2008 Analyst Day - library.corporate-ir.netlibrary.corporate-ir.net/library/78/789/78965/items/282039/KEG... · Readers should also refer to the section entitled “Risk Factors”

2008 Analyst Day

Windsor Court HotelNew Orleans, LA

March 3, 2008

2

Agenda

Session One

WelcomeAl PetrieAl Petrie Investor + Media Relations, LLC

Company ReviewDick AlarioChairman & CEO

TechnologyDon WeinheimerSenior Vice President, Technology & Planning

InternationalBoris CuraVice President - International, Western Hemisphere

Trey WilsonSenior Vice President, General Counsel

Session Two

Performance ManagementTommy MurphyVice President, Performance Management

Business DevelopmentTommy PipesVice President, Business Development

Financial Review & 2008 OutlookBill AustinSenior Vice President, Chief Financial Officer

Concluding RemarksDick AlarioChairman & CEO

Q&A Session

Management team

3

Safe Harbor Language

Certain statements contained in this news release constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on current expectations, estimates and projections about the Company, the Company’s industry, management’s beliefs and certain assumptions made by management. Whenever possible, the Company has identified these “forward-looking statements” by words such as “expects,” “believes,” “anticipates” and similar phrases. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and are subject to certain risks, uncertainties and assumptions that are difficult to predict, including, but not limited to: risks that the Company will be unable to complete its capital investment plan, including that it will be unable to identify or complete acquisitions and that it will be unable to integrate acquired operations; risks affecting the ability of the Company to maintain or improve operations, including the ability to maintain price increases, the impact of new rigs coming into the market and weather risk; and risks that the Company will be unable to achieve budgeted financial targets or cost reductions; the impact of changes of interest rates on the Company’s interest expense; factors affecting the Company's stock repurchase program, including, among others, the market price of the company's stock prevailing from time to time, the nature of other investment opportunities presented to the company from time to time, the company's cash flows from operations, and general economic conditions; and risks affecting activity levels for rig hours including the risk that commodity prices decline or the risk that capital budgets from the Company's customers decrease. Readers should also refer to the section entitled “Risk Factors” in the 2007 Annual Report on Form 10-K filed February 29, 2008 for a discussion of risks to which the Company is subject. Because such statements involve risks and uncertainties, the actual results and performance of the Company may differ materially from the results expressed or implied by such forward-looking statements. Given these uncertainties, readers are cautioned not to place undue reliance on such forward-looking statements. Unless otherwise required by law, the Company also disclaims any obligation to update its view of any such risks or uncertainties or to announce publicly the result of any revisions to the forward-looking statements made here; however, readers should review carefully reports or documents the Company files periodically with the Securities and Exchange Commission

2008 Analyst Day

Company Overview

Dick AlarioChairman and CEO

March 3, 2008

5

Goals Today…………

Provide company update

Review strategic initiatives

Provide 2008 guidance

6

2008 Objectives

7

U.S. Competitive Landscape

Key Energy ServicesWell

ServicesPressure Pumping

Fishing & Rental

Electric Wireline

Baker Hughes

Basic Energy Services

Complete Production Services

Halliburton

Nabors Industries

RPC Inc.

