Planned
Performance.
2008
Annual Report
Revenue
Revenue
(in millions)
(in millions)
$2,000
$2,000
$1,500
$1 500
$1,000
$500
Revenue growth rate (%)
Revenue growth rate (%)
30
30
20
10
2006
2007
2008
2006
2007
2008
Net income
(in millions)
Shareholders’ equity
(in millions)
$200
$150
$100
$50
$1,000
$800
$600
$400
$200
2006
2007
2008
2006
2007
2008
Employee turnover (%)
Safety record
(TRIR = Total Recordable Incident Rate.
A lower number is desirable)
50
40
30
20
3.0
2.5
2.0
2006
2007
2008
2006
2007
2008
Financial Highlights
(in thousands, except per share data)
Revenues
Direct expenses
Year Ended
December 31,
2006
Year Ended
December 31,
2007
Year Ended
December 31,
2008
$ 1,546,177
$ 1,662,012
$ 1,972,088
920,602
985,614
1,250,327
Depreciation and amortization
126,011
129,623
170,774
Impairment of goodwill and equity method investment
—
—
75,137
General and administrative expenses
195,527
230,396
257,707
Interest expense
Other, net
Income from continuing operations before income taxes
and minority interest
Income tax expense
Minority interest
38,927
36,207
41,247
(9,370)
4,232
2,840
274,480
275,940
174,056
(103,447)
(106,768)
(90,243)
0
117
245
Net income
$ 171,033
$ 169,289
$ 84,058
Net income per common share
Basic
Diluted
Total assets
Total debt
$
$
1.30
$
1.29
$
0.68
1.28
$
1.27
$
0.67
$ 1,541,398
$ 1,859,077
$ 2,016,923
$ 421,794 $ 523,993
$
659,295
Shareholders’ equity
$
730,511
$
888,998
$
860,732
2008 Annual Report | 1
Dear Shareholder,
Dear Shareholder,
In normal times, annual shareholder letters
In normal times, annual shareholder letters
are typically lists of highlights accompanied
are typically lists of highlights accompanied
by craftily worded depictions of the initiatives and
by craftily worded depictions of the initiatives and
strategies that underlie corporate performance.
strategies that underlie corporate performance.
These times are anything but normal and, while
These times are anything but normal and, while
we do include some accomplishments on the
facing page, I thought you might appreciate
some straight talk about the current conditions
in Key’s markets, what we are doing to address
them and the opportunities they will create.
In the second half of 2008, we witnessed extremes in the
fundamental drivers of our business. At record-setting
speed, oil prices went from all-time highs to levels at which our
customer base began to severely curtail capital expenditures.
Natural gas futures followed generally the same path.
Th e dramatic decline in capital expenditures has caused a
cliff -drop in U.S. drilling activity. Th is energy shutdown,
over-arched by the global fi nancial crisis, brought a new
twist in our customers’ reaction to the fall in commodity
prices. In addition to focusing their spending cuts on
capital-intensive new drilling activity as they had in the
past, many of our customers also cut fi eld programs across
their entire return-on-capital spectra, including well
maintenance expenditures in low-cost-to-produce oilfi elds.
Th is resulted in a signifi cant contraction of activity across
all of Key’s service lines in most of our marketplaces.
During the fourth quarter, our management team acted
quickly and decisively to address the activity downturn
and the impending pressure on pricing. We made the
tough decisions and took the hard steps. We fi rst cut
costs through reductions in force, eliminated discretionary
spending and leveraged our buying power on large-spend
items such as fuel, tires and maintenance. We believe that
our decisive actions to align our cost structure with current
market conditions kept Key’s operating margins in the
fourth quarter of 2008 in line with the third quarter, an
enviable and unique outcome compared to our peers.
Under the weight of the economic climate, we understand
we must manage our cost structure so that we can aff ord
to assist our customers in generating cost-eff ective projects
that create new activity for our services. From our patented
2 | 2008 Annual Report
KeyView® system technology, to our unique service-bundling
KeyView® system technology, to our unique service-bundling
capabilities — all our eff orts are designed with just that in
capabilities — all our eff orts are designed with just that in
mind. We believe that these value creators diff erentiate Key
mind. We believe that these value creators diff erentiate Key
in the market.
in the market.
th
ff er
We can’t discern how deep this down-cycle will go or how
will go or how
We can’t discern how deep this down-cycle will go or how
long it will last. However, we have and will continue to
long it will last However we have and will coontinue to
adjust our short-term strategy to fi t these unprecedented
times. We are focused on cash generation and liquidity, and
remain resolute to keep Key’s balance sheet strong.
In the past, companies in the oilfi eld service arena that
have come out of down-cycles well fi nanced and highly
liquid are the ones that were able to grow rapidly, and at
low cost with respect to adding assets. Th e challenge is
choosing the proper timing for such steps and selecting
the best opportunity from the many that will be presented.
At Key, we know what opportunity looks like and we are
ready to act when the time is right.
Finally, we have not altered our core values in the face
of the market upheaval. Our long-term strategy to grow
internationally and improve Key’s “fi ngerprint,” that is the
combination of what we do and where we do it, remains
intact. We are still committed to improving the safety of
our operations, bettering the communities in which we live,
training for success and treating our employees fairly. Th ese
values do not change, no matter the market conditions.
In fact, we also believe that these market conditions are
temporary and off er us an opportunity that did not exist in
the fi ve-year run that preceded them — the ability to show
that we are better structured, better managed and better
fi nanced to take advantage of the many opportunities to
become more valuable to our customers, which will in turn
make Key more valuable to its shareholders.
In closing, I thank you for your continued support of Key
Energy Services, and I thank our thousands of employees
for the hard work they perform every day to support our
customers and their projects.
Best Regards,
Dick Alario
Chairman, President and CEO
Key Energy
Services de México
Technology, Effi ciency, Engineering:
A planned performance success
story in Mexico.
During 2004, Key met with the Mexican national
oil company, PEMEX, to address the problem
of declining production. We designed a
method of arresting these declines, employing
our well-servicing competencies as a platform
to deliver comprehensive value, creating value
to a distinguished customer. By 2008, with
the help of our patented KeyView® system, we
had increased effi ciency versus comparable
well-servicing operations by 30% and now
look forward to a long-lasting partnership. In
addition to our climbing rig count, we continue
to deploy our KeyView system on an increasing
number of PEMEX-owned rigs.
Our engineering team in Poza Rica, Mexico
analyzes fi eld data collected by the KeyView
system and then proposes tangible solutions
and specifi c operational recommendations
to the fi eld to further improve performance.
Highly trained crews, working hand-in-hand
with dedicated Key employees, then implement
these recommendations at the fi eld level. Th is
results in improved operating procedures,
creates a culture of safety and positions Key as
a service provider of choice with exposure to a
high-quality customer: Planned Performance.
Th e Key success story in Mexico is just one
of many places where we deliver superior
solutions and results — on a daily basis.
2008 Accomplishments
• Achieved record quarterly revenue of $535 million for
the third quarter of 2008 and $1,972 million for the full
year 2008 despite signifi cant business interruptions
from Hurricanes Ike and Gustav and a sharp
deterioration in the economic climate
• Emerged as the California well service rig market
leader with the purchase of Western Drilling, LLC,
and leveraged our leading well service rig position
by extending our product offerings in the promising
Marcellus Shale region
• Entered the Russian oilfi eld service market by taking
an initial 26-percent interest in GeoStream Services
Group; Geostream is a high quality provider of
sub-surface, reservoir engineering as well as drilling
and workover services
• Completed the acquisition of all U.S.-based assets of
Canadian oil service provider Leader Energy Services Ltd.
and all of the outstanding stock of specialized pipe-handling
company Hydra-Walk, Inc.
• Contracted with PEMEX to place our 21st rig in Mexico
by the second quarter of 2009, at which time Key will
have built a 500-employee business with an annualized
revenue run rate of $120 million, from essentially
nothing in early 2007
• Recognizing Key’s commitment to quality, safety and
effi ciency, a major U.S. producer promoted Key to an
Advanced Supplier Relationship; this is the highest
supplier relationship with this producer, a status which
only three other suppliers enjoy
• Joined the Russell 3,000 index in June 2008,
as Russell Investments reconstituted its U.S. and
global indices
A Letter from COO Trey Wilson
In early 2009, Key Energy Services streamlined its
operations into a business marketplace matrix organization.
Th is was spurred in part by the early recognition of rapidly
changing market conditions, but more so because the
leadership team identifi ed a need to better understand
and respond to our customers’ needs, streamline decision-
making and to accelerate operational enhancements.
Th e fi rst step in implementing this plan was to consolidate
all domestic operations into six distinct lines of business –
Rig Services, Fluid Management Services, Pressure Pumping
Services (which includes Coiled Tubing), Rental Services,
Wireline Services and Fishing Services – each led by
experienced managers. Second, we divided the lower 48
states into six marketplaces: West Coast, Rockies, Permian,
Gulf Coast, Central and Northeast. Teams were created for
each of these marketplaces and are led by senior members
of our marketplace organization. Every team includes a
senior LOB (Line of Business) leader and staff leaders
within its specifi c marketplace.
Th e resulting structure better aligns Key assets and personnel
with its customers in each marketplace, facilitating quick,
solid decision-making by our teams. Th is allows us to
rapidly respond to customer needs or opportunities and
deliver bundled service packages that provide solutions to
benefi t our customers. By delivering packaged services, Key
reduces its customers’ total costs through improved onsite
project management and better scheduling, thereby reducing
or eliminating non-productive time.
Th e new structure also provides Key with a larger, broader
“fi ngerprint” on its service matrix, resulting in an increase
in revenue per job, as well as a more agile line of customer-
centric thinking. Early wins for Key are already apparent.
In a number of areas, the Company has kept or expanded
rig services’ market share because of an ability to bundle
it with other services, such as fl uid management or rental
services. Wireline services have been combined with pressure
pumping services to maintain or obtain new pressure
pumping business.
Additionally, Key’s signifi cant footprint, meaning its ability
to service its customers’ needs just about anywhere in the
lower 48, is a competitive advantage, appealing to many
customers – both major and large independents. Customers
continue to rely on Key’s wellsite and fi eld solutions while
Key makes every eff ort to maintain and improve, wherever
possible, safety and operational performance. Key has
also leveraged its well-developed presence in the lower
48 to grow its footprint internationally, an expansionary
strategy that we believe will serve us well into the future.
Th e bottom line is that Key eff ectively manages our business
in a rapidly changing environment. Th is new marketplace
organization provides the leadership team with real-time
information needed to quickly make course corrections, and
the new LOB organization allows Key to swift ly execute these
course corrections without compromising quality of service.
4 | 2008 Annual Report
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
¥
n
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2008
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-08038
KEY ENERGY SERVICES, INC.
(Exact name of registrant as specified in its charter)
Maryland
(State or other jurisdiction of
incorporation or organization)
04-2648081
(I.R.S. Employer
Identification No.)
1301 McKinney Street
Suite 1800
Houston, Texas 77010
(Address of principal executive offices, including Zip Code)
(713) 651-4300
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Exchange on Which Registered
Common Stock, $0.10 par value
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class
None
Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities
Act). Yes n
No ¥
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange
Act. Yes n
No ¥
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¥
No n
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K. n
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a
smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in
Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ¥
Smaller reporting company n
Accelerated filer n
Non-accelerated filer n
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes n
No ¥
The aggregate market value of the common stock of the registrant held by non-affiliates of the registrant as of June 30, 2008,
based on the $19.42 per share closing price for the registrant’s common stock as quoted on the New York Stock Exchange on such
date, was $1,727,937,807 (for purposes of calculating these amounts, only directors, officers and beneficial owners of 10% or more
of the outstanding capital stock of the registrant have been deemed affiliates).
As of February 23, 2009, the number of outstanding shares of common stock of the registrant was 121,210,781.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement to be filed pursuant to Regulation 14A under the Securities Exchange
Act of 1934 with respect to the 2009 Annual Meeting of Shareholders are incorporated by reference into Part III of this
Form 10-K.
KEY ENERGY SERVICES, INC.
ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2008
INDEX
PART I
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 1.
ITEM 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 1B. Unresolved Staff Comments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 2.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 3.
Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 4.
PART II
ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 6.
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . .
Consolidated Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . .
ITEM 8.
Changes in and Disagreements with Accountants on Accounting and Financial
ITEM 9.
Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III
ITEM 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . .
ITEM 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 12.
Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 13. Certain Relationships and Related Transactions, and Director Independence . . . . . . . . .
Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 14.
Page
Number
4
17
23
23
25
25
25
28
29
63
64
127
127
129
130
130
130
130
130
ITEM 15. Exhibits, Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
130
PART IV
2
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
In addition to statements of historical fact, this report contains forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995. Statements that are not historical in nature or
that relate to future events and conditions are, or may be deemed to be, forward-looking statements. These
“forward-looking statements” are based on our current expectations, estimates and projections about Key
Energy Services, Inc. and its subsidiaries, our industry and management’s beliefs and assumptions concerning
future events and financial trends affecting our financial condition and results of operations. In some cases,
you can identify these statements by terminology such as “may,” “will,” “predicts,” “projects,” “potential” or
“continue” or the negative of such terms and other comparable terminology. These statements are only
predictions and are subject to substantial risks and uncertainties. In evaluating those statements, you should
carefully consider the information above as well as the risks outlined in “Item 1A. Risk Factors.” Actual
performance or results may differ materially and adversely.
We undertake no obligation to update any forward-looking statement to reflect events or circumstances
after the date of this report except as required by law. All of our written and oral forward-looking statements
are expressly qualified by these cautionary statements and any other cautionary statements that may
accompany such forward-looking statements.
3
ITEM 1. BUSINESS
PART I
THE COMPANY
Key Energy Services, Inc. is a Maryland corporation. References to “Key,” the “Company,” “we,” “us” or
“our” are intended to refer to Key Energy Services, Inc., its wholly-owned subsidiaries and its controlled
subsidiaries.
We provide a complete range of well services to major oil companies, foreign national oil companies and
independent oil and natural gas production companies, including rig-based well maintenance, workover, well
completion and recompletion services, fluid management services, pressure pumping services, fishing and
rental services and ancillary oilfield services.
We believe that we are the leading onshore, rig-based well servicing contractor in the world. We operate
in most major oil and natural gas producing regions of the United States as well as internationally in Argentina
and Mexico. Additionally, we have a technology development group based in Canada. We also have an
ownership interest in a drilling and production services company based in Canada, and, during October 2008,
acquired a 26% ownership interest in a drilling and workover services and sub-surface engineering and
modeling company based in the Russian Federation.
Key’s principal executive office is located at 1301 McKinney Street, Suite 1800, Houston, Texas 77010.
Our phone number is (713) 651-4300 and website address is www.keyenergy.com. We make available free of
charge through our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current
Reports on Form 8-K and all amendments to those reports as soon as reasonably practicable after such
material is electronically filed with the Securities and Exchange Commission (the “SEC”). We have filed the
required certifications under Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to this
Annual Report on Form 10-K. In 2008, we submitted to the New York Stock Exchange (the “NYSE”) the
CEO certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual. Information on our
website or any other website is not a part of this report.
DESCRIPTION OF BUSINESS SEGMENTS
During fiscal year 2008, our business was comprised of three primary business segments: well servicing,
pressure pumping services and fishing and rental services. Key operates in various regions in the continental
United States and internationally in Argentina and Mexico. The following is a description of these three
business segments. For financial information regarding these business segments, see “Note 19. Segment
Information,” in “Item 8. Consolidated Financial Statements and Supplementary Data.”
In early 2009, we implemented a reorganization of our U.S. operating segments to realign both our
management structure and resources along six lines of business. We have undertaken this structural
realignment in an effort to better position the Company to utilize our assets efficiently in meeting customer
needs and to ensure that all lines of business share the same geographic footprint. The six lines of business
will be rig services, fluid management services, pressure pumping services, wireline services, rental services
and fishing services.
Well Servicing Segment
Through our well servicing segment (which accounted for approximately 76.6% of revenues for the year
ended December 31, 2008), we provide a broad range of well services, including rig-based services, fluid
management services (which includes oilfield transportation and produced-water disposal services), cased-hole
electric wireline services and ancillary oilfield services. These services are necessary to complete, stimulate,
maintain and workover oil and natural gas producing wells. Our well service rig fleet provides well
maintenance, workover, completion, and plugging and abandonment services to our customers. Certain of our
larger well service rigs are suitable for and used in certain drilling applications, including horizontal drilling.
4
Our fluid management fleet provides vacuum truck services, fluid transportation services and disposal services
for operators whose wells produce saltwater or other fluids and is also a supplier of frac tanks, which are used
for temporary storage of fluids used in conjunction with fluid hauling operations.
During 2008, we conducted well servicing operations in virtually every major onshore oil and natural gas
producing region of the continental United States, including the Gulf Coast (including South Texas, Central
Gulf Coast of Texas and South Louisiana), Permian Basin of West Texas and Eastern New Mexico, Mid-
Continent (including the Anadarko, Hugoton and Arkoma Basins and the Ark-La-Tex and North Texas
regions), Four Corners (including the San Juan, Piceance, Uinta and Paradox Basins), the Appalachian Basin,
Rocky Mountains (including the Denver Julesberg, Powder River, Wind River, Green River and Williston
Basins), and California (the San Joaquin Basin), and internationally in Argentina and Mexico. In addition to
our onshore operations, we also operate six barge-based rigs that serve customers along the Gulf Coast that
can conduct operations in shallow water.
Rig-based Services
Rig-based services include the maintenance of existing wells, workover of existing wells, completion of
newly drilled wells, drilling of horizontal wells, recompletion of existing wells (re-entering a well to complete
the well in a new geologic zone or formation) and plugging and abandonment of wells at the end of their
useful lives. Our rig fleet consists of 924 active rigs and is diverse, allowing us to work on all types of wells
ranging from very shallow wells to wells as deep as 20,000 feet. Over 250 of our well service rigs are outfitted
with our proprietary KeyView» technology, which captures and reports well site operating data. This
technology allows our customers and our crews to actively monitor well site operations, to improve efficiency
and safety and to add value to the services we offer. Included in our domestic well service fleet are six
operational inland barge rigs. Inland barge rigs are mobile, self-contained, drilling and/or workover vessels
that are used in the drilling and completion of oil and natural gas wells in shallow marshes, inland lakes,
rivers and swamps along the Gulf Coast of the United States. When moved from one location to another, the
barge floats; when stationed on the drill or workover site, the barge is submerged to rest on the bottom.
Typically, inland barge rigs are used to drill or workover wells in marshes, shallow inland bays and offshore
where the water covering the drill site is not too deep. Our barge rigs can operate at depths between three and
17 feet. For our rig-based services, we typically charge by the hour in the United States and Argentina, and by
the job in Mexico.
Maintenance Services
We provide well service rigs, equipment and crews for maintenance services. These services are
performed on both oil and natural gas wells, but more frequently on oil wells. While some oil wells in the
United States flow oil to the surface without mechanical assistance, most require pumping or some other
method of artificial lift. Oil wells that require pumping characteristically require more maintenance than
flowing wells due to the operation of the mechanical pumping equipment. Because few natural gas wells have
mechanical pumping systems in the wellbore, maintenance work on natural gas wells is less frequent.
Maintenance services are required throughout the life of most producing wells to ensure efficient and
continuous operation. These services consist of routine mechanical repairs necessary to maintain production
from the well, such as repairing inoperable pumping equipment in an oil well or replacing defective tubing in
an oil or natural gas well, and removing debris such as sand and paraffin from the well. Other services include
pulling the rods, tubing, pumps and other downhole equipment out of the wellbore to identify and repair a
production problem.
Maintenance services are often performed on a series of wells in close proximity to each other and
typically require less than 48 hours per well to complete. In general, demand for maintenance services is
closely related to the total number of producing oil and natural gas wells in a geographic market, and
maintenance services are generally the most stable type of well service activity.
5
Workover Services
In addition to periodic maintenance, producing oil and natural gas wells occasionally require major
repairs or modifications, called “workovers.” Workover services are performed to enhance the production of
existing wells. Such services include extensions of existing wells to drain new formations either by deepening
wellbores to new zones or by drilling horizontal or lateral wellbores to improve reservoir drainage. In less
extensive workovers, our rigs are used to seal off depleted zones in existing wellbores and access previously
bypassed productive zones. Our workover rigs are also used to convert former producing wells to injection
wells through which water or carbon dioxide is pumped into the formation for enhanced recovery operations.
Other workover services include: conducting major subsurface repairs such as casing repair or replacement,
recovering tubing and removing foreign objects in the wellbore, repairing downhole equipment failures,
plugging back a section of a well to reduce the amount of water being produced with the oil and natural gas,
cleaning out and recompleting a well if production has declined and repairing leaks in the tubing and casing.
These extensive workover operations are normally performed by a well service rig with a workover package,
which may include rotary drilling equipment, mud pumps, mud tanks and blowout preventers, depending upon
the particular type of workover operation. Most of our well service rigs are designed to perform complex
workover operations.
Workover services are more complex and time consuming than routine maintenance operations and
consequently may last from a few days to several weeks. These services are almost exclusively performed by
well service rigs. Demand for workover services is closely related to capital spending by oil and natural gas
producers, which is generally a function of oil and natural gas prices. As commodity prices increase, oil and
natural gas producers tend to increase capital spending for workover services in order to increase oil and
natural gas production. Conversely, as commodity prices decrease, as they have during the second half of
2008, oil and natural gas producers tend to decrease capital spending for workover services.
Completion Services
Our completion services prepare a newly drilled oil or natural gas well for production. The completion
process may involve selectively perforating the well casing to access producing zones, stimulating and testing
these zones and installing downhole equipment. We typically provide a well service rig and may also provide
other equipment such as a workover package to assist in the completion process. However, during periods of
weak drilling rig demand, some drilling contractors may compete with service rigs for completion work. Also,
for some completion work on natural gas wells, coiled tubing units can be used in place of a well service rig.
The completion process typically requires a few days to several weeks, depending on the nature and type
of the completion, and generally requires additional auxiliary equipment that we provide for an additional fee.
The demand for well completion services is directly related to drilling activity levels, which are highly
sensitive to expectations relating to, and changes in, oil and natural gas prices. As the number of newly drilled
wells decreases, the number of completion jobs correspondingly decreases.
Plugging and Abandonment Services
Well service rigs and workover equipment are also used in the process of permanently shutting-in oil and
natural gas wells at the end of their productive lives. Plugging and abandonment work can be performed with
a well service rig along with electric wireline and cementing equipment. Plugging and abandonment services
require compliance with state regulatory requirements. The demand for oil and natural gas does not
significantly affect the demand for plugging and abandonment services because well operators are required by
state regulations to plug wells that are no longer productive. The need for these services is also driven by
lease or operator policy requirements.
Fluid Management Services
We provide fluid management services, including oilfield transportation and produced-water disposal
services. Our oilfield transportation and produced-water disposal services include vacuum truck services, fluid
transportation services and disposal services for operators whose oil or natural gas wells produce saltwater and
6
other fluids. In addition, we are a supplier of frac tanks which are used for temporary storage of fluids in
conjunction with the fluid hauling operations.
Fluid hauling trucks are utilized in connection with drilling and workover projects, which tend to use
large amounts of various oilfield fluids. In connection with drilling or maintenance activity at a well site, we
transport fresh water to the well site and provide temporary storage and disposal of produced saltwater and
drilling or workover fluids. In many oil and natural gas producing regions of the United States, saltwater is
produced along with the oil and natural gas. The production of saltwater typically increases as the oil and
natural gas production decreases. Our fluid management services will collect, transport and dispose of the
saltwater. These fluids are removed from the well site and transported for disposal in a saltwater disposal
(“SWD”) well. Key owned or leased 52 active SWD wells at December 31, 2008. In addition, we provide
equipment trucks that are used to move large pieces of equipment from one well site to the next, and we
operate a fleet of hot oilers which are capable of pumping heated fluids that are used to clear soluable
restrictions in a wellbore. Demand and pricing for these services generally correspond to demand for our well
service rigs. Fluid hauling and equipment hauling services are typically priced on a per barrel or per hour
basis while frac tank rentals are typically billed on a per day basis.
Cased-Hole Electric Wireline Services
Key provides cased-hole electric wireline services in the Appalachian Basin, Texas and Louisiana. These
services are performed at various times throughout the life of the well and includes perforating, completion
logging, production logging and casing integrity services. After the wellbore is cased and cemented, we can
provide a number of services. Perforating creates the flow path between the reservoir and the wellbore.
Production logging can be performed throughout the life of the well to measure temperature, fluid type, flow
rate, pressure and other reservoir characteristics. This service helps the operator analyze and monitor well
performance and determine when a well may need a workover or further stimulation.
In addition, cased-hole services may involve wellbore remediation, which could include the positioning
and installation of various plugs and packers to maintain production or repair well problems, and casing
inspection for internal or external abnormalities in the casing string. Wireline services are provided from
surface logging units, which lower tools and sensors into the wellbore. We owned 27 wireline units as of
December 31, 2008. Cased-hole electric wireline services are conducted during the completion of an oil or
natural gas well and often times throughout the life of a producing well. Services include: production logging,
perforating, pipe recovery, pressure control and setting services. We use advanced wireline instruments to
evaluate well integrity and perform cement evaluations and production logging. Demand for our cased-hole
electric wireline services is correlated to current and anticipated oil and natural gas prices and the resulting
effect on the willingness of our customers to make operating and capital expenditures.
Contract Drilling Services
We provide limited drilling services to oil and natural gas producers. In Argentina, we operate seven
drilling rigs and in the continental United States we operate 151 heavy-duty well service rigs that are capable
of providing conventional and/or horizontal drilling services. Our drilling services are primarily provided under
standard day rates, and, to a lesser extent, footage contracts. Our drilling rigs vary in size and capability. The
rigs located in Argentina are equipped with mechanical power systems and have depth ratings of approx-
imately 10,000 feet, although one rig can drill up to approximately 15,000 feet. Domestically, we recently
acquired three new rigs equipped with mechanical power systems and 250 ton hydraulic top drive units. These
three new rigs are rated to drill to 12,000 feet. Like workover services, the demand for contract drilling is
directly related to expectations about, and changes in, oil and natural gas prices which, in turn, are driven by
the supply of and demand for these commodities.
Ancillary Oilfield Services
We provide ancillary oilfield services, which include, among others: well site construction (preparation of
a well site for drilling activities); roustabout services (provision of manpower to assist with activities on a well
7
site); and air drilling services (drilling technique using compressed air). Demand and pricing for these services
are generally related to demand for our well service operations.
Pressure Pumping Services Segment
Through our pressure pumping services segment (which accounted for approximately 17.5% of revenues
for the year ended December 31, 2008), we provide well stimulation and cementing services to oil and natural
gas producers. Well stimulation services include fracturing, nitrogen, coiled tubing and acidizing services.
These services (which may be completion or workover services) are provided to oil and natural gas producers
and are used to enhance the production of oil and natural gas wells from formations which exhibit restricted
flow of oil and natural gas. In the fracturing process, we typically pump fluid and sized sand, or proppants,
into a well at high pressure in order to fracture the formation and thereby increase the flow of oil and natural
gas. With our cementing services, we pump cement into a well between the casing and the wellbore. Demand
for our pressure pumping services is primarily influenced by current and anticipated oil and natural gas prices
and the resulting effect on the willingness of our customers to make operating and capital expenditures. Coiled
tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well
applications, such as wellbore clean-outs, nitrogen jet lifts and through tubing fishing and formation
stimulations utilizing acid, chemical treatments and sand fracturing. Coiled tubing is also used for a number of
horizontal well applications, including “stiff wireline” uses in which a wireline is placed in the coiled tube and
then fed into a well to carry the wireline to a desired depth (since gravity will not pull the wireline to the
desired depth in a horizontal well).
Our pressure pumping services in 2008 were conducted in the Permian Basin and Barnett Shale in Texas,
the Marcellus Shale in West Virginia, the Bakken Shale in North Dakota, the Michigan Basin, Illinois Basin
and New Albany Shale in the four state area of Michigan, Illinois, Indiana and western Ohio, the San Juan
Basin in Colorado and New Mexico and the Oswego, Mississippi and Anadarko Basins in Oklahoma. Our well
stimulation services were provided in the Permian Basin and Barnett Shale in Texas and Mississippi and
Anadarko Basins in Oklahoma. We provided cementing services in the Permian Basin and Barnett Shale in
Texas, Mississippi and Anadarko Basins in Oklahoma and the Bakken Shale in North Dakota. We provided
coiled tubing services in the Permian Basin and Barnett Shale in Texas, the Marcellus Shale in West Virginia,
the Bakken Shale in North Dakota, the Michigan Basin, Illinois Basin, New Albany Shale in the four state
area of Michigan, Illinois, Indiana and western Ohio and Minden, Louisiana. We also provided cementing and
coiled tubing services in conjunction with our plugging and abandonment operations in the Elk Hills and Kern
River Basins of California.
Fishing and Rental Services Segment
Through our fishing and rental services segment (which accounted for approximately 5.9% of revenues
for the year ended December 31, 2008), we provided fishing and rental services to major and independent oil
and natural gas production companies in the Gulf Coast, Mid-Continent and Permian Basin regions, as well as
in California. We also provided limited services offshore in the Gulf of Mexico. Fishing services involve
recovering lost or stuck equipment in the wellbore utilizing a “fishing tool.” We offer a full line of services
and rental equipment designed for use both onshore and offshore for drilling and workover services. Our rental
tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk» pipe-
handling units and services), pressure-controlled equipment, power swivels and foam air units. Demand for our
fishing and rental services is also closely related to capital spending by oil and natural gas producers, which is
generally a function of oil and natural gas prices. Pricing for fishing services is typically on a per job basis,
including charges for equipment and tools used during the operation along with charges for equipment
operators and consulting services. Prices for rental services typically include a daily charge for equipment and
tools in addition to any equipment operators furnished.
8
EQUIPMENT OVERVIEW
Well Service Rigs
Our rigs typically are billed to customers on a per hour basis, but in certain cases may be billed on a day
rate or by project. We categorize our rigs as active, stacked or inactive. We consider an active rig or piece of
equipment to be a unit that is working, on standby, or down for repairs but with work orders assigned to it or
that is available for work. A stacked rig or piece of equipment is defined as a unit that is in the remanufacturing
process and could not be put to work without significant investment in repairs and additional equipment. A rig
or piece of equipment is considered inactive if we intend to salvage the unit for parts, sell the unit or scrap the
unit. The definitions of active, stacked and inactive are used for the majority of our equipment.
As of December 31, 2008, our fleet of active well service rigs totaled 924 rigs. These rigs are located
throughout the United States and internationally in Argentina and Mexico. Our geographic diversification
provides us with a balanced mix of oil versus natural gas exposure. We estimate that approximately 68% of
our rigs are located in predominantly oil regions, while 32% of our rigs are located in predominantly natural
gas regions.
As mentioned above, our fleet is diverse and allows us to work on all types of wells, ranging from very
shallow wells to wells as deep as 20,000 feet. The following table classifies our active rigs based on size and
location. Typically, heavy-duty rigs will be utilized on deep wells while light-duty rigs will be used on shallow
wells. In most cases, these rigs can be reassigned to other regions should market conditions warrant the
transfer of equipment.
Region
Swab(1)
Light-Duty(2) Medium-Duty(3)
Heavy-Duty(4)
Total
Active Well Service Rig Fleet as of December 31, 2008
Appalachia . . . . . . . . . . . . . . . . . .
Argentina . . . . . . . . . . . . . . . . . . .
Ark-La-Tex. . . . . . . . . . . . . . . . . .
California . . . . . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . .
Mexico . . . . . . . . . . . . . . . . . . . . .
Mid-Continent
. . . . . . . . . . . . . . .
Permian Basin . . . . . . . . . . . . . . .
Rocky Mountains . . . . . . . . . . . . .
Southeastern Marine(5) . . . . . . . . .
Southeastern . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . .
2
1
4
0
2
0
10
12
2
0
4
37
14
3
1
88
0
0
9
8
1
0
1
125
8
31
36
66
47
11
97
216
47
3
41
603
1
7
7
20
11
3
4
59
33
3
11
159
25
42
48
174
60
14
120
295
83
6
57
924
(1) Swab rigs include rigs used in shallow-depth wells.
(2) Light-duty rigs include rigs with rated capacity of less than 90 tons.
(3) Medium-duty rigs include rigs with rated capacity of 90 tons to 125 tons.
(4) Heavy-duty rigs include rigs with rated capacity of greater than 125 tons. The seven heavy-duty rigs in
Argentina are drilling rigs.
(5) Consists of six inland barge rigs.
Fluid Management Services — Oilfield Transportation Equipment
We have a broad and diverse fleet of oilfield transportation service vehicles. We broadly define an oilfield
transportation service vehicle as any heavy-duty, revenue-generating vehicle weighing over one ton. Our
transportation fleet includes vacuum trucks, winch trucks, hot oilers and other vehicles, including kill trucks
and various hauling and transport trucks.
9
Region
Vacuum Truck Winch Truck
Hot Oil Truck
Other
Total
Transportation Fleet as of December 31, 2008
Appalachia . . . . . . . . . . . . . . . . . . . .
Argentina . . . . . . . . . . . . . . . . . . . . .
Ark-La-Tex . . . . . . . . . . . . . . . . . . . .
California . . . . . . . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . .
Mid-Continent
Permian Basin. . . . . . . . . . . . . . . . . .
Rocky Mountains . . . . . . . . . . . . . . .
Southeastern . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . .
19
1
174
29
158
23
181
13
0
598
Pressure Pumping Equipment
21
13
25
2
30
14
29
2
33
169
0
2
0
0
0
6
64
0
3
75
11
30
36
30
8
20
110
6
6
257
51
46
235
61
196
63
384
21
42
1,099
Our pressure pumping services segment operates a diverse fleet of equipment, including frac pumps,
cementing units, acidizing units, nitrogen units and coiled tubing units.
Region
Frac Pumps Cement Units Acidizing Units Nitrogen Units Coiled Tubing Units Total
Pressure Pumping Fleet as of December 31, 2008
California . . . . . . . . .
Barnett Shale . . . . . .
Mid-Continent
. . . . .
Permian Basin. . . . . .
Eastern . . . . . . . . . . .
Rocky Mountains . . .
Total . . . . . . . . . . . . .
0
50
13
23
0
0
86
9
8
3
7
0
0
27
0
7
3
8
8
3
29
0
2
0
6
6
2
16
8
5
0
2
6
3
17
72
19
46
20
8
24
182
SEASONALITY
Our operations are impacted by seasonal factors. Historically, our business has been negatively impacted
during the winter months due to inclement weather, fewer daylight hours and holidays. Our well service rigs
are mobile, and we operate a significant number of oilfield transportation service vehicles. During the summer
months, our operations may be impacted by tropical weather systems. During periods of heavy snow, ice or
rain, we may not be able to move our equipment between locations, thereby reducing our ability to generate
rig or trucking hours. In addition, the majority of our well service rigs work only during daylight hours. In the
winter months when days become shorter, this reduces the amount of time that the rigs can work and therefore
has a negative impact on total hours worked. Lastly, during the fourth quarter, we historically have experienced
significant slowdown during the Thanksgiving and Christmas holiday seasons.
PATENTS, TRADE SECRETS, TRADEMARKS AND COPYRIGHTS
We own numerous patents, trademarks and proprietary technology that we believe provide us with a
competitive advantage in the various markets in which we operate or intend to operate. We have devoted
significant resources to developing technological improvements in our well service business and have sought
patent protection both inside and outside the United States for products and methods that appear to have
commercial significance. In the United States, as of December 31, 2008, we had 34 patents issued and 16
patents pending. As of December 31, 2008, we had 23 patents issued and 182 patents pending in foreign
countries. All the issued patents have varying remaining durations and begin expiring between 2013 and 2025.
The most notable of our technologies include numerous patents surrounding the KeyView» system, a field data
10
acquisition system that captures vital well site operating data from service equipment. We believe this
information helps us and our customers improve safety, reduce costs and increase productivity.
We own several trademarks that are important to our business both in the United States and in foreign
countries. In general, depending upon the jurisdiction, trademarks are valid as long as they are in use or their
registrations are properly maintained and they have not been found to become generic. Registrations of
trademarks can generally be renewed indefinitely as long as the trademarks are in use. While our patents and
trademarks, in the aggregate, are of considerable importance to maintaining our competitive position, no single
patent or trademark is considered to be of a critical or essential nature to our business.
We also rely on a combination of trade secret laws, copyright and contractual provisions to establish and
protect proprietary rights in our products and services. We typically enter into confidentiality agreements with
our employees, strategic partners and suppliers and limit access to the distribution of our proprietary
information.
FOREIGN OPERATIONS
During 2008, we operated internationally in Argentina and Mexico, and we have a technology develop-
ment group based in Canada. We also have ownership interests in a drilling and production services company
based in Canada and a drilling and workover services and sub-surface engineering and modeling company
based in the Russian Federation.
Revenue from our international operations during 2008 totaled $171.9 million, or 8.7% of total revenue.
Revenue from international operations for 2007 and 2006 totaled $105.9 million and $78.3 million, respec-
tively. International revenues by country are summarized in the following table:
For the year ended December 31, 2008:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage of total Revenue . . . . . . . . . . . . . . . . . . . .
For the year ended December 31, 2007:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage of total Revenue . . . . . . . . . . . . . . . . . . . .
For the year ended December 31, 2006:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage of total Revenue . . . . . . . . . . . . . . . . . . . .
Argentina
Mexico
Canada
Total
(In thousands, except for percentages)
$118,841
$47,200
$5,848
$171,889
6.0%
2.4%
0.3%
8.7%
$ 93,925
$ 9,041
$2,938
$105,904
5.7%
0.5%
0.2%
6.4%
$ 78,321
$ — $ — $ 78,321
5.1%
0.0%
0.0%
5.1%
In Argentina, we operate 42 well service rigs (of which seven are drilling rigs) and 46 oilfield
transportation vehicles, all of which we include in our well servicing segment. Beginning in the third quarter
of 2008, we experienced a significant downturn in activity levels in Argentina due, in part, to deteriorating oil
prices. At December 31, 2008, approximately 75% of our rigs in Argentina were working. The downturn has
been further exacerbated by labor-related issues in this country. We are currently exploring other options for
our equipment in Argentina if market conditions there do not improve. For additional information regarding
Argentina, see the discussion on “International Expansion” under “Business and Growth Strategies” in
“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
In Mexico, we commenced operations during the second quarter of 2007 after Petróleos Mexicanos, the
Mexican national oil company (“PEMEX”), awarded our Mexican subsidiary, Key Energy Services de México
S. de R.L. de C.V., a 22-month contract (the “First PEMEX Contract”) valued at approximately $45.8 million
to provide field production solutions and well workover services. During the fourth quarter of 2008, we were
awarded a second 24-month contract with PEMEX (the “Second PEMEX Contract”) to provide the same type
of well services valued at approximately $68.0 million. Also, during the fourth quarter of 2008, our First
PEMEX Contract was extended until September 2009 and the value increased approximately $60.0 million,
for an aggregate value of approximately $105.8 million. Under the terms of the First PEMEX Contract, we
11
initially provided three well service rigs outfitted with our proprietary KeyView» system, and we installed two
KeyView» systems on PEMEX-owned well service rigs. PEMEX has the option to call for additional rigs and
KeyView» systems in the future, and, as of December 31, 2008, we had supplied PEMEX a total of 14 rigs.
As of February 23, 2009, we have increased the number of rigs in Mexico to 17 rigs. The projects under both
contracts cover PEMEX’s North Region assets and initially focus on oil wells in Burgos, Poza Rica-Altamira
and Cerro Azul. We anticipate that we will install units with KeyView» systems on all PEMEX-owned
workover rigs over the next two years, through 2010.
On October 31, 2008, we acquired a 26% interest in OOO Geostream Services Group (“Geostream”) for
$17.4 million. Geostream is based in the Russian Federation and provides drilling and workover services and
sub-surface engineering and modeling in the Russian Federation. We are contractually required to purchase an
additional 24% of Geostream no later than March 31, 2009 for approximately A11.3 million (which at
February 23, 2009 is equivalent to $14.4 million). For a period not to exceed six years subsequent to
October 31, 2008, we will have the option to increase our ownership percentage to 100%. If we have not
acquired 100% of Geostream on or before the end of the six-year period, we will be required to arrange an
initial public offering for those shares.
In 2007, we acquired Advanced Measurements, Inc. (“AMI”), a privately-held Canadian technology
company focused on oilfield service equipment controls, data acquisition and digital information work flow.
AMI builds Key’s proprietary KeyView» systems for deployment on our well service rigs, designs and builds
control and data acquisition systems for fracturing services and develops additional technologies for Key as
well as other service providers. In addition, in connection with the acquisition of AMI, we acquired an
ownership interest in Advanced Flow Technologies, Inc. (“AFTI”), a privately-held Canadian technology
company focused on low cost wireless gas well production monitoring. As of December 31, 2008, we held a
48.73% interest in AFTI.
CUSTOMERS
Our customers include major oil companies, independent oil and natural gas production companies, and
foreign national oil and natural gas production companies. During the years ended December 31, 2008, 2007
and 2006, no single customer accounted for 10% or more of our consolidated revenues.
COMPETITION AND OTHER EXTERNAL FACTORS
In the well servicing markets, we believe that, based on available industry data, we are the largest
provider of land-based well service rigs in the United States. At December 31, 2008, we had 924 active rigs.
Based on the Weatherford-AESC (“AESC”) well service rig count, which is available on Weatherford
International’s internet website, there were approximately 2,910 well service rigs in the United States at
December 31, 2008. A prior survey suggested that there are more well service rigs in the United States than
are reported by the AESC count. While we agree that there are likely more rigs than reported by the AESC,
AESC provides the most readily available information concerning the U.S. well service rig count. We believe
that the difference between the AESC data and the prior survey is likely attributable to (i) not all U.S. well
service providers being members of the AESC, (ii) some U.S. oil and natural gas producers owning well
service rigs and not reporting to the AESC and (iii) poor reporting of equipment by certain members of the
AESC.
The markets in which we operate are highly competitive. Competition is influenced by such factors as
price, capacity, availability of work crews, and reputation and experience of the service provider. We believe
that an important competitive factor in establishing and maintaining long-term customer relationships is having
an experienced, skilled and well-trained work force. In recent years, many of our larger customers have placed
increased emphasis on the safety performance and quality of the crews, equipment and services provided by
their contractors. We have devoted, and will continue to devote, substantial resources toward employee safety
12
and training programs. In addition, we believe that the KeyView» system has provided and will continue to
provide important safety enhancements. Although we believe customers consider all of these factors, price is
often the primary factor in determining which service provider is awarded the work. However, in numerous
instances we secure and maintain work for large customers for which efficiency, safety, technology, size of
fleet and availability of other services are of equal importance to price. Due, in part, to dramatic declines in
the price of oil and natural gas, pricing for our services has become increasingly competitive since September
of 2008. Further, as demand drops for oilfield services, the market is left with excess supply, placing additional
pressure on our pricing.
Significant well service providers include Nabors Industries, Basic Energy Services and Complete
Production Services. Other public-company competitors include Bronco Drilling, Forbes Energy Services and
Pioneer Drilling Company. In addition, though there has been consolidation in the domestic well servicing
industry, there are numerous small companies that compete in Key’s well servicing markets. We do not believe
that any other competitor has more active well service rigs than Key. In Argentina, our largest competitors are
San Antonio International (formerly Pride International), Nabors Industries and Allis-Chalmers Energy.
San Antonio International and Forbes Energy Services are our largest competitors in Mexico.
The pressure pumping services market is dominated by three major competitors: Schlumberger Ltd.,
Halliburton Company and BJ Services Company. These three companies have a substantially larger asset base
than Key and are believed to operate in all major U.S. oil and natural gas producing basins. Other competitors
include Weatherford International Ltd., Superior Well Services, Inc., Basic Energy Services, Inc., Complete
Production Services, Inc., Frac-Tech Services, Ltd. and RPC, Inc. The pressure pumping industry is very
competitive, and the three major competitors generally lead pricing in any particular region. Our pressure
pumping services operate in niche markets and historically have competed effectively with these competitors
based on performance and strong customer service. Where feasible, we cross-market our electric wireline
services to a number of customers where our pressure pumping crews work in tandem with our wireline crews,
thereby offering our customers the ability to minimize vendors, which, we believe, will improve efficiency. We
may be able to further pursue other cross-marketing opportunities utilizing capabilities that are unique to Key,
because none of the three major pressure pumping contractors own and operate well service rigs in the United
States.
The U.S. fishing and rental services market is fragmented compared to our other product lines.
Companies that provide fishing services generally compete based on the reputation of their fishing tool
operators and their relationships with customers. Competition for rental tools is sometimes based on price;
however, in most cases, when a customer chooses a specific fishing tool operator for a particular job, then the
necessary rental equipment will be part of that job as well. Our primary competitors include Baker Oil Tools,
Smith International, Inc., Weatherford International Ltd., Basic Energy Services, Inc., Superior Energy Services
Inc., Quail Tools (owned by Parker Drilling Company) and Knight Oil Tools.
The need for well servicing, pressure pumping services and fishing and rental services fluctuates,
primarily, in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven by the
supply of and demand for oil and natural gas. Generally, as supply of those commodities decreases and
demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to
maximize the productivity of their wells in a higher priced environment. However, in a lower oil and natural
gas price environment, such as the one we are currently experiencing, demand for service and maintenance
decreases as oil and natural gas producers decrease their activity. In particular, the demand for new or existing
field drilling and completion work, including electric wireline services, is driven by available investment
capital for such work. Because these types of services can be easily “started” and “stopped,” and oil and
natural gas producers are less risk tolerant when commodity prices are low or volatile, we may experience a
more rapid decline in demand for these types of well maintenance services compared with demand for other
types of oilfield services. Further, in this lower-priced environment, fewer well service rigs are needed for
completions and there is reduced demand for fishing services because these activities are generally associated
with drilling activity.
13
The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the
level of domestic and international oil and natural gas exploration and development activity, as well as the
equipment capacity in any particular region. For a more detailed discussion, see “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations.”
EMPLOYEES
As of December 31, 2008, we employed approximately 8,411 persons in our domestic operations and
approximately 1,710 additional persons in Argentina, Mexico and Canada. Not including the reductions in
force that were initiated by the Company in response to market conditions, we experienced an annual domestic
employee turnover rate of approximately 42% during 2008, compared to a turnover rate of approximately 41%
in 2007. The high turnover rate is caused, in part, by the nature of the work, which is physically demanding
and sometimes performed in harsh outdoor conditions. As a result, workers may choose to pursue employment
in fields that offer a more desirable work environment at wage rates that are competitive with ours.
Alternatively, some employees may leave Key if they can earn a higher wage with a competitor.
