EX-99.2

EX-99.2 8 d497657dex992.htm EX-99.2 EX-99.2

Exhibit 99.2

Management’s Discussion and Analysis

Consolidated Financial Statements and Notes

Precision Drilling Corporation 2012


What’s inside

6		About Precision

8		2012 Highlights and Outlook

12		Contract Drilling Services

13		Completion and Production Services

14		Understanding Our Business Drivers
		The energy industry A competitive operating model An effective strategy Risks to achieving our strategy

26		2012 Results

36		Financial Condition

41		Critical Accounting Estimates

43		Evaluation of Disclosure Controls and Procedures

43		Corporate Governance

44		Consolidated Financial Statements and Notes


2		Management’s Discussion and Analysis

Management’s Discussion and Analysis

This management’s discussion and analysis (MD&A) contains information to help you understand our business and financial performance. Information is as of March 8, 2013. 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 4. We began reporting under IFRS effective January 1, 2011, and restated our 2010 results at that time. 2009 and prior years are presented in accordance with previous Canadian Generally Accepted Accounting Principles (Previous Canadian GAAP).

The terms, we, us, our, corporation and Precision mean Precision Drilling Corporation and all of our consolidated subsidiaries and any partnerships that we and/or our subsidiaries are part of.

All amounts are in Canadian dollars unless otherwise stated.


		Precision Drilling Corporation 2012 Annual Report		3

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 Private Securities Litigation Reform Act of 1995 (collectively the forward-looking information and statements).

Forward-looking information and statements in this MD&A:

typically include words and phrases about the future, such as anticipate, could, should, can, expect, seek, may, intend, likely, will, plan, estimate and believe

are based on certain assumptions and analyses based on our experience, understanding of historical trends, current conditions and expected future developments, and other factors we believe are appropriate given the circumstances

can be affected by known and unknown risks, uncertainties and other factors which could cause actual results to differ materially from our expectations.

Actual results, performance or achievements may be significantly different from what is expressed or implied in the forward-looking information.

Our forward-looking information includes statements about the following, among other things:

performance of the oil and natural gas industry, including commodity prices

our capital expenditures and potential international expansion

2013 strategic plans

deployment of additional rigs, building new ones and upgrading existing ones

the obsolescence of Tier 3 rigs in North American markets over the next few years and Precision exiting the Tier 3 contract drilling business

the supply and demand for oil and natural gas

demand for our equipment and services

the potential impact of current or anticipated regulatory regimes and tax, environmental, health, safety and other laws

the potential impact of seasonal and weather conditions, competition in markets where we compete, technology advances, finding and retaining employees, reliance on suppliers, credit market conditions, access to additional financing, foreign exchange, international operations as well as other risks and uncertainties discussed herein

payment of quarterly dividends

our future growth potential

remaining compliant with financial ratio covenants

amounts of contractual obligations not yet accrued.


4		Management’s Discussion and Analysis

Risks and uncertainties

This MD&A discusses a number of risks and uncertainties, including the following among others:

fluctuations in the price and demand for oil and natural gas

fluctuations in the level of oil and natural gas exploration and development activities

fluctuations in the demand for contract drilling, directional drilling, well servicing and ancillary oilfield services

liquidity of the capital markets to fund customer drilling programs

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

the sustainability of our dividend

the impact of seasonal and weather conditions on operations and facilities

competitive operating risks inherent in contract drilling, directional drilling, well servicing and ancillary oilfield services

ability to improve our rig technology to improve drilling efficiency

general economic, market or business conditions

changes in laws or regulations

availability of qualified personnel, management or other key inputs

currency exchange fluctuations

operating in foreign countries

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 Achieve Our Strategy”.

These risks and uncertainties are also discussed in our annual information form (AIF), on file with the Canadian securities commissions on SEDAR (www.sedar.com) and with the SEC on EDGAR (www.sec.gov).

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

ADDITIONAL GAAP MEASURES

In this MD&A we reference Generally Accepted Accounting Principles (GAAP) measures that are not defined terms under IFRS to assess performance because we believe they provide useful supplemental information to investors.

Adjusted EBITDA

We believe that Adjusted EBITDA (earnings before income taxes, finance charges, foreign exchange, impairment of goodwill, loss on asset decommissioning and depreciation and amortization) as reported in the Consolidated Statement of Earnings is a useful supplemental measure, because it gives an indication of the results from our principal business activities prior to consideration of how our activities are financed and 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 provides an indication of the results of our principal business activities before consideration of how our activities are financed and 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 provides 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 2012 Annual Report		5

About Precision

Precision Drilling provides onshore drilling and 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 drillers in the United States. We also have operations in Mexico and Saudi Arabia, and have announced long-term contracts for other areas in 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.

Two business segments

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

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6		Management’s Discussion and Analysis

2012 Adjusted EBITDA by Segment

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2012 Revenue by Region

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Vision

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

Strategy


2012 strategic priorities		2012 results
Execute our High Performance, High Value strategy Continue to deliver safe, reliable, predictable and repeatable performance with high environmental responsibility and community standards.		Improved safety performance in both operating segments in 2012, matching the best results in our history.
Execute on existing organic growth opportunities including contracting additional new build and upgraded drilling rigs, adding assets and people to the directional drilling and Completion and Production Services businesses and pursuing additional rig deployments internationally. Continue to evaluate accretive acquisitions.		Delivered 36 new build Tier 1 Super Series drilling rigs to customers on long-term contracts and upgraded 11 existing drilling rigs to higher specification assets under long-term contracts. Established footprint in the Middle East and expanded international operations from two rigs to eight operating at the end of the year. However, start-up activities took longer than expected. Expanded service lines in Completion and Production Services adding higher end rental offerings and entered the coil tubing business. Expanded penetration into Northern U.S. markets. Over the past two years, we have grown our directional drilling business but financial results and utilization have been weaker than expected.
Build our brand Continue to promote Precision’s High Performance, High Value brand with customers, employees, investors and within the communities in which we operate.		Had strong Canadian and U.S. dayrates throughout 2012 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.

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.

a competitive operating model drives efficiency, quality and cost control

size and scale provide higher margins and better service

strong liquidity position allows us to take advantage of opportunities throughout business cycles

capital structure provides long-term stability and flexibility


		Precision Drilling Corporation 2012 Annual Report		7

2012 Highlights and Outlook

Adjusted EBITDA and funds provided by operations are additional GAAP measures.

Please see page 5 for more information.

Financial highlights


Year ended December 31 (thousands of $, except where noted)	2012			% increase/ (decrease)			2011			% increase/ (decrease)			2010			% increase/ (decrease)
Revenue		2,040,741			4.6			1,951,027			36.5			1,429,653			19.4
Adjusted EBITDA		670,792			(3.5	)		695,064			59.8			434,908			6.9
Adjusted EBITDA % of revenue		32.9%						35.6%						30.4%
Net earnings		52,360			(72.9	)		193,477			344.4			43,535			(73.1	)
Cash provided by operations		635,286			19.2			532,772			74.0			306,264			(39.3	)
Funds provided by operations		598,812			1.1			592,388			46.6			404,165			21.9
Investing activities
Capital spending:
Expansion		596,194			30.9			455,302			539.7			71,179			(56.4	)
Upgrade		130,094			(13.2	)		149,811			174.0			54,683			3,007.0
Maintenance and infrastructure		141,769			16.9			121,244			142.3			50,039			75.3
Proceeds on sale		(31,423	)		96.6			(15,983	)		30.4			(12,256	)		(23.3	)
Net capital spending		836,634			17.8			710,374			334.1			163,645			(7.8	)
Business acquisitions (net of cash acquired)		25			(100.0	)		92,886			n/m			–			–
Earnings per share ($):
Basic		0.19			(72.9	)		0.70			337.5			0.16			(75.4	)
Diluted		0.18			(73.1	)		0.67			346.7			0.15			(76.2	)
Dividends per share ($)		0.05			n/m			–			–			–			–
n/m – calculation not meaningful.
Operating highlights
Year ended December 31	2012			% increase/ (decrease)			2011			% increase/ (decrease)			2010			% increase/ (decrease)
Contract drilling rig fleet		321			(4.7	)		337			(5.1	)		355			0.9
Drilling rig utilization days:
Canada		32,352			(14.8	)		37,970			21.8			31,176			46.9
United States		34,597			(8.7	)		37,887			16.8			32,450			43.1
International		2,086			197.2			702			16.6			602			(15.2	)
Service rig fleet		214			3.4			207			(5.9	)		220			–
Service rig operating hours¹		294,681			(7.2	)		317,418			7.9			294,126			33.9

¹	Prior year comparatives have been changed to include United States based service rig activity.


