 37.6 15.8 11.1 10.7 2011 1,632,037 931,062 35,586 665,389 219,194 113,366 332,829 % of revenue 57.0 2.2 40.8 13.4 7.0 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  $98 million – on maintenance and infrastructure. Most of the expansion capital was for our rig build program; seven of these were completed and placed into service by December 31, 2013. Precision Drilling Corporation 2013 Annual Report 29 Operating Statistics Year ended December 31 Number of drilling rigs (year-end) Drilling utilization days (operating and moving) Canada U.S. International Drilling revenue per utilization day Canada (Cdn$) U.S.(US$) Drilling statistics (Canadian operations only) Wells drilled Average days per well Metres drilled (hundreds) Average metres per well 2013 327 30,530 30,268 3,555 22,108 23,575 3,211 8.4 5,576 1,736 % increase/ (decrease) 1.9 (5.6) (12.5) 70.4 5.1 (0.5) 4.1 (10.6) 6.6 2.4 2012 321 32,352 34,597 2,086 21,030 23,696 3,085 9.4 5,233 1,696 % increase/ (decrease) (4.7) (14.8) (8.7) 197.2 14.0 9.0 (13.5) (1.1) (8.5) 5.8 2011 337 37,970 37,887 702 18,442 21,744 3,566 9.5 5,717 1,603 % increase/ (decrease) (5.1) 21.8 16.8 16.6 14.3 14.7 11.6 8.0 11.7 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. Average number of active land rigs for quarters ended: March 31 June 30 September 30 December 31 Annual average 1 Source: Baker Hughes 2013 2012 Precision Industry1 Precision Industry1 81 80 81 90 83 1,706 1,710 1,709 1,697 1,705 104 97 90 87 95 1,947 1,924 1,855 1,759 1,871 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) Revenue Expenses Operating General and administrative Adjusted EBITDA Depreciation and amortization Loss on asset decommissioning Operating earnings 2013 323,353 242,768 19,553 61,032 32,630 – 28,402 % of revenue 75.1 6.0 18.9 10.1 8.8 2012 326,079 217,326 15,199 93,554 30,758 – 62,796 % of revenue 66.6 4.7 28.7 9.4 – 19.3 2011 330,225 211,195 14,778 104,252 25,598 1,527 77,127 % of revenue 64.0 4.5 31.6 7.8 0.5 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. Precision Drilling Corporation 2013 Annual Report 31 Operating Results Year ended December 31 Number of service rigs (end of year)1 Service rig operating hours2 Revenue per operating hour2 2013 222 283,576 854 % increase/ (decrease) 3.7 (3.8) 14.8 2012 214 294,681 744 % increase/ (decrease) 3.4 (7.2) 8.1 2011 207 317,418 688 % increase/ (decrease) (5.9) 7.9 8.0 1 Now includes snubbing services. Comparative numbers have been restated to reflect this change. 2 Prior year comparatives have been changed to include U.S. based service rig activity. In 2013, we added one coil tubing unit in Canada and six in the U.S. In addition, we moved two service rigs from Canada to the U.S., added one service rig to Canada and moved one snubbing unit from the U.S. to Canada. We also added rental equipment as we continue to expand our North American footprint. Service rig rates increased 15% as we provided higher-end services and crew wage increases were passed through to customers. Our service rig hours decreased 4% although higher rig rates and our U.S. expansion partially offset market activity declines. CORPORATE AND OTHER Financial Results Adjusted EBITDA is an additional GAAP measure. See page 5 for more information. Year ended December 31 (thousands of dollars) 2013 2012 2011 Revenue Expenses Operating General and administrative Adjusted EBITDA Depreciation and amortization Operating earnings (loss) – – 75,863 (75,863) 8,312 (84,175) – – 72,043 (72,043) 4,774 (76,817) – – 74,577 (74,577) 6,691 (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 31 Revenue Adjusted EBITDA Net earnings (loss) Per basic share Per diluted share Funds provided by operations Cash provided by operations Dividends per share 595,720 215,181 93,313 0.34 0.33 144,682 62,948 0.05 378,898 88,248 473 0.00 0.00 33,791 182,345 0.05 488,450 137,660 29,443 0.11 0.10 127,684 88,341 0.05 566,909 197,744 67,921 0.24 0.24 155,816 94,452 0.06 2012 – Quarters Ended (thousands of dollars, except per share amounts) March 31 June 30 September 30 December 31 Revenue Adjusted EBITDA Net earnings (loss) Per basic share Per diluted share Funds provided by operations Cash provided by operations Dividends per share 640,066 245,574 111,081 0.40 0.39 247,739 162,440 – 381,966 97,192 18,261 0.07 0.06 62,373 275,346 – 484,761 151,000 39,357 0.14 0.14 146,124 61,183 – 533,948 177,026 (116,339) (0.42) (0.42) 142,576 136,317 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. Precision Drilling Corporation 2013 Annual Report 33 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. Precision Drilling Corporation 2013 Annual Report 35 Financial Condition Management’s Discussion and Analysis 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) Working capital Working capital ratio Long-term debt Total long-term financial liabilities Total assets Enterprise value (see table on page 40) Long-term debt to long-term debt plus equity Long-term debt to cash provided by operations Long-term debt to adjusted EBITDA Long-term debt to enterprise value 2013 305,783 1.9 1,323,268 1,355,535 4,579,123 3,919,763 0.36 3.09 2.07 0.34 2012 278,021 1.7 1,218,796 1,245,290 4,300,263 3,213,406 0.36 1.92 1.82 0.38 2011 610,429 2.4 1,239,616 1,267,040 4,427,874 3,528,046 0.37 2.33 1.78 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. Corporate credit rating Senior secured bank credit facility rating Senior unsecured credit rating Moody’s Ba1 S&P BB+ Not rated Not rated 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. Precision Drilling Corporation 2013 Annual Report 37 SOURCES AND USES OF CASH At December 31 (thousands of dollars) Cash from operations Cash used in investing Deficit Cash (used in) from financing Effect of exchange rate changes on cash Net cash generated (used) 2013 428,086 (526,535) (98,449) 21,517 4,770 (72,162) 2012 635,286 (930,121) (294,835) (14,899) (4,974) (314,708) 2011 532,772 (715,462) (182,690) 366,887 26,448 210,645 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 Maturity Senior facility (secured) US$850 million (extendible, revolving term credit facility with US$250 million accordion feature) Drawn US$28 million and US$29 million in outstanding letters of credit General corporate purposes November 17, 2018 Operating facilities (secured) $40 million Undrawn, except $17 million in outstanding letters of credit Letters of credit and general corporate purposes US$15 million Undrawn Short term working capital requirements Demand letter of credit facility (secured) US$25 million Undrawn, except $0.2 million in outstanding letters of credit Letters of credit Senior notes (unsecured) $200 million US$650 million US$400 million Fully drawn Fully drawn Fully drawn Debt repayment Debt repayment and general corporate purposes March 15, 2019 November 15, 2020 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. At December 31, 2013 (thousands of dollars) Long-term Interest on long-term debt Rig construction Operating leases Contractual incentive plans1 Contingent purchase consideration Total Less than 1 year – 87,176 150,624 16,833 14,952 28,133 297,718 Payments due (by period) 1-3 years 4-5 years – 174,352 – 25,434 29,788 – 229,574 29,781 174,263 – 15,824 – – More than 5 years 1,316,780 170,394 – 15,714 – – Total 1,346,561 606,185 150,624 73,805 44,740 28,133 219,868 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. Precision Drilling Corporation 2013 Annual Report 39 CAPITAL STRUCTURE Shares outstanding Deferred shares outstanding Warrants outstanding Share options outstanding March 7, 2014 December 31, 2013 December 31, 2012 December 31, 2011 291,979,671 291,979,671 276,475,770 276,081,797 221,112 – 221,112 – 9,515,278 8,074,694 335,946 15,000,000 6,413,777 417,495 15,000,000 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) Shares outstanding Year-end share price on the TSX Shares at market Long-term debt Less working capital Enterprise value December 31, 2013 December 31, 2012 December 31, 2011 291,979,671 276,475,770 276,081,797 9.94 2,902,278 1,323,268 (305,783) 3,919,763 8.22 2,272,631 1,218,796 (278,021) 3,213,406 10.50 2,898,859 1,239,616 (610,429) 3,528,046 40 Management’s Discussion and Analysis Accounting Policies and Estimates Management’s Discussion and Analysis 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. Precision Drilling Corporation 2013 Annual Report 41 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 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. Precision Drilling Corporation 2013 Annual Report 43 Evaluation of Disclosure Controls and Procedures Management’s Discussion and Analysis 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 Corporate Governance Management’s Discussion and Analysis 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. Precision Drilling Corporation 2013 Annual Report 45 Management’s Report to the Shareholders The accompanying consolidated financial statements and all information in this Annual Report are the responsibility of management. The consolidated financial statements have been prepared by management in accordance with the accounting policies in the notes to the consolidated financial statements. When necessary, management has made informed judgments and estimates in accounting for transactions that were not complete at the balance sheet date. In the opinion of management, the consolidated financial statements have been prepared within acceptable limits of materiality, and are in accordance with International Financial Reporting Standards (IFRS) appropriate in the circumstances. The financial information elsewhere in the Annual Report has been reviewed to ensure consistency with that in the consolidated financial statements. Management has prepared Management’s Discussion and Analysis (MD&A). The MD&A is based on the financial results of Precision Drilling Corporation (the Corporation) prepared in accordance with IFRS. The MD&A compares the audited financial results for the years ended December 31, 2013 to December 31, 2012 and the years ended December 31, 2012 to December 31, 2011. Management is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting and is supported by an internal audit function that conducts periodic testing of these controls. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external reporting purposes in accordance with IFRS. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with direction from our principal executive officer and principal financial and accounting officer, management conducted an evaluation of the effectiveness of the Corporation’s internal control over financial reporting. Management’s evaluation of internal control over financial reporting was based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (1992). Based on this evaluation, management concluded that the Corporation’s internal control over financial reporting was effective as of December 31, 2013. Also management determined that there were no material weaknesses in the Corporation’s internal control over financial reporting as of December 31, 2013. KPMG LLP (KPMG), an independent firm of Chartered Accountants, was engaged, as approved by a vote of shareholders at the Corporation’s most recent annual meeting, to audit the consolidated financial statements and provide an independent professional opinion. KPMG completed an audit of the design and effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2013, as stated in its report included herein, and expressed an unqualified opinion on the design and effectiveness of internal control over financial reporting as of December 31, 2013. The Audit Committee of the Board of Directors, which is comprised of five independent directors who are not employees of the Corporation, provides oversight to the financial reporting process. Integral to this process is the Audit Committee’s review and discussion with management and KPMG of the quarterly and annual financial statements and reports prior to their respective release. The Audit Committee is also responsible for reviewing and discussing with management and KPMG major issues as to the adequacy of the Corporation’s internal controls. KPMG has unrestricted access to the Audit Committee to discuss its audit and related matters. The consolidated financial statements have been approved by the Board of Directors of Precision Drilling Corporation and its Audit Committee. Kevin A. Neveu President and Chief Executive Officer Precision Drilling Corporation Robert J. McNally Executive Vice President and Chief Financial Officer Precision Drilling Corporation March 7, 2014 March 7, 2014 46 Consolidated Financial Statements Independent Auditors’ Report of Registered Public Accounting Firm To the Shareholders and Board of Directors of Precision Drilling Corporation We have audited the accompanying consolidated financial statements of Precision Drilling Corporation (the Corporation), which comprise the consolidated statements of financial position as at December 31, 2013 and December 31, 2012, the consolidated statements of earnings, comprehensive income, changes in equity and cash flow for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information. Management’s Responsibility for the Consolidated Financial Statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. Auditors’ Responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Corporation as at December 31, 2013 and December 31, 2012, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. Other Matter We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Corporation’s internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (1992), and our report dated March 7, 2014 expressed an unqualified opinion on the effectiveness of the Corporation’s internal control over financial reporting. Chartered Accountants Calgary, Canada March 7, 2014 Precision Drilling Corporation 2013 Annual Report 47 Report of Independent Registered Public Accounting Firm To the Shareholders and Board of Directors of Precision Drilling Corporation We have audited Precision Drilling Corporation’s (the Corporation) internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (1992). The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report to the Shareholders. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (1992). We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Corporation as of December 31, 2013 and December 31, 2012, and the related consolidated statements of income, shareholders’ equity and cash flow for the years then ended, and our report dated March 7, 2014 expressed an unqualified opinion on those consolidated financial statements. Chartered Accountants Calgary, Canada March 7, 2014 48 Consolidated Financial Statements Consolidated Statements of Financial Position (Stated in thousands of Canadian dollars) ASSETS Current assets: Cash Accounts receivable Inventory Total current assets Non-current assets: Income tax recoverable Property, plant and equipment Intangibles Goodwill Total non-current assets Total assets LIABILITIES AND EQUITY Current liabilities: December 31, 2013 December 31, 2012 $ 80,606 $ 549,697 12,378 642,681 58,435 3,561,734 3,917 312,356 152,768 509,547 13,787 676,102 64,579 3,242,929 6,101 310,552 3,936,442 3,624,161 $ 4,579,123 $ 4,300,263 (Note 23) (Note 4) (Note 5) (Note 6) Accounts payable and accrued liabilities (Note 23) $ 332,838 $ 333,893 Income tax payable Total current liabilities Non-current liabilities: Share based compensation Provisions and other Long-term debt Deferred tax liabilities Total non-current liabilities Shareholders’ equity: Shareholders’ capital Contributed surplus Retained earnings (deficit) (Note 8) (Note 9) (Note 10) (Note 11) 4,060 336,898 14,431 17,836 1,323,268 487,347 1,842,882 64,188 398,081 8,676 17,818 1,218,796 485,592 1,730,882 (Note 12) 2,305,227 2,251,982 29,175 88,416 (23,475) 24,474 (44,621) (60,535) 2,399,343 2,171,300 $ 4,579,123 $ 4,300,263 Accumulated other comprehensive loss (Note 13) Total shareholders’ equity Total liabilities and shareholders’ equity See accompanying notes to consolidated financial statements. Approved by the Board of Directors: Allen R. Hagerman Director Patrick M. Murray Director Precision Drilling Corporation 2013 Annual Report 49 Consolidated Statements of Earnings Years ended December 31, (Stated in thousands of Canadian dollars, except per share amounts) Revenue Expenses: Operating General and administrative Earnings before income taxes, finance charges, foreign exchange, impairment of goodwill, loss on asset decommissioning and depreciation and amortization Depreciation and amortization Loss on asset decommissioning Operating earnings Impairment of goodwill Foreign exchange Finances charges Earnings before tax Income taxes: Current Deferred Net earnings Earnings per share: Basic Diluted (Note 23) (Note 23) (Note 4) (Note 14) (Note 11) (Note 18) 2013 2012 $ 2,029,977 $ 2,040,741 1,248,637 142,507 1,243,301 126,648 638,833 333,159 – 305,674 – (9,112) 93,248 221,538 45,017 (14,629) 30,388 191,150 0.69 0.66 $ $ $ $ $ $ 670,792 307,525 192,469 170,798 52,539 3,753 86,829 27,677 70,576 (95,259) (24,683) 52,360 0.19 0.18 See accompanying notes to consolidated financial statements. Consolidated Statements of Comprehensive Income Years ended December 31, (Stated in thousands of Canadian dollars) Net earnings Unrealized gain (loss) on translation of assets and liabilities of operations denominated in foreign currency Foreign exchange gain (loss) on net investment hedge with U.S. denominated debt, net of tax Comprehensive income See accompanying notes to consolidated financial statements. 2013 2012 $ 191,150 $ 52,360 109,195 (32,878) (72,135) $ 228,210 $ 23,205 42,687 50 Consolidated Financial Statements Consolidated Statements of Cash Flow Years ended December 31, (Stated in thousands of Canadian dollars) Cash provided by (used in): Operations: Net earnings Adjustments for: Long-term compensation plans Depreciation and amortization Loss on asset decommissioning Impairment of goodwill Foreign exchange Finance charges Income taxes Other Income taxes paid Income taxes recovered Interest paid Interest received Funds provided by operations Changes in non-cash working capital balances (Note 23) Investments: Business acquisitions, net of cash acquired Purchase of property, plant and equipment Proceeds on sale of property, plant and equipment Changes in income tax recoverable (Note 19) (Note 4) Changes in non-cash working capital balances (Note 23) Financing: Debt issue costs Debt facility amendment costs Dividends paid Increase in long-term debt Issuance of common shares on the exercise of options Issuance of common shares on the exercise of warrants (Note 12) (Note 12) (Note 12) Effect of exchange rate changes on cash and cash equivalents Decrease in cash and cash equivalents Cash and cash equivalents, beginning of year Cash and cash equivalents, end of year See accompanying notes to consolidated financial statements. 2013 2012 $ 191,150 $ 52,360 20,708 333,159 – – (9,216) 93,248 30,388 (3,754) (109,326) 3,761 (89,156) 1,011 461,973 (33,887) 428,086 – (535,804) 13,372 6,144 (10,247) (526,535) (883) – (58,113) 29,781 2,432 48,300 21,517 4,770 (72,162) 152,768 $ 80,606 $ 19,350 307,525 192,469 52,539 4,403 86,829 (24,683) 1,018 (10,403) 721 (85,251) 1,935 598,812 36,474 635,286 (25) (868,057) 31,423 – (93,462) (930,121) (2,855) (149) (13,821) – 1,926 – (14,899) (4,974) (314,708) 467,476 152,768 Precision Drilling Corporation 2013 Annual Report 51 Consolidated Statements of Changes in Equity (Stated in thousands of Canadian dollars) Balance at January 1, 2013 Net earnings for the period Other comprehensive income for the period Dividends Shareholders’ capital Contributed surplus Accumulated other comprehensive loss (Note 13) Retained earnings (deficit) Total equity $ 2,251,982 $ 24,474 $ (60,535) $ (44,621) $ 2,171,300 – – – – – – – 191,150 191,150 37,060 – – – – – – (58,113) – – – – 37,060 (58,113) 2,432 207 48,300 7,007 Share options exercised (Note 12) 3,707 (1,275) Shares issued on redemption of non-management directors’ DSUs Warrants exercised Share based compensation expense (Note 8) 1,238 48,300 – (1,031) – 7,007 Balance at December 31, 2013 $ 2,305,227 $ 29,175 $ (23,475) $ 88,416 $ 2,399,343 Shareholders’ capital Contributed surplus Accumulated other comprehensive loss (Note 13) Deficit Total equity $ 2,248,217 $ 18,396 $ (50,862) $ (83,160) $ 2,132,591 (Stated in thousands of Canadian dollars) Balance at January 1, 2012 Net earnings for the period Other comprehensive loss for the period Dividends – – – – – – Share options exercised (Note 12) 3,050 (1,124) Shares issued on redemption of non-management directors’ DSUs Shares issued on waiver of right to dissent by dissenting unitholder Share based compensation expense (Note 8) 706 (706) 9 – (3) 7,911 – 52,360 52,360 (9,673) – – – – – – (13,821) – – – – (9,673) (13,821) 1,926 – 6 7,911 Balance at December 31, 2012 $ 2,251,982 $ 24,474 $ (60,535) $ (44,621) $ 2,171,300 See accompanying notes to consolidated financial statements. 52 Consolidated Financial Statements Notes to Consolidated Financial Statements (Tabular amounts are stated in thousands of Canadian dollars except share numbers and per share amounts) NOTE 1. DESCRIPTION OF BUSINESS Precision Drilling Corporation (Precision or the Corporation) is incorporated under the laws of the Province of Alberta, Canada and is a provider of contract drilling and completion and production services primarily to oil and natural gas exploration and production companies in Canada, the United States and certain international locations. The address of the registered office is 800, 525 – 8th Avenue S.W., Calgary, Alberta, Canada, T2P 1G1. NOTE 2. BASIS OF PREPARATION (a) Statement of Compliance These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). These consolidated financial statements were authorized for issue by the Board of Directors on March 7, 2014. (b) Basis of Measurement The consolidated financial statements have been prepared using the historical cost basis except as detailed in the Corporation’s accounting policies in Note 3 and are presented in thousands of Canadian dollars. (c) Use of Estimates and Judgments The preparation of the consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingencies. These estimates and judgments are based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. The estimation of anticipated future events involves uncertainty and, consequently, the estimates used in preparation of the consolidated financial statements may change as future events unfold, more experience is acquired or the Corporation’s operating environment changes. Significant estimates and judgments used in the preparation of the financial statements are described in Note 3. NOTE 3. SIGNIFICANT ACCOUNTING POLICIES (a) Basis of Consolidation These consolidated financial statements include the accounts of the Corporation and all of its subsidiaries and partnerships substantially all of which are wholly-owned. The financial statements of the subsidiaries are prepared for the same period as the parent entity, using consistent accounting policies. All significant intercompany balances, transactions and any unrealized gains and losses arising from intercompany transactions, have been eliminated. Subsidiaries are entities controlled by the Corporation. Control exists when Precision has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases. Precision does not hold investments in any companies where it exerts significant influence and does not hold interests in any special-purpose entities. The acquisition method is used to account for acquisitions of subsidiaries and assets that meet the definition of a business under IFRS. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the cost of acquisition over the fair value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognized immediately in the statement of earnings. Transaction costs, other than those associated with the issuance of debt or equity securities, that the Corporation incurs in connection with a business combination are expensed as incurred. Precision Drilling Corporation 2013 Annual Report 53 (b) Cash and Cash Equivalents Cash and cash equivalents consist of cash and short-term investments with original maturities of three months or less. (c) Inventory Inventory is primarily comprised of operating supplies and is carried at the lower of average cost, being the cost to acquire the inventory, and net realizable value. Inventory is charged to operating expenses as items are sold or consumed at the amount of the average cost of the item. (d) Property, Plant and Equipment Property, plant and equipment are carried at cost, less accumulated depreciation and any accumulated impairment losses. Cost includes an expenditure that is directly attributable to the acquisition of the asset. The cost of self-constructed assets includes the cost of materials and direct labour, any other costs directly attributable to bringing the assets to a working condition for their intended use and borrowing costs on qualifying assets. The cost of replacing a part of an item of property, plant and equipment is recognized in the carrying amount of the item if it is probable that the future economic benefits embodied within the part will flow to the Corporation, and its cost can be measured reliably. The carrying amount of the replaced part is derecognized. The costs of the day-to-day servicing of property, plant and equipment (repair and maintenance) are recognized in profit or loss as incurred. Property, plant, and equipment are depreciated as follows: Expected Life Salvage Value Basis of Depreciation Drilling rig equipment: – Power & Tubulars – Dynamic – Structural 1,700 utilization days 3,400 utilization days 5,000 utilization days Seasonal, stratification and turnkey drilling equipment 4 years Service rig equipment 24,000 service hours Drilling rig spare equipment Service rig spare equipment Rental equipment Other equipment Light duty vehicles Heavy duty vehicles Buildings up to 15 years up to 15 years 10 to 15 years 3 to 10 years 4 years 7 to 10 years 10 to 20 years – – 20% 0 to 20% 20% – – 0 to 25% – – – – unit-of-production unit-of-production unit-of-production straight-line unit-of-production straight-line straight-line straight-line straight-line straight-line straight-line straight-line Assets that are depreciated on a unit-of-production method that have less than 60 utilization days (drilling rig equipment) or 600 service hours (service rig equipment) in a rolling 12 month period are deemed to be idle and are depreciated at a rate of five utilization days or 50 service hours per month until the asset exceeds the utilization threshold. Gains and losses on disposal of an item of property, plant and equipment are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment, and are recognized in the statements of earnings. The estimated useful lives, residual values and methods or depreciation are reviewed annually, and adjusted prospectively if appropriate. (e) Intangibles Intangible assets that are acquired by the Corporation with finite lives are initially recorded at estimated fair value and subsequently measured at cost less accumulated amortization and any accumulated impairment losses. Subsequent expenditures are capitalized only when it increases the future economic benefits of the specific asset to which it relates. 