Our domestic employees are not represented by a labor union and are not covered by collective
bargaining agreements. Many of our employees in Argentina are represented by formal unions. Beginning in
2008, we have been experiencing significant labor-related issues in Argentina as a result of not being able to
terminate the employment of field and office personnel because of restrictions imposed by local regulatory
agencies in that country. In Mexico, during 2008, we entered into a collective bargaining agreement that
applies to our workers in Mexico performing work under the PEMEX contracts. Other than with respect to the
labor situation in Argentina, we have not experienced any significant work stoppages associated with labor
disputes or grievances and consider our relations with our employees to be satisfactory. A discussion of the
risks associated with our high turnover is presented under “Business Related Risk Factors” in “Item 1A. Risk
Factors.”
GOVERNMENTAL REGULATIONS
Our operations are subject to various federal, state and local laws and regulations pertaining to health,
safety and the environment. We cannot predict the level of enforcement of existing laws or regulations or how
such laws and regulations may be interpreted by enforcement agencies or court rulings in the future. We also
cannot predict whether additional laws and regulations affecting our business will be adopted, or the effect
such changes might have on us, our financial condition or our business. The following is a summary of the
more significant existing environmental, health and safety laws and regulations to which our operations are
subject and for which compliance may have a material adverse impact on our results of operation or financial
position.
Environmental Regulations
Our operations routinely involve the storage, handling, transport and disposal of bulk waste materials,
some of which contain oil, contaminants and regulated substances. Various environmental laws and regulations
require prevention, and where necessary, cleanup of spills and leaks of such materials, and some of our
operations must obtain permits that limit the discharge of materials. Failure to comply with such environmental
requirements or permits may result in fines and penalties, remediation orders and revocation of permits.
Laws and regulations protecting the environment have become more stringent over the years, and in
certain circumstances may impose “strict liability,” rendering us liable for environmental damage without
regard to negligence or fault on our part. Moreover, cleanup costs, penalties and other damages arising as a
result of new or changes to existing environmental laws and regulations could be substantial and could have a
material adverse effect on our financial condition, results of operations and cash flows. From time to time,
claims have been made and litigation has been brought against us under such laws. However, the costs
incurred in connection with such claims and other costs of environmental compliance have not had a material
adverse effect on our past operations or financial statements. Management believes that Key conducts its
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operations in substantial compliance with current federal, state and local requirements related to health, safety
and the environment.
Hazardous Substances and Waste
The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to
as “CERCLA” or the “Superfund” law, and comparable state laws impose liability without regard to fault or
the legality of the original conduct on certain defined persons, including current and prior owners or operators
of a site where a release of hazardous substances occurred and entities that disposed or arranged for the
disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be
liable for the costs of cleaning up the hazardous substances, for damages to natural resources and for the costs
of certain health studies.
In the course of our operations, we do not typically generate materials that are considered “hazardous
substances.” One exception, however, would be spills that occur prior to well treatment materials being
circulated downhole. For example, if we spill acid on a roadway as a result of a vehicle accident in the course
of providing well stimulation services, or if a tank with acid leaks prior to downhole circulation, the spilled
material may be considered a “hazardous substance.” In this respect, we are occasionally considered to
“generate” materials that are regulated as hazardous substances and, as a result, may incur CERCLA liability
for cleanup costs. Also, claims may be filed for personal injury and property damage allegedly caused by the
release of hazardous substances or other pollutants.
We also generate solid wastes that are subject to the requirements of the Resource Conservation and
Recovery Act, as amended, or “RCRA,” and comparable state statutes. Certain materials generated in the
exploration, development or production of crude oil and natural gas are excluded from RCRA’s hazardous
waste regulation, but these wastes, which include wastes currently generated during our operations, could be
designated as “hazardous wastes” in the future and become subject to more rigorous and costly disposal
requirements. Any such changes in these laws and regulations could have a material adverse effect on our
operating expense.
Although we used operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been released at properties owned or leased by us now or in the past,
or at other locations where these hydrocarbons and wastes were taken for treatment or disposal. Under
CERCLA, RCRA and analogous state laws, we could be required to clean up contaminated property (including
contaminated groundwater), or to perform remedial activities to prevent future contamination.
Air Emissions
The Clean Air Act, as amended, or “CAA,” and similar state laws and regulations restrict the emission of
air pollutants and also impose various monitoring and reporting requirements. These laws and regulations may
require us to obtain approvals or permits for construction, modification or operation of certain projects or
facilities and may require use of emission controls. Our failure to comply with CAA requirements and those
of similar state laws and regulations could subject us to civil and criminal penalties, injunctions and
restrictions on operations.
Global Warming and Climate Control
Scientific studies suggest that emissions of greenhouse gases (including carbon dioxide and methane) may
contribute to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is considering
legislation to reduce greenhouse gas emissions. In addition, many states have already taken measures to
address greenhouse gases through the development of greenhouse gas emission inventories and/or regional
greenhouse gas cap and trade programs. As a result of the U.S. Supreme Court’s decision on April 2, 2007 in
Massachusetts et al. v. EPA, the Environmental Protection Agency (the “EPA”) may regulate greenhouse gas
emissions from mobile sources (e.g. cars and trucks) even if Congress does not adopt new legislation. The
Court’s holding in Massachusetts that greenhouse gases are covered pollutants under the CAA may also result
in future regulation of greenhouse gas emissions from stationary sources. In addition, some states where we
15
have operations have become more active in the regulation of emissions that are believed to be contributing to
global climate change. For example, California enacted the Global Warming Solutions Act of 2006, which
established the first statewide program in the United States to limit greenhouse gas emissions and impose
penalties for non-compliance. While we do not believe our operations raise climate control issues different
from those generally raised by commercial use of fossil fuels, legislation or regulatory programs that restrict
greenhouse gas emissions in areas where we conduct business could increase our costs in order to stay
compliant with any new laws.
Water Discharges
We operate facilities that are subject to requirements of the Clean Water Act, as amended, or “CWA,” and
analogous state laws that impose restrictions and controls on the discharge of pollutants into navigable waters.
Pursuant to these laws, permits must be obtained to discharge pollutants into state waters or waters of the
United States, including to discharge storm water runoff from certain types of facilities. Spill prevention,
control and countermeasure requirements under the CWA require implementation of measures to help prevent
the contamination of navigable waters in the event of a hydrocarbon spill. Other requirements for the
prevention of spills are established under the Oil Pollution Act of 1990, as amended, or “OPA”, which amends
the CWA and applies to owners and operators of vessels, including barges, offshore platforms and certain
onshore facilities. Under OPA, regulated parties are strictly liable for oil spills and must establish and maintain
evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties
could be statutorily responsible. The CWA can impose substantial civil and criminal penalties for non-
compliance.
Employees
Occupational Safety and Health Act
We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or
“OSHA”, and comparable state laws that regulate the protection of employee health and safety. OSHA’s hazard
communication standard requires that information about hazardous materials used or produced in our
operations be maintained and provided to employees, state and local government authorities and citizens. We
believe that our operations are in substantial compliance with OSHA requirements.
Marine Employees
Certain of our employees who perform services on our barge rigs or work offshore are covered by the
provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws operate to
make the liability limits established under state workers’ compensation laws inapplicable to these employees.
Instead, these employees or their representatives are permitted to pursue actions against us for damages
resulting from job related injuries, with generally no limitations on our potential liability.
Other Laws and Regulations
Saltwater Disposal Wells
We operate SWD wells that are subject to the CWA, Safe Drinking Water Act, and state and local laws
and regulations, including those established by the EPA’s Underground Injection Control Program which
establishes the minimum program requirements. Most of our SWD wells are located in Texas and we also
operate SWD wells in Arkansas, Louisiana and New Mexico. Regulations in these states require us to obtain a
permit to operate each of our SWD wells. The applicable regulatory agency may suspend or modify one of
our permits if our well operation is likely to result in pollution of freshwater, substantial violation of permit
conditions or applicable rules, or leaks to the environment. We maintain insurance against some risks
associated with our well service activities, but there can be no assurance that this insurance will continue to be
commercially available or available at premium levels that justify its purchase by us. The occurrence of a
significant event that is not fully insured or indemnified could have a material adverse effect on our financial
condition and operations.
16
Electric Wireline
We conduct cased-hole electric wireline logging, which may entail the use of radioactive isotopes along
with other nuclear, electrical, acoustic and mechanical devices to evaluate downhole formation. Our activities
involving the use of isotopes are regulated by the U.S. Nuclear Regulatory Commission and specified agencies
of certain states. Additionally, we may use high explosive charges for perforating casing and formations, and
various explosive cutters to assist in wellbore cleanout. Such operations are regulated by the U.S. Department
of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives and require us to obtain licenses or other
approvals for the use of densitometers as well as explosive charges. We have obtained these licenses and
approvals when necessary and believe that we are in substantial compliance with these federal requirements.
ITEM 1A. RISK FACTORS
In addition to the other information in this report, the following factors should be considered in evaluating
us and our business.
BUSINESS-RELATED RISK FACTORS
Our business is dependent on conditions in the oil and natural gas industry, especially oil and natural
gas prices and capital expenditures by oil and natural gas companies, and the recent volatility in oil and
natural gas prices, in addition to the deteriorating credit markets and disruptions in the U.S. and global
financial systems, may adversely impact our business.
Prices for oil and natural gas historically have been extremely volatile and have reacted to changes in the
supply of and demand for oil and natural gas. These include changes resulting from, among other things, the
ability of the Organization of Petroleum Exporting Countries to support oil prices, domestic and worldwide
economic conditions and political instability in oil-producing countries. Weakness in oil and natural gas prices
(or the perception by our customers that oil and natural gas prices will continue to decrease) could result in
further reduction in the utilization of available well service equipment and result in lower rates. In addition,
when oil and natural gas prices are weak, or when our customers expect oil and natural gas prices to decrease,
fewer wells are drilled, resulting in less completion and maintenance work for us. Additional factors that affect
demand for our services include:
(cid:129) the level of development, exploration and production activity of, and corresponding capital spending by,
oil and natural gas companies;
(cid:129) oil and natural gas production costs;
(cid:129) government regulation; and
(cid:129) conditions in the worldwide oil and natural gas industry.
Financial markets are in an unprecedented economic crisis worldwide, affecting both debt and equity markets.
The shortage of liquidity and credit combined with the recent substantial losses in worldwide equity markets have
led to an economic recession that could continue for an extended period of time. The slowdown in economic
activity caused by the recession has reduced worldwide demand for energy and resulted in lower oil and natural
gas prices. This reduction in demand could continue through 2009 and beyond. Demand for our services is
primarily influenced by current and anticipated oil and natural gas prices. As a result of recent volatility and
significant decreases in oil and natural gas prices and the substantial uncertainty due to the deteriorating credit
markets and disruptions in the U.S. and global financial systems, our customers have reduced, and may continue
to reduce, their spending on exploration and development drilling. If economic conditions continue to deteriorate
or do not improve, it could result in additional reductions of exploration and production expenditures by our
customers, causing further declines in the demand for our services and products. The decline in demand for our
oil and natural gas services could have a material adverse effect on our revenue and profitability. Further, it is
uncertain whether customers, vendors and suppliers will be able to access financing necessary to sustain their
previous level of operations, fulfill their commitments and fund future operations and obligations.
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Periods of diminished or weakened demand for our services have occurred in the past. We experienced a
material decrease in the demand for our services beginning in August 2001 and continuing through September
2002. Although we experienced strong demand for our services following that period through the third quarter
of 2008, we believe the overall decrease in demand resulting from the current economic crisis could be more
severe than what we experienced during the 2001 — 2002 downturn. The current economic downturn and oil
and natural gas price volatility could have a material adverse effect on our financial condition and results of
operations. In light of these and other factors relating to the oil and natural gas industry, our historical
operating results may not be indicative of future performance.
We may be unable to maintain pricing on our core services.
During the past three years, we have periodically increased the prices on our services to offset rising costs
and to generate higher returns for our shareholders. However, as a result of pressures stemming from
deteriorating market conditions and falling commodity prices, it has become increasingly difficult to maintain
our prices. We have and will likely continue to face pricing pressure from our competitors. We have made
price concessions, and may be compelled to make further price concessions, in order to maintain market share.
The inability to maintain our pricing or reduction in our pricing may have a material negative impact on our
operating results.
Industry capacity may adversely affect our business.
Over much of the past three years, new capacity, including new well service rigs, new pressure pumping
equipment and new fishing and rental equipment, has entered the market. In some cases, the new capacity is
attributable to start-up oilfield service companies and, in other cases, the new capacity has been deployed by
existing service providers to increase their service capacity. The new capacity adversely affected our utilization
rates in 2008, which is down from prior years. Lower utilization of our fleet has led to reduced pricing for our
services. The combination of overcapacity and declining demand has further exacerbated the pricing pressure
for our services. Although oilfield service companies are not likely to add significant new capacity under
current market conditions, in light of current market conditions and the deteriorating demand for our services,
the overcapacity could cause us to experience continued pressure on the pricing of our services and experience
lower utilization. This could have a material negative impact on our operating results.
Our business involves certain operating risks, which are primarily self-insured, and our insurance may
not be adequate to cover all losses or liabilities we might incur in our operations.
Our operations are subject to many hazards and risks, including the following:
(cid:129) blow-outs, the uncontrolled flow of natural gas, oil or other well fluids into the atmosphere or an
underground formation;
(cid:129) reservoir damage;
(cid:129) fires and explosions;
(cid:129) accidents resulting in serious bodily injury and the loss of life or property;
(cid:129) pollution and other damage to the environment; and
(cid:129) liabilities from accidents or damage by our fleet of trucks, rigs and other equipment.
If these hazards occur, they could result in suspension of operations, damage to or destruction of our
equipment and the property of others, or injury or death to our or a third party’s personnel.
We self-insure a significant portion of these liabilities. For losses in excess of our self-insurance limits,
we maintain insurance from unaffiliated commercial carriers. However, our insurance may not be adequate to
cover all losses or liabilities that we might incur in our operations. Furthermore, our insurance may not
adequately protect us against liability from all of the hazards of our business. We also are subject to the risk
that we may not be able to maintain or obtain insurance of the type and amount we desire at a reasonable
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cost. If we were to incur a significant liability for which we were uninsured or for which we were not fully
insured, it could have a material adverse effect on our financial position, results of operations and cash flows.
We are subject to the economic, political and social instability risks of doing business in certain foreign
countries.
We currently have operations in Argentina, Mexico and Canada, as well as investments in a drilling and
production services company based in Canada and a drilling and workover services and sub-surface
engineering and modeling company based in the Russian Federation. We may expand our operations into other
foreign countries as well. As a result, we are exposed to risks of international operations, including:
(cid:129) increased governmental ownership and regulation of the economy in the markets where we operate;
(cid:129) inflation and adverse economic conditions stemming from governmental attempts to reduce inflation,
such as imposition of higher interest rates and wage and price controls;
(cid:129) increased trade barriers, such as higher tariffs and taxes on imports of commodity products;
(cid:129) exposure to foreign currency exchange rates;
(cid:129) exchange controls or other currency restrictions;
(cid:129) war, civil unrest or significant political instability;
(cid:129) restrictions on repatriation of income or capital;
(cid:129) expropriation, confiscatory taxation, nationalization or other government actions with respect to our
assets located in the markets where we operate;
(cid:129) governmental policies limiting investments by and returns to foreign investors;
(cid:129) labor unrest and strikes, including the significant labor-related issues we are currently experiencing in
Argentina;
(cid:129) deprivation of contract rights; and
(cid:129) restrictive governmental regulation and bureaucratic delays.
The occurrence of one or more of these risks may:
(cid:129) negatively impact our results of operations;
(cid:129) restrict the movement of funds and equipment to and from affected countries; and
(cid:129) inhibit our ability to collect receivables.
We historically have experienced a high employee turnover rate. Any difficulty we experience replacing
or adding workers could adversely affect our business.
We historically have experienced an annual employee turnover rate of almost 50%, although we
experienced a lower 42% turnover rate domestically during 2008. We believe that the high turnover rate is
attributable to the nature of the work, which is physically demanding and performed outdoors. As a result,
workers may choose to pursue employment in fields that offer a more desirable work environment at wage
rates that are competitive with ours. We cannot assure that at times of high demand we will be able to retain,
recruit and train an adequate number of workers. Potential inability or lack of desire by workers to commute
to our facilities and job sites and competition for workers from competitors or other industries are factors that
could affect our ability to attract and retain workers. We believe that our wage rates are competitive with the
wage rates of our competitors and other potential employers. A significant increase in the wages other
employers pay could result in a reduction in our workforce, increases in our wage rates, or both. Either of
these events could diminish our profitability and growth potential.
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We may not be successful in implementing technology development and technology enhancements.
A component of our business strategy is to incorporate our technology into our well service rigs,
primarily through the KeyView» system. The inability to successfully develop and integrate the technology
could:
(cid:129) limit our ability to improve our market position;
(cid:129) increase our operating costs; and
(cid:129) limit our ability to recoup the investments made in technology initiatives.
We may incur significant costs and liabilities as a result of environmental, health and safety laws and
regulations that govern our operations.
Our operations are subject to U.S. federal, state and local, and foreign laws and regulations that impose
limitations on the discharge of pollutants into the environment and establish standards for the handling, storage
and disposal of waste materials, including toxic and hazardous wastes. To comply with these laws and
regulations, we must obtain and maintain numerous permits, approvals and certificates from various
governmental authorities. While the cost of such compliance has not been significant in the past, new laws,
regulations or enforcement policies could become more stringent and significantly increase our compliance
costs or limit our future business opportunities, which could have a material adverse effect on our operations.
Failure to comply with environmental, health and safety laws and regulations could result in the
assessment of administrative, civil or criminal penalties, imposition of cleanup and site restoration costs and
liens, revocation of permits, and, to a lesser extent, orders to limit or cease certain operations. Certain
environmental laws impose strict and/or joint and several liability, which could cause us to become liable for
the conduct of others or for consequences of our own actions that were in compliance with all applicable laws
at the time of those actions. For additional information, see the discussion under “Governmental Regulations”
in “Item 1. Business.”
We rely on a limited number of suppliers for certain materials used in providing our pressure pumping
services.
We rely heavily on three suppliers for sized sand, a principal raw material that is critical for our pressure
pumping operations. While the materials are generally available, if we were to have a problem sourcing raw
materials or transporting these materials from these suppliers, our ability to provide pressure pumping services
could be limited.
We may not be successful in identifying, making and integrating our acquisitions.
A component of our growth strategy is to make geographic-focused acquisitions that will strengthen our
presence in selected regional markets. Pursuit of this strategy may be restricted by the recent deterioration of
the credit markets, which may significantly limit the availability of funds for such acquisitions. In addition to
restricted funding availability, the success of this strategy will depend on our ability to identify suitable
acquisition candidates and to negotiate acceptable financial and other terms. There is no assurance that we will
be able to do so. The success of an acquisition depends on our ability to perform adequate diligence before
the acquisition and on our ability to integrate the acquisition after it is completed. While we commit
significant resources to ensure that we conduct comprehensive due diligence, there can be no assurance that all
potential risks and liabilities will be identified in connection with an acquisition. Similarly, while we expect to
commit substantial resources, including management time and effort, to integrating acquired businesses into
ours, there is no assurance that we will be successful integrating these businesses. In particular, it is important
that we be able to retain both key personnel of the acquired business and its customer base. A loss of either
key personnel or customers could negatively impact the future operating results of the acquired business.
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DEBT-RELATED RISK FACTORS
We may not be able to generate sufficient cash flow to meet our debt service obligations.
Our ability to make payments on our indebtedness, and to fund planned capital expenditures, will depend
on our ability to generate cash in the future. This, to a certain extent, is subject to conditions in the oil and gas
industry, general economic and financial conditions, competition in the markets where we operate, the impact
of legislative and regulatory actions on how we conduct our business and other factors, all of which are
beyond our control. This risk is significantly exacerbated by the current economic downturn and related
instability in the global and U.S. credit markets.
We cannot assure you that our business will generate sufficient cash flow from operations to service our
outstanding indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us
to pay our indebtedness or to fund our other capital needs. If our business does not generate sufficient cash
flow from operations to service our outstanding indebtedness, we may have to undertake alternative financing
plans, such as:
(cid:129) refinancing or restructuring our debt;
(cid:129) selling assets;
(cid:129) reducing or delaying acquisitions or capital investments, such as remanufacturing our rigs and related
equipment; or
(cid:129) seeking to raise additional capital.
However, we cannot assure you that we would be able to implement alternative financing plans, if
necessary, on commercially reasonable terms or at all, or that implementing any such alternative financing
plans would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our
debt obligations, or to obtain alternative financings, could materially and adversely affect our business,
financial condition, results of operations and future prospects for growth.
In addition, a downgrade in our credit rating could become more likely if current market conditions
continue to worsen. Although such a credit downgrade would not have an effect on our currently outstanding
senior debt under our indenture or senior secured credit facility, such a downgrade would make it more
difficult for us to raise additional debt financing in the future.
The amount of our debt and the covenants in the agreements governing our debt could negatively impact
our financial condition, results of operations and business prospects.
Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have
important consequences for our operations, including:
(cid:129) making it more difficult for us to satisfy our obligations under our indebtedness and increasing the risk
that we may default on our debt obligations;
(cid:129) requiring us to dedicate a substantial portion of our cash flow from operations to required payments on
indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures
and other general business activities;
(cid:129) limiting our ability to obtain additional financing in the future for working capital, capital expenditures,
acquisitions and general corporate and other activities;
(cid:129) limiting management’s flexibility in operating our business;
(cid:129) limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which
we operate;
(cid:129) diminishing our ability to withstand successfully a downturn in our business or the economy generally;
(cid:129) placing us at a competitive disadvantage against less leveraged competitors; and
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(cid:129) making us vulnerable to increases in interest rates, because certain debt will vary with prevailing
interest rates.
We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances.
If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could
lead to an event of default and the consequent acceleration of our obligation to repay outstanding debt. Our
ability to comply with debt covenants and other restrictions may be affected by events beyond our control,
including prevailing economic and financial conditions.
In particular, under the terms of our indebtedness, we must comply with certain financial ratios and
satisfy certain financial condition tests, several of which become more restrictive over time and could require
us to take action to reduce our debt or take some other action in order to comply with them. Our ability to
satisfy required financial ratios and tests can be affected by events beyond our control, including prevailing
economic, financial and industry conditions, and we cannot assure you that we will continue to meet those
ratios and tests in the future. A breach of any of these covenants, ratios or tests could result in a default under
our indebtedness. If we default, our credit facility lenders will no longer be obligated to extend credit to us
and they, as well as the trustee for our outstanding notes, could elect to declare all amounts outstanding under
the indenture or senior secured credit facility, as applicable, together with accrued interest, to be immediately
due and payable. The results of such actions would have a significant negative impact on our results of
operations, financial condition and cash flows.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obliga-
tions to increase significantly.
Borrowings under our senior secured credit facility bear interest at variable rates, exposing us to interest
rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase
even though the amount borrowed remained the same, and our net income and cash available for servicing our
indebtedness would decrease.
DELAYED FINANCIAL REPORTING-RELATED RISK FACTORS
Taxing authorities may determine that we owe additional taxes from previous years.
We restated our financial statements for periods prior to 2004 and experienced delays in our financial
reporting for subsequent periods. As result, we have amended previously filed tax returns and reports through
2004. We also intend to amend our 2005 and 2006 federal and state income tax filings during 2009. Where
legal, regulatory or administrative rules require or allow us to amend our previous tax filings, we intend to
comply with our obligations under applicable law. To the extent that tax authorities do not accept our
conclusions about the tax effects of the restatement, liabilities for taxes could differ from those which have
been recorded in our consolidated financial statements. If it is determined that we have additional tax
liabilities, there could be an adverse effect on our financial condition, results of operations and cash flows.
During the past three years, we have identified material weaknesses in our internal control over financial
reporting. These material weaknesses, if not corrected, could affect the reliability of our financial
statements and have other adverse consequences.
Section 404 of the Sarbanes-Oxley Act of 2002 and the related SEC rules require management of public
companies to assess the effectiveness of their internal control over financial reporting annually and to include
in Annual Reports on Form 10-K a management report on that assessment, together with an attestation report
by an independent registered public accounting firm. Under Section 404 and the SEC rules, a company cannot
find that its internal control over financial reporting is effective if there exist any “material weaknesses” in its
financial controls. A “material weakness” is a control deficiency, or combination of control deficiencies in
internal control over financial reporting such that there is a reasonable possibility that a material misstatement
of the annual or interim financial statements will not be prevented or detected.
22
We have identified one material weakness in internal control over financial reporting as of December 31,
2008. We have taken actions to remediate the material weakness and improve the effectiveness of our internal
control over financial reporting; however, we cannot assure you that material weaknesses will not exist during
2009. Any failure in the effectiveness of internal control over financial reporting, if it results in misstatements
in our financial statements, could have a material effect on financial reporting or cause us to fail to meet
reporting obligations, and could negatively impact investor perceptions.
TAKEOVER PROTECTION-RELATED RISKS
Our bylaws contain provisions that may prevent or delay a change in control.
Our Amended and Restated Bylaws contain certain provisions designed to enhance the ability of the
Board of Directors to respond to unsolicited attempts to acquire control of the Company. These provisions:
(cid:129) establish a classified Board of Directors, providing for three-year staggered terms of office for all
members of our Board of Directors;
(cid:129) set limitations on the removal of directors;
(cid:129) provide our Board of Directors the ability to set the number of directors and to fill vacancies on the
Board of Directors occurring between shareholder meetings; and
(cid:129) set limitations on who may call a special meeting of shareholders.
These provisions may have the effect of entrenching management and may deprive investors of the
opportunity to sell their shares to potential acquirers at a premium over prevailing prices. This potential
inability to obtain a control premium could reduce the price of our common stock.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We lease executive office space in both Houston, Texas and Midland, Texas (our principal executive
office is in Houston, Texas). We own or lease numerous rig yards, storage yards, truck yards and sales and
administrative offices throughout the geographic regions in which we operate. Also, in connection with our
fluid management services, we operate a number of SWD facilities. Our leased properties are subject to
various lease terms and expirations.
We believe all properties that we currently occupy are suitable for their intended uses. We believe that we
have sufficient facilities to conduct our operations. However, we continue to evaluate the purchase or lease of
additional properties or the consolidation of our properties, as our business requires.
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The following table shows our active owned and leased properties, as well as active SWD facilities,
categorized by business segment and geographic region:
Division
MID-CONTINENT
OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GULF COAST
OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ARK-LA-TEX
OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
APPALACHIA
OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PERMIAN BASIN
OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ROCKY MOUNTAINS
OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CALIFORNIA
OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ARGENTINA
OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CANADA
OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MEXICO
OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
TOTAL OWNED . . . . . . . . . . . . . . . . . . . .
TOTAL LEASE . . . . . . . . . . . . . . . . . . . . .
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Well Services
(Other Than SWD)
SWD
Facilities
Pressure
Pumping
Fishing &
Rental
13
13
14
16
15
12
0
8
55
25
14
9
1
11
2
14
0
2
0
2
114
112
226
0
1
4
11
13
7
0
0
6
10
0
0
0
0
0
0
0
0
0
0
23
29
52
1
1
0
0
1
1
0
1
0
1
0
5
0
0
0
0
0
0
0
0
2
9
11
3
6
1
11
1
2
0
0
2
3
0
1
0
1
0
0
0
0
0
0
7
24
31
Although we have listed some of our SWD facilities as “leased” in the above table, in some of these
cases, we actually own the wellbore for the SWD and lease only the land. In other cases, we lease both the
wellbore and the land. Lease terms vary among different sites, but with respect to some of the SWD facilities
for which we lease the land and own the wellbore, the land owner has an option under the land lease to retain
the wellbore at the termination of the lease.
Also included in the figures shown in the table above are nine apartments leased in the United States and
eight apartments leased in Argentina. These apartments are for Key employees to use for operational support
and business purposes only.
24
ITEM 3. LEGAL PROCEEDINGS
In addition to various suits and claims that have arisen in the ordinary course of business, we continue to
be involved in litigation with some of our former executive officers. We do not believe that the disposition of
any of these items, including litigation with former management, will result in a material adverse effect on our
consolidated financial position, results of operations or cash flows. For additional information on legal
proceedings, see “Note 13. Commitments and Contingencies” in “Item 8. Consolidated Financial Statements
and Supplementary Data.”
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
MARKET AND SHARE PRICES
During fiscal year 2008, Key’s common stock traded on the NYSE, under the symbol “KEG.” From
April 8, 2005 until October 2, 2007, our stock was quoted on the Pink Sheets Electronic Quotation Service
(the “Pink Sheets”) under the symbol “KEGS.” As of February 23, 2009, there were 537 registered holders of
121,210,781 issued and outstanding shares of common stock. The following table sets forth the reported high
and low sales price of Key’s common stock for the periods indicated:
High
Low
Year Ended December 31, 2008
1st Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $14.47
19.75
2nd Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18.94
3rd Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11.14
4th Quarter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11.23
13.36
11.33
3.58
Year Ended December 31, 2007
1st Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $16.90
20.07
2nd Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18.38
3rd Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16.95
4th Quarter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$14.85
16.52
13.08
13.25
High
Low
The following Corporate Performance Graph and related information shall not be deemed “soliciting
material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any
future filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that
we specifically incorporate it by reference into such filing.
The following performance graph compares the performance of our common stock to the PHLX Oil
Service Sector, the Russell 1000 Index, the Russell 2000 Index and to a peer group established by
management. During 2008, the Company moved from the Russell 2000 Index to the Russell 1000 Index. For
comparative purposes, both the Russell 2000 and the Russell 1000 Indices are reflected in the following
performance graph. The peer group is comprised of five other companies with a similar mix of operations and
includes Nabors Industries Ltd., Weatherford International Ltd., Basic Energy Services, Inc., Complete
Production Services, Inc. and RPC, Inc. The graph below matches the cumulative five-year total return to
holders of our common stock with the cumulative total returns of the PHLX Oil Service Sector, the listed
Russell Indices and our peer group. The graph assumes that the value of the investment in our common stock
25
and each index (including reinvestment of dividends) was $100 at December 31, 2003 and tracks the return on
the investment through December 31, 2008.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Key Energy Services, Inc., The Russell 1000 Index, The Russell 2000 Index,
The PHLX Oil Service Sector and the Peer Group
Key Energy Services, Inc.
Russell 2000
PHLX Oil Service Sector
Peer Group
Russell 1000
350
300
250
200
150
100
50
0
S
R
A
L
L
O
D
2003
2004
2005
2006
2007
2008
* $100 invested on December 31, 2003 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31.
DIVIDEND POLICY
There were no dividends paid on Key’s common stock for the year ended December 31, 2008. Key must
meet certain financial covenants before it may pay dividends under the terms of its current credit facility. Key
does not currently intend to pay dividends.
STOCK REPURCHASES
On October 26, 2007, the Company’s Board of Directors authorized a share repurchase program, in which
the Company may spend up to $300.0 million to repurchase shares of its common stock on the open market.
The program expires March 31, 2009. At December 31, 2008, the Company had $132.7 million of availability
remaining under the share repurchase program to repurchase shares of its common stock on the open market.
During 2008, the Company repurchased an aggregate of approximately 11.1 million shares at a total cost of
approximately $135.2 million, which represents the fair market value of the shares based on the price of the
Company’s stock on the dates of purchase.
From the inception of the program in November 2007 through December 31, 2008, the Company has
repurchased an aggregate of approximately 13.4 million shares for a total cost of approximately $167.3 million.
Under the terms of our Senior Secured Credit Facility (as defined under “Sources of Liquidity and Capital
Resources” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operation”), we are limited to stock repurchases of $200.0 million if our consolidated debt to capitalization
ratio, as defined in the Senior Secured Credit Facility, is in excess of 50%. As of December 31, 2008, our
consolidated debt to capitalization ratio was less than 50%.
During the fourth quarter of 2008, the Company repurchased an aggregate 2.3 million shares of its
common stock. The repurchases were made pursuant to the Company’s $300.0 million share repurchase
program and to satisfy tax withholding obligations that arose upon vesting of restricted stock that had been
26
granted to certain senior executives. As noted above, the share repurchase program expires March 31, 2009.
Set forth below is a summary of the share repurchases:
ISSUER PURCHASES OF EQUITY SECURITIES
Period
Total Number
of Shares
Purchased
Weighted
Average Price
Paid Per Share
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or
Programs
October 1, 2008 to October 31, 2008 . . . . . . .
November 1, 2008 to November 30, 2008 . . . .
December 1, 2008 to December 31, 2008 . . . .
1,728,528(1)
522,500
33,463(3)
$6.56(2)
$5.73
$4.42(4)
1,725,000
522,500
—
(1) Includes 3,528 shares repurchased to satisfy tax withholding obligations of certain executive officers upon
vesting of restricted stock.
(2) The price paid per share on the vesting date with respect to the tax withholding repurchases was deter-
mined using the closing prices on October 2, 2008 and October 30, 2008, respectively, as quoted on the
NYSE.
(3) Relates to shares repurchased to satisfy tax withholding obligations of certain executive officers upon vest-
ing of restricted stock.
(4) The price paid per share on the vesting date with respect to the tax withholding repurchases was deter-
mined using the closing price on December 19, 2008, as quoted on the NYSE.
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information as of December 31, 2008 with respect to compensation plans
(including individual compensation arrangements) under which our common stock is authorized for issuance:
Plan Category
Equity compensation plans
approved by
shareholders(1) . . . . . . . . .
Equity compensation plans
not approved by
shareholders(2) . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . .
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants And Rights
(a)
(In thousands)
Weighted Average
Exercise Price of
Outstanding
Options, Warrants
And Rights
(b)
Number of Securities Remaining
Available for Future Issuance
Under Equity Compensation
Plans (Excluding Securities
Reflected in Column (a))
(c)
(In thousands)
5,429
120
5,549
$12.53
$ 8.07
2,250
—
2,250
(1) Represents options and other stock-based awards granted under the Key Energy Group, Inc. 1997 Incentive
Plan (the “1997 Incentive Plan”) and the options and other stock-based awards available under the Key
Energy Services, Inc. 2007 Equity and Cash Incentive Plan (the “2007 Incentive Plan”). The 1997 Incen-
tive Plan expired in November 2007.
(2) Represents non-statutory stock options granted outside the 1997 Incentive Plan and the 2007 Incentive
Plan. The options have a ten-year term and other terms and conditions as those options granted under the
1997 Incentive Plan. These options were granted during 2000 and 2001.
27
ITEM 6. SELECTED FINANCIAL DATA
The following historical selected financial data for the years ended December 31, 2004 through
December 31, 2008 has been derived from the audited financial statements of the Company. The historical
selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations” and the historical consolidated financial statements and related
notes thereto included in “Item 8. Consolidated Financial Statements and Supplementary Data.”
CONSOLIDATED RESULTS OF OPERATIONS DATA
2008
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,972,088
1,250,327
Direct operating expenses . . . . . . . . . . . . . . .
Depreciation and amortization expense . . . . .
170,774
Impairment of goodwill and equity method
2007
Year Ended December 31,
2006
(In thousands, except per share amounts)
$1,662,012 $1,546,177 $1,190,444 $987,739
685,420
103,339
780,243
111,888
920,602
126,011
985,614
129,623
2004
2005
investment
. . . . . . . . . . . . . . . . . . . . . . . .
General and administrative expenses . . . . . . .
Interest expense, net of amounts capitalized . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations before
income taxes and minority interest . . . . . . .
Income tax (expense) benefit . . . . . . . . . . . . .
Minority interest . . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations . . . . . . . .
Discontinued operations, net of tax . . . . . . . .
75,137
257,707
41,247
2,840
174,056
(90,243)
245
84,058
—
—
230,396
36,207
4,232
275,940
(106,768)
117
169,289
—
—
195,527
38,927
(9,370)
274,480
(103,447)
—
171,033
—
—
151,303
50,299
12,313
—
162,133
46,206
19,114
84,398
(35,320)
—
49,078
(3,361)
(28,473)
1,890
—
(26,583)
(5,643)
Net income (loss) . . . . . . . . . . . . . . . . . . . . . $
84,058
$ 169,289
$ 171,033
$
45,717 $ (32,226)
Income (loss) per common share from
continuing operations:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Income (loss) per common share from
discontinued operations:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Net income (loss) per common share:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
0.68
0.67
$
$
1.29 $
1.27 $
1.30 $
1.28 $
0.37 $
0.37 $
(0.20)
(0.20)
— $
— $
— $
— $
— $
— $
(0.03) $
(0.03) $
(0.04)
(0.04)
0.68
0.67
$
$
1.29 $
1.27 $
1.30 $
1.28 $
0.34 $
0.34 $
(0.24)
(0.24)
SELECTED CONSOLIDATED CASH FLOW DATA
Net cash provided by operating activities . . .
Net cash used in investing activities . . . . . . .
Net cash (used in) provided by financing
activities. . . . . . . . . . . . . . . . . . . . . . . . . .
Effect of exchange rates on cash . . . . . . . . . .
2008
$ 367,164
(329,074)
(7,970)
4,068
28
2007
Year Ended December 31,
2006
(In thousands)
$ 258,724
(245,647)
$ 249,919
(302,847)
2005
2004
$ 218,838
(33,218)
$ 69,801
(64,081)
23,240
(184)
(18,634)
(238)
(111,213)
(662)
(88,277)
(233)
SELECTED CONSOLIDATED BALANCE SHEET DATA
. . . . . . . . . . . . . . . . . $ 285,749
1,858,307
1,051,683
2,016,923
Working capital
Property and equipment, gross. . . . . . .
Property and equipment, net . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . .
Long-term debt and capital leases, net
of current maturities . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . .
Stockholders’ equity . . . . . . . . . . . . . .
Cash dividends per common share . . . .
2008
2007
2005
2004
Year Ended December 31,
2006
(In thousands)
$ 265,498
1,279,980
694,291
1,541,398
$ 253,068
1,595,225
911,208
1,859,077
$ 169,022
1,089,826
610,341
1,329,244
633,591
1,156,191
860,732
—
511,614
970,079
888,998
—
406,080
810,887
730,511
—
410,781
775,187
554,057
—
$ 165,920
999,414
597,778
1,316,622
481,047
810,956
505,666
—
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in
conjunction with our consolidated financial statements and related notes thereto in “Item 8. Consolidated Financial
Statements and Supplementary Data.” The discussion below contains forward-looking statements that are based
upon our current expectations and are subject to uncertainty and changes in circumstances including those
identified in “Cautionary Note Regarding Forward-Looking Statements” above. Actual results may differ materially
from these expectations due to inaccurate assumptions and known or unknown risks and uncertainties. Such
forward-looking statements should be read in conjunction with our disclosures under “Item 1A. Risk Factors.”
OVERVIEW
We provide a complete range of well services to major oil companies, foreign national oil companies and
independent oil and natural gas production companies, including rig-based well maintenance, workover, well
completion and recompletion services, fluid management services, pressure pumping services, fishing and
rental services and ancillary oilfield services. We believe that we are the leading onshore, rig-based well
servicing contractor in the world. We operate in most major oil and natural gas producing regions of the
United States as well as internationally in Argentina and Mexico. Additionally, we have a technology
development group based in Canada. We also have ownership interests in a drilling and production services
company based in Canada and a drilling and workover services and sub-surface engineering and modeling
company based in the Russian Federation.
During 2008, we operated in three business segments: the well servicing segment, the pressure pumping
services segment and the fishing and rental services segment. For further detail regarding these business
segments, please see the discussion under “Description of Business Segments” in “Item 1. Business.”
BUSINESS AND GROWTH STRATEGIES
Our strategy is to improve results through acquisitions, controlling spending, maintenance and growth of
our market share in core segments, maintenance of a strong balance sheet and good liquidity, expansion
internationally, investments in technology and new service offerings and enhancement of safety and quality.
Acquisition Strategy
Our strategy contemplates that from time to time we may make acquisitions that strengthen one or more
of our service lines, enhance our presence in selected regional markets or expand the service offerings we
provide to our customer base. During 2008, we completed the acquisitions of the fishing and rental assets of
Tri-Energy Services, LLC (“Tri-Energy”), Western Drilling, LLC (“Western”) and Hydra-Walk, Inc. (“Hydra-
29
Walk”). In addition, we acquired the U.S.-based assets of Leader Energy Services, Ltd. (“Leader”). Through
these acquisitions and purchases, we expanded our well servicing rig fleet in the California market by 22 rigs,
increased our presence in the Southeastern Gulf Coast and Gulf of Mexico rental tool market, acquired an
automated pipe handling business that we feel is complementary to our rig-based service offerings and
increased our presence in the Baaken and Marcellus shale formations through the acquisition of nine coiled
tubing units. We believe that these transactions will help us to expand our geographic “footprint” and diversify
and improve our service offerings to our customers. For more information on the acquisitions we completed
during 2008, see the discussion below under “Acquisitions” in this Item.
Our acquisitions in 2008 were made with cash on hand and availability under our Senior Secured Credit
Facility, and our objective is to use cash for future acquisitions. Depending on future market conditions,
however, we may elect to use equity as a financing tool for acquisitions. See “Liquidity and Capital
Resources” under this Item for further discussion of the financing tools available to us.
Controlling Spending
During the late third quarter of 2008, we saw signs that the market for oilfield services was beginning to
weaken. This weakening in the market for our services resulted from the overall turmoil in the credit markets
that caused many of our customers to begin to slow down their capital spending, and from significant declines
in the prices of oil and natural gas. In response to the pending downturn, we took steps during the later part of
the third quarter and in the fourth quarter of 2008 to decrease our spending levels and control costs. These
steps included targeted reductions in our workforce, reductions in pay and other reductions in our cost
structure. We believe that the actions we have already taken will result in significant cost savings in the near
term, and we are continuing to implement other cost saving measures during early 2009, including further
reductions in our spending levels and capital expenditures, in order to further improve our cost structure.
Maintain and Grow in Core Segments
During the past three years, we have significantly increased our capital expenditures, devoting more
capital to organic growth. Excluding acquisitions, we have cumulatively spent approximately $627.4 million
on capital expenditures since the beginning of 2006, including capital expenditures of $219.0 million in 2008.
These expenditures include the purchase of new pressure pumping equipment, new cased-hole electric wireline
units and new and remanufactured well service rigs, as well as numerous rental equipment and fishing tools.
With the overall downturn in the economy during late 2008 and the projected slowdown for activity in our
industry during the near term, we intend to reduce our capital expenditure program in 2009 in order to
maintain liquidity and provide flexibility for the use of our capital. Presently, we estimate that we will spend
approximately $130.0 million in capital expenditures in 2009, of which we estimate approximately $20.0 mil-
lion a quarter will be devoted to maintenance of our existing fleet. Our 2009 capital spending could increase if
we are awarded additional international work or recognize an opportunity to expand our services in a
particular market.
Maintain Strong Balance Sheet and Liquidity
We believe that our ability to maintain a strong balance sheet and exercise sound capital discipline is
critical, and this will position the Company well to sustain itself through the current and projected downturn in
the market. We also believe that our ability to maintain ample liquidity and borrowing capacity is important in
order to enable us to maintain operational flexibility, as well as to take advantage of other attractive business
opportunities, should they develop. As of December 31, 2008, we had $92.7 million in cash and cash
equivalents as well as $139.3 million of availability under the revolving portion of our Senior Secured Credit
Facility, and we have no maturities under our 8.375% Senior Notes (the “Senior Notes”) until 2014 or required
repayments of borrowings on our Senior Secured Credit Facility until 2012. Also, in the fourth quarter of
2009, we are required to make principal payments totaling $14.5 million related to the Moncla Notes (as
defined in the discussion below of “Moncla Notes Payable” under “Liquidity and Capital Resources” in this
Item). We expect to fund our obligations under the Moncla Notes through cash on hand generated by operating
activities or borrowing under our Senior Secured Credit Facility.
30
International Expansion
We presently operate in Argentina and Mexico and have a technology development group based in
Canada. We also have an ownership interest in a drilling and production services company based in Canada.
During October 2008, we purchased a 26% interest in a drilling, workover and sub-surface engineering and
reservoir modeling company operating in the Russian Federation, and we have an obligation to expand that
interest in 2009. One of our objectives is to redeploy under-utilized assets to international markets. In addition,
we will consider strategic international acquisitions in order to establish a presence in a particular market, if
appropriate. We have evaluated a number of international markets, and our near-term priority is expansion in
Mexico. During 2008, we increased the number of working rigs we had positioned in Mexico to 14. We intend
to further increase our working rigs in Mexico to 21 by the end of the second quarter of 2009. See “Foreign
Operations” in “Item 1. Business” for further discussion of our current international operations.
Investing in Technology and New Service Offerings
We have invested, and will continue to invest, in technology projects that improve operating efficiencies
for both ourselves and our customers, improve the safety performance of our well service rigs and fluid
hauling vehicles and provide opportunities for additional revenue. In 2003, we began deployment of our
proprietary well service technology called KeyView». The KeyView» control and data acquisition system
measures certain well-site operating parameters and actively uses this information for safety intervention
purposes on the rig, allowing our customers and ourselves to monitor and analyze the information about well
servicing to promote improved efficiency and quality. At December 31, 2008, we had more than 250
KeyView» systems installed. The KeyView» system increases our and our customers’ visibility into activities
at the well site. Through this technology, we have the ability to (i) ensure proper rod and tubing make-up
which will result in reduced downhole failures, (ii) improve efficiency, through better logistics and planning,
and (iii) improve safety. We believe that this system provides us a competitive advantage as it is a patented
technology. For a further discussion of the KeyView» system, see “Patents, Trade Secrets, Trademarks and
Copyrights” and “Foreign Operations” in “Item 1. Business.”
Our technology initiative was expanded with the acquisition of AMI in 2007. AMI designs and produces
oilfield service data acquisition, control and information systems. AMI’s technology platform and applications
facilitate the collection of job performance and related information and digitally distributes the information to
customers. AMI contributed to the development of the KeyView» system and will assist in the advancement of
this technology.
We also believe that it is important to have a broad, diverse and complementary services offering. For
this reason, we have expanded the service offerings of our pressure pumping segment and our fishing and
rental segment. We took delivery of five coiled tubing units during the fourth quarter of 2008 that we had
previously ordered during 2007, as well as four segments of drill string for our rental tools group. In addition,
we took delivery of three drilling rigs and continued to expand our cased-hole wireline business that we
entered into during 2006. We believe that some customers prefer to consolidate vendors and we feel that our
expanded services offering may provide better opportunities to serve our customers.
Safety and Quality
We devote significant resources to the training and professional development of our employees, with a
special emphasis on safety. We currently own and operate training centers in Texas, California, Wyoming and
Louisiana. In addition, in conjunction with local community colleges, we have two cooperative training centers
in New Mexico and Oklahoma. The training centers are used to enhance our employees’ understanding of
operating and safety procedures. We recognize the historically high turnover rate in the industry in which we
operate. We are committed to offering competitive compensation, benefits and incentive programs for our
employees in order to ensure we have qualified, safety-conscious personnel who are able to provide quality
service to our customers.