8		Management’s Discussion and Analysis

Financial position and ratios


Years ended December 31 (thousands of $, except ratios)	2012	2011	2010
Working capital	278,021	610,429	458,003
Working capital ratio	1.7	2.4	3.1
Long-term debt	1,218,796	1,239,616	804,494
Total long-term financial liabilities	1,245,290	1,267,040	834,813
Total assets	4,300,263	4,427,874	3,564,540
Enterprise value¹	3,213,406	3,528,046	2,993,083
Long-term debt to long-term debt plus equity	0.36	0.37	0.29
Long-term debt to cash provided by operations	1.92	2.33	2.63
Long-term debt to enterprise value	0.38	0.35	0.27

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

2012 OVERVIEW

Net earnings this year were $52 million or $0.18 per diluted share, compared to $193 million or $0.67 per diluted share in 2011. This year’s 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 this year was $2,041 million, or 5% higher than 2011, mainly due to higher drilling pricing in both Canada and the United States, growth in international operations, and product line expansion partially offset by lower utilization days in North America. Contract Drilling Services revenue was up 6%, while revenue from Completion and Production Services was down 1%. Our international drilling activity increased three-fold: an average of six rigs working in 2012 compared to two in 2011.

Adjusted EBITDA this year was $671 million, or 3% lower than 2011. Our adjusted EBITDA margin was 33% this year, compared to 36% in 2011. The decrease in adjusted EBITDA margin was mainly the result of higher average operating costs and lower equipment utilization in both Canada and the United States, partially offset by higher average dayrates in both Canada and the United States. Operating costs were higher because of labour related costs, repairs and maintenance costs and higher operating costs internationally. 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.

North America industry activity was down on 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 2012 our Board of Directors approved the introduction of an annualized dividend of $0.20 per common share, payable quarterly.

Outlook

Contracts

Our strong portfolio of term customer contracts provides a base level of activity and revenue, and as at March 8, 2013 we have term contracts in place for an average of 96 rigs: 52 in Canada, 36 in the United States and 8 internationally in 2013. In Canada, term contracted rigs normally generate 250 utilization days per rig year because of the seasonal nature of well access. In most regions in the United States and internationally, they normally generate 365 utilization days per rig year.

Pricing, demand and utilization

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


		Precision Drilling Corporation 2012 Annual Report		9

Natural gas prices, however, remain depressed, reaching 10-year lows in 2012. Lower natural gas prices have persisted due to higher than average storage levels, increased production from unconventional resource development and the lack of an export market from North America. Despite lower industry-wide natural gas drilling activity, production remained stable, meeting or exceeding demand and keeping prices low.

Natural gas demand largely depends on the weather, and moderate North American winter temperatures in 2011 and 2012 hampered overall demand. Other demand drivers, however, like natural gas fired power generation and industrial applications, have shown positive growth over the past three years and are expected to continue, and the growing potential of liquefied natural gas (“LNG”) export development could serve as a catalyst for natural gas directed drilling activity in the medium to long term.

Industry-wide drilling utilization has declined year-over-year in North America, however demand for the higher specification Tier 1 drilling assets has remained strong, supporting dayrates. We have deployed 60 new build Tier 1 Super Series drilling rigs since the beginning of 2010 for a total current fleet of 189 Tier 1 drilling rigs and we have upgradeable rigs within our fleet. We believe the existing new builds and potential rig upgrades favourably position us in the market for premium drilling rigs.

While the increase in oil and liquids rich natural gas drilling in areas like the Montney, Cardium, Bakken, Viking, Eagle Ford, Tuscaloosa, Niobrara and Granite Wash have been strong, the oil rig count at March 8, 2013 was 2% higher in the United States than it was a year ago, and 9% lower in Canada. The overall North American land oil directed rig count on March 8, 2013 was 3.9 times higher than it was on March 6, 2009. As exploration and production companies continue to improve unconventional oil drilling and completion techniques, we expect that the economics our customers realize will drive additional investment capital toward these unconventional plays, supporting drilling activity especially for Tier 1 rigs.

International

We contracted two new build 3000 horsepower (HP) drilling rigs in 2012 for deep drilling operations in Kuwait. The two new rigs are on long-term contracts and are expected to be deployed in 2014 on a long-term contract. We contracted two 2000 HP rigs for deep drilling operations in Northern Iraq in the Kurdistan region. The two rigs are existing Precision rigs that will be upgraded for desert operations. These rigs are expected to be deployed mid 2013 under a long-term contract. We also signed a contract for operations in Mexico that will add a rig to our Mexican fleet in the second quarter of 2013, increasing our active Mexican fleet to six rigs.

Upgrading the fleet

We and the land drilling industry are in the process of upgrading the drilling rig fleet by building new rigs and upgrading existing ones. We believe this “retooling” of the industry-wide fleet will make Tier 3 rigs virtually obsolete in North America over the next few years. In the fourth quarter of 2012 we decommissioned 42 Tier 3 drilling rigs and 10 Tier 2 rigs from our fleet. We are exiting the Tier 3 contract drilling business but will retain 26 drilling rigs for seasonal, stratification and turnkey drilling work. These will be categorized as “PSST” rigs. 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 2013 to be approximately $526 million:

$205 million for expansion capital, which includes the cost to complete the two remaining drilling rigs from the 2012 new build rig program, one new rig build for the North American market, the cost to complete about 50 percent of two new build rigs going to Kuwait and new equipment for our Completion and Production Services segment

$127 million for upgrade capital, which includes the upgrade of approximately 20 rigs, including the two rigs going to Northern Iraq in the Kurdistan region

$194 million for sustaining and infrastructure expenditures, which is based on currently anticipated activity levels, and the cost to consolidate and upgrade our Nisku, Alberta operations facility.


10		Management’s Discussion and Analysis

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		Precision Drilling Corporation 2012 Annual Report		11

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 American servicing approximately 24% of the land drilling market in Canada and five percent of the United States market. We also have an international presence with operations in Mexico and the Middle East.

At December 31, 2012, the segment consisted of:

321 land drilling rigs, including:

–

186 in Canada

–

127 in the U.S.

–

3 in Saudi Arabia

–

5 in Mexico

capacity for approximately 91 concurrent directional drilling jobs in Canada and 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, 2012


Horsepower	< 1000	1000-1500	> 1500	Total
Tier 1	94	89	5	188
Tier 2	64	25	18	107
PSST	17	4	5	26
Total	175	118	28	321

Geographic location	Canada	U.S.	International	Total
Tier 1	105	83	–	188
Tier 2	64	35	8	107
PSST	17	9	–	26
Total	186	127	8	321

Contract Drilling Revenue

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Contract Drilling Adjusted EBITDA

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Note:		2008 and 2009 are prepared under previous Canadian Generally Accepted Accounting Principles

Contract Drilling Utilization Days

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12		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, 2012, the segment consisted of:

190 well completion and workover service rigs, including:

–

185 in Canada

–

5 in the U.S.

19 snubbing units, including:

–

16 in Canada

–

3 in the U.S.

5 coil tubing units, including:

–

3 in Canada

–

2 in the U.S.

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

243 wellsite accommodation units in Canada and 61 in the U.S.