Schlumberger

Smith International

Superior Energy Services

Weatherford International

8

Blue Chip Customer Base

9

Blue Chip Customer Base

CVX7.4%

OXY6.5%

EOG4.5%

COP4.3%

AERA4.1%

XTO3.4%

KWK3.3%

PXD2.8%

XOM2.4%

Other57.9%

CHK3.4%

3.3%Quicksilver Resources

3.4%Chesapeake Energy

3.4%XTO Energy

4.1%AERA Energy

4.3%Conoco

2.8%Pioneer Natural Resources

42.1%Top 10 U.S. Customers

2.4% Exxon

4.5%EOG Resources

6.5% Occidental Petroleum

7.4% Chevron

Top 10U.S. Customers

Domestic sales by customer during 2007

10

Positive Market Outlook

Robust commodity prices

– E&P companies expected to spend more than in 2007

Positive January permit data

– Drilling activity should improve this summer

Service companies reducing capital expenditures

– Growth of equipment supply moderating

60% oil vs. 40% natural gas exposure– Oil markets strong

– Natural gas markets improving

NOC’s increasing reliance on service companies

11

Operational Initiatives

Safety

Employee Turnover

Technology

International Growth

Performance Management

Business Development

Acquisitions

ROA

12

2000 2001 2002 2003 2004 2005 2006 2007 2008LTIR

6.53

5.55

4.264.02

2.152.49

2.92

3.47

3.97

1.42

0.90 0.85 0.750.320.440.50

0.761.16

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

LTIR TRIR/OSHA

Focused on Safety

Better Safety = Lower Costs

2007 Workers’ Compensation Costs Down ~$22 million

Objective

13

Employee Turnover Rates Improving

59.2%55.5%

50.7%

44.7%40.9% 39.0%

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

2003 2004 2005 2006 2007 2008

Lower Turnover Reduces Costs and Adds Consistency

Objective

Well Servicing Segment

15

Broad Service Offering

Largest rig-based service companyFluid transportation services Cased-hole electric wirelineWell service technologyContract drilling services

16

Segment Revenue By Product Line – 2007

67.0%2.0%

19.2%

1.8%

0.2%

9.8%

Well Service Rig

Contract Drilling

Fluid Services

Wireline

AMI

Ancilliary

2007 Segment Revenue: $1,264,797,000

17

Market Outlook

Well Service RigsNew capacity slowing

~250 net rigs added in 2007

~150 net rigs in 2008

– KEG: 0 new rigs

– NBR: ~50 new rigs

– BAS: ~25 new rigs

– CPX: ~12 new rigs

Pricing stabilizing

Consolidation underway

Fluid ServicesHigh return business

Often synergistic with rig services

Consolidation possible, but not a high priority

Activity stabilizing

Increased drilling could lead to increased hours

Capital discipline improving

(1) Rig count estimates are management’s estimate

(2) Estimates assume that some competitors sell retired rigs to the market; thereby, not reducing industry supply

18

Current Market Share for U.S. Well Service Rigs

26%

16%

11%6%3%

2%

36%

100Forbes Energy Services

60Wedge Well Service

3,600Total

1,329 Other

225 Complete Production Services

393Basic Energy Services

568 Nabors Industries

925 Key Energy Services

RigsMarketable

Key Energy

Nabors

Basic

Other

Com

plet

e

Source: Company estimates and publicly available information

Marketable rig defined as either active, available or idle

19

Composite Well Service Pricing

$150.0

$175.0

$200.0

$225.0

$250.0

$275.0

$300.0

$325.0

$350.0

$375.0

$400.0

$425.0

$450.0

2001

2002

2003

1Q04

2Q04

3Q04

4Q04

1Q05

2Q05

3Q05

4Q05

1Q06

2Q06

3Q06

4Q06

1Q07

2Q07

3Q07

4Q07

Rig Revenue Ancillary Revenue

Revenue Per Hour

2007 pricing improvements due to Moncla rig mix, increased Argentina rates and Mexico contract

Composite pricing includes well service rig and other well service revenue; including Argentina division; trucking and drilling revenue not included

20

Historical Trucking Activity

100,000

120,000

140,000

160,000

180,000

200,000

220,000

240,000

260,000

Jan-04

Mar-04

May-04

Jul-0

4Sep

-04Nov

-04Ja

n-05Mar-

05May

-05Ju

l-05

Sep-05

Nov-05

Jan-06

Mar-06

May-06

Jul-0

6Sep

-06Nov

-06Ja

n-07Mar-

07May

-07Ju

l-07

Sep-07

Nov-07

Jan-08

Monthly Trucking Hours

Activity stabilizing and expected to be supported by increased drilling

21

Organic Growth – Cased-Hole WirelineRevenue in millions Units at Quarter End

$3.3

$5.5

$6.5$7.0

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

$9.0

$10.0

1Q07 2Q07 3Q07 4Q070.0

5.0

10.0

15.0

20.0

25.0

Revenue Units28 units by end of 2008 - $40 million in revenue targeted

Pressure Pumping Services Segment

23

Pressure Pumping Services Segment Mid-Size U.S. provider

11 frac spreads located in four regionsPermian Basin, Mid-Continent, Four Corners and Barnett ShaleAbandonment operations in California70% natural gas, 30% oil

24

Market Outlook

Increased drilling and high decline rates should keep activity strong

New capacity still entering market

– Pricing pressures exist

– Several Key customers have agreed to lock-in pricing

Relocating assets to stronger markets

– Barnett Shale and Permian markets strong

– Four Corners soft due to harsh winter and new capacity

Cementing services growing

January results encouraging

– Segment revenue totaled ~$27 million

– Freight costs expected to decline

25

Pressure Pumping Revenue Revenue in millions

$18.1$22.7 $24.5 $26.0

$30.5

$36.2

$43.7

$51.8

$60.2

$69.0$66.5

$74.1$77.3 $77.1

$70.9

$41.9

$0.0

$10.0

$20.0

$30.0

$40.0

$50.0

$60.0

$70.0

$80.0

$90.0

1Q04 2Q04 3Q04 4Q04 1Q05 2Q05 3Q05 4Q05 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07 4Q07