31
PERFORMANCE MEASURES
In determining the overall health of the oilfield service industry, we believe that the Baker Hughes
U.S. land drilling rig count is the best barometer of capital spending and activity levels, since this data is
made publicly available on a weekly basis. Historically, our activity levels have been highly correlated to
capital spending by oil and natural gas producers. When commodity prices are strong, capital spending by our
customers tends to be high, as illustrated by the Baker Hughes U.S. land drilling rig count. As the following
table indicates, the land drilling rig count has increased significantly since 2002 and commodity prices for
both oil and natural gas have increased.
Year
2002 . . . . . . . . . . . . . . . . . . . .
2003 . . . . . . . . . . . . . . . . . . . .
2004 . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . .
2008 . . . . . . . . . . . . . . . . . . . .
WTI Cushing Crude
Oil(1)
NYMEX Henry Hub
Natural Gas(1)
Average Baker Hughes Land
Drilling Rigs(2)
$26.18
$31.08
$41.51
$56.64
$66.05
$72.34
$99.57(3)
$3.37
$5.49
$6.18
$9.02
$6.98
$7.12
$8.90(3)
717
924
1,095
1,290
1,559
1,695
1,814(4)
(1) Represents average crude oil or natural gas price, respectively, for each of the years presented. Source:
Bloomberg
(2) Source: www.bakerhughes.com
(3) Prices for oil and natural gas declined sharply during the fourth quarter of 2008. The spot prices at Febru-
ary 23, 2009 for WTI-Cushing crude oil and NYMEX Henry Hub natural gas were $39.47 per barrel and
$4.20 per Mcf, respectively.
(4) The land drilling rig count was affected by the drop in commodity prices. The land drilling rig count at
January 31, 2009 was 1,412.
32
Internally, we measure activity levels primarily through our rig and trucking hours. Generally, as capital
spending by oil and natural gas producers increases, demand for our services also rises, resulting in increased
rig and trucking services and more hours worked. Conversely, when activity levels decline due to lower
spending by oil and natural gas producers, we generally provide fewer rig and trucking services, which results
in lower hours worked. We publicly release our monthly rig and trucking hours and the following table
presents our quarterly rig and trucking hours from 2006 through 2008.
Rig Hours
Trucking Hours
2008
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
659,462
701,286
721,285
634,772
Total 2008: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,716,805
2007
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
625,748
611,890
597,617
614,444
Total 2007: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,449,699
2006
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
663,819
679,545
677,271
637,994
585,040
603,632
620,885
607,004
2,416,561
571,777
583,074
570,356
583,191
2,308,398
609,317
602,118
587,129
578,471
Total 2006: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,658,629
2,377,035
MARKET CONDITIONS AND OUTLOOK
Market Conditions — Year Ended December 31, 2008
During 2008, the overall industry demand for the services that we provide was high. The average Baker
Hughes land rig count in the United States during 2008 was 1,814 rigs, which was an increase of
approximately 7% over the 2007 average and approximately 16% over the 2006 average. The increase in the
average land rig count was driven primarily by record commodity prices; during 2008 the West Texas
Intermediate — Cushing crude oil price averaged almost $100 per barrel and natural gas at the Henry Hub
averaged almost $9.00 per Mcf, increases of approximately 38% and 25%, respectively, over 2007 levels.
Overall, our activity levels and asset utilization during 2008 were high. For 2008, we had approximately
2.7 million rig hours and 2.4 million trucking hours, which was an increase of approximately 10.9% and 4.7%,
respectively, over 2007 activity levels. Acquisitions we made during 2008 contributed approximately 65,509
rig hours during 2008, and the full year effect of acquisitions we completed during 2007 was 242,545 rig
hours. Also contributing to the increase in rig hours was our expansion into Mexico during 2008, which
contributed an additional 44,736 rig hours. Excluding the effects of acquisitions and expansion in Mexico, our
domestic rig and trucking hours per working day increased slightly during 2008.
During the first three quarters of 2008, we saw our activity levels steadily increase, due to high demand
for our services associated with strong commodity prices. However, throughout 2008, there were signs that the
financial markets of the United States were becoming unstable. As the turmoil in the credit markets increased
during the summer and fall of 2008, commodity prices peaked at all-time highs. Late in the third quarter of
2008, we began to see demand for our services starting to weaken, as the tightening of the credit markets
33
made access to capital for spending more difficult for our customers and uncertainty grew around future
pricing for oil and natural gas.
Conditions continued to deteriorate during the fourth quarter of 2008, driven by rapidly declining
commodity prices, tight credit markets and overall uncertainty about market conditions. We responded to these
deteriorating market conditions by implementing an aggressive cost control program, implementing pricing
changes in selected markets in an effort to maintain asset utilization and cutting our own capital spending
plans. Additionally, the steps we were taking towards a new organizational structure to more efficiently
manage our under-utilized assets allowed us to identify cost savings.
Market Outlook
We believe that 2009 will be a challenging year for our business, as public estimates point to an
anticipated decline in the land rig count of a magnitude not seen since the 2001 — 2002 timeframe. Because
of tighter credit markets and declining borrowing bases, our customers will likely have less access to capital,
and because of lower commodity prices, our customers will likely not be inclined to spend capital even if they
can access it. These assessments are supported by the fact that the land drilling rig count at January 31, 2009
stood at 1,412, a decline of approximately 22.2% from the 2008 average, and oil and natural gas prices were
$41.73 per barrel and $4.42 per MMbtu, respectively, down approximately 58.1% and 50.3%, respectively,
from their 2008 averages.
Near-term, we anticipate that our service lines whose revenues are more closely tied to new drilling
activity will be most severely affected. However, we believe that our core service lines, including rig-based
well servicing and our fluids management business, will be more resilient to the market downturn because our
customers will still need to maintain their existing wells and transport and dispose of saltwater and other
fluids. While we expect prices for our core services will decline during 2009, we do not believe they will fall
as much as prices in some other service lines that are more closely connected with new drilling.
In light of these challenging conditions, we believe that Key is well equipped for the downturn until
production decline rates begin to drive commodity prices higher, causing our customers to spend capital
dollars and increasing the demand for our services. Management has focused on maintaining a strong balance
sheet, with acceptable leverage ratios and good liquidity, and we do not currently believe that the downturn in
2009 will affect the Company’s compliance with the financial covenants in its debt agreements. We also feel
that our geographic diversity will help the Company maintain its margins until the market for all of our
services in the United States recovers.
Impact of Inflation on Operations
We are of the opinion that inflation has not had a significant impact on Key’s business.
ACQUISITIONS
Acquisitions and equity method investments completed during 2008
Tri-Energy Services, LLC. On January 17, 2008, the Company purchased the fishing and rental assets of
Tri-Energy for approximately $1.9 million in cash. These assets were integrated into our fishing and rental
segment. The equity interests of Tri-Energy were owned by employees of the Company who joined the
Company in October 2007 in connection with the earlier acquisition in 2007 of Moncla Well Service, Inc. and
related entities (collectively, “Moncla”).
Western Drilling, LLC. On April 3, 2008, the Company purchased all of the outstanding equity interests of
Western, a privately-owned company based in California that operated 22 working well service rigs, three
stacked well service rigs and equipment used in the workover and rig relocation process, for total consideration
of $51.6 million. We acquired Western to increase our service footprint in the California market. The acquisition
was funded from borrowings under the Company’s Senior Secured Credit Facility and cash on hand.
34
Hydra-Walk, Inc. On May 30, 2008, the Company purchased all of the outstanding stock of Hydra-Walk
for approximately $10.5 million in cash. The Company retained approximately $1.1 million of Hydra-Walk’s
net working capital and did not assume any debt of Hydra-Walk. Hydra-Walk is a leading provider of pipe
handling solutions for the oil and gas industry and operates over 80 automated pipe handling units in
Oklahoma, Texas and Wyoming. We acquired Hydra-Walk to expand the level of integrated services we are
able to provide customers. The assets and results of operations for Hydra-Walk were integrated into our fishing
and rental segment.
Leader Energy Services Ltd. On July 22, 2008, the Company acquired all of the United States-based
assets of Leader, a Canadian company, for consideration of $34.6 million in cash. The acquired assets include
nine coiled tubing units, seven nitrogen trucks, twelve pumping trucks and other ancillary equipment.
Additionally, the Company paid approximately $0.7 million for supplies and inventory used in pressure
pumping operations. The Leader assets were integrated into our pressure pumping segment.
OOO Geostream Services Group. On October 31, 2008, we acquired a 26% interest in Geostream for
$17.4 million. We incurred direct transaction costs of approximately $1.9 million associated with the
transaction. Geostream is based in the Russian Federation and provides drilling and workover services and
sub-surface engineering and modeling in the Russian Federation. In connection with our initial investment in
Geostream, three officers of the Company became board members of Geostream, representing 50% of the
board membership. We are contractually required to purchase an additional 24% of Geostream no later than
March 31, 2009 for approximately A11.3 million (which at December 31, 2008 was equivalent to $15.9 mil-
lion). For a period not to exceed six years subsequent to October 31, 2008, we will have the option to increase
our ownership percentage of Geostream to 100%. If we have not acquired 100% of Geostream on or before
the end of the six-year period, we will be required to arrange an initial public offering for those shares.
Acquisitions completed during 2007
AMI. On September 5, 2007, the Company acquired AMI, which operates in Canada and is a technology
company focused on oilfield service equipment controls, data acquisition and digital information flow. The
purchase price was $6.6 million in cash and $2.9 million in assumed debt.
Moncla. On October 25, 2007, the Company acquired Moncla, which operated well service rigs, barges
and ancillary equipment in the southeastern United States for total consideration of $146.0 million, consisting
of cash, notes payable and assumed debt. The acquisition was made to expand our presence in the southeastern
United States market, and was incorporated into our well servicing segment.
Kings Oil Tools. On December 7, 2007, the Company acquired the well service assets and related
equipment of Kings Oil Tools, Inc. (“Kings”), a California-based well service company, for approximately
$45.1 million in cash to increase our presence in the California market. The assets of Kings were incorporated
into our well servicing segment.
Acquisitions completed during 2006
We made no acquisitions during 2006.
35
RESULTS OF OPERATIONS
Consolidated Results of Operations
The following table shows our consolidated results of operations for the years ended December 31, 2008,
2007 and 2006:
REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,972,088
COSTS AND EXPENSES:
2008
2006
Year Ended December 31,
2007
(In thousands)
$1,662,012
$1,546,177
Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization expense . . . . . . . . . . . . .
Impairment of goodwill and equity method
investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative expenses . . . . . . . . . . . . . . .
Interest expense, net of amounts capitalized . . . . . . . . .
Loss on early extinguishment of debt . . . . . . . . . . . . . .
(Gain) loss on sale of assets, net . . . . . . . . . . . . . . . . . .
Interest income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other expense (income), net . . . . . . . . . . . . . . . . . . . . .
1,250,327
170,774
75,137
257,707
41,247
—
(641)
(1,236)
4,717
985,614
129,623
—
230,396
36,207
9,557
1,752
(6,630)
(447)
920,602
126,011
—
195,527
38,927
—
(4,323)
(5,574)
527
Total costs and expenses, net . . . . . . . . . . . . . . . . . . . . . .
1,798,032
1,386,072
1,271,697
Income before income taxes and minority interest . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minority interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
174,056
(90,243)
245
275,940
(106,768)
117
274,480
(103,447)
—
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
84,058
$ 169,289
$ 171,033
Year Ended December 31, 2008 and 2007
For the year ended December 31, 2008, our net income was $84.1 million, which represents a 50.3%
decrease from net income of $169.3 million for the year ended December 31, 2007. Our earnings per fully
diluted share for the year were $0.67 per share compared to $1.27 per share for the same period in 2007.
Items contributing to the decline in net income and diluted earnings per share during 2008 included an
impairment of the Company’s goodwill pursuant to Statement of Financial Accounting Standards (“SFAS”)
No. 142, Goodwill and Other Intangible Assets (“SFAS 142”) (approximately $69.8 million before tax, or
$0.54 per fully diluted share); a charge associated with the acceleration of the vesting of certain of the
Company’s equity awards (approximately $10.9 million before tax, or $0.05 per fully diluted share); an
impairment of the Company’s investment in IROC Energy Services Corp. (“IROC”) (approximately $5.4 mil-
lion before tax, or $0.03 per fully diluted share); severance charges associated with a reduction in the
Company’s domestic and international workforce (approximately $2.6 million before tax, or $0.01 per fully
diluted share); and the impact of hurricanes and their after-effects in the Gulf Coast during the third quarter of
2008 (estimated to have decreased our pre-tax earnings by $8.4 million, or $0.04 per fully diluted share).
Partially offsetting these items were price increases implemented during the second and third quarters of 2008,
incremental net income from acquisitions the Company completed during 2008, the integration of acquisitions
completed during 2007 for a full year of operations, and expansion of the Company’s cased-hole wireline
operations and operations in Mexico.
Revenues
Our consolidated revenue for the year ended December 31, 2008 was $2.0 billion, an increase of
$310.1 million, or 18.7%, from $1.7 billion for the year ended December 31, 2007. The increase in revenue is
36
primarily attributable to price increases implemented during the second and third quarters of 2008, expansion
of the Company’s cased-hole wireline operations and international operations in Mexico, acquisitions
completed during 2008 and the integration of the acquisitions the Company made during 2007 for a full year
of operations. Please refer to “Segment Operating Results” below for further discussion of the changes in
revenues from 2007. Changes in revenues for each of our reportable segments were (in millions):
Change from 2007
Well Servicing segment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pressure Pumping segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fishing and Rental segment
Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$245.1
45.6
19.4
$310.1
Weather, including hurricanes Ike and Gustav, impacted our land-based operations during the third quarter
of 2008 in parts of Texas, Louisiana and Oklahoma. The inclement weather also significantly impacted our
fishing operations in the Gulf of Mexico. The Company estimates that inclement weather during the third
quarter of 2008 reduced well servicing segment revenues by approximately $7.0 million and fishing and rental
segment revenues by approximately $1.4 million.
Direct operating expenses
Our consolidated direct operating expenses increased approximately $264.7 million, or 26.9%, to
$1.3 billion for the year ended December 31, 2008 compared to $985.6 million for the year ended
December 31, 2007. Excluding depreciation and amortization, these costs were 63.4% of consolidated revenues
during 2008, compared to 59.3% of consolidated revenues for 2007. The change in consolidated direct
operating expenses was the result of (in millions):
Change from 2007
Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equipment, supplies and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Frac sand and chemicals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Self-insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$125.5
58.0
33.4
29.4
4.7
13.7
$264.7
Direct employee compensation, which includes salaries, cash bonuses, health insurance, 401(k) costs and
payroll taxes, increased approximately $125.5 million, or 23.4%, for 2008 compared to the same period in
2007. Acquisitions completed by the Company during 2008 contributed approximately $18.6 million to the
increase over 2007, and the incorporation of acquisitions completed during 2007 for a full year of operations
in 2008 contributed approximately $57.4 million to the increase. The Company’s expansion of its operations in
Mexico contributed approximately $7.4 million to the increase. Excluding these items, direct employee
compensation increased approximately 7.9% for 2008 compared to the same period last year. This increase is
primarily attributable to organic direct headcount growth over the course of 2008 to support our ongoing
operations, as well as pay rate increases that were implemented over the course of the year in order to retain a
high quality workforce. In response to deteriorating market conditions during the fourth quarter of 2008, the
Company’s management implemented a cost control program, which included freezing pay rates and
reductions in the Company’s workforce in certain areas.
Equipment, supplies and maintenance costs increased approximately $58.0 million for 2008 compared to
the same period in 2007. Acquisitions completed during 2008 contributed approximately $5.7 million to the
year-over-year increase in these costs, and the full year effect of acquisitions the Company completed during
2007 was approximately $24.5 million. The expansion of our operations in Mexico contributed approximately
$23.0 million to the increase. Absent these items, these costs increased approximately 0.3% during 2008. The
increase in these costs is related to higher prices from the Company’s vendors, and increased requirements for
37
repairs and maintenance related to the preparation of our assets for increased utilization and expansion of our
operations.
Fuel costs increased approximately $33.4 million, or 44.9%, for the year ended December 31, 2008
compared to the same period in 2007. Acquisitions completed during 2008 contributed approximately
$2.1 million to the increase in fuel costs, while the incorporation of acquisitions the Company completed
during 2007 for a full year of operations during 2008 contributed approximately $3.6 million to the increase.
The Company estimates that on average, the per-gallon cost of diesel fuel increased approximately 27.5%
during 2008 compared to 2007. This, combined with the overall higher usage of fuel because of higher activity
levels, led to the remaining increase in fuel costs.
Frac sand and chemical costs, which also includes the cost of transporting those supplies, increased
approximately $29.4 million, or 34.0%, during 2008 compared to the same period in 2007. Acquisitions by the
Company during 2008 contributed approximately $1.2 million to the increase in these costs and the full year
effect of acquisitions completed during 2007 contributed approximately $0.6 million to the increase in 2008.
Overall demand for frac sand and chemicals increased during 2008 because of the overall increase in pressure
pumping activity. As a result, prices increased for all users of these products. This also had a direct impact on
the cost to transport our frac sand; these costs increased approximately 36.1% during 2008. Additionally,
during 2008 the Company began using coated sand as a proppant for certain high pressure frac jobs in the
Barnett Shale formation. Coated sand is more expensive than normal types of frac sand, which contributed to
the overall increase in these costs. Our pressure pumping operations are able to charge higher rates for frac
jobs that require coated sand.
The Company’s costs associated with self-insurance increased approximately $4.7 million during 2008
compared to 2007. The Company is largely self-insured against loss and uses actuarial information, as well as
actual claims history, in order to calculate the required reserves. The primary cause for the increase in self-
insurance costs was the increase in the number of employees covered, as we added headcount through
acquisitions during 2007 and 2008.
Depreciation and amortization expense
Depreciation and amortization expense increased $41.2 million, or 31.7%, to $170.8 million for the
twelve months ended December 31, 2008 compared to $129.6 million for the same period in 2007.
Acquisitions the Company completed during 2008 contributed approximately $6.6 million to the increase and
the integration of acquisitions made during 2007 for a full year of operations during 2008 contributed
approximately $24.1 million. The remaining $10.5 million increase can be attributed to the Company’s capital
expenditures and its larger fixed asset base, which resulted from the Company’s capital expenditures.
Impairment of goodwill and equity method investment
As discussed in “Critical Accounting Policies — Valuation of Tangible and Intangible Assets,” we test
goodwill for impairment on an annual basis, or more often if circumstances indicate our goodwill might be
impaired. Our tests for 2006 and 2007 resulted in no indications of impairment. However, upon completion of
our test in 2008, there were indicators that the goodwill of our pressure pumping and fishing and rental
segments might be impaired. As required by SFAS 142, we calculated the implied fair value of the goodwill
for the pressure pumping and fishing and rental segments and determined that the implied fair value was less
than the carrying value of the goodwill, meaning that the goodwill was impaired. As a result, during the fourth
quarter of 2008 we recorded a pre-tax charge of approximately $69.8 million to write off the goodwill
balances for both the pressure pumping and fishing and rental segments. Management of the Company
believes that the goodwill of these segments was impaired because of the overall economic downturn and
deterioration in the global credit markets and specifically the downturn in the oilfield services sector, which
has resulted in a decline in the Company’s stock price and market valuation. All of the goodwill written off
from our pressure pumping segment and approximately $18.9 million of the goodwill written off from our
fishing and rental segment arose from our acquisition of Q Services, Inc. during 2002.
38
In 2007, the fair value of the Company’s investment in IROC, based on publicly available stock prices,
declined below its book value. At that time, management of the Company believed that steps being taken by
IROC’s management as well as economic trends in the Canadian markets indicated that the impairment of the
investment was temporary and would be recovered. In the fourth quarter of 2008, management of the
Company determined that, based on IROC’s continued depressed stock price and the overall negative outlook
for the general economy and oilfield services sector, the impairment was other than temporary and as a result
we recorded a pre-tax charge of $5.4 million in order to write the carrying value of our investment in IROC
down to fair value.
General and administrative expenses
General and administrative expenses were approximately $257.7 million for the year ended December 31,
2008, which represents an increase of $27.3 million, or 11.9%, over approximately $230.4 million for the
same period in 2007. General and administrative expenses were 13.1% of revenue during 2008, compared to
13.9% of revenue during 2007. The change in general and administrative expense was the result of (in
millions):
Change from 2007
Employee compensation (non-equity) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Legal fees and reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Professional fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 27.1
11.3
(2.2)
(12.3)
3.4
$ 27.3
Non-equity employee compensation costs increased $27.1 million, or 30.6%, for the year ended
December 31, 2008 compared to the same period in 2007. Acquisitions made during 2008 contributed
approximately $0.9 million to this increase, and the integration of acquisitions made during 2007 for a full
year during 2008 contributed approximately $5.2 million to the increase. Other increases in non-equity
compensation during 2008 were the result of pay rate increases given over the course of 2008, the expansion
of our operations in Mexico, and the expansion of our business development group through the transfer of
existing personnel who previously held positions classified as direct labor. During the fourth quarter of 2008,
due to declining industry conditions, the Company’s management initiated a cost control program, which
included efforts to curtail all nonessential spending and, in some cases, reductions in the Company’s
workforce. Severance charges associated with these workforce reductions resulted in a pre-tax charge totaling
approximately $1.8 million recorded in general and administrative expenses.
Equity-based compensation increased $11.3 million for the year ended December 31, 2008 compared to
the same period in 2007. Because of declines in the Company’s stock price, during the fourth quarter of 2008
we accelerated the vesting period on certain of the Company’s outstanding unvested stock option awards and
stock appreciation rights. As a result of the acceleration the Company recorded a pre-tax charge of
approximately $10.9 million in general and administrative expenses. Absent this item, equity-based compensa-
tion was approximately $12.5 million during 2008, which represents an increase of approximately $0.4 million
from 2007. The increase was primarily due to new awards granted during 2008, partially offset be declines in
the fair value of certain awards classified as liabilities whose value is based on the Company’s stock price.
Legal fees and reserves decreased $2.2 million for the year ended December 31, 2008 compared to the
same period in 2007. The Company records loss contingencies related to lawsuits, claims, and proceedings in
the normal course of our business. These loss contingencies are reviewed routinely to ensure that appropriate
liabilities are recorded and are adjusted as appropriate.
Professional fees declined approximately $12.3 million, or 27.2%, during 2008 compared to 2007.
Professional fees declined primarily as a result of the Company emerging from its delayed financial reporting
process and becoming current with its SEC filings and re-listed on a national stock exchange during 2007.
39
Loss on early extinguishment of debt
For the year ended December 31, 2007, we incurred a loss of $9.6 million associated with the termination
of our prior senior credit agreement, dated July 29, 2005 (the “Prior Credit Facility”). During 2007, we issued
the $425.0 million of Senior Notes and used the proceeds to retire the term loans then outstanding under the
Prior Credit Facility. Concurrently, we entered into the Senior Secured Credit Facility and terminated the Prior
Credit Facility. The loss represents the write-off of debt issue costs we incurred when we entered into the
Prior Credit Facility.
Interest expense, net of amounts capitalized
The Company’s interest expense increased approximately $5.0 million, or 13.9%, to $41.2 million for the
twelve months ended December 31, 2008 compared to $36.2 million for the same period in 2007. Higher
overall debt levels led to the increase in interest expense.
Gain on sale of assets, net
The Company recorded a net gain of approximately $0.6 million in connection with the sale of various
assets during 2008, compared with a loss of approximately $1.8 million during 2007. From time to time and
in the normal course of business, the Company sells assets that are either in scrap condition or no longer being
used by the Company.
Interest income
Interest income recognized by the Company during 2008 was approximately $1.2 million. This represents
a decline of approximately $5.4 million from the amounts recognized during 2007. The primary reason for the
decline in interest income was the decline in the Company’s short-term investment balances since 2007.
During the fourth quarter of 2007, the Company liquidated its short-term interest-bearing investments to
complete the acquisition of Moncla.
Other expense, net
Other expense, net for the twelve months ended December 31, 2008 was approximately $4.7 million,
compared to other income, net of approximately $0.4 million for the year ended December 31, 2007. Other
expense, net for 2008 primarily relates to foreign currency transaction losses associated with the Company’s
foreign operations in Mexico, Argentina, and Canada of approximately $3.5 million. Partially offsetting these
losses was equity in earnings from the Company’s investment in IROC.
Income tax expense
Our income tax expense was $90.2 million for the year ended December 31, 2008, compared to
$106.8 million for the year ended December 31, 2007. Our effective tax rate was 51.8% in 2008, compared to
38.7% in 2007. The decrease in income tax expense is primarily attributable to lower pretax income in 2008.
The increase in our effective tax rate is primarily attributable to the impairment of $63.4 million of goodwill
that was non-deductible for income tax purposes and $6.4 million of goodwill that was deductible for income
tax purposes in 2008. The 2008 effective tax rate exclusive of the goodwill impairment would be 38.0%. Other
differences in the effective tax rate and the statutory rate of 35.0% result primarily from the effect of state and
certain foreign income taxes and permanent items attributable to book-tax differences.
Year Ended December 31, 2007 and 2006
For the year ended December 31, 2007, the Company’s net income was $169.3 million, which represented
a decline of approximately $1.7 million, or 1%, from the Company’s net income of $171.0 million for the year
ended December 31, 2006. Fully diluted earnings per share for the year ended December 31, 2007 were $1.27
per share, a decline of $0.01 per share from fully diluted earnings per share for the year ended December 31,
2006 of $1.28 per share. Items contributing to the decline in net income and diluted earnings per share were
40
costs associated with the refinancing of indebtedness during the fourth quarter of 2007. In connection with that
refinancing, the Company recorded a pre-tax loss of approximately $9.6 million, or $0.04 per fully diluted
share, associated with the write-off of existing unamortized debt issuance costs, and the termination of two
interest rate swaps, which led to a pre-tax charge of approximately $2.3 million, or $0.01 per fully diluted
share. Offsetting these one-time charges were increased revenues and net income associated with acquisitions
the Company made during the third and fourth quarters of 2007 as well as the effect of higher pricing and
increased activity during 2007, and expansion of our cased-hole wireline business and international operations
in Mexico.
Revenues
Consolidated revenue for the year ended December 31, 2007 was approximately $1.7 billion, which
represented an increase of $115.8 million, or 7.5%, from $1.6 billion for the year ended December 31, 2006.
Please refer to “Segment Operating Results” below for further discussion of the changes in revenues from
2006. Changes in revenue for each of our reportable segments were (in millions):
Well Servicing segment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pressure Pumping segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fishing and Rental segment
Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 63.5
51.9
0.4
$115.8
Change from 2006
Contributing to the increase in revenues in 2007 were acquisitions the Company made during the third
and fourth quarters, the startup of our operations in Mexico during the second quarter, and the expansion of
our cased-hole wireline business, as well as price increases and increased activity levels.
Direct operating expenses
Consolidated direct operating expenses increased approximately $65.0 million, or 7.1%, to $985.6 million
for the year ended December 31, 2007, compared to $920.6 million for the year ended December 31, 2006.
The increase in direct operating expenses was the result of (in millions):
Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pressure pumping supplies and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Well service acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Self-insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 25.4
41.6
16.0
(21.8)
3.8
$ 65.0
Change from 2006
Our employee compensation costs, which include salaries, bonuses and related expenses, increased
$25.4 million primarily as the result of increased incentive compensation and increased headcount, exclusive
of the impact of acquisitions. Wage and bonus increases during the year were necessary, as the market for our
labor was extremely competitive. Because new competitors entered the market and existing competitors added
equipment capacity, we were forced to increase wage rates in order to maintain our high levels of quality
personnel. Supplies and equipment for our pressure pumping segment increased $41.6 million, primarily as a
result of increases in the size of our pressure pumping fleet and increases in the costs to purchase and
transport materials used in providing services to our customers. Acquisitions in our well services segment
added $16.0 million to our direct operating expenses in 2007. Our self-insurance costs, comprised of costs
associated with workers compensation, vehicular liability exposure, and insurance premiums declined signifi-
cantly in 2007 as compared to 2006.
41
Depreciation and amortization expense
Depreciation and amortization expense increased $3.6 million, or 2.9%, to $129.6 million for the year
ended December 31, 2007, compared to $126.0 million for the year ended December 31, 2006. Contributing to
the increase in depreciation and amortization expense was depreciation expense associated with our acquisi-
tions during 2007, which totaled approximately $4.8 million, and increased depreciation of approximately
$7.7 million related to management’s reassessment of the useful lives of certain assets. Excluding the
depreciation and amortization expense associated with acquisitions and reassessment of useful lives, our
depreciation expense would have declined approximately $8.9 million because the assets we added through
various acquisitions during the 1994 to 2002 time period were reaching the end of their depreciable lives.
Depreciation and amortization expense as a percentage of revenue for the year ended December 31, 2007
totaled 7.8%, compared to 8.1% for the year ended December 31, 2006.
General and administrative expenses
General and administrative expense increased $34.9 million, or 17.8%, to $230.4 million for the year
ended December 31, 2007, compared to $195.5 million for the year ended December 31, 2006. The
$34.9 million increase was primarily the result of (in millions):
Change from 2006
Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 legal settlement to the Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Professional fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bad debt expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 7.5
3.0
7.5
9.6
1.8
5.5
$34.9
Employee compensation, exclusive of the impact of acquisitions, which includes salaries, bonuses, equity-
based compensation and payroll taxes, increased primarily due to higher equity-based compensation and, to a
lesser extent, increased salaries. Equity-based compensation expense during 2007, excluding grants made to
our outside directors, totaled $12.0 million, compared to $5.6 million during 2006. The $6.4 million increase
is primarily attributable to awards granted under our Phantom Share Plan at the end of 2006, as well as
incremental stock options, restricted stock and stock appreciation rights awarded during 2007 under our 1997
Incentive Plan. General and administrative expenses added through acquisitions made during 2007 contributed
$3.0 million to the increase in costs when compared to 2006.
General and administrative expenses also increased in 2007 because 2006 general and administrative
expenses included a $7.5 million benefit from a legal settlement in 2006 that was not repeated during 2007.
Professional fees increased approximately $9.6 million during 2007, primarily due to our delayed financial
reporting process. Also contributing to the increase was an additional $1.8 million in bad debt expense and
$5.5 million in other general and administrative costs. General and administrative expense as a percentage of
revenue for the year ended December 31, 2007 totaled 13.9% compared to 12.6% for the year ended
December 31, 2006.
Interest expense, net of amounts capitalized
Interest expense decreased $2.7 million, or 7.0%, to $36.2 million for the year ended December 31, 2007,
compared to $38.9 million for the year ended December 31, 2006. The decrease was primarily the result of
the impact of higher capitalized interest as a result of higher capital expenditures. This decrease was partially
offset by a one-time $2.3 million cost associated with the settlement of two interest rate swaps that were
terminated in connection with the termination of our Prior Credit Facility in 2007. Interest expense as a
percentage of revenue for the year ended December 31, 2007 totaled 2.2%, compared to 2.5% for the year
ended December 31, 2006.
42
Loss on early extinguishment of debt
For the year ended December 31, 2007, we incurred a loss of $9.6 million associated with the termination
of our Prior Credit Facility. During 2007, we issued the $425.0 million of Senior Notes and used the proceeds
to retire the term loans then outstanding under the Prior Credit Facility. Concurrently, we entered into the
Senior Secured Credit Facility and terminated the Prior Credit Facility. The loss represents the write-off of
debt issue costs we incurred when we entered into the Prior Credit Facility.
Loss on sale of assets, net
For the year ended December 31, 2007, we incurred a net loss on the disposal of assets of approximately
$1.8 million, compared to a net gain of approximately $4.3 million in 2006. From time to time and in the
ordinary course of business the Company sells assets that are in scrap condition or are no longer being used
by the Company, and recognizes gains or losses as a result of these sales.
Interest Income
Interest income was approximately $6.6 million during 2007, compared to approximately $5.6 million
during 2006. The increase in interest income is primarily associated with the Company’s investments of excess
cash and cash equivalents. These investments were liquidated during the fourth quarter of 2007 to partially
fund our purchase of Moncla.
Other income, net
Other income, net was approximately $0.4 million during 2007 compared to other expense, net of
approximately $0.5 million in 2006. The increase in other income, net was primarily attributable to our equity
in earnings from our investment in IROC and foreign currency transaction gains.
Income tax expense
Our income tax expense was $106.8 million for the year ended December 31, 2007, as compared to
income tax expense of $103.4 million for the year ended December 31, 2006. Our effective tax rate in 2007
was 38.7%, as compared to 37.7% in 2006. The increase in income tax and our effective tax rate was
primarily attributable to the revised Texas Franchise Tax. In general, differences between the effective tax rates
and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and
permanent items attributable to book-tax differences.
43
Segment Operating Results
Year Ended December 31, 2008 and 2007
The following table shows operating results for each of our reportable segments for the twelve month
periods ended December 31, 2008 and 2007:
Segments
Well Servicing
Year Ended December 31,
2008
2007
(In thousands, except for percentages)
Change
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses, as a percentage of revenue . . .
$1,509,823
939,893
$1,264,797
738,694
$245,026
201,199
62.3%
58.4%
Pressure Pumping
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses, as a percentage of revenue . . .
$ 344,993
239,833
$ 299,348
189,645
$ 45,645
50,188
69.5%
63.4%
Fishing and Rental
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses, as a percentage of revenue . . .
$ 117,272
70,601
$
97,867
57,275
$ 19,405
13,326
60.2%
58.5%
Well servicing segment
Revenues for the well servicing segment increased $245.0 million, or 19.4%, to $1.5 billion for the year
ended December 31, 2008 compared to $1.3 billion for the same period in 2007. Acquisitions the Company
completed during 2008 that were incorporated into the well servicing segment contributed $34.7 million to the
increase, and the full year impact of the acquisitions the Company completed during 2007 was approximately
$134.9 million. Also leading to higher revenues during 2008 was the expansion of our cased-hole wireline
business (approximately $14.3 million) and the continuing expansion of our operations for PEMEX in Mexico
(approximately $38.2 million). Additionally, the Company implemented price increases during the second and
third quarters of 2008 across most of the markets in which the Company operates, leading to higher revenues.
Partially offsetting these increases in revenues for the well servicing segment during 2008 were the effects of
hurricanes Ike and Gustav during the third quarter, which restricted the Company’s well servicing operations
in Texas, Louisiana, and Oklahoma. The Company estimates that this negatively impacted well servicing
segment revenue by approximately $7.0 million during 2008.
Direct operating expenses, excluding depreciation and amortization expense, for the well servicing
segment were $939.9 million during 2008, which was an increase of $201.2 million, or 27.2%, from the same
period in 2007. These costs were 62.3% of revenue during 2008, up from 58.4% during 2007. The increase in
direct costs for the well servicing segment resulted from (in millions):
Change from 2007
Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplies, equipment and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Self-insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$110.9
48.9
24.6
3.1
13.7
$201.2
Employee compensation for the well servicing segment, which includes salaries, cash bonuses, health
insurance, 401(k) fees and payroll taxes, increased $110.9 million during 2008 compared to the same period in
2007. Acquisitions made by the Company during 2008 that were incorporated into the well servicing segment
44
contributed approximately $13.9 million to the increase, and the incorporation of acquisitions made during
2007 for a full year of operations during 2008 contributed approximately $57.4 million to the increase. Also
contributing to the increase in employee compensation for the well servicing segment was the expansion of
our cased-hole wireline business (approximately $3.6 million) and the Company’s international operations in
Mexico (approximately $7.4 million). Additionally, during the third quarter of 2008 the Company incurred
approximately $2 million in retroactive union wage increases in Argentina that it will likely be unable to
recover from our customers. Excluding these items, direct employee compensation increased approximately
5.7% during 2008, mainly due to organic growth and wage rate increases made throughout the course of the
year in order to maintain a quality workforce.
Supplies, equipment and maintenance costs for the well servicing segment were approximately $222.5 million
for the year ended December 31, 2008, which was an increase of approximately $48.9 million, or 28.2%, compared
to the same period in 2007. Acquisitions the Company made during 2008 contributed approximately $4.0 million
to the increase and the incorporation of acquisitions the Company made during 2007 for a full twelve months of
operations in 2008 contributed approximately $24.5 million to the increase. Absent these items, these costs
increased approximately $20.4 million, or 11.8%, from 2007. This increase was due primarily to higher prices
being charged by vendors, especially for certain chemicals used in the well servicing process.
Fuel costs for the well servicing segment increased approximately $24.6 million, or 43.7%, to $80.7 million
for the year ended December 31, 2008 compared to the year ended December 31, 2007. Acquisitions the
Company made during 2008 contributed approximately $1.3 million to the increase in fuel costs and the
incorporation of acquisitions made during 2007 for a full twelve months during 2008 contributed approximately
$3.6 million to the increase. Absent acquisitions, fuel costs have increased primarily as a result of higher usage
due to increased utilization and the per gallon price of fuel. The Company estimates that on average, the per-
gallon price of diesel increased approximately 27.5% during 2008 compared to 2007.
Self-insurance costs for the well servicing segment increased approximately $3.1 million, or 15.8%,
during 2008 compared to the same period in 2007. Acquisitions the Company made during 2008 and the
incorporation of acquisitions the Company made during 2007 for a full year of operations during 2008
contributed to the increase, primarily due to the costs of insuring increased headcount. These increases were
offset by better safety performance resulting in a lower number of incidents.
Pressure pumping segment
Revenues for the Company’s pressure pumping segment were approximately $345.0 million for the year
ended December 31, 2008, which represents an increase of $45.6 million, or 15.2%, from revenues of
$299.3 million for the same period in 2007. The acquisition of the Leader assets during the third quarter of
2008 contributed approximately $9.6 million to the increase in pressure pumping segment revenues. Excluding
the effects of acquisitions, revenues for the pressure pumping segment increased approximately $36.1 million,
or 12.0%, during 2008. This increase was driven primarily by the incremental equipment added by the
Company over the course of the year, as well as price increases implemented during the second quarter of
2008. However, during the fourth quarter of 2008, the Company’s pressure pumping segment began to
experience significant pricing pressure and began to increase the discounts offered to customers in order to
preserve market share. Revenues during 2008 were also negatively impacted by a decline in the number of
cementing and acid jobs performed, but these declines were partially offset by an increase in the number of
coiled tubing jobs as a result of several coiled tubing units being placed in service during late 2008 in addition
to the coiled tubing units acquired from Leader.
Direct operating expenses, excluding depreciation and amortization expense, for the pressure pumping
segment were approximately $239.9 million during 2008, which represents an increase of $50.2 million, or
26.5%, from the same period in 2007. Excluding depreciation and amortization, direct operating expenses of
the pressure pumping segment were 69.5% of revenue during 2008 and 63.4% of revenue during 2007. The
increase in the pressure pumping segment’s direct operating expenses as a percentage of revenue was primarily
attributable to pricing pressures during the second half of 2008 combined with increasing supply costs during
45
2008 for fuel and proppants. The increase in direct operating expenses for the pressure pumping segment
resulted from (in millions):
Change from 2007
Frac sand and chemicals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplies, equipment and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$29.5
8.1
7.2
3.6
1.8
$50.2
Frac sand and chemical costs for the pressure pumping segment increased approximately $29.5 million, or
34.0%, to $115.9 million during 2008 compared to $86.4 million during 2007. The acquisition of the Leader
assets during the third quarter of 2008 contributed approximately $0.7 million to the increase in these costs during
2008. Absent the effect from the Leader asset purchase, costs for frac sand and chemicals increased during 2008
primarily due to higher commodity prices, as well as higher prices being charged by shippers to transport the
sand. In addition, during 2008 the pressure pumping segment began using coated sand as a proppant in certain
high-pressure frac jobs in the Barnett Shale formation. Using coated sand is more costly than normal sand, but
allows the pressure pumping segment to charge a higher rate to its customers to cover the additional cost.
Employee compensation for the pressure pumping segment, which is comprised of salaries, cash bonuses,
health insurance, 401(k) fees and payroll taxes, increased approximately $8.1 million during 2008 compared to
the same period in 2007. The Leader asset purchase during the third quarter of 2008 contributed approximately
$2.4 million to the increase in direct employee compensation for the pressure pumping segment. Absent the
effects of the Leader asset purchase, direct employee compensation for the pressure pumping segment
increased $5.6 million, or 14.1%, during 2008. This increase was the result of the addition of several frac and
coiled tubing crews during the year in order to meet customer demand, and wage rate increases given
throughout the course of the year in order to maintain a high quality workforce.
Fuel costs for the pressure pumping segment increased approximately $7.2 million or 48.9% during 2008
to $22.0 million compared to $14.8 million for the same period in 2007. The acquisition of the Leader assets
during the third quarter of 2008 contributed approximately $0.5 million to the increase. Absent the effects of
the Leader asset purchase, the primary driver in the increase in fuel is the per gallon price of diesel; the
Company estimates that on average the price of diesel rose approximately 27.5% during 2008. Other factors
driving the increase in fuel costs are higher activity levels during 2008.
Supplies, equipment and maintenance costs for our pressure pumping segment increased $3.6 million, or
9.5%, during 2008 compared to 2007. The increase in these costs is attributable to the acquisition of the Leader
fixed assets during 2008, higher prices from the Company’s vendors, and increased requirements for repairs and
maintenance associated with the overall increase in utilization of our pressure pumping assets during 2008.
Fishing and rental segment
Revenues for the Company’s fishing and rental segment were approximately $117.3 million for the year
ended December 31, 2008, which represented an increase of $19.4 million, or 19.8%, from revenues of
$97.9 million for the same period in 2007. The acquisition of Hydra-Walk during the second quarter of 2008
contributed approximately $6.9 million to the increase in revenues. Excluding the effects of the acquisition,
fishing and rental segment revenues increased $12.5 million, or 12.8%, from the same period in 2007. The
increase in revenues is attributable to price increases implemented during the second quarter of 2008 as well
as a higher number of reverse unit and fishing jobs during 2008 compared to 2007. Partially offsetting these
increased revenues were the effects of hurricanes in the Gulf Coast region during the second and third quarters
of 2008, which significantly restricted the segment’s operations in the Gulf of Mexico.
Direct operating expenses, excluding depreciation and amortization expense, for the fishing and rental
segment were $70.6 million during 2008, which was an increase of $13.3 million, or 23.3%, from 2007. The
acquisition of Hydra-Walk during 2008 contributed approximately $3.2 million to the increase in direct
46
operating expenses. Excluding depreciation and amortization expense, direct operating expenses for the fishing
and rental segment were 60.2% of revenue during 2008 and 58.5% of revenue during 2007. The increase in
direct operating expenses resulted from (in millions):
Change from 2007
Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplies, equipment and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 6.5
5.5
1.6
(0.3)
$13.3
Employee compensation expenses, which include salaries, bonuses, insurance, 401(k) fees and payroll
taxes, increased approximately $6.5 million during 2008 compared to the same period in 2007. The acquisition
of Hydra-Walk during 2008 contributed approximately $2.2 million to the increase in employee compensation.
Absent the effects of the acquisition, employee compensation increased as the segment added personnel to
keep pace with increased demand, and also resulted from wage rate increases given throughout the course of
the year in order to maintain a quality workforce.
Supplies, equipment and maintenance for the fishing and rental segment were approximately $24.0 million
during 2008, which represents an increase of approximately $5.5 million, or 29.6% from 2007. The acquisition
of Hydra-Walk during 2008 contributed approximately $1.0 million to the increase in these costs. Other
increases in these costs were attributable to a larger asset fleet and higher activity levels.
Fuel for the fishing and rental segment increased approximately $1.6 million, or 47.9%, during 2008
compared to the same period in 2007. The acquisition of Hydra-Walk contributed approximately $0.3 million
to the increase in fuel costs during 2008. The remainder of the increase is attributable to increased activity
levels and an increase in the per-gallon price of diesel. The Company estimates that on average, the per-gallon
price of diesel increased approximately 27.5% during 2008.
Year Ended December 31, 2007 and 2006
The following table shows the results of operations for each of the Company’s reportable segments for
the years ended December 31, 2007 and 2006:
Segments
Well Servicing
Year Ended December 31,
2007
2006
Change
(In thousands, except for percentages)
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses, as a percentage of revenue . . . .
$1,264,797
738,694
$1,201,228
725,008
$63,569
13,686
58.4%
60.4%
Pressure Pumping
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses, as a percentage of revenue . . . .
$ 299,348
189,645
$ 247,489
138,377
$51,859
51,268
63.4%
55.9%
Fishing and Rental
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses, as a percentage of revenue . . . .
$
97,867
57,275
$
97,460
57,217
$
407
58
58.5%
58.7%
Well servicing segment
Well servicing segment revenue increased $63.5 million, or 5.3%, to $1.26 billion for the year ended
December 31, 2007, compared to revenue of $1.20 billion for the year ended December 31, 2006. The increase
47
in revenue is largely attributable to the impact of the acquisition of Moncla, which contributed $23.6 million,
$9.0 million from our contract with PEMEX in Mexico and $13.7 million in higher revenue from our cased-
hole electric wireline operations. The remainder of the increase is a result of the full-year impact of pricing
increases implemented during the second half of 2006, though revenues were affected by declines in activity
levels and reductions from overall peak pricing in the second half of 2007. During the year ended
December 31, 2007, our rig hours decreased 7.9% compared to the year ended December 31, 2006 and our
trucking hours decreased 2.9% during the comparable period. The decrease in both rig and trucking hours was
due primarily to lost market share to new market entrants.
Well servicing direct operating expenses increased $13.7 million, or 2.0%, to $738.7 million for the year
ended December 31, 2007, compared to $725.0 million for the year ended December 31, 2006. Acquisitions
made during 2007 contributed approximately $16.0 million to the increase in direct operating expenses.
Excluding the effect of acquisitions, well servicing direct operating expenses increased as a result of higher
employee compensation costs of $17.2 million. Compensation-related expenses increased due to the need to
retain our workforce. As a result of new equipment capacity in the marketplace, the demand for labor was
strong and we implemented programs to retain our personnel, including higher wage rates. Partially offsetting
the increased compensation costs was a $22.8 million decrease in costs associated with our self-insurance
programs. These costs, which include workers’ compensation, vehicular liability exposure and insurance
premiums declined primarily as a result of improved safety performance and fewer and less severe incidents in
2007 compared to 2006. Other well servicing direct expenses increased approximately $3.3 million.