50 drilling camps and three base camps in Canada and four drilling camps in the U.S.

eight large-flow treatment units and six potable water production units in Canada

Canadian fleet as at December 31


Type of Service Rig	Horsepower	2008	2009	2010	2011	2012
Singles:
Mobile	150-400	2	–	–	–	–
Freestanding mobile	150-400	97	94	94	90	88
Doubles:
Mobile	250-550	42	28	25	19	18
Freestanding mobile	200-550	23	30	35	40	38
Skid	300-860	48	30	28	22	22
Slants:
Freestanding	250-400	17	18	18	18	19
Total service rigs		229	200	200	189	185
Snubbing units		29	20	20	18	16
Coil tubing units		–	–	–	–	3
Total service rigs, snubbing units and coil tubing units		258	220	220	207	204

Completion & Production Revenue

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Completion & Production

Adjusted EBITDA

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Note:		2008 and 2009 are prepared under previous Canadian Generally Accepted Accounting Principles

Completion and Production

Service Rig Hours

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		Precision Drilling Corporation 2012 Annual Report		13

Understanding Our Business Drivers

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THE ENERGY INDUSTRY

Precision operates in the energy services business, which is an inherently challenging cyclical industry. Customer demand depends on the price for their end products: oil, natural gas, and natural gas liquids. Oil is a more global commodity that depends on global oil economics, while natural gas and natural gas liquids are more regional energy commodities.

We depend on oil and natural gas exploration and production companies to contract us as part of their development. The economics of their business are dictated by the current and expected future margin between the cost to find and develop oil and natural gas, and the eventual prices of those products.

To excel in this environment, we operate using a business model designed to control risk and optimize performance. The model is directly linked to competitive strategy and reflected in our operating capabilities.

Commodity prices

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 and cheaply, so it is priced in a more global market influenced by an array of economic and political factors. Recently, transportation constraints have resulted in oil prices in North America decoupling from global prices. Natural gas and natural gas liquids continue to be priced regionally.

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 prices have dipped to levels that existed during the economic crisis of 2008, because increasing supplies of unconventional natural gas, particularly in North America, are keeping markets well supplied. This is keeping prices competitive compared to oil, and is supporting the projected growth in worldwide gas consumption.

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14		Management’s Discussion and Analysis

New technology

Recent technological advancements in fracturing, stimulation and horizontal drilling have brought about a shift in development from conventional to unconventional oil and natural gas 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 the more demanding directional/horizontal well programs, which require higher capacity equipment and greater technical expertise for drilling. These trends are driving the demand growth for high performing drilling rigs, which garner premium pricing.

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These technical innovations have been a major factor in the increase in natural gas production in the United States. Although oil production has been increasing in Canada, natural gas production is declining as the U.S. is becoming less reliant on Canada as a source of natural gas resulting in pricing pressure on Canadian natural gas.

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		Precision Drilling Corporation 2012 Annual Report		15

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Drilling activity

The graphs below show that since 2010 drilling activity in the United States 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 United States.

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16		Management’s Discussion and Analysis

A COMPETITIVE OPERATING MODEL

The contract drilling business is highly competitive and there are many industry participants. We compete for drilling contracts that are usually awarded based on competitive bids.

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 delivering passionate people supported by superior systems and equipment designed to maximize productivity and reduce risks. We create High Value by operating safely, lowering customer risks and costs, developing people, generating financial growth and attracting investment.

Operating efficiency

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

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

having equipment that is geographically dispersed, reliable and well maintained

monitoring 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 capture incremental time savings during all phases of the well drilling process, including multi-well pad capability and mobility between wells.

The versatile Precision Super Single design includes technical innovations in safety and drilling efficiency in slant or directional drilling on single or multiple well pad locations in shallow to medium depth wells. Precision Super Single rigs use extended length tubulars, 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 and ST-1500) 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 along with a computerized electronic auto driller feature that precisely controls weight, rotation and torque on the drill bit. These rigs use extended length drill pipe, an integrated top drive, automated pipe handling with iron roughnecks and control automation off the rig floor.

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 most active regions in North America, including all the major prolific unconventional oil and gas fields. More recently, we have expanded drilling operations into select international markets.

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 placed spare equipment, an in-house supply chain and continuous equipment upgrades.

We minimize non-productive time (move, rig-up and rig-out time) by utilizing walking and skidding systems, decreasing the number of move loads per rig, and using mechanized equipment for safer and quicker rig component connections.


		Precision Drilling Corporation 2012 Annual Report		17

Tracking our results

We unitize key financial information per day and per hour, and compare it to established benchmarks and past performance. We evaluate the relative strength of our financial position by monitoring our working capital, debt ratios and returns on capital employed. We track industry rig utilization statistics to evaluate our performance against competitors. And we link incentive compensation for our senior team to returns generated compared to established benchmarks.

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

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

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.

Financial performance – total shareholder return performance against an industry peer group, including dividends, over a three year period. Measured against predetermined selection of competitors in 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.

Large, diverse fleet of rigs

Our fleet of drilling rigs can handle every kind of onshore conventional and unconventional oil and natural gas wells in North America.

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

Snubbing complements 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.

We are investing in coil tubing units that have the ability to service horizontal wells by pushing the tubing rather than relying on gravity. Coil tubing often works more effectively in unconventional horizontal wells which represent the majority of wells drilled in North America today. We began using our first coil tubing unit in the first quarter of 2012 and finished with five units at the end of 2012.

This year we high-graded our drilling rig fleet by:

adding 36 Tier 1 new build drilling rigs

upgrading 11 drilling rigs – about half of these were Tier upgrades

decommissioning 42 Tier 3 and 10 Tier 2 rigs.


18		Management’s Discussion and Analysis

As at December 31, 2012, 92% of our 321 drilling rigs were Tier 1 or Tier 2 rigs.

Tier 1

Tier 2

PSST

high performance rigs

conventional

newer design and manufacture

modified and new equipment

added to improve performance

mechanical rigs

Capabilities

Best suited to the more complex

Capable of directional and

Designed for traditional, vertical drilling

resources in North American shale

horizontal drilling

used in seasonal and stratification

and unconventional plays:

work in Canada

pad development

can be used in our turkey operations

directional or horizontal drilling

in the United States

slant drilling

drilling in environmentally sensitive

areas

Key features

advanced AC, silicone controlled

some mechanization of tubular

no automation

rectifier (“SCR”), or mechanical

handling equipment

lower pump capacity

power distribution and controls

top drive adaptability

provide acceptable performance

mobile in their class (require fewer

SCR or mechanical type power

some are top drive adaptable

trucking loads)

systems

highly mechanized tubular handling

increased hook load and or racking

equipment

capabilities

integrated top drive or top drive

upgraded power generating,

adaptability

control systems and other major

electronic or hydraulic control of the

components

majority of operating parameters

high-capacity mud pumps

specialized drilling tubulars

high-capacity mud pumps

Inventory of ancillary equipment

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 if there is an equipment failure.

Precision Rentals supplies customers with an inventory of specialized equipment and wellsite accommodations. LRG Catering 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 LRG Catering and other camp facilities.

Systematic maintenance

We consistently reinvest capital to sustain and upgrade existing property, plant and equipment, and benchmark equipment repair and maintenance expenses to activity levels in accordance with our maintenance and certification programs.

We use computer systems to track key preventative maintenance indicators for major rig components, to record equipment performance history, schedule equipment certifications, reduce downtime and allow for better asset management.

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 United States.

We have a continuous maintenance program for essential elements, like 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 may result in a change in tier classification.


		Precision Drilling Corporation 2012 Annual Report		19

People

Having an experienced, high performance crew is a competitive strength and highly valued by our customers. There are often shortages of qualified manpower in peak operating periods. We rely heavily on our safety record, investment in employee development and reputation to attract and retain employees, and focus on initiatives that provide a safe and productive work environment, opportunity for advancement and added wage security. We have centralized personnel, orientation and training programs in Canada and the U.S.; however, in the U.S. these functions are sometimes managed to align with regional labour and customer service requirements. In 2008 we launched Toughnecks, our highly successful North America field recruiting program.

Systems

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

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 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 fundamental 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, which is seen as a leading indicator for the potential of a more serious incident. In 2012, 269 of our drilling rigs and 186 of our service rigs and snubbing units achieved Target Zero. We continue to embrace technological advancements which make operations safer.

Together with our customers, we are continuously looking for opportunities to reduce our consumption of non-renewable resources and our environmental footprint. We use technology to reduce 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 that vision by defining and measuring our results against strategic priorities we establish at the beginning of every year.