Higher performance due to expanded fleet

26

Pressure Pumping Jobs

0

200

400

600

800

1,000

1,200

1,400


Frac Cement Acid Other

Performance driven by new equipment additions

Excludes well abandonment jobs performed in the California P&A business unit

Fishing & Rental Services Segment

28

Segment Overview

Synergistic to well servicing

24 locations throughout U.S.

Good presence in Gulf Coast and Permian Basin

Provides career path for our rig operators

29

Key Fishing and Rental Services

$18.7 $18.9$20.3 $20.6 $20.4 $20.0

$21.1

$23.2 $23.4$24.9

$25.9

$23.7$24.4

$25.6$24.2

$20.2

$0.0

$3.0

$6.0

$9.0

$12.0

$15.0

$18.0

$21.0

$24.0

$27.0

$30.0


Revenue in millions

30

Market Outlook

Targeting ~$110 million in revenue in 2008

Expanding rental fleet

– 2 foam air units to be delivered in 1Q08

– 2 work strings to be delivered in 4Q08

Pricing stable

Recent deep water awards open door to GOM

Expansion in the Southeastern U.S. planned

2008 Analyst Day

Technology

Don WeinheimerSenior Vice President – Business Development, Technology and Strategic Planning

March 3, 2008

32

KeyView® System

Patented Well Service Rig Technology which enables– process improvements

– operator skill enhancement

– improved safety

– higher job quality

– increased asset efficiency

33

KeyView® System

Rig Data Capture & ControlKeyView Portal

Customers can access Key Energy’s web site to monitor activity at their well site.

34

KeyView® System ControlHook Load Limiter protects people, rig and customer’s well

KeyView system intervenes in 1/50 of a sec, preventing possible

major incident.

KeyView system intervenes in 1/50 of a sec, preventing possible

major incident.

35

KeyView® System InformationJob Efficiency Saves 60% on Non-Production Time

5.6%

8.2%8.6%

5.9%

6.9% 6.7%

6.2%

4.6%4.1%

4.4%

2.3%

3.6%

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Hou

rs

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

% W

ait T

ime

On Task Non Production Time (NPT) Percent NPT

• Major Operator in West Texas• 4 Fields, 13 to 15 rigs working• 60% reduction in NPT 1H vs 2H• $320K estimated savings

• Major Operator in West Texas• 4 Fields, 13 to 15 rigs working• 60% reduction in NPT 1H vs 2H• $320K estimated savings

36

KeyView® System Safety

Permian Basin - 2006 & 2007Two years of recordable Incidences / Rig

0.17

0.37

Rigs w/o KeyView Rigs with KeyView

56% Lower

56% Lower

Note: Avg 145 rigs with KeyView® units and avg 159 rigs without KeyView® units

37

KeyView® System Preference

PEMEX direct award– 3 Key rigs with KeyView® system– 2 Pemex rigs with KeyView® system Keyview– More being deployed

Chevron U.S. Well Service– Jan 2006: 70 rigs working, 30 with KeyView® system– Jan 2007: 86 rigs working, 38 with KeyView® system

– Jan 2008: 122 rigs working, 45 with KeyView® system

38

KeyView® System Deployed

US Operations– Eastern Region

• 21 systems– Western Region

• 190 systemsMexico– Currently

• 3 Key rigs• 3 PEMEX rigs

– Near Future Total• 6 Key rigs• 5 PEMEX rigs

– Potential• 11 Key rigs• ~20 PEMEX rigs

39

Advanced Measurements (“AMI”)

Acquired in September 2007Calgary based technology firmStrong leadership with 65 technology professionals

40

Advanced Measurements

Advanced Measurements, Inc.– Control and data acquisition systems for

oilfield service equipment– Data and information collection, transfer

and reporting– Developed the original KeyView system

Advanced Flow Technology Inc.– Spin off company of AMI that

provides low cost wellsite gas flow monitoring products & service.