Pressure pumping segment
Pressure pumping segment revenue increased $51.9 million, or 21.0%, to $299.3 million for the year
ended December 31, 2007, compared to revenue of $247.5 million for the year ended December 31, 2006. The
increase in revenue is attributable to the purchase of incremental pressure pumping equipment and higher
activity levels, but was offset somewhat by lower pricing in 2007. Over the course of 2006 and 2007 we
purchased additional new pressure pumping equipment to service and satisfy our customers’ needs, increasing
the size of our fleet. The new equipment resulted in additional services performed, which resulted in higher
revenue during 2007. During 2007, we completed 2,152 fracturing jobs and 2,074 cementing jobs as compared
to 1,585 and 1,958, respectively, in 2006. Fracturing and cementing jobs accounted for the substantial majority
of the segment revenue.
Direct operating expenses increased $51.3 million, or 37.0%, to $189.6 million for the year ended
December 31, 2007, compared to $138.4 million for the year ended December 31, 2006. The increase in direct
operating expenses is largely attributable to costs associated with increased demand for pressure pumping
services and the increased size of our pressure pumping fleet. During 2007, costs related to employee
compensation for the pressure pumping segment increased $8.8 million due primarily to expansion of our
pressure pumping fleet through the introduction of new equipment, which required us to hire additional
personnel and increased wage rates for our crews. Our equipment costs increased $13.2 million from 2006
primarily due to the expansion of our pressure pumping fleet. Additionally, sand, chemical and associated
freight costs increased approximately $29.3 million during 2007. These costs relate to the purchase of sand
and chemicals used in our operations from our various suppliers and the shipment to our pressure pumping
facilities and job locations. As activity levels in our pressure pumping segment increased in 2007, we used
greater amounts of sand and chemicals. Additionally, as overall activity in the pressure pumping sector
increased during 2007, the costs for the materials and their transportation increased.
Fishing and rental segment
Fishing and rental segment revenue totaled $97.9 million for the year ended December 31, 2007,
compared to revenue of $97.5 million for the year ended December 31, 2006. Although the segment benefited
from additional rental equipment in 2007, these equipment additions were offset somewhat by lower overall
pricing. Fishing and rental segment direct operating expenses were flat at $57.3 million for the year ended
December 31, 2007, compared to $57.2 million for the year ended December 31, 2006.
48
LIQUIDITY AND CAPITAL RESOURCES
Current Financial Condition and Liquidity
The following table summarizes our cash flows for the years ended December 31, 2008 and 2007:
Year Ended December 31,
2008
2007
(In thousands)
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash paid for capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash paid for short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from the sale of short-term investments . . . . . . . . . . . . . . . . . . . .
Investment in Geostream . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions, net of cash acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of fixed assets from asset purchases. . . . . . . . . . . . . . . . . . . . .
Other investing activities, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from long-term debt, net of cash paid for debt issance costs. . . . .
Repayments of capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . .
Borrowings under revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . .
Payments on revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repurchases of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other financing activities, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Effect of exchange rates on cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 367,164
(218,994)
$ 249,919
(212,560)
— (121,613)
183,177
—
(157,955)
—
6,104
461,600
(424,751)
—
—
(30,454)
16,845
(184)
276
(19,306)
(63,457)
(34,468)
6,875
—
(11,506)
172,813
(35,000)
(139,358)
5,081
4,068
Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . .
$ 34,188
$ (29,872)
Cash flow from operating activities increased approximately $117.2 million, which was primarily the
result of growth in revenues and earnings during 2008. Cash flows related to accounts receivable increased and
vendor payments were also managed more effectively. While we have not yet experienced collectibility issues
on receivable balances from our customers in excess of historical norms, a reduction in commodity prices may
increase the credit risk associated with our customer payments. The deterioration and uncertainty of the global
economy and the resulting impact on oil and natural gas prices may also have an impact on our customer’s
ability to pay for our services in 2009. We actively monitor our customers’ ability to pay for our services and
have and will take appropriate actions with respect to collectibility issues as circumstances dictate.
Cash flow used in investing activities increased $26.2 million in 2008 compared to the same period in
2007. For the past three years, we have devoted significant amounts of our cash flow from operations to
support organic growth. From the beginning of 2006 through December 31, 2008, we have cumulatively
invested approximately $627.4 million in our rig fleet and equipment, which does not include expenditures for
acquisitions. Capital expenditures for the year ended December 31, 2008 were $219.0 million, excluding
acquisitions. During 2008, we completed four acquisitions for approximately $98.2 million in the aggregate,
net of cash acquired. Cash used in investing activities also increased from 2007 to 2008 due to the Company’s
investment in Geostream in the fourth quarter of 2008 and the sale of the Company’s marketable securities in
the fourth quarter of 2007. The Company expects its capital expenditure program for 2009 to decrease from
2008 and total approximately $130.0 million. Our focus in 2009 will be maintaining and maximizing the
utilization of our existing asset base.
Cash used in financing activities during 2008 also increased due to the repurchase of approximately
$139.4 million of our common stock. In 2007, our Board of Directors authorized a share repurchase program
of up to $300 million which is effective through March 31, 2009. From the inception of the program through
December 31, 2008, we have repurchased approximately 13.4 million shares of our common stock for
approximately $167.3 million. Our share repurchase program, as well as the amount and timing of future
repurchases, is subject to market conditions and our financial condition and liquidity. Our Senior Secured
49
Credit Facility permits share repurchases up to $200.0 million and provides that share repurchases in excess of
$200.0 million can be made if our debt to capitalization ratio is below 50%. As of December 31, 2008, we
would have been permitted to make share repurchases in excess of $200.0 million.
Cash outflows from financing activities during 2008 were partially offset by increased proceeds from
borrowings on the revolving portion of our Senior Secured Credit Facility. During 2008, we borrowed
approximately $172.8 million under the revolving portion of our Senior Secured Credit Facility to finance our
acquisitions, fund our initial investment in Geostream and for general corporate purposes. During 2008, we
paid down approximately $35.0 million on our outstanding borrowings under the Senior Secured Credit
Facility.
As of December 31, 2008, we had net working capital (excluding the current portion of long-term debt,
notes payable to affiliates, and capital lease obligations of $25.7 million) of $311.5 million. Net working
capital at December 31, 2007 (excluding the current portion of long-term debt, notes payable to affiliates, and
capital lease obligations of $12.4 million) was $265.4 million. Our working capital increased from
December 31, 2007 to December 31, 2008 primarily as a result of increases in our cash and cash equivalents
and accounts receivable balances associated with incremental revenues from our acquisitions, higher pricing
during 2008 and higher values for our sand inventories due to higher pricing for commodities and freight
costs, offset by a decline in our income tax refund receivable and increases in our current accrued liabilities.
As of December 31, 2008, approximately $16.9 million of our cash and cash equivalents was held in bank
accounts of our foreign subsidiaries, representing approximately 20.3% of total cash and cash equivalents. Of
the total amount held by our foreign subsidiaries as of December 31, 2008, approximately $8.9 million was
held by our Argentinean subsidiary, with $5.6 million of that amount being held in U.S. bank accounts and
denominated in U.S. Dollars; $0.8 million was located in Canada; approximately $7.1 million was held by our
Mexican subsidiary, with $1.1 million of that amount being held in U.S. bank accounts; and the remaining
$0.1 million located in other countries. We do not believe that the repatriation of any of our cash balances
held by our foreign subsidiaries would cause material withholdings. We maintain our cash in bank deposit and
brokerage accounts which exceed federally insured limits. As of December 31, 2008, accounts were guaranteed
by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 and substantially all of the Company’s
accounts held deposits in excess of the FDIC limits.
We believe our current financial condition is strong. As of December 31, 2008, we had $92.7 million in
cash and cash equivalents, and working capital, excluding the current portion of long-term debt, notes payable
to affiliates and capital lease obligations, of $311.5 million. As of December 31, 2008, $187.8 million of
borrowings were outstanding under our revolving credit facility and $53.6 million of letters of credit issued
under the letter of credit sub-facility were outstanding, which also reduces the total borrowing capacity under
the Senior Secured Credit Facility. We have $139.3 million of availability under our Senior Secured Credit
Facility. The availability under our Senior Secured Credit Facility reflects a reduction of approximately
$19.3 million of unfunded commitments by Lehman Commercial Paper, Inc. (“LCPI”), a subsidiary of Lehman
Brothers Holdings (“Lehman”), one of the members in the syndicate of banks participating in our Senior
Secured Credit Facility. We do not believe that the reduction in the available capacity under the Senior
Secured Credit Facility has had or will have a material impact on the Company’s liquidity. Our borrowing
level at December 31, 2008 represents the highest amount of outstanding borrowings incurred by us during
2008. See “Senior Secured Credit Facility” under “Sources of Liquidity and Capital Resources” below in this
“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further
discussion of LCPI.
50
At December 31, 2008, our annual debt maturities for our Senior Notes, borrowings under our Senior
Secured Credit Facility, notes payable to affiliates and other indebtedness were as follows (in millions):
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Principal Payments
(In thousands)
$ 16,500
3,015
2,000
189,813
—
425,000
Total principal payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
636,328
At December 31, 2008, the Company is in compliance with all the covenants required under our Senior
Notes and the Senior Secured Credit Facility. See “Sources of Liquidity and Capital Resources” and “Liquidity
Outlook and Future Capital Requirements” in this “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations” for further discussion of the Senior Notes and the Senior
Secured Credit Facility.
Sources of Liquidity and Capital Resources
The Company’s sources of liquidity include our current cash and cash equivalents, availability under our
Senior Secured Credit Facility, and internally generated cash flows from operations. During the fourth quarter
of 2007, we refinanced our indebtedness and issued the Senior Notes, using the proceeds from that issuance to
retire our then-existing senior credit facility. We also entered into our current Senior Secured Credit Facility
during the fourth quarter of 2007. See “Note 12. Long-Term Debt” in “Item 8. Consolidated Financial
Statements and Supplementary Data” for further detail.
8.375% Senior Notes
On November 29, 2007, we issued the Senior Notes. The Senior Notes were priced at 100% of their face
value to yield 8.375%. Net proceeds, after deducting initial purchasers’ fees and offering expenses, were
approximately $416.1 million. We used approximately $394.9 million of the net proceeds to retire our term
loans, including accrued and unpaid interest, under our then-existing senior credit facility.
The Senior Notes are general unsecured senior obligations of Key. Accordingly, they rank effectively
subordinate to all of our existing and future secured indebtedness. The Senior Notes are jointly and severally
guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. Interest on
the Senior Notes is payable on June 1 and December 1 of each year. The Senior Notes mature on December 1,
2014.
On or after December 1, 2011, the Senior Notes will be subject to redemption at any time and from time
to time at our option, in whole or in part, upon not less than 30 nor more than 60 days’ notice, at the
redemption prices (expressed as percentages of the principal amount redeemed) set forth below, plus accrued
and unpaid interest thereon to the applicable redemption date, if redeemed during the twelve-month period
beginning on December 1 of the years indicated below:
Year
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage
104.19%
102.09%
100.00%
Notwithstanding the foregoing, at any time and from time to time before December 1, 2010, we may, on
any one or more occasions, redeem up to 35% of the aggregate principal amount of the outstanding Senior
Notes at a redemption price of 108.375% of the principal amount thereof, plus accrued and unpaid interest
thereon to the redemption date, with the net cash proceeds of any one or more equity offerings; provided that
51
at least 65% of the aggregate principal amount of the Senior Notes issued under the indenture remains
outstanding immediately after each such redemption; and provided, further, that each such redemption shall
occur within 180 days of the date of the closing of such equity offering.
In addition, at any time and from time to time prior to December 1, 2011, we may, at our option, redeem
all or a portion of the Senior Notes at a redemption price equal to 100% of the principal amount thereof plus
the applicable premium (as defined in the Indenture) with respect to the Senior Notes and plus accrued and
unpaid interest thereon to the redemption date. If we experience a change of control, subject to certain
exceptions, we must give holders of the Senior Notes the opportunity to sell to us their Senior Notes, in whole
or in part, at a purchase price equal to 101% of the aggregate principal amount thereof, plus accrued and
unpaid interest thereon to the date of purchase.
We are subject to certain negative covenants under the Indenture governing the Senior Notes. The
indenture limits our ability to, among other things:
(cid:129) sell assets;
(cid:129) pay dividends or make other distributions on capital stock or subordinated indebtedness;
(cid:129) make investments;
(cid:129) incur additional indebtedness or issue preferred stock;
(cid:129) create certain liens;
(cid:129) enter into agreements that restrict dividends or other payments from our subsidiaries to us;
(cid:129) consolidate, merge or transfer all or substantially all of our assets;
(cid:129) engage in transactions with affiliates; and
(cid:129) create unrestricted subsidiaries.
These covenants are subject to certain exceptions and qualifications, and contain cross-default provisions
in connection with the covenants of our Senior Secured Credit Facility. In addition, substantially all of the
covenants will terminate before the Senior Notes mature if one of two specified ratings agencies assigns the
Senior Notes an investment grade rating in the future and no events of default exist under the Indenture. Any
covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored,
even if the credit rating assigned to the Senior Notes later falls below an investment grade rating.
In connection with the sale of the Senior Notes, the Company entered into a registration rights agreement
with the initial purchasers, pursuant to which it agreed to file an exchange offer registration statement with the
SEC with respect to an offer to exchange the Senior Notes for substantially identical notes that would be
registered under the Securities Act, and to use reasonable best efforts to cause such registration statement to
become effective on or prior to November 29, 2008. In accordance with the agreement, the Company filed an
exchange offer registration statement with the SEC, which became effective on August 22, 2008, and offered
to exchange an aggregate principal amount of $425.0 million of registered 8.375% Senior Notes due 2014,
which the Company refers to as the exchange notes, for any and all of our original unregistered 8.375% Senior
Notes due 2014 that were issued in a private offering on November 29, 2007. The terms of the exchange notes
were substantially identical to those terms of the original notes, except that transfer restrictions, registration
rights and additional interest provisions relating to the originally issued notes did not apply to the exchange
notes. References to the “Senior Notes” herein includes exchange notes issued in the exchange offer.
Senior Secured Credit Facility
Simultaneously with the closing of the offering of the Senior Notes, the Company entered into a new
credit agreement with several lenders that provides for a senior secured credit facility (the “Senior Secured
Credit Facility”) consisting of a revolving credit facility, letter of credit sub-facility and swing line facility of
up to an aggregate principal amount of $400.0 million, all of which will mature no later than November 29,
2012. All obligations under the Senior Secured Credit Facility are guaranteed by most of our subsidiaries and
52
are secured by most of our assets, including our accounts receivable, inventory and equipment. The Senior
Secured Credit Facility and the obligations thereunder are secured by substantially all of the assets of the
Company and are or will be guaranteed by certain of the Company’s existing and future domestic subsidiaries.
The Senior Secured Credit Facility replaced the Company’s Prior Credit Facility, which was terminated in
connection with the closing of the offering of the Senior Notes.
The interest rate per annum applicable to amounts borrowed under the Senior Secured Credit Facility are,
at the Company’s option, (i) LIBOR plus the applicable margin or (ii) the higher of (x) Bank of America’s
prime rate and (y) the Federal Funds rate plus 0.5%, plus the applicable margin. The applicable margin for
LIBOR loans ranges from 150 to 200 basis points, and the applicable margin for all other loans ranges from
50 to 100 basis points, both of which depend upon the Company’s consolidated leverage ratio. The one-month
LIBOR rate at December 31, 2008 was 0.43625%.
The Senior Secured Credit Facility contains certain financial covenants, which, among other things,
require the maintenance of a consolidated leverage ratio not to exceed 3.50 to 1.00 and a consolidated interest
coverage ratio of not less than 3.00 to 1.00, and limit the Company’s capital expenditures to $250.0 million
per fiscal year, up to 50% of which amount may be carried over for expenditure in the following fiscal year.
Each of the ratios referred to above will be calculated quarterly on a consolidated basis for each trailing four
fiscal quarter period. In addition, the Senior Secured Credit Facility contains certain affirmative and negative
covenants, including, without limitation, restrictions on (i) liens; (ii) debt, guarantees and other contingent
obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets;
(v) loans, acquisitions, joint ventures and other investments (with acquisitions permitted so long as, after
giving pro forma effect thereto, no default or event of default exists under the Senior Secured Credit Facility,
the consolidated leverage ratio does not exceed 2.75 to 1.00, the Company is in compliance with the
consolidated interest coverage ratio and the Company has at least $25 million of availability under the Senior
Secured Credit Facility); (vi) dividends and other distributions to, and redemptions and repurchases from,
equity holders; (vii) prepaying, redeeming or repurchasing subordinated (contractually or structurally) debt;
(viii) granting negative pledges other than to the lenders; (ix) changes in the nature of the Company’s business;
(x) amending organizational documents, or amending or otherwise modifying any debt, any related document
or any other material agreement if such amendment or modification would have a material adverse effect; and
(xi) changes in accounting policies or reporting practices; in each of the foregoing cases, with certain
exceptions. The Senior Secured Credit Facility also contains cross-default provisions in connection with the
covenants of the Senior Notes. Further, the Senior Secured Credit Facility permits share repurchases up to
$200.0 million and provides that share repurchases in excess of $200.0 million can be made only if our debt
to capitalization ratio is below 50%.
The Company may prepay the Senior Secured Credit Facility in whole or in part at any time without
premium or penalty, subject to certain reimbursements to the lenders for breakage and redeployment costs.
On September 15, 2008, Lehman filed for bankruptcy protection under Chapter 11 of the United States
Bankruptcy Code. A subsidiary of Lehman, LCPI, was a member of the syndicate of banks participating in
our Senior Secured Credit Facility. LCPI’s commitment was approximately 11% of the Company’s total
facility.
Moncla Notes Payable
In connection with the acquisition of Moncla, we entered into two notes payable with its former owners
(each, a “Moncla Note” and, collectively, the “Moncla Notes”). The first Moncla Note is an unsecured note in
the amount of $12.5 million, which is due and payable in a lump-sum, together with accrued interest, on
October 25, 2009. Interest on this note is due on each anniversary of the closing date, which was October 25,
2007. The second Moncla Note is an unsecured note in the amount of $10.0 million is payable in annual
installments of $2.0 million, plus accrued interest, beginning October 25, 2008 through 2012. Each of the
Moncla Notes bears interest at the Federal Funds rate adjusted annually on the anniversary of the closing date
of the Moncla acquisition.
53
Capital Lease Agreements
We lease equipment, such as vehicles, tractors, trailers, frac tanks and forklifts, from financial institutions
under master lease agreements. As of December 31, 2008, there was approximately $23.1 million outstanding
under such equipment leases.
Off-Balance Sheet Arrangements
At December 31, 2008 we did not, and we currently do not, have any off-balance sheet arrangements that
have or are reasonably likely to have a material current or future effect on our financial condition, revenues or
expenses, results of operations, liquidity, capital expenditures or capital resources.
Liquidity Outlook and Future Capital Requirements
Set forth below is a summary of our contractual obligations as of December 31, 2008. The obligations we
pay in future periods reflect certain assumptions, including variability in interest rates on our variable-rate
obligations and the duration of our obligations, and actual payments in future periods may vary.
Payments Due by Period
Total
Less than 1 Year
(2009)
1-3 Years
(2010-2012)
(In thousands)
4-5 Years
(2013-2014)
After 5 Years
(2015+)
8.375% Senior Notes due 2014 . . . . . . . . . . $425,000
Interest associated with 8.375% Senior
$
—
$
— $425,000
$ —
Notes due 2014 . . . . . . . . . . . . . . . . . . . .
213,668
35,595
106,883
71,190
Borrowings under Senior Secured Credit
Facility . . . . . . . . . . . . . . . . . . . . . . . . . .
187,813
—
187,813
—
—
—
—
—
Interest associated with Senior Secured
Credit Facility(1) . . . . . . . . . . . . . . . . . . .
Commitment and availability fees associated
with Senior Secured Credit Facility . . . . .
Notes payable — related party, excluding
14,238
3,507
10,731
2,480
620
discount . . . . . . . . . . . . . . . . . . . . . . . . .
20,500
14,500
Interest associated with notes payable —
related party(1) . . . . . . . . . . . . . . . . . . . .
484
304
1,860
6,000
180
Capital lease obligations, excluding interest
and executory costs . . . . . . . . . . . . . . . . .
Interest and executory costs associated with
capital lease obligations(1) . . . . . . . . . . . .
Other long-term indebtedness . . . . . . . . . . .
Interest associated with other long-term
indebtedness . . . . . . . . . . . . . . . . . . . . . .
Investment in Geostream Services
Group(2) . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cancellable operating leases . . . . . . . . .
FIN 48 liabilities . . . . . . . . . . . . . . . . . . . . .
Equity based compensation liability
awards(3) . . . . . . . . . . . . . . . . . . . . . . . .
Earnout payments(4) . . . . . . . . . . . . . . . . . .
Sand purchse contract(5) . . . . . . . . . . . . . . .
23,149
9,386
13,440
323
2,577
3,015
70
15,900
28,229
5,600
2,556
26,500
5,176
1,248
2,000
60
15,900
6,312
3,200
898
6,000
2,545
1,274
1,015
10
—
14,242
1,800
1,658
20,500
2,631
55
—
—
—
5,639
600
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2,036
—
—
—
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $976,955
$102,075
$370,037
$502,807
$2,036
(1) Interest costs on our floating rate debt were estimated using the rates in effect at December 31, 2008.
54
(2) Based on the December 31, 2008 exchange rate.
(3) Based on the Company’s stock price at December 31, 2008.
(4) These amounts assume certain performance targets will be achieved.
(5) These amounts assume the minimum required purchase and price for the remaining two years of the
contract.
We believe that our internally generated cash flow from operations and current reserves of cash and cash
equivalents are sufficient to finance the majority of our cash requirements for current and future operations,
budgeted capital expenditures and debt service for 2009. As we have historically done, the Company may,
from time to time, access available funds under its Senior Secured Credit Facility to supplement its liquidity to
meet its cash requirements for day to day operations and times of peak needs throughout the year. Our planned
capital expenditures as well as any acquisitions we choose to pursue, are expected to be financed through a
combination of cash on hand, cash flow from operations and borrowings under our Senior Secured Credit
Facility.
As of February 23, 2009, we had $53.6 million of letters of credit issued under the letter of credit sub-
facility and approximately $658.3 million of total debt, notes payable and capital leases. As of February 23,
2009 we had cash on hand of $149.7 million and available borrowing capacity of $139.3 million under our
Senior Secured Credit facility. This availability reflects the reduction of approximately $19.3 million of
unfunded commitments by LCPI. As of February 23, 2009, approximately $13.5 million of our cash and cash
equivalents was held in the bank accounts of our foreign subsidiaries, with $5.5 million of that amount being
held in U.S. bank accounts and denominated in U.S. Dollars. We believe that these balances could be
repatriated for general corporate use without material withholdings.
Our Senior Secured Credit Facility and Senior Notes contain numerous covenants that govern our ability
to make domestic and international investments and to repurchase our stock. Even if we experience a more
severe downturn in our business, we believe that the covenants related to our capital spending and our
investments in our foreign subsidiaries are within our control. Therefore, we believe we can avoid a default of
these covenants.
Our Senior Secured Credit Facility also requires us to maintain certain financial performance levels. The
financial covenants are as follows:
(cid:129) Consolidated Interest Coverage Ratio — As calculated pursuant to the terms of the Senior Secured
Credit Facility, we are required to maintain a ratio of trailing four quarters earnings before interest, tax,
depreciation and amortization (“EBITDA”) to interest expense of at least 3.0 to 1.0. At December 31,
2008, the calculated consolidated interest coverage ratio was 11.8 to 1.0. Management believes that the
Company will remain in compliance with this covenant through at least the end of 2009.
(cid:129) Consolidated Leverage Ratio — As calculated pursuant to the terms of the Senior Secured Credit
Facility, we are required to maintain a ratio of total debt to trailing four quarters EBITDA of no greater
than 3.5 to 1.0. At December 31, 2008, the calculated consolidated leverage ratio was 1.4 to 1.0. With
total qualifying debt of $712.9 million at December 31, 2008, this covenant requires that our trailing
four quarters EBITDA meet a minimum threshold of $203.7 million. Management believes that the
Company will remain in compliance with the covenant through at least the end of 2009. Should the
trailing four quarter EBITDA fall below the required threshold in the future, management may also
utilize cash on hand to reduce debt outstanding to lower the EBITDA minimum and maintain
compliance with this covenant.
A breach of any of these covenants, ratios or tests could result in a default under our indebtedness. See
“Item 1A. Risk Factors.”
Although continued deterioration of market conditions could lead to a downgrade in the credit ratings of
companies in our industry, a downgrade of Key’s credit rating would not have an effect on our outstanding
debt under either the Senior Secured Credit Facility or the Senior Notes, but would potentially impact our
ability to obtain additional external financing, if it was required.
55
During 2009, management plans to continue to invest in our business through capital expenditures, albeit
at levels lower than in prior years. Our capital expenditure program for 2009 is expected to total approximately
$130.0 million, of which approximately $50.0 million had already been committed, either on order or to fulfill
customer requests, as of December 31, 2008; however, that amount is subject to market conditions, including
activity levels, commodity prices and industry capacity. Our focus in 2009 will be maximizing the utilization
of our current equipment; however, we may seek to increase our 2009 capital expenditure budget in the event
international expansion opportunities develop. We currently plan to fund these expenditures through a
combination of cash on hand, operating cash flows and borrowings under our Senior Secured Credit Facility.
Should our operating cash flows prove to be insufficient to fund these expenditures, management expects it
will adjust capital spending plans accordingly.
In the fourth quarter of 2009, we are required to make principle payments totaling $14.5 million related
to the Moncla Notes. These payments represent a lump sum payment of one Moncla Note totaling
$12.5 million and a $2.0 million annual installment payment on the second Moncla Note. We expect to fund
our obligations under the Moncla Notes through cash on hand generated by operating activities or borrowings
under our Senior Secured Credit Facility.
On October 31, 2008, we acquired a 26% interest in Geostream for $17.4 million. Geostream is based in
the Russian Federation and provides drilling and workover services and sub-surface engineering and modeling
in the Russian Federation. We are contractually required to purchase an additional 24% of Geostream no later
than March 31, 2009 for approximately A11.3 million (which at December 31, 2008 was equivalent to
$15.9 million). For a period not to exceed six years subsequent to October 31, 2008, we have the option to
increase our ownership percentage of Geostream to 100%. If we have not acquired 100% of Geostream on or
before the end of the six-year period, we will be required to arrange an initial public offering for those shares.
We expect to fund our obligation to Geostream through cash on hand generated by operating cash flows or
from borrowings under our Senior Secured Credit Facility.
While management anticipates that 2009 may be a period of lower demand and prices for our services,
we believe that our operating cash flow, cash on hand and available borrowings, coupled with our ability to
control our capital expenditures, will be sufficient to maintain adequate liquidity throughout 2009.
CRITICAL ACCOUNTING POLICIES
Our Accounting Department is responsible for the development and application of our accounting policies
and internal control procedures. It reports to the principal financial officer.
The process and preparation of our financial statements in conformity with generally accepted accounting
principles in the United States (“GAAP”) requires our management to make certain estimates, judgments and
assumptions, which may affect reported amounts of our assets and liabilities, disclosures of contingencies at
the balance sheet date, the amounts of revenues and expenses recognized during the reporting period and the
presentation of our statement of cash flows for the period ended. We may record materially different amounts
if these estimates, judgments and assumptions change or if actual results differ. However, we analyze our
estimates, assumptions and judgments based on our historical experience and various other factors that we
believe to be reasonable under the circumstances.
As such, we have identified the following critical accounting policies that require a significant amount of
estimation and judgment to accurately present our financial position, results of operations and cash flows:
(cid:129) Estimate of reserves for workers’ compensation, vehicular liability and other self-insured reserves;
(cid:129) Accounting for contingencies;
(cid:129) Accounting for income taxes;
(cid:129) Estimate of fixed asset depreciable lives;
(cid:129) Valuation of tangible and intangible assets; and
(cid:129) Valuation of equity-based compensation.
56
Workers’ Compensation, Vehicular Liability and Other Self-Insurance Reserves
Well servicing and workover operations expose our employees to hazards generally associated with the
oilfield. Heavy lifting, moving equipment and slippery surfaces can cause or contribute to accidents involving
our employees and third parties who may be present at a site. Environmental conditions in remote domestic oil
and natural gas basins range from extreme cold to extreme heat, from heavy rain to blowing dust. Those
conditions can also lead to or contribute to accidents. Our business activities incorporate significant numbers
of fluid transport trucks, other oilfield vehicles and supporting rolling stock that move on public and private
roads. Vehicle accidents are a significant risk for us. We also conduct contract drilling operations, which
present additional hazards inherent in the drilling of wells, such as blowouts, explosions and fires, which could
result in loss of hole, damaged equipment and personal injury.
As a contractor, we also enter into master service agreements with our customers. These agreements
subject us to potential contractual liabilities common in the oilfield.
All of these hazards and accidents could result in damage to our property or a third party’s property or
injury or death to our employees or third parties. Although we purchase insurance to protect against large
losses, much of the risk is retained in the form of large deductibles or self-insured retentions.
The occurrence of an event not fully insured or indemnified against, or the failure of a customer or
insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, there
can be no assurance that insurance will be available to cover any or all of these risks, or that, if available, it
could be obtained without a substantial increase in premiums. It is possible that, in addition to higher
premiums, future insurance coverage may be subject to higher deductibles and coverage restrictions.
Based on the risks discussed above, we estimate our liability arising out of potentially insured events,
including workers’ compensation, employer’s liability, vehicular liability, and general liability, and record
accruals in our consolidated financial statements. Reserves related to claims covered by insurance are based on
the specific facts and circumstances of the insured event and our past experience with similar claims. Loss
estimates for individual claims are adjusted based upon actual claim judgments, settlements and reported
claims. The actual outcome of these claims could differ significantly from estimated amounts.
We are largely self-insured for physical damage to our equipment, automobiles and rigs. Our accruals that
we maintain on our consolidated balance sheet relate to these deductibles and self-insured retentions, which
we estimate through the use of historical claims data and trend analysis. The actual outcome of any claim
could differ significantly from estimated amounts. We adjust loss estimates in the calculation of these accruals,
based upon actual claim settlements and reported claims.
Accounting for Contingencies
In addition to our workers’ compensation, vehicular liability and other self-insurance reserves, we record
other loss contingencies, which relate to numerous lawsuits, claims, proceedings and tax-related audits in the
normal course of our operations on our consolidated balance sheet. In accordance with SFAS No. 5,
Accounting for Contingencies (“SFAS 5”), we record a loss contingency for these matters when it is probable
that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss
contingencies routinely to ensure that we have appropriate liabilities recorded on the balance sheet. We adjust
these liabilities based on estimates and judgments made by management with respect to the likely outcome of
these matters, including the effect of any applicable insurance coverage for litigation matters. Our estimates
and judgments could change based on new information, changes in laws or regulations, changes in
management’s plans or intentions, the outcome of legal proceedings, settlements or other factors. Actual
results could vary materially from these reserves.
We record liabilities when environmental assessment indicates that site remediation efforts are probable
and the costs can be reasonably estimated. We measure liabilities based, in part, on relevant past experience,
currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements.
Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of
such liability or the low amount in a range of estimates. These assumptions involve the judgments and
estimates of management, and any changes in assumptions or new information could lead to increases or
decreases in our ultimate liability, with any such changes recognized immediately in earnings.
57
Under the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), we
record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded
at a discount when we incur the liability. Significant judgment is involved in estimating our future cash flows
associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount
or timing of the cash flows change, the change may have a material impact on our results of operations.
Accounting for Income Taxes
We follow SFAS No. 109, Accounting for Income Taxes (“SFAS 109”), which requires that we account
for deferred income taxes using the asset and liability method and provide income taxes for all significant
temporary differences. Management determines our current tax liability as well as taxes incurred as a result of
current operations, yet deferred until future periods. Current taxes payable represent our liability related to our
income tax return for the current year, while net deferred tax expense or benefit represents the change in the
balance of deferred tax assets and liabilities reported on our consolidated balance sheets. Management
estimates the changes in both deferred tax assets and liabilities using the basis of assets and liabilities for
financial reporting purposes and for enacted rates that management estimates will be in effect when the
differences reverse. Further, management makes certain assumptions about the timing of temporary tax
differences for the differing treatment of certain items for tax and accounting purposes or whether such
differences are permanent. The final determination of our tax liability involves the interpretation of local tax
laws, tax treaties, and related authorities in each jurisdiction as well as the significant use of estimates and
assumptions regarding the scope of future operations and results achieved and the timing and nature of income
earned and expenditures incurred.
We establish valuation allowances to reduce deferred tax assets if we determine that it is more likely than
not (e.g., a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized
in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income,
as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation
allowance is required. Such evidence can include our current financial position, our results of operations, both
actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the
current and forecasted business economics of our industry. Additionally, we record reserves for uncertain tax
positions that are subject to management judgment related to the resolution of the tax positions and completion
of audits by tax authorities in the domestic and international tax jurisdictions in which we operate.
Please see “Note 11. Income Taxes” in “Item 8. Consolidated Financial Statements and Supplementary
Data,” for further discussion of accounting for our income taxes, changes in our valuation allowance,
components of our tax rate reconciliation and realization of loss carryforwards.
Estimates of Depreciable Lives
We use the estimated depreciable lives of our long-lived assets, such as rigs, heavy-duty trucks and
trailers, to compute depreciation expense, to estimate future asset retirement obligations and to conduct
impairment tests. We base the estimates of our depreciable lives on a number of factors, such as the
environment in which the assets operate, industry factors including forecasted prices and competition, and the
assumption that we provide the appropriate amount of capital expenditures while the asset is in operation to
maintain economical operation of the asset and prevent untimely demise to scrap. The useful lives of our
intangible assets are determined by the years over which we expect the assets to generate a benefit based on
legal, contractual or other expectations.
We depreciate our operational assets over their depreciable lives to their salvage value, which is 10% of
the acquisition cost. We recognize a gain or loss upon ultimate disposal of the asset.
We periodically analyze our estimates of the depreciable lives of our fixed assets to determine if the
depreciable periods and salvage value continue to be appropriate. We also analyze useful lives and salvage
value when events or conditions occur that could shorten the remaining depreciable life of the asset. We
review the depreciable periods and salvage values for reasonableness, given current conditions. As a result, our
depreciation expense is based upon estimates of depreciable lives of the fixed assets, the salvage value and
58
economic factors, all of which require management to make significant judgments and estimates. If we
determine that the depreciable lives should be different than originally estimated, depreciation expense may
increase or decrease and impairments in the carrying values of our fixed assets may result.
Valuation of Intangible and Tangible Assets
The Company periodically reviews its intangible assets not subject to amortization, including goodwill, to
determine whether an impairment of those assets may exist. SFAS 142 requires that these tests be made on at
least an annual basis, or more often if circumstances indicate that the assets may be impaired. These
circumstances include, but are not limited to, significant adverse changes in the business climate.
The test for impairment of indefinite-lived intangibles is a two step test. In the first step of the test, a fair
value is calculated for each of the Company’s reporting units, and that fair value is compared to the carrying
value of the reporting unit, including the reporting unit’s goodwill. If the fair value of the reporting unit
exceeds its carrying value, there is no impairment, and the second step of the test is not performed. If the
carrying value exceeds the fair value for the reporting unit, then the second step of the test is required.
The second step of the test compares the implied fair value of the reporting unit’s goodwill to its carrying
value. The implied fair value of the reporting unit’s goodwill is determined in the same manner as the amount
of goodwill recognized in a business combination, with the purchase price being equal to the fair value of the
reporting unit. If the implied fair value of the reporting unit’s goodwill is in excess of its carrying value, no
impairment is recorded. If the carrying value is in excess of the implied fair value, an impairment equal to the
excess is recorded.
The Company conducts its annual impairment test for goodwill on December 31 of each year. In
determining the fair value of the Company’s reporting units, management uses a weighted-average approach of
three commonly used valuation techniques — a discounted cash flow method, a guideline companies method,
and a similar transaction method. The Company’s management assigns a weight to the results of each of these
methods based on the facts and circumstances that are in existence for that testing period. During 2008,
because of the acquisitions and international investments made by the Company over the prior two years and
the overall economic downturn and the decline in the Company’s stock price and market valuation during
2008, management assigned more weighting to the discounted cash flow method than other methods. In prior
years the Company had assigned higher weightings to the guideline companies method.
In addition to the estimates made by management regarding the weighting of the various valuation
techniques, the creation of the techniques themselves requires significant estimates and assumptions to be
made by management. The discounted cash flow method, which is assigned the highest weight by
management, requires assumptions about future cash flows, future growth rates, and discount rates. The
assumptions about future cash flows and growth rates are based on the Company’s budgets and strategic plans,
as well as the beliefs of management about future activity levels. Discount rate assumptions include an
assessment of the specific risk associated with the reporting unit being tested. To assist management in the
preparation and analysis of the valuation of the Company’s reporting units, management utilized the services
of a third-party valuation consultant, who reviewed management’s estimates, assumptions and calculations.
The ultimate conclusions of the valuation techniques remain the sole responsibility of the Company’s
management. While this test is required on an annual basis, it also can be required more frequently based on
changes in external factors. While we do not currently expect that additional tests would result in an additional
charge, the fair value used in the test is heavily impacted by the market prices of our equity and debt
securities, and could result in impairment charges in the future.
Unlike goodwill and indefinite-lived intangible assets, fixed assets and finite-lived intangibles are not
tested for impairment on a recurring basis, but only when circumstances or events indicate that a possible
impairment may exist. These circumstances or events are referred to as “trigger events” and examples of such
trigger events include, but are not limited to, an adverse change in market conditions, a significant decrease in
benefits being derived from an acquired business, or a significant disposal of a particular asset or asset class.
59
If a trigger event occurs, an impairment test pursuant to the guidelines established by SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”), is performed based on an
undiscounted cash flow analysis. To perform an impairment test, we make judgments, estimates and
assumptions regarding long-term forecasts of revenues and expenses relating to assets subject to review.
Market conditions, energy prices, estimated depreciable lives of the assets, discount rate assumptions and legal
factors impact our operations and have a significant effect on the estimates of management.
Using different judgments, these estimates could differ significantly and actual financial results could
differ materially from these estimates. These long-term forecasts are used in the impairment tests to determine
if an asset’s carrying value is recoverable or if a write-down to fair value is required. If the analysis determines
that the assets of a reporting unit or asset grouping are impaired, then an impairment charge is recorded.
Valuation of Equity-Based Compensation
We account for share based compensation under the provisions of SFAS No. 123 (revised 2004), Share-
Based Payment (“SFAS 123(R)”), which we adopted on January 1, 2006. We adopted the provisions of
SFAS 123(R) using the modified prospective transition method. The Company has granted stock options,
stock-settled stock appreciation rights (“SARs”), restricted stock (“RSAs”), and phantom shares (“Phantom
Shares”) to its employees and non-employee directors. Option and SAR awards granted by the Company are
fair valued using a Black-Scholes option model and are amortized to compensation expense over the vesting
period of the option award, net of estimated and actual forfeitures. Compensation related to RSAs is based on
the fair value of the award on the grant date and is recognized based on the vesting requirements that have
been satisfied during the period. Phantom Shares are accounted for at fair value, and changes in the fair value
of these awards are recorded as compensation expense during the period. Please see “Note 17. Share-Based
Compensation” in “Item 8. Consolidated Financial Statements and Supplementary Data” for further discussion
of the various award types and our accounting for our equity-based compensation.
In utilizing the Black-Scholes option pricing model to determine fair values of awards, certain
assumptions are made which are based on subjective expectations, and are subject to change. A change in one
or more of these assumptions would impact the expense associated with future grants. These key assumptions
include the volatility of our common stock, the risk-free interest rate and the expected life of awards.
We used the following weighted average assumptions in the Black-Scholes option pricing model for
determining the fair value of our stock option grants during the years ended December 31, 2008, 2007 and
2006:
Year Ended December 31,
2008
2006
2007
Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected life of options, years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected volatility of the Company’s stock price . . . . . . . . . . . . . . . . . . . .
Expected dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6
2.86% 4.41% 4.70%
6
36.86% 39.49% 48.80%
none
none
none
6
We calculate the expected volatility for our stock option grants by measuring the volatility of our
historical stock price for a period equal to the expected life of the option and ending at the time the option
was granted. We determine the risk-free interest rate based upon the interest rate on a U.S. Treasury Bill with
a term equal to the expected life of the option at the time the option was granted. In estimating the expected
lives of our stock options, we have relied primarily on our actual experience with our previous stock option
grants. The expected life is less than the term of the option as option holders, in our experience, exercise or
forfeit the options during the term of the option.
We are not required to recalculate the fair value of our stock option grants estimated using the Black-
Scholes option pricing model after the initial calculation unless the original option grant terms are modified.
However, a 100 basis point increase in our expected volatility and risk-free interest rate at the grant date
would have increased our compensation expense for the year ended December 31, 2008 by approximately
$1.0 million.
60
New Accounting Standards Adopted in this Report
FIN 48 and FSP FIN 48-1.
In June 2006, the Financial Accounting Standards Board (“FASB”) issued
FASB Interpretation (“FIN”) No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB
Statement No. 109 (“FIN 48”), which provides clarification of SFAS 109 with respect to the recognition of
income tax benefits of uncertain tax positions in financial statements. FIN 48 requires that uncertain tax
positions be reviewed and assessed, with recognition and measurement of the tax benefit based on a “more
likely than not” standard.
In May 2007 the FASB issued FASB Staff Position (“FSP”) FIN 48-1 (“FSP FIN 48-1”). FSP FIN 48-1
provides guidance on how an enterprise should determine whether a tax position is effectively settled for the
purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position has been
effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination
procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a
completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any
aspect of a taxing position. FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48.
We adopted the provisions of FIN 48 and FSP FIN 48-1 on January 1, 2007 and recorded a $1.3 million
decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of
adopting these standards.
FSP EITF 00-19-2.
In December 2006, the FASB issued FSP EITF 00-19-2, Accounting for Registration
Payment Arrangements (“FSP EITF 00-19-2”). FSP EITF 00-19-2 addresses accounting for Registration
Payment Arrangements (“RPAs”), which are provisions within financial instruments such as equity shares,
warrants or debt instruments in which the issuer agrees to file a registration statement and to have that
registration statement declared effective by the SEC within a specified grace period. If the registration
statement is not declared effective within the grace period or its effectiveness is not maintained for the period
of time specified in the RPA, the issuer must compensate its counterparty. The FASB Staff concluded that the
contingent obligation to make future payments or otherwise transfer consideration under a RPA should be
recognized as a liability and measured in accordance with SFAS 5 and FIN No. 14, Reasonable Estimation of
the Amount of a Loss, and that the RPA should be recognized and measured separately from the instrument to
which the RPA is attached.
In January 1999, the Company completed the private placement of 150,000 units consisting of $150.0 million
of 14% Senior Subordinated Notes due January 25, 2009 (the “14% Senior Subordinated Notes”) and 150,000
warrants to purchase an aggregate of approximately 2.2 million shares of the Company’s common stock at an
exercise price of $4.88125 per share (the “Warrants”). Under the terms of the Warrants, we were required to
maintain an effective registration statement covering the shares of common stock issuable upon exercise of the
Warrants. Due to our past failure to file our SEC reports in a timely manner, we did not have an effective
registration statement covering the Warrants, and were required to make liquidated damages payments. The
requirement to make liquidated damages payments constituted an RPA under the provisions of FSP EITF 00-19-2,
and as prescribed by the transition provisions of that standard, on January 1, 2007 the Company recorded a pre-tax
current liability of approximately $1.0 million, which is equivalent to the payments for the Warrant RPA for one
year, with an offsetting adjustment to the opening balance of retained earnings.
SFAS 157.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”),
effective for periods beginning on or after January 1, 2008. SFAS 157 establishes a framework for measuring
fair value and requires expanded disclosure about the information used to measure fair value. The statement
applies whenever other statements require or permit assets or liabilities to be measured at fair value, and does
not expand the use of fair value accounting in any new circumstances. The adoption of this standard did not
have a material impact on our consolidated financial statements.
SFAS 159. The Company adopted Statement of Financial Accounting Standards No. 159, The Fair Value
Option for Financial Assets and Liabilities, including an amendment of FASB Statement No. 115 (“SFAS 159”),
on January 1, 2008. SFAS 159 permits companies to choose, at specified election dates, to measure eligible
items at fair value (the “Fair Value Option”). Companies choosing such an election report unrealized gains and
61
losses on items for which the Fair Value Option has been elected in earnings at each subsequent reporting
period. We did not elect to measure any of our financial assets or liabilities using the Fair Value Option. We
will assess at each measurement date whether to use the Fair Value Option on any future financial assets or
liabilities as permitted pursuant to the provisions of SFAS 159.
FSP SFAS 157-3.
In October 2008, the FASB issued FSP SFAS No. 157-3, Determining the Fair Value
of a Financial Asset When the Market for That Asset Is Not Active (“FSP 157-3”). FSP SFAS 157-3 clarified
the application of SFAS 157. FSP SFAS 157-3 demonstrated how the fair value of a financial asset is
determined when the market for that financial asset is inactive. FSP SFAS 157-3 was effective upon issuance,
including prior periods for which financial statements had not been issued. The implementation of this
standard did not have a material impact on our consolidated financial statements.
Accounting Standards Not Yet Adopted in this Report
FSP SFAS 142-3.
In April 2008, the FASB issued FSP SFAS No. 142-3, Determination of Useful Life of
Intangible Assets (“FSP 142-3”). FSP SFAS 142-3 amends the factors that should be considered in developing
the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under
SFAS 142. FSP SFAS 142-3 also requires expanded disclosure regarding the determination of intangible asset
useful lives. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. We are currently
evaluating the potential impact the adoption of FSP SFAS 142-3 will have on our consolidated financial
statements.
SFAS 161.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments
and Hedging Activities (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and requires qualitative
disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value
amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent
features in derivative agreements. This statement is effective for financial statements issued for fiscal periods
beginning after November 15, 2008. The Company currently has no financial instruments that qualify as
derivatives, and we do not expect that the adoption of this standard will have a material impact on the
Company’s financial position, results of operations and cash flows.
FSP SFAS 157-2.
In February 2008, the FASB issued FSP SFAS No. 157-2, Effective Date of FASB
Statement No. 157 (“FSP 157-2”), to partially defer SFAS 157. FSP 157-2 defers the effective date of
SFAS 157 for nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at
fair value in the financial statements on a recurring basis (at least annually), to fiscal years, and interim
periods within those fiscal years, beginning after November 15, 2008. We are currently evaluating the impact
of adopting the provisions of SFAS 157 as it relates to nonfinancial assets and liabilities.
SFAS 141(R).