2012 Strategic Priorities	2012 Results	Plans for 2013
Execute our High Performance, High Value strategy Continue to deliver safe, reliable, predictable and repeatable performance with high environmental responsibility and community standards.	Improved safety performance in both operating segments in 2012, matching the best results in our history.	Continue to drive execution excellence in our people, internal systems and infrastructure supporting our world class safety, training and development programs, upgrading and consolidating our Nisku operations and leveraging our investments in our Houston and Red Deer Tech Centers.
Execute on existing organic growth opportunities including contracting additional new build and upgraded drilling rigs, adding assets and people to the directional drilling and Completion and Production Services businesses and pursuing additional rig deployments internationally. Continue to evaluate accretive acquisitions.	Delivered 36 new build Super Series to customers on long-term contracts and upgraded 11 existing drilling rigs to higher specification assets under long-term contracts. Established footprint in the Middle East and expanded international operations from two rigs to eight operating at the end of the year. Start-up activities took longer than expected. Expanded service lines in Completion and Production Services adding higher end rental offerings and entering the coil tubing business. Expanded penetration into Northern U.S. markets. Over the past two years, we have grown our directional drilling business but financial results and utilization have been weaker than expected.	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. Continue to expand geographically with international drilling operations and increased Completion and Production presence in the U.S. market.
Build our brand Continue to promote Precision’s High Performance, High Value brand with customers, employees, investors and within the communities in which we operate.	Had strong Canadian and U.S. dayrates throughout 2012 and exceeded employee retention goals across all targeted skill positions. Increased recognition from U.S. and international investors while retaining strong support from Canadian base.	Uphold our reputation and market breadth in North America while strengthening our presence 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 market place. Unconventional resource development requires advanced Tier 1 drilling rigs and other highly developed services that promote 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 2012 Annual Report		21

RISKS TO ACHIEVING OUR STRATEGY

The following is a list of our key business risks. You’ll find more information and other risks to our business in our annual information form, which you can find on our website, www.precisiondrilling.com.

Price of oil and 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 part of the 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. The rigs and other necessary equipment cannot cross the 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 are unable to be relocated to another site if the muskeg thaws unexpectedly. Our business results depend partly on how long and severe the winter season lasts.

Competition

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 more new or newer rigs 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 and the waiting period between when a decision is made to upgrade or build new equipment and 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 our equipment and services. The additional supply of drilling rigs has intensified price competition in the past and could continue to do so and possibly lead to lower rates in the oilfield services industry generally and lower utilization of existing rigs. If any of these factors materializes, it would have an adverse effect on our revenues, cash flows, earnings and asset valuation.

Technology

Complex drilling programs for the exploration and development of conventional and unconventional oil and natural gas reserves demand high performance drilling rigs. The ability of drilling rig service providers to meet this demand depends on continuous improvement of existing rig technology like 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 cannot assure that our rig technology will continue to meet demands, especially as rigs age and technology advances, or that our competitors will not develop technological improvements that are more advantageous, timely or cost effective than our own advancements.


22		Management’s Discussion and Analysis

We have an experienced internal engineering department that works closely with operations and marketing on equipment design and improvements. We cannot guarantee, 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

We may not be able to find enough skilled labor to meet our needs, and this could limit growth. We may also have difficulty finding enough skilled and unskilled labor 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. We also focus on providing a safe and productive work environment, opportunity for advancement and added wage security, to retain and attract quality staff.

Reliance 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. We maintain relationships with key suppliers and contractors and an inventory of key components, materials, equipment and parts. We also place advance orders for components that have long lead times.

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

We may, however, experience cost increases, delays in delivery due to 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 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

Safety

Standards for accident prevention in the oil and 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. 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.

We manage our safety performance using our Target Zero program, a comprehensive training and assessment program designed to work toward a vision of no workplace incidents resulting in injury.

Laws, regulations and guidelines

Our operations are affected by numerous laws, regulations and guidelines relating to the protection of the environment and health and safety, including those governing the management, transportation and disposal of hazardous substances and other waste materials. These include laws, regulations and guidelines relating to spills, releases, emissions and discharges of hazardous substances or other waste materials into the environment, requiring removal or remediation of pollutants or contaminants, and imposing civil and criminal penalties for violations. Some of these apply to our operations and authorize the recovery of natural resource damages by the government, injunctive relief, and the imposition of stop, control, remediation and abandonment orders. In addition, our land drilling operations may be conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and may expose us to additional operating costs and liabilities for noncompliance with certain laws. Some environmental laws and regulations


		Precision Drilling Corporation 2012 Annual Report		23

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 facility. 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 may be incurred by us 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.

Energy and the environment

The issue of energy and the environment has created intense public debate in Canada and around the world in recent years, and it is likely to continue for the foreseeable future and could potentially have a significant impact on all aspects of the economy. The trend in environmental regulation has been to impose more restrictions and limitations on activities that may impact the environment. Any regulatory changes that impose additional environmental restrictions or requirements on us, or our customers, could increase our operating costs and potentially lead to lower demand for our services and have an adverse effect on us. For example, there is growing concern about the apparent connection between the burning of fossil fuels and climate change. Laws, regulations or treaties concerning climate change or greenhouse gas emissions can have an adverse impact on the demand for oil and natural gas, which could have a material adverse effect on us. Governments in Canada and the U.S. are also reviewing 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. There is no assurance of the outcome of these developments, their effect on the regulatory landscape and the contract drilling industry, or that additional governmental organizations will not seek to pass legislation on hydraulic fracturing in the future.

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 lower demand for drilling rigs, well service rigs, reduced dayrates and a decrease in demand for directional drilling and turnkey jobs, other wellsite services or 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, 2020 notes, 2019 notes, 2021 notes and other debt agreements we have in the future. 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


24		Management’s Discussion and Analysis

other liquidity requirements. If we are not able to borrow a sufficient amount, or generate enough cash flow from operations to service and repay our debt, we will need to refinance our debt or we will be in default, and we could be forced to reduce or delay investments and capital expenditures or dispose of material assets. We may not be able to refinance or arrange alternative measures on favorable terms or at all. If we are unable to service, repay and/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

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 revenue 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 US 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 US dollars. We have designated our US dollar denominated unsecured senior 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 US dollar, we will incur a foreign exchange gain from the translation of this debt. Most of our international operations are transacted in US dollars or US 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 US dollars. These types of transactions and resulting foreign exchange exposure would not typically have a material impact on our financial results.

Liabilities from prior reorganizations

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

International operations

We conduct some of our business outside of Canada and the U.S., like Mexico and the Kingdom of Saudi Arabia. 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:

insurrection and geopolitical and other political risks

fluctuations in foreign currency and exchange controls

increases in duties, taxes and governmental royalties

renegotiation of contracts with governmental entities

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

If there is a dispute with our international operations, we may be under 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 2012 Annual Report		25


2012 Results

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

Summarized consolidated statements of earnings


Year ended December 31 (thousands of $ )	2012			2011			2010
Revenue:
Contract Drilling Services		1,725,240			1,632,037			1,186,007
Completion and Product Services		326,079			330,225			255,827
Inter-segment elimination		(10,578	)		(11,235	)		(12,181	)
		2,040,741			1,951,027			1,429,653
Adjusted EBITDA:
Contract Drilling Services		649,281			665,389			434,167
Completion and Product Services		93,554			104,252			66,443
Corporate and other		(72,043	)		(74,577	)		(65,702	)
		670,792			695,064			434,908
Depreciation and amortization		307,525			251,483			210,103
Loss on asset decommissioning		192,469			114,893			–
Operating earnings		170,798			328,688			224,805
Impairment of goodwill		52,539			–			–
Foreign exchange		3,753			(23,674	)		(12,712	)
Finance charges		86,829			111,578			211,327
Earning before income taxes		27,677			240,784			26,190
Income taxes		(24,683	)		47,307			(17,345	)
Net earnings		52,360			193,477			43,535
Results by geographic segment
Year ended December 31 (thousands of $ )	2012			2011			2010
Revenue
Canada		1,053,966			1,071,526			772,332
United States		936,113			866,776			634,885
International		64,017			22,994			27,239
Inter-segment elimination		(13,355	)		(10,269	)		(4,803	)
		2,040,741			1,951,027			1,429,653
Total assets
Canada		2,119,891			2,252,084			1,720,785
United States		1,913,810			2,027,676			1,789,441
International		266,562			148,114			54,314
		4,300,263			4,427,874			3,564,540


26		Management’s Discussion and Analysis

2012 compared to 2011

Net earnings this year were $52 million or $0.18 per diluted share, compared to $193 million or $0.67 per diluted share in 2011. Revenue this year was $2,041 million, or 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, as previously disclosed.