– With our purchase of AMI, we obtaineda majority interest in AFTI

41

Advanced Measurements

Enables Key with– KeyView® system

manufacturing

– Next generation KeyView®system development

– Digital well site development

– Equipment control and automation expertise

– Technology & product development skills

2008 Analyst Day

International

Boris CuraVice President - International, Western Hemisphere

Trey WilsonSenior Vice President, General Counsel

43

International

77% of the world’s oil reserves held by NOC’sInternational rig activity more dependent on oil marketsMature Oil Fields require more Well Service workEvaluating most major marketsPartnerships, JV’s or acquisitions may be a venue to gain quick access to other markets

44

Global Oil Demand Growth

Source : A Thousand Barrels A Second ..Peter TertzakianAdapted from: U.S. Energy Information Agency, the International Energy Agency, and ARC Financial

45

Major Proved Oil Reserves(In Billion of Barrels)

Canada17

US29.9

Mexico12.9

Venezuela80

Brazil12.2

Argentina2.0

Columbia1.5

Nigeria36.2

Algeria12.3

Saudi Arabia264

Russia79.4

Iran138

Iraq115

Kuwait102

Oman5.6

Libya42

Kazakhstan40

China16

Qatar15

Egypt3.7

UAE98

Angola9

Norway8.5

TOP TEN – 82.2% of WorldSaudia Arabia 264Iran 138Iraq 115Kuwait 101UAE 98Venezuela 80Russia 79Libya 42Kazakhstan 40Nigeria 36

India5.7

Indonesia4.3

Malaysia4.2

Ecuador4.7

UK3.9

Yemen2.9

Source: BP Statistical Review of World Energy June 2007Notes: Canada and Venezuela do not include heavy oil.Blue Bars denote top 10 reserves

2008 Analyst Day

Latin America Growth Plan

Boris CuraVice President - International, Western Hemisphere

47

Latin America Target Markets 2008 - 2010

1. Mexico – Existing

2. Argentina - Existing

3. Brazil

4. Colombia

48

Mexico Expansion Initiated

Awarded $46 million, 22-month direct assignment from PEMEX

Supplied 3 well service rigs with the KeyView® system

Outfitted 2 PEMEX well service rigs with the KeyView® system

Operations to be conducted in PEMEX’ Northern Region

Contract commenced in 2Q07

2007 revenue: ~$9 million

49

Mexico Expansion Initiated

NorthNorth

South

NE Marine

SW Marine

EXPLORACIÓN Y PRODUCCIÓN

Market Size: ~29 well service rigs

Market Size: ~16 well service rigs

Increased drilling should drive need for more service rigs

50

Mexico: 2008 Outlook

8 incremental rigs and 3 KeyView® system units requested

Contract increased $9 million; extension discussions underway

PEMEX has inquired about other services:

– Coiled tubing, pressure pumping and electric wireline

Integrated project management a logical transition

2008 revenue: $35 million to $45 million, subject to rig deliveries

51

South America

Strategy– Organic growth using Argentina as platform for South America – Use of current U.S. relations with customers operating overseas– Introduce KeyView® system as tool for workover optimization– Take advantage of national oil companies’ needs to invest in

workover technology– Possible acquisitions

52

Argentina

34 well service rigs and 6 drilling rigs operating in country

2007 revenue: ~$94 million

Top customers: Repsol, Pluspetrol, Panamerican

2008 outlook is favorable; pricing improvements made in late 2007

Focused on enhancing margins, no new Key rigs expected in 2008

OSHA recordable rate improved to 1.78x in 2007 vs. 4.04x in 2006

Fleet upgrades in 2007

53

Latin America - Brazil

Politically stableSafe operating environmentReserves: ~12.2 Billion BblsForecasted D&C Spend Increase– Land: 104.0%– Offshore: 93.9%

~50 service rigs in countryPetrobras tender– 29 rigs earlier this year– Second tender this summer

Ability to move rigs No unions

Oil Production (BPD)(1,000's)

1,000

1,250

1,500

1,750

2,000

2000

2001

2002

2003

2004

2005

2006

*Spend Increase for years 2008-2012over spend for years 2003-2007 D&C Spend Source: Spears September DPO

54

Latin America - Colombia

Colombia is politically stable Strongest USA ally in the regionSecurity environment improvingReserves: ~1.5 Billion BblsForecasted D&C Spend Increase– Land: 194.8%

~55 rigs in countryPrimarily local providersEvaluating acquisition opportunitiesHigh utilization