In December 2007, the FASB issued SFAS No. 141 (Revised 2007), Business Combina-
tions (“SFAS 141(R)”). SFAS 141(R) establishes principles and requirements for how an acquirer in a business
combination recognizes and measures in its financial statements the identifiable assets acquired, liabilities
assumed and any noncontrolling interests in the acquiree, as well as the goodwill acquired. Significant changes
from current practice resulting from SFAS 141(R) include the expansion of the definitions of a “business” and
a “business combination.” For all business combinations (whether partial, full or step acquisitions), the acquirer
will record 100% of all assets and liabilities of the acquired business, including goodwill, at their fair values;
contingent consideration will be recognized at its fair value on the acquisition date and, for certain
arrangements, changes in fair value will be recognized in earnings until settlement; and acquisition-related
transaction and restructuring costs will be expensed rather than treated as part of the cost of the acquisition.
SFAS 141(R) also establishes disclosure requirements to enable users to evaluate the nature and financial
effects of the business combination. SFAS 141(R) applies prospectively to business combinations for which
the acquisition date is on or after the beginning of the first annual reporting period beginning on or after
December 15, 2008. SFAS 141(R) may have an impact on our consolidated financial statements. The nature
and magnitude of the specific impact will depend upon the nature, terms, and size of the acquisitions
consummated after the effective date.
62
SFAS 160.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements — An amendment of ARB No. 51 (“SFAS 160”). SFAS 160 amends Accounting Research
Bulletin No. 51, Consolidated Financial Statements, to establish accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a
noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is a third-party
ownership interest in the consolidated entity that should be reported as a component of equity in the
consolidated financial statements. Among other requirements, SFAS 160 requires the consolidated statement of
income to be reported at amounts that include the amounts attributable to both the parent and the
noncontrolling interest. SFAS 160 also requires disclosure on the face of the consolidated statement of income
of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest.
SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after
December 15, 2008. Earlier adoption is not permitted. We are currently evaluating the potential impact of this
statement.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to certain market risks as part of our ongoing business operations, including risks from
changes in interest rates, foreign currency exchange rates and equity prices that could impact our financial
position, results of operations and cash flows. We manage our exposure to these risks through regular
operating and financing activities, and may, on a limited basis, use derivative financial instruments to manage
this risk. To the extent that we use such derivative financial instruments, we will use them only as risk
management tools and not for speculative investment purposes.
Interest Rate Risk
As of December 31, 2008, we had outstanding $425.0 million of 8.375% Senior Notes due 2014. These
notes are fixed-rate obligations, and as such do not subject us to risks associated with changes in interest rates.
Borrowings under our Senior Secured Credit Facility, our capital lease obligations, and the Moncla Notes all
bear interest at variable interest rates, and therefore expose us to interest rate risk. As of December 31, 2008,
the weighted average interest rate on our outstanding variable-rate debt obligations was 4.17%. A hypothetical
10% increase in that rate would increase the annual interest expense on those instruments by approximately
$0.5 million.
Foreign Currency Risk
As of December 31, 2008, we conduct operations in Argentina and Mexico, and also own Canadian
subsidiaries and have equity-method investments in a Canadian company and a Russian company. The
functional currency is the local currency for all of these entities, and as such we are exposed to the risk of
changes in the exchange rates between the U.S. Dollar and the local currencies. For balances denominated in
our foreign subsidiaries’ local currency, changes in the value of the subsidiaries’ assets and liabilities due to
changes in exchange rates are deferred and accumulated in other comprehensive income until we liquidate our
investment. For balances denominated in currencies other than the local currency, our foreign subsidiaries must
remeasure the balance at the end of each period to an equivalent amount of local currency, with changes
reflected in earnings during the period. A hypothetical 10% decrease in the average value of the U.S. Dollar
relative to the value of the local currencies for our Argentinean, Mexican and Canadian subsidiaries and our
Canadian and Russian investments would decrease our net income by approximately $1.3 million.
Equity Risk
We account for our equity-based compensation awards at fair value under the provisions of SFAS 123(R).
Certain of these awards’ fair values are determined based upon the price of the Company’s common stock on
the measurement date. Any increase in the price of the Company’s common stock would lead to a
corresponding increase in the fair value of those awards. A 10% increase in the price of the Company’s
common stock from its value at December 31, 2008 would increase annual compensation expense recognized
on these awards by approximately $0.1 million.
63
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Key Energy Services, Inc. and Subsidiaries
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Report of Independent Registered Public Accounting Firm on Internal Control over Financial
Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Comprehensive Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Cash Flows. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Stockholders’ Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
65
66
67
68
69
70
71
72
64
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders of
Key Energy Services, Inc.
We have audited the accompanying consolidated balance sheets of Key Energy Services, Inc. and
subsidiaries (a Maryland corporation) as of December 31, 2008 and 2007, and the related consolidated
statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the three
years in the period ended December 31, 2008. These financial statements are the responsibility of the
Company’s management. Our responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material
respects, the financial position of Key Energy Services, Inc. and subsidiaries as of December 31, 2008 and
2007, and the results of their operations and their cash flows for each of the three years in the period ended
December 31, 2008 in conformity with accounting principles generally accepted in the United States of
America.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2007, the Company
adopted the provisions of Financial Accounting Standards Interpretation No. 48, Accounting for Uncertainty in
Income Taxes.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2007, the Company
adopted the provisions of FSP EITF 00-19-2, Accounting for Registration Payment Arrangements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of Key Energy Services, Inc. and subsidiaries’ internal control over
financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and
our report dated February 24, 2009 expressed an adverse opinion on the effectiveness of internal control over
financial reporting.
/s/ GRANT THORNTON LLP
Houston, Texas
February 24, 2009
65
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders of
Key Energy Services, Inc.
We have audited Key Energy Services, Inc.’s and subsidiaries (a Maryland Corporation) internal control
over financial reporting as of December 31, 2008, based on criteria established in Internal Control —
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO). Key Energy Services, Inc. and subsidiaries’ management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the effectiveness of internal control over
financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial
Reporting. Our responsibility is to express an opinion on Key Energy Services, Inc. and subsidiaries’ internal
control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing
the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk, and performing such other procedures as we considered necessary
in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
A material weakness is a deficiency, or combination of control deficiencies, in internal control over
financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s
annual or interim financial statements will not be prevented or detected on a timely basis. The following
material weakness has been identified and included in management’s assessment.
Payroll: The Company determined that deficiencies surrounding its payroll process, in particular, lack of
proper documentation concerning hours worked, employee master file data and rate changes coupled with
deficiencies with reconciliations where payroll or payroll related data was a major component, constituted a
material weakness in its system of internal controls.
In our opinion, because of the effect of the material weakness described above on the achievement of the
objectives of the control criteria, Key Energy Services, Inc. and subsidiaries have not maintained effective
internal control over financial reporting as of December 31, 2008, based on criteria established in Internal
Control — Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets, statements of operations, comprehensive income,
stockholders’ equity, and cash flows of Key Energy Services, Inc. and subsidiaries. The material weakness
identified above was considered in determining the nature, timing, and extent of audit tests applied in our audit
of the 2008 consolidated financial statements, and this report does not affect our report dated February 24,
2009, which expressed an unqualified opinion on those consolidated financial statements.
/s/ GRANT THORNTON LLP
Houston, Texas
February 24, 2009
66
Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
December 31,
2007
2008
(In thousands, except
share amounts)
Current assets:
ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Accounts receivable, net of allowance for doubtful accounts of $11,468 and
92,691
$
58,503
377,353
$13,501, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34,756
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15,513
Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
26,623
Deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,848
Income taxes receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,338
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
559,122
Total current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,858,307
Property and equipment, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(806,624)
Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,051,683
Property and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
320,992
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
42,345
Other intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,489
Deferred financing costs, net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
336
Notes and accounts receivable — related parties . . . . . . . . . . . . . . . . . . . . . . . . . .
24,220
Equity method investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,736
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,016,923
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current portion of capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current notes payable — related parties, net of discount . . . . . . . . . . . . . . . . . . .
Current portion of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital lease obligations, less current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes payable — related parties, less current portion . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, less current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Workers’ compensation, vehicular, health and other insurance claims . . . . . . . . . . .
Deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-current accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minority interest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 121,305,289
46,185
197,116
4,368
9,386
14,318
2,000
273,373
13,763
6,000
613,828
43,151
188,581
17,495
—
343,408
22,849
12,997
27,676
15,796
6,636
487,865
1,595,225
(684,017)
911,208
378,550
45,894
12,117
173
11,217
12,053
$1,859,077
$
35,159
183,364
3,895
10,701
1,678
—
234,797
16,114
20,500
475,000
43,818
160,068
19,531
251
and 131,142,905 shares issued and outstanding, respectively . . . . . . . . . . . . . .
12,131
601,872
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(46,550)
Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
293,279
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total stockholders’ equity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
860,732
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY . . . . . . . . . . . . . . . $2,016,923
13,114
704,644
(37,981)
209,221
888,998
$1,859,077
See the accompanying notes which are an integral part of these consolidated financial statements
67
Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,972,088
COSTS AND EXPENSES:
Year Ended December 31,
2006
2007
2008
(In thousands, except per share amounts)
$1,662,012
$1,546,177
Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization expense . . . . . . . . . . . . . . . . . . . .
Impairment of goodwill and equity method investment . . . . . . . . .
General and administrative expenses . . . . . . . . . . . . . . . . . . . . . .
Interest expense, net of amounts capitalized . . . . . . . . . . . . . . . . .
Loss on early extinguishment of debt. . . . . . . . . . . . . . . . . . . . . .
(Gain) loss on sale of assets, net . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other expense (income), net . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,250,327
170,774
75,137
257,707
41,247
—
(641)
(1,236)
4,717
985,614
129,623
—
230,396
36,207
9,557
1,752
(6,630)
(447)
920,602
126,011
—
195,527
38,927
—
(4,323)
(5,574)
527
Total costs and expenses, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,798,032
1,386,072
1,271,697
Income before income taxes and minority interest . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minority interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
174,056
(90,243)
245
275,940
(106,768)
117
274,480
(103,447)
—
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
84,058
$ 169,289
$ 171,033
EARNINGS PER SHARE:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
0.68
0.67
$
$
1.29
1.27
$
$
1.30
1.28
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
124,246
125,565
131,194
133,551
131,332
134,064
See the accompanying notes which are an integral part of these consolidated financial statements
68
Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $84,058
OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX:
2008
Year Ended December 31,
2007
(In thousands)
$169,289
2006
$171,033
Foreign currency translation loss, net of tax of $(952), $0, and $0,
respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net deferred (loss) gain from cash flow hedges, net of tax of $0, $(115),
and $115, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred (loss) gain from available for sale investments, net of tax of
$0, $(97), and $97, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(8,561)
(1,281)
(51)
—
(8)
(213)
(203)
213
181
COMPREHENSIVE INCOME, NET OF TAX. . . . . . . . . . . . . . . . . . . . . $75,489
$167,592
$171,376
See the accompanying notes which are an integral part of these consolidated financial statements
69
Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
2008
Year Ended December 31,
2007
(In thousands)
2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 84,058
Adjustments to reconcile net income to net cash provided by operating activities:
Minority interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion on asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from equity method investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment of goodwill and equity method investment . . . . . . . . . . . . . . . . . . . .
Amortization of deferred financing costs and discount . . . . . . . . . . . . . . . . . . . .
Deferred income tax expense. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capitalized interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Gain) loss on sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on early extinguishment of debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Share-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Excess tax benefits from share-based compensation . . . . . . . . . . . . . . . . . . . . . .
(245)
170,774
594
(160)
75,137
2,115
29,747
(6,514)
(641)
—
24,233
(1,733)
Changes in working capital:
(34,906)
(516)
(15,622)
46,375
—
—
(5,532)
367,164
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Share-based compensation liability awards . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable, accrued interest and accrued expenses . . . . . . . . . . . . . . . . . .
Income tax refund receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash paid for legal settlement with former chief executive officer . . . . . . . . . . . .
Other assets and liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of fixed assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in Geostream Services Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions, net of cash acquired of $2,017, $2,154, and $0, respectively . . . . . . . .
Acquisition of fixed assets from asset purchases . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash paid for short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from the sale of short-term investments . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CASH FLOWS FROM FINANCING ACTIVITIES:
—
Repayments of long-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
Proceeds from long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(35,000)
Payments on revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
172,813
Borrowings under revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(11,506)
Repayments of capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(3,026)
Repayments of other long-term indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
Repayments of debt assumed in acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(314)
Proceeds paid for deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(139,358)
Repurchases of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,688
Proceeds from exercise of stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,733
Excess tax benefits from share-based compensation . . . . . . . . . . . . . . . . . . . . . . . .
(7,970)
Net cash (used in) provided by financing activities . . . . . . . . . . . . . . . . . . . . . . .
4,068
Effect of exchange rates on cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34,188
Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . .
58,503
Cash and cash equivalents, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 92,691
(218,994)
7,961
(19,306)
(63,457)
(34,468)
—
276
(1,086)
(329,074)
$ 169,289
$ 171,033
(117)
129,623
585
(387)
—
1,680
24,613
(5,296)
1,752
9,557
9,355
(3,401)
(44,712)
3,701
(424)
(1,360)
(15,154)
(21,200)
(8,185)
249,919
(212,560)
8,427
—
(157,955)
—
(121,613)
183,177
(2,323)
(302,847)
(396,000)
425,000
—
50,000
(11,316)
—
(17,435)
(13,400)
(30,454)
13,444
3,401
23,240
(184)
(29,872)
88,375
$ 58,503
—
126,011
508
(416)
—
1,620
6,757
(3,358)
(4,323)
—
6,345
—
(60,801)
—
976
35,138
(642)
—
(20,124)
258,724
(195,830)
11,658
—
—
—
(83,769)
22,294
—
(245,647)
(4,000)
—
—
—
(12,975)
—
—
(479)
(1,180)
—
—
(18,634)
(238)
(5,795)
94,170
$ 88,375
See the accompanying notes which are an integral part of these consolidated financial statements
70
Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Common Stock
Number of
Shares
Amount
at par
Additional
Paid-in
Capital
Accumulated
Other
Comprehensive
(Loss) Income
Retained
(Deficit)
Earnings
Total
(In thousands)
BALANCE AT DECEMBER 31,
2005 . . . . . . . . . . . . . . . . . . . . . . . .
131,334
$13,133 $ 706,749
$(36,627)
$(129,198) $ 554,057
Comprehensive income, net of tax . .
Common stock purchases . . . . . . . . .
Share-based compensation . . . . . . . .
Tax benefits from share-based
compensation . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . .
BALANCE AT DECEMBER 31,
—
(81)
371
—
—
—
(8)
37
—
—
—
(1,172)
6,181
40
—
343
—
—
—
—
—
—
—
343
(1,180)
6,218
—
171,033
40
171,033
2006 . . . . . . . . . . . . . . . . . . . . . . . .
131,624
13,162
711,798
(36,284)
41,835
730,511
Effect of adoption of FIN 48 . . . . . .
Effect of adoption of EITF 00-19-2,
net of tax . . . . . . . . . . . . . . . . . . .
—
—
—
—
—
—
—
—
(1,272)
(1,272)
(631)
(631)
Adjusted balance, beginning of
year . . . . . . . . . . . . . . . . . . . . . .
131,624
13,162
711,798
(36,284)
39,932
728,608
Comprehensive loss, net of tax . . . . .
Common stock purchases . . . . . . . . .
Exercise of stock options . . . . . . . . .
Exercise of warrants . . . . . . . . . . . .
Share-based compensation . . . . . . . .
Tax benefits from share-based
compensation . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . .
—
(2,414)
1,592
23
318
—
—
—
(241)
159
2
32
—
—
—
(33,161)
13,285
(2)
9,323
3,401
—
(1,697)
—
—
—
—
—
(1,697)
— (33,402)
13,444
—
—
—
9,355
—
—
—
—
169,289
3,401
169,289
BALANCE AT DECEMBER 31,
2007 . . . . . . . . . . . . . . . . . . . . . . . .
131,143
13,114
704,644
(37,981)
209,221
888,998
Comprehensive loss, net of tax . . . . .
Common stock purchases . . . . . . . . .
Exercise of stock options . . . . . . . . .
Exercise of warrants . . . . . . . . . . . .
Share-based compensation . . . . . . . .
Tax benefits from share-based
compensation . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . .
BALANCE AT DECEMBER 31,
—
(11,183)
757
160
428
—
(1,118)
76
16
43
—
(135,291)
6,612
(16)
24,190
(8,569)
—
—
—
—
—
(8,569)
— (136,409)
6,688
—
—
—
24,233
—
—
—
—
—
1,733
—
—
—
—
84,058
1,733
84,058
2008 . . . . . . . . . . . . . . . . . . . . . . . .
121,305
$12,131 $ 601,872
$(46,550)
$ 293,279 $ 860,732
See the accompanying notes which are an integral part of these consolidated financial statements
71
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Key Energy Services, Inc., its wholly-owned subsidiaries and its controlled subsidiaries (collectively,
“Key,” the “Company,” “we,” “us,” “its,” and “our”) provide a complete range of well services to major oil
companies, foreign national oil companies and independent oil and natural gas production companies,
including rig-based well maintenance, workover, well completion and recompletion services, fluid management
services, pressure pumping services, fishing and rental services and ancillary oilfield services. We operate in
most major oil and natural gas producing regions of the United States as well as internationally in Argentina
and Mexico. We also own a technology development company based in Canada and have equity interests in
oilfield service companies in Canada and the Russian Federation.
Basis of Presentation
The consolidated financial statements and associated schedules included in this Annual Report on
Form 10-K present our financial position, results of operations and cash flows for the periods presented in
accordance with generally accepted accounting principles in the United States (“GAAP”).
The preparation of these consolidated financial statements requires us to develop estimates and to make
assumptions that affect our financial position, results of operations and cash flows. These estimates also impact
the nature and extent of our disclosure, if any, of our contingent liabilities. Among other things, we use
estimates to (i) analyze assets for possible impairment, (ii) determine depreciable lives for our assets,
(iii) assess future tax exposure and realization of deferred tax assets, (iv) determine amounts to accrue for
contingencies, (v) value tangible and intangible assets, (vi) assess workers’ compensation, vehicular liability,
self-insured risk accruals and other insurance reserves, (vii) provide allowances for our uncollectible accounts
receivable, and (viii) value our equity-based compensation. We review all significant estimates on a recurring
basis and record the effect of any necessary adjustments prior to publication of our financial statements.
Adjustments made with respect to the use of estimates relate to improved information not previously available.
Because of the limitations inherent in this process, our actual results may differ materially from these
estimates. We believe that our estimates are reasonable.
Certain reclassifications have been made to prior period amounts to conform to current period financial
statement classifications. We now present our short-term investments in marketable securities as a component
of other current assets in the accompanying consolidated balance sheets. In prior years, we presented these
amounts as a separate component of current assets.
We apply the provisions of Emerging Issues Task Force (“EITF”) Issue 04-10, Determining Whether to
Aggregate Operating Segments That Do Not Meet Quantitative Thresholds (“EITF 04-10”) for our segment
reporting in “Note 19. Segment Information.” Under the provisions of EITF 04-10, operating segments that do
not individually meet the aggregation criteria described in Statement of Financial Accounting Standards
(“SFAS”) No. 131, Disclosures About Segments of an Enterprise and Related Information (“SFAS 131”), may
be combined with other operating segments that do not individually meet the aggregation criteria to form a
separate reportable segment. We have combined all of our operating segments that do not individually meet
the aggregation criteria established in SFAS 131 to form the “Corporate and Other” segment in our segment
reporting.
Principles of Consolidation
Within our consolidated financial statements, we include our accounts and the accounts of our majority-
owned or controlled subsidiaries. We eliminate intercompany accounts and transactions. When we have an
interest in an entity for which we do not have significant control or influence, we account for that interest
using the cost method. When we have an interest in an entity and can exert significant influence but not
control, we account for that interest using the equity method.
72
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As further discussed in “Note 2. Acquisitions,” in September 2007 we completed the acquisition of
Advanced Measurements, Inc. (“AMI”), a privately-held Canadian company focused on oilfield technology.
Prior to the acquisition, AMI owned a portion of another Canadian company, Advanced Flow Technologies,
Inc. (“AFTI”). As part of the acquisition, AMI increased its ownership percentage of AFTI to 51.46%. At
December 31, 2007, we consolidated the assets, liabilities, results of operations and cash flows of AFTI into
our consolidated financial statements, with the portion of AFTI remaining outside of our control forming a
minority interest in our consolidated financial statements. Our ownership of AFTI declined to 48.73% during
the fourth quarter of 2008 due to the issuance of additional shares by AFTI. As a result, we deconsolidated
AFTI from our consolidated financial statements at December 31, 2008 and accounted for that interest under
the equity method.
We apply Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) No. 46, Consolidation
of Variable Interest Entities — an Interpretation of ARB No. 51 (Revised 2003) (“FIN 46(R)”) when
determining whether or not to consolidate a Variable Interest Entity (“VIE”). FIN 46(R) requires that an equity
investor in a VIE have significant equity at risk (generally a minimum of 10%) and hold a controlling interest,
evidenced by voting rights, and absorb a majority of the entity’s expected losses, receive a majority of the
entity’s expected returns, or both. If the equity investor is unable to evidence these characteristics, the entity
that retains these ownership characteristics will be required to consolidate the VIE. We have determined that
we do not have an interest in a VIE, and as such we are not the primary beneficiary of a variable interest in a
VIE and are not the holder of a significant variable interest in a VIE.
Revenue Recognition
We recognize revenue when all of the following criteria established in the Securities and Exchange
Commission (the “SEC”) Staff Accounting Bulletin (“SAB”) No. 101, Revenue Recognition in Financial
Statements (“SAB 101”), as amended by SAB No. 104, Revenue Recognition (“SAB 104”), have been met:
(i) evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price
to the customer is fixed and determinable and (iv) collectibility is reasonably assured.
(cid:129) Evidence of an arrangement exists when a final understanding between the Company and its customer
has occurred, and can be evidenced by a completed customer purchase order, field ticket, supplier
contract, or master service agreement.
(cid:129) Delivery has occurred or services have been rendered when the Company has completed what is
required pursuant to the terms of the arrangement and can be evidenced by a completed field ticket or
service log.
(cid:129) The price to the customer is fixed and determinable when the amount that is required to be paid is
agreed upon. Evidence of the price being fixed and determinable is evidenced by contractual terms, a
Company price book, a completed customer purchase order, or a completed customer field ticket.
(cid:129) Collectibility is reasonably assured as a result of the Company screening its customers and providing
goods and services to customers that have been granted credit terms in accordance with the Company’s
credit policy.
In accordance with EITF Issue No. 06-03, How Taxes Collected from Customers and Remitted to
Governmental Authorities Should be Presented in the Income Statement (That is, Gross versus Net Presenta-
tion) (“EITF 06-03”), we present our revenues net of any sales taxes collected by us from our customers that
are required to be remitted to local or state governmental taxing authorities.
73
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than three months to be cash
equivalents. None of our cash is restricted, and we have not entered into any compensating balance
arrangements. However, at December 31, 2008, all of our obligations under our Senior Secured Credit Facility
were secured by most of our assets, including assets held by our subsidiaries, which includes our cash and
cash equivalents. We restrict investment of cash to financial institutions with high credit standing and limit the
amount of credit exposure to any one financial institution.
We maintain our cash in bank deposit and brokerage accounts which exceed federally insured limits. As
of December 31, 2008, accounts were guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up
to $250,000 and substantially all of the Company’s accounts held deposits in excess of the FDIC limits.
Certain of our cash accounts are zero-balance controlled disbursement accounts that do not have right of
offset against our other cash balances. In accordance with FIN No. 39, Offsetting of Amounts Related to
Certain Contracts, an Interpretation of APB No. 10 and FASB Statement No. 105 (“FIN 39”), we present the
outstanding checks written against these zero-balance accounts as a component of accounts payable in the
accompanying consolidated balance sheets.
Investment in Debt and Equity Securities
We account for investments in debt and equity securities under the provisions of SFAS No. 115,
Accounting for Certain Investments in Debt and Equity Securities (“SFAS 115”). Under SFAS 115, investments
are classified as either “trading,” “available for sale,” or “held to maturity,” depending on management’s intent
regarding the investment.
Securities classified as “trading” are carried at fair value, with any unrealized holding gains or losses
reported currently in earnings. Securities classified as “available for sale” or “held to maturity” are carried at
fair value, with any unrealized holding gains or losses, net of tax, reported as a separate component of
shareholders’ equity in other comprehensive income.
Accounts Receivable and Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable if we determine that we will not collect all or
part of the outstanding balances. We regularly review collectibility and establish or adjust our allowance as
necessary using the specific identification method.
From time to time we are entitled to proceeds under our insurance policies, and in accordance with
FIN No. 39, we present insurance receivables gross on our balance sheet as a component of accounts
receivable, separate from the corresponding liability.
Concentration of Credit Risk and Significant Customers
Key’s customers include major oil and natural gas production companies, independent oil and natural gas
production companies, and foreign national oil and natural gas production companies. We perform ongoing
credit evaluations of our customers and usually do not require material collateral. We maintain reserves for
potential credit losses when necessary. Our results of operations and financial condition should be considered
in light of the fluctuations in demand experienced by oilfield service companies as changes in oil and gas
producers’ expenditures and budgets occur. These fluctuations can impact our results of operations and
financial condition as supply and demand factors directly affect utilization and hours which are the primary
determinants of our net cash provided by operating activities.
For all periods presented, no single customer accounted for more than ten percent of our consolidated
revenue.
74
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Inventories
Inventories, which consist primarily of equipment parts for use in our well servicing operations, sand and
chemicals for our pressure pumping operations, and supplies held for consumption, are valued at the lower of
average cost or market.
Property and Equipment
Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for
our assets over the estimated depreciable lives of the assets using the straight-line method. We depreciate our
operational assets over their depreciable lives to their salvage value, which is a fair value higher than the
assets’ value as scrap. Salvage value approximates 10% of an operational asset’s acquisition cost. When an
operational asset is stacked or taken out of service, we review its physical condition, depreciable life and
ultimate salvage value to determine if the asset is no longer operable and whether the remaining depreciable
life and salvage value should be adjusted.
. In the first quarter of 2007, management reassessed the estimated useful lives assigned to all of the
Company’s equipment in light of the higher activity and utilization levels experienced in 2006 and early 2007.
As a result, the maximum estimated useful lives of certain assets were adjusted to reflect higher annual
utilization. As a result, the useful life expected for a well service rig was reduced from an average expected
life of 17 years to 15 years. With respect to oilfield trucks, trailers and related equipment the expected life
was reduced from an average expected life of 15 years to 12 years. Management also determined that the life
assigned to a self-remanufactured well service rig should be the same as the 15-year life assigned to a newly
constructed well service rig acquired from third parties.
As of December 31, 2008, the estimated useful lives of the Company’s asset classes are as follows:
Description
Years
3-15
Well service rigs and components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7-12
Oilfield trucks, pressure pumping equipment, and related equipment . . . . . . . . . . . . . . . . . . .
3-5
Motor vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4-10
Fishing and rental tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Disposal wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15-30
Furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3-7
Buildings and improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15-30
The Company leases certain of its operating assets under capital lease obligations whose terms run from
55 to 60 months. These assets are depreciated over their estimated useful lives or the term of the capital lease
obligation, whichever is shorter.
We apply SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”)
in reviewing our long-lived assets for possible impairment. This statement requires that long-lived assets held
and used by us, including certain identifiable intangibles, be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not be recoverable. For purposes
of testing for impairment, we group our long-lived assets into divisions, which are based on geographical
regions or the services provided. We then compare the estimated future cash flows of each division to the
division’s net carrying value. The division level represents the lowest level for which identifiable cash flows
are available. We would record an impairment charge, reducing the division’s net carrying value to an
estimated fair value, if its estimated future cash flows were less than the division’s net carrying value. “Trigger
events,” as defined in SFAS 144, that cause us to evaluate our fixed assets for recoverability and possible
impairment may include changes in market conditions, such as adverse movements in the prices of oil and
natural gas, which could reduce the fair value of certain of our property and equipment. The development of
75
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
future cash flows and the determination of fair value for a division involves significant judgment and
estimates. During 2007 and 2006, no trigger events were identified by management. During the fourth quarter
of 2008, the impairment of the Company’s goodwill was identified as a trigger event by management. As a
result, an undiscounted cash flow analysis was performed for our long-lived assets, and no impairment was
indicated.
Asset Retirement Obligations
In accordance with SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), we
recognize a liability for the fair value of all legal obligations associated with the retirement of tangible long-
lived assets and capitalize an equal amount as a cost of the asset. We depreciate the additional cost over the
estimated useful life of the assets. Our obligations to perform our asset retirement activities are unconditional,
despite the uncertainties that may exist surrounding an individual retirement activity. Accordingly, we
recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be
reasonably estimated. Significant judgment is involved in estimating future cash flows associated with such
obligations, as well as the ultimate timing of those cash flows. If our estimates of the amount or timing of the
cash flows change, such changes may have a material impact on our results of operations. See “Note 7. Asset
Retirement Obligations.”
Capitalized Interest
Interest is capitalized on the average amount of accumulated expenditures for major capital projects using
an effective interest rate based on related debt until the underlying assets are placed into service. The
capitalized interest is added to the cost of the assets and amortized to depreciation and amortization expense
over the useful life of the assets. It is included in the depreciation and amortization line in the accompanying
consolidated statements of operations.
Long-Term Debt
Deferred financing costs associated with long-term debt are carried at cost and are expensed over the
term of the applicable long-term debt facility or the term of the notes. These costs are amortized to interest
expense using the effective interest method over the life of the related debt instrument. When the related debt
instrument is retired, any remaining unamortized costs are included in the determination of the gain or loss on
the extinguishment of the debt. We record gains and losses from the extinguishment of debt as a part of
continuing operations. See “Note 12. Long-Term Debt.”
Goodwill and Other Intangible Assets
Goodwill results from business combinations and represents the excess of acquisition costs over the fair
value of the net assets acquired. We account for goodwill and other intangible assets under the provisions of
SFAS No. 142, Accounting for Goodwill and Intangible Assets (“SFAS 142”). Goodwill and other intangible
assets not subject to amortization are tested for impairment annually or more frequently if events or changes
in circumstances indicate that the asset might be impaired.
The test for impairment of indefinite-lived intangibles is a two step test. In the first step of the test, a fair
value is calculated for each of the Company’s reporting units, and that fair value is compared to the carrying
value of the reporting unit, including the reporting unit’s goodwill. If the fair value of the reporting unit
exceeds its carrying value, there is no impairment, and the second step of the test is not performed. If the
carrying value exceeds the fair value for the reporting unit, then the second step of the test is required.
The second step of the test compares the implied fair value of the reporting unit’s goodwill to its carrying
value. The implied fair value of the reporting unit’s goodwill is determined in the same manner as the amount
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
of goodwill recognized in a business combination, with the purchase price being equal to the fair value of the
reporting unit. If the implied fair value of the reporting unit’s goodwill is in excess of its carrying value, no
impairment is recorded. If the carrying value is in excess of the implied fair value, an impairment equal to the
excess is recorded.
To assist management in the preparation and analysis of the valuation of the Company’s reporting units,
management utilized the services of a third-party valuation consultant, who reviewed management’s estimates,
assumptions and calculations. The ultimate conclusions of the valuation techniques remain the sole responsi-
bility of the Company’s management. The Company conducts its annual impairment test on December 31 of
each year. For the annual test completed as of December 31, 2008, an impairment of the Company’s goodwill
was indicated. While this test is required on an annual basis, it also can be required more frequently based on
changes in external factors. We do not currently expect that additional tests would result in additional charges,
but the determination of the fair value used in the test is heavily impacted by the market prices of our equity
and debt securities. See “Note 5. Goodwill and Other Intangible Assets.”
Internal-Use Software
As required by Statement of Position (“SOP”) No. 98-1, Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use (“SOP 98-1”), we capitalize costs incurred during the application
development stage of internal-use software and amortize these costs over its estimated useful life, generally
five years. Costs incurred related to selection or maintenance of internal-use software are expensed as incurred.
See “Note 4. Property and Equipment.”
Derivative Instruments and Hedging Activities
The Company applies SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities
(“SFAS 133”), as amended, in accounting for derivative instruments. SFAS 133 establishes accounting and
reporting standards for derivative instruments, including certain derivative instruments embedded in other
contracts, and hedging activities. It requires the recognition of all derivative instruments as assets and liabilities
on the balance sheet and measurement of those instruments at fair value. The accounting treatment of changes
in fair value is dependent upon whether or not a derivative instrument is designated as a hedge, and if so, the
type of hedge. To account for a financial instrument as a hedge, the contract must meet the following criteria:
the underlying asset or liability must expose a company to risk that is not offset in another asset or liability,
the hedging contract must reduce that risk, and the instrument must be properly designated as a hedge at the
inception of the contract and throughout the contract period. To be an effective hedge, there must be a high
correlation between changes in the fair value of the financial instrument and the fair value of the underlying
asset or liability, such that changes in the market value of the financial instrument would be offset by the
effect of price changes on the exposed items. For derivatives designated as cash flow hedges, the effective
portion of the change in the fair value of the hedging instrument is recognized in other comprehensive income
until the hedged item is recognized in earnings. Any ineffective portion of changes in the fair value of the
hedging instrument is recognized currently in earnings. For all derivative contracts entered into, the Company
analyzes the derivative contracts for embedded instruments and accounts for those instruments based on
current guidance.
During the years ended December 31, 2007 and 2006, the Company had interest rate swaps and foreign
currency instruments that qualified as derivative instruments under SFAS 133. During 2008, the Company had
no derivative instruments. See “Note 10. Derivative Financial Instruments” for further discussion.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Litigation
When estimating our liabilities related to litigation, we take into account all available facts and
circumstances in order to determine whether a loss is probable and reasonably estimable in accordance with
SFAS No. 5, Accounting for Contingencies (“SFAS 5”).
Various suits and claims arising in the ordinary course of business are pending against us. Due in part to
the locations where we conduct business in the continental United States, we are often subject to jury verdicts
and arbitration hearings that result in outcomes in favor of the plaintiffs. We continually assess our contingent
liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and our need for the
disclosure of these items. In accordance with SFAS 5 we establish a provision for a contingent liability when
it is probable that a liability has been incurred and the amount is able to be estimated. See “Note 13.
Commitments and Contingencies.”
Environmental
Our operations are subject to various federal, state and local laws and regulations intended to protect the
environment. Our operations routinely involve the storage, handling, transport and disposal of bulk waste
materials, some of which contain oil, contaminants, and regulated substances. Various environmental laws and
regulations require prevention, and where necessary, cleanup of spills and leaks of such materials, and some of
our operations must obtain permits limiting the discharge of materials. Failure to comply with such
environmental requirements or permits may result in fines and penalties, remediation orders and revocation of
permits. Laws and regulations have become more stringent over the years, and in certain circumstances may
impose “strict liability,” rendering us liable for environmental damage without regard to negligence or fault on
our part. Cleanup costs, penalties, and other damages arising as a result of environmental laws and costs
associated with changes in environmental laws and regulations, could be substantial and could have a material
adverse effect on our financial condition, results of operations and cash flows. From time to time, claims have
been made and litigation has been brought against us under such laws. Environmental expenditures are
expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing
condition caused by past operations and that have no future economic benefits are expensed. For environmen-
tal reserve matters, including remediation efforts for current locations and those relating to previously-disposed
properties, we record liabilities when our remediation efforts are probable and the costs to conduct such
remediation efforts can be reasonably estimated. While our litigation reserves reflect the application of our
insurance coverage, our environmental reserves do not reflect management’s assessment of the insurance
coverage that may apply to the matters at issue. See “Note 13. Commitments and Contingencies” for further
discussion.
Self Insurance
We are largely self-insured for physical damage to our equipment, automobiles and rigs. Our accruals that
we maintain on our consolidated balance sheet relate to these deductibles and self-insured retentions, which
we estimate through the use of historical claims data and trend analysis. The actual outcome of any claim
could differ significantly from estimated amounts. We adjust loss estimates in the calculation of these accruals,
based upon actual claim settlements and reported claims.
Income Taxes
In accounting for income taxes, we follow SFAS No. 109, Accounting for Income Taxes (“SFAS 109”),
which requires that we account for deferred income taxes using the asset and liability method and provide
income taxes for all significant temporary differences. Management determines our current tax liability as well
as taxes incurred as a result of current operations, but which are deferred until future periods. Current taxes
payable represent our liability related to our income tax return for the current year, while net deferred tax
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
expense or benefit represents the change in the balance of deferred tax assets and liabilities reported on our
consolidated balance sheets. Management estimates the changes in both deferred tax assets and liabilities using
the basis of assets and liabilities for financial reporting purposes and for enacted rates that management
estimates will be in effect when the differences reverse. Further, management makes certain assumptions about
the timing of temporary tax differences for the differing treatment of certain items for tax and accounting
purposes or whether such differences are permanent. The final determination of our tax liability involves the
interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction as well as the
significant use of estimates and assumptions regarding the scope of future operations and results achieved and
the timing and nature of income earned and expenditures incurred.
We establish valuation allowances to reduce deferred tax assets if we determine that it is more likely than
not (e.g., a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized
in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income,
as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation
allowance is required. Such evidence can include our current financial position, our results of operations, both
actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the
current and forecasted business economics of our industry. Additionally, we record reserves for uncertain tax
positions that are subject to management judgment related to the resolution of the tax positions and completion
of audits by tax authorities in the domestic and international tax jurisdictions in which we operate.
The Company is subject to the revised Texas Franchise tax. The revised Texas Franchise tax is an income
tax equal to one percent of Texas-sourced revenue reduced by the greater of (a) cost of goods sold (as defined
by Texas law), (b) compensation (as defined by Texas law), or (c) thirty percent of the Texas-sourced revenue.
We account for the revised Texas Franchise tax in accordance with SFAS 109, as the tax is derived from a
taxable base that consists of income less deductible expenses.
See “Note 11. Income Taxes” for further discussion of accounting for our income taxes, changes in our
valuation allowance, components of our tax rate reconciliation and realization of loss carryforwards.
Earnings Per Share
We present earnings per share information in accordance with the provisions of SFAS No. 128, Earnings
Per Share (“SFAS 128”). Under SFAS 128, basic earnings per common share is determined by dividing net
earnings applicable to common stock by the weighted average number of common shares actually outstanding
during the period. Diluted earnings per common share is based on the increased number of shares that would
be outstanding assuming conversion of dilutive outstanding convertible securities using the treasury stock and
“as if converted” methods. See “Note 6. Earnings Per Share” for further discussion.
Share-Based Compensation
We account for share-based compensation under the provisions of SFAS No. 123 (revised 2004), Share-
Based Payment (“SFAS 123(R)”), which we adopted on January 1, 2006. We adopted SFAS 123(R) using the
modified prospective transition method, and no cumulative effect was recorded on the adoption date of
SFAS 123(R). We record share-based compensation as a component of general and administrative expense.
See “Note 17. Share-Based Compensation” for further discussion.
Foreign Currency Gains and Losses
We follow a translation policy in accordance with SFAS No. 52, Foreign Currency Translation
(“SFAS 52”). In our international locations in Argentina, Mexico and Canada where the local currency is the
functional currency, assets and liabilities are translated at the rates of exchange on the balance sheet date,
while income and expense items are translated at average rates of exchange during the year. The resulting
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
gains or losses arising from the translation of accounts from the functional currency to the U.S. Dollar are
included as a separate component of stockholders’ equity in other comprehensive income until a partial or
complete sale or liquidation of our net investment in the foreign entity.
From time to time our foreign subsidiaries may enter into transactions that are denominated in currencies
other than their functional currency. These transactions are initially recorded in the functional currency of that
subsidiary based on the applicable exchange rate in effect on the date of the transaction. At the end of each
month, these transactions are remeasured to an equivalent amount of the functional currency based on the
applicable exchange rates in effect at that time. Any adjustment required to remeasure a transaction to the
equivalent amount of the functional currency at the end of the month is recorded in the income or loss of the
foreign subsidiary as a component of other income and expense. See “Note 14. Accumulated Other
Comprehensive Loss.”
Comprehensive Income
We report and display comprehensive income in accordance with SFAS No. 130, Reporting Comprehen-
sive Income (“SFAS 130”), which establishes standards for reporting and displaying comprehensive income
and its components. SFAS 130 requires enterprises to display comprehensive income and its components in the
enterprise’s financial statements, to classify items of comprehensive income by their nature in the financial
statements and to display the accumulated balance of other comprehensive income separately in shareholders’
equity.
Leases
We account for leases in accordance with SFAS No. 13, Accounting for Leases (“SFAS 13”). Certain of
our operating lease agreements are structured to include scheduled and specified rent increases over the term
of the lease agreement. These increases may be the result of an inducement or “rent holiday” conveyed to us
early in the lease, or are included to reflect the anticipated effects of inflation. We apply the provisions of
FASB Technical Bulletin (“FTB”) No. 85-3, Accounting for Operating Leases with Scheduled Rent Increases
(“FTB 85-3”), when accounting for scheduled and specified rent increases. FTB 85-3 provides that the effects
of scheduled and specified rent increases should be recognized on a straight-line basis over the lease term
unless another systematic and rational allocation basis is more representative of the time pattern in which the
leased property is physically employed. We recognize scheduled and specified rent increases on a straight-line
basis over the term of the lease agreement.
In addition, certain of our operating lease agreements contain incentives to induce us to enter into the
lease agreement, such as up-front cash payments to us, payment by the lessor of our costs, such as moving
expenses, or the assumption by the lessor of our pre-existing lease agreements with third parties. Any
payments made to us or on our behalf represent incentives that we consider to be a reduction of our rent
expense, and are recognized on a straight-line basis over the term of the lease agreement. We amortize
leasehold improvements on our operating leases over the shorter of their economic lives or the lease term.
New Accounting Standards Adopted in this Report
FIN 48 and FSP FIN 48-1.
In June 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in
Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”), which provides clarification of
SFAS 109 with respect to the recognition of income tax benefits of uncertain tax positions in financial
statements. FIN 48 requires that uncertain tax positions be reviewed and assessed, with recognition and
measurement of the tax benefit based on a “more likely than not” standard.
In May 2007 the FASB issued FASB Staff Position (“FSP”) FIN 48-1 (“FSP FIN 48-1”). FSP FIN 48-1
provides guidance on how an enterprise should determine whether a tax position is effectively settled for the
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position has been
effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination
procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a
completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any
aspect of a taxing position. FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48.
We adopted the provisions of FIN 48 and FSP FIN 48-1 on January 1, 2007 and recorded a $1.3 million
decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of
adopting these standards.
FSP EITF 00-19-2.
In December 2006, the FASB issued FSP EITF 00-19-2, Accounting for Registration
Payment Arrangements (“FSP EITF 00-19-2”). FSP EITF 00-19-2 addresses accounting for Registration
Payment Arrangements (“RPAs”), which are provisions within financial instruments such as equity shares,
warrants or debt instruments by which the issuer agrees to file a registration statement and to have that
registration statement declared effective by the SEC within a specified grace period. If the registration
statement is not declared effective within the grace period or its effectiveness is not maintained for the period
of time specified in the RPA, the issuer must compensate its counterparty. The FASB Staff concluded that the
contingent obligation to make future payments or otherwise transfer consideration under a RPA should be
recognized as a liability and measured in accordance with SFAS 5 and FIN No. 14, Reasonable Estimation of
the Amount of a Loss, and that the RPA should be recognized and measured separately from the instrument to
which the RPA is attached.
In January 1999, the Company completed the private placement of 150,000 units consisting of $150.0 million
of 14% Senior Subordinated Notes due January 25, 2009 (the “14% Senior Subordinated Notes”) and 150,000
warrants to purchase an aggregate of approximately 2.2 million shares of the Company’s common stock at an
exercise price of $4.88125 per share (the “Warrants”). Under the terms of the Warrants, we were required to
maintain an effective registration statement covering the shares of common stock issuable upon exercise of the
Warrants. Due to our past failure to file our SEC reports in a timely manner, we did not have an effective
registration statement covering the Warrants, and were required to make liquidated damages payments. The
requirement to make liquidated damages payments constituted an RPA under the provisions of FSP EITF 00-19-2,
and as prescribed by the transition provisions of that standard, on January 1, 2007 the Company recorded a pre-tax
current liability of approximately $1.0 million, which is equivalent to the payments for the Warrant RPA for one
year, with an offsetting adjustment to the opening balance of retained earnings.
SFAS 157.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”).
SFAS 157 establishes a framework for measuring fair value and requires expanded disclosure about the
information used to measure fair value. The statement applies whenever other statements require or permit
assets or liabilities to be measured at fair value, and does not expand the use of fair value accounting in any
new circumstances. The adoption of this standard did not have a material impact on our consolidated financial
statements.
SFAS 159. The Company adopted Statement of Financial Accounting Standards No. 159, The Fair Value
Option for Financial Assets and Liabilities, including an amendment of FASB Statement No. 115 (“SFAS 159”),
on January 1, 2008. SFAS 159 permits companies to choose, at specified election dates, to measure eligible
items at fair value (the “Fair Value Option”). Companies choosing such an election report unrealized gains and
losses on items for which the Fair Value Option has been elected in earnings at each subsequent reporting
period. We did not elect to measure any of our financial assets or liabilities using the Fair Value Option. We
will assess at each measurement date whether to use the Fair Value Option on any future financial assets or
liabilities as permitted pursuant to the provisions of SFAS 159.
FSP SFAS 157-3.
In October 2008, the FASB issued FSP SFAS No. 157-3, Determining the Fair Value
of a Financial Asset When the Market for That Asset Is Not Active (“FSP 157-3”). FSP 157-3 clarified the
81
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
application of SFAS 157. FSP 157-3 demonstrated how the fair value of a financial asset is determined when
the market for that financial asset is inactive. FSP 157-3 was effective upon issuance, including for prior
periods for which financial statements had not been issued. The implementation of this standard did not have a
material impact on our consolidated financial statements.
Accounting Standards Not Yet Adopted in this Report
FSP SFAS 142-3.
In April 2008, the FASB issued FSP SFAS No. 142-3, Determination of Useful Life of
Intangible Assets (“FSP 142-3”). FSP 142-3 amends the factors that should be considered in developing the
renewal or extension assumptions used to determine the useful life of a recognized intangible asset under
SFAS 142. FSP 142-3 also requires expanded disclosure regarding the determination of intangible asset useful
lives. FSP 142-3 is effective for fiscal years beginning after December 15, 2008. Earlier adoption is not
permitted. We are currently evaluating the potential impact the adoption of FSP 142-3 will have on our
consolidated financial statements.
SFAS 161.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments
and Hedging Activities (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and requires qualitative
disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value
amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent
features in derivative agreements. This statement is effective for financial statements issued for fiscal periods
beginning after November 15, 2008. Early application is encouraged. The Company currently has no financial
instruments that qualify as derivatives, and we do not expect that the adoption of this standard will have a
material impact on the Company’s financial position, results of operations and cash flows.