54 Notes to Consolidated Financial Statements Amortization is recognized in profit and loss using the straight-line method based over the estimated useful lives of the respective assets as follows: Customer relationships Patents Brand 1 to 5 years 10 years 1 to 5 years The estimated useful lives and methods of amortization are reviewed annually, and adjusted prospectively if appropriate. (f) Goodwill Goodwill is the amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the assets acquired, less liabilities assumed, based on their fair values. If the fair value of the identifiable net assets acquired exceeds the fair value of the consideration, Precision reassesses whether it has correctly identified and measured the assets acquired and liabilities assumed. If that excess remains after reassessment, Precision recognizes the resulting gain in profit or loss on the acquisition date. After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, attributed to the cash generating unit or groups of cash generating units that are expected to benefit and as identified in the business combination. (g) Impairment (i) Financial Assets A financial asset not carried at fair value through profit or loss is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is tested for impairment if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset. Objective evidence that financial assets are impaired can include default or delinquency by a debtor, restructuring of an amount due to the Corporation on terms that the Corporation would not consider otherwise, and indications that a debtor will enter bankruptcy. Precision considers evidence of impairment for receivables at both a specific asset and collective level. All individually significant receivables are assessed for specific impairment. All significant receivables found not to be specifically impaired are then collectively assessed for impairment by grouping together receivables with similar risk characteristics. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in profit or loss. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in profit or loss. (ii) Non-Financial Assets The carrying amounts of the Corporation’s non-financial assets, other than inventories and deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. For goodwill and other intangible assets that have indefinite lives or that are not yet available for use an impairment test is completed at the same time each year. For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the cash-generating unit or CGU). The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from the cash generating unit. Precision Drilling Corporation 2013 Annual Report 55 An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU on a pro rata basis. An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortization, if no impairment loss had been recognized. (h) Borrowing Costs Interest and borrowing costs that are directly attributable to the acquisition, construction or production of assets that take a substantial period of time to prepare for their intended use are capitalized as part of the cost of those assets. Capitalization ceases during any extended period of suspension of construction or when substantially all activities necessary to prepare the asset for its intended use are complete. All other interest and borrowing costs are recognized in earnings in the period in which they are incurred. (i) Income Taxes Income tax expense is recognized in net earnings except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity. Current tax is the expected tax payable or receivable on the taxable earnings or loss for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years. Deferred tax is recognized using the liability method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted at the reporting date. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in net earnings in the period that includes the date of enactment or substantive enactment. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset and they relate to taxes levied by the same tax authority on the same taxable entity, or on different tax entities that are expected to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously. A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized. (j) Revenue Recognition The Corporation’s services are generally sold based on service orders or contracts with a customer that include fixed or determinable prices based on daily, hourly or job rates. Customer contract terms do not include provisions for significant post-service delivery obligations. Revenue is recognized when services and equipment rentals are rendered and only when collectability is reasonably assured. The Corporation also provides services under turnkey contracts whereby it drills a well to an agreed upon depth under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. Revenue from turnkey drilling contracts is recognized using the percentage-of-completion method based on costs incurred to date and estimated total contract costs. Anticipated losses, if any, on uncompleted contracts are recorded at the time the estimated costs exceed the contract revenue. (k) Employee Benefit Plans Precision sponsors various defined contribution retirement plans for its employees. The Corporation’s contributions to defined contribution plans are expensed as employees earn the entitlement. 56 Notes to Consolidated Financial Statements (l) Provisions Provisions are recognized when the Corporation has a present obligation (legal or constructive) as a result of a past event, when it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and when a reliable estimate can be made of the amount of the obligation. The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows. (m) Share Based Incentive Compensation Plans The Corporation has established several cash settled share based incentive compensation plans for officers, non-management directors and other eligible employees. The fair values as estimated by management of the amounts payable to eligible participants under these plans are recognized as an expense with a corresponding increase in liabilities over the period that the participants become unconditionally entitled to payment. The recorded liability is re-measured at the end of each reporting period until settlement with the resultant change to the fair value of the liability recognized in net earnings for the period. When the plans are settled, the cash paid reduces the outstanding liability. Prior to January 1, 2012 the Corporation had an equity settled deferred share unit plan whereby non-management directors of Precision could elect to receive all or a portion of their compensation in fully-vested deferred share units. Compensation expense was recognized based on the fair value price of the Corporation’s shares at the date of grant with a corresponding increase to contributed surplus. Upon redemption of the deferred share units into common shares, the amount previously recognized in contributed surplus is recorded as an increase to shareholders’ capital. The Corporation continues to have obligations under this plan. A share option plan has been established for certain eligible employees. Under this plan the fair value of share purchase options is calculated at the date of grant using the Black-Scholes option pricing model and that value is recorded as compensation expense over the grant’s vesting period with an offsetting credit to contributed surplus. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest. Upon exercise of the equity purchase option, the associated amount is reclassified from contributed surplus to shareholders’ capital. Consideration paid by employees upon exercise of the equity purchase options is credited to shareholders’ capital. (n) Foreign Currency Translation Transactions of the Corporation’s individual entities are recorded in the currency of the primary economic environment in which it operates (its functional currency). Transactions in currencies other than the entities’ functional currency are translated at rates in effect at the time of the transaction. At each period end, monetary assets and liabilities are translated at the prevailing period end rates. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated. Gains and losses are included in net earnings except for gains and losses on translation of long-term debt designated as a hedge of foreign operations, which are deferred and included in accumulated other comprehensive income. For the purpose of preparing the Corporation’s consolidated financial statements, the financial statements of each foreign operation that does not have a Canadian dollar functional currency are translated into Canadian dollars. Assets and liabilities are translated at exchange rates in effect at the balance sheet date. Revenues and expenses are translated using average exchange rates for the month of the respective transaction. Gains or losses resulting from these translation adjustments are recognized initially in other comprehensive income and reclassified from equity to net earnings on disposal or partial disposal of the foreign operation. (o) Per Share Amounts Basic per share amounts are calculated using the weighted average number of shares outstanding during the period. Diluted per share amounts are calculated by using the treasury stock method for equity based compensation arrangements. The treasury stock method assumes that any proceeds obtained on exercise of equity based compensation arrangements would be used to purchase common shares at the average market price during the period. The weighted average number of shares outstanding is then adjusted by the difference between the number of shares issued from the exercise of equity based compensation arrangements and shares repurchased from the related proceeds. Precision Drilling Corporation 2013 Annual Report 57 (p) Financial Instruments (i) Non-Derivative Financial Assets Financial assets are classified as either fair value through profit and loss, loans and receivables, held to maturity or available for sale. Financial liabilities are classified as either fair value through profit and loss or other financial liabilities. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs. Transaction costs attributable to fair value through profit or loss items are expensed as incurred. Subsequent to initial recognition non-derivative financial instruments are measured based on their classification. Accounts receivable are classified as “loans and receivables”. After their initial fair value measurement, they are measured at amortized cost using the effective interest rate method. For the Corporation, the measured amount generally corresponds to historical cost. Accounts payable and accrued liabilities and long-term debt are classified as “other financial liabilities”. After their initial fair value measurement, they are measured at amortized cost using the effective interest rate method. For the Corporation, the measured amount generally corresponds to historical cost. (ii) Derivative Financial Instruments The Corporation may enter into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in interest rates or exchange rates. These instruments are not used for trading or speculative purposes. Precision has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though it considers certain financial contracts to be economic hedges. As a result, financial derivative contracts are classified as fair value through profit or loss and are recorded on the balance sheet at estimated fair value. Transaction costs are recognized in profit or loss when incurred. Derivatives embedded in other instruments or host contracts are separated from the host contract and accounted for separately when their economic characteristics and risks are not closely related to the host contract. Embedded derivatives are recorded on the balance sheet at estimated fair value and changes in the fair value are recognized in earnings. (q) Hedge Accounting The Corporation utilizes foreign currency long-term debt to hedge its exposure to changes in the carrying values of the Corporation’s net investment in certain foreign operations as a result of changes in foreign exchange rates. To be accounted for as a hedge, the foreign currency long-term debt must be designated and documented as a hedge, and must be effective at inception and on an ongoing basis. The documentation defines the relationship between the foreign currency long-term debt and the net investment in the foreign operations, as well as the Corporation’s risk management objective and strategy for undertaking the hedging transaction. The Corporation formally assesses, both at inception and on an ongoing basis whether the changes in fair value of the foreign currency long-term debt is highly effective in offsetting changes in fair value of the net investment in the foreign operations. The portion of gains or losses on the hedging item that is determined to be an effective hedge is recognized in other comprehensive income, net of tax, and is limited to the translation gain or loss on the net investment, while the ineffective portion is recorded in earnings. If the hedging relationship is terminated or ceases to be effective, hedge accounting is not applied to subsequent gains or losses. The amounts recognized in other comprehensive income are reclassified to net earnings when corresponding exchange gains or losses arising from the translation of the foreign operation are recorded in net earnings. 