Adjusted EBITDA this year was $671 million, or 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.

Average oil and natural gas prices

2012

2011

2010

Oil

West Texas Intermediate (per barrel)

US $94.13

US $95.02

US $79.38

Natural gas

Canada

AECO (per MMBtu)

$2.39

$3.62

$4.00

United States

Henry Hub (per MMBtu)

US $2.75

US $3.98

US $4.37

Key statistics

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

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 by 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.

Fleet

We and the land drilling industry are in the process of upgrading the drilling rig fleet by building new rigs and upgrading existing ones. 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 are exiting the Tier 3 contract drilling business but will retain 26 drilling rigs for seasonal, stratification and turnkey drilling work. These will be categorized as “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. We recognized a $53 million goodwill impairment charge this year (the goodwill attributable to our Canadian directional drilling operations), because of the outlook for natural gas pricing, and the fact that natural gas drilling in Canada is down.

Foreign exchange

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


		Precision Drilling Corporation 2012 Annual Report		27

Finance charges

Finance charges were $87 million, or $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 2011 year mainly because operating results were lower and income tax was taxed at lower rates.

2011 compared to 2010

Net earnings in 2011 were $193 million or $0.67 per diluted share, compared to $44 million or $0.15 per diluted share in 2010. Revenue in 2011 was $1,951 million compared to $1,430 million in 2010. Net earnings and net earnings per diluted share include the impact of charges associated with asset decommissioning, as previously disclosed.

Adjusted EBITDA in 2011 was $695 million, or 60% higher than the $435 million in 2010 because of improved pricing and margins, and higher activity levels in both operating segments. Activity, as measured by utilization days, increased 22% in Canada and 17% in the U.S. compared to 2010.

Higher oil and natural gas liquids prices increased utilization in 2011 for us and for the industry in general.

Key statistics

There were 11,832 wells drilled in western Canada in 2011, or 1% less than the 11,936 drilled in 2010. Approximately 37,800 wells were started onshore in the U.S. in 2011, or approximately 13% more than the approximately 33,500 wells started there in 2010.

In Canada, total industry drilling operating days, at 144,646, were 21% higher than 2010. Average industry drilling operating days per well was 12.2 compared to 10.0 in 2010. The increase in days per well reflects the increase in horizontal drilling. Wells drilled horizontally typically have a longer drilling distance and take longer to drill.

Foreign exchange

We recognized a foreign exchange gain of $24 million in 2011 compared to a $13 million gain in 2010. The gain in 2011 resulted from the strengthening of the Canadian dollar against the U.S. dollar, and the effect that had on the net U.S. dollar denominated monetary position in our Canadian dollar-based companies. We designated our U.S. dollar debt as a hedge of our U.S. denominated operations on November 17, 2010 and July 26, 2011.

Finance charges

Finance charges were $112 million in 2011, or $100 million lower than 2010. In 2010, we incurred a $116 million loss on settlement of a debt, and debt amortization costs were higher. These were offset by a $27 million make-whole premium we paid in 2011 from the refinancing of $175 million 10% senior unsecured notes, and the interest expense associated with Canadian income tax settlements.

Income taxes

In 2011 income taxes were $65 million higher than 2010 mainly because earnings before income taxes were higher, and we recorded $11 million in income taxes in 2011 that related to a prior year.


28		Management’s Discussion and Analysis

CONTRACT DRILLING SERVICES

Financial results

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


Year ended December 31 (thousands of $, except where noted)	2012		% of revenue		2011		% of revenue		2010		% of revenue
Revenue		1,725,240				1,632,037				1,186,007
Expenses
Operating		1,036,553		60.1		931,062		57.0		720,347		60.7
General and administrative		39,406		2.3		35,586		2.2		31,493		2.7
Adjusted EBITDA		649,281		37.6		665,389		40.8		434,167		36.6
Depreciation and amortization		271,993		15.8		219,194		13.4		177,516		15.0
Loss on asset decommissioning		192,469		11.1		113,366		7.0		–		–
Operating earnings		184,819		10.7		332,829		20.4		256,651		21.6

2012 compared to 2011

Revenue from Contract Drilling Services was $1,725 million this year, or 6% higher than 2011, mainly because drilling rig revenue per day increased in both Canada and the U.S., and we realized growth in our international and directional drilling operations. These were partially offset by lower utilization days in North America.

Operating expenses were 60% of revenue this year compared to 57% in 2011, mainly because labour related costs and costs associated with international and directional drilling activity were higher. Operating expenses per day were 10% higher in Canada and 12% higher in the U.S. mainly because of higher crew labour related costs. General and administrative expense was higher because of the growth in our international business.

Operating earnings were $185 million this year, or 44% lower than 2011, and 11% of revenue compared to 20% in 2011. Included in 2012 is a loss on asset decommissioning charge of $192 million related to the decommissioning of 52 drilling rigs in the fourth quarter. In the fourth quarter of 2011, we recorded an impairment charge of $113 million related to the decommissioning of 36 drilling rigs.

Capital expenditures in 2012 were $751 million:

$513 million – to expand the underlying asset base

$130 million – to upgrade existing equipment

$108 million – spending on maintenance and infrastructure capital.

Most of the expansion capital was on 38 new build rigs, as part of our rig build program. 36 of these were completed and placed into service by December 31, 2012.

Canadian Drilling

Revenue from Canadian Drilling was lower by $20 million or 3% when compared to 2011. Drilling rig activity, as measured by utilization days, was down 15%.

10,753 wells were drilled in Canada in 2012, or 9% fewer than in 2011. Industry operating days decreased 14% to 124,319. These were the result of lower activity as customer demand for oil and liquids-rich natural gas related drilling activity declined.

Adjusted EBITDA was $332 million, in line with 2011 of $329 million, as a decrease in industry activity was offset by higher pricing.

Depreciation expense for the year was $9 million higher than 2011 because utilization of our Tier 1 rigs was higher, depreciation on our Tier 3 rigs increased and a loss on sale of assets was recognized.


		Precision Drilling Corporation 2012 Annual Report		29

United States Drilling

Revenue from United States Drilling was US$820 million or 1% less than 2011. Drilling rig activity, as measured by utilization days, was down 9%.

Average dayrates in the United States increased 9% this year because we had a higher percentage of drilling rigs working under term contracts, Tier 1 and upgraded rigs were added to the fleet and we experienced increased turnkey activity.

Adjusted EBITDA was US$308 million, or 5% lower than US$325 million in 2011, mainly because industry activity was lower due to depressed natural gas economics.

Depreciation expense for the year was $32 million higher than 2011 because utilization of our Tier 1 rigs was higher, increased depreciation on our Tier 3 rigs and recognition of a loss on sale of assets.

Operating statistics


Year ended December 31	2012		% increase/ (decrease)		2011		% increase/ (decrease)		2010		% increase/ (decrease)
Number of drilling rigs (year end)		321		(4.7)		337		(5.1)		355		0.9
Drilling utilization days (operating and moving)
Canada		32,352		(14.8)		37,970		21.8		31,176		46.9
United States		34,597		(8.7)		37,887		16.8		32,450		43.1
International		2,086		197.2		702		16.6		602		(15.2)
Drilling revenue per utilization day
Canada (Cdn$)		21,030		14.0		18,442		14.3		16,139		(9.5)
United States (US$)		23,696		9.0		21,744		14.7		18,965		(17.4)
Drilling statistics (Canadian operations only)
Wells drilled		3,085		(13.5)		3,566		11.6		3,196		45.4
Average days per well		9.4		(1.1)		9.5		8.0		8.8		2.3
Metres drilled (hundreds)		5,233		(8.5)		5,717		11.7		5,119		54.4
Average metres per well		1,696		5.8		1,603		0.0		1,602		6.2

Drilling statistics – Canada

This year we decommissioned 22 rigs and completed 20 new builds, bringing our Canadian 2012 year end net rig count to 186 (down by 2).