FSP SFAS 157-2.
In February 2008, the FASB issued FSP SFAS No. 157-2, Effective Date of FASB
Statement No. 157 (“FSP 157-2”), to partially defer SFAS 157. FSP SFAS 157-2 defers the effective date of
SFAS 157 for nonfinancial assets and non-financial liabilities, except those that are recognized or disclosed at
fair value in the financial statements on a recurring basis (at least annually), to fiscal years, and interim
periods within those fiscal years, beginning after November 15, 2008. We are currently evaluating the impact
of adopting the provisions of SFAS 157 as it relates to nonfinancial assets and liabilities.
SFAS 141(R).
In December 2007, the FASB issued SFAS No. 141 (Revised 2007), Business Combina-
tions (“SFAS 141(R)”). SFAS 141(R) establishes principles and requirements for how an acquirer in a business
combination recognizes and measures in its financial statements the identifiable assets acquired, liabilities
assumed and any noncontrolling interests in the acquiree, as well as the goodwill acquired. Significant changes
from current practice resulting from SFAS 141(R) include the expansion of the definitions of a “business” and
a “business combination.” For all business combinations (whether partial, full or step acquisitions), the acquirer
will record 100% of all assets and liabilities of the acquired business, including goodwill, at their fair values;
contingent consideration will be recognized at its fair value on the acquisition date and, for certain
arrangements, changes in fair value will be recognized in earnings until settlement; and acquisition-related
transaction and restructuring costs will be expensed rather than treated as part of the cost of the acquisition.
SFAS 141(R) also establishes disclosure requirements to enable users to evaluate the nature and financial
effects of the business combination. SFAS 141(R) applies prospectively to business combinations for which
the acquisition date is on or after the beginning of the first annual reporting period beginning on or after
December 15, 2008. SFAS 141(R) may have an impact on our consolidated financial statements. The nature
and magnitude of the specific impact will depend upon the nature, terms, and size of the acquisitions
consummated after the effective date.
SFAS 160.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements — An amendment of ARB No. 51 (“SFAS 160”). SFAS 160 amends Accounting Research
Bulletin No. 51, Consolidated Financial Statements, to establish accounting and reporting standards for the
82
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a
noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is a third-party
ownership interest in the consolidated entity that should be reported as a component of equity in the
consolidated financial statements. Among other requirements, SFAS 160 requires the consolidated statement of
income to be reported at amounts that include the amounts attributable to both the parent and the
noncontrolling interest. SFAS 160 also requires disclosure on the face of the consolidated statement of income
of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest.
SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after
December 15, 2008. Earlier adoption is not permitted. We are currently evaluating the potential impact of this
statement.
NOTE 2. ACQUISITIONS
From time to time, the Company may acquire businesses or assets that are consistent with its long-term
growth strategy. Results of operations for acquisitions are included in the Company’s financial statements
beginning from the date of acquisition. Acquisitions through December 31, 2008 are accounted for using the
purchase method of accounting and the purchase price is allocated to the assets acquired and liabilities
assumed based upon their estimated fair values at the date of acquisition. Final valuations of assets and
liabilities are obtained and recorded as soon as practicable and within one year from the date of the
acquisition. Purchase price allocations that have not yet been finalized are based on preliminary information
and are subject to change when final fair value determinations are made for the assets acquired and liabilities
assumed.
Acquisitions completed during 2008
Tri-Energy Services, LLC. On January 17, 2008, the Company purchased the fishing and rental assets of
Tri-Energy Services, LLC (“Tri-Energy”) for approximately $1.9 million in cash. These assets were integrated
into our fishing and rental segment. The equity interests of Tri-Energy are owned by employees of the
Company who joined the Company in October 2007 in connection with the earlier acquisition in 2007 of
Moncla Well Service, Inc. and related entities (collectively, “Moncla”). The purchase price was allocated to
the tangible and intangible assets purchased and the acquisition of the Tri-Energy assets was accounted for as
an asset purchase and did not result in the establishment of goodwill. The assets acquired include an
identifiable intangible asset of $1.1 million related to customer relationships and is subject to amortization
under SFAS No. 142. The asset will be amortized on a straight-line basis over two years from the acquisition
date.
Western Drilling, LLC. On April 3, 2008, the Company purchased all of the outstanding equity interests
of Western Drilling, LLC (“Western”), a privately-owned company based in California that operated 22
working well service rigs, three stacked well service rigs and equipment used in the workover and rig
relocation process. We acquired Western to increase our service footprint in the California market.
The purchase price was $51.5 million in cash and was paid on April 3, 2008. The purchase price was
subject to a working capital adjustment 45 days from the closing date of the acquisition that resulted in
additional consideration paid of $0.1 million in May 2008. The Company also incurred direct transaction costs
of approximately $0.4 million. The acquisition was funded by borrowings of $50.0 million under the
Company’s Senior Secured Credit Facility (see “Note 12. Long-Term Debt”) and cash on hand.
The acquisition of Western was accounted for as a business combination. The total purchase price was
allocated to the assets acquired and liabilities assumed based on their estimated fair values. The excess of the
purchase price over the fair value of net assets acquired was recorded as goodwill. The allocation of the
purchase price was based upon preliminary valuations and estimates, and is subject to change as the valuations
are finalized. The primary area of the purchase price allocation that is not yet finalized relates to pre-merger
83
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
contingencies. The final valuation is expected to be completed no later than the first quarter of 2009. The
following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed
on the date of the Western acquisition (in thousands):
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
687
6,839
30,162
8,166
9,000
132
54,986
2,979
Total liabilities assumed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net assets acquired. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,979
$52,007
The fair values of property and equipment were determined using a market approach. The fair values of
identified intangible assets were determined using an income approach to measure the present worth of
anticipated future economic benefits. The Company also performed an economic obsolescence analysis to
confirm the values identified through the aforementioned methods. The allocation is still preliminary at this
time, and may potentially change by a material amount once the purchase price allocation is finalized.
Goodwill was recognized as part of the acquisition of Western as the purchase price exceeded the fair
value of the acquired assets and assumed liabilities. The Company believes the goodwill associated with the
Western acquisition is related to the acquired workforce, potential future expansion of the Western service
offerings, and the ability to expand our service offerings. Therefore, it was not allocated to the acquired assets
and assumed liabilities.
The acquired identifiable intangible asset of $9.0 million is related to customer relationships and is
subject to amortization under SFAS No. 142. The customer relationships will be amortized as the value of the
relationships are realized using rates of 17%, 19%, 15%, 12%, 9%, 7%, 6%, 5%, 4%, 3%, 2% and 1% for
2008 through 2019, respectively. The $8.2 million of goodwill associated with the purchase of Western was
allocated to our well servicing segment, and the assets and results of operations subsequent to April 3, 2008
have also been integrated into the well servicing segment. Of the goodwill recorded, $8.2 million is expected
to be deductible for income tax purposes.
Hydra-Walk, Inc. On May 30, 2008, the Company purchased all of the outstanding stock of Hydra-
Walk, Inc. (“Hydra-Walk”) for approximately $10.3 million in cash and a performance earn-out of up to
$2.0 million over two years from the acquisition date if certain financial and operational performance measures
are met. Additionally, during the third quarter of 2008 the Company paid approximately $0.2 million in
additional consideration related to a holdback amount that was withheld from the seller pending the
completion of a seller closing requirement. The purchase price was also subject to a post-closing working
capital adjustment of less than $0.1 million that was paid during the third quarter of 2008. The Company
incurred direct transaction costs of approximately $0.1 million. The Company retained approximately
$1.1 million of Hydra-Walk’s net working capital as a result of the transaction and did not assume any debt of
Hydra-Walk.
Hydra-Walk is a leading provider of pipe handling solutions for the oil and gas industry and operates over
80 automated pipe handling units in Oklahoma, Texas and Wyoming. We acquired Hydra-Walk to expand the
level of integrated well servicing services we are able to provide customers. The assets and results of
operations for Hydra-Walk were integrated into our fishing and rental segment beginning on May 31, 2008.
84
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The acquisition of Hydra-Walk was accounted for as a business combination and the purchase price was
allocated to the assets acquired and liabilities assumed based on their estimated fair values. The excess of the
purchase price over the fair value of net assets acquired was recorded as goodwill. The allocation of the
purchase price was based upon preliminary valuations and estimates, and is subject to change as valuations are
finalized. The primary area of the purchase price allocation that is not yet finalized relates to pre-merger
contingencies. The final valuation is expected to be completed no later than the second quarter of 2009.
This business combination resulted in the acquisition of $3.7 million of tangible assets, $4.5 million of
intangible assets and $1.3 million of goodwill. The fair values of tangible assets were determined using a
market approach. The fair values of intangible assets were determined using an income approach to measure
the present worth of anticipated future economic benefits. The Company also performed an economic
obsolescence analysis to confirm the values identified through the aforementioned methods. The allocation is
still preliminary at this time and may potentially change by a material amount once the purchase price
allocation is finalized.
The acquired identifiable intangible assets of $4.5 million relate to customer relationships, a tradename
and a non-compete agreement. These intangible assets are subject to amortization under SFAS 142. The
customer relationships asset of $4.0 million will be amortized as the value of the relationships are realized
using rates of 19%, 24%, 17%, 13%, 9%, 6%, 4%, 3%, 3% and 2% for 2008 through 2017, respectively. The
tradename asset of $0.4 million will be amortized straight-line over 10 years and the non-compete agreement
asset will be amortized straight-line over 3 years.
Goodwill of $1.3 million has been recognized as part of the purchase price allocation as the purchase
price exceeded the fair value of the acquired assets and assumed liabilities. The Company believes the
goodwill associated with the Hydra-Walk acquisition is related to the acquired workforce and potential
expansion of our service offerings. Therefore, it was not allocated to the acquired assets and assumed
liabilities. The $1.3 million of goodwill was allocated to our fishing and rental segment and $1.3 million is
expected to be deductible for income tax purposes.
As of December 31, 2008, the Hydra-Walk operations had met performance earn-out requirements that
resulted in additional consideration of $0.5 million which has been recorded as additional goodwill.
Leader Energy Services Ltd. On July 22, 2008, the Company acquired all of the United States-based
assets of Leader Energy Services Ltd. (“Leader”), a Canadian company, for consideration of $34.6 million in
cash. The acquired assets include nine coiled tubing units, seven nitrogen trucks, twelve pumping trucks and
other ancillary equipment. Additionally, the Company paid approximately $0.7 million for supplies and
inventory used in pressure pumping operations. The Company also incurred direct transaction costs of
approximately $0.1 million. The purchase price was allocated to the tangible assets acquired. The acquisition
of the Leader assets was accounted for as an asset purchase as the assets acquired did not constitute a business
and therefore did not result in the establishment of goodwill. The Company did not identify any acquired
intangible assets. The Leader assets were integrated into our pressure pumping segment.
Acquisitions completed during 2007
AMI. On September 5, 2007, the Company acquired AMI, which operates in Canada and is a technology
company focused on oilfield service equipment controls, data acquisition and digital information flow. The
purchase price was $6.6 million in cash and $2.9 million in assumed debt and was paid in September 2007.
During the nine months ended September 30, 2008, the Company refined its fair value allocation of the assets
acquired and liabilities assumed by increasing its deferred tax asset balance by $0.3 million and decreasing its
deferred tax liability balance by $1.0 million. These changes were offset by a corresponding net decrease to
goodwill of $1.3 million. During 2008, but prior to the anniversary of the acquisition, the Company made
additional payments to settle its working capital adjustment with the former owners of AMI and incurred
85
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
additional transaction costs directly related to the business combination. These payments totaled $1.3 million
and resulted in additional goodwill of $1.3 million. The purchase price allocation was completed during the
third quarter of 2008.
Moncla. On October 25, 2007, the Company acquired Moncla, which operated well service rigs, barges
and ancillary equipment in the southeastern United States for total consideration of $146.0 million. During
2008, the Company refined its fair value allocation of the assets acquired and liabilities assumed by increasing
the working capital accounts (excluding deferred tax assets) by $2.2 million, decreasing the fair value of the
well service assets acquired by $3.6 million, decreasing the deferred tax and other long-term asset balances by
$0.4 million, increasing its long-term deferred tax liability balance by $2.1 million and incurring additional
fees related to the closing of the transaction of less than $0.2 million. The Company also paid additional
purchase consideration of $0.8 million during the third quarter of 2008. These changes were offset with a
corresponding net increase to goodwill of $4.9 million. The purchase price allocation was finalized in the
fourth quarter of 2008.
Kings Oil Tools. On December 7, 2007, the Company acquired the well service assets and related
equipment of Kings Oil Tools, Inc. (“Kings”), a California-based well service company for approximately
$45.1 million. During the nine months ended September 30, 2008, the Company revised its fair value
allocation of the assets acquired and liabilities assumed by increasing the fair value of the well service assets
acquired by $1.6 million, increasing the deferred tax assets by $0.4 million, decreasing the fair value of
working capital accounts by $0.1 million and incurring additional fees related to the closing of the transaction
of $0.1 million. These changes were offset with a corresponding net decrease to goodwill for $1.7 million.
The purchase price allocation was finalized in the fourth quarter of 2008 .
Acquisitions completed during 2006
We made no acquisitions during 2006.
NOTE 3. OTHER CURRENT AND NON-CURRENT LIABILITIES
December 31,
2008
2007
(In thousands)
Current Accrued Liabilities:
Accrued payroll, taxes and employee benefits . . . . . . . . . . . . . . . . . . . . . . . $ 67,408
50,833
Accrued operating expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
41,003
Income, sales, use and other taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
25,724
Self-insurance reserve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,550
Unsettled legal claims . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
902
Phantom share liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,696
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 55,486
52,180
35,310
25,208
6,783
2,458
5,939
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $197,116
$183,364
86
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Non-Current Accrued Liabilities:
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Environmental liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued rent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Phantom share liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31,
2008
2007
(In thousands)
$ 9,348
3,004
2,497
1,359
478
809
$ 9,298
3,090
2,829
2,705
896
713
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$17,495
$19,531
NOTE 4. PROPERTY AND EQUIPMENT
Property and equipment consists of the following:
December 31,
2008
2007
(In thousands)
Major classes of property and equipment:
Well servicing equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,431,624
60,508
Disposal wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
125,031
Motor vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
81,129
Furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
71,014
Buildings and land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
89,001
Work in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,200,069
56,576
112,986
73,032
64,258
88,304
Gross property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,858,307
(806,624)
1,595,225
(684,017)
Net property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,051,683
$ 911,208
The Company capitalizes costs incurred during the application development stage of internal-use software.
These costs are capitalized to work in progress until such time the application is put in service. For the years
ended December 31, 2008, 2007 and 2006 the Company capitalized costs in the amount of $4.5 million,
$1.9 million, and zero, respectively.
Interest is capitalized on the average amount of accumulated expenditures for major capital projects using
an effective interest rate based on related debt until the underlying assets are placed into service. Capitalized
interest for the years ended December 31, 2008, 2007 and 2006 was $6.5 million, $5.3 million and
$3.4 million, respectively.
87
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company is obligated under various capital leases for certain vehicles and equipment that expire at
various dates during the next five years. The carrying value of assets acquired under capital leases consists of
the following:
December 31,
2008
2007
(In thousands)
Well servicing equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Motor vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$20,442
9,271
$19,687
5,938
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$29,713
$25,625
Depreciation of assets held under capital leases of approximately $4.3 million, $5.9 million and
$6.0 million for the years ended December 31, 2008, 2007 and 2006, respectively, and is included in
depreciation and amortization expense in the accompanying consolidated statements of operations.
NOTE 5. GOODWILL AND OTHER INTANGIBLE ASSETS
The following table summarizes the activity in our goodwill accounts for the years ended December 31,
2008 and 2007:
Well Servicing
Segment
Balance at December 31, 2006 . . . . . . . . . . . . . . .
Goodwill acquired during the period . . . . . . . . .
Impact of foreign currency translation . . . . . . . .
$252,975
57,820
(182)
Pressure
Pumping
Segment
(In thousands)
$ 49,036
—
—
Balance at December 31, 2007 . . . . . . . . . . . . . . .
310,613
49,036
Goodwill acquired during the period . . . . . . . . .
Purchase price allocation and other adjustments,
net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment of goodwill . . . . . . . . . . . . . . . . . . .
Impact of foreign currency translation . . . . . . . .
8,970
2,376
—
(967)
—
(49,036)
—
Fishing and
Rental Services
Segment
$ 18,901
—
—
18,901
1,815
—
(20,716)
—
Total
$320,912
57,820
(182)
378,550
10,785
2,376
(69,752)
(967)
Balance at December 31, 2008 . . . . . . . . . . . . . . .
$320,992
$
—
$
—
$320,992
88
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following tables present the gross carrying values and accumulated amortization of our identified
intangible assets with determinable lives that are subject to amortization under SFAS 142 as of December 31,
2008 and 2007:
December 31,
2008
2007
(In thousands)
Noncompete agreements:
Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 16,309
(4,699)
$18,402
(2,772)
Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 11,610
$15,630
Patents and trademarks:
Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 4,391
(3,114)
$ 4,150
(2,526)
Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,277
$ 1,624
Customer relationships:
Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 39,225
(12,359)
$25,139
(1,649)
Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 26,866
$23,490
Customer backlog:
Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
622
(207)
Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
415
$
$
999
(214)
785
Developed technology:
Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 3,598
(1,421)
$ 4,762
(397)
Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,177
$ 4,365
Amortization expense for our intangible assets with determinable lives was as follows:
Noncompete agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,108
748
Patents and trademarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,710
Customer relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer backlog . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
252
1,803
Developed technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
2006
Year Ended December 31,
2007
(In thousands)
$1,919
774
1,649
210
389
$2,202
713
—
—
—
Total intangible asset amortization expense . . . . . . . . . . . . . . . . . . . . $17,621
$4,941
$2,915
89
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The weighted average remaining amortization periods and expected amortization expense for the next five
years for our intangible assets are as follows:
Weighted
Average Remaining
Amortization
Period (Years)
Noncompete agreements. . . . . . . . . . . . .
Patents and trademarks . . . . . . . . . . . . . .
Customer relationships . . . . . . . . . . . . . .
Customer backlog . . . . . . . . . . . . . . . . .
Developed technology . . . . . . . . . . . . . .
Total intangible asset amortization
expense . . . . . . . . . . . . . . . . . . . . . . .
5.9
4.5
9.3
2.3
2.8
Expected Amortization Expense
2009
2010
2011
2012
2013
$ 3,221
489
8,113
797
156
(In thousands)
$2,620
203
3,808
423
104
$2,652
273
5,232
668
156
$2,423
96
2,818
—
—
$ 406
40
2,069
—
—
$12,776
$8,981
$7,158
$5,337
$2,515
Certain of our intangible assets are denominated in currencies other than U.S. Dollars and as such the
values of these assets are subject to fluctuations associated with changes in exchange rates. Additionally,
certain of these assets are also subject to purchase accounting adjustments. The estimated fair values of
intangible assets obtained through acquisitions consummated in the preceding twelve months are based on
preliminary information which is subject to change until final valuations are obtained.
We perform annual impairment tests associated with our goodwill on December 31 of each year, or more
frequently if circumstances warrant, as dictated by SFAS 142. As of December 31, 2008, 2007 and 2006, we
had three reporting units as determined and identified by SFAS 142.
We estimate the fair values of our reporting units using three common valuation techniques — the
discounted cash flow method, the guideline company method, and the similar transaction method. The
Company’s management assigns a weighting to the results of each method based on the facts and
circumstances that exist at the assessment date. The discounted cash flows for each reporting unit being tested
are based on the Company’s financial budgets and forecasts, as well as management’s beliefs about the long-
term growth patterns of the reporting units. For the 2008 future cash flow projections were discounted at rates
ranging from 14% to 15% and terminal growth rates of approximately 3%. As part of the assessment,
management also considered the current market capitalization of the Company, based on publicly available
information and adjusted for an estimate of a control premium, in assessing the reasonableness of the fair
values of the reporting units based on the results of the valuation models.
To assist management in the preparation and analysis of the valuation of the Company’s reporting units,
management utilized the services of a third-party valuation consultant, who reviewed management’s estimates,
assumptions and calculations. The ultimate conclusions of the valuation techniques remain the sole responsi-
bility of the Company’s management. The Company conducts its annual impairment test on December 31 of
each year. Upon completion of the 2007 and 2006 assessments, no impairment was indicated since the
estimated fair values of the reporting units were in excess of their carrying values. Upon completion of the
2008 assessment, we determined that the fair value associated with the reporting units comprising our pressure
pumping and fishing and rental reportable segments was less than the carrying value of the reporting units of
those segments, indicating potential impairment. Because indicators of impairment existed for these reporting
units, we performed step two of the SFAS 142 impairment test for those units. While this test is required on
an annual basis, it also can be required more frequently based on changes in external factors. We do not
currently expect that additional tests would result in any additional charges, but the determination of fair value
used in the test is heavily impacted by the market prices of our equity and debt securities.
90
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In accordance with SFAS 142, the implied fair value of the goodwill of the reporting units being tested
was determined in the same manner as a hypothetical business combination, with the fair value of the
reporting unit representing the purchase price. As a result of the calculations of step two of the test, we
determined that the goodwill of the reporting units comprising our pressure pumping and fishing and rental
segments was impaired, and that the amount of the impairment loss was greater than the current carrying value
of those reporting units’ goodwill. As such, we recorded a pre-tax impairment charge of approximately
$49.0 million and $20.7 million for our pressure pumping and fishing and rental segments, respectively, during
the fourth quarter of 2008.
NOTE 6. EARNINGS PER SHARE
The following table presents our basic and diluted earnings per share for the years ended December 31,
2008, 2007 and 2006:
Year Ended December 31,
2007
(In thousands, except per share data)
2006
2008
Basic EPS Computation:
Numerator
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 84,058
$169,289
$171,033
Denominator
Weighted average shares outstanding . . . . . . . . . . . . . . . . . . . . . . . . . .
Basic earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted EPS Computation:
Numerator
124,246
0.68
$
131,194
1.29
$
131,332
1.30
$
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 84,058
$169,289
$171,033
Denominator
Weighted average shares outstanding . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock appreciation rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
124,246
555
254
506
4
131,194
1,518
256
565
18
131,332
2,180
—
552
—
125,565
133,551
134,064
Diluted earnings per share. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
0.67
$
1.27
$
1.28
Stock options, warrants and stock appreciation rights are included in the computation of diluted earnings
per share using the treasury stock method. Restricted stock grants are legally considered issued and
outstanding, but are included in basic and diluted earnings per share only to the extent that they are vested.
Unvested restricted stock is included in the computation of diluted earnings per share using the treasury stock
method. The diluted earnings per share calculation for the years ended December 31, 2008, 2007 and 2006
exclude the potential exercise of 2.6 million, 0.5 million and 0.4 million stock options, respectively, because
the effects of such exercises on earnings per share in those periods would be anti-dilutive. The diluted earnings
per share calculation for the year ended December 31, 2008 excludes the potential exercise of 0.4 million
stock-settled stock appreciation rights (“SARs”) because the effects of such exercises on earnings per share in
those periods would be anti-dilutive. Shares are considered anti-dilutive because their exercise prices exceeded
the average price of the Company’s stock during those years.
91
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
There have been no material changes in share amounts subsequent to the balance sheet date that would
have a material impact on the earnings per share calculation for the year ended December 31, 2008.
NOTE 7. ASSET RETIREMENT OBLIGATIONS
In connection with our well servicing activities, we operate a number of saltwater disposal (“SWD”)
facilities. Our operations involve the transportation, handling and disposal of fluids in our SWD facilities that
are by-products of the drilling process, some of which have been determined to be harmful to the environment.
SWD facilities used in connection with our fluid hauling operations are subject to future costs associated with
the abandonment of these properties. As a result, we have incurred costs associated with the proper storage
and disposal of these materials.
Annual amortization of the assets associated with the asset retirement obligations was $0.6 million,
$0.6 million and $0.5 million for the years ended December 31, 2008, 2007 and 2006, respectively. A
summary of changes in our asset retirement obligations is as follows (in thousands):
Balance at December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$9,622
Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Costs incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Disposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
(576)
585
(345)
Balance at December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,298
Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Costs incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Disposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
397
(462)
594
(478)
Balance at December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$9,349
NOTE 8. EQUITY METHOD INVESTMENTS
IROC Energy Services Corp.
As of December 31, 2008 and 2007, we owned approximately 8.7 million shares of IROC Energy Services
Corp. (“IROC”), an Alberta-based oilfield services company. This represented approximately 19.7% of IROC’s
outstanding common stock on December 31, 2008 and 2007. IROC shares trade on the Toronto Venture Stock
Exchange and had a closing price of $0.54 CDN and $0.74 CDN per share on December 31, 2008 and 2007,
respectively. Mr. William Austin, our former chief financial officer, and Mr. Newton W. Wilson III, our Chief
Operating Officer, serve on the board of directors of IROC.
Through December 31, 2008, we have significant influence over the operations of IROC through our
ownership interest and representation on IROC’s board of directors, but we do not control it. We account for
our investment in IROC using the equity method. Our investment in IROC totaled $3.7 million and
$11.2 million as of December 31, 2008 and 2007, respectively. The pro-rata share of IROC’s earnings and
losses to which we are entitled is recorded in our consolidated statements of operations as a component of
other income and expense, with an offsetting increase or decrease to the carrying value of our investment, as
appropriate. Any earnings distributed back to us from IROC in the form of dividends would result in a
decrease in the carrying value of our equity investment. The value of our investment may also increase or
decrease each period due to changes in the exchange rate between the U.S. Dollar and Canadian Dollar.
92
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Changes in the value of our investment due to fluctuations in exchange rates are offset by accumulated other
comprehensive income.
IROC had net income of approximately $0.8 million, $2.0 million and $1.8 million U.S. Dollars for the
years ended December 31, 2008, 2007 and 2006, respectively. In addition to our pro-rata share of IROC’s net
income, the value of our investment changes based on the exchange rate between the U.S. and Canadian
dollars. During the fourth quarter of 2008 the U.S. Dollar strengthened significantly against the Canadian
Dollar, reducing the value of our investment. This decrease was offset in accumulated other comprehensive
income.
During the years ended December 31, 2008, 2007 and 2006, we recorded $0.2 million, $0.4 million and
$0.4 million, respectively, of equity income related to our investment in IROC. During the years ended
December 31, 2008, 2007 and 2006, no earnings were distributed to us by IROC. Only distributed earnings or
any gains or losses arising from the disposal of our investment are reportable for income tax purposes; as a
result, the amounts we record for our pro-rata share of IROC’s earnings or losses to which we are entitled
result in a temporary difference between book and taxable income. Under the provisions of SFAS 109, we
record a deferred tax asset or liability, as appropriate, to account for these temporary differences.
An impairment review of our equity method investment in IROC is performed on a quarterly basis to
determine if there has been a decline in fair value that is other than temporary. The fair value of the asset is
measured using quoted market prices or, in the absence of quoted market prices, fair value is based on an
estimate of discounted cash flows. In determining whether the decline is other than temporary, we consider the
cyclicality of the industry in which the investment operates, its historical performance, its performance in
relation to its peers and the current economic environment. Future conditions in the industry, operating
performance and performance in relation to peers and the future economic environment may vary from our
current assessment of recoverability. While the carrying value of the investment approximated the fair value
during the second quarter of 2008, IROC’s stock price is currently depressed and has historically been volatile.
During the fourth quarter of 2008 the Company’s management determined that the decline in the value of the
investment in IROC was other than temporary and as such recorded a pretax charge of $5.4 million in order to
reduce the carrying value of the investment to fair value. Fair value was determined by using the quoted
market prices for the IROC shares as of December 31, 2008.
Geostream Services Group
On October 31, 2008, we acquired a 26% interest in OOO Geostream Services Group (“Geostream”) for
$17.4 million. We incurred direct transaction costs of approximately $1.9 million associated with the
transaction. Geostream is located in the Russian Federation and provides drilling and workover services and
sub-surface engineering and modeling in the Russian Federation. In connection with our initial investment,
three officers of the Company became board members of Geostream, representing 50% of the board
membership. We can exert significant influence over the operations of Geostream, but do not control it;
therefore we account for it using the equity method.
The fair value of the amounts we have invested in Geostream is in excess of the underlying book value of
our investment. We are currently performing a valuation to determine the components of the difference in
basis and have preliminarily allocated substantially all of the difference to goodwill. Our pro-rata share of
Geostream’s net income for the two months ended December 31, 2008 was not material.
We are contractually required to purchase an additional 24% of Geostream no later than March 31, 2009
for approximately A11.3 million (which at December 31, 2008 was equivalent to $15.9 million). For a period
not to exceed six years subsequent to October 31, 2008, we have the option to increase our ownership
percentage of Geostream to 100%; however, if we have not acquired 100% of Geostream on or before the end
of the six-year period, we will be required to arrange an initial public offering for those shares.
93
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Advanced Flow Technologies, Inc.
In September 2007 we completed the acquisition of AMI, a privately-held Canadian company focused on
oilfield technology. Prior to the acquisition, AMI owned a portion of another Canadian company, AFTI. As
part of the acquisition, AMI increased its ownership percentage of AFTI to 51.46%. At December 31, 2007
we consolidated the assets, liabilities, results of operations and cash flows of AFTI into our consolidated
financial statements, with the portion of AFTI remaining outside of our control forming a minority interest in
our consolidated financial statements.
Our ownership of AFTI declined to 48.73% as of December 31, 2008 due to the issuance of additional
shares by AFTI. As a result, we deconsolidated AFTI results from our consolidated financial statements at
December 31, 2008 and now account for that interest under the equity method.
NOTE 9. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The following is a summary of the carrying amounts and estimated fair values of our financial
instruments as of December 31, 2008 and 2007. SFAS No. 107, Disclosures about Fair Value of Financial
Instruments (“SFAS 107”) defines the fair value of a financial instrument as the amount at which the
instrument could be exchanged in a current transaction between willing parties.
Cash, cash equivalents, short-term investments, accounts payable and accrued liabilities. These carrying
amounts approximate fair value because of the short maturity of the instruments or because the carrying value
is equal to the fair value of those instruments on the balance sheet date.
December 31, 2008
December 31, 2007
Carrying Value
Fair Value
Carrying Value
Fair Value
(In thousands)
Financial assets:
Notes receivable — related parties . . . . .
$
336
$
336
$
173
$
173
Financial liabilities:
8.375% Senior Notes due 2014 . . . . . . .
Senior Secured Credit Facility revolving
loans . . . . . . . . . . . . . . . . . . . . . . . . .
Notes payable — related parties . . . . . . .
$425,000
$282,115
$425,000
$434,563
187,813
20,318
187,813
20,318
50,000
22,178
50,000
22,178
Notes receivable-related parties. The amounts reported relate to notes receivable from certain employees
of the Company related to relocation and retention agreements. The carrying values of these notes approximate
their fair values as of the applicable balance sheet dates.
8.375% Senior Notes due 2014. The fair value of our long-term debt is based upon the quoted market
prices and face value for the various debt securities at December 31, 2008. The carrying value of these notes
as of December 31, 2008 was $425.0 million and the fair value was $282.1 million.
Senior Secured Credit Facility revolving loans. Because of their variable interest rates, the fair values of
the revolving loans borrowed under our Senior Secured Credit Facility approximate their carrying values as of
December 31, 2008. The carrying and fair values of these loans as of December 31, 2008 were approximately
$187.8 million.
Notes payable — related parties. The amounts reported relate to the seller financing arrangement entered
into in connection with our acquisition of Moncla (see “Note 2. Acquisitions”). The carrying value of these
notes approximate their fair values as of December 31, 2008.
94
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 10. DERIVATIVE FINANCIAL INSTRUMENTS
Interest Rate Swaps. On March 10, 2006 we entered into two $100.0 million notional amount interest
rate swaps to fix the interest rate on a portion of the borrowings under our prior senior credit agreement, dated
July 29, 2005 (the “Prior Credit Facility”). These swaps met the criteria of derivative instruments.
In connection with the termination of our Prior Credit Facility in November 2007, we settled all
outstanding interest rate swap arrangements. We recognized a loss of approximately $2.3 million related to the
settlement of our interest rate swaps, which is recorded in our consolidated statements of operations as a
component of interest expense.
Call Options on 8.375% Senior Notes due 2014. The indenture related to our $425.0 million in
8.375% Senior Notes due 2014 (see “Note 12. Long-Term Debt”) contains provisions by which, at our option,
we may redeem the notes at varying prices before their stated maturity date. Certain of these provisions are
based on contingent events, such as a future equity offering by us or a change in control of the Company.
Other provisions are not contingent in nature. In one of the non-contingent scenarios, the price at which we
could retire the notes is based, in part, on a variable interest rate. We have analyzed all the provisions of the
indenture that allow us to repay this debt early in order to determine if any of these call options constitute an
embedded derivative instrument under SFAS 133 and require bifurcation and separate measurement from the
host contract. We followed the guidance provided in paragraphs 6, 12, 13 and 61 of SFAS 133 and Derivatives
Implementation Group (“DIG”) Issues B-16 and B-39 in determining whether or not the call options required
bifurcation and separate measurement. Based on our analysis, we do not believe these options require
bifurcation and separate measurement.
NOTE 11.
INCOME TAXES
The components of our income tax expense are as follows:
2008
Year Ended December 31,
2007
(In thousands)
2006
Current income tax expense:
Federal and state . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(55,190)
(5,306)
$ (81,384)
(771)
$ (92,213)
(4,242)
Deferred income tax (expense) benefit:
Federal and state . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(60,496)
(82,155)
(96,455)
(30,363)
616
(29,747)
(24,281)
(332)
(24,613)
(7,906)
914
(6,992)
Total income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(90,243)
$(106,768)
$(103,447)
We made net federal income tax payments of approximately $33.5 million, $85.5 million and $87.6 million
for the years ended December 31, 2008, 2007 and 2006, respectively. We made net state income tax payments of
approximately $6.6 million, $6.6 million and $8.4 million for the years ended December 31, 2008, 2007 and
2006, respectively. We made net foreign tax payments of approximately $3.4 million, $4.2 million and
$3.0 million for the years ended December 31, 2008, 2007 and 2006, respectively. For the years ended
December 31, 2008, 2007 and 2006, tax benefits allocated to stockholders’ equity for compensation expense for
income tax purposes in excess of amounts recognized for financial reporting purposes were $1.7 million,
$3.4 million and less than $0.1 million, respectively. The Company had allocated tax benefits to stockholders’
equity in prior years for compensation expense for income tax purposes in excess of amounts recognized for
financial reporting purposes.
95
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Income tax expense differs from amounts computed by applying the statutory federal rate as follows:
Year Ended
December 31,
2007
2006
2008
Income tax computed at Federal statutory rate . . . . . . . . . . . . . . . . . . . . . . . .
State taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non deductible goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35.0% 35.0% 35.0%
3.2
3.1
—
12.8
0.2
(0.3)
0.3
1.2
1.7
—
(0.5)
1.5
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
51.8% 38.7% 37.7%
As of December 31, 2008 and 2007, our deferred tax assets and liabilities were comprised of the
following:
December 31,
2008
2007
(In thousands)
Deferred tax assets:
Net operating loss and tax credit carryforwards . . . . . . . . . . . . . . . . . . .
Self-insurance reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,664
20,944
4,023
14,681
10,116
3,085
57,513
Valuation allowance for deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . .
(844)
Net deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
56,669
$
6,000
21,484
4,731
15,600
3,876
488
52,179
(1,458)
50,721
Deferred tax liabilities:
Property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(190,675)
(27,952)
—
(150,802)
(31,993)
(318)
Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(218,627)
(183,113)
Net deferred tax liability, net of valuation allowance . . . . . . . . . . . . . . . . .
$(161,958)
$(132,392)
In 2008, deferred tax liabilities decreased by $1.0 million for adjustments to accumulated other
comprehensive loss. In 2007, deferred tax liabilities decreased by $0.2 million for adjustments to accumulated
other comprehensive loss.
In recording deferred income tax assets, we consider whether it is more likely than not that some portion
or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets
is dependent upon the generation of future taxable income during the periods in which those deferred income
tax assets would be deductible. We consider the scheduled reversal of deferred income tax liabilities and
projected future taxable income for this determination. To fully realize the deferred income tax assets related
to our federal net operating loss carryforwards that do not have a valuation allowance due to Section 382
limitations, we would need to generate future federal taxable income of approximately $4.8 million over the
next ten years. With certain exceptions noted below, we believe that after considering all the available
96
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
objective evidence, both positive and negative, historical and prospective, with greater weight given to the
historical evidence, it is more likely than not that these assets will be realized.
We estimate that as of December 31, 2008, 2007 and 2006 we have available $7.1 million, $8.2 million
and $9.3 million, respectively, of federal net operating loss carryforwards. Approximately $4.7 million of our
net operating losses as of December 31, 2008 are subject to a $1.1 million annual Section 382 limitation and
expire in 2018. Approximately $2.4 million of our net operating losses as of December 31, 2008 are subject to
a $5,000 annual Section 382 limitation and expire in 2016 through 2018. A valuation allowance is provided
when it is more likely than not that some portion of the deferred tax assets will not be realized. Due to annual
limitations under Sections 382 and 383, management believes that we will not be able to utilize all available
carryforwards prior to their ultimate expiration. The deferred tax asset associated with our remaining federal
net operating loss carryforwards that will expire before utilization due to Section 382 limitations of $2.3 million
includes a valuation allowance of $0.8 million as a result of the Section 382 limitations at December 31, 2008
and 2007, respectively.
We estimate that as of December 31, 2008, 2007 and 2006 we have available $16 million, $19 million,
and $31 million, respectively, of state net operating loss carryforwards that will expire from 2009 to 2025. To
fully realize the deferred income tax assets related to our state net operating loss carryforwards, we would
need to generate future West Virginia taxable income of $12.9 million over the next 17 years and future
Pennsylvania taxable income of $2.0 million over the next 17 years. Management believes that it is not more
likely than not that we will be able to utilize all available carryforwards prior to their ultimate expiration. The
deferred tax asset associated with our remaining state net operating loss carryforwards at December 31, 2008
of $1.4 million includes a valuation allowance of less than $0.1 million as a result.
In 2007, the Company began operations in Mexico that resulted in a net operating loss of $2 million and
a deferred tax asset related to the net operating loss carryforward of $0.6 million. Mexico enacted a new flat
tax rate effective January 1, 2008. The flat tax functions in addition to the regular corporate tax rate of 28%.
Tax expense is calculated under both methods and if the flat tax is greater than the regular tax, the additional
tax expense above the regular tax is assessed in addition to the regular tax calculation. In 2007, we recorded a
full valuation allowance related to our Mexico net operating loss carryforwards of $0.6 million, as
management believed that, due to the enactment of the Mexico flat tax, all of our net operating loss
carryforwards related to the Mexico operations were not more likely than not to be fully realized in the future.
It was determined the Company would not be in a flat tax position in 2008 and all of the 2007 regular net
operating loss will be utilized against 2008 regular Mexico income. Accordingly, the valuation allowance of
$0.6 million set up in 2007 was released in 2008.
In 2007, the Company made a stock acquisition of AMI, a Canadian company. At December 31, 2008
and 2007, the Company’s Canadian operations had net operating losses of $3.8 million and $3.2 million,
respectively. At December 31, 2008 and 2007 the deferred tax asset related to the net operating loss
carryforward was $1.1 million and $1.0 million respectively. We have recorded no valuation allowance related
to our Canadian net operating loss carryforwards at December 31, 2008 and 2007, as management believes
that all of our net operating loss carryforwards related to the Canadian operations are more likely than not to
be fully realized in the future. To fully realize the deferred income tax assets related to our Canadian net
operating loss carryforwards, we would need to generate $0.2 million of future Canadian taxable income over
the next seven years and $3.6 million of future Canadian taxable income over the next nineteen years. The net
operating losses expire from 2015 to 2028.
We did not provide for U.S. income taxes or withholding taxes on the 2008 unremitted earnings of our
Mexico subsidiaries as these earnings are considered permanently reinvested. Unremitted earnings of our Mexico
subsidiaries, representing tax basis accumulated earnings and profits, totaled approximately $6.3 million as of
December 31, 2008. We did not provide for U.S. income taxes on 2007 and 2006 unremitted earnings of our
97
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
foreign subsidiaries as our tax basis in each foreign subsidiary was in excess of the book basis as of
December 31, 2007 and 2006.
In December 2006, the FASB issued FIN 48. FIN 48 clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements in accordance with SFAS 109. FIN 48 prescribes a
recognition threshold and measurement attributes for the financial statement recognition and measurement of
an income tax position taken or expected to be taken in an income tax return. FIN 48 also provides guidance
on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.
In May 2007, the FASB issued FSP FIN 48-1. FSP FIN 48-1 provides guidance on how an enterprise
should determine whether a tax position is effectively settled for the purpose of recognizing previously
unrecognized tax benefits. In determining whether a tax position has been effectively settled, entities must
evaluate (i) whether taxing authorities have completed their examination procedures; (ii) whether the entity
intends to appeal or litigate any aspect of a tax position included in a completed evaluation; and (iii) whether
it is remote that a taxing authority would examine or re-examine any aspect of a taxing position. FSP FIN 48-1
is to be applied upon the initial adoption of FIN 48.
As of December 31, 2008, December 31, 2007 and January 1, 2007 we had approximately $5.6 million,
$6.8 million and $3.4 million, respectively, of unrecognized tax benefits net of federal benefits which, if
recognized, would impact our effective tax rate. We have accrued approximately $2.1 million, $2.3 million
and $1.0 million for the payment of interest and penalties as of December 31, 2008, December 31, 2007 and
January 1, 2007, respectively. We believe that is reasonably possible that approximately $2.8 million of our
currently remaining unrecognized tax positions, each of which are individually insignificant, may be
recognized by the end of 2008 as a result of a lapse of the statute of limitations.
We file income tax returns in the United States federal jurisdiction and various states and foreign
jurisdictions. We are not under a current federal tax examination. Federal tax years ending December 31, 2005
and forward are open for tax audits as of December 31, 2008. Our other significant filings are Argentina
which has been examined through 2006, Mexico which is in the initial stages of a 2007 tax audit of our initial
year of operations and in the State of Texas, where tax filings remain open for 2003 to 2006 for certain
subsidiaries of the Company.
We recognized tax benefits in 2008 of $1.7 million for expirations of statutes of limitations. We recorded
an income tax benefit of $0.7 million, increase to deferred tax liabilities of $0.5 million and decrease to
goodwill of $0.5 million related to these statute expirations.
The following table presents the activity during 2008 related to our FIN 48 reserve (in thousands):
Balance at January 1, 2008. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additions based on tax positions related to the current year . . . . . . . . . . . . . . . . . . . . . . . . .
Additions based on tax positions related to prior years . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decreases in unrecognized tax benefits acquired or assumed in business combinations . . . . .
Reductions for tax positions from prior years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$5,722
551
104
(707)
(612)
—
Balance at December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$5,058
Tax Legislative Changes
The Economic Stimulus Act of 2008. The Economic Stimulus Act of 2008 permits a bonus first-year
depreciation deduction of 50% of the adjusted basis of qualified property (most personal property and
software) acquired and placed in service after December 31, 2007 and before January 1, 2009. We have
98
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
estimated $123 million of qualifying additions in 2008 resulting in additional 2008 tax depreciation of
$49 million.
The American Recovery and Reinvestment Act of 2009. The American Recovery and Reinvestment Act
of 2009 extends the bonus first-year depreciation deduction of 50% of the adjusted basis of qualified property
acquired and placed in service to after December 31, 2008 and before January 1, 2010.
Revised Texas Franchise tax.
In May 2006, the state of Texas enacted a new law, effective January 1,
2007, that substantially changes the tax system in Texas. The law replaces the taxable capital and earned
surplus components of its franchise tax with a new tax that is based on modified gross revenue. This law
imposes a tax on a unitary group of affiliated entities’ net receipts rather than on the earned surplus of each
separate entity.
NOTE 12. LONG-TERM DEBT
The components of our long-term debt are as follows:
December 31,
2008
2007
(In thousands)
8.375% Senior Notes due 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $425,000
187,813
Senior Secured Credit Facility revolving loans due 2012. . . . . . . . . . . . . . . .
3,015
Other long-term indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20,318
Notes payable — related party, net of discount of $182 and $322 . . . . . . . . .
23,149
Capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$425,000
50,000
—
22,178
26,815
659,295
523,993
Less current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(25,704)
(12,379)
Total long-term debt and capital lease obligations, net of fair value
discount
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $633,591
$511,614
8.375% Senior Notes due 2014
On November 29, 2007, the Company issued $425.0 million aggregate principal amount of 8.375% Senior
Notes due 2014 (the “Senior Notes”), under an Indenture, dated as of November 29, 2007 (the “Indenture”),
among us, the guarantors party thereto (the “Guarantors”) and The Bank of New York Trust Company, N.A.,
as trustee. The Senior Notes were priced at 100% of their face value to yield 8.375%. Net proceeds, after
deducting initial purchasers’ fees and estimated offering expenses, were approximately $416.1 million. We
used approximately $394.9 million of the net proceeds to retire then existing term loans, including accrued
and unpaid interest, with the balance used for general corporate purposes.
The Senior Notes are general unsecured senior obligations of Key. Accordingly, they will rank effectively
subordinate to all of our existing and future secured indebtedness. The Senior Notes are or will be jointly and
severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries.
Interest on the Senior Notes is payable on June 1 and December 1 of each year beginning June 1, 2008.
The Senior Notes mature on December 1, 2014.
On or after December 1, 2011, the Senior Notes will be subject to redemption at any time and from time
to time at our option, in whole or in part, upon not less than 30 nor more than 60 days’ notice, at the
redemption prices (expressed as percentages of the principal amount redeemed) set forth below, plus accrued
99
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
and unpaid interest thereon to the applicable redemption date, if redeemed during the twelve-month period
beginning on December 1 of the years indicated below:
Year
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage
104.19%
102.09%
100.00%
Notwithstanding the foregoing, at any time and from time to time before December 1, 2010, we may, on
any one or more occasions, redeem up to 35% of the aggregate principal amount of the outstanding Senior
Notes at a redemption price of 108.375% of the principal amount thereof, plus accrued and unpaid interest
thereon to the redemption date, with the net cash proceeds of any one or more equity offerings; provided that
at least 65% of the aggregate principal amount of the Senior Notes issued under the Indenture remains
outstanding immediately after each such redemption; and provided, further, that each such redemption shall
occur within 180 days of the date of the closing of such equity offering.