58 Notes to Consolidated Financial Statements (r) Critical Accounting Judgments (i) Depreciation and Amortization Precision’s property, plant and equipment and its 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 Precision’s 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. (ii) 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. The Corporation establishes provisions, based on reasonable estimates, for possible consequences of audits by the tax authorities of the respective countries in which it operates. 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 thru 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. (s) Critical Accounting Assumptions and Estimates Impairment of Long-Lived Assets Long-lived assets, which include property, plant and equipment, intangibles and goodwill, comprise the majority of Precision’s 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 Precision 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 change in circumstance that indicates that the carrying value may not be recoverable. The recoverability of goodwill requires a calculation of the recoverable amount of the CGU or groups of CGUs to which goodwill has been allocated. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Judgment is required in the aggregation of assets into CGUs. The recoverability calculation requires an estimation of the future cash flows from the CGU or group of CGUs and judgment is required in 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. Precision 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. 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. Precision Drilling Corporation 2013 Annual Report 59 (t) Accounting Policies Adopted January 1, 2013 The Corporation adopted IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of Interests in Other Entities, as well as the consequential amendments to IAS 28 Investments in Associates and Joint Ventures (2011) and IFRS 13 Fair Value Measurement, with a date of initial application of January 1, 2013. The adoption of these standards on January 1, 2013 had no impact on the amounts recorded in the Corporation’s financial statements. (i) 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. (ii) 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. (iii) 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, 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. (iv) 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. (u) 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. 60 Notes to Consolidated Financial Statements NOTE 4. PROPERTY, PLANT AND EQUIPMENT Cost Accumulated depreciation Rig equipment Rental equipment Other equipment Vehicles Buildings Assets under construction Land Cost 2013 2012 $ $ $ 5,260,263 (1,698,529) 3,561,734 3,033,159 108,453 78,670 42,993 49,506 219,433 29,520 $ $ $ 4,608,381 (1,365,452) 3,242,929 2,819,491 91,351 78,358 40,759 50,585 133,791 28,594 $ 3,561,734 $ 3,242,929 Rig Equipment Rental Equipment Other Equipment Vehicles Buildings Assets Under Construction Land Total December 31, 2011 $ 3,441,052 $ 112,707 $ 142,563 $ 28,051 $ 48,082 $ 336,605 $ 20,658 $ 4,129,718 Additions Disposals 256,661 17,068 18,330 32,994 21,998 512,139 8,867 868,057 (26,796) (920) (8,311) (2,267) (971) (38,405) (857) (78,527) Asset decommissioning (262,192) – – – – – – (262,192) Reclassifications 619,351 24,530 19,144 4,959 2,295 (670,279) – – (71) – – – – – – (71) Removal of fully depreciated assets Effect of foreign currency exchange differences (41,333) (1,034) (18) (541) 665 (6,269) (74) (48,604) December 31, 2012 3,986,743 152,351 171,637 63,196 72,069 133,791 28,594 4,608,381 Additions Disposals 143,252 6,346 1,651 3,588 (52,659) (1,126) (2,971) (5,324) – – – 380,788 179 535,804 Reclassifications 270,615 10,508 14,141 4,900 825 (300,989) – – (62,080) – Effect of foreign currency exchange differences 163,445 1,866 936 3,251 2,070 5,843 747 178,158 December 31, 2013 $ 4,511,396 $ 169,945 $ 185,394 $ 69,611 $ 74,964 $ 219,433 $ 29,520 $ 5,260,263 Precision Drilling Corporation 2013 Annual Report 61 Accumulated Depreciation Rig Equipment Rental Equipment Other Equipment Vehicles Buildings Assets Under Construction Land Total December 31, 2011 $ 1,008,185 $ 54,118 $ 87,358 $ 17,812 $ 19,949 $ – $ – $ 1,187,422 Depreciation expense 274,129 7,901 14,280 6,917 2,341 Disposals (35,697) (785) (8,213) (2,132) (884) Asset decommissioning (69,723) – Reclassifications 60 (156) – 646 – 16 – (566) Removal of fully depreciated assets Effect of foreign currency exchange differences – – (71) – – (9,702) (78) (721) (176) 644 December 31, 2012 1,167,252 61,000 93,279 22,437 21,484 Depreciation expense 295,807 9,695 15,518 8,299 3,774 Disposals (43,423) (1,007) (2,937) (5,069) 8,314 (8,557) 273 (20) – (10) Reclassifications Effect of foreign currency exchange differences December 31, 2013 $ 1,478,237 $ 61,492 $ 106,724 $ 26,618 $ 25,458 $ 50,287 361 591 971 210 – – – – – – – – – – – – – – – 305,568 (47,711) (69,723) – (71) – (10,033) – 1,365,452 – – – 333,093 (52,436) – – – $ – 52,420 – $ 1,698,529 In 2012, the Corporation incurred a $192.5 million loss on the decommissioning of certain drilling rigs. The assets were decommissioned due to the inefficient nature of the assets and the high cost to maintain. The charge was allocated fully to the Contract Drilling Services segment. During 2012, the Corporation reviewed the remaining economic lives of certain drilling rigs and determined that, due to current market conditions, the lives of these rigs should be reduced to four years and depreciation be charged on a straight-line basis to their estimated salvage value. The effect of this change was to increase depreciation expense by $21.3 million in 2012. 62 Notes to Consolidated Financial Statements NOTE 5. INTANGIBLES Cost Accumulated amortization Customer relationships Patents and brands Loan commitment fees related to revolving credit facility Cost December 31, 2011 Business acquisitions Additions Effect of foreign currency exchange differences Removal of fully amortized assets December 31, 2012 Business acquisitions Additions Effect of foreign currency exchange differences Removal of fully amortized assets 2013 12,221 (8,304) 3,917 616 16 3,285 3,917 $ $ $ $ $ $ $ $ Customer Relationships Patents and Brands Loan Commitment Fees $ 4,600 $ 420 $ 4,905 $ – – (25) 4,575 – – 78 (1,128) – – (8) (359) 53 – – – – – 2,855 – – 7,760 12,388 – 883 – – – 883 78 (1,128) 2012 12,388 (6,287) 6,101 1,890 21 4,190 6,101 Total 9,925 – 2,855 (33) (359) December 31, 2013 $ 3,525 $ 53 $ 8,643 $ 12,221 Accumulated Amortization Customer Relationships Patents and Brands December 31, 2011 Amortization expense Effect of foreign currency exchange differences Removal of fully amortized assets December 31, 2012 Amortization expense Effect of foreign currency exchange differences Removal of fully amortized assets $ 1,317 1,376 (8) – 2,685 1,294 58 (1,128) $ 302 $ 96 (7) (359) 32 5 – – Loan Commitment Fees $ 1,835 1,735 – – 3,570 1,788 – – December 31, 2013 $ 2,909 $ 37 $ 5,358 $ Total 3,454 3,207 (15) (359) 6,287 3,087 58 (1,128) 8,304 Precision Drilling Corporation 2013 Annual Report 63 NOTE 6. GOODWILL Balance, December 31, 2011 Business acquisitions Impairment charge Exchange adjustment Balance, December 31, 2012 Exchange adjustment Balance, December 31, 2013 $ 363,646 25 (52,539) (580) 310,552 1,804 $ 312,356 The Corporation performed an impairment test on the well servicing CGU at December 31, 2013. This CGU has $89 million of goodwill allocated to it. The cash flow projections used in performing the impairment test were based on future expected outcomes taking into account past experience and management expectation of future market conditions. No terminal value growth rate was used due to the finite lives of the underlying assets of the CGU. 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. During 2012 the Corporation determined that the carrying value of the goodwill allocated to the Canadian directional drilling CGU exceeded its recoverable amount and recognized an impairment loss of $52.5 million. The recoverable amount was based on its value in use determined by discounting expected future cash flows to be generated from the continuing use of the assets within the CGU. Key assumptions used in the calculation of value in use included a discount rate of 15%, terminal value growth rate of nil % and average projected annual cash flow growth over the next four years of 40%. No terminal value growth rate was used due to the finite lives of the underlying assets of the CGU. Projected cash flow was based on future expected outcomes taking into account past experience and management expectation of future market conditions. A 10% change in the key assumptions would not change the amount of the impairment loss recognized. NOTE 7. BANK INDEBTEDNESS At December 31, 2013 and 2012, Precision had available $40.0 million and US$15.0 million under secured operating facilities, and a secured US$25.0 million facility for the issuance of letters of credit and performance and bid bonds to support international operations. As at December 31, 2013 and 2012, no amounts had been drawn on any of the facilities. Availability of the $40.0 million and US$25.0 million facility were reduced by outstanding letters of credit in the amount of $17.3 million (2012 – $18.9 million) and US$0.2 million (2012 – US $nil), respectively. The facilities are primarily secured by charges on substantially all present and future property of Precision and its material subsidiaries. Advances under the $40.0 million facility are available at the bank’s prime lending rate, U.S. base rate, U.S. LIBOR plus applicable margin, or Banker’s Acceptance plus applicable margin, or in combination, and under the US$15.0 million and US$25.0 million facilities at the bank’s prime lending rate. 64 Notes to Consolidated Financial Statements NOTE 8. SHARE BASED COMPENSATION PLANS Liability Classified Plans Deferred Share Units Restricted Share Units Performance Share Units Share Appreciation Rights Non- Management Directors’ DSUs Total December 31, 2011 $ 762 $ 12,529 $ 25,250 $ 1,693 $ – $ 40,234 Expensed (recovered) during the period Payments December 31, 2012 Expensed (recovered) during the period Payments and redemptions December 31, 2013 Current Long-term (44) (718) – – – – – – – $ $ $ 5,094 (7,938) 9,685 11,622 (7,769) 6,022 (17,494) 13,778 8,137 (8,953) (1,195) (1) 497 (251) – 816 – 816 1,245 (207) 10,693 (26,151) 24,776 20,753 (16,929) $ 13,538 $ 12,962 $ 246 $ 1,854 $ 28,600 $ 9,027 $ 4,896 $ 246 $ – $ 14,169 4,511 8,066 – 1,854 14,431 $ 13,538 $ 12,962 $ 246 $ 1,854 $ 28,600 (a) Restricted Share Units and Performance Share Units Precision has two cash settled share based incentive plans for officers and other eligible employees. Under the Restricted Share Unit (RSU) incentive plan shares granted to eligible employees vest annually over a three year term. Vested shares are automatically paid out in cash at a value determined by the fair market value of the shares at the vesting date. Under the Performance Share Unit (PSU) incentive plan shares granted to eligible employees vest at the end of a three-year term. Vested shares are automatically paid out in cash in the first quarter following the vested term at a value determined by the fair market value of the shares at the vesting date and based on the number of performance shares held multiplied by a performance factor that ranges from zero to two times. The performance factor is based on Precision’s share price performance compared to a peer group over the three-year period. A summary of the RSUs and PSUs outstanding under these share based incentive plans is presented below: December 31, 2011 Granted Issued as a result of cash dividends Redeemed Forfeitures December 31, 2012 Granted Issued as a result of cash dividends Redeemed Forfeitures December 31, 2013 RSUs Outstanding 1,836,830 1,117,850 11,566 (864,857) (221,139) 1,880,250 1,295,739 51,113 (869,744) (243,863) PSUs Outstanding 2,129,508 802,000 11,972 (851,499) (143,029) 1,948,952 1,258,650 54,623 (696,171) (128,126) 2,113,495 2,437,928 Precision Drilling Corporation 2013 Annual Report 65 (b) Share Appreciation Rights The Corporation has a U.S. dollar denominated Share Appreciation Rights (SAR) plan under which eligible participants were granted SARs that entitle the rights holder to receive cash payments calculated as the excess of the market price over the exercise price per share on the exercise date. The SARs vest over a period of 5 years and expire 10 years from the date of grant. At December 31, 2013, the intrinsic value of these awards was $7,000 (2012 – $nil). Share Appreciation Rights December 31, 2011 Exercised Forfeited December 31, 2012 Forfeited December 31, 2013 Range of Exercise Prices (US$): $ 9.26 – 11.99 12.00 – 14.99 15.00 – 17.38 $ 9.26 – 17.38 Outstanding Range of Exercise Price (US$) Weighted Average Exercise Price (US$) 705,688 $ 9.26 – 17.92 $ 14.83 (721) 9.26 – 9.59 (26,725) 678,242 (90,080) 15.22 – 17.92 9.26 – 17.38 13.26 – 17.38 9.45 15.55 14.81 15.42 Exercisable 705,688 678,242 588,162 $ 9.26 – 17.38 $ 14.71 588,162 Total SARs Outstanding and Exercisable Weighted Average Exercise Price (US$) $ 9.26 13.26 15.82 $ 14.71 Weighted Average Remaining Contractual Life (Years) 1.23 1.10 3.43 2.71 Number 59,903 100,844 427,415 588,162 (c) Non-Management Directors Effective January 1, 2012, Precision instituted a new deferred share unit plan for non-management directors whereby fully vested deferred share units are granted quarterly based on an election by the non-management director to receive all or a portion of their compensation in deferred share units. These deferred share units are redeemable in cash or for an equal number of common shares upon the director’s retirement. The redemption of deferred share units in cash or common shares is solely at Precision’s discretion. Non-management directors can receive a lump sum payment or two separate payments any time up until December 15 of the year following retirement. If the non-management director does not specify a redemption date, the deferred share units will be redeemed on a single date six months after retirement. The cash settlement amount is based on the weighted average trading price for Precision’s shares on the Toronto Stock Exchange for the five days immediately prior to payout. A summary of the DSUs outstanding under this share based incentive plan is presented below: Deferred Share Units January 1, 2011 Granted Issued as a result of cash dividends December 31, 2012 Granted Issued as a result of cash dividends Redeemed December 31, 2013 66 Notes to Consolidated Financial Statements Outstanding – 101,535 429 101,964 105,338 2,836 (21,563) 188,575 Equity Settled Plans (d) Non-Management Directors Prior to January 1, 2012, Precision had a deferred share unit plan for non-management directors. Under the plan fully vested deferred share units were granted quarterly based on an election by the non-management director to receive all or a portion of their compensation in deferred share units. These deferred share units are redeemable into an equal number of common shares any time after the director’s retirement. A summary of this share based incentive plan is presented below: Deferred Share Units December 31, 2011 Issued as a result of cash dividends Redeemed December 31, 2012 Issued as a result of cash dividends Redeemed December 31, 2013 Outstanding 417,495 1,630 (83,179) 335,946 5,459 (120,293) 221,112 (e) Option Plan The Corporation has a share option plan under which a combined total of 16,569,134 options to purchase common shares are reserved to be granted to employees. Of the amount reserved, 9,357,588 options have been granted. Under this plan, the exercise price of each option equals the fair market of the option at the date of grant determined by the weighted average trading price for the five days preceding the grant. The options are denominated in either Canadian or U.S. dollars, and vest over a period of three years from the date of grant as employees render continuous service to the Corporation and have a term of seven years. A summary of the status of the equity incentive plan is presented below: Canadian share options December 31, 2011 Granted Exercised Forfeitures December 31, 2012 Granted Exercised Forfeitures Options Outstanding Range of Exercise Prices 3,267,571 $ 5.22 – 14.50 $ 1,117,050 (237,545) (133,279) 4,013,797 1,237,500 (172,158) (178,253) 7.15 – 10.67 5.85 – 10.44 5.85 – 14.50 5.22 – 14.50 7.82 – 9.02 5.85 – 10.67 5.85 – 14.50 December 31, 2013 4,900,886 $ 5.22 – 14.50 $ U.S. share options December 31, 2011 Granted Exercised Forfeitures December 31, 2012 Granted Exercised Forfeitures Options Outstanding Range of Exercise Prices (US$) 1,886,552 $ 4.95 – 15.21 $ 867,000 (72,409) (281,163) 2,399,980 1,025,100 (189,887) (61,385) 7.14 – 10.74 4.95 – 10.55 4.95 – 15.21 4.95 – 15.21 8.99 – 9.28 4.95 – 10.55 7.14 – 15.21 December 31, 2013 3,173,808 $ 4.95 – 15.21 $ Weighted Average Exercise Price 8.45 10.60 6.01 10.27 9.13 8.99 7.43 9.77 9.14 Weighted Average Exercise Price (US$) 8.61 10.58 6.94 9.84 9.23 9.00 5.89 10.82 9.32 Options Exercisable 1,008,305 1,846,603 2,676,865 Options Exercisable 396,188 935,035 1,438,335 Precision Drilling Corporation 2013 Annual Report 67 The weighted average share price at the date of exercise for share options exercised in 2013 was $10.11 (2012 – $9.42) for the Canadian share options and US$9.90 (2012 – US$10.10) for the U.S. share options. The range of exercise prices for options outstanding at December 31, 2013 is as follows: Canadian share options Total Options Outstanding Exercisable Options Range of Exercise Prices: $ 5.22 – 6.99 7.00 – 8.99 9.00 – 14.50 $ 5.22 – 14.50 Number 706,438 981,297 3,213,151 Weighted Average Exercise Price $ 5.85 8.53 10.04 4,900,886 $ 9.14 Weighted Average Remaining Contractual Life (Years) 2.35 3.25 5.16 4.37 Number 706,438 942,662 1,027,765 Weighted Average Exercise Price $ 5.85 8.56 10.62 2,676,865 $ 8.64 U.S. share options Total Options Outstanding Exercisable Options Weighted Average Exercise Price (US$) Weighted Average Remaining Contractual Life (Years) Range of Exercise Prices (US$): $ 4.95 – 5.99 6.00 – 8.99 9.00 – 15.21 $ 4.95 – 15.21 Number 188,872 1,606,533 1,378,403 $ 4.95 8.55 10.82 3,173,808 $ 9.32 2.35 5.08 4.67 4.74 Weighted Average Exercise Price (US$) $ 4.95 7.82 10.89 Number 188,872 581,195 668,268 1,438,335 $ 8.87 The per option weighted average fair value of the share options granted during 2013 was $3.26 (2012 – $4.79) estimated on the grant date using the Black-Scholes option pricing model with the following assumption: average risk-free interest rate 1% (2012 – 1%), average expected life of four years (2012 – four years), expected forfeiture rate of 5% (2012 – 5%) and expected volatility of 53% (2012 – 59%). Included in net earnings for the year ended December 31, 2013 is an expense of $7.0 million (2012 – $7.9 million). 68 Notes to Consolidated Financial Statements NOTE 9. PROVISIONS AND OTHER Balance December 31, 2011 Expensed during the year Payment of deductibles and uninsured claims Effects of foreign currency exchange differences Balance December 31, 2012 Expensed during the year Payment of deductibles and uninsured claims Effects of foreign currency exchange differences Balance December 31, 2013 Current Long-term Workers’ Compensation $ $ $ $ 23,984 11,604 (8,436) (551) 26,601 4,350 (8,546) 1,781 24,186 2012 8,783 17,818 26,601 2013 6,350 17,836 24,186 $ $ Precision maintains a provision for the deductible and uninsured portions of workers’ compensation and general liability claims. The amount accrued for the provision for losses incurred varies depending on the number and nature of the claims outstanding at the balance sheet dates. In addition, the accrual includes management’s estimate of the future cost to settle each claim such as future changes in the severity of the claim and increases in medical costs. Precision uses third parties to assist in developing the estimate of the ultimate costs to settle each claim, which is based on historical experience associated with the type of each claim and specific information related to each claim. The specific circumstances of each claim may change over time prior to settlement and, as a result, the estimates made as of the balance sheet dates may change. NOTE 10. LONG-TERM DEBT Secured revolving credit facility Unsecured senior notes: 6.625% senior notes due 2020 (US$650.0 million) 6.5% senior notes due 2021 (US$400.0 million) 6.5% senior notes due 2019 Less net unamortized debt issue costs 2013 $ 29,781 $ 691,340 425,440 200,000 2012 – 646,685 397,960 200,000 1,346,561 1,244,645 (23,293) (25,849) $ 1,323,268 $ 1,218,796 Precision Drilling Corporation 2013 Annual Report 69 (a) Secured Revolving Credit Facility The secured revolving credit facility provides Precision with senior secured financing for general corporate purposes, including for acquisitions, of up to US$850 million with a provision for an increase in the facility of up to an additional US$250 million. The secured revolving credit facility is secured by charges on substantially all of Precision’s present and future assets and the present and future assets of its material U.S. and Canadian subsidiaries and, if necessary, in order to adhere to covenants under the revolving credit facility, on certain assets of certain subsidiaries organized in a jurisdiction outside of Canada or the U.S. The secured revolving credit facility requires that Precision comply with certain financial covenants including leverage ratios of consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (EBITDA) of less than 3:1 and consolidated total debt to EBITDA of less than 4:1 for the most recent four consecutive fiscal quarters; and a interest coverage ratio of greater than 2.75:1 for the most recent four consecutive fiscal quarters. As well the revolving credit facility contains certain covenants that place restrictions on Precision’s ability to dispose of assets; make or pay dividends, share redemptions or other distributions; change its primary business; incur liens on assets; enter into mergers, consolidations or amalgamations; and enter into speculative swap agreements. At December 31, 2013, Precision was in compliance with the covenants of the revolving credit facility. The revolving credit facility has a term of five years, with an annual option on Precision’s part to request that the lenders extend, at their discretion, the facility to a new maturity date not to exceed five years from the date of the extension request. The current maturity date of the revolving credit facility is November 17, 2018. Under the revolving credit facility amounts can be drawn in U.S. dollars and/or Canadian dollars and as at December 31, 2013, US$28.0 was outstanding (2012 – $nil). Up to US$200 million of the revolving credit facility is available for letters of credit denominated in U.S and/or Canadian dollars and as at December 31, 2013 outstanding letters of credit amounted to US$28.6 million (2012 – US$26.8 million). The interest rate on loans that are denominated in U.S. dollars is, at the option of Precision, either a margin over a U.S. base rate or a margin over LIBOR. The interest rate on loans denominated in Canadian dollars is, at the option of Precision, either a margin over the Canadian prime rate or a margin over the bankers’ acceptance rate; such margins will be based on the then applicable ratio of consolidated total debt to EBITDA. (b) Unsecured Senior Notes Precision has outstanding the following unsecured senior notes:  US$650.0 million of 6.625% Senior Notes due 2020. These notes bear interest at a fixed rate of 6.625% per annum, and mature on November 15, 2020. Interest is payable semi-annually on May 15 and November 15 of each year  $200.0 million of 6.5% Senior Notes due 2019. These notes bear interest at a fixed rate of 6.5% per annum, and mature on March 15, 2019. Interest is payable semi-annually on March 15 and September 15 of each year.  US$400.0 million of 6.5% Senior Notes due 2021. These notes bear interest at a fixed rate of 6.5% per annum, and mature on December 15, 2021. Interest is payable semi-annually on June 15 and December 15 of each year. The 6.625% Senior Notes due 2020 and the 6.5% Senior Notes due 2019 are unsecured, ranking equally with existing and future senior unsecured indebtedness, and have been guaranteed by current and future U.S. and Canadian subsidiaries that guaranteed the revolving credit facility. These notes contain certain covenants that limit Precision’s ability and the ability of certain subsidiaries to incur additional indebtedness and issue preferred stock; create liens; make restricted payments; create or permit to exist restrictions on the ability of Precision or certain subsidiaries to make certain payments and distributions; engage in amalgamations, mergers or consolidations; make certain dispositions and transfers of assets; and engage in transactions with affiliates. If the notes receive an investment grade rating by Standard & Poor’s and Moody’s Investors Service and Precision and its subsidiaries are not in default under the indenture governing the notes, then Precision will not be required to comply with particular covenants contained in the indenture. 