500

550

600

650

700

750

2000

2001

2002

2003

2004

2005

2006


2008 Analyst Day

Eastern Hemisphere Growth Plan

Trey WilsonSenior Vice President and General Counsel

March 3, 2008

56

Overview

Russian and Middle Eastern markets are a major focus

Investigation of opportunities well underway

Table set for investment and business in late 2008

57

Russia

Western Siberian Oil & Gas Basin is second in the world in hydrocarbon reserves after Persian Gulf BasinTotal area of Western Siberia is 3.5 million Km2Hydrocarbon production from Western Siberia makes up 70% of the oil and 90% of the gas production of RussiaReserves: 79.4 Billion BblsReserves to Production Ratio: 22.3 yrsForecasted D&C Spend Increase– Land: 66.6%– Offshore: 100.9%


6,000

7,000

8,000

9,000

10,000

2000

2001

2002

2003

2004

2005

2006

*Spend Increase for years 2008-2012over spend for years 2003-2007 D&C Spend Source: Spears September DPO Source: SPE 102679

58

Russia

To date, ~625 oilfields discovered First oilfield discovered in 1953Majority of fields are mature reservoirs High water production with similar characteristics to Permian Basin fieldsSignificant number of non-producing wells

59

Russia

Historically, drilling and well-servicing were performed by operator equipment or by an affiliate-owned service companyOperators generally prefer to have drilling and well-servicing performed by a third party and would like to foster an independent service company environmentMany operators have sold drilling and well-servicing equipment More equipment is likely to be sold in 2008-09

60

Russia

Many assets still retained by operators of all sizes, but new service companies are emerging to compete with the established companies like Schlumberger and WeatherfordRussian service market estimated to be $12-13 Billion and could almost double in three yearsOperators want third party servicing and are looking for technology, better productivity and project management capabilitiesCurrent opportunity for Key to enter the market and establish an operating vehicleNiche acquisition or joint venture likely method of market entry. Initial activity could be in sidetracking or drilling or other services with well-servicing to follow at some pointOnce established in Russia, Key can pursue additional opportunities either through organic growth or acquisitions

61

Middle East / North Africa


1,3001,4001,5001,6001,7001,8001,900

2000

2001

2002

2003

2004

2005

2006

Libya– Opening of opportunities for western companies to do business– Key customers operating mature fields– Reserves: 45.1 Billion Bbls– Reserves to Production Ratio: 62.0 yrs– Forecasted D&C Spend Increase

• Land: 139.1%• Offshore: 89.6%


62

Oman

Wilayat Key JV established and market opportunities assessedPlan to seek production optimization contract using PEMEX contract performance recordBelieve KeyView® system can deliver valuable production enhancement in Oman– Reserves: 5.6 Billion Bbls– Forecasted D&C Spend Increase

• Land: 91.8%Oil Production (BPD)(1,000's)

700

800

900

1,000

2000

2001

2002

2003

2004

2005

2006


63

Middle East / North Africa - Strategy

Continue assessment of markets to identify– Best growth opportunities– Markets conducive to western investment or entry into markets– Existing service providers as potential acquisitions or partners

Initial focus on Libya, Oman and other North African countries

Key will actively seek business in the Middle East and North Africa via joint ventures, acquisitions and direct contracts

64

International Summary

International expansion the right thing to do– Investment community values international exposure– Bulk of world oil reserves are outside of US

International operators in need of quality well servicing

– Technology to be differentiator

Acquisitions expected to provide platform for growth

Mexico project can be replicated

2008 Analyst Day

Performance Management

Tommy MurphyVice President, Performance Management

March 3, 2008

66

Key Continuous Improvement (KCI)

As of December 31, 2007

213

385

533607

807 838884

1048

1257

1538

9177

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

1,300

1,400

1,500

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Month

Poin

ts

ACTUAL

GOAL

67

KCI Examples

Fluorescent Gloves– Zero OSHA recordable hand and finger

injuries since starting the “Green Glove” Policy

– Safety cost avoidance of $92,350 per year

Engine Hour Meters– 30% reduction in Preventative Maintenance

cost– Savings of $324,975 in Permian Basin and

Rocky Mountains– Implemented in Permian Basin and Rocky

Mountains and is currently being rolled out to California and the Eastern Region

68

Strategy Implementation

69

Strategic Objectives

Differentiate with technology

Differentiate through our people

Expand the business

Improve operational efficiencies

Improve data quality

Improve processes

2008 Analyst Day

Business Development

Tommy PipesVice President, Business Development

March 3, 2008

71

Historical Approach

Historically embedded and managed by operations

Regional focus with limited cross selling

Inter-division communication poor

Inconsistent approach to major accounts

72

Business Development Today

Building a connected organization– Manage customer relationships

– Develop opportunities to enhance revenue

Consistent approach to national account management

Partnered with operations

Staffed with internal and external professionals– Recruited ~20 outside professionals