The industry drilling rig fleet increased slightly – there were approximately 822 rigs at the end of 2012 compared to 805 at the end of 2011. Our operating day utilization was 40% (six percentage points lower than 2011), compared to industry utilization, which was 42% (seven percentage points lower than 2011).

Our average dayrates in Canada increased by 14% this year because we had a better rig mix and demand for our Tier 1 rigs was strong.

Drilling statistics – US

This year we decommissioned 30 rigs, completed 16 new builds and transferred two rigs to our Mexican fleet, bringing our U.S. 2012 year end net rig count to 127 (down by 16). We averaged 95 rigs working, a 9% decrease over 2011.


30		Management’s Discussion and Analysis

Drilling statistics (lower 48 operations only)


	2012				2011
	Precision		Industry¹		Precision		Industry¹
Average number of active land rigs for quarters ended:
March 31		104		1,947		100		1,695
June 30		97		1,924		102		1,803
September 30		90		1,855		106		1,915
December 31		87		1,759		107		1,972
Year to date average		95		1,871		104		1,846

¹Source: Baker Hughes

COMPLETION AND PRODUCTION SERVICES

Financial results

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


Year ended December 31 (thousands of $, except where noted)	2012		% of revenue		2011		% of revenue		2010		% of revenue
Revenue		326,079				330,225				255,827
Expenses
Operating		217,326		66.7		211,195		64.0		178,585		69.8
General and administrative		15,199		4.7		14,778		4.5		10,799		4.2
Adjusted EBITDA		93,554		28.7		104,252		31.6		66,443		26.0
Depreciation and amortization		30,758		9.4		25,598		7.8		24,128		9.4
Loss on asset decommissioning		–		–		1,527		0.5		–		–
Operating earnings		62,796		19.3		77,127		23.4		42,315		16.5

Revenue from Completion and Production Services was $326 million this year, or 1% lower than 2011, mainly because industry activity was lower as customers reduced their spending on production activity as natural gas prices remained relatively low. Reduced activity was partially offset by improved pricing for our services and expansion of our services into the U.S.

Operating earnings were $62,796 this year, or 19% lower than 2011, and 19% of revenue compared to 23% in 2011, because service rig activity was down, and rental equipment and base camps saw less activity.

Operating expenses were 67% of revenue this year, or three percentage points higher than 2011, mainly because equipment utilization was down, 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 $5 million higher than 2011 mainly because of depreciation on equipment purchases in 2011 and 2012.

Capital expenditures were $109 million:

$83 million – to expand the underlying asset base

$26 million – spending on maintenance and infrastructure capital.

Revenue from Precision Well Servicing was $220 million, or 1% lower than 2011, because operating activity was down by 9%. This decline in activity was partially offset by a higher revenue rate per hour.


		Precision Drilling Corporation 2012 Annual Report		31

Revenue from Precision Rentals was $53 million, or 7% lower than 2011. 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 include power generation equipment, solids control equipment and WaterDams (containment rings). The expansion increased the overall rental rate compared to 2011.

Revenue from LRG Camp and Catering was $32 million, or 24% lower than 2011 because there were fewer base camp days this year. LRG operated three base camps and 50 drill camps during 2012.

Operating results


Year ended December 31	2012		% increase/ (decrease)		2011		% increase/ (decrease)		2010		% increase/ (decrease)
Number of drilling rigs (end of year)¹		214		3.4		207		(5.9)		220		–
Service rig operating hours²		294,681		(7.2)		317,418		7.9		294,126		33.9
Revenue per operating hour²		744		8.1		688		8.0		637		(3.8)

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.

This year we added three coil tubing units in Canada and two in the U.S. Equipment was moved from Canada to the U.S. as we continue to build on our footprint.

This year our service rig hours decreased 7% as market activity declines was partially offset by our U.S. expansion.

Service rig rates increased 8% due to crew wage increased pass through to customers and the provision of higher end services.

This year in Completion and Production Services, we moved five service rigs and two snubbing rigs from Canada to the U.S. and added two new build coil tubing rigs and rental equipment to develop our U.S. business.

CORPORATE AND OTHER

Financial results

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


Year ended December 31 (thousands of $)	2012			2011			2010
Revenue		–			–			–
Expenses
Operating		–			–			–
General and administrative		72,043			74,577			65,702
Adjusted EBITDA		(72,043	)		(74,577	)		(65,702	)
Depreciation and amortization		4,774			6,691			8,459
Operating earnings (loss)		(76,817	)		(81,268	)		(74,161	)

We view our corporate segment as support functions that provide assistance to more than one segment. It includes costs incurred in corporate groups in both Canada and the U.S.

Corporate and other expenses were $72 million in 2012, or $3 million less than 2011, mainly related to performance based incentive plans. In 2012 corporate general and administrative costs were 3.5% of consolidated revenue compared to 3.8% in 2011 and 4.6% in 2010.


32		Management’s Discussion and Analysis

QUARTERLY FINANCIAL RESULTS

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

2012 – quarters ended

(thousands of $, except per share amounts)

March 31

June 30

September 30

December 31

Revenue

640,066

381,966

484,761

533,948

Adjusted EBITDA

245,574

97,192

151,000

177,026

Net earnings (loss)

111,081

18,261

39,357

(116,339

)

Per basic share

0.40

0.07

0.14

(0.42

)

Per diluted share

0.39

0.06

0.14

(0.42

)

Funds provided by operations

247,739

62,373

146,124

142,576

Cash provided by operations

162,440

275,346

61,183

136,317

Dividends per share

–

0.05

2011 – quarters ended

(thousands of $, except per share amounts)

March 31

June 30

September 30

December 31

Revenue

525,350

345,325

492,944

587,408

Adjusted EBITDA

186,411

92,566

186,248

229,839

Net earnings

65,560

16,403

83,468

28,046

Per basic share

0.24

0.06

0.30

0.10

Per diluted share

0.23

0.06

0.29

0.10

Funds provided by operations

192,337

70,766

73,182

256,103

Cash provided by operations

117,322

176,312

20,281

218,857

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 requirements for working capital. Activity in the U.S. does not have the same seasonality.

We had a net loss in the fourth quarter of $116 million or $0.42 per diluted share, compared to net earnings of $28 million in the fourth quarter of 2011. This reflects the impact of charges associated with asset decommissioning and a goodwill impairment which, combined, reduced net earnings by $179 million and net earnings per diluted share by $0.63 compared to the fourth quarter of 2011.

Revenue and Adjusted EBITDA were both lower in the fourth quarter compared to the fourth quarter of 2011: revenue was $534 million compared to $587 million in the fourth quarter of 2011; Adjusted EBITDA was $177 million compared to $230 million in the fourth quarter of 2011. These results were mainly because of lower activity across most business lines and higher operating costs, partially offset by higher pricing.

Our Adjusted EBITDA margin was 33% this quarter, compared to 39% in the fourth quarter of 2011. The decrease in Adjusted EBITDA margin was mainly due to higher average costs and lower equipment utilization in both Canada and the U.S.

Operating costs were higher because of labour related costs and higher operating costs internationally. 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.

Drilling rig utilization days (drilling days plus move days) in Canada were 8,242 this quarter, or 23% lower than the fourth quarter of 2011. Drilling rig utilization days in the U.S. were 8,014 this quarter, or 19% lower than the fourth quarter of 2011. This was the result of lower customer demand as customers conserved cash and deferred drilling programs into 2013.


		Precision Drilling Corporation 2012 Annual Report		33

The majority of activity was from oil and liquids-rich natural gas related plays. We averaged a total of 185 rigs working in the quarter (average 90 in Canada, 87 in the U.S. and eight internationally), compared to a total average 182 rigs in the third quarter of 2012 and 225 rigs in the fourth quarter of 2011.

Service rig activity in the fourth quarter was 12% lower than the fourth quarter of 2011 (77,234 operating hours compared to 88,131 hours in the fourth quarter of 2011).