70 Notes to Consolidated Financial Statements The 6.5% Senior Notes due 2021 are unsecured, ranking equally with existing and future senior unsecured indebtedness, and have been guaranteed by current and future U.S. and Canadian subsidiaries that guaranteed the revolving credit facility. These notes contain certain covenants that limit Precision’s ability and the ability of certain subsidiaries to incur additional indebtedness and issue preferred stock; create liens; make restricted payments; create or permit to exist restrictions on the ability of Precision or certain subsidiaries to make certain payments and distributions; engage in amalgamations, mergers or consolidations; make certain dispositions and transfers of assets; and engage in transactions with affiliates. If the notes receive an investment grade rating by Standard & Poor’s or Moody’s Investors Service and Precision and its subsidiaries are not in default under the indenture governing the notes, then Precision will not be required to comply with particular covenants contained in the indenture. Prior to November 15, 2015, Precision may redeem the 6.625% Senior Notes due 2020 in whole or in part at 100.0% of their principal amount, plus accrued interest and the greater of 1.0% of the principal amount of the note to be redeemed and the excess, if any, of the present value of the November 15, 2015 redemption price plus required interest payments through November 15, 2015 (calculated using the United States Treasury rate plus 50 basis points) over the principal amount of the note. As well, Precision may redeem these notes in whole or in part at any time on or after November 15, 2015 and before November 15, 2018, at redemption prices ranging between 103.313% and 101.104% of their principal amount plus accrued interest. Any time on or after November 15, 2018 these notes can be redeemed for their principal amount plus accrued interest. Upon specified change of control events, each holder of a note will have the right to sell to Precision all or a portion of its notes at a purchase price in cash equal to 101% of the principal amount, plus accrued interest to the date of purchase. Prior to March 15, 2014, Precision may redeem up to 35% of the 6.5% Senior Notes due 2019 with the net proceeds of certain equity offerings at a redemption price equal to 106.5% of the principal amount plus accrued interest. Prior to March 15, 2015, Precision may redeem these notes in whole or in part at 100.0% of their principal amount, plus accrued interest and the greater of 1.0% of the principal amount of the note to be redeemed and the excess, if any, of the present value of the March 15, 2015 redemption price plus required interest payments through March 15, 2015 (calculated using the Government of Canada rate plus 100 basis points) over the principal amount of the note. As well, Precision may redeem these notes in whole or in part at any time on or after March 15, 2015 and before March 15, 2017, at redemption prices ranging between 103.250% and 101.6254% of their principal amount plus accrued interest. Any time on or after March 15, 2017 these notes can be redeemed for their principal amount plus accrued interest. Upon specified change of control events, each holder of a note will have the right to sell to Precision all or a portion of its notes at a purchase price in cash equal to 101% of the principal amount, plus accrued interest to the date of purchase. Prior to December 15, 2014, Precision may redeem up to 35% of the 6.5% Senior Notes due 2021 with the net proceeds of certain equity offerings at a redemption price equal to 106.5% of the principal amount plus accrued interest. Prior to December 15, 2016, Precision may redeem these notes in whole or in part at 100.0% of their principal amount, plus accrued interest and the greater of 1.0% of the principal amount of the note to be redeemed and the excess, if any, of the present value of the December 15, 2016 redemption price plus required interest payments through December 15, 2016 (calculated using the United States Treasury rate plus 50 basis points) over the principal amount of the note. As well, Precision may redeem these notes in whole or in part at any time on or after December 15, 2016 and before December 15, 2019, at redemption prices ranging between 103.250% and 101.083% of their principal amount plus accrued interest. Any time on or after December 15, 2019 these notes can be redeemed for their principal amount plus accrued interest. Upon specified change of control events, each holder of a note will have the right to sell to Precision all or a portion of its notes at a purchase price in cash equal to 101% of the principal amount, plus accrued interest to the date of purchase. Long-term debt obligations at December 31, 2013 will mature as follows: 2018 Thereafter $ 29,781 1,316,780 $ 1,346,561 Precision Drilling Corporation 2013 Annual Report 71 (c) Guarantor Disclosures The following presents supplemental condensed consolidating financial information for the parent company, guarantor subsidiaries and the non-guarantor subsidiaries, respectively. Condensed Consolidating Statement of Financial Position as at December 31, 2013 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Consolidating Adjustments Total Assets Cash Other current assets Intercompany receivables Investments in subsidiaries Income tax recoverable Property, plant and equipment Intangibles Goodwill Total assets Liabilities and Shareholders’ Equity Current liabilities Intercompany payables and debt Long-term debt Other long-term liabilities Total liabilities Shareholders’ equity $ 27,160 $ 23,039 $ 30,407 $ 3,592 424,178 5,904,795 – 56,501 3,286 – 6,419,512 40,624 2,442,373 1,323,268 263,410 4,069,675 2,349,837 $ $ 456,574 2,342,467 69 – 3,261,610 631 312,356 6,396,746 240,052 202,986 – 262,308 705,346 5,691,400 $ $ – 3 $ 80,606 562,075 101,906 74,795 (2,841,440) – (5,904,864) 58,435 243,858 – – – (235) – – $ $ $ $ 509,401 $ (8,746,536) 56,222 $ – 196,081 (2,841,440) – (6,104) 246,199 263,202 – – (2,841,440) (5,905,096) – – 58,435 3,561,734 3,917 312,356 4,579,123 336,898 – 1,323,268 519,614 2,179,780 2,399,343 Total liabilities and shareholders’ equity $ 6,419,512 $ 6,396,746 $ 509,401 $ (8,746,536) $ 4,579,123 Condensed Consolidating Statement of Financial Position as at December 31, 2012 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Consolidating Adjustments Total Assets Cash Other current assets Intercompany receivables Investments in subsidiaries Income tax recoverable Property, plant and equipment Intangibles Goodwill Total assets Liabilities and Shareholders’ Equity Current liabilities Intercompany payables and debt Long-term debt Other long-term liabilities Total liabilities Shareholders’ equity $ 114,709 $ 15,709 $ 22,350 $ 9,238 394,112 5,412,168 9,441 57,939 4,190 – 6,001,797 103,383 2,200,650 1,218,796 245,377 3,768,206 2,233,591 $ $ 465,695 2,082,616 3,099 – 3,043,239 1,911 310,552 5,922,821 264,788 185,855 – 273,547 724,190 5,198,631 $ $ – 3 $ 152,768 523,334 48,398 65,279 (2,542,007) – (5,415,267) 55,138 142,104 – – – (353) – – $ $ $ $ 333,269 $ (7,957,624) 29,910 $ – 155,502 (2,542,007) – (6,838) 178,574 154,695 – – (2,542,007) (5,415,617) – – 64,579 3,242,929 6,101 310,552 4,300,263 398,081 – 1,218,796 512,086 2,128,963 2,171,300 Total liabilities and shareholders’ equity $ 6,001,797 $ 5,922,821 $ 333,269 $ (7,957,624) $ 4,300,263 72 Notes to Consolidated Financial Statements Condensed Consolidating Statement of Earnings (Loss) for the Year ended December 31, 2013 Revenue Operating expense $ General and administrative expense Earnings (loss) before income taxes, finance charges, foreign exchange, and depreciation and amortization Depreciation and amortization Operating earnings (loss) Foreign exchange Finance charges Equity in earnings of subsidiaries Earnings (loss) before tax Income taxes Net earnings (loss) Parent 143 273 29,174 (29,304) 7,393 (36,697) (3,356) 92,112 (360,468) 235,015 43,615 Guarantor Subsidiaries Non-Guarantor Subsidiaries Consolidating Adjustments Total $ 1,912,750 $ 137,681 $ (20,597) $ 2,029,977 1,148,786 101,407 120,175 11,926 662,557 309,939 352,618 (5,198) 1,141 – 356,675 (15,431) 5,580 15,576 (9,996) (558) (5) – (9,433) 2,204 (20,597) 1,248,637 – – 251 (251) – – 360,468 (360,719) – 142,507 638,833 333,159 305,674 (9,112) 93,248 – 221,538 30,388 $ 191,400 $ 372,106 $ (11,637) $ (360,719) $ 191,150 Condensed Consolidating Statement of Earnings (Loss) for the Year ended December 31, 2012 Guarantor Subsidiaries Non-Guarantor Subsidiaries Consolidating Adjustments Total $ 1,986,590 $ 64,779 $ (10,779) $ 2,040,741 $ Parent 151 82 27,246 1,173,157 94,014 80,841 5,388 Revenue Operating expense General and administrative expense Earnings (loss) before income taxes, finance charges, foreign exchange, impairment of goodwill, loss on asset decommissioning and depreciation and amortization Depreciation and amortization Loss on asset decommissioning Operating earnings (loss) Impairment of goodwill Foreign exchange Finance charges Equity in earnings of subsidiaries Earnings (loss) before tax Income taxes Net earnings (loss) (27,177) 3,405 – (30,582) – 4,252 86,780 (196,489) 74,875 30,011 719,419 303,693 192,469 223,257 52,539 (189) 48 – 170,859 (49,342) (21,450) 7,922 – (29,372) – (310) 1 – (29,063) (5,352) (10,779) 1,243,301 – – (7,495) – 7,495 – – – 196,489 (188,994) – 126,648 670,792 307,525 192,469 170,798 52,539 3,753 86,829 – 27,677 (24,683) $ 44,864 $ 220,201 $ (23,711) $ (188,994) $ 52,360 Precision Drilling Corporation 2013 Annual Report 73 Condensed Consolidating Statement of Comprehensive Income (Loss) for the Year ended December 31, 2013 Net earnings Other comprehensive income (loss) Comprehensive income (loss) Parent 191,400 (72,135) 119,265 $ $ Guarantor Subsidiaries Non-Guarantor Subsidiaries Consolidating Adjustments $ $ 372,106 98,105 470,211 $ $ (11,637) 10,720 (917) $ $ (360,719) 370 (360,349) $ $ Condensed Consolidating Statement of Comprehensive Income (Loss) for the Year ended December 31, 2012 Net earnings Other comprehensive income (loss) Comprehensive income (loss) Parent 44,864 23,205 68,069 $ $ Guarantor Subsidiaries Non-Guarantor Subsidiaries Consolidating Adjustments $ $ 220,201 (30,899) 189,302 $ $ (23,711) (1,934) (25,645) $ $ (188,994) (45) (189,039) $ $ Total 191,150 37,060 228,210 Total 52,360 (9,673) 42,687 Condensed Consolidating Statement of Cash Flow for the Year ended December 31, 2013 Cash provided by (used in): Operations Investments Financing Effects of exchange rate changes on cash and cash equivalents Increase (decrease) in cash and cash equivalents Cash and cash equivalents, beginning of year Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Consolidating Adjustments Total $ (207,558) $ 693,757 $ (58,113) $ – $ 428,086 96,685 21,517 1,807 (87,549) (458,810) (229,688) 2,071 7,330 (68,951) 134,229 892 8,057 114,709 15,709 22,350 (95,459) 95,459 – – – – (526,535) 21,517 4,770 (72,162) 152,768 $ 80,606 Cash and cash equivalents, end of year $ 27,160 $ 23,039 $ 30,407 $ Condensed Consolidating Statement of Cash Flow for the Year ended December 31, 2012 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Consolidating Adjustments Total $ (135,797) $ 775,145 $ (65,654) $ 61,592 $ 635,286 (171,158) (14,899) (806,436) 41,996 (43,971) 111,040 91,444 (153,036) Cash provided by (used in): Operations Investments Financing Effects of exchange rate changes on cash and cash equivalents Increase (decrease) in cash and cash equivalents Cash and cash equivalents, beginning of year (4,197) (811) (326,051) 440,760 9,894 5,815 34 1,449 20,901 Cash and cash equivalents, end of year $ 114,709 $ 15,709 $ 22,350 $ 74 Notes to Consolidated Financial Statements (930,121) (14,899) (4,974) (314,708) 467,476 $ 152,768 – – – – NOTE 11. INCOME TAXES The provision for income taxes differs from that which would be expected by applying statutory Canadian income tax rates. A reconciliation of the difference at December 31 is as follows: Earnings before income taxes Federal and provincial statutory rates Tax at statutory rates Adjusted for the effect of: Non-deductible expenses Non-taxable capital gains Income taxed at lower rates Impact of foreign tax rates Withholding taxes Taxes related to prior years Other Income tax expense (recovery) $ $ $ $ 2013 221,538 25% 55,385 4,097 (626) (31,118) (5,957) 3,343 4,738 526 2012 27,677 25% 6,919 15,975 (546) (30,191) (26,559) 4,009 1,053 4,657 $ 30,388 $ (24,683) The net deferred tax liability is comprised of the tax effect of the following temporary differences: Deferred income tax liability: Property, plant and equipment and intangibles $ 749,760 $ 686,833 2013 2012 Partnership deferrals Debt issue costs Other Deferred income tax assets: Losses (expire from time to time up to 2033) Long-term incentive plan Other Net deferred income tax liability 34,938 2,966 6,569 60,906 1,561 4,260 794,233 753,560 285,438 14,800 6,648 244,888 13,917 9,163 $ 487,347 $ 485,592 Included in the net deferred tax liability is $257.8 million (2012 – $242.6 million) of tax effected temporary differences related to the Corporation’s United States operations. As at December 31, 2013, the Corporation had unrecognized net deferred tax assets related to its foreign operations of $7.2 million (2012 – $5.9 million). Precision Drilling Corporation 2013 Annual Report 75 The movement in temporary differences is as follows: Property, Plant and Equipment and Intangibles Other Deferred Income Tax Liabilities Partnership Deferrals Losses Debt Issue Costs Long-Term Incentive Plan Other Deferred Income Tax Assets Net Deferred Income Tax Liability December 31, 2011 $ 735,815 $ 91,319 $ 5,704 $ (221,982) $ (2,568) $ (13,026) $ (7,472) $ 587,790 Recognized in net earnings (37,034) (30,413) (1,413) (27,784) 4,129 (1,058) (1,686) (95,259) Effect of foreign currency exchange differences (11,948) – (31) 4,878 December 31, 2012 686,833 60,906 4,260 (244,888) Recognized in net earnings 28,176 (25,968) 2,312 (22,968) – 1,561 1,405 167 (5) (6,939) (13,917) (9,163) 485,592 (173) 2,587 (14,629) Effect of foreign currency exchange differences 34,751 – (3) (17,582) – (710) (72) 16,384 December 31, 2013 $ 749,760 $ 34,938 $ 6,569 $ (285,438) $ 2,966 $ (14,800) $ (6,648) $ 487,347 On December 31, 2013, Precision had $30.9 million (2012 – $34.4 million) of unrecognized tax benefits that, if recognized, would have a favourable impact on Precision’s effective income tax rate in future periods. Precision classifies interest accrued on unrecognized tax benefits and income tax penalties as income tax expense. Included in the unrecognized tax benefit, as at December 31, 2013 was interest and penalties of $10.1 million (2012 – $9.2 million). Reconciliation of Unrecognized Tax Benefits Year ended December 31, Unrecognized tax benefits, beginning of year Additions: Prior year’s tax positions Reductions: Prior year’s tax positions Unrecognized tax benefits, end of year 2013 2012 $ 34,357 $ 34,300 2,031 2,033 (5,458) (1,976) $ 30,930 $ 34,357 It is anticipated that approximately $0.5 million (2012 – $0.6 million) of an unrecognized tax position that relates to prior year activities will be realized during the next 12 months. Subject to the results of audit examinations by taxing authorities and/or legislative changes by taxing jurisdictions, Precision does not anticipate further adjustments of unrecognized tax positions during the next 12 months that would have a material impact on the financial statements of Precision. 