73

National Presence

74

Account Management / Sales Analysis Tools

Account Management System (AMS) – data warehouse for customer & market activityCognos Analysis Studio – Web-based tool for researching, analyzing, and comparing sales & other dimensional data

75

Success Story: U.S. Major

Major contemplated bid of U.S. well servicing work

BD team approach major with volume-discount proposal– Allowed major to see reduction in per-unit cost

– Allowed Key to increase revenue across multiple LOB’s

Operations and BD collectively developed proposal

Proposal accepted prior to 1/1/08; bid process avoided

Revenue expected to increase from ~$30MM in 2007 to ~$37-$49MM

76

Success Story: Cimarex

Prior to 2006, small customer to Key with ~$10 million in revenue

BD team developed and expanded relationship in 2006

Cimarex wanted flexibility for drilling, reentries and workovers– Entered 2-year contract for 2 horizontal packages

– Entered 60-day agreements for 3 other well service rigs

Cimarex now seeking to package services and interested in wirelineand pressure pumping services in 2008

Revenue expected to increase to $35 million in 2008

Good working relationship with excellent, safety-conscious operator

2008 Analyst Day

Financial Review

Bill AustinChief Financial Officer

March 3, 2008

78

2007 Achievements

Listed on the New York Stock Exchange

Record revenue and EBITDA

Balance sheet refinanced

Liquidity strong

Acquisition program underway

Share repurchase program commenced

79

Annual Performance

Historical Annual Income Statements

Year Ended December 31,12/31/04 12/31/05 12/31/06 12/31/07

Actual Actual Actual Actual

Revenue 987,739$ 1,190,444$ 1,546,177$ 1,662,012$

- Direct Costs 685,420$ 780,243$ 920,602$ 985,614$ - G&A 162,133$ 151,303$ 195,527$ 230,396$ - D&A 103,339$ 111,888$ 126,011$ 129,623$ - Interest, net 45,546$ 47,586$ 33,353$ 29,577$ - Loss on early retirement of debt 12,025$ 20,918$ -$ 9,557$ - Loss (gain) on sale of assets 8,040$ (656)$ (4,323)$ 1,752$ - Other (291)$ (5,236)$ 527$ (447)$

Pre-Tax Income (28,473)$ 84,398$ 274,480$ 275,940$

- Income Taxes (1,890)$ 35,320$ 103,447$ 106,768$ - Minority Interest Income -$ -$ -$ 117$

Income from Continuing Operations (26,583)$ 49,078$ 171,033$ 169,289$ Diluted Earnings Per Share (0.24)$ 0.34$ 1.28$ 1.27$

80

Strong Top Line Growth

$150.0

$175.0

$200.0

$225.0

$250.0

$275.0

$300.0

$325.0

$350.0

$375.0

$400.0

$425.0

$450.0

$475.0

$500.0


Well Service PPS FRS

Revenue in millions

81

Segment Gross ProfitGross Profit in millions

$50.0

$75.0

$100.0

$125.0

$150.0

$175.0

$200.0

1Q05 2Q05 3Q05 4Q05 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07 4Q07

Well Service PPS FRS

82

2007 Capital Expenditures

64%

24%

9%3%

Well Service PPS FRS Other

2007 capital expenditures totaled ~$213 million

83

Capital Structure Remains Strong12/31/03 12/31/06 12/31/07Actual Actual Actual

Revolver -$ -$ 50,000$

Bank Loans -$ 396,000$ -$

6 ⅜% Notes 150,000$ -$ -$

8 ⅜% Notes 276,106$ -$ 425,000$

14% Notes 95,339$ -$ -$

5% Converts 18,699$ -$ -$

Other Debt 16,827$ 25,794$ 48,993$

Total Debt (1) 556,971$ 421,794$ 523,993$

Cash & Investments 103,210$ 150,142$ 58,779$

Net Debt 453,761$ 271,652$ 465,214$

Shareholder Equity 526,087$ 730,511$ 888,998$

Net Debt / Capitalization 46.3% 27.1% 34.4%

1) Reconciliations of net debt to capitalization attached

84

Share Repurchase Program

5,673,596 shares repurchased through February 26, 2008 – Program commenced on November 19, 2007