In addition, at any time and from time to time prior to December 1, 2011, the Company may, at our
option, redeem all or a portion of the Senior Notes at a redemption price equal to 100% of the principal
amount thereof plus the applicable premium (as defined in the Indenture) with respect to the Senior Notes and
plus accrued and unpaid interest thereon to the redemption date. If the Company experiences a change of
control, subject to certain exceptions, it must give holders of the Senior Notes the opportunity to sell to the
Company their Senior Notes, in whole or in part, at a purchase price equal to 101% of the aggregate principal
amount thereof, plus accrued and unpaid interest thereon to the date of purchase.
The Company and its restricted subsidiaries are subject to certain negative covenants under the indenture
governing the Senior Notes. The indenture limits the ability of the Company and each of its restricted
subsidiaries to, among other things, (i) sell assets, (ii) pay dividends or make other distributions on capital
stock or subordinated indebtedness, (iii) make investments, (iv) incur additional indebtedness or issue preferred
stock, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments from its
subsidiaries to itself, (vii) consolidate, merge or transfer all or substantially all of its assets, (viii) engage in
transactions with affiliates and (ix) create unrestricted subsidiaries.
In connection with the sale of the Senior Notes, the Company entered into a registration rights agreement
with the initial purchasers, pursuant to which it agreed to file an exchange offer registration statement with the
SEC with respect to an offer to exchange the Senior Notes for substantially identical notes that would be
registered under the Securities Act, and to use reasonable best efforts to cause such registration statement
become effective on or prior to November 29, 2008. In accordance with the agreement, the Company filed an
exchange offer registration statement with the SEC on August 19, 2008, which became effective August 22,
2008, and offered to exchange an aggregate principal amount of $425.0 million of registered 8.375% Senior
Notes due 2014, which the Company refers to as the exchange notes, for any and all of our original
unregistered 8.375% Senior Notes due 2014 that were issued in a private offering on November 29, 2007. The
terms of the exchange notes were substantially identical to those terms of the original notes, except that the
transfer restrictions, registration rights and additional interest provisions relating to the originally issued notes
did not apply to the exchange notes. References to the “Senior Notes” herein includes exchange notes issued
in the exchange offer.
As of December 31, 2008, the Company is in compliance with all the covenants required under the Senior
Notes.
100
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Senior Secured Credit Facility
Simultaneously with the closing of the offering of the Senior Notes, the Company entered into a new
credit agreement (the “Credit Agreement”) with several lenders. The Credit Agreement provides for a senior
secured credit facility (the “Senior Secured Credit Facility”) consisting of a revolving credit facility, letter of
credit sub-facility and swing line facility of up to an aggregate principal amount of $400.0 million, all of
which will mature no later than November 29, 2012. All obligations under the Senior Secured Credit Facility
are guaranteed by most of our subsidiaries and are secured by most of our assets, including our accounts
receivable, inventory and equipment.
The Senior Secured Credit Facility replaced the Company’s Prior Credit Facility, which was repaid with
the proceeds from the Senior Notes.
The interest rate per annum applicable to amounts borrowed under the Senior Secured Credit Facility are,
at the Company’s option, (i) LIBOR plus the applicable margin or (ii) the higher of (x) Bank of America’s
prime rate and (y) the Federal Funds rate plus 0.5%, plus the applicable margin. The applicable margin for
LIBOR loans ranges from 150 to 200 basis points, and the applicable margin for all other loans ranges from
50 to 100 basis points, both of which depend upon the Company’s consolidated leverage ratio.
The Senior Secured Credit Facility contains certain financial covenants, which, among other things,
require the maintenance of a consolidated leverage ratio not to exceed 3.50 to 1.00 and a consolidated interest
coverage ratio of not less than 3.00 to 1.00, and limit the Company’s capital expenditures to $250.0 million
per fiscal year, up to 50% of which amount may be carried over for expenditure in the following fiscal year.
Each of the ratios referred to above will be calculated quarterly on a consolidated basis for each trailing four
fiscal quarter period. In addition, the Senior Secured Credit Facility contains certain affirmative and negative
covenants, including, without limitation, restrictions on (i) liens; (ii) debt, guarantees and other contingent
obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets;
(v) loans, acquisitions, joint ventures and other investments (with acquisitions permitted so long as, after
giving pro forma effect thereto, no default or event of default exists under the Senior Secured Credit Facility,
the consolidated leverage ratio does not exceed 2.75 to 1.00, the Company is in compliance with the
consolidated interest coverage ratio and the Company has at least $25 million of availability under the Senior
Secured Credit Facility); (vi) dividends and other distributions to, and redemptions and repurchases from,
equity holders; (vii) prepaying, redeeming or repurchasing subordinated (contractually or structurally) debt;
(viii) granting negative pledges other than to the lenders; (ix) changes in the nature of the Company’s business;
(x) amending organizational documents, or amending or otherwise modifying any debt, any related document
or any other material agreement if such amendment or modification would have a material adverse effect; and
(xi) changes in accounting policies or reporting practices; in each of the foregoing cases, with certain
exceptions. Further, the Senior Secured Credit Facility permits share repurchases up to $200.0 million and
provides that share repurchases in excess of $200.0 million can be made only if our debt to capitalization ratio
is below 50%.
As of December 31, 2008, the Company is in compliance with all the covenants required under the Senior
Secured Credit Facility.
The Company may prepay the Senior Secured Credit Facility in whole or in part at any time without
premium or penalty, subject to certain reimbursements to the lenders for breakage and redeployment costs.
On September 15, 2008, Lehman Brothers Holdings (“Lehman”) filed for bankruptcy protection under
Chapter 11 of the United States Bankruptcy Code. Lehman Commercial Paper, Inc. (“LCPI”), a subsidiary of
Lehman, was a member of the syndicate of banks participating in our Senior Secured Credit Facility. LCPI’s
commitment was approximately 11% of the Company’s total facility. As of December 31, 2008, the Company
had approximately $139.3 million available under its Senior Secured Credit Facility. This availability reflects
the reduction of approximately $19.3 million of unfunded commitments by LCPI. The Company also had
101
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
$53.6 million in committed letters of credit under the facility. Under the terms of the agreement, committed
letters of credit count against our borrowing capacity under the revolving credit facility.
Seller Financing Arrangement in Moncla Purchase
In connection with the acquisition of Moncla (see “Note 2. Acquisitions”), the Company entered into two
promissory notes with the sellers. The first is an unsecured note in the amount of $12.5 million, which is due
and payable in a lump-sum, together with accrued interest, on October 25, 2009. Interest on this note is due
on each anniversary of the closing of the acquisition of Moncla, which was October 25, 2007. The second
unsecured note in the amount of $10.0 million is payable in annual installments of $2.0 million, plus accrued
interest, beginning October 25, 2008 through 2012. Each of the notes bears interest at the Federal Funds rate,
adjusted annually on the anniversary of the closing date. As of December 31, 2008, the interest rate on these
notes was 1.5%. Interest expense for the years ended December 31, 2008 and 2007 was $1.2 million and
$0.2 million, respectively, on the two notes in aggregate.
The Federal Funds rate does not represent a rate that would have resulted if an independent borrower and
an independent lender had negotiated a similar transaction under comparable terms and conditions and is not
equal to our incremental borrowing rate. In accordance with Accounting Principles Board (“APB”) No. 21,
Interest on Receivables and Payables (“APB 21”) and SFAS No. 141, Business Combinations (“SFAS 141”),
we recorded the promissory notes at fair value which resulted in a discount being recorded. The discount will
be recognized as interest expense over the life of the promissory notes using the effective interest method. The
amount of discount remaining to be amortized as of December 31, 2008 and 2007 was $0.2 million and
$0.3 million, respectively, for both notes in the aggregate. The total amount of discount amortization included
in interest expense related to the notes for the years ended December 31, 2008 and 2007 was approximately
$0.1 million and less than $0.1 million, respectively.
Long-Term Debt Principal Repayment and Interest Expense
Presented below is a schedule of the repayment requirements of long-term debt for each of the next five
years and thereafter as of December 31, 2008:
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total principal payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: fair value discount. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Principal Amount of Long-Term Debt
(In thousands)
$ 16,500
3,015
2,000
189,813
—
425,000
636,328
182
$636,146
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Presented below is a schedule of our estimated minimum lease payments on our capital lease obligations
for the next five years and thereafter as of December 31, 2008:
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total minimum lease payments . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: executory costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net minimum lease payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: amounts representing interest . . . . . . . . . . . . . . . . . . . . . . . . .
Capital Lease Obligation Minimum
Lease Payments
(In thousands)
$10,635
7,913
4,832
1,969
378
—
25,727
(729)
24,998
(1,849)
Present value of minimum lease payments . . . . . . . . . . . . . . . . . . . .
$23,149
Interest expense for the years ended December 31, 2008, 2007 and 2006 consisted of the following:
Cash payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commitment and agency fees paid . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of discount, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred financing costs . . . . . . . . . . . . . . . . . . . .
Settlement of interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . .
Net change in accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capitalized interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
2006
Year Ended December 31,
2007
(In thousands)
$33,964
2,232
—
1,680
2,261
1,366
(5,296)
$45,211
102
140
1,975
—
333
(6,514)
$40,290
4,244
—
1,620
—
(3,869)
(3,358)
Total interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$41,247
$36,207
$38,927
As of December 31, 2008 and 2007, the weighted average interest rate of our variable rate debt was
4.17% and 5.98%, respectively.
Deferred Financing Costs
In connection with our long-term debt, we capitalized costs and expenses of approximately $0.3 million,
$13.4 million and $0.5 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Amortization of deferred financing costs totaled $2.0 million, $1.7 million and $1.6 million for the years
ended December 31, 2008, 2007 and 2006, respectively. Unamortized debt issuance costs written off and
included in the determination of the gain or loss on the extinguishment of debt were zero, $9.6 million and
103
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
zero for the years ended December 31, 2008, 2007 and 2006, respectively. Net carrying values for the years
presented appear in the table below:
December 31,
2008
2007
(In thousands)
Deferred financing costs:
Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$12,609
(2,120)
$12,262
(145)
Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$10,489
$12,117
NOTE 13. COMMITMENTS AND CONTINGENCIES
Operating Lease Arrangements
Key leases certain property and equipment under non-cancelable operating leases that expire at various
dates through 2019, with varying payment dates throughout each month.
As of December 31, 2008, the future minimum lease payments under non-cancelable operating leases are
as follows (in thousands):
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lease Payments
$ 6,312
5,664
4,578
4,000
2,996
4,679
$28,229
The Company also is party to a significant number of month-to-month leases that are cancelable at any
time. Operating lease expense was $22.4 million, $16.4 million and $17.0 million for the years ended
December 31, 2008, 2007 and 2006, respectively.
Litigation
Various suits and claims arising in the ordinary course of business are pending against us. Due in part to
the locations where we conduct business in the continental United States, we are often subject to jury verdicts
and arbitration hearings that result in outcomes in favor of the plaintiffs. We continually assess our contingent
liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and our need for the
disclosure of these items. In accordance with SFAS 5, we establish a provision for a contingent liability when
it is probable that a liability has been incurred and the amount is estimable. As of December 31, 2008, the
aggregate amount of our provisions for losses related to litigation that are deemed probable and estimable is
approximately $4.5 million. We do not believe that the disposition of any of these matters will result in an
additional loss materially in excess of amounts that have been recorded. In the year ended December 31, 2008,
we recorded a benefit of approximately $2.2 million related to settlement of ongoing legal matters and
continued refinement of liabilities recognized for litigation deemed probable and estimable. Provisions related
to litigation matters that were deemed probable and estimable were $6.8 million in 2007 and $28.8 million in
2006.
104
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Gonzales Matter
In September 2005, a class action lawsuit, Gonzales v. Key Energy Services, Inc., was filed in Ventura
County, California Superior Court, alleging that Key did not pay its hourly employees for travel time between
the yard and the wellhead and that certain employees were denied meal and rest periods. On September 17,
2008, we reached an agreement in principle, subject to court approval, to settle all claims related to this matter
for $1.2 million. In 2005 we recorded a liability for this lawsuit, and the subsequent settlement of this matter
in 2008 did not have a material impact on our financial position, results of operations or cash flows.
Litigation with Former Officers and Employees
We were named in a lawsuit by our former general counsel, Jack D. Loftis, Jr., filed in the U.S. District
Court, District of New Jersey on April 21, 2006, in which he alleges a “whistle-blower” claim under the
Sarbanes-Oxley Act, breach of contract, breach of duties of good faith and fair dealing, breach of fiduciary
duty and wrongful termination. On August 17, 2007, the Company filed counterclaims against Mr. Loftis
alleging attorney malpractice, breach of contract and breach of fiduciary duties. In its counterclaims, the
Company seeks repayment of all severance paid to Mr. Loftis to date (approximately $0.8 million) plus
benefits paid during the period July 8, 2004 to September 21, 2004, and damages relating to the allegations of
malpractice and breach of fiduciary duties. The case was transferred to and is now pending in the U.S. District
Court for the Eastern District of Pennsylvania and is currently set for trial in the fourth quarter of 2009. We
recorded for the fourth quarter of 2008 a liability for this matter and do not believe that the conclusion of this
matter will have a material impact on our financial position, results of operations or cash flows.
On October 17, 2006, Jane John, the ex-wife of our former chief executive officer, Francis John, filed a
complaint in Bucks County, Pennsylvania against her ex-husband and the Company. Ms. John alleges breach
of marital agreement, breach of options agreements, civil conspiracy and fraud. She alleges that Mr. John and
the Company defrauded her with regard to Mr. John’s compensation, as well as in the disclosures of marital
property. By virtue of assignments, Ms. John holds 375,000 stock options which expired unexercised during
the period before the Company became current in its financial statements, when such options could not be
exercised. In resolving a separate lawsuit between the Company and Mr. John, Mr. John agreed to indemnify
the Company with respect to damages attributable to any and all of Ms. John’s claims, other than damages
attributable to any alleged breach of Ms. John’s stock option agreements, for which the Company agreed to
indemnify Mr. John. Discovery in the case remains ongoing, and there is currently not a trial setting. We
recorded a liability for this matter for the third quarter of 2008 and do not believe that the conclusion of this
matter will have a material impact on our financial position, results of operations or cash flows.
On September 3, 2006, our former controller and former assistant controller filed a joint complaint
against the Company in the 133rd District Court, Harris County, Texas, alleging constructive termination and
breach of contract. Additionally, on January 11, 2008, our former chief operating officer, James Byerlotzer,
filed a lawsuit in the 55th District Court, Harris County, Texas, alleging breach of contract based on his
inability to exercise his stock options during the period that we were not current in our SEC filings, and based
on our failure to provide him shares of restricted stock. We are currently set for trial in both of these matters
in the second quarter of 2009. We have not recorded a liability for these matters and do not believe that the
conclusion of these matters will have a material impact on our financial position, results of operations or cash
flows.
On August 21, 2006, our former chief financial officer, Royce W. Mitchell, filed a suit against the
Company in 385th District Court, Midland County, Texas alleging breach of contract with regard to alleged
bonuses, benefits, expense reimbursements, conditional stock grants and stock options, as well as relief under
theories of quantum meruit, promissory estoppel and specific performance. On February 15, 2008, the parties
105
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
settled the matter for $0.5 million, which included reimbursement of expenses and attorneys fees of
approximately $0.4 million.
Stockholder Class Action Suits and Derivative Actions
Since June 2004, we and certain of our officers and directors were named as defendants in six class
action complaints brought on behalf of a putative class of purchasers of our securities for alleged violations of
federal securities laws, which were filed in federal district court in Texas. These six actions were consolidated
into one action. Four stockholder derivative actions were also filed, purportedly on our behalf, generally
alleging the same facts as those in the consolidated stockholder class action. On September 7, 2007, we
reached agreements in principle to settle all of these stockholder class action and derivative lawsuits in
consideration of payments totaling $16.6 million in exchange for full and complete releases for all defendants,
of which the Company paid approximately $1.1 million. We received final approval of the settlement of the
stockholder class action claims by the court on March 6, 2008, and final court approval on the derivative
settlement was received on August 8, 2008. All litigation in the stockholder class action and derivative matters
has been concluded.
Expired Option Holders
In September 2007, Belinda Taylor filed a lawsuit in the 11th Judicial District of Harris County, Texas,
on behalf of herself and all similarly situated current and former employees who held vested options that
expired between April 28, 2004 and the date that the Company became current in its financial statements (the
“Expired Option Holders”). The suit, as amended, alleged that the Company breached its contracts with the
Expired Option Holders, and breached its fiduciary duties and duties of good faith and fair dealing in the
pricing of stock options it granted to those Expired Option Holders. On March 6, 2008, the parties agreed to
settle all pending claims with all Expired Option Holders, excluding those terminated for cause and those who
have previously filed suits against us, for approximately $1.0 million, which includes all taxes and legal fees.
The court entered a final order approving the settlement on August 25, 2008 and dismissed the case. In
December 2008, the payments to the class, pursuant to the terms of the settlement, were completed.
The lawsuits in which we are involved with Jane John and our former controller and former assistant
controller, described above under “Litigation with Former Officers and Employees,” also involve claims
relating to expired stock options.
Automobile Accident Litigation
On August 22, 2007, one of our employees was involved in an automobile accident that resulted in a
third party fatality and during the first quarter of 2008 we recorded an appropriate liability for this matter. The
lawsuit arising from this accident was settled during the third quarter of 2008 and the Company recognized
incremental expense of less than $0.5 million related to the settlement during the third quarter of 2008.
Tax Audits
We are routinely the subject of audits by tax authorities, and in the past have received material
assessments from tax auditors. As of December 31, 2008 and 2007, we have recorded reserves that
management feels are appropriate for future potential liabilities as a result of these audits. While we believe
we have fully reserved for these assessments, the ultimate amount of settlements can vary from our estimates.
In connection with an ongoing sales tax audit, the Company recorded a liability of approximately
$3.2 million during the third quarter of 2008 relating to state sales taxes not collected from the Company’s
customers from 2003 through September 30, 2008 and therefore not remitted to the appropriate state agency.
106
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The provision was recorded as general and administrative expense. We do not expect that the ultimate
resolution of the matter will result in a loss materially in excess of the amount already accrued.
In connection with our former Egyptian operations, which terminated in 2005, we are undergoing income
tax audits for all periods in which we had operations. As of December 31, 2008, the Company has recorded a
liability of approximately $0.4 million relating to open Egyptian income tax audits. In the fourth quarter of
2007, the Company reached a preliminary settlement with the Egyptian tax authorities on the 2003 and 2004
tax years, recording a tax benefit of $0.7 million and reducing the tax liability accrued at December 31, 2007
to approximately $0.4 million. We do not expect that the ultimate resolution of the matter will result in a loss
materially in excess of the amount already accrued.
Self-Insurance Reserves
We maintain reserves for workers’ compensation and vehicle liability on our balance sheet based on our
judgment and estimates using an actuarial method based on claims incurred. We estimate general liability
claims on a case-by-case basis. We maintain insurance policies for workers’ compensation, vehicle liability
and general liability claims. These insurance policies carry self-insured retention limits or deductibles on a per
occurrence basis. The retention limits or deductibles are accounted for in our accrual process for all workers’
compensation, vehicular liability and general liability claims. As of December 31, 2008 and 2007, we have
recorded $68.9 million and $69.0 million, respectively, of self-insurance reserves related to workers’ compen-
sation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had approxi-
mately $10.8 million and $8.1 million of insurance receivables as of December 31, 2008 and 2007,
respectively. We feel that the liabilities we have recorded are appropriate based on the known facts and
circumstances and do not expect further losses materially in excess of the amounts already accrued for existing
claims.
Environmental Remediation Liabilities
For environmental reserve matters, including remediation efforts for current locations and those relating
to previously-disposed properties, we record liabilities when our remediation efforts are probable and the costs
to conduct such remediation efforts can be reasonably estimated. While our litigation reserves reflect the
application of our insurance coverage, our environmental reserves do not reflect management’s assessment of
the insurance coverage that may apply to the matters at issue. As of December 31, 2008 and 2007, we have
recorded $3.0 million and $3.1 million, respectively, for our environmental remediation liabilities. We feel that
the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect
further losses materially in excess of the amounts already accrued.
We provide performance bonds to provide financial surety assurances for the remediation and mainte-
nance of our SWD properties to comply with environmental protection standards. Costs for SWD properties
may be mandatory (to comply with applicable laws and regulations), in the future (required to divest or cease
operations), or for optimization (to improve operations, but not for safety or regulatory compliance).
Registration Payment Arrangement
In January 1999, we issued 150,000 warrants (the “Warrants”) in connection with a debt offering that
were exercisable for an aggregate of approximately 2.2 million shares of the Company’s stock at an exercise
price of $4.88125 per share. As of December 31, 2008, 83,800 Warrants had been exercised, leaving 66,200
outstanding, which were exercisable for approximately 1.0 million shares of our common stock. Termination
notice was provided to the holders of the outstanding Warrants that the Warrants expired on February 2, 2009.
Under the terms of the Warrants, the Company was required to maintain an effective registration
statement covering the shares potentially issuable upon exercise of the Warrants. If the Company did not have
107
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
an effective registration statement covering the shares, the Company was required to make liquidated damages
payments to the holders of the Warrants. During the twelve months ended December 31, 2008, 2007 and 2006,
the Company made liquidated damages payments totaling $0.8 million, $0.9 million and $0.9 million,
respectively. On August 21, 2008, the requisite registration statement required by the terms of the Warrants
became effective. From and after August 22, 2008, no additional liquidated damage payments were required to
be made by the Company.
NOTE 14. ACCUMULATED OTHER COMPREHENSIVE LOSS
The components of our accumulated other comprehensive loss are as follows:
December 31,
2008
2007
(In thousands)
Foreign currency translation loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(46,520)
(30)
Deferred loss from available for sale investments. . . . . . . . . . . . . . . . . . . . . .
$(37,959)
(22)
Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . $(46,550)
$(37,981)
The local currency is the functional currency for our operations in Argentina, Mexico and Canada, and
for our equity investments in Canada and the Russian Federation. The cumulative translation gains and losses
resulting from translating each foreign subsidiary’s financial statements from the functional currency to
U.S. dollars are included in other comprehensive income and accumulated in stockholders’ equity until a
partial or complete sale or liquidation of our net investment in the foreign entity. The table below summarizes
the conversion ratios used to translate the financial statements and the cumulative currency translation gains
and losses, net of tax, for each currency:
As of December 31, 2008:
Conversion ratio . . . . . . . . .
Cumulative translation
Argentine Peso Mexican Peso Canadian Dollar
Euro
Russian Rouble
Total
(In thousands, except for conversion ratios)
3.46:1
13.78:1
1.22:1
0.71:1
29.48:1
n/a
adjustment . . . . . . . . . . . .
$(43,654)
$ (1,663)
$ (917)
$ (286)
$
— $(46,520)
As of December 31, 2007:
Conversion ratio . . . . . . . . .
Cumulative translation
3.15:1
10.92:1
0.98:1
0.68:1
24.51:1
n/a
adjustment . . . . . . . . . . . .
$(38,181)
$
(143)
$
365
$ — $
— $(37,959)
NOTE 15. EMPLOYEE BENEFIT PLANS
We maintain a 401(k) plan as part of our employee benefits package. We match 100% of employee
contributions up to 4% of the employee’s salary into our 401(k) plan, subject to maximums of $9,200, $9,000
and $8,800 for the years ended December 31, 2008, 2007 and 2006, respectively. Our matching contributions
were $11.9 million, $10.2 million and $7.4 million for the years ended December 31, 2008, 2007 and 2006,
respectively. Employees are fully vested in the matching contributions when they are made by the Company.
Effective January 1, 2006, we no longer offered participants the option to purchase units of company
stock through a 401(k) plan fund. We discontinued this option for participants and transferred all units of Key
stock into another 401(k) plan fund, which did not affect the ability of plan participants to manage these
contributions.
108
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 16. STOCKHOLDERS’ EQUITY
Common Stock
On December 31, 2008, we had 200,000,000 shares of common stock authorized with a $0.10 par value,
of which 121,305,289 shares were issued and outstanding, and during 2008 no dividends were paid. On
December 31, 2007, we had 200,000,000 shares of common stock authorized with a $0.10 par value, of which
131,142,905 shares were issued and outstanding, and during 2007 no dividends were paid. Under the terms of
the Senior Notes and Senior Secured Credit Facility, we must meet certain financial covenants before we may
pay dividends. We currently do not intend to pay dividends.
Share Repurchase Program
In October 2007, our Board of Directors authorized a share repurchase program of up to $300.0 million
which is effective through March 31, 2009. From the inception of the program in November 2007 through
December 31, 2008, we have repurchased approximately 13.4 million shares of our common stock through
open market transactions for an aggregate price of approximately $167.3 million. Share repurchases during
2008 were approximately 11.1 million shares for an aggregate price of approximately $135.2 million. Our
repurchase program, as well as the amount and timing of future repurchases, is subject to market conditions,
our financial condition, and our liquidity. Our Senior Secured Credit Facility permits us to make stock
repurchases in excess of $200.0 million only if our consolidated debt to capitalization ratio (as defined) is
below 50%; as of December 31, 2008, that ratio was below 50%.
Tax Withholding
In June 2006, the Company began purchasing shares of restricted common stock that had been previously
granted to certain of the Company’s officers, pursuant to an agreement under which those individuals were
permitted to sell shares back to the Company in order to satisfy the minimum income tax withholding
requirements related to vesting of these grants. We repurchased a total of 97,443 and 72,847 shares for an
aggregate cost of $1.2 million and $1.3 million during 2008 and 2007, respectively, which represented the fair
market value of the shares based on the price of the Company’s stock on the dates of purchase.
Through December 31, 2008, under the share repurchase program, tax withholdings and share acquisitions
in prior years, we have repurchased approximately 13.7 million shares of our common stock, at an aggregate
cost of $171.0 million.
Common Stock Warrants
In January 1999, we issued 150,000 warrants (the “Warrants”) in connection with a debt offering that
were exercisable for an aggregate of approximately 2.2 million shares of the Company’s stock at an exercise
price of $4.88125 per share. As of December 31, 2008, 83,800 Warrants had been exercised, leaving 66,200
outstanding, which were exercisable for approximately 1.0 million shares of our common stock. Termination
notice was provided to the holders of the outstanding Warrants and the Warrants expired on February 2, 2009.
Under the terms of the Warrants, the Company was required to maintain an effective registration
statement covering the shares potentially issuable upon exercise of the Warrants. If the Company did not have
an effective registration statement covering the shares, the Company was required to make liquidated damages
payments to the holders of the Warrants. Because of the Company’s past failure to timely file its Annual and
Quarterly Reports with the SEC, it did not have an effective registration statement, and during the twelve
months ended December 31, 2008, 2007 and 2006, the Company made liquidated damages payments totaling
$0.8, $0.9 and $0.9 million, respectively. On August 21, 2008, the requisite registration statement required by
the terms of the Warrants became effective. From and after August 22, 2008, no additional liquidated damage
payments were required to be made by the Company related to the Warrants.
109
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 17. SHARE-BASED COMPENSATION
2007 Incentive Plan
On December 6, 2007, the Company’s shareholders approved the 2007 Equity and Cash Incentive Plan
(the “2007 Incentive Plan”). The 2007 Incentive Plan is administered by the Board or a committee designated
by the Board (the “Committee”). The Board or the Committee (the “Administrator”) will have the power and
authority to select Participants (as defined below) in the 2007 Incentive Plan and to grant Awards (as defined
below) to such Participants pursuant to the terms of the 2007 Incentive Plan.
Subject to adjustment, the total number of shares of the Company’s common stock, par value $0.10 per
share, that will be available for the grant of Awards under the 2007 Incentive Plan may not exceed
4,000,000 shares; however, for purposes of this limitation, any stock subject to an award that is canceled,
forfeited or expires prior to exercise or realization will again become available for issuance under the 2007
Incentive Plan. Subject to adjustment, no Participant will be granted, during any one year period, options to
purchase common stock and/or stock appreciation rights with respect to more than 500,000 shares of common
stock. Stock available for distribution under the 2007 Incentive Plan will come from authorized and unissued
shares or shares reacquired by the Company in any manner. All awards under the 2007 Incentive Plan are
granted at fair market value on the date of issuance.
Awards may be in the form of options (incentive stock options and nonstatutory stock options), restricted
stock, restricted stock units, performance compensation awards and stock appreciation rights (collectively,
“Awards”). Awards may be granted to employees, directors and, in some cases, consultants and those
individuals whom the Administrator determines are reasonably expected to become employees, directors or
consultants following the grant date of the Award (“Participants”). However, incentive stock options may be
granted only to employees. Vesting periods may be set at the Board’s discretion, and Awards have ten-year
contractual lives.
The Board at any time, and from time to time, may amend or terminate the 2007 Incentive Plan.
However, except as provided otherwise in the 2007 Incentive Plan, no amendment will be effective unless
approved by the shareholders of the Company to the extent shareholder approval is necessary to satisfy any
applicable law or securities exchange listing requirements. As of December 31, 2008, there have been
1,806,556 awards granted with 2,250,144 remaining grants available under the 2007 Incentive Plan.
1997 Incentive Plan
On January 13, 1998, Key’s shareholders approved the Key Energy Group, Inc. 1997 Incentive Plan, as
amended (the “1997 Incentive Plan”, and together with the 2007 Incentive Plan, the “Plans”). The 1997
Incentive Plan is an amendment and restatement of the plans formerly known as the Key Energy Group, Inc.
1995 Stock Option Plan and the Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan. On
November 17, 2007, the 1997 Incentive Plan terminated pursuant to its terms.
The exercise price of options granted under the 1997 Incentive Plan is at or above the fair market value
per share on the date the options are granted. Under the 1997 Incentive Plan, while the shares of common
stock are listed on a securities exchange, fair market value was determined using the closing sales price on the
immediate preceding business day as reported on such securities exchange.
When the shares were not listed on an exchange, which includes the period from April 2005 through
October 2007, the fair market value was determined by using the published closing price of the common stock
on the Pink Sheets on the business day immediately preceding the date of grant.
The exercise of NSOs results in a U.S. tax deduction to us equal to the difference between the exercise
price and the market price at the exercise date.
110
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
During the period 2000-2001, the Board of Directors granted 3.7 million stock options that were outside
the 1997 Incentive Plan, of which 120,000 remained outstanding as of December 31, 2008 The 3.7 million
non-plan options were in addition to and do not include other options which were granted under the 1997
Incentive Plan, but not in conformity with certain of the terms of the 1997 Incentive Plan.
Accelerated Vesting of Option and SAR Awards
Because of declines in the Company’s stock price, the Company’s Board of Directors resolved during the
fourth quarter of 2008 to accelerate the vesting period on certain of the Company’s outstanding unvested stock
option awards and stock appreciation rights, which affected approximately 280 employees. As a result of the
acceleration, the Company recorded a pre-tax charge of approximately $10.9 million in general and adminis-
trative expense in the accompanying consolidated statement of operations.
Stock Option Awards
Stock option awards granted under the Plans have a maximum contractual term of ten years from the date
of grant. Shares issuable upon exercise of a stock option are issued from authorized but unissued shares of the
Company’s common stock. The following table summarizes the stock option activity related to the Plans and
certain options granted in prior years that were outside the 1997 Incentive Plan. 5.0 million options were
outstanding as of December 31, 2008, and 2.3 million shares remained available for issuance under the 2007
Incentive Plan as of December 31, 2008 (shares in thousands):
Outstanding at beginning of period. . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancelled or expired . . . . . . . . . . . . . . . . . . . . . . . . .
Options
4,594
1,379
(757)
(255)
Outstanding at end of period . . . . . . . . . . . . . . . . . . .
4,961
Exercisable at end of period . . . . . . . . . . . . . . . . . . . .
4,911
Outstanding at beginning of period. . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancelled or expired . . . . . . . . . . . . . . . . . . . . . . . . .
Options
5,829
1,195
(1,592)
(838)
Outstanding at end of period . . . . . . . . . . . . . . . . . . .
4,594
Exercisable at end of period . . . . . . . . . . . . . . . . . . . .
2,615
Year Ended December 31, 2008
Weighted Average
Exercise Price
Weighted Average
Fair Value
$11.01
$14.76
$ 8.81
$14.53
$12.21
$12.30
$5.32
$5.43
$4.81
$6.15
$5.38
$5.42
Year Ended December 31, 2007
Weighted Average
Exercise Price
Weighted Average
Fair Value
$ 9.46
$14.41
$ 8.45
$10.36
$11.01
$ 8.34
$4.94
$5.98
$4.58
$5.03
$5.32
$4.47
111
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Outstanding at beginning of period. . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancelled or expired(1) . . . . . . . . . . . . . . . . . . . . . . .
Options
9,275
833
—
(4,279)
Outstanding at end of period . . . . . . . . . . . . . . . . . . .
5,829
Exercisable at end of period . . . . . . . . . . . . . . . . . . . .
4,791
Year Ended December 31, 2006
Weighted Average
Exercise Price
Weighted Average
Fair Value
$ 8.68
$15.03
$ —
$ 8.86
$ 9.46
$ 8.42
$4.79
$7.21
$ —
$5.06
$4.94
$4.51
(1) Cancelled/expired options in 2006 include approximately 3.9 million options previously held by our former
chief executive officer, which were cancelled in connection with his termination.
The following table summarizes information about the stock options outstanding at December 31, 2008
(shares in thousands):
Options Outstanding
Weighted Average
Remaining
Contractual Life
(Years)
Number of
Options
Outstanding
Weighted Average
Exercise Price
Weighted Average
Fair Value
Range of exercise prices:
$ 3.00 - $ 7.44 . . . . . . . . . . . .
$ 7.45 - $ 9.37 . . . . . . . . . . . .
$ 9.38 - $13.10 . . . . . . . . . . . .
$13.11 -$14.70 . . . . . . . . . . . .
$14.71 -$19.42 . . . . . . . . . . . .
1.42
2.28
5.63
8.55
8.63
Aggregate intrinsic value (in
thousands) . . . . . . . . . . . . . .
549
660
813
1,066
1,873
4,961
$ 578
$ 3.85
$ 8.31
$11.32
$14.31
$15.22
$12.21
$2.62
$4.89
$5.28
$5.99
$6.14
$5.38
Range of exercise prices:
$ 3.00 - $ 7.44 . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 7.45 - $ 9.37 . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 9.38 - $13.10 . . . . . . . . . . . . . . . . . . . . . . . . . . .
$13.11 -$14.70 . . . . . . . . . . . . . . . . . . . . . . . . . . .
$14.71 -$19.42 . . . . . . . . . . . . . . . . . . . . . . . . . . .
Options Exercisable
Number of
Options
Exercisable
Weighted Average
Exercise Price
Weighted Average
Fair Value
499
653
821
1,066
1,872
4,911
$ 3.83
$ 8.33
$11.30
$14.31
$15.22
$12.30
$2.71
$4.89
$5.11
$5.99
$6.14
$5.42
Aggregate intrinsic value (in thousands) . . . . . . . . .
$ 556
The total fair value of stock options granted during the years ended December 31, 2008, 2007 and 2006
was $7.5 million, $7.1 million and $6.0 million, respectively. The total fair value of stock options vested
during the year ended December 31, 2008 was $19.4 million, including $14.8 million resulting from the
112
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
acceleration of the vesting of certain of the Company’s equity awards. For the years ended December 31,
2008, 2007 and 2006, the Company recognized approximately $15.1 million, $3.5 million and $2.6 million in
pre-tax expense related to stock options, respectively. For unvested stock option awards outstanding as of
December 31, 2008, the Company expects to recognize approximately less than $0.1 million of compensation
expense over a weighted average remaining vesting period of approximately 2.4 years. The weighted average
remaining contractual term for stock option awards exercisable as of December 31, 2008 is 6.5 years. The
intrinsic value of the options exercised for the years ended December 31, 2008 and 2007 was $5.8 million and
$10.2 million, respectively. No options were exercised in 2006. Cash received from the exercise of options for
the year ended December 31, 2008 was $6.7 million with recognition of associated tax benefits in the amount
of $5.2 million.
Common Stock Awards
In June 2005 we began granting shares of common stock to our outside directors and certain employees.
Common stock awards granted to our outside directors vest immediately, while those granted to our employees
vest ratably over a three-year period and are subject to forfeiture. The total fair market value of all common
stock awards granted during the years ended December 31, 2008, 2007 and 2006 was $6.5 million, $4.7 million
and $5.9 million, respectively.
Pursuant to the agreement under which they are issued common stock awards, recipients of those awards
may have shares withheld in order to satisfy those individuals’ income tax obligations associated with the
vesting of the awards granted to them. Shares withheld for tax withholding purposes totaled 97,443 and
72,847 for the years ended December 31, 2008 and 2007, respectively, with aggregate repurchase values of
$1.2 million and $1.3 million, respectively. In connection with a vesting in June of 2006, one of the recipients
was permitted to have an amount withheld that was in excess of the required minimum withholding under
current tax law. Under SFAS 123(R), the Company is required to account for this grant as a liability award.
Compensation expense for this award during the years ended December 31, 2008, 2007 and 2006 was less
than $0.1 million, $0.1 million and $0.2 million, respectively. The last tranche of shares associated with this
award vested during 2008.
The following table summarizes information for the years ended December 31, 2008, 2007 and 2006
about the common share awards that have been issued by the Company (shares in thousands):
Year Ended December 31, 2008
Outstanding
Weighted Average
Issuance Price
Shares at beginning of year. . . . . . . . . . .
Shares issued during year(1) . . . . . . . . . .
Previously issued shares vesting during
year . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares repurchased during year . . . . . . . .
1,078
428
—
(97)
Shares at end of year . . . . . . . . . . . . . . .
1,409
$14.01
$15.10
$ —
$12.86
$14.42
Vested
478
47
320
(97)
748
Weighted Average
Issuance Price
$13.48
$18.01
$13.97
$12.86
$14.05
113
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Year Ended December 31, 2007
Outstanding
Weighted Average
Issuance Price
Shares at beginning of year. . . . . . . . . . .
Shares issued during year(1) . . . . . . . . . .
Previously issued shares vesting during
year . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares repurchased during year . . . . . . . .
833
318
—
(73)
Shares at end of year . . . . . . . . . . . . . . .
1,078
$13.69
$14.87
$ —
$14.05
$14.01
Vested
258
54
239
(73)
478
Weighted Average
Issuance Price
$12.44
$17.48
$13.87
$14.05
$13.48
Year Ended December 31, 2006
Outstanding
Weighted Average
Issuance Price
Vested
Weighted Average
Issuance Price
Shares at beginning of year. . . . . . . . . . .
Shares issued during year(1) . . . . . . . . . .
Previously issued shares vesting during
year . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares repurchased during year . . . . . . . .
Shares at end of year . . . . . . . . . . . . . . .
543
371
—
(81)
833
$11.90
$15.92
$ —
$11.90
$13.69
43
46
250
(81)
258
$11.90
$14.95
$11.90
$11.90
$12.44
(1) Shares of common stock issued to our non-employee directors vest immediately upon issuance.
For common stock grants that vest immediately upon issuance, the Company records expense equal to the
fair market value of the shares on the date of grant. For common stock awards that do not immediately vest,
the Company recognizes compensation expense ratably over the vesting period of the grant, net of estimated
and actual forfeitures. For the years ended December 31, 2008, 2007 and 2006, the Company recognized
$6.1 million, $5.6 million and $3.6 million, respectively, of pre-tax expense associated with common stock
awards, including common stock grants to our outside directors, net of estimated and actual forfeitures. In
connection with the expense related to common stock awards recognized during the year ended December 31,
2008, the Company recognized tax benefits of approximately $1.5 million. For the unvested common stock
awards outstanding as of December 31, 2008, the Company anticipates that it will recognize approximately
$5.5 million of pre-tax expense over the next 1.5 years.
Phantom Share Plan
In December 2006, the Company announced the implementation of a “Phantom Share Plan,” in which
certain of our employees were granted “Phantom Shares.” The Phantom Shares vest ratably over a four-year
period and convey the right to the grantee to receive a cash payment on the anniversary date of the grant equal
to the fair market value of the Phantom Shares vesting on that date. Grantees are not permitted to defer this
payment to a later date. The Phantom Shares are a “liability” type award under SFAS 123(R), and we account
for these awards at fair value. We recognize compensation expense related to the Phantom Shares based on the
change in the fair value of the awards during the period and the percentage of the service requirement that has
been performed, net of estimated and actual forfeitures, with an offsetting liability recorded on our
consolidated balance sheets. We recognized less than $0.1 million of pre-tax benefit and approximately
$3.3 million of pre-tax compensation expense associated with the Phantom Shares for the years ended
December 31, 2008 and 2007, respectively. As of December 31, 2008, we recorded current and non-current
liabilities of $0.9 million and $0.5 million, respectively, which represented the aggregate fair value of the
114
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Phantom Shares on that date. As of December 31, 2006, the amount of compensation expense and liabilities
recorded related to the Phantom Share Plan in our consolidated financial statements were not material.
We recognized income tax benefits associated with the Phantom Shares of less than $0.1 million and
$1.3 million in 2008 and 2007, respectively. For unvested Phantom Share awards outstanding as of
December 31, 2008, we expect to recognize approximately $1.3 million of compensation expense over a
weighted average remaining vesting period of approximately 1.7 years. The first payout under the Phantom
Share Plan was made in January 2008, at which time we paid approximately $1.6 million in cash to the
holders of Phantom Shares that vested in December 2007.
Stock Appreciation Rights
In August 2007, the Company issued approximately 587,000 SARs to its executive officers. Each SAR
has a ten-year term from the date of grant and vests in equal annual installments on the first, second and third
anniversaries of the date of grant. Upon the exercise of a SAR, the recipient will receive an amount equal to
the difference between the exercise price and the fair market value of a share of the Company’s common stock
on the date of exercise, multiplied by the number of shares of common stock for which the SAR was
exercised. All payments will be made in shares of the Company’s common stock. Prior to exercise, the SAR
does not entitle the recipient to receive any shares of the Company’s common stock and does not provide the
recipient with any voting or other stockholders’ rights. The Company accounts for these SARs as equity
awards under SFAS 123(R) and recognizes compensation expense ratably over the vesting period of the SAR
based on their fair value on the date of issuance, net of estimated and actual forfeitures.
Compensation expense recognized in 2008 and 2007 in connection with the SARs was approximately
$3.1 million and $0.6 million, respectively. Income tax benefits of approximately $1.1 million and $0.2 million
in 2008 and 2007, respectively, were recognized by the Company in connection with this expense. The vesting
of all of the Company’s outstanding SAR awards was accelerated during the fourth quarter of 2008 and
therefore there were no outstanding unvested SAR awards as of December 31, 2008. As such, the Company
will not recognize expense in future periods associated with these awards.
Valuation Assumptions on Stock Options and Stock Appreciation Rights
The fair value of each stock option grant or SAR was estimated on the date of grant using the Black-
Scholes option-pricing model, based on the following weighted-average assumptions:
Year Ended December 31,
2008
2006
2007
Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected life of options, years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected volatility of the Company’s stock price . . . . . . . . . . . . . . . . . . . .
Expected dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NOTE 18. TRANSACTIONS WITH RELATED PARTIES
Employee Loans and Advances
6
2.86% 4.41% 4.70%
6
36.86% 39.49% 48.80%
none
none
none
6
From time to time and continuing in the comparative periods contained in this report, we have made
certain retention loans and relocation loans to employees other than executive officers. The retention loans are
forgiven over various time periods so long as the employee continues employment at the Company. The
relocation loans are repaid upon the employee selling his prior residence. As of December 31, 2008 and 2007,
these loans, in the aggregate, totaled approximately $0.2 million and $0.2 million, respectively. Of this
115
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
amount, less than $0.1 million were made to former officers of the Company, with the remainder being made
to current employees of the Company.
Seller Financing Arrangement Associated with Moncla Acquisition
In connection with the acquisition of Moncla (see “Note 2. Acquisitions”), the Company entered into two
promissory notes payable agreement with the seller, who, subsequent to the acquisition, became an officer of
the Company. The first is an unsecured note in the amount of $12.5 million, which is due and payable in a
lump-sum, together with accrued interest, on October 25, 2009. Interest on this note is payable on each
anniversary of the closing of the acquisition of Moncla, which was October 25, 2007. The second unsecured
note in the amount of $10.0 million is payable in annual installments of $2.0 million, plus accrued interest,
beginning October 25, 2008 through 2012. Each of the notes bears interest at the Federal Funds rate adjusted
annually on the anniversary of the closing date.
The Federal Funds rate does not represent a rate that would have resulted if an independent borrower and
an independent lender had negotiated a similar transaction under comparable terms and conditions and is not
equal to our incremental borrowing rate. In accordance with APB 21 and SFAS 141, we recorded the
promissory notes at fair value which resulted in a discount being recorded. The discount will be recognized as
interest expense over the life of the promissory notes using the effective interest method.
Transactions with Employees
In connection with our acquisition of Western, the former owner of Western, Fred Holmes, became an
employee of the Company. Mr. Holmes owned at the time of the acquisition, and continues to own, an
exploration and production company, Holmes Western Oil Corporation (“HWOC”), which was a customer of
Western. Subsequent to the acquisition, the Company continued to provide services to HWOC. The prices
charged for these services are at rates that are an average of the prices charged to our other customers in the
California market. As of December 31, 2008, our receivables with HWOC totaled approximately $0.2 million,
and for the year ended December 31, 2008, revenues from HWOC totaled approximately $4.3 million.
Board of Director Relationship with Customer
In October 2007, we added a member to the Company’s Board of Directors who is the Senior Vice
President, General Counsel and Chief Administrative Officer of Anadarko Petroleum Corporation (“Ana-
darko”), which is one of our customers. Sales to Anadarko comprised less than 2% of our total revenues for
the years ended December 31, 2008 and 2007, respectively. Transactions with Anadarko for our services are
made at market prices.
NOTE 19. SEGMENT INFORMATION
For 2008, our reportable operating business segments are well servicing, pressure pumping and fishing
and rental. We aggregate services which create our reportable segments in accordance with SFAS 131. The
accounting policies of the reportable segments are the same as those described in “Note 1. Organization and
Summary of Significant Accounting Policies.” We evaluate the performance of our operating segments based
on revenue and EBITDA, which is a non-GAAP measure and not disclosed below. All inter-segment sales
pricing is based on current market conditions.
Well servicing. These operations provide a full range of well services, including rig-based services,
oilfield transportation services, cased-hole wireline services and other ancillary oilfield services necessary to
complete, maintain and workover oil and natural gas producing wells. Our Argentina and Mexico operations
are included in our well servicing segment. We aggregate our operating divisions engaged in well servicing
activities into our well servicing reportable segment.
116
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Pressure pumping. These operations provide well stimulation and cementing services. Stimulation
includes fracturing, nitrogen services and acidizing services and is used to enhance the production of oil and
natural gas wells from formations which exhibit a restricted flow of oil and / or natural gas. Cementing
services include pumping cement into a well between the casing and the wellbore.