Contract Drilling Services

Revenue and Adjusted EBITDA from Contract Drilling Services were both down in the fourth quarter compared to the fourth quarter of 2011: revenue was $452 million, or 9% lower than the fourth quarter of 2011; Adjusted EBITDA was $172 million, or 21% lower than the fourth quarter of 2011. These results were mainly because of lower drilling rig activity, partially offset by higher average rates per day in Canada and the U.S. and higher revenue from our international contract drilling operations.

Customer demand for oil and liquids-rich natural gas related drilling activity was down in the fourth quarter because oil prices were down. Drilling rig revenue per utilization day in both Canada and the U.S. was up 10% over 2011. The increase in average dayrates for Canada was the result of improved rig mix and solid demand for Tier 1 assets. In the United States the majority of the increase was driven by higher turnkey activity.

In Canada, 41% of utilization days in the fourth quarter were generated from rigs under term contract, compared to 38% in the fourth quarter of 2011. In the U.S., 68% of utilization days were generated from rigs under term contract as compared to 79% in the fourth quarter of 2011. At the end of the quarter, we had 55 drilling rigs working under term contracts in Canada and 54 in the U.S.

Operating costs were 60% of revenue for the quarter, or six percentage points higher than the fourth quarter of 2011 because costs were higher internationally, labour related costs were higher and activity was lower, so fixed costs were spread over a lower revenue base. Operating costs per day in Canada were higher than the fourth quarter of 2011 mainly because crew wage expenses were higher. Operating costs per day in the United States were higher than in the fourth quarter of 2011 mainly because of higher proportionate turnkey activity as well as higher labour related and overall operating costs. Labour rate increases are typically recovered through higher dayrates.

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. Quarterly depreciation increased 25% over the fourth quarter of 2011. As discussed in our MD&A dated December 31, 2011, we changed our depreciation policy on certain Tier 3 rigs from the unit of production method to straight-line over four years, which increased depreciation by approximately $5 million in the fourth quarter of 2012. Higher utilization of our Tier 1 rigs, losses on asset disposals and depreciation from the growth in directional drilling and international contract drilling have also increased depreciation.

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

Completion and Production Services

Revenue and Adjusted EBITDA from Completion and Production Services were both down compared to the fourth quarter of 2011: revenue was $85 million or 11% lower than the fourth quarter of 2011; Adjusted EBITDA was $22 million or 34% lower than the fourth quarter of 2011. These results are mainly because customers reduced spending in response to greater economic uncertainty, which reduced activity across all service lines.

Well servicing activity in the fourth quarter was 12% lower than the fourth quarter of 2011 (77,234 operating hours and utilization of 39%, compared to 88,131 hours and utilization of 43%). Results were down because of reduced completion and production work on oil wells. Approximately 95% of the fourth quarter service rig activity was oil related. Our rental division activity in the fourth quarter was 38% lower than the fourth quarter of 2011 mainly because completion and frac-related activity was down industry-wide, offset by new equipment added to the fleet.


34		Management’s Discussion and Analysis

Average service rig revenue in the fourth quarter was $740, or $9 per operating hour higher than the fourth quarter of 2011 because our coil tubing operations, which operate at higher rates, started in 2012.

Operating costs as a percentage of revenue increased to 70% in the fourth quarter of 2012, from 61% in the fourth quarter of 2011. Operating costs per service rig operating hour were higher than in the fourth quarter of 2011 mainly because fuel costs were higher, and because of the new coil tubing operations.

Depreciation in the fourth quarter of 2012 was 33% higher than the fourth quarter of 2011 because depreciation expense per unit associated with new equipment was higher, and we incurred losses on asset disposals. We use the straight-line method of calculating depreciation for our completion and production lines, except for the well servicing division, where we use the unit of production method.

Consolidated

General and administrative expenses were $30 million in the fourth quarter, or $6 million lower than the fourth quarter of 2011 because of lower costs associated with declines in activity, combined with lower incentive compensation costs tied to the price of our common shares.

Net finance charges were $22 million in the fourth quarter, or $3 million higher than the fourth quarter of 2011 mainly because of a non-recurring items in 2011.

Capital expenditures were $187 million in the fourth quarter, compared to $328 million in the fourth quarter of 2011. Spending in the fourth quarter of 2012 included:

$123 million – to expand the underlying asset base

$23 million – to upgrade existing equipment

$41 million – spending on maintenance and infrastructure capital.


		Precision Drilling Corporation 2012 Annual Report		35


Financial Condition

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 flow, 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 variable cost structure so we can be responsive to changing competition and demand. And we invest in our fleet to make sure we remain competitive.

Term contracts provide more certainty of future revenues and return of capital on our investments.

Liquidity

As at December 31, 2012 our liquidity is supported by a cash balance of $153 million, a senior secured credit facility of US$850 million, operating facilities totaling approximately $55 million and a $25 million secured facility for letters of credit.

At December 31, 2012, we had approximately $1,290 million (2011 – $1,268 million) outstanding under our secured and unsecured credit facilities. Our secured facility includes financial ratio covenants that are tested quarterly. We’re compliant with these covenants and expect to remain compliant.

We ended 2012 with a long-term debt to long-term debt plus equity ratio of 0.36 (compared to 0.37 in 2011) and a ratio of long-term debt to cash provided by operations of 1.92 (compared to 2.33 in 2011).

The current blended cash interest cost of our debt is about 6.6%.

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 link our executives’ incentive compensation to the returns we generate, compared to our peers.


36		Management’s Discussion and Analysis


Financial position and ratios
(in thousands of $, except ratios)	December 31, 2012		December 31, 2011		December 31, 2010
Working capital (includes current portion of long-term debt)		278,021		610,429		458,003
Working capital ratio		1.7		2.4		3.1
Long-term debt		1,218,796		1,239,616		804,494
Total long-term financial liabilities		1,245,290		1,267,040		834,813
Total assets		4,300,263		4,427,874		3,564,540
Enterprise value		3,213,406		3,528,046		2,993,083
(share price x number of shares outstanding + long-term debt
– working capital – see page 40)
Long-term debt to long-term debt plus equity		0.36		0.37		0.29
Long-term debt to cash provided by operations		1.92		2.33		2.63
Long-term debt to Adjusted EBITDA		1.82		1.78		1.85
Long-term debt to enterprise value		0.38		0.35		0.27

Credit rating

Credit ratings affect our ability to obtain short and long-term financing, the cost of this financing, and our ability to engage in certain business activities cost-effectively.


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

CAPITAL MANAGEMENT

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

We base our maintenance capital decisions on actual activity levels, using key financial indicators that we express on a per operating day or per operating hour basis. 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 US dollars and currencies that are pegged to the US dollar). That 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 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 2012 Annual Report		37


SOURCES AND USES OF CASH
At December 31 (thousands of $)	2012		2011
Cash from operations		635,286		532,772
Cash used in investing		(930,121)		(715,462)
Surplus (deficit)		(294,835)		(182,690)
Cash from (used in) financing		(14,899)		366,887
Effect of exchange rate changes on cash		(4,974)		26,448
Net cash generated (used)		(314,708)		210,645

Cash from operations

In 2012, we generated cash from operations of $635 million (compared to $533 million in 2011).

Investing activity

We made capital investments of $868 million in 2012:

$596 million in expansion capital expenditures

$130 million in upgrade capital expenditures

$142 million in maintenance and infrastructure capital expenditures.

Of the $868 million in capital expenditures in 2012, $751 was for the Contract Drilling segment, $109 million for the Completion and Production segment and $8 million for the Corporate and other segment.

Expansion and upgrade capital includes the cost of long lead items purchased for our capital inventory, like 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

With the exception of foreign exchange translation, our net borrowings in 2012 were the same as in 2011 (2011 increased by $407 million over 2010).

Our senior secured facility was increased from US$550 million to US$850 million effective August 30, 2012, and the US$100 million “accordion” feature was increased to US$250 million, allowing the facility to be increased to US$1.1 billion with additional lender commitments. The term was extended to five years and several negative covenants were relaxed.

Our operating facility was increased from $25 million to $40 million effective August 30, 2012, and remains undrawn except for $19 million in outstanding letters of credit. Our operating facility of US$15 million remains undrawn as at December 31, 2012. Effective September 27, 2012, we entered into a new US$25 million demand facility for letters of credit and it remained undrawn as at December 31, 2012.