$73.8 million invested in plan

$13.01 average share price

$226.2 million remaining under current authorization

Regular repurchase approach to continue, subject to market conditions

and other factors

85

Acquisitions Rationale

HypotheticalAcquisition

Annual Budget

Revenue 36,000$ EBITDA 14,400 - Interest 2,250 - Depreciation 4,179Pre-Tax Income 7,971 - Taxes 3,069Net Income 4,902$

Purchase Price 45,000$ Depreciable Life 7.0

IRR 20.5%NPV $17,323Accretion 0.04$

Long term strategic value

Strengthens core business

Broaden relationships with customers

Good return and accretive

Incremental cash flow

___________________________1. Hypothetical acquisition assumes acquisition of a pure play well service rig company2. Assumes 65% of purchase price allocated to fixed assets and assumes a 10% discount rate3. Analysis assume un-levered transaction

86

Moncla Companies

Acquired the Moncla in 4Q07– 59 well service rigs, including 8 barge rigs

and 6 swab units

$146 million total consideration

Estimated revenues of ~$140 million

Market leader in the Southeastern U.S.

Pull through opportunities for other services

87

Kings Oil Tools

Acquired well service assets from Kings Oil Tools on 12/7/07

– 36 working rigs, 10 stacked rigs and related equipment

– All assets located in California

$45 million total consideration, paid in cash

2008 revenue estimate of ~$36 million

California is Key’s best performing division

Performing ahead of planCalifornia Market

Working MarketContractor Rigs (1) Share

Nabors 160 37.6%Key Energy Services 102 24.0%Oil Well Service 38 8.9%Kings Oil Tool 36 8.5%Excalibur 21 4.9%Others 68 16.0%

Total (1) 425 100.0%

(1) Source: Management estimates

2008 Analyst Day

2008 Outlook

Bill AustinChief Financial Officer

March 3, 2008

89

Macro Assumptions

Industry newbuild activity slows

Commodity prices remain strong

E&P spending higher in 2008 than 2007

90

Company Assumptions

No acquisitions or asset sales

No debt reduction aside from contractual repayments

Depreciation higher due to acquisitions and capex

$165 million to $185 million in capital expenditures

Up to $200 million of share repurchases

38.0% - 40.0% tax rate (90% cash)

91

1Q08 Outlook1Q08Range

(in thousands, except per share and hourly data)

Diluted E.P.S. 0.28$ 0.32$ Revenue 435,000$ 450,000$ G&A 59,000$ 62,000$ DD&A 41,000$ 43,000$ Interest, net 9,500$ 10,000$ Tax rate 38.0% 40.0% Rig Hours 630,000 650,000

Truck Hours 555,000 575,000

Preliminary January revenue encouraging

92

2008 Outlook2008

Range(in thousands, except per share and hourly data)

Diluted E.P.S. 1.22$ 1.40$ Revenue 1,750,000$ 1,850,000$ G&A 230,000$ 240,000$ DD&A 165,000$ 175,000$ Interest, net 39,000$ 41,000$ Tax rate 38.0% 40.0% Rig Hours 2,500,000 2,600,000

Truck Hours 2,200,000 2,300,000

Preliminary January revenue encouraging

93

2008 Capital Structure Targets

Debt to Capitalization 38% - 42%

Debt / EBITDA 1.25x

Shares repurchased $150 - $200 million

Minimum cash balance $50 million

Minimum undrawn revolver $100 million

Excess cash flow for share buybacks and/or acquisitions

Capital structure targets assume stable industry activity levels

94

Capital Structure Remains Strong

Free cash flow directed towards share repurchase plan and acquisitions

12/31/07 12/31/08Actual Objectives

Cash and Investments $58,779 $50,000

Revolver $50,000 $100,0008 ⅜% Notes $425,000 $425,000Capitalized Leases $26,815 $26,815Other Debt $22,178 $20,000

Total Debt $523,993 $571,815

Shareholder Equity $888,998 $850,000

Total Debt / Capitalization 37.1% 40.2%

___________________________1. Other debt includes: Moncla note payable

95

Factors That Could Impact Outlook

New capacity additions do not moderate

Acquisitions

Legal settlements or prolonged litigation– Litigation with several former employees expected to conclude in 2008