76 Notes to Consolidated Financial Statements NOTE 12. SHAREHOLDERS’ CAPITAL (a) Authorized – unlimited number of voting common shares – unlimited number of preferred shares, issuable in series, limited to an amount equal to one half of the issued and outstanding common shares (b) Issued Common shares December 31, 2011 Options exercised – cash consideration – reclassification from contributed surplus Issued on redemption of non-management directors’ DSUs Issued on waiver of right to dissent by dissenting unitholder December 31, 2012 Options exercised – cash consideration – reclassification from contributed surplus Issued on redemption of non-management directors’ DSUs Issued on exercise of warrants December 31, 2013 Number Amount 276,081,797 $ 2,248,217 309,954 – 83,179 840 1,926 1,124 706 9 276,475,770 $ 2,251,982 362,045 – 141,856 15,000,000 2,432 1,275 1,238 48,300 291,979,671 $ 2,305,227 (c) Dividends During 2013, the Corporation approved and paid dividends of $0.21 per common share (2012 – $0.05) for total payments of $58 million (2012 – $14 million). On February 12, 2014, the Board of Directors declared a dividend of $0.06 per common share payable on March 14, 2014 to shareholders of record on February 27, 2014. NOTE 13. ACCUMULATED OTHER COMPREHENSIVE LOSS December 31, 2011 Other comprehensive loss December 31, 2012 Other comprehensive income December 31, 2013 Unrealized Foreign Currency Translation Gains (Losses) Foreign Exchange Gain (Loss) on Net Investment Hedge Accumulated Other Comprehensive Loss $ (27,987) $ (22,875) $ (50,862) (32,878) (60,865) 109,195 23,205 330 (72,135) (9,673) (60,535) 37,060 $ 48,330 $ (71,805) $ (23,475) Precision Drilling Corporation 2013 Annual Report 77 NOTE 14. FINANCE CHARGES Interest: Long-term debt Other Income Amortization of debt issue costs Debt amendment fees Other Finance charges 2013 2012 $ 88,516 $ 85,113 1,356 (967) 4,343 – – 138 (1,933) 4,120 149 (758) $ 93,248 $ 86,829 NOTE 15. EMPLOYEE BENEFIT PLANS The Corporation has a defined contribution pension plan covering a significant number of its employees. Under this plan, the Corporation matches individual contributions up to 5% of the employee’s eligible compensation. Total expense under the defined contribution plan in 2013 was $13.0 million (2012 – $11.1 million). NOTE 16. RELATED PARTY TRANSACTIONS Compensation of Key Management Personnel The remuneration of key management personnel is as follows: Salaries and other benefits Equity settled share based compensation Cash settled share based compensation $ 2013 6,752 3,433 8,051 2012 6,988 3,257 4,872 18,236 $ 15,117 $ $ Key management personnel are comprised of the directors and executive officers of the Corporation. Certain executive officers have entered into employment agreements with Precision that provide termination benefits of up to 24 months base salary plus up to two times targeted incentive compensation upon dismissal without cause. 78 Notes to Consolidated Financial Statements NOTE 17. COMMITMENTS (a) Operating Lease Commitments The Corporation has commitments under various operating lease agreements, primarily for vehicles and office space. Terms of the office leases run for a period of one to 10 years while the vehicle leases are typically for terms of between three and four years. Expected non-cancellable operating lease payments are as follows: Less than one year Between one and five years Later than five years 2013 2012 16,833 $ 15,561 41,258 15,714 41,898 23,161 73,805 $ 80,620 $ $ Three of the leased properties was sublet by the Corporation. The following amounts were recognized as expenses in respect of operating leases in the consolidated statement of earnings: Operating leases Sub-lease recoveries 2013 19,578 (1,024) 18,554 $ $ 2012 19,075 (583) 18,492 $ $ (b) Capital Commitments At December 31, 2013 the Corporation had commitments to purchase property, plant and equipment totaling $178.8 million (2012 – $157.5 million). Payments of $178.8 million for these commitments are expected to be made in 2014. NOTE 18. PER SHARE AMOUNTS The following tables reconcile the net earnings and weighted average shares outstanding used in computing basic and diluted earnings per share: Net earnings – basic and diluted (Stated in thousands) Weighted average shares outstanding – basic Effect of share warrants Effect of stock options and other equity compensation plans Weighted average shares outstanding – diluted 2013 2012 $ 191,150 $ 52,360 2013 277,583 9,327 971 2012 276,276 9,418 933 287,881 286,627 Precision Drilling Corporation 2013 Annual Report 79 NOTE 19. BUSINESS ACQUISITIONS In 2012 a contingent liability from a previous acquisition was settled, resulting in a $758 thousand recovery in the statement of earnings and a $25 thousand increase to goodwill. NOTE 20. SEGMENTED INFORMATION The Corporation operates primarily in Canada and the United States, in two industry segments; Contract Drilling Services and Completion and Production Services. Contract Drilling Services includes drilling rigs, directional drilling, procurement and distribution of oilfield supplies, and manufacture, sale and repair of drilling equipment. Completion and Production Services includes service rigs, snubbing units, coil tubing units, oilfield equipment rental, camp and catering services, and wastewater treatment units. 2013 Revenue Operating earnings Depreciation and amortization Total assets Goodwill Capital expenditures 2012 Revenue Operating earnings Depreciation and amortization Loss on asset decommissioning Total assets Goodwill Capital expenditures* * Excludes business acquisitions Contract Drilling Services Completion and Production Services Corporate and Other Inter- Segment Eliminations Total $ 1,719,910 $ 323,353 $ – $ (13,286) $ 2,029,977 361,447 292,217 3,837,919 200,217 446,566 Contract Drilling Services 28,402 32,630 590,992 112,139 83,470 Completion and Production Services (84,175) 8,312 150,212 – 5,768 – – – – – 305,674 333,159 4,579,123 312,356 535,804 Corporate and Other Inter- Segment Eliminations Total $ 1,725,240 $ 326,079 $ – $ (10,578) $ 2,040,741 184,819 271,993 192,469 3,495,604 198,413 750,763 62,796 30,758 – 551,893 112,139 109,202 (76,817) 4,774 – 252,766 – 8,092 – – – – – – 170,798 307,525 192,469 4,300,263 310,552 868,057 The Corporation’s operations are carried on in the following geographic locations: 2013 Revenue Total assets 2012 Revenue Total assets Canada United States International Inter- Segment Eliminations Total $ 1,002,199 $ 901,246 $ 137,681 $ (11,149) $ 2,029,977 2,082,958 2,006,519 489,646 – 4,579,123 Canada United States International Inter- Segment Eliminations Total $ 1,053,966 $ 936,113 $ 64,017 $ (13,355) $ 2,040,741 2,119,891 1,913,810 266,562 – 4,300,263 During the year ended December 31, 2013, no one individual customer accounted for more than 10% of the Corporation’s total revenue. For the year ended December 31, 2012 revenues from one customer of the Corporation’s Contract Drilling Services and Completion and Production Services segments accounted for $222.7 million of the Corporation’s total revenue. 80 Notes to Consolidated Financial Statements NOTE 21. FINANCIAL INSTRUMENTS Financial Risk Management The Board of Directors is responsible for identifying the principal risks of Precision’s business and for ensuring the implementation of systems to manage these risks. With the assistance of senior management, who report to the Board of Directors on the risks of Precision’s business, the Board of Directors considers such risks and discusses the management of such risks on a regular basis. Precision has exposure to the following risks from its use of financial instruments: (a) Credit Risk Accounts receivable includes balances from a large number of customers primarily operating in the oil and gas industry. The Corporation manages credit risk by assessing the creditworthiness of its customers before providing services and on an ongoing basis as well as monitoring the amount and age of balances outstanding. In some instances the Corporation will take additional measures to reduce credit risk including obtaining letters of credit and prepayments from customers. When indicators of credit problems appear the Corporation takes appropriate steps to reduce its exposure including negotiating with the customer, filing liens and entering into litigation. The Corporation views the credit risks on these amounts as normal for the industry. Precision’s most significant customer accounted for $19.6 million of the trade receivables amount at December 31, 2013 (2012 – $23.0 million). The movement in the allowance for doubtful accounts during the year was as follows: Balance at January 1 Impairment loss recognized Amounts written off as uncollectible Impairment loss reversed Effect of movement in exchange rates Balance at December 31 The ageing of trade receivables at December 31 was: Not past due Past due 0-30 days Past due 31-120 days Past due more than 120 days 2013 2012 $ 12,187 $ 12,179 325 (1,172) (138) 501 348 (174) – (166) $ 11,703 $ 12,187 2013 2012 Gross Provision for Impairment Gross Provision for Impairment $ 177,141 $ 98,529 28,897 21,584 – – – 11,703 $ 197,194 $ 100,217 27,861 15,016 $ 326,151 $ 11,703 $ 340,288 $ – – – 12,187 12,187 (b) Interest Rate Risk As at December 31, 2013 and 2012, all of Precision’s long-term debt, with the exception of the secured revolving credit facility, bears fixed interest rates. As a result Precision is not exposed to significant fluctuations in interest expense as a result of changes in interest rates. Based on the debt outstanding at the end of the year, a 100 basis point change in interest rates would change the annual interest expense by $0.3 million (2012 – $nil). (c) Foreign Currency Risk The Corporation is exposed to foreign currency fluctuations in relation to the working capital and long-term debt of its United States operations and certain long-term debt facilities of its Canadian operations. The Corporation has no significant exposures to foreign currencies other than the U.S. dollar. The Corporation monitors its foreign currency exposure and attempts to minimize the impact by aligning appropriate levels of U.S. denominated debt with cash flows from U.S. based operations. Precision Drilling Corporation 2013 Annual Report 81 The following financial instruments were denominated in U.S. dollars: Cash Accounts receivable Accounts payable and accrued liabilities Long-term liabilities, excluding long-term incentive plans Net foreign currency exposure Impact of $0.01 change in the U.S. dollar to Canadian dollar exchange rate on net earnings Impact of $0.01 change in the U.S. dollar to Canadian dollar exchange rate on comprehensive income 2013 2012 Canadian Operations (1) U.S. Operations Canadian Operations (1) U.S. Operations $ $ $ $ 995 26 (13,385) – (12,364) 124 – $ 53,327 $ 39,693 $ 61,515 290,995 (180,626) (16,770) 146,926 – 1,469 $ $ $ $ $ $ 56 (13,028) – 26,721 267 – $ $ $ 237,370 (184,593) (17,909) 96,383 – 964 (1) Excludes US$1,050 million of long-term debt that has been designated as a hedge of the Corporation’s net investment in certain self-sustaining foreign operations. (d) Liquidity Risk Liquidity risk is the exposure of the Corporation to the risk of not being able to meet its financial obligations as they become due. The Corporation manages liquidity risk by monitoring and reviewing actual and forecasted cash flows to ensure there are available cash resources to meet these needs. The following are the contractual maturities of the Corporation’s financial liabilities as at December 31, 2013: 2014 2015 2016 2017 2018 Thereafter Total Long-term debt $ – $ – $ – $ – $ 29,781 $ 1,316,780 $ 1,346,561 Interest on long-term debt (1) Commitments Total 87,176 195,589 87,176 14,061 87,176 11,373 87,176 8,467 87,087 170,394 606,185 7,357 15,714 252,561 $ 282,765 $ 101,237 $ 98,549 $ 95,643 $ 124,225 $ 1,502,888 $ 2,205,307 (1) Interest has been calculated based on debt balances, interest rates and foreign exchange rates in effect as at December 31, 2013 and excludes amortization of long-term debt issue costs. Fair Values The carrying value of cash, accounts receivable, and accounts payable and accrued liabilities approximates their fair value due to the relatively short period to maturity of the instruments. The fair value of the unsecured senior notes at December 31, 2013 was approximately $1,403 million (2012 – $1,330 million). Financial assets and liabilities recorded or disclosed at fair value in the consolidated balance sheet are categorized based on the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels are based on the amount of subjectivity associated with the inputs in the fair determination and are as follows: Level I—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. Level II—Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level III—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. The estimated fair value of unsecured senior notes is based on level II inputs. The fair value is estimated considering the risk free interest rates on government debt instruments of similar maturities, adjusted for estimated credit risk, industry risk and market risk premiums. 