38		Management’s Discussion and Analysis

Debt

At December 31, 2012, we had approximately $925 million in secured and operating credit facilities, and $1,245 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)

Undrawn, except US$27 million in outstanding letters of credit

General corporate purposes

November 17, 2017

Operating facilities (secured)

$40 million

Undrawn, except $19 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

Letters of credit

Senior notes (unsecured)

$200 million

Fully drawn

Debt repayment

March 15, 2019

US$650 million

Fully drawn

Debt repayment and general corporate purposes

November 15, 2020

US$400 million

Fully drawn

Capital expenditures and general corporate purposes

December 15, 2021

Contractual obligations

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

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


	Payments due (by period)
At December 31, 2012 (thousands of $)		Less than 1 year		1-3 years		4-5 years		More than 5 years		Total
Long-term			–		–		–		1,244,645		1,244,645
Interest on long-term debt			81,710		163,421		163,421		241,273		649,825
Rig construction			68,120		36,443		–		–		104,563
Operating leases			15,561		25,389		16,509		23,161		80,620
Contractual incentive plans¹			16,260		18,622		–		–		34,882
Contingent purchase consideration			52,915		–		–		–		52,915
Total			234,566		243,875		179,930		1,509,079		2,167,450

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 $8.22 at December 31, 2012.


		Precision Drilling Corporation 2012 Annual Report		39

CAPITAL STRUCTURE

Shares outstanding


	March 8, 2013		December 31, 2012		December 31, 2011		December 31, 2010
Shares outstanding		276,502,155		276,475,770		276,081,797		275,686,676
Deferred shares outstanding		335,946		335,946		417,495		393,717
Warrants outstanding		15,000,000		15,000,000		15,000,000		15,000,000
Share options outstanding		8,593,251		6,413,777		5,154,123		3,723,123

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

Common shares

Our articles of amalgamation allow us to issue an unlimited number of common shares. As of December 2012, we issue an annual dividend paid to our shareholders quarterly.

Warrants

On April 22, 2009, we issued 15,000,000 purchase warrants under a private placement. Each warrant can be exercised for one common share at a price of $3.22 per common share for five years from the date of issue. No warrants have been exercised as at December 31, 2012.

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 don’t currently have any preferred shares issued.

Enterprise value


(in thousands of $, except shares outstanding and per share amounts)	December 31, 2012		December 31, 2011		December 31, 2010
Shares outstanding		276,475,770		276,081,797		275,686,676
Year-end share price on the TSX		8.22		10.50		9.60
Shares at market		2,272,631		2,898,859		2,646,592
Long-term debt		1,218,796		1,239,616		804,494
Less working capital		(278,021)		(610,429)		(458,003)
Enterprise value		3,213,406		3,528,046		2,993,083


40		Management’s Discussion and Analysis


Critical Accounting Estimates

Because of the nature of our business, we are required to make estimates about the future that affect the amount of assets, liabilities, revenues and expenses we report. 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:

allowance for doubtful accounts receivable

impairment of long-lived assets

depreciation and amortization

income taxes.

Allowance for doubtful accounts receivable

We evaluate the creditworthiness of our customers on an ongoing basis and grant credit based on the customer’s past payment history, financial condition and expected conditions in the industry. We monitor customer payments regularly and include a provision for doubtful accounts based on industry conditions and the state of specific accounts. If we have concerns about a customer’s creditworthiness, we may require cash or a letter of credit or deposit before we provide services, or we may choose not to provide services.

Bad debt losses to date have been within expected limits and generally related to specific customer circumstances, but our customers’ ability to fulfill their payment obligations to us may change suddenly and without notice. The cyclical nature of the oil and gas industry, continuing uncertainty in debt and equity markets, and the risk that a customer may not be successful in finding the oil and gas reserves they’re looking for can all affect their ability to pay us as expected.

Impairment of long-lived assets

Long-lived assets (property, plant and equipment, intangibles and goodwill) make up the majority of our assets. We review the carrying value of these assets for impairment periodically or whenever events or changes in circumstances suggest that we may not be able to recover the carrying amounts of these assets.

For property, plant and equipment, we estimate the future cash flows we would gain from using these assets based on assumptions about future business conditions and developments in technology. These assumptions may change.


		Precision Drilling Corporation 2012 Annual Report		41

A cash generating unit (CGU) is the smallest identifiable group of assets that generates cash independently of inflows from other assets or groups. We use judgment to aggregate assets into cash generating units and allocate goodwill to them. To test goodwill for impairment, we calculate the recoverable amount of the CGU or groups of CGUs the goodwill has been allocated to. This involves estimating future cash flows and applying an appropriate discount rate.

We assessed the carrying value of our long-lived assets for impairment in 2012 and 2011 and concluded:

the goodwill associated with Canada directional drilling was impaired

certain of our drilling rigs were obsolete and would be removed from our operating fleet.

Depreciation and amortization

We depreciate and amortize our property, plant and equipment and intangible assets based on estimates we make about their useful lives and salvage value. We base these estimates on data and information from different sources, including vendors, our own historical experience and industry practice. Our estimates may change based on market conditions, future experience or changes technology.

We assign independent values to costly parts of our drilling rig equipment and depreciate and amortize these parts separately (called componentization). We use our judgment to decide which parts of a rig represent a significant cost relative to the entire item, and to assess whether different components have similar consumption patterns and useful lives.

Income taxes

Deferred tax assets and liabilities represent temporary differences between the carrying amounts of our assets and liabilities (as shown in our financial statements) and their tax bases. They reflect our estimates and assumptions about when the differences will be reversed, what the effect on our balance sheet will be and what future tax rates will be applied to the reversals.

We have tax benefits from previous transactions that we expect to be able to use to reduce our income taxes in the future. If our future cash flows and taxable income differ significantly from what we’ve estimated, or if tax laws in the jurisdictions where we operate change, amounts we’ve recorded as deferred taxes on our balance sheet could change.

Interpreting complex tax regulations, changes in tax laws, and the amount and timing of future taxable income is challenging and uncertain. If actual results are different from our assumptions (or our assumptions change) we may need to adjust the income and expenses we’ve recorded related to taxes. We make provisions for the possible consequences of future tax audits using reasonable estimates. We base the amount of these provisions on our past experience with tax audits and differences in interpreting tax regulations in the countries where we operate. See Note 24 to our consolidated financial statements.


42		Management’s Discussion and Analysis

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports we file with (or submit to) securities regulatory authorities are recorded, processed, summarized and reported within the time periods specified by Canadian and U.S. securities laws. This includes gathering information and communicating it to management (including the President and Chief Executive Officer and the Chief Financial Officer) to allow them to make timely decisions about required disclosure.

We evaluated the effectiveness of our disclosure controls and procedures (as defined under the rules adopted by the Canadian securities regulatory authorities and by the United States Securities and Exchange Commission) as of December 31, 2012.

Management (including the President and Chief Executive Officer and Chief Financial Officer) supervised and participated in the evaluation and concluded that the design and operation of our disclosure controls and procedures were effective as of that date. However, control systems can only provide reasonable, not absolute, assurance that information will be timely, complete and accurate, and we cannot guarantee that errors and fraud will not occur.

During the fourth quarter of 2012, there were no changes in internal control over financial reporting that materially affected (or are reasonably likely to materially affect) our internal control over financial reporting.

Corporate Governance

At Precision, we believe that a strong culture of corporate governance and ethical behavior 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.

William T. Donovan, B.Sc., MBA

Brian J. Gibson, MBA, CFA, ICD.D (Institute of Corporate Directors)

Robert J. S. Gibson, ICD.D (Institute of Corporate Directors)

Allen R. Hagerman, FCA, B. Comm, MBA, CF (Canadian Institute of Chartered Accountants),

ICD.D (Institute of Corporate Directors)

Stephen J. J. Letwin, B.Sc, MBA, CGA

Kevin O. Meyers, Ph.D. (chemical engineering), B.A.

Patrick M. Murray, B.Sc. (Accounting), MBA

Kevin A. Neveu, B.Sc, P.Eng

Robert L. Phillips, B.Sc. (chemical engineering), LLB


		Precision Drilling Corporation 2012 Annual Report		43