Material change in interest rates

Natural gas prices drop below $6.00 – customer spending reduced

2H08 price increases

2008 Analyst Day

Concluding Remarks

Dick Alario

March 3, 2008

97

Conclusion

Industry activity levels expected to increase

Acquisitions remain an objective– Additional acquisitions in 2008 probable

– Financial forecast assumes no acquisitions

Targeting international growth

Disciplined and prudent return of capital to shareholders a priority

Up to $200 million share buyback planned for 2008

2008 Analyst Day

Q&A

Management Team

March 3, 2008

2008 Analyst Day

Non-GAAP Reconciliations

March 3, 2008

100

Adjusted EBITDA ReconciliationYear Ending

12/31/06 12/31/07

Net Income 171,033$ 169,289$ Income tax expense 103,447$ 106,768$ Loss on early extinguishment of debt -$ 9,557$ Loss (Gain) on sale of assets (4,323)$ 1,752$ Other expense (income), net 527$ (447)$ Interest expense 38,927$ 36,207$ Interest income (5,574)$ (6,630)$ Depreciation and amortization expense 126,011$ 129,623$ Adjusted EBITDA 430,048$ 446,119$

“Adjusted EBITDA” is defined as net income before interest, taxes, depreciation and amortization, other expense (income), net, losses on early extinguishment of debt and losses (gains) on sale of assets. Management does not include loss on early extinguishment of debt, loss (gain) on sale of assets and other expense (income), net, in its calculations of Adjusted EBITDA, as it believes that they are either non-recurring or not representative of our core operations. Loss on early extinguishment of debt is a non-cash charge consisting of writeoffs of deferred debt issues costs that resulted from the refinancing of the Company’s long-term indebtedness; management believes it should be treated the same as interest in calculating Adjusted EBITDA. Other expense (income), net generally represents our minority investment in IROC Energy Services, Corp. As a minority shareholder in IROC, we cannot directly impact the performance of that investment. Further, management believes that most investors exclude loss (gain) on sale of assets, net from customary EBITDA calculations as that item is often viewed as non-recurring and not reflective of ongoing financial performance.

Adjusted EBITDA is a non-GAAP measure that is used as a supplemental financial measure by our management and directors and by external users of our financial statements, such as investors, to assess:The financial performance of our assets without regard to financing methods, capital structure or historical cost basis;The ability of our assets to generate cash sufficient to pay interest on our indebtedness; andOur operating performance and return on invested capital as compared to those of other companies in the well services industry, without regard to financing methods and capital structure.

Adjusted EBITDA has limitations as an analytical tool and should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Limitations to using Adjusted EBITDA as an analytical tool include:

Adjusted EBITDA does not reflect our current or future requirements for capital expenditures or capital commitments;Adjusted EBITDA does not reflect changes in, or cash requirements necessary to service interest or principal payments on our debt;Adjusted EBITDA does not reflect income taxes; Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, andAdjusted EBITDA does not reflect any cash requirements for suchreplacements; and Other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure.

101

Net Debt / Total Capitalization Reconciliation

SUPPLEMENTAL DATA (in thousands - unaudited)Reconciliations of Debt to Total Capitalization and Net Debt to Total Capitalization with Net Debt 2007 2006 2003

Total Funded Debt: Debt 475,000 396,000 540,176 Capitalized leases 26,815 25,794 16,795 Due to related parties 22,178 - -Total Debt $523,993 $421,794 $556,971 Less: Cash and cash equivalents 58,503 88,375 103,210 Less: Short term investments 276 61,767 - Net Debt $465,214 $271,652 $453,761

Total Capitalization: Debt $523,993 $421,794 $556,971 Stockholders’ Equity 888,998 730,511 526,087Total Capitalization $1,412,991 $1,152,305 $1,083,058

Debt to Capitalization 37.1% 36.6% 51.4%

Total Capitalization with Net Debt: Net Debt $465,214 $271,652 $453,761 Stockholders’ Equity 888,998 730,511 526,087Total Capitalization with Net Debt: $1,354,212 $1,002,163 $979,848

Net Debt / Total Capitalization with Net Debt 34.4% 27.1% 46.3%

Twelve Months EndedDecember 31,

Net Funded Debt to Total Capitalization: Net funded debt to total capitalization is a non-GAAP financial measure that represents total debt (including capitalized leases and notes to related parties) less cash and cash equivalents divided by total capitalization, which consists of total debt (including capitalized leases and notes payable to related parties) less cash and cash equivalents plus stockholders’ equity. Management considers net funded debt to total capitalization to be a measure of liquidity and believes that it is a more useful measure than total debt to total capitalization since cash and cash equivalents can be used to retire outstanding indebtedness.

Documents

2008 Analyst Day - library.corporate-ir.netlibrary.corporate-ir.net/library/78/789/78965/items/282039/KEG... · Readers should also refer to the section entitled “Risk Factors”