82 Notes to Consolidated Financial Statements NOTE 22. CAPITAL MANAGEMENT The Corporation’s strategy is to carry a capital base to maintain investor, creditor and market confidence and to sustain future development of the business. The Corporation seeks to maintain a balance between the level of long-term debt and shareholders’ equity to ensure access to capital markets to fund growth and working capital given the cyclical nature of the oilfield services sector. The Corporation strives to maintain a conservative ratio of long-term debt to long-term debt plus equity. As at December 31, 2013 and 2012 these ratios were as follows: Long-term debt Shareholders’ equity Total capitalization Long-term debt to long-term debt plus equity ratio $ $ 2013 1,323,268 2,399,343 3,722,611 0.36 $ $ 2012 1,218,796 2,171,300 3,390,096 0.36 As at December 31, 2013 liquidity remained sufficient as Precision had $80.6 million (2012 – $152.8 million) in cash and access to a US$850.0 million senior secured revolving credit facility (2012 – US$850.0 million) and $82.5 million (2012 – $79.8 million) secured operating facilities. As at December 31, 2013, US$28 million (2012 – US $nil) was drawn on the US$850 million secured revolving credit facility with availability further reduced by US$28.6 million (2012 – US$26.8 million) in outstanding letters of credit. Availability of the $40 million and US$25 million secured operating facilities were reduced by outstanding letters of credit of $17.3 million (2012 – $18.9 million) and US$0.2 million (2012 – US$ nil), respectively. There was no amount drawn on the US$15 million secured operating facility. NOTE 23. SUPPLEMENTAL INFORMATION Components of changes in non-cash working capital balances are as follows: Accounts receivable Inventory Accounts payable and accrued liabilities Pertaining to: Operations Investments The components of accounts receivable are as follows: Trade Accrued trade Prepaids and other 2013 2012 (23,110) $ 61,052 1,658 (22,682) (44,134) (33,887) (10,247) $ $ $ (6,707) (111,333) (56,988) 36,474 (93,462) $ $ $ $ 2013 2012 $ 314,448 $ 328,101 152,768 82,481 125,035 56,411 $ 549,697 $ 509,547 Precision Drilling Corporation 2013 Annual Report 83 The components of accounts payable and accrued liabilities are as follows: Accounts payable Accrued liabilities: Payroll Other 2013 2012 $ 148,081 $ 146,234 81,586 103,171 79,978 107,681 $ 332,838 $ 333,893 Precision presents expenses in the consolidated statement of earnings by function with the exception of depreciation and amortization and loss on asset decommissioning which are presented by nature. Operating expense and general and administrative expense would include $324.8 million and $8.3 million (2012 – $495.2 million and $4.8 million) respectively of depreciation and amortization and loss on asset decommissioning if the statements of earnings were presented purely by function. The following table presents operating and general and administrative expenses by nature: Wages, salaries and benefits Purchased materials, supplies and services Share-based compensation Allocated to: Operating expense General and administrative 2013 2012 $ 773,901 $ 795,243 589,394 27,849 1,391,144 1,248,637 142,507 1,391,144 $ $ $ 556,103 18,603 1,369,949 1,243,301 126,648 1,369,949 $ $ $ NOTE 24. CONTINGENCIES AND GUARANTEES The business and operations of the Corporation are complex and the Corporation has executed a number of significant financings, business combinations, acquisitions and dispositions over the course of its history. The computation of income taxes payable as a result of these transactions involves many complex factors as well as the Corporation’s interpretation of relevant tax legislation and regulations. The Corporation’s management believes that the provision for income tax is adequate and in accordance with IFRS and applicable legislation and regulations. However, there are tax filing positions that have been and can still be the subject of review by taxation authorities who may successfully challenge the Corporation’s interpretation of the applicable tax legislation and regulations, with the result that additional taxes could be payable by the Corporation and the amount owed, with estimated interest but without penalties, could be up to $58 million and is included in long-term income tax recoverable on the balance sheet. 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 thru 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. The Corporation, through the performance of its services, product sales and business arrangements, is sometimes named as a defendant in litigation. The outcome of such claims against the Corporation is not determinable at this time; however, their ultimate resolution is not expected to have a material adverse effect on the Corporation. The Corporation has entered into agreements indemnifying certain parties primarily with respect to tax and specific third party claims associated with businesses sold by the Corporation. Due to the nature of the indemnifications, the maximum exposure under these agreements cannot be estimated. No amounts have been recorded for the indemnities as the Corporation’s obligations under them are not probable or estimable. 84 Notes to Consolidated Financial Statements NOTE 25. SUBSIDIARIES Significant Subsidiaries Precision Limited Partnership Precision Drilling Canada Limited Partnership Precision Diversified Oilfield Services Corp. Precision Directional Services Ltd. Precision Drilling (US) Corporation Precision Drilling Company LP Precision Completion & Production Services Ltd. Precision Directional Services, Inc. Grey Wolf Drilling Limited Country of Incorporation Canada Canada Canada Canada United States United States United States United States Cyprus Ownership Interest 2013 100 100 100 100 100 100 100 100 100 2012 100 100 100 100 100 100 100 100 100 Precision Drilling Corporation 2013 Annual Report 85 Consolidated Statements of Earnings 2013 2012 2011 2010 2009 (1) $ 2,029.9 $ 2,040.7 $ 1,951.0 $ 1,429.7 $ 1,197.4 1,248.6 1,243.3 1,131.0 142.5 126.6 124.9 886.8 108.0 434.9 210.1 – 224.8 – 692.2 98.2 407.0 138.0 82.1 186.9 – 695.1 251.5 114.9 328.7 – (23.7) (12.7) (122.8) 111.6 240.8 47.3 193.5 211.3 26.2 (17.3) 43.5 147.4 162.3 0.6 161.7 638.8 333.1 – 305.7 – (9.1) 93.3 221.5 30.3 191.2 670.8 307.5 192.5 170.8 52.5 3.8 86.8 27.7 (24.7) 52.4 $ $ 0.69 0.66 $ $ 0.19 0.18 $ $ 0.70 0.67 $ $ 0.16 0.15 $ $ 0.65 0.63 Years ended December 31, (Stated in millions of Canadian dollars, except per unit/share amounts) Revenue Expenses: Operating General and administrative Earnings before income taxes, finance charges, foreign exchange, impairment of goodwill, loss on asset decommissioning, and depreciation and amortization (Adjusted EBITDA) Depreciation and amortization Loss on decommissioning Operating earnings Impairment of goodwill Foreign exchange Finance charges Earnings before income taxes Income taxes Net earnings Earnings per unit/share: Basic Diluted (1) 2009 was prepared under previous Canadian GAAP. 86 Supplemental Information Additional Selected Financial Information Years ended December 31, (Stated in millions of Canadian dollars, except per unit/share amounts) Return on sales – % (2) Return on assets – % (3) Return on equity – % (4) Working capital Current ratio PP&E and intangibles Total assets Long-term debt Shareholders’ equity Long-term debt to long-term debt plus equity Interest coverage (5) Net capital expenditures excluding business acquisitions Adjusted EBITDA Adjusted EBITDA – % of revenue Operating earnings Operating earnings – % of revenue 2013 2012 2011 2010 2009 (1) 9.4 4.3 8.4 2.6 1.2 2.4 9.9 4.9 9.5 3.0 1.3 2.2 13.5 3.6 6.2 $ 305.8 $ 278.0 $ 610.4 $ 458.0 $ 320.9 1.9 1.7 2.4 3.1 3.5 $ 3,565.7 $ 3,249.0 $ 2,948.8 $ 2,538.8 $ 2,917.1 $ 4,579.1 $ 4,300.3 $ 4,427.9 $ 3,564.5 $ 4,191.7 $ 1,323.3 $ 1,218.8 $ 1,239.6 $ 804.5 $ 748.7 $ 2,399.3 $ 2,171.3 $ 2,132.6 $ 1,932.8 $ 2,584.5 0.36 3.3 522.4 638.8 31.5 $ $ 0.36 2.0 836.6 670.8 32.9 0.37 2.9 710.4 695.1 35.6 $ $ $ $ 0.29 1.1 163.6 434.9 30.4 0.22 1.3 177.5 407.0 34.0 $ $ $ $ $ 305.7 $ 170.8 $ 328.7 $ 224.8 $ 186.9 15.1 8.4 16.8 15.7 15.6 Cash flow from continuing operations $ 428.1 $ 635.3 $ 532.8 $ 306.3 $ 504.7 Cash flow from continuing operations per unit/share: Basic Diluted Book value per unit/share (6) Price earnings ratio (7) $ $ $ 1.54 1.49 8.22 $ $ $ 2.30 2.22 7.85 $ $ $ 1.93 1.85 7.72 $ $ $ 1.11 1.07 7.01 $ $ $ 2.02 1.94 9.38 14.41 43.26 15.00 41.74 11.77 Basic weighted average units/shares outstanding (000s) 277,583 276,276 275,899 275,655 249,925 (1) 2009 was prepared under previous Canadian GAAP. (2) Return on sales was calculated by dividing earnings from continuing operations by total revenues. (3) Return on assets was calculated by dividing net earnings by quarter average total assets. (4) Return on equity was calculated by dividing net earnings by quarter average total shareholders’ equity. (5) Interest coverage was calculated by dividing operating earnings by net interest expense. (6) Book value per unit/share was calculated by dividing shareholders’ equity by shares outstanding. (7) Price earnings ratio was calculated using year-end closing price divided by basic earnings per unit/share. Precision Drilling Corporation 2013 Annual Report 87 ACCOUNT QUESTIONS Our transfer agent can help you with shareholder related services, including:  change of address   lost share certificates transferring shares to another person  estate settlement. Computershare Trust Company of Canada 100 University Avenue, 9th Floor, North Tower Toronto, Ontario, Canada M5J 2Y1 Telephone: 1.800.564.6253 (toll free in Canada and the United States) 1.514.982.7555 (international direct dialing) Email: service@computershare.com Shareholder Information STOCK EXCHANGE LISTINGS Our shares are listed on the Toronto Stock Exchange under the trading symbol PD and on the New York Stock Exchange under the trading symbol PDS. TRANSFER AGENT AND REGISTRAR Computershare Trust Company of Canada Calgary, Alberta TRANSFER POINT Computershare Trust Company NA Denver, Colorado 2013 TRADING PROFILE Toronto (TSX: PD) High: $11.53 Low: $7.47 Close: $9.94 Volume Traded: 297,457,268 New York (NYSE: PDS) High: US$11.21 Low: US$7.29 Close: US$9.37 Volume Traded: 288,801,100 ONLINE INFORMATION To receive news releases by email, or to view this report online, please visit the Investor Relations section of our website at www.precisiondrilling.com. You can find additional information about us, including our annual information form, 2013 annual report and management information circular, on our website as well as under our profile on the SEDAR website at www.sedar.com and on the EDGAR website at www.sec.gov. PUBLISHED INFORMATION Please contact us if you would like additional copies of this annual report, or copies of our 2013 annual information form as filed with the Canadian securities commissions and under Form 40-F with the U.S. Securities and Exchange Commission: Investor Relations Suite 800, 525 – 8th Avenue SW Calgary, Alberta, Canada T2P 1G1 Telephone: 403.716.4500 88 Shareholder Information LEAD BANK Royal Bank of Canada Calgary, Alberta AUDITORS KPMG LLP Calgary, Alberta HEAD OFFICE Suite 800, 525 – 8th Avenue SW Calgary, Alberta, Canada T2P 1G1 Telephone: 403.716.4500 Email: info@precisiondrilling.com www.precisiondrilling.com Corporate Information DIRECTORS William T. Donovan1,2 North Palm Beach, Florida, USA Brian J. Gibson1,2 Mississauga, Ontario, Canada Allen R. Hagerman, FCA1,3 Calgary, Alberta, Canada Catherine Hughes2,3 Calgary, Alberta, Canada Stephen J. J. Letwin2,3 Toronto, Ontario, Canada Kevin O. Meyers2,3 Houston, Texas, USA Patrick M. Murray1,3 Dallas, Texas, USA Kevin A. Neveu Calgary, Alberta, Canada Robert L. Phillips1,2,3 Vancouver, British Columbia, Canada 1. Member of Audit Committee 2. Member of Corporate Governance, Nominating and Risk Committee 3. Member of Human Resources and Compensation Committee OFFICERS Kevin A. Neveu President and Chief Executive Officer Joanne L. Alexander Senior Vice President, General Counsel and Corporate Secretary Niels Espeland President, International Operations Douglas B. Evasiuk Senior Vice President, Sales and Marketing Kenneth J. Haddad Senior Vice President, Business Development Robert J. McNally Executive Vice President and Chief Financial Officer Darren J. Ruhr Senior Vice President, Corporate Services Gene C. Stahl President, Drilling Operations Douglas J. Strong President, Completion and Production Services Precision Drilling Corporation 2013 Annual Report 89 Precision Drilling Corporation Suite 800, 525 – 8th Avenue SW Calgary, Alberta, Canada T2P 1G1 Telephone: 403.716.4500 Email: info@precisiondrilling.com www.precisiondrilling.com P R I N T E D I N C A N A D A 

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