Fishing and rental. These operations provide services that include “fishing” to recover lost or stuck
equipment in a wellbore through the use of “fishing tools.” In addition, this segment offers a full line of
services and rental equipment designed for use both onshore and offshore for drilling and workover services
and includes an inventory consisting of tubulars, handling tools, pressure-control equipment and power
swivels.
Corporate / Other. We apply the provisions of EITF 04-10 for our segment reporting. Under the
provisions of EITF 04-10, operating segments that do not individually meet the aggregation criteria described
in SFAS 131 may be combined with other operating segments that do not individually meet the aggregation
criteria to form a separate reportable segment. We have combined all of our operating segments that do not
individually meet the aggregation criteria established in SFAS 131 to form the “Corporate and Other” segment
for our segment reporting. Corporate expenses include general expenses associated with managing all
reportable operating segments. Corporate assets consist principally of cash and cash equivalents, short-term
investments, deferred financing costs, investments in subsidiaries, accounts and notes receivable from subsid-
iaries, the Company’s investment in IROC Services Corp., and deferred income tax assets.
Well
Servicing
Pressure
Pumping
Fishing
and Rental
Corporate/
Other
Eliminations
Total
(In thousands)
As of and for the year
ended December 31,
2008:
Operating revenues . . . . . .
Inter-segment revenue . . . .
Direct operating
expenses . . . . . . . . . . . .
Depreciation and
$1,509,823
4,153
$344,993
$117,272
1,221
$
— $
— $1,972,088
—
(5,374)
942,886
239,870
70,706
—
(3,135)
1,250,327
amortization expense . . .
125,008
22,237
11,809
11,720
—
170,774
Interest expense, net of
amounts capitalized . . . .
Net income (loss) . . . . . . .
Property and equipment,
net . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . .
Capital expenditures,
excluding acquisitions . .
(1,880)
347,007
(1,402)
23,834
(512)
3,991
44,793
(289,329)
248
(1,445)
41,247
84,058
762,849
1,688,732
191,563
277,693
62,429
103,521
34,842
2,035,206
— 1,051,683
2,016,923
(2,088,229)
147,963
42,860
19,970
8,201
—
218,994
117
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Well
Servicing
Pressure
Pumping
Fishing
and Rental
Corporate/
Other
Eliminations
Total
(In thousands)
As of and for the year ended
December 31, 2007:
Operating revenues, net . . . . $1,264,797
Direct operating expenses . .
738,694
Depreciation and
$299,348
189,645
$97,867
57,275
$
— $
—
— $1,662,012
985,614
—
amortization expense . . . .
90,274
16,854
8,742
13,753
—
129,623
Interest expense, net of
amounts capitalized . . . . .
Net income (loss) . . . . . . . .
Property and equipment,
net
. . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . .
Capital expenditures,
excluding acquisitions . . .
(712)
360,617
(1,048)
83,785
(493)
22,028
38,708
(297,141)
(248)
—
36,207
169,289
693,804
1,500,913
133,903
247,018
48,703
89,802
34,798
402,513
—
(381,169)
911,208
1,859,077
135,336
51,115
19,811
6,298
—
212,560
Well
Servicing
Pressure
Pumping
Fishing
and Rental
Corporate/
Other
Eliminations
Total
(In thousands)
As of and for the year ended
December 31, 2006:
Operating revenues, net
Direct operating expenses . . .
Depreciation and
. . . . $1,201,228
725,008
$247,489
138,377
$97,460
57,217
$
— $ — $1,546,177
920,602
—
—
amortization expense . . . .
95,673
12,416
6,787
11,135
(615)
311,339
(600)
88,070
(98)
22,860
40,240
(251,236)
—
—
—
126,011
38,927
171,033
Interest expense, net of
amounts capitalized . . . . .
Net income (loss) . . . . . . . . .
Property and equipment,
net . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . .
Capital expenditures,
excluding acquisitions . . . .
531,685
1,022,898
97,372
190,704
35,971
79,364
29,263
206,622
—
41,810
694,291
1,541,398
143,080
35,513
12,953
4,284
—
195,830
118
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table presents information related to our foreign operations (in thousands of U.S. Dollars):
U.S.
Argentina
Mexico
Canada
Eliminations
Total
(In thousands)
As of and for the year ended
December 31, 2008:
Revenue from external
customers . . . . . . . . . . . . . . . . $1,800,199
1,434,578
Long-lived assets. . . . . . . . . . . . .
Capital expenditures, excluding
acquisitions . . . . . . . . . . . . . . .
181,525
$118,841
25,419
$47,200
45,547
$ 5,848
7,482
$
(55,225)
— $1,972,088
1,457,801
2,677
34,792
—
—
218,994
As of and for the year ended
December 31, 2007:
Revenue from external
customers . . . . . . . . . . . . . . . .
Long-lived assets. . . . . . . . . . . . .
Capital expenditures, excluding
1,556,108
1,368,735
$ 93,925
29,762
$ 9,041
11,089
$ 2,938
10,782
$
(49,156)
— $1,662,012
1,371,212
acquisitions . . . . . . . . . . . . . . .
197,120
3,997
11,348
95
—
212,560
As of and for the year ended
December 31, 2006:
Revenue from external
customers . . . . . . . . . . . . . . . . $1,467,856
1,064,031
Long-lived assets. . . . . . . . . . . . .
Capital expenditures, excluding
acquisitions . . . . . . . . . . . . . . .
186,348
$ 78,321
30,623
9,482
$ — $ — $
— $1,546,177
1,052,792
(41,862)
—
—
—
—
—
195,830
NOTE 20. SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
2008
Year Ended December 31,
2007
(In thousands)
2006
Noncash investing and financing activities:
Property and equipment acquired under captial lease obligations . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized (loss) gain on short-term investments . . . . . . . . . . . . . .
Unrealized gain on cash flow hedges . . . . . . . . . . . . . . . . . . . . . . .
Accrued repurchases of common stock . . . . . . . . . . . . . . . . . . . . . .
Debt assumed and issued in acquisitions. . . . . . . . . . . . . . . . . . . . .
Software acquired under financing arrangement . . . . . . . . . . . . . . .
Supplemental cash flow information:
Cash paid for interest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash paid for taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$12,003
$ 7,654
12
397
—
(8)
—
—
—
2,949
— 40,149
—
3,985
$15,349
155
328
185
—
—
—
$45,313
$43,494
$38,457
$96,327
$44,534
$99,048
Cash paid for interest includes cash payments for interest on our long-term debt and capital lease
obligations, commitment and agency fees paid, and cash paid to settle the interest rate swaps associated with
the termination of our Prior Credit Facility.
119
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 21. UNAUDITED SUPPLEMENTARY INFORMATION — QUARTERLY RESULTS OF
OPERATIONS
Set forth below is unaudited summarized quarterly information for the two most recent years covered by
these consolidated financial statements (in thousands, except for per share data):
Year Ended December 31, 2008:
Revenues . . . . . . . . . . . . . . . . . . .
Direct operating expenses . . . . . . .
Impairment of goodwill and equity
method investment . . . . . . . . . .
Income (loss) before income
taxes. . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . .
Earnings per share(1):
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
$456,399
281,641
$502,003
322,488
$535,620
342,195
$478,066
304,003
—
—
—
75,137
56,907
34,484
71,247
44,012
77,541
48,462
(31,639)
(42,900)
Basic . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . .
$
$
0.27
0.27
$
$
0.35
0.35
$
$
0.39
0.39
$
$
(0.35)
(0.35)
First Quarter
Second Quarter
Third Quarter
Fourth Quarter(2)
Year Ended December 31, 2007:
Revenues . . . . . . . . . . . . . . . . .
Direct operating expenses . . . . .
Income before income taxes . . .
Net income . . . . . . . . . . . . . . . .
Earnings per share(1):
$408,919
235,513
84,694
52,190
Basic. . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . .
$
$
0.40
0.39
$410,511
238,223
78,471
48,136
$
$
0.37
0.36
$413,967
257,482
59,832
35,896
$
$
0.27
0.27
$428,615
254,396
52,943
33,067
$
$
0.25
0.25
(1) Quarterly earnings per common share are based on the weighted average number of shares outstanding
during the quarter, and the sum of the quarters may not equal annual earnings per common share.
(2) Revenues, gross margins, income before income taxes, net income and earnings per share were impacted
in the fourth quarter of 2007 due to the acquisitions of Moncla, Kings and AMI. See “Note 2.
Acquisitions.”
NOTE 22. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
The Notes are guaranteed by virtually all of our domestic subsidiaries, all of which are wholly-owned.
The guarantees were joint and several, full, complete and unconditional. There were no restrictions on the
ability of subsidiary guarantors to transfer funds to the parent company.
As a result of these guarantee arrangements, we are required to present the following condensed
consolidating financial information pursuant to SEC Regulation S-X Rule 3-10, “Financial Statements of
Guarantors and Issuers of Guaranteed Securities Registered or Being Registered.”
120
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CONDENSED CONSOLIDATING BALANCE SHEET
Parent
Company
Guarantor
Subsidiaries
December 31, 2008
Non-Guarantor
Subsidiaries
(In thousands)
Eliminations
Consolidated
Assets:
Current assets . . . . . . . . . . . . . . . $
Property and equipment, net . . . .
Goodwill . . . . . . . . . . . . . . . . . .
Deferred financing costs, net . . . .
Intercompany notes and accounts
receivable and investment in
subsidiaries . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . .
29,673
$ 440,758
— 1,025,007
316,669
—
—
10,489
$ 88,534
26,676
4,323
—
$
157
$ 559,122
— 1,051,683
320,992
—
10,489
—
1,917,522
22,597
419,554
48,237
1,775
3,803
(2,338,851)
—
—
74,637
TOTAL ASSETS. . . . . . . . . . . . . . $1,980,281
$2,250,225
$125,111
$(2,338,694)
$2,016,923
Liabilities and equity:
Current liabilities . . . . . . . . . . . . $
Capital lease obligations, less
current portion . . . . . . . . . . . .
Notes payable — related parties,
less current portion . . . . . . . . .
Long-term debt, less current
portion . . . . . . . . . . . . . . . . . .
Intercompany notes and accounts
payable . . . . . . . . . . . . . . . . . .
Deferred tax liabilities. . . . . . . . .
Other long-term liabilities . . . . . .
Stockholders’ equity . . . . . . . . . .
TOTAL LIABILITIES AND
13,792
$ 231,528
$ 28,054
$
(1)
$ 273,373
—
—
612,813
305,348
187,596
—
860,732
13,714
6,000
1,015
1,624,932
—
60,386
312,650
49
—
—
—
—
—
69,204
985
260
26,559
(1,999,484)
—
—
(339,209)
13,763
6,000
613,828
—
188,581
60,646
860,732
STOCKHOLDERS’ EQUITY . . $1,980,281
$2,250,225
$125,111
$(2,338,694)
$2,016,923
121
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Parent
Company
Guarantor
Subsidiaries
December 31, 2007
Non-Guarantor
Subsidiaries
(In thousands)
Eliminations
Consolidated
39,501
—
—
12,117
$ 378,865
880,907
373,283
—
$ 69,499
30,301
5,267
—
$
— $ 487,865
911,208
—
378,550
—
12,117
—
Assets:
Current assets . . . . . . . . . . . . . . . . $
Property and equipment, net . . . . . .
Goodwill . . . . . . . . . . . . . . . . . . . .
Deferred financing costs, net . . . . . .
Intercompany notes and accounts
receivable and investment in
subsidiaries . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . .
Liabilities and equity:
Current liabilities . . . . . . . . . . . . . . $
Capital lease obligations, less
current portion . . . . . . . . . . . . . .
Notes payable — related parties,
less current portion . . . . . . . . . . .
Long-term debt, less current
TOTAL ASSETS. . . . . . . . . . . . . . $1,620,828
$1,860,590
$111,113
$(1,733,454)
$1,859,077
1,557,993
11,217
175,461
52,074
—
6,046
(1,733,454)
—
—
69,337
17,278
$ 192,222
$ 25,297
$
— $ 234,797
—
—
15,998
20,500
116
—
—
24,408
2,388
251
58,653
—
—
—
(1,592,445)
—
—
(141,009)
16,114
20,500
475,000
—
160,068
63,600
888,998
portion . . . . . . . . . . . . . . . . . . . .
475,000
—
Intercompany notes and accounts
payable. . . . . . . . . . . . . . . . . . . .
Deferred tax liabilities . . . . . . . . . .
Other long-term liabilities . . . . . . . .
Stockholders’ equity . . . . . . . . . .
TOTAL LIABILITIES AND
78,660
157,759
3,133
888,998
1,489,377
(79)
60,216
82,356
STOCKHOLDERS’ EQUITY . . $1,620,828
$1,860,590
$111,113
$(1,733,454)
$1,859,077
122
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
Revenues . . . . . . . . . . . . . . . . . . . . . $
Costs and expenses: . . . . . . . . . . . . .
Direct operating expenses . . . . . . . .
Depreciation and amortization
expense . . . . . . . . . . . . . . . . . . .
Impairment of goodwill and equity-
method investment . . . . . . . . . . .
General and administrative
Parent
Company
Guarantor
Subsidiaries
— $1,818,736
Year Ended December 31, 2008
Non-Guarantor
Subsidiaries
(In thousands)
$175,845
Eliminations
$(22,493)
Consolidated
$1,972,088
—
—
—
1,139,006
127,374
(16,053)
1,250,327
163,257
7,517
75,137
—
—
—
170,774
75,137
expenses . . . . . . . . . . . . . . . . . .
1,616
237,635
19,251
(795)
257,707
Interest expense, net of amounts
capitalized . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . .
Other, net
Total costs and expenses, net . . . . . .
(Loss) income before income taxes
and minority interest . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . .
Minority interest . . . . . . . . . . . . . . . .
44,842
5,219
51,677
(51,677)
(81,233)
—
(4,320)
(7,073)
477
9,143
248
(4,449)
41,247
2,840
1,603,642
163,762
(21,049)
1,798,032
215,094
(4,320)
—
12,083
(4,690)
245
(1,444)
—
—
174,056
(90,243)
245
NET (LOSS) INCOME . . . . . . . . . . $(132,910)
$ 210,774
$
7,638
$ (1,444)
$
84,058
123
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Parent
Company
Guarantor
Subsidiaries
— $1,561,059
Year Ended December 31, 2007
Non-Guarantor
Subsidiaries
(In thousands)
$105,819
Eliminations
$(4,866)
—
906,254
82,980
(3,620)
Revenues . . . . . . . . . . . . . . . . . . . . . $
Costs and expenses: . . . . . . . . . . . . .
Direct operating expenses . . . . . . . . .
Depreciation and amortization
expense . . . . . . . . . . . . . . . . . . . . .
General and administrative expenses. .
Interest expense, net of amounts
—
1,693
123,821
216,959
capitalized . . . . . . . . . . . . . . . . . . .
38,866
(3,134)
Loss on early extinguishment of
debt . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . .
9,557
(449)
—
(5,850)
5,802
11,935
723
—
1,781
—
(191)
(248)
—
(807)
Consolidated
$1,662,012
—
985,614
129,623
230,396
36,207
9,557
(5,325)
Total costs and expenses, net . . . . . .
49,667
1,238,050
103,221
(4,866)
1,386,072
(Loss) income before income taxes
and minority interest . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . .
Minority interest . . . . . . . . . . . . . . . .
(49,667)
(105,928)
—
323,009
934
—
2,598
(1,774)
117
—
—
—
275,940
(106,768)
117
NET (LOSS) INCOME . . . . . . . . . . $(155,595)
$ 323,943
$
941
$ —
$ 169,289
124
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
Parent
Company
Guarantor
Subsidiaries
Year Ended December 31, 2008
Non-Guarantor
Subsidiaries
(In thousands)
Eliminations
Consolidated
Net cash provided by operating
activities. . . . . . . . . . . . . . . . . . . . .
Cash flows from investing activities:
Capital expenditures . . . . . . . . . . . .
Acquisitions, net of cash acquired . .
Acquisition of fixed assets from
asset purchases . . . . . . . . . . . . . .
Investment in Geostream Services
Group . . . . . . . . . . . . . . . . . . . . .
Intercompany notes and accounts . . .
Other investing activities, net . . . . . .
Net cash (used in) provided by
$ 17,573
$ 364,840
$(15,249)
$
— $ 367,164
—
—
—
(214,659)
(63,457)
(4,335)
—
(34,468)
—
—
—
—
(19,306)
(179,501)
—
—
(199,428)
7,151
—
(1,515)
—
—
380,444
—
(218,994)
(63,457)
(34,468)
(19,306)
—
7,151
investing activities . . . . . . . . . . . . .
(198,807)
(504,861)
(5,850)
380,444
(329,074)
Cash flows from financing activities:
Borrowings on revolving credit
facility . . . . . . . . . . . . . . . . . . . . . .
172,813
—
—
—
172,813
Repayments on revolving credit
facility . . . . . . . . . . . . . . . . . . . . . .
Repurchases of common stock. . . . . . .
Intercompany notes and accounts. . . . .
Other financing activities, net . . . . . . .
Net cash provided by (used in)
(38,026)
(139,358)
177,698
8,107
—
—
181,016
(11,506)
—
—
21,730
—
—
—
(380,444)
—
(38,026)
(139,358)
—
(3,399)
financing activities . . . . . . . . . . . . .
181,234
169,510
21,730
(380,444)
(7,970)
Effect of changes in exchange rates
on cash. . . . . . . . . . . . . . . . . . . . . .
Net increase in cash . . . . . . . . . . . . .
Cash and cash equivalents at
beginning of period . . . . . . . . . . . .
Cash and cash equivalents at end of
—
—
—
—
29,489
4,068
4,699
46,358
12,145
—
—
—
4,068
34,188
58,503
period . . . . . . . . . . . . . . . . . . . . . .
$
— $ 75,847
$ 16,844
$
— $ 92,691
125
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Parent
Company
Guarantor
Subsidiaries
Year Ended December 31, 2007
Non-Guarantor
Subsidiaries
(In thousands)
Eliminations
Consolidated
Net cash (used in) provided by
operating activities . . . . . . . . . . . . .
Cash flows from investing activities:
Capital expenditures . . . . . . . . . . . .
Acquisitions, net of cash acquired . .
Investment in available for sale
securities . . . . . . . . . . . . . . . . . . .
Proceeds from the sale of available
of sale securities . . . . . . . . . . . . .
Intercompany notes and accounts . . .
Other investing activities, net . . . . . .
Net cash (used in) provided by
$ (3,401)
$ 264,275
$(10,955)
$
— $ 249,919
—
—
—
—
(473,412)
—
(207,400)
(157,955)
(121,613)
183,177
(434,672)
6,104
(5,160)
—
—
—
—
—
—
—
—
—
908,084
—
(212,560)
(157,955)
(121,613)
183,177
—
6,104
investing activities . . . . . . . . . . . . .
(473,412)
(732,359)
(5,160)
908,084
(302,847)
Cash flows from financing activities:
Repayment of long-term debt. . . . . .
Proceeds from long-term debt . . . . .
Borrowings on revolving credit
(396,000)
425,000
facility . . . . . . . . . . . . . . . . . . . .
50,000
—
—
—
—
—
—
—
—
—
Common stock acquired by
purchase . . . . . . . . . . . . . . . . . . .
Intercompany notes and accounts . . .
. . . . .
Other financing activities, net
Net cash provided by (used in)
(30,454)
424,822
3,445
—
458,560
(28,751)
—
24,702
—
—
(908,084)
—
(396,000)
425,000
50,000
(30,454)
—
(25,306)
financing activities . . . . . . . . . . . . .
476,813
429,809
24,702
(908,084)
23,240
Effect of changes in exchange rates
on cash. . . . . . . . . . . . . . . . . . . . . .
Net (decrease) increase in cash . . . . .
Cash and cash equivalents at
beginning of period . . . . . . . . . . . .
Cash and cash equivalents at end of
—
—
—
—
(38,275)
(184)
8,403
84,633
3,742
—
—
—
(184)
(29,872)
88,375
period . . . . . . . . . . . . . . . . . . . . . .
$
— $ 46,358
$ 12,145
$
— $ 58,503
126
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We maintain a set of disclosure controls and procedures that are designed to provide reasonable assurance
that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 (the
“Exchange Act”) is recorded, processed, summarized, and reported within the time periods specified in the
SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures
designed to ensure that information required to be disclosed by us in the reports that we file or submit under
the Exchange Act is accumulated and communicated to the Company’s management, including the Company’s
principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding
required disclosure.
The Company’s management, with the participation of the Company’s principal executive officer and
principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures
(as such term is defined in Rules 13a-15(e) under the Exchange Act) as of the end of the period covered by
this report. Based on such evaluation, the Company’s principal executive and financial officers have concluded
that, because of the material weakness described below for our payroll process, our disclosure controls and
procedures were ineffective as of the end of such period.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial
reporting. Internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes
in accordance with generally accepted accounting principles. Internal control over financial reporting includes
those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements
in accordance with generally accepted accounting principles, and that receipts and expenditures of the
Company are being made only in accordance with authorizations of management and directors of the
Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial
statements.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting
objectives because of its inherent limitations. Internal control over financial reporting is a process that involves
human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human
failures. Internal control over financial reporting can also be circumvented by collusion or improper
management override. Because of such limitations, there is a risk that material misstatements may not be
prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate. However, these inherent limitations are known features of the financial reporting process.
Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
A material weakness (as defined in SEC Rule 12b-2) is a deficiency, or combination of deficiencies, in
internal control over financial reporting such that there is a reasonable possibility that a material misstatement
of the annual or interim financial statements will not be prevented or detected on a timely basis.
Management conducted an assessment of the effectiveness of the Company’s internal control over
financial reporting as of December 31, 2008. In making this assessment, management used the criteria
127
described in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO). Based on this assessment, management concluded that the Company’s
internal control over financial reporting was not effective as of December 31, 2008 due to a material weakness
described below.
Payroll process. We determined that ineffective control activities surrounding our payroll process
constituted a material weakness in our system of internal control as of December 31, 2008. In particular, these
control activities pertained to documentation and approvals of employee master file data, proper evidence
concerning approval of hours worked or rate changes and deficiencies with reconciliations where payroll data
was a major component. The actions taken and the controls that were in place and operating during 2008 with
respect to this material weakness, which was identified in previous years, were not sufficient to effectively
remediate this material weakness as of December 31, 2008. In 2008, we continued our process to improve our
data quality and controls surrounding our payroll process that began in 2007. During the middle of 2008, we
began to relocate the payroll function from a shared services location in Midland, Texas to our corporate
offices in Houston, Texas. During this transition, the payroll department lost a significant percentage of its
staff which required their replacement with new personnel. We also increased the overall size of the payroll
department upon its relocation to Houston. With this change, we also added new payroll practices and
procedures. Additionally, throughout 2008, we worked on the replacement of our existing payroll system with
a new human resource information system, which included a payroll system, that was initiated in late 2007.
However, due to the nature and functionality of the payroll system that was in place during 2008, our
conversion to a new system was delayed until January 2009. The implementation of a new human resource
information system allows for automated workflow and approval of information, including, among other
things, employee master file data, hours worked and rate changes. We believe that as the new payroll
department employees receive the proper training and with the implementation of the new human resource and
payroll system that was completed in January 2009, we will further strengthen our control structure, increase
our efficiency in processing payroll and provide transparency of payroll related data, allowing for the
remediation of this material weakness.
Our internal control over financial reporting has been audited by Grant Thornton LLP, an independent
registered public accounting firm, as stated in their report included herein.
Remediation of Material Weaknesses in Internal Control Over Financial Reporting
In October 2006, we filed our 2003 Financial and Informational Report on Form 8-K/A with the SEC,
which described numerous material weaknesses in internal control over financial reporting that we identified
during our restatement and delayed financial reporting process. In the third quarter of 2007, we filed our
Annual Report on Form 10-K for the year ended December 31, 2006 and reported that nine of the material
weaknesses that we had previously identified remained as of December 31, 2006. Our Annual Report on
Form 10-K for the year ended December 31, 2007, filed in February 2008, reported that some of these
material weaknesses had been remediated and that seven existed at December 31, 2007.
Beginning in the fourth quarter of 2007 and continuing in 2008, the Company implemented numerous
remediation efforts to address the material weaknesses in existence at December 31, 2007 as described in
“Item 9A. Controls and Procedures” in the 2007 Report. As a result of these efforts, the Company’s
management determined that as of December 31, 2008, six of the seven material weaknesses identified in the
2007 Report had been remediated, but as discussed above, the material weakness relating to the controls
surrounding the payroll process had not been remediated. While many of the changes in internal control over
financial reporting were made during the fourth quarter of 2007, they were not in place and operating long
enough during 2007 to be assessed as effective. In addition, we made changes in internal control over financial
reporting during 2008 to further address the material weaknesses identified in the 2007 Report. The material
weaknesses identified in the 2007 Report that have been remediated are:
Financial Close and Reporting. Management instituted substantial changes in the fourth quarter of 2007
to our internal control structure related to our financial reporting and close process. These changes included
additional personnel, additional analytical procedures and reviews, revised methodologies for the preparation
128
of our financial statements, more reconciliations of our accounts and additional reconciliations between our
general ledger and subledger systems as well as increased evidence validating those controls. Based upon these
changes in internal control and the testing and evaluation of the effectiveness of these controls, the Company’s
management has concluded that remediation of the material weakness for financial close and reporting had
been achieved as of December 31, 2008.
Authorizations of Expenditures. During 2007, changes concerning authorization of expenditures were
made that included the establishment of approval authorities, automated controls in our procurement system
and analytical procedures around expenditures. Additionally, in 2008, we implemented an application that
allows for automated and paperless invoicing and an automated workflow for approvals of expenditures. Based
upon these changes in internal control and the testing and evaluation of the effectiveness of these controls, the
Company’s management has concluded that remediation of the material weakness for authorizations of
expenditures had been achieved as of December 31, 2008.
Recording of Revenues. During 2007, we added controls surrounding our recognition of revenues, such
as analytical reviews of accrued revenues, analysis of aged receivables and account reconciliations between
our revenue systems and general ledger. Based upon these changes in internal control and the testing and
evaluation of the effectiveness of these controls, the Company’s management has concluded that remediation
of the material weakness for recording of revenues had been achieved as of December 31, 2008.
Property, Plant & Equipment (PP&E).
In 2007, changes related to accounting for PP&E were made that
included the preparation of roll forwards, reconciliations of balances and analytical reviews of balances and
depreciation expense. Additionally, in 2008, we implemented analytical procedures and reviews to evaluate the
status of assets recorded as work-in-progress to ensure that depreciation expense for assets transferred out of
work-in-progress was correct in all material respects as well as to ensure that gains and losses associated with
disposals are reflected in the appropriate periods. Based upon these changes in internal control and the testing
and evaluation of the effectiveness of these controls, the Company’s management has concluded that
remediation of the material weakness for PP&E had been achieved as of December 31, 2008.
User Developed Applications.
In 2008, we implemented a formal financial spreadsheet controls policy
to govern the development, use and control of critical financial spreadsheets, which the users of these
applications are following. Based upon this change in internal control and the testing and evaluation of the
effectiveness of these controls within the financial spreadsheet controls policy, the Company’s management
has concluded that remediation of the material weakness for user developed applications had been achieved as
of December 31, 2008.
Application Access and Segregation of Duties.
In 2007, to address application access and segregation of
duties, we implemented management reports for business owner review as well as administrative controls and
procedures. In 2008, we made improvements to our business owner review of application access and
segregation of duties to allow for a more thorough review of access rights and duties. Based upon these
changes in internal control and the testing and evaluation of the effectiveness of these controls, the Company’s
management has concluded that remediation of the material weakness for application access and segregation
of duties had been achieved as of December 31, 2008.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during our last fiscal quarter of
2008, other than those described above, that materially affected, or are reasonably likely to materially affect,
our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
Not applicable.
129
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to
file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31,
2008.
ITEM 11. EXECUTIVE COMPENSATION
Item 11 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to
file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31,
2008.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Item 12 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to
file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31,
2008.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
Item 13 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to
file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31,
2008.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to
file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31,
2008.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
The following financial statements, schedules and exhibits are filed as part of this report:
1. Financial Statements — See “Index to Consolidated Financial Statements” at Page 64.
2. Financial Statement Schedules filed in Part IV of this report are listed below:
(cid:129) Schedule II — Valuation and other Qualifying Accounts
We have omitted all other financial statement schedules because they are not required or are not
applicable, or the required information is shown in the financial statements in notes to the financial statements.
3. Exhibits
Exhibit No.
Description
3.1
3.2
Articles of Restatement of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of
the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File
No. 001-08038.)
Unanimous consent of the Board of Directors of Key Energy Services, Inc., dated January 11,
2000, limiting the designation of the additional authorized shares to common stock. (Incorporated
by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q for the quarter
ended March 31, 2000, File No. 001-08038.)
130
Exhibit No.
Description
3.3
3.4
3.5
4.1
4.2
4.3
4.4
4.5
4.6*
10.1†
10.2†
10.3†
10.4†
10.5†
10.6†
Second Amended and Restated By-laws of Key Energy Services, Inc., adopted September 21,
2006. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K
filed on September 22, 2006, File No. 001-08038.)
Amendment to Second Amended and Restated By-laws of Key Energy Services, Inc., adopted
November 2, 2007. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on
Form 8-K filed on November 2, 2007, File No. 001-08038.)
Amendments to Second Amended and Restated By-laws of Key Energy Services, Inc., adopted
April 4, 2008. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on
Form 8-K filed on April 9, 2008, File No. 001-08038.)
Warrant Agreement, dated as of January 22, 1999, between Key Energy Services, Inc. and the
Bank of New York, a New York banking corporation as warrant agent. (Incorporated by reference
to Exhibit 99(b) of the Company’s Current Report on Form 8-K filed on February 3, 1999, File
No. 001-08038.)
Warrant Registration Rights Agreement dated January 22, 1999, by and among Key Energy
Services, Inc., the Guarantors named therein, Lehman Brothers Inc., Bear, Stearns & Co., Inc.,
F.A.C. / Equities, a division of First Albany Corporation, and Dain Rauscher Wessels, a division
of Dain Rauscher Incorporated. (Incorporated by reference to Exhibit 99(e) of the Company’s
Current Report on Form 8-K filed on February 3, 1999, File No. 001-08038.)
Indenture, dated as of November 29, 2007, among Key Energy Services, Inc., the guarantors party
thereto and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to
Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on November 30, 2007, File
No. 001-08038.)
Registration Rights Agreement dated as of November 29, 2007, among Key Energy Services, Inc.,
the subsidiary guarantors of the Company party thereto, and Lehman Brothers Inc., Banc of
America Securities LLC and Morgan Stanley & Co. Incorporated, as representatives of the several
initial purchasers named therein. (Incorporated by reference to Exhibit 4.2 of the Company’s
Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.)
First Supplemental Indenture, dated as of January 22, 2008, among Key Marine Services, LLC,
the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee.
(Incorporated by reference to Exhibit 4.5 of the Company’s Quarterly Report on Form 10-Q for
the quarter ended March 31, 2008, File No. 001-08038.)
Second Supplemental Indenture, dated as of January 13, 2009, among Key Energy Mexico, LLC,
the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee.
Key Energy Group, Inc. 1997 Incentive Plan, as an amendment and restatement effective
November 17, 1997 of the Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan.
(Incorporated by reference to Exhibit B of the Company’s Schedule 14A Proxy Statement filed
November 26, 1997, File No. 001-08038.)
Form of Restricted Stock Award Agreement under Key Energy Group, Inc. 1997 Incentive Plan.
(Incorporated by reference to Exhibit 10.15 of the Company’s Annual Report on Form 10-K for
the year ended December 31, 2006, File No. 001-08038.)
The 2006 Phantom Share Plan of Key Energy Services, Inc. (Incorporated by reference to
Exhibit 10.1 of the Company’s Current Report on Form 8-K dated October 19, 2006, File
No. 001-08038.)
Form of Award Agreement under the 2006 Phantom Share Plan of Key Energy Services, Inc.
(Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K dated
October 19, 2006, File No. 001-08038.)
Form of Stock Appreciation Rights Agreement under Key Energy Group, Inc. 1997 Incentive Plan.
(Incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K filed on
August 24, 2007, File No. 001-08038.)
Form of Non-Plan Option Agreement under Key Energy Group, Inc. 1997 Incentive Plan.
(Incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-8
filed on September 25, 2007, File No. 333-146294.)
131
Exhibit No.
10.7†
10.8†
10.9†
10.10†
10.11†
10.12†
10.13†
Description
Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan. (Incorporated by Reference to
Appendix A of the Company’s Schedule 14A Proxy Statement filed on November 1, 2007, File
No. 001-08038.)
Form of Nonstatutory Stock Option Agreement under 2007 Equity and Cash Incentive Plan.
(Incorporated by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K for the
year ended December 31, 2007 filed on February 28, 2008, File No. 001-08038.)
Restated Employment Agreement, dated effective as of December 31, 2007, among Richard J.
Alario, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by
reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on January 7, 2008,
File No. 001-08038.)
Acknowledgment and Waiver by Richard J. Alario, dated March 25, 2005, regarding rescinded
option grant. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on
Form 8-K dated March 29, 2005, File No. 001-08038.)
Restated Employment Agreement, dated effective as of December 31, 2007, among William M.
Austin, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by
reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on January 7, 2008,
File No. 001-08038.)
Restated Employment Agreement, dated effective as of December 31, 2007, among Newton W.
Wilson III, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by
reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on January 7, 2008,
File No. 001-08038.)
Acknowledgment and Waiver by Newton W. Wilson III, dated March 25, 2005, regarding
rescinded option grant. (Incorporated by reference to Exhibit 10.2 of the Company’s Current
Report on Form 8-K dated March 29, 2005, File No. 001-08038.)
10.14†* Amended and Restated Employment Agreement, dated October 22, 2008, between Kimberly R.
10.15†
10.16†
10.17†
10.18†
10.19†
10.20†
10.21†
10.22†
Frye, Key Energy Services, Inc. and Key Energy Shared Services, LLC.
Restated Employment Agreement dated effective as of December 31, 2007, among Kim B. Clarke,
Key Energy Services, Inc. and Key Energy Shared Services, LLC (Incorporated by reference to
Exhibit 10.4 of the Company’s Current Report on Form 8-K filed on January 7, 2008, File
No. 001-08038.)
Employment Agreement, dated as of January 1, 2004, between Key Energy Services, Inc. and Jim
D. Flynt. (Incorporated by reference to Exhibit 10.6 of the Company’s Current Report on
Form 8-K dated October 19, 2006, File No. 001-08038.)
First Amendment to Employment Agreement, dated November 26, 2007, between Key Energy
Services, Inc. and Jim D. Flynt. (Incorporated by reference to Exhibit 10.2 of the Company’s
Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.)
Employment Agreement, dated November 17, 2004, between Key Energy Services, Inc. and Phil
Coyne. (Incorporated by reference to Exhibit 10.8 of the Company’s Current Report on Form 8-K
dated October 19, 2006, File No. 001-08038.)
First Amendment to Employment Agreement, effective as of January 24, 2005, between Key
Energy Services, Inc. and Phil Coyne. (Incorporated by reference to Exhibit 10.9 of the
Company’s Current Report on Form 8-K dated October 19, 2006, File No. 001-08038.)
Amended and Restated Employment Agreement, dated December 31, 2007, between Key Energy
Services, Inc. and Don D. Weinheimer. (Incorporated by reference to Exhibit 10.19 of the
Company’s Annual Report on Form 10-K for the year ended December 31, 2007 filed on
February 28, 2008, File No. 001-08038.)
Employment Agreement, dated August 14, 2007, between Key Energy Shared Services, LLC and
J. Marshall Dodson. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report
on Form 10-Q for the quarter ended September 30, 2007, File No. 001-08038.)
Employment Agreement, dated August 14, 2007, between Key Energy Shared Services, LLC and
D. Bryan Norwood. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report
on Form 10-Q for the quarter ended September 30, 2007, File No. 001-08038.)
132
Exhibit No.
10.23†*
10.24†*
10.25
10.26
10.27
10.28
10.29
10.30
10.31*
10.32
10.33
10.34
10.35
10.36
Description
Restated Employment Agreement, effective August 1, 2007, between Key Energy Shared Services,
LLC and Tommy Pipes.
Employment Agreement, effective August 1, 2007, between Key Energy Services, Inc. and John
Carnett.
Office Lease, effective as of January 20, 2005, between Crescent 1301 McKinney, L.P. and Key
Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report
on Form 8-K dated January 26, 2005, File No. 001-08038.)
First Amendment to Office Lease, dated as of March 15, 2005, between Crescent 1301 McKinney,
L.P. and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s
Current Report on Form 8-K dated June 30, 2005, File No. 001-08038.)
Second Amendment to Office Lease, dated as of July 24, 2005, between Crescent 1301 McKinney,
L.P. and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.2 of the Company’s
Current Report on Form 8-K dated June 30, 2005, File No. 001-08038.)
Credit Agreement, dated as of November 29, 2007, among Key Energy Services, Inc., each lender
from time to time party thereto, Bank of America, N.A., as Paying Agent, Co-Administrative
Agent, Swing Line Lender and L/C Issuer, and Wells Fargo Bank, National Association, as Co-
Administrative Agent, Swing Line Lender and L/C Issuer. (Incorporated by reference to
Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on November 30, 2007, File
No. 001-08038.)
Stock and Membership Interest Purchase Agreement, dated as of September 19, 2007, between
and among Key Energy Services, LLC, the Sellers named therein, and Moncla Well Service, Inc.
and certain other affiliated companies named therein. (Incorporated by reference to Exhibit 10.1 of
the Company’s Current Report on Form 8-K filed on September 20, 2007, File No. 001-08038.)
First Amendment to Stock and Membership Interest Purchase Agreement, dated as of October 25,
2007, among Key Energy Services, LLC, the Sellers named therein, and Moncla Well Service,
Inc. and certain other affiliated companies named therein. (Incorporated by reference to
Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 2007, File No. 001-08038.)
Second Amendment to Stock and Membership Interest Purchase Agreement, dated as of
September 30, 2008, among Key Energy Services, LLC, the Sellers named therein, and Moncla
Well Service, Inc. and certain other affiliated companies named therein.
Purchase Agreement, dated November 14, 2007, by and among the Company, certain of its
domestic subsidiaries, and Lehman Brothers, Inc., Banc of America Securities LLC and Morgan
Stanley & Co. Incorporated, as representatives of the initial purchasers. (Incorporated by reference
to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on November 15, 2007, File
No. 001-08038.)
Asset Purchase Agreement, dated December 7, 2007, among Key Energy Services, LLC, Kings
Oil Tools, Inc. and Thomas Fowler. (Incorporated by reference to Exhibit 10.1 of the Company’s
Current Report on Form 8-K filed on December 13, 2007, File No. 001-08038.)
Purchase Agreement, dated April 3, 2008, among Key Energy Services, LLC, Western Drilling
Holdings, Inc., and Fred S. Holmes and Barbara J. Holmes. (Incorporated by reference to
Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 9, 2008, File
No. 001-08038.)
Stock Purchase Agreement, dated May 30, 2008, by and among Key Energy Services, LLC, and
E. Kent Tolman, Nita Tolman, Ronald D. Jones and Melinda Jones. (Incorporated by reference to
Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on June 5, 2008, File
No. 001-08038.)
Asset Purchase Agreement, dated July 22, 2008, by and among Key Energy Pressure Pumping
Services, LLC, Leader Energy Services Ltd., Leader Energy Services USA Ltd., and CementRite,
Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K
filed on July 24, 2008, File No. 001-08038.)
133
Exhibit No.
10.37
21*
23*
31.1*
31.2*
32*
Description
Master Agreement, dated August 26, 2008, by and among Key Energy Services, Inc., Key Energy
Services Cyprus Ltd., OOO Geostream Assets Management and L-Group. (Incorporated by
reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on September 2,
2008, File No. 001-08038.)
Significant Subsidiaries of the Company.
Consent of Independent Registered Public Accounting Firm.
Certification of CEO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act. of 2002.
Certification of Principal Financial Officer pursuant to Securities Exchange Act Rules 13a-14(a)
and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of CEO and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
† Indicates a management contract or compensatory plan, contract or arrangement in which any Director or
any Executive Officer participates.
* Filed herewith.
134
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
KEY ENERGY SERVICES, INC.
By:
/s/
J. MARSHALL DODSON
J. Marshall Dodson,
Vice President and Chief Accounting Officer
(Principal Financial Officer)
Date: February 27, 2009
POWER OF ATTORNEY
Each person whose signature appears below hereby constitutes and appoints Richard J. Alario and J.
Marshall Dodson, and each of them, his true and lawful attorney-in-fact and agent, with full powers of
substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all
amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other
documents in connection therewith, with the Securities and Exchange Commission granting to said attorneys-
in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned
required to be done in connection therewith.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below
by the following persons on behalf of the registrant in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Richard J. Alario
Richard J. Alario
/s/
J. Marshall Dodson
J. Marshall Dodson
/s/ David J. Breazzano
David J. Breazzano
/s/ Lynn R. Coleman
Lynn R. Coleman
/s/ Kevin P. Collins
Kevin P. Collins
/s/ William D. Fertig
William D. Fertig
/s/ W. Phillip Marcum
W. Phillip Marcum
Chairman of the Board of Directors,
President and Chief Executive Officer
(Principal Executive Officer)
February 27, 2009
Vice President and Chief Accounting
Officer (Principal Financial Officer)
February 27, 2009
Director
February 27, 2009
Director
February 27, 2009
Director
February 27, 2009
Director
February 27, 2009
Director
February 27, 2009
Signature
/s/ Ralph S. Michael,
Ralph S. Michael, III
/s/ William F. Owens
William F. Owens
/s/ Arlene M. Yocum
Arlene M. Yocum
/s/ Robert K. Reeves
Robert K. Reeves
/s/
J. Robinson West
J. Robinson West
Title
Director
Date
February 27, 2009
Director
February 27, 2009
Director
February 27, 2009
Director
February 27, 2009
Director
February 27, 2009
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders of
Key Energy Services, Inc.
We have audited in accordance with the standards of the Public Company Accounting Oversight Board
(United States) the consolidated financial statements of Key Energy Services, Inc. and Subsidiaries referred to
in our report dated February 24, 2009, which is included in the annual report to security holders and
incorporated by reference in Part II of this form. Our report on the consolidated financial statements includes
explanatory paragraphs, which discuss the adoption of Financial Accounting Standards Interpretation No. 48,
Accounting for Uncertainty in Income Taxes, and FSP EITF 00-19-2, Accounting for Registration Payment
Arrangements. Our audits of the basic financial statements included the financial statement schedule listed in
the index appearing under Item 15, which is the responsibility of the Company’s management. In our opinion,
this financial statement schedule, when considered in relation to the basic financial statements taken as a
whole, presents fairly, in all material respects, the information set forth therein.
/s/ GRANT THORNTON LLP
Houston, Texas
February 24, 2009
S-1
Key Energy Services, Inc. and Subsidiaries
Schedule II — Valuation and Qualifying Accounts
Balance at
Beginning of
Period
Charged to
Expense
Additions
Charged to
Other
Accounts
Acquisitions Deductions
Balance at
End of Period
(In thousands)
Allowance for doubtful accounts:
As of December 31, 2008 . . . . .
As of December 31, 2007 . . . . .
As of December 31, 2006 . . . . .
$13,501
12,998
10,843
$
37
3,675
1,854
$ (38)
—
301
$
15
1,251
—
$(2,047)
(4,423)
—
$11,468
13,501
12,998
S-2
Information below as of April 1, 2009
MANAGEMENT
DIRECTORS
Richard J. Alario
Chairman, President
and Chief Executive Offi cer
Newton W. “Trey” Wilson III
Executive Vice President
and Chief Operating Offi cer
T.M. “Trey” Whichard III
Senior Vice President
and Chief Financial Offi cer
Kim B. Clarke
Senior Vice President, Administration
and Chief People Offi cer
Don D. Weinheimer
Senior Vice President of Product
Development, Strategic Planning
and Quality
David J. Breazzano
President and Founding Principal
DDJ Capital Management, LLC
Lynn R. Coleman
Retired Partner
Skadden, Arps, Slate, Meagher
and Flom LLP
Kevin P. Collins
Managing Member
The Old Hill Company LLC
William D. Fertig
Co-Chair and Chief Investment Offi cer
Context Capital Management LLC
W. Phillip Marcum
Principal
MG Advisors, LLC
Kimberly R. Frye
Senior Vice President, General Counsel
and Secretary
Ralph S. Michael, III
Former President
and Chief Operating Offi cer
The Ohio Casualty Insurance Company
Phil G. Coyne
Senior Vice President
Wireline Services
John R. Carnett
Senior Vice President
Pressure Pumping Operations
Thomas R. Pipes
Senior Vice President
Well Service Rig Operations
Dennis C. Douglas
Senior Vice President
U.S. Marketplace Management
J. Marshall Dodson
Vice President
and Chief Accounting Offi cer
D. Bryan Norwood
Vice President and Treasurer
William F. Owens
Former Governor of Colorado
Principal
JF Companies LLC
Robert K. Reeves
Senior Vice President, General Counsel
and Chief Administrative Offi cer
Anadarko Petroleum Corporation
J. Robinson West
Founder and Chairman
PFC Energy
Arlene M. Yocum
Executive Vice President
and Managing Executive
PNC Wealth Management
and Institutional Investment Groups
Annual Meeting
The Company’s Annual Meeting of
Stockholders will be held at 9:00 a.m.
on June 4, 2009, at:
Inn at the Ballpark
1520 Texas Avenue
Houston, TX 77002
Financial Information
and News Releases
Information updates about us, including
quarterly fi nancial results and current
news releases, are available to the public
on our Web site at keyenergy.com
or upon request from our Investor
Relations Department.
Stock Transfer Agent and Registrar
American Stock Transfer & Trust Company
59 Maiden Lane
Plaza Level
New York, NY 10038
(800) 937-5449
www.amstock.com
Corporate Governance Certifi cation
Key Energy Services has fi led the
certifi cation of its Chief Executive Offi cer
and Chief Financial Offi cer and each have
signed and fi led the required certifi cations
under Section 302 of the Sarbanes-Oxley
Act of 2002 with its Annual Report on
Form 10-K.
Independent Auditors
Grant Thornton LLP
Houston, Texas
Stock Listing
New York Stock Exchange
Symbol: KEG
Form 10-K
A copy of the Company’s Annual Report to
the Securities and Exchange Commission
(Form 10-K) is available by writing to:
Investor Relations
Key Energy Services, Inc.
1301 McKinney Street, Suite 1800
Houston, TX 77010
Key Energy Services
1301 McKinney Street
Suite 1800
Houston, Texas 77010
713-651-4300
keyenergy.com
3.09.KES1881 © 2009